<PAGE>

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

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

                                   FORM 10-Q
(Mark One)
[X]             QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                  FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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 NUMBER 1-2745

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

                          SOUTHERN NATURAL GAS COMPANY
             (Exact Name of Registrant as Specified in its Charter)

<Table>
<S>                                                 <C>
                     DELAWARE                                           63-0196650
           (State or Other Jurisdiction                              (I.R.S. Employer
         of Incorporation or Organization)                          Identification No.)
</Table>

<Table>
<S>                                                 <C>
                 EL PASO BUILDING
               1001 LOUISIANA STREET                                       77002
                  HOUSTON, TEXAS                                        (Zip Code)
     (Address of Principal Executive Offices)
</Table>

                        Telephone Number: (713) 420-2600

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

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

     Common stock, par value $1 per share. Shares outstanding on August 13,
2003: 1,000

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

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                          SOUTHERN NATURAL GAS COMPANY

                               TABLE OF CONTENTS

<Table>
<Caption>
                                    CAPTION                             PAGE
                                    -------                             ----
<S>       <C>                                                           <C>
                        PART I -- Financial Information
Item 1.   Financial Statements........................................    1
Item 2.   Management's Discussion and Analysis of Financial Condition
            and Results of Operations.................................   13
          Cautionary Statement Regarding Forward-Looking Statements...   16
Item 3.   Quantitative and Qualitative Disclosures About Market
            Risk......................................................   16
Item 4.   Controls and Procedures.....................................   16

                          PART II -- Other Information
Item 1.   Legal Proceedings...........................................   18
Item 2.   Changes in Securities and Use of Proceeds...................   18
Item 3.   Defaults Upon Senior Securities.............................   18
Item 4.   Submission of Matters to a Vote of Security Holders.........   18
Item 5.   Other Information...........................................   18
Item 6.   Exhibits and Reports on Form 8-K............................   18
          Signatures..................................................   19
</Table>

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

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

<Table>
<S>      <C>
/d       = per day
BBtu     = billion British thermal units
Bcf      = billion cubic feet
Bcfe     = billion cubic feet equivalent
MMcf     = million cubic feet
</Table>

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

                                        i
<PAGE>

                        PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

                          SOUTHERN NATURAL GAS COMPANY

                CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND
                              COMPREHENSIVE INCOME
                                 (IN MILLIONS)
                                  (UNAUDITED)

<Table>
<Caption>
                                                          QUARTER ENDED       SIX MONTHS ENDED
                                                             JUNE 30,             JUNE 30,
                                                          --------------      ----------------
                                                          2003      2002      2003       2002
                                                          ----      ----      -----      -----
<S>                                                       <C>       <C>       <C>        <C>
Operating revenues......................................  $111      $100      $231       $203
                                                          ----      ----      ----       ----
Operating expenses
  Operation and maintenance.............................    44        38        89         75
  Depreciation, depletion and amortization..............    11        11        23         22
  Taxes, other than income taxes........................     6         6        11         11
                                                          ----      ----      ----       ----
                                                            61        55       123        108
                                                          ----      ----      ----       ----
Operating income........................................    50        45       108         95
Earnings from unconsolidated affiliates.................     9        14        28         20
Other income............................................     3         2         6          4
Interest and debt expense...............................   (23)      (15)      (39)       (28)
Affiliated interest income..............................    --         3         2          4
                                                          ----      ----      ----       ----
Income before income taxes and cumulative effect of
  accounting change.....................................    39        49       105         95
Income taxes............................................    13        15        35         31
                                                          ----      ----      ----       ----
Income before cumulative effect of accounting change....    26        34        70         64
Cumulative effect of accounting change, net of income
  taxes.................................................    --        --        --         57
                                                          ----      ----      ----       ----
Net income..............................................  $ 26      $ 34      $ 70       $121
                                                          ----      ----      ----       ----
Comprehensive income....................................  $ 26      $ 34      $ 70       $121
                                                          ====      ====      ====       ====
</Table>

                            See accompanying notes.

                                        1
<PAGE>

                          SOUTHERN NATURAL GAS COMPANY

                     CONDENSED CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)
                                  (UNAUDITED)

<Table>
<Caption>
                                                              JUNE 30,   DECEMBER 31,
                                                                2003         2002
                                                              --------   ------------
<S>                                                           <C>        <C>
                                       ASSETS

Current assets
  Cash and cash equivalents.................................   $   95       $   --
  Accounts and notes receivable
     Customer, net of allowance of $3 in 2003 and 2002......       51           71
     Affiliates.............................................       49           61
     Other..................................................        1            3
  Materials and supplies....................................       13           14
  Other.....................................................       11           10
                                                               ------       ------
          Total current assets..............................      220          159
                                                               ------       ------
Property, plant and equipment, at cost......................    2,953        2,846
  Less accumulated depreciation, depletion and
     amortization...........................................    1,333        1,319
                                                               ------       ------
          Total property, plant and equipment, net..........    1,620        1,527
                                                               ------       ------
Other assets
  Investments in unconsolidated affiliates..................      760          734
  Note receivable from affiliate............................       76          369
  Regulatory assets.........................................       36           34
  Other.....................................................       19            7
                                                               ------       ------
                                                                  891        1,144
                                                               ------       ------
          Total assets......................................   $2,731       $2,830
                                                               ======       ======

                        LIABILITIES AND STOCKHOLDER'S EQUITY

Current liabilities
  Accounts payable
     Trade..................................................   $   32       $   36
     Affiliates.............................................        7            9
     Other..................................................       --            1
  Taxes payable.............................................       57           49
  Accrued interest..........................................       31           20
  Deposits on transportation contracts......................       13           13
  Other.....................................................        5            4
                                                               ------       ------
          Total current liabilities.........................      145          132
                                                               ------       ------
Long-term debt..............................................    1,193          798
                                                               ------       ------
Other liabilities
  Deferred income taxes.....................................      285          260
  Other.....................................................       34           37
                                                               ------       ------
                                                                  319          297
                                                               ------       ------
Commitments and contingencies
Stockholder's equity
  Common stock, par value $1 per share; 1,000 shares
     authorized, issued and outstanding.....................       --           --
  Additional paid-in capital................................      341          341
  Retained earnings.........................................      741        1,270
  Accumulated other comprehensive loss......................       (8)          (8)
                                                               ------       ------
          Total stockholder's equity........................    1,074        1,603
                                                               ------       ------
          Total liabilities and stockholder's equity........   $2,731       $2,830
                                                               ======       ======
</Table>

                            See accompanying notes.

                                        2
<PAGE>

                          SOUTHERN NATURAL GAS COMPANY

                CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)
                                  (UNAUDITED)

<Table>
<Caption>
                                                              SIX MONTHS ENDED
                                                                  JUNE 30,
                                                              -----------------
                                                              2003        2002
                                                              -----       -----
<S>                                                           <C>         <C>
Cash flows from operating activities
  Net income................................................  $  70       $ 121
  Adjustments to reconcile net income to net cash from
     operating activities
     Depreciation, depletion and amortization...............     23          22
     Deferred income tax expense............................     25           8
     Undistributed earnings of unconsolidated affiliates....    (26)        (20)
     Cumulative effect of accounting change.................     --         (57)
     Other adjustments to net income........................     --          --
  Working capital changes...................................     29          37
  Non-working capital changes...............................     (5)         (3)
                                                              -----       -----
          Net cash provided by operating activities.........    116         108
                                                              -----       -----
Cash flows from investing activities
  Additions to property, plant and equipment................   (114)       (103)
  Net change in affiliated advances receivable..............     (5)       (103)
  Net proceeds from the sale of assets......................      4           1
                                                              -----       -----
          Net cash used in investing activities.............   (115)       (205)
                                                              -----       -----
Cash flows from financing activities
  Payments to retire long-term debt.........................     --        (200)
  Net proceeds from the issuance of long-term debt..........    384         297
  Dividends paid............................................   (290)         --
                                                              -----       -----
          Net cash provided by financing activities.........     94          97
                                                              -----       -----
Net change in cash and cash equivalents.....................     95          --
Cash and cash equivalents
  Beginning of period.......................................     --          --
                                                              -----       -----
  End of period.............................................  $  95       $  --
                                                              =====       =====
</Table>

                            See accompanying notes.

                                        3
<PAGE>

                          SOUTHERN NATURAL GAS COMPANY

              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)

1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     We are a wholly owned subsidiary of El Paso Corporation (El Paso). We
prepared this Quarterly Report on Form 10-Q under the rules and regulations of
the United States Securities and Exchange Commission. Because this is an interim
period filing presented using a condensed format, it does not include all of the
disclosures required by generally accepted accounting principles. You should
read it along with our Current Report on Form 8-K/A dated May 19, 2003, and our
Current Report on Form 8-K filed June 4, 2003 (the Combined Historical Financial
Statements), which include a summary of our significant accounting policies and
our audited combined financial statements and related footnotes as of December
31, 2002 and 2001 and for the three years ended December 31, 2002. As discussed
below, our historical financial information has been restated to reflect the
contribution of Citrus Corp. (Citrus) to us by El Paso for all periods
presented. The financial statements as of June 30, 2003, and for the quarters
and six months ended June 30, 2003 and 2002, are unaudited. We derived the
balance sheet as of December 31, 2002, from the Combined Historical Financial
Statements. In our opinion, we have made all adjustments which are of a normal,
recurring nature to fairly present our interim period results. Due to the
seasonal nature of our business, information for interim periods may not
indicate the results of operations for the entire year. In addition, prior
period information presented in these financial statements also includes
reclassifications which were made to conform to the current period presentation.
These reclassifications have no effect on our previously reported net income or
stockholder's equity.

  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 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 its operating results in our financial
statements for all periods presented. Our financial statements reflect our
ownership of Citrus in the earliest period presented combined with our results.
Our combined income before cumulative effect of accounting change and net income
for the quarter and six months ended June 30, 2002 is presented below.

<Table>
<Caption>
                                                              QUARTER ENDED   SIX MONTHS ENDED
                                                              JUNE 30, 2002    JUNE 30, 2002
                                                              -------------   ----------------
                                                                       (IN MILLIONS)
<S>                                                           <C>             <C>
Income before cumulative effect of accounting change
  Historical................................................       $24              $ 51
  Citrus....................................................        10                13
                                                                   ---              ----
    Combined income before cumulative effect of accounting
      change................................................       $34              $ 64
                                                                   ===              ====
Net income
  Historical................................................       $24              $ 51
  Citrus....................................................        10                70
                                                                   ---              ----
    Combined net income.....................................       $34              $121
                                                                   ===              ====
</Table>

  Significant Accounting Policies

     Our accounting policies are consistent with those discussed in our Combined
Historical Financial Statements, except as discussed below:

     Accounting for Costs Associated with Exit or Disposal Activities.  As of
January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS)
No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS
No. 146 requires that we recognize costs associated with exit or disposal
activities

                                        4
<PAGE>

when they are incurred rather than when we commit to an exit or disposal plan.
There was no initial financial statement impact of adopting this standard.

     Accounting for Guarantees.  On January 1, 2003, we adopted Financial
Accounting Standards Board Interpretation (FIN) No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. FIN No. 45 requires that we record a liability for all
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at fair value when they are issued. There was no
initial financial statement impact of adopting this standard.

     Accounting for Regulated Operations.  Our natural gas system, storage and
terminalling operations are subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and
the Natural Gas Policy Act of 1978, and we apply the provisions of SFAS No. 71,
Accounting for the Effects of Certain Types of Regulation, to these businesses.
We continue to evaluate the application of SFAS No. 71 for changes in the
competitive environment and our operating cost structures. See a further
discussion of our accounting for regulated operations in our Combined Historical
Financial Statements.

2. 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 1 for a discussion of the accounting
treatment for this transaction. As a result of our ownership in Citrus, which
had negative goodwill associated with the 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.

3. ACCOUNTING FOR HEDGING ACTIVITIES

     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 Derivatives and
Hedging Activities, and records changes in the fair value of these derivatives
in other comprehensive income. We have reflected our proportionate share of the
impact that these derivative instruments have on Citrus' financial statements as
adjustments to our other comprehensive income and our investment in
unconsolidated affiliates.

     As of June 30, 2003, the value of cash flow hedges included in accumulated
other comprehensive income was an unrealized loss of $8 million, net of income
taxes. This amount will be reclassified to earnings over the terms of the
outstanding debt. We estimate that $1 million of this unrealized loss will be
reclassified from accumulated other comprehensive loss over the next twelve
months. For the quarters and six months ended June 30, 2003 and 2002, there was
no ineffectiveness on these cash flow hedges.

4. DEBT AND OTHER CREDIT FACILITIES

     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. This facility replaces El Paso's previous $3 billion revolving credit
facility. Approximately $1 billion of other financing arrangements (including
leases, letters of credit and other facilities) were also amended to conform El
Paso's obligations to the new $3 billion revolving credit facility. El Paso's
equity in several of its subsidiaries, including our equity in Bear Creek
Storage, collateralizes the $3 billion revolving credit facility and the other
financing arrangements. In March 2003, El Paso retired the outstanding balance
under the Trinity River financing arrangement. Our 50 percent ownership in Bear
Creek Storage, along with various assets of El Paso, collateralized that
arrangement.

     In March 2003, we issued $400 million of senior unsecured notes with an
annual interest rate of 8.875%. The notes mature in 2010. Net proceeds of
approximately $385 million were used to pay a cash dividend to our parent of
approximately $290 million, while $95 million was retained for future capital
expenditures. Key

                                        5
<PAGE>

covenants in the indenture include (i) limitations on the occurrence of
additional debt, based on a ratio of debt to EBITDA, as defined in the
indenture; (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 described in Note
6. For the six months ended June 30, 2003, we were in compliance with these
covenants.

5. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

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

     Will Price (formerly Quinque).  We and a number of our affiliates were
named defendants in Quinque Operating Company, et al v. Gas Pipelines and Their
Predecessors, et al, filed in 1999 in the District Court of Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiffs in this case seek certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiffs contend these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with
prejudgment and postjudgment interest, punitive damages, treble damages,
attorney's fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. Plaintiffs' motion for class
certification was denied on April 10, 2003. Plaintiffs' motion to file another
amended petition to narrow the proposed class to royalty owners in wells in
Kansas, Wyoming and Colorado was granted on July 28, 2003. We are not named as a
defendant in this Fourth Amended Petition. Our costs and legal exposure related
to this lawsuit and claims are not currently determinable.

     Key.  We were named as a defendant in Randall Key v. 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 repressuration 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 February 2004. Our costs and legal
exposure related to this lawsuit and claims are not currently determinable.

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

     For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of June 30, 2003, we had no accruals for our outstanding legal matters.

                                        6
<PAGE>

  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 June 30,
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 most likely
outcome that can be reasonably estimated. Below is a reconciliation of our
environmental remediation liabilities as of June 30, 2003 (in millions):

<Table>
<S>                                                           <C>
Balance as of January 1, 2003...............................  $ 4
Additions/Adjustments for remediation activities............    1
Payments for remediation activities.........................   (2)
                                                              ---
Balance as of June 30, 2003.................................  $ 3
                                                              ===
</Table>

     In addition, we expect to make capital expenditures for environmental
matters of approximately $6 million in the aggregate for the years 2003 through
2008. These expenditures primarily relate to compliance with clean air
regulations. For the remainder of 2003, we estimate that our total remediation
expenditures will be approximately $3 million, which primarily will be expended
under government directed clean-up plans.

     CERCLA Matters.  We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to one active site under the
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or
state equivalents. We have sought to resolve our liability as a PRP at these
sites through indemnification by third parties and settlements which provide for
payment of our allocable share of remediation costs. As of June 30, 2003, we
have estimated our share of the remediation costs of these sites to be zero. The
estimate is subject to revision as more information becomes available about the
extent of remediation required and because in some cases we have asserted a
defense to any liability. Liability under the federal CERCLA statute is joint
and several, meaning that we could be required to pay in excess of our pro rata
share of remediation costs. Our understanding of the financial strength of other
PRP's has been considered, where appropriate, in estimating our liabilities.

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

  Rates and Regulatory Matters

     Order No. 637.  In February 2000, the FERC issued Order No. 637. Order 637
impacts the way pipelines conduct their operational activities, including how
they release capacity, segment capacity and manage imbalance services, issue
operational flow orders and impose pipeline penalties. In July 2001, we filed a
settlement addressing our compliance with Order No. 637 and we received an order
on the settlement from the FERC in April 2002. The FERC approved our settlement,
subject to modifications related to our capacity segmentation proposal, and
rejected our proposed changes to our cash-out mechanism. In response we sought
rehearing and made another compliance filing. At its July 23, 2003 meeting, the
FERC approved an order addressing our compliance filing and the requests for
rehearing. After rehearing, the FERC accepted our capacity segmentation
proposal. The FERC denied the rehearing requests regarding discounting to
alternate points. The FERC also clarified that our penalty crediting tariff
provision was acceptable. The FERC approved our operational flow order (OFO)
proposal but limited the applicable penalty for a Type 3, Level 3

                                        7
<PAGE>

OFO to $15.00 per dekatherm. The FERC denied all requests for rehearing
regarding our cashout mechanism. We filed revised tariff revisions and must
implement the Order No. 637 proposal on September 1, 2003.

     Elba Island LNG Expansion.  In May 2002, we applied to expand our Elba
Island LNG terminal based on a precedent agreement for new firm terminalling
service that we entered into with Shell NA LNG in December 2001. This expansion
adds a new marine slip, a fourth storage tank with a capacity of 3.3 Bcfe, and
new pumps and vaporizers that increase the design sendout rate from 446 MMcf/d
to 806 MMcf/d and the maximum sendout rate from 675 MMcf/d to 1,215 MMcf/d. In
November 2002, the FERC issued a Preliminary Determination on Nonenvironmental
Issues authorizing the proposed expansion, subject to completion of a favorable
environmental assessment. Marathon Oil Company filed a request for rehearing in
December 2002, which raised issues concerning the potential adverse impact of
the proposed expansion on existing customers. In April 2003, the FERC issued a
final order authorizing the proposed expansion and denying Marathon's request
for rehearing. A service agreement was executed by us and Shell on May 27, 2003.
Construction of the Terminal Expansion commenced in mid-July 2003.

     On July 1, 2003, the U.S. Coast Guard issued new regulations it called "the
foundation of national Maritime Transportation Security." The regulations
include new security requirements for LNG terminals. By December 29, 2003, each
LNG terminal must have completed a security assessment and have submitted an
assessment and security plan to the local Captain of the Port for review. By
June 30, 2004, each LNG terminal must comply with the new requirements,
including the filing of a plan approved by the Captain of the Port. SLNG has
started to review the impact on Elba Island operations, including cost recovery
options.

     In January 2003, the Transportation Security Administration announced the
availability of $148 million in federal funds for transportation security
programs. In February 2003, we filed an application for a federal port security
grant to enhance security at Elba Island. On June 12, 2003, TSA recommended one
of our three proposals, a patrol boat, for federal funding. We will incorporate
the patrol boat into the security planning required by the new Coast Guard
Regulations.

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

     In November 2002, we filed a petition to amend the September 20 order to
change the construction schedule to three phases and to provide for the joint
ownership of the Port Wentworth meter station. In February 2003, the FERC
granted our requested amendment. Construction will now be completed in three
phases for this expansion. Due to heavier than normal rainfall in the
construction areas, FERC granted our request for an extension of time until
September 1, 2003 to complete construction of the Phase I facilities.

     In March 2003, one of the expansion shippers that had been determined to be
non-creditworthy filed a complaint with the FERC requesting a finding that a $21
million security bond that it had been required to provide, representing an
amount equivalent to approximately 30 months of reservation charges, violates
provisions in our effective tariff, our firm transportation agreement and FERC's
policy on security requirements for non-creditworthy parties. We filed our
answer with the FERC in April 2003. In June 2003, the FERC issued an order
denying the complaint stating that SNG's level of collateral did not violate its
service agreements, its tariff, or the FERC's policy on creditworthiness.
Accordingly, compared to the risk that a non-creditworthy shipper poses to a
project, the collateral required by SNG was not unreasonable and there was no
basis to undo an agreement under which the parties had operated and for which
construction was proceeding. On August 4, 2003, FERC issued a tolling order to
provide additional time to consider a request for rehearing of the June 2003
order.

     Termination of Blanket Marketing Authority. Contemporaneously with our
issuance of notes in March 2003, El Paso contributed its 50 percent interest in
Citrus to us. Enron owns the other 50 percent interest. In March 2003, the FERC
issued an order directing Citrus Trading Corporation (CTC), a direct subsidiary
of

                                        8
<PAGE>

Citrus, to show cause, in a proceeding initiated by the order against various
Enron affiliates, 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. In April 2003, CTC filed its answer to the show cause order, denying that
it had engaged in any of the activities cited by the FERC as justifying the
revocation of its blanket marketing certificate. On June 26, 2003, the FERC
issued an order revoking the market-based authority for Enron Power Marketing
and Enron Energy Services and blanket sales certificate authority for eight
Enron gas marketing companies. CTC was specifically exempted from the order
because it did not engage in speculative gas trading or market making
activities.

     Marketing Affiliate NOPR.  In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how we conduct business and interact with our energy affiliates.
We have filed comments with the FERC addressing our concerns with the proposed
rules, participated in a public conference and filed additional comments. At
this time, we cannot predict the outcome of the NOPR, but adoption of the
regulations in their proposed form would, at a minimum, place additional
administrative and operational burdens on us.

     Negotiated Rate Policy.  In July 2002, the FERC issued a Notice of Inquiry
(NOI) that sought comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. The FERC is now reviewing whether
negotiated rates should be capped, whether or not the "recourse rate" (a
cost-of-service based rate) continues to safeguard against a pipeline exercising
market power and other issues related to negotiated rate programs. El Paso's
pipelines and others filed comments on the NOI.

     In July 2003, the FERC issued modifications to its negotiated rate policy
applicable to interstate natural gas pipelines. The new policy has two primary
changes. First, the FERC will no longer permit the pricing of negotiated rates
based on natural gas commodity price indices, although it will permit current
contracts negotiated on that basis to continue until the end of the applicable
contract period. Second, the FERC is imposing new filing requirements on
pipelines to ensure the transparency of negotiated rate transactions.

     Interim Rule on Cash Management.  In August 2002, the FERC issued a NOPR
proposing, inter alia, that all cash management or money pool arrangements
between a FERC-regulated subsidiary and its non-FERC regulated parent be in
writing and that, as a condition of participating in such an arrangement, the
FERC-regulated entity maintain a minimum proprietary capital balance of 30
percent and both it and its parent maintain investment grade credit ratings.
After receiving written comments and hearing industry participants' concerns at
a public conference in September 2002, the FERC issued an Interim Rule on Cash
Management on June 26, 2003, which did not adopt the proposed limitations on
entry into or participation in cash management programs. Instead, the Interim
Rule requires natural gas companies to maintain up-to-date documentation
authorizing the establishment of the cash management programs in which they
participate and supporting all deposits into, borrowings and interest from, and
interest expense paid to such programs.

     The Interim Rule also seeks comments on a proposed reporting requirement
that a FERC-regulated entity file cash management agreements and any changes
thereto within ten days and that it notify the FERC within five days when its
proprietary capital ratio falls below 30 percent (i.e., its long-term
debt-to-equity ratio rises above 70 percent) and when it subsequently returns to
or exceeds 30 percent. We filed comments on the Interim Rule on August 7, 2003.

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

                                        9
<PAGE>

     Emergency Reconstruction of Interstate Natural Gas Facilities Final
Rule.  On May 19, 2003, the FERC issued a Final Rule that amends its regulations
to enable natural gas interstate pipeline companies, in emergency situations
resulting in sudden, unanticipated loss of natural gas or capacity, to replace
facilities when immediate action is required to restore service for the
protection of life or health or for the maintenance of physical property.
Specifically, the Final Rule permits a pipeline to replace mainline facilities
using a route other than an existing right-of-way, to commence construction
without being subject to a 45-day waiting period, and to undertake projects that
exceed the existing blanket cost constraints. Lastly, the Final Rule requires
that landowners be notified of potential construction but provides for a
possible waiver of the 30-day waiting period.

     FERC Inquiry.  In February 2003, El Paso received a letter from the Office
of the Chief Accountant at the FERC requesting details of its announcement of
2003 asset sales and plans for ANR Pipeline Company (an El Paso subsidiary) and
us to issue a combined $700 million of long-term notes. The letter requested
that El Paso explain how it intended to use the proceeds from the issuance of
the notes and if the notes will be included in the two regulated companies'
capital structure for rate-setting purposes. Our response to the FERC was filed
on March 12, 2003. On April 2, 2003, we received an additional request for
information, to which we fully responded on April 15, 2003.

     Other Matters

     Duke.  Contemporaneously with our issuance of notes in March 2003, El Paso
contributed to us its 50 percent interest in Citrus. 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
pursuant to which CTC was entitled to purchase, through August 2005, up to 30.4
Bcf per year of regasified liquefied natural gas (LNG). On April 14, 2003, Duke
forwarded to CTC a letter purporting to terminate the gas supply contract
effective April 16, 2003, due to the alleged failure of CTC to increase the
amount of an outstanding letter of credit backstopping its purchase obligations.
On April 16, 2003, Duke filed an answer to the complaint, averring variously
that (1) CTC had triggered the early termination of the gas supply agreement by
allegedly failing to provide an adequate letter of credit to Duke; (2) CTC had
breached the gas supply contract by allegedly violating certain use restrictions
that required volumes equivalent to those purchased by CTC from Duke to be sold
by CTC into the power generation market in the State of Florida; and (3) Duke
was partially excused from performance under the gas supply agreement by reason
of an alleged loss of supply of LNG on January 15, 2002 and would be fully
excused from providing replacement gas upon the earlier of (i) 730 days or (ii)
the incurrence of replacement costs equal to $60 million, escalated by the GNP
implicit price deflator commencing January 1990 (approximately $79.2 million as
of December 31, 2002). On April 29, 2003, Duke removed the pending litigation to
federal court, based on the existence of foreign arbitration with its supplier
of LNG, Sonatrading Amsterdam B.V., which had allegedly repudiated its supply
contract as of January 27, 2003. On May 1, 2003, CTC notified Duke that it was
in default under the gas supply contract, demanding cover damages for alternate
supplies obtained by CTC beginning April 17, 2003. On May 23, 2003, CTC filed a
motion to remand the case back to state court. On June 2, 2003, CTC gave notice
of early termination to Duke in preparation for the subsequent filing of an
amended petition for monetary damages. The outcome of this litigation is not
currently determinable. However, CTC subsequently invoiced Duke for cover
damages arising from the terminated contract. On July 31, 2003, the federal
court remanded this case back to state court. CTC plans to file its amended
petition for monetary damages on August 19, 2003. We do not expect the ultimate
resolution of this matter to have a material adverse effect on our financial
position, operating results or cash flows.

     While the outcome of our outstanding legal matters, environmental matters
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that the outcome of these
matters could impact our credit rating and that of our parent. Further, for
environmental matters it is

                                        10
<PAGE>

also possible that other developments, such as increasingly strict environmental
laws and regulations and claims for damages to property, employees, other
persons and the environment resulting from our current or past operations, could
result in substantial costs and liabilities in the future. As new information
for our outstanding legal matters, environmental matters and rates and
regulatory matters becomes available, or relevant developments occur, we will
review our accruals and make any appropriate adjustments. The impact of these
changes may have a material effect on our results of operations, our financial
position, and on our cash flows in the period the event occurs.

6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

  Investment in Unconsolidated Affiliates

     Our investments in unconsolidated affiliates consist of our equity
ownership interests in Citrus and in Bear Creek Storage. Earnings from our
unconsolidated affiliates for the quarters and six months ended June 30, 2003
and 2002 are as follows:

<Table>
<Caption>
                                                  QUARTER ENDED        SIX MONTHS ENDED
                                                    JUNE 30,               JUNE 30,
                                                 ---------------       -----------------
                                                 2003       2002       2003        2002
                                                 ----       ----       -----       -----
                                                              (IN MILLIONS)
<S>                                              <C>        <C>        <C>         <C>
Operating results data:
  Operating revenues...........................  $40        $57        $120         $92
  Operating expenses...........................    6         23          48          38
  Net income(1)................................    7         15          21          21
</Table>

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

     In March 2003, El Paso contributed its 50 percent ownership interest in
Citrus to us. Enron Corp. owns the other 50 percent. Citrus owns and operates
Florida Gas Transmission, a 4,804 mile regulated pipeline system that extends
from producing regions in Texas to markets in Florida. Our investment in Citrus
is limited to our ownership of the voting stock of Citrus. El Paso has provided
a parent guarantee of certain contractual obligations of Citrus Trading Corp.

     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.

     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.

                                        11
<PAGE>

     Summarized income statement information of our proportionate share of
Citrus for the quarters and six months ended June 30, 2003 and 2002 are as
follows:

<Table>
<Caption>
                                                  QUARTER ENDED        SIX MONTHS ENDED
                                                    JUNE 30,                JUNE 30
                                                 ---------------       -----------------
                                                 2003       2002       2003        2002
                                                 ----       ----       -----       -----
                                                              (IN MILLIONS)
<S>                                              <C>        <C>        <C>         <C>
Operating results data:
  Operating revenues...........................  $36        $52        $111         $83
  Operating expenses...........................    4         20          45          34
  Income from continuing operations............    4         12          15          14
  Net income(1)................................    4         12          15          14
</Table>

---------------
(1) The difference between our proportionate share of our equity investments'
    net income and our earnings from unconsolidated affiliates reflected in our
    income statement is 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 participating affiliates, thus minimizing
total borrowings from outside sources. Our continued participation in the
program may be dependent on any final rule issued by the FERC in connection with
its interim rule on cash management as discussed in Note 5. As of June 30, 2003
and December 31, 2002, we had advanced to El Paso $125 million and $430 million.
The market rate of interest at June 30, 2003 and December 31, 2002 was 1.3% and
1.5%. As of June 30, 2003 and December 31, 2002, we have classified $76 million
and $369 million of these advances as non-current notes receivables from
affiliates. These receivables were due upon demand, however, we do not
anticipate settlement within the next twelve months. Also, 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 $7 million and $9 million at June
30, 2003 and December 31, 2002. These balances arose in the normal course of
business.

     The following table shows revenues and charges from our affiliates for the
quarters and six months ended June 30, 2003 and 2002:

<Table>
<Caption>
                                                   QUARTER ENDED        SIX MONTHS ENDED
                                                      JUNE 30               JUNE 30,
                                                  ---------------       -----------------
                                                  2003       2002       2003        2002
                                                  ----       ----       -----       -----
                                                               (IN MILLIONS)
<S>                                               <C>        <C>        <C>         <C>
Revenues from affiliates........................  $11        $12         $22         $22
Operations and maintenance from affiliates......   11         10          24          23
</Table>

                                        12
<PAGE>

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

     The information contained in Item 2 updates, and should be read in
conjunction with, the information disclosed in our Combined Historical Financial
Statements, which include our audited combined financial statements and related
footnotes as of December 31, 2002 and 2001 and for three years ended December
31, 2002, our combined business and property discussion as of March 31, 2003 and
our combined management's discussion and analysis of financial condition and
results of operations for the three years ended December 31, 2002 and the
quarters ended March 31, 2003 and 2002, in addition to the financial statements
and notes presented in Item 1 of this Form 10-Q.

                             RESULTS OF OPERATIONS

     We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business. We define EBIT as net
income adjusted for (i) items that do not impact our income from continuing
operations such as the impact of an accounting change, (ii) income taxes, (iii)
interest and debt expense and (iv) affiliated interest income. We exclude
interest and debt expense so that investors may evaluate our operating results
without regard to our financing methods. Our business consists of our
consolidated operations as well as our investments in unconsolidated affiliates.
As a result, we believe EBIT, which includes the results of our consolidated and
unconsolidated operations, is useful to our investors because it allows them to
more effectively evaluate the operating performance of our business and
investments. In addition, this is the measurement used by El Paso to evaluate
the operating performance of its business segments. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income or other performance measures such as operating income
or operating cash flow. As discussed in Item 1, Notes 1, 5 and 6, in March 2003,
El Paso contributed its 50 percent equity interest in Citrus to us. Our
historical financial statements have been restated to reflect this transaction
in all periods presented in this filing. The following is a reconciliation of
our operating income to our EBIT and our EBIT to our net income for the periods
ended June 30:

<Table>
<Caption>
                                                   QUARTER ENDED      SIX MONTHS ENDED
                                                      JUNE 30,            JUNE 30,
                                                  ----------------    ----------------
                                                   2003      2002      2003      2002
                                                  ------    ------    ------    ------
                                                  (IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S>                                               <C>       <C>       <C>       <C>
Operating revenues..............................  $  111    $  100    $  231    $  203
Operating expenses..............................     (61)      (55)     (123)     (108)
                                                  ------    ------    ------    ------
  Operating income..............................      50        45       108        95
                                                  ------    ------    ------    ------
Earnings from unconsolidated affiliates.........       9        14        28        20
Other income....................................       3         2         6         4
                                                  ------    ------    ------    ------
  Other.........................................      12        16        34        24
                                                  ------    ------    ------    ------
     EBIT.......................................      62        61       142       119
Interest and debt expense.......................     (23)      (15)      (39)      (28)
Affiliated interest income......................      --         3         2         4
Income taxes....................................     (13)      (15)      (35)      (31)
                                                  ------    ------    ------    ------
     Income before cumulative effect of
       accounting change........................      26        34        70        64
Cumulative effect of accounting change, net of
  income taxes..................................      --        --        --        57
                                                  ------    ------    ------    ------
     Net income.................................  $   26    $   34    $   70    $  121
                                                  ======    ======    ======    ======
Throughput volumes (BBtu/d)(1)..................   2,970     3,040     3,168     3,148
                                                  ======    ======    ======    ======
</Table>

---------------
(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.

                                        13
<PAGE>

  Second Quarter 2003 Compared to Second Quarter 2002

     Operating revenues for the quarter ended June 30, 2003, were $11 million
higher than in 2002. The increase was primarily due to increased revenues of $4
million from our South System I (Phase I) expansion, which was placed in service
in June 2002, revenues of $2 million at our Elba Island facility and revenues of
$1 million from sales of excess natural gas recoveries. Also contributing to the
increase in 2003 were higher sales under natural gas purchase contracts of $3
million. During 2003, our average realized price on sales under natural gas
purchase contracts was $5.32/Bcf versus $3.34/Bcf in 2002. These gas sales are a
result of a remaining gas purchase contract that the FERC allows us to market at
prices that approximate our cost. Therefore, we do not earn any significant
margins on these gas sales, and these gas sales have no significant effect on
our net results of operations.

     Operating expenses for the quarter ended June 30, 2003, were $6 million
higher than in 2002. The increase was primarily due to higher purchased natural
gas costs of $3 million due to higher prices in 2003. During 2003, our average
gas cost on these purchases was $5.30/Bcf versus $3.33/Bcf in 2002. This gas
cost results from the sales under natural gas purchase contracts discussed
above. Also contributing to the increase were higher allocated overhead costs of
$3 million from our parent in 2003 versus 2002. Allocated costs for 2002
included a downward adjustment of $3 million to reflect reduced compensation
expenses.

     Other income for the quarter ended June 30, 2003 was $4 million lower than
in 2002. The decrease was primarily due to $6 million in lower equity earnings
on our investment in Citrus, partially offset by higher allowance for funds used
during construction in 2003 of $2 million due to higher levels of construction
work in process in 2003.

  Six Months Ended 2003 Compared to Six Months Ended 2002

     Operating revenues for the six months ended June 30, 2003, were $28 million
higher than in 2002. The increase was primarily due to increased revenues of $8
million from our South System I (Phase I) expansion, which was placed in service
in June 2002, revenues of $4 million at our Elba Island facility and revenues of
$5 million from sales of excess natural gas recoveries. Also contributing to the
increase in 2003 were higher sales under natural gas purchase contracts of $11
million. During 2003, our average realized price on sales under natural gas
purchase contracts was $6.00/Bcf versus $2.80/Bcf in 2002.

     Operating expenses for the six months ended June 30, 2003, were $15 million
higher than in 2002. The increase was primarily due to higher purchased natural
gas costs of $11 million due to higher prices in 2003. During 2003, our average
gas cost on these purchases was $5.97/Bcf versus $2.79/Bcf in 2002. This gas
cost results from the sales under natural gas purchase contracts discussed
above. Also contributing to the increase were higher allocated overhead costs of
$3 million from our parent in 2003 versus 2002. Allocated costs for 2002
included a downward adjustment of $3 million to reflect reduced compensation
expenses.

     Other income for the six months ended June 30, 2003, was $10 million higher
than in 2002. The increase was primarily due to $8 million in higher equity
earnings on our investment in Citrus and higher allowance for funds used during
construction in 2003 of $3 million due to higher levels of construction work in
process.

INTEREST AND DEBT EXPENSE

     Interest and debt expense for the quarter and six months ended June 30,
2003, was $8 million and $11 million higher than the same period in 2002
primarily due to the issuance of $400 million of senior unsecured notes in March
2003.

AFFILIATED INTEREST INCOME

  Second Quarter 2003 Compared to Second Quarter 2002

     Affiliated interest income for the quarter ended June 30, 2003, was $3
million lower than the same period in 2002 due to lower average advances to El
Paso under our cash management program and lower short-term interest rates in
2003. The average advance balance for the second quarter of $561 million in 2002
decreased

                                        14
<PAGE>

to $225 million in 2003. The average short-term interest rates for the second
quarter decreased from 1.9% in 2002 to 1.3% in 2003.

  Six Months Ended 2003 Compared to Six Months Ended 2002

     Affiliated interest income for the six months ended June 30, 2003, was $2
million lower than the same period in 2002 due to lower average advances to El
Paso under our cash management program and lower short-term interest rates in
2003. The average advance balance for the six months ended June 30, 2002 of $449
million decreased to $342 million in 2003. The average short-term interest rates
for the six months ended decreased from 1.9% in 2002 to 1.3% in 2003.

INCOME TAXES

<Table>
<Caption>
                                                QUARTER ENDED          SIX MONTHS ENDED
                                                   JUNE 30,                JUNE 30,
                                               ----------------        ----------------
                                               2003        2002        2003        2002
                                               ----        ----        ----        ----
                                                   (IN MILLIONS, EXCEPT FOR RATES)
<S>                                            <C>         <C>         <C>         <C>
Income taxes.................................  $13         $15         $35         $31
Effective tax rate...........................   33%         31%         33%         33%
</Table>

     Our effective tax rates were different than the statutory rate of 35
percent in all periods, primarily due to state income taxes and earnings from
unconsolidated affiliates where we anticipate receiving dividends.

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. The construction will be undertaken in three phases, with a target
in-service date for Phases I, II and III facilities of mid-August 2003, November
1, 2003 and May 1, 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 June 30, 2003 are approximately $127 million.

     On May 31, 2002, we filed with the FERC to expand our Elba Island LNG
facility for estimated capital costs of $148 million. This expansion increases
the design sendout rate from 446 MMcf/d to 806 MMcf/d. On April 10, 2003, the
FERC approved our expansion. Construction commenced in July 2003 with an
in-service date expected to be in the first quarter of 2006.

                         COMMITMENTS AND CONTINGENCIES

     See Item 1, Financial Statements, Note 5, which is incorporated herein by
reference.

                                        15
<PAGE>

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 to be made 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     This information updates, and you should read it in conjunction with,
information disclosed in Part II, Item 7A in our Combined Historical Financial
Statements, in addition to the information presented in Items 1 and 2 of this
Quarterly Report on Form 10-Q.

     In March 2003, we issued $400 million of senior unsecured notes with an
annual interest rate of 8.875% due 2010. In addition, our 50 percent ownership
interest in Citrus has increased our overall market risks as discussed in our
2002 Form 10-K. There were no other material changes in our quantitative and
qualitative disclosures about market risks from those as of December 31, 2002.

ITEM 4. 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 Quarterly 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.
                                        16
<PAGE>

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 Quarterly 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.

     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 Quarterly
Report.

                                        17
<PAGE>

                          PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     See Part I, Item 1, Financial Statements, Note 5, which is incorporated
herein by reference.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

     None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

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

     None.

ITEM 5. OTHER INFORMATION

     None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

     a. Exhibits

     Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.

<Table>
<Caption>
EXHIBIT
NUMBER                            DESCRIPTION
-------                           -----------
<S>       <C>
 *31.A    Certification of Chief Executive Officer pursuant to
          sec. 302 of the Sarbanes-Oxley Act of 2002.
 *31.B    Certification of Chief Financial Officer pursuant to
          sec. 302 of the Sarbanes-Oxley Act of 2002.
 *32.A    Certification of Chief Executive Officer pursuant to 18
          U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
          Sarbanes-Oxley Act of 2002.
 *32.B    Certification of Chief Executive Officer pursuant to 18
          U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
          Sarbanes-Oxley Act of 2002.
</Table>

     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 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.

     b. Reports on Form 8-K

<Table>
<S>                    <C>

   May 19, 2003        Filed financial statements reflecting the contribution to us
                       by El Paso Corporation of its 50 percent ownership interest
                       in Citrus Corp.

   June 3, 2003        Filed our Computation of our Ratio of Earnings to Fixed
                       Charges for the five years ended December 31, 2002 and the
                       three months ended March 31, 2003 and 2002.

   June 4, 2003        Provided additional financial information regarding the
                       contribution to us by El Paso Corporation of its 50 percent
                       ownership in Citrus Corp.
</Table>

                                        18
<PAGE>

                                   SIGNATURES

     Pursuant to the requirements 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.

                                            SOUTHERN NATURAL GAS COMPANY

Date: August 13, 2003                          /s/ JOHN W. SOMERHALDER II
                                            ------------------------------------
                                                   John W. Somerhalder II
                                             Chairman of the Board and Director
                                               (Principal Executive Officer)

Date: August 13, 2003                              /s/ GREG G. GRUBER
                                            ------------------------------------
                                                       Greg G. Gruber
                                                   Senior Vice President,
                                             Chief Financial Officer, Treasurer
                                                        and Director
                                            (Principal Financial and Accounting
                                                          Officer)

                                        19
<PAGE>

                                 EXHIBIT INDEX

     Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.

<Table>
<Caption>
EXHIBIT
NUMBER                            DESCRIPTION
-------                           -----------
<S>       <C>
 *31.A    Certification of Chief Executive Officer pursuant to
          sec. 302 of the Sarbanes-Oxley Act of 2002.
 *31.B    Certification of Chief Financial Officer pursuant to
          sec. 302 of the Sarbanes-Oxley Act of 2002.
 *32.A    Certification of Chief Executive Officer pursuant to 18
          U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
          Sarbanes-Oxley Act of 2002.
 *32.B    Certification of Chief Executive Officer pursuant to 18
          U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
          Sarbanes-Oxley Act of 2002.
</Table>