<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 SEPTEMBER 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 November 10,
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
Dth      = dekatherm
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>
                                                                               NINE MONTHS
                                                          QUARTER ENDED           ENDED
                                                          SEPTEMBER 30,       SEPTEMBER 30,
                                                          --------------      --------------
                                                          2003      2002      2003      2002
                                                          ----      ----      ----      ----
<S>                                                       <C>       <C>       <C>       <C>
Operating revenues......................................  $111      $101      $342      $304
                                                          ----      ----      ----      ----
Operating expenses
  Operation and maintenance.............................    49        41       138       116
  Depreciation, depletion and amortization..............    12        12        35        34
  Taxes, other than income taxes........................     5         5        16        16
                                                          ----      ----      ----      ----
                                                            66        58       189       166
                                                          ----      ----      ----      ----
Operating income........................................    45        43       153       138
Earnings from unconsolidated affiliates.................    14        19        42        39
Other income............................................     3         2         9         6
Interest and debt expense...............................   (24)      (14)      (63)      (42)
Affiliated interest income..............................     1         2         3         6
                                                          ----      ----      ----      ----
Income before income taxes and cumulative effect of
  accounting change.....................................    39        52       144       147
Income taxes............................................    11        15        46        46
                                                          ----      ----      ----      ----
Income before cumulative effect of accounting change....    28        37        98       101
Cumulative effect of accounting change, net of income
  taxes.................................................    --        --        --        57
                                                          ----      ----      ----      ----
Net income..............................................  $ 28      $ 37      $ 98      $158
                                                          ----      ----      ----      ----
Comprehensive income....................................  $ 28      $ 37      $ 98      $158
                                                          ====      ====      ====      ====
</Table>

                            See accompanying notes.

                                        1
<PAGE>

                          SOUTHERN NATURAL GAS COMPANY

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

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

Current assets
  Cash and cash equivalents.................................     $   43          $   --
  Accounts and notes receivable
     Customer, net of allowance of $3 in 2003 and 2002......         51              71
     Affiliates.............................................         40              61
     Other..................................................          1               3
  Materials and supplies....................................         13              14
  Other.....................................................         14              10
                                                                 ------          ------
          Total current assets..............................        162             159
                                                                 ------          ------
Property, plant and equipment, at cost......................      3,022           2,846
  Less accumulated depreciation, depletion and
     amortization...........................................      1,339           1,319
                                                                 ------          ------
          Total property, plant and equipment, net..........      1,683           1,527
                                                                 ------          ------
Other assets
  Investments in unconsolidated affiliates..................        775             734
  Note receivable from affiliate............................         87             369
  Regulatory assets.........................................         42              34
  Other.....................................................         17               7
                                                                 ------          ------
                                                                    921           1,144
                                                                 ------          ------
          Total assets......................................     $2,766          $2,830
                                                                 ======          ======

                           LIABILITIES AND STOCKHOLDER'S EQUITY

Current liabilities
  Accounts payable
     Trade..................................................     $   48          $   36
     Affiliates.............................................         29               9
     Other..................................................          1               1
  Taxes payable.............................................         42              49
  Accrued interest..........................................          6              20
  Deposits on transportation contracts......................         13              13
  Other.....................................................          4               4
                                                                 ------          ------
          Total current liabilities.........................        143             132
                                                                 ------          ------
Long-term debt..............................................      1,193             798
                                                                 ------          ------
Other liabilities
  Deferred income taxes.....................................        294             260
  Other.....................................................         35              37
                                                                 ------          ------
                                                                    329             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................................        340             341
  Retained earnings.........................................        769           1,270
  Accumulated other comprehensive loss......................         (8)             (8)
                                                                 ------          ------
          Total stockholder's equity........................      1,101           1,603
                                                                 ------          ------
          Total liabilities and stockholder's equity........     $2,766          $2,830
                                                                 ======          ======
</Table>

                            See accompanying notes.

                                        2
<PAGE>

                          SOUTHERN NATURAL GAS COMPANY

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

<Table>
<Caption>
                                                              NINE MONTHS ENDED
                                                                SEPTEMBER 30,
                                                              -----------------
                                                              2003        2002
                                                              -----       -----
<S>                                                           <C>         <C>
Cash flows from operating activities
  Net income................................................  $  98       $ 158
  Adjustments to reconcile net income to net cash from
     operating activities
     Depreciation, depletion and amortization...............     35          34
     Deferred income tax expense............................     36          24
     Undistributed earnings of unconsolidated affiliates....    (41)        (39)
     Cumulative effect of accounting change.................     --         (57)
     Other adjustments to net income........................     (1)          1
     Working capital changes................................      4          24
     Non-working capital changes............................     (3)         (5)
                                                              -----       -----
          Net cash provided by operating activities.........    128         140
                                                              -----       -----
Cash flows from investing activities
  Additions to property, plant and equipment................   (181)       (169)
  Net change in affiliated advances receivable..............     (6)        (71)
  Proceeds from the sale of assets..........................      8           3
                                                              -----       -----
          Net cash used in investing activities.............   (179)       (237)
                                                              -----       -----
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.....................     43          --
Cash and cash equivalents
  Beginning of period.......................................     --          --
                                                              -----       -----
  End of period.............................................  $  43       $  --
                                                              =====       =====
Supplemental cash flow disclosures:
  Non-cash dividend to parent of affiliated receivables.....  $ 310       $  --
                                                              =====       =====
</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. These financial statements
are unaudited and, because this is an interim period filing presented using a
condensed format, do 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 (our 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 as of December 31, 2002, and for the quarter and nine
months ended September 30, 2002, has been restated to reflect the contribution
of Citrus Corp. (Citrus) to us by El Paso. We derived the balance sheet as of
December 31, 2002, from our 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 be indicative of our results
of operations for the entire year. In addition, prior period information
presented in these financial statements includes reclassifications which were
made to conform to the current period presentation. These reclassifications had
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 prior to its contribution. As a result, our financial
statements reflect the contribution of Citrus as though it occurred on January
1, 2002 (the beginning of the earliest period presented in these financial
statements). Our historical and combined income before cumulative effect of
accounting change and net income for the quarter and nine months ended September
30, 2002 is presented below.

<Table>
<Caption>
                                                               QUARTER ENDED      NINE MONTHS ENDED
                                                             SEPTEMBER 30, 2002   SEPTEMBER 30, 2002
                                                             ------------------   ------------------
                                                                          (IN MILLIONS)
<S>                                                          <C>                  <C>
Income before cumulative effect of accounting change
  Historical...............................................         $22                  $ 73
  Citrus...................................................          15                    28
                                                                    ---                  ----
    Combined income before cumulative effect of accounting
      change...............................................         $37                  $101
                                                                    ===                  ====
Net income
  Historical...............................................         $22                  $ 73
  Citrus...................................................          15                    85
                                                                    ---                  ----
    Combined net income....................................         $37                  $158
                                                                    ===                  ====
</Table>

                                        4
<PAGE>

  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 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 systems and storage
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 currently apply the provisions of SFAS No. 71,
Accounting for the Effects of Certain Types of Regulation. 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
the capitalization of 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. As a result of recent changes in our
competitive environment and operating cost structure, we continue to assess the
applicability of the provisions of SFAS No. 71 to our 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 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.

3. ACCOUNTING FOR HEDGING ACTIVITIES

     Citrus uses derivatives to mitigate, or hedge, cash flow risk associated
with variable interest rates on its 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 September 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 term of
Citrus' 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 nine months ended September 30, 2003 and
2002, there was no ineffectiveness on these cash flow hedges.

                                        5
<PAGE>

4. DEBT AND OTHER CREDIT FACILITIES

  Debt

     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 covenants in the indenture include (i) limitations on the
incurrence 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 nine months ended September 30, 2003, we were in
compliance with these covenants.

  Trinity River

     In March 2003, El Paso retired amounts outstanding under its Trinity River
financing arrangement. Prior to this retirement, our 50 percent ownership in
Bear Creek Storage, along with various assets of El Paso, collateralized that
arrangement.

  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 El Paso 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.

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 plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with
prejudgment and postjudgment interest, punitive damages, treble damages,
attorneys' fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement

                                        6
<PAGE>

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 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 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 September 30, 2003, we had no accruals for our outstanding legal matters.

  Environmental Matters

     We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of September
30, 2003, we had accrued approximately $4 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 September 30, 2003 (in millions):

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

     In addition, we expect to make capital expenditures for environmental
matters of approximately $8 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 $1 million, which primarily will be expended
under government directed clean-up plans.

     Toca Air Permit Violation.  On June 30, 2003, we met with the Louisiana
Department of Environmental Quality (LDEQ) to notify LDEQ that we had discovered
possible compliance issues with respect to operations at our Toca Compressor
Station. In response to a request from LDEQ, we submitted a detailed report to
LDEQ on September 23, 2003, documenting that there had been unpermitted VOC
emissions from nine condensate storage tanks and a tank truck loading station.
These unpermitted emissions have also triggered the need to revise various
compliance certifications. We advised LDEQ that we would seek to revise our
Title V Federal Operating Permit to accurately represent emissions from storage
tanks and the truck loading station and would revise and update all prior
certifications and reports to state correctly the emissions from these sources.
The report also noted that our 1997 replacement and relocation of the nine
storage tanks may result in a possible compliance issue with respect to the
Prevention of Significant Deterioration Regulations.

     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

                                        7
<PAGE>

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

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

     Elba Island LNG Expansion.  In April 2003, the FERC approved and issued a
final order authorizing the proposed expansion of 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. A service agreement at the
maximum rates for thirty years was executed by us and Shell on May 27, 2003. The
in-service date of the expansion is expected to be February 2006.

     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. After
requests from shippers we amended our application. In September 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 2002 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. Service from our Phase I facilities began on
September 8, 2003. We requested and received FERC authorization to begin
construction of the Phase IA facilities, and construction began on these
facilities in July 2003.

     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 the
FERC's policy on security requirements for non-creditworthy parties. 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. The FERC issued an order in October 2003 affirming
its dismissal of the complaint.

     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 Citrus, to show cause, in a proceeding initiated by the order against various
Enron affiliates, why the FERC

                                        8
<PAGE>

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) proposing 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 an order that prospectively prohibits
pipelines from negotiating rates based upon natural gas commodity price indices
and imposes certain new filing requirements to ensure the transparency of
negotiated rate transactions. Requests for rehearing were filed on August 25,
2003 and remain pending. We do not expect that the order or rehearing will have
a material effect on us.

     Cash Management Rule.  On October 23, 2003, the FERC approved a rule that
requires a FERC regulated entity to file its cash management agreement with the
FERC, maintain records of transactions involving its participation in the cash
management program, compute its proprietary capital ratio quarterly based on
criteria established by the FERC, and notify the FERC 45 days after the end of a
calendar quarter whether its proprietary capital ratio falls below 30 percent
and subsequently when its proprietary capital ratio returns to or exceeds 30
percent. In the rule, the FERC stated that the requirements imposed by the rule
are not in the nature of a regulation governing participation in cash management
programs and that the rule does not dictate the content or terms for
participating in a cash management program. Although the rule is subject to
rehearing, we do not believe an order on rehearing will have a material effect
on us.

     On September 10, 2003, the Office of Executive Director of Regulatory
Audits completed an industry-wide audit of the FERC Form 2 related to cash
management. The audit included our affiliates, EPNG and Mojave. The audit did
not identify any instances of non-compliance with the FERC's reporting and
recording requirements but recommended that EPNG and Mojave revise and update
their existing cash management agreements with El Paso. We are in the process of
reviewing and revising our cash management agreement pursuant to this
recommendation.

     Emergency Reconstruction of Interstate Natural Gas Facilities Rule.  On May
19, 2003, the FERC issued a 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 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. It also requires that landowners be notified of
potential construction, but provides for a possible waiver of the 30-day waiting
period.

     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

                                        9
<PAGE>

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. Although we cannot
predict the outcome of this rulemaking, we do not expect this order to have a
material effect on us.

     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 were to 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

     Enron Bankruptcy.  In December 2001, Enron Corp. 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 Corp.
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 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 Corp. and
then be distributed to Enron's creditors. We will object 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.

     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, stating 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 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,

                                        10
<PAGE>

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. On July 31, 2003, the
federal court remanded this case back to state court. On August 18, 2003, Duke
filed a third-party petition against Sonatrading, its Algerian LNG supplier. CTC
opposed the petition since, even in the event of a failure to receive supplies
from Algeria, Duke was required to furnish supplies to CTC for a stated period
of time. On October 6, 2003, the court ruled that, although Duke may attempt to
get service on Sonatrading, Duke's claim against its supplier will be tried
separately (and thus not delay or otherwise impact this case). Also on October
6, 2003, CTC filed its amended petition against Duke seeking termination damages
of $187 million. We do not expect the ultimate resolution of this matter to have
a material adverse effect on us.

     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 possible that the outcome of these
matters could impact our credit rating and that of our parent. Further, for
environmental matters it is 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 nine months ended September 30,
2003 and 2002 are as follows:

<Table>
<Caption>
                                                 QUARTER ENDED        NINE MONTHS ENDED
                                                 SEPTEMBER 30,          SEPTEMBER 30,
                                                ---------------       -----------------
                                                2003       2002       2003        2002
                                                ----       ----       -----       -----
                                                             (IN MILLIONS)
<S>                                             <C>        <C>        <C>         <C>
Operating results data:
  Operating revenues..........................  $63        $61        $183        $153
  Operating expenses..........................   30         24          78          62
  Net income(1)...............................   17         18          38          39
</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 parental 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.

                                        11
<PAGE>

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

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

<Table>
<Caption>
                                                 QUARTER ENDED        NINE MONTHS ENDED
                                                 SEPTEMBER 30,          SEPTEMBER 30,
                                                ---------------       -----------------
                                                2003       2002       2003        2002
                                                ----       ----       -----       -----
                                                             (IN MILLIONS)
<S>                                             <C>        <C>        <C>         <C>
Operating results data:
  Operating revenues..........................  $59        $56        $170        $139
  Operating expenses..........................   28         23          73          57
  Income from continuing operations...........   14         16          29          30
  Net income(1)...............................   14         16          29          30
</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. As of September 30, 2003 and December 31,
2002, we had advanced to El Paso $126 million and $430 million. The market rate
of interest at September 30, 2003 was 3.5% and at December 31, 2002 was 1.5%. As
of September 30, 2003 and December 31, 2002, we have classified $87 million and
$369 million of these advances as non-current notes receivables from affiliates.
These receivables are 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.

     At September 30, 2003, we had other accounts receivable from related
parties of $1 million. Accounts payable to affiliates was $29 million and $9
million at September 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 nine months ended September 30, 2003 and 2002:

<Table>
<Caption>
                                                                          NINE MONTHS
                                                   QUARTER ENDED             ENDED
                                                   SEPTEMBER 30,         SEPTEMBER 30,
                                                  ---------------       ---------------
                                                  2003       2002       2003       2002
                                                  ----       ----       ----       ----
                                                              (IN MILLIONS)
<S>                                               <C>        <C>        <C>        <C>
Revenues from affiliates........................  $ 6        $12        $28        $34
Operations and maintenance from affiliates......   14         12         38         35
</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 and 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 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 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 both our consolidated
business and our unconsolidated investments. In addition, this is the
measurement used by El Paso to evaluate the operating performance of its
business segments. We exclude interest and debt expense from this measure so
that investors may evaluate our operating results without regard to our
financing methods. EBIT may not be comparable to 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 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 for 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 September 30:

<Table>
<Caption>
                                                   QUARTER ENDED      NINE MONTHS ENDED
                                                   SEPTEMBER 30,        SEPTEMBER 30,
                                                  ----------------    ------------------
                                                   2003      2002      2003       2002
                                                  ------    ------    -------    -------
                                                   (IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S>                                               <C>       <C>       <C>        <C>
Operating revenues..............................  $  111    $  101    $  342     $  304
Operating expenses..............................     (66)      (58)     (189)      (166)
                                                  ------    ------    ------     ------
  Operating income..............................      45        43       153        138
                                                  ------    ------    ------     ------
Earnings from unconsolidated affiliates.........      14        19        42         39
Other income....................................       3         2         9          6
                                                  ------    ------    ------     ------
  Other.........................................      17        21        51         45
                                                  ------    ------    ------     ------
     EBIT.......................................      62        64       204        183
Interest and debt expense.......................     (24)      (14)      (63)       (42)
Affiliated interest income......................       1         2         3          6
Income taxes....................................     (11)      (15)      (46)       (46)
                                                  ------    ------    ------     ------
     Income before cumulative effect of
       accounting change........................      28        37        98        101
Cumulative effect of accounting change, net of
  income taxes..................................      --        --        --         57
                                                  ------    ------    ------     ------
     Net income.................................  $   28    $   37    $   98     $  158
                                                  ======    ======    ======     ======
Throughput volumes (BBtu/d)(1)..................   2,961     3,133     3,098      3,144
                                                  ======    ======    ======     ======
</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.

  Third Quarter 2003 Compared to Third Quarter 2002

     Operating revenues for the quarter ended September 30, 2003, were $10
million higher than in 2002. The increase was primarily due to increased
revenues of $7 million from our South System I and North System expansions,
which were placed in service in the second and third quarters of 2003 and
revenues of $2 million at our Elba Island facility. Also contributing to the
increase in 2003 were higher sales under natural gas purchase contracts of $2
million. During 2003, our average realized price on sales under natural gas
purchase contracts

                                        13
<PAGE>

was $4.99/Dth versus $3.12/Dth 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 significant profit 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 September 30, 2003, were $8
million higher than in 2002. The increase was primarily due to higher purchased
natural gas costs of $2 million due to higher prices in 2003. During 2003, our
average gas cost on these purchases was $4.95/Dth versus $3.12/Dth in 2002.
These gas costs result from the sales under natural gas purchase contracts
discussed above. Also contributing to the increase was a $2 million accrual for
environmental remediation costs in 2003 and operating costs of $1 million at our
Elba Island facility that are fully recovered in our rates pursuant to our
latest rate settlement. In addition, we incurred higher depreciation and ad
valorem and franchise taxes of $1 million due to higher levels of property,
plant and equipment resulting from system expansions.

     Other income for the quarter ended September 30, 2003 was $4 million lower
than in 2002. The decrease was primarily due to $4 million in lower equity
earnings on our investment in Citrus.

  Nine Months Ended 2003 Compared to Nine Months Ended 2002

     Operating revenues for the nine months ended September 30, 2003, were $38
million higher than in 2002. The increase was primarily due to increased
revenues of $15 million from our South System and North System expansions, which
were placed in service in the second and third quarters of 2003, revenues of $6
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 as described above of $13
million. During 2003, our average realized price on sales under natural gas
purchase contracts was $5.68/Dth versus $2.90/Dth in 2002.

     Operating expenses for the nine months ended September 30, 2003, were $23
million higher than in 2002. The increase was primarily due to higher purchased
natural gas costs of $12 million due to higher prices in 2003. During 2003, our
average gas cost on these purchases was $5.64/Dth versus $2.90/Dth in 2002.
These gas costs result from purchases under the natural gas purchase contracts
discussed above. Also contributing to the increase were operating costs of $3
million from our Elba Island facility that are fully recovered in our rates
pursuant to our latest rate settlement, $2 million in higher depreciation and ad
valorem and franchise taxes due to system expansion and a $2 million accrual for
environmental remediation costs. In addition, we had 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 nine months ended September 30, 2003, was $6 million
higher than in 2002. The increase was primarily due to $3 million in higher
equity earnings on our investment in Citrus and higher allowance for funds used
during construction in 2003 of $4 million due to higher levels of construction
in 2003.

INTEREST AND DEBT EXPENSE

     Interest and debt expense for the quarter and nine months ended September
30, 2003, was $10 million and $21 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

  Third Quarter 2003 Compared to Third Quarter 2002

     Affiliated interest income for the quarter ended September 30, 2003, was $1
million lower than the same period in 2002 due to lower average advances to El
Paso under its cash management program, offset by higher short-term interest
rates in 2003. The average advance balance for the third quarter of $461 million
in 2002 decreased to $112 million during the same period in 2003. The average
short-term interest rates for the third quarter increased from 1.8% in 2002 to
1.9% during the same period in 2003.

                                        14
<PAGE>

  Nine Months Ended 2003 Compared to Nine Months Ended 2002

     Affiliated interest income for the nine months ended September 30, 2003,
was $3 million lower than the same period in 2002 due to lower average advances
to El Paso under its cash management program and lower short-term interest rates
in 2003. The average advance balance for the nine months ended September 30,
2002 of $443 million decreased to $246 million during the same period in 2003.
The average short-term interest rates for the nine months ended decreased from
1.9% in 2002 to 1.6% during the same period in 2003.

INCOME TAXES

<Table>
<Caption>
                                                QUARTER ENDED          NINE MONTHS ENDED
                                                SEPTEMBER 30,            SEPTEMBER 30,
                                               ----------------        ------------------
                                               2003        2002        2003         2002
                                               ----        ----        -----        -----
                                                    (IN MILLIONS, EXCEPT FOR RATES)
<S>                                            <C>         <C>         <C>          <C>
Income taxes.................................  $11         $15          $46          $46
Effective tax rate...........................   28%         29%          32%          31%
</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. Phase I was placed
in service in September 2003. The targeted in service dates for Phase IA and
Phase II are November 2003 and 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 September 30, 2003 are
approximately $165 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 will
increase the design sendout rate of the facility 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, El Paso's contribution of
its 50 percent ownership interest in Citrus increased our overall market risks
as discussed in our Combined Historical Financial Statements. 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

                                        16
<PAGE>

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 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 Financial 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

     None.

                                        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: November 10, 2003                        /s/ JOHN W. SOMERHALDER II
                                            ------------------------------------
                                                   John W. Somerhalder II
                                             Chairman of the Board and Director
                                               (Principal Executive Officer)

Date: November 10, 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 Financial Officer pursuant to 18
          U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the
          Sarbanes-Oxley Act of 2002.
</Table>