EL PASO CORP/DE - 10-Q Quarterly Report

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

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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 MARCH 31, 2004

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 1-14365

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EL PASO CORPORATION
(Exact Name of Registrant as Specified in its Charter)

DELAWARE 76-0568816
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET 77002
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)

Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com

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 [ ] No [X]

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

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 $3 per share. Shares outstanding on October 22,
2004: 643,232,071

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EL PASO CORPORATION

TABLE OF CONTENTS

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

/d = per day
Bbl = barrels
BBtu = billion British thermal units
Bcf = billion cubic feet
Bcfe = billion cubic feet of natural gas equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas equivalents
MMBtu = million British thermal units
MMcf = million cubic feet
MMcfe = million cubic feet of natural gas equivalents
TBtu = trillion British thermal units
MW = megawatt

When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Oil includes natural gas liquids unless otherwise specified. Also,
when we refer to cubic feet measurements, all measurements are at a pressure of
14.73 pounds per square inch.

When we refer to "us", "we", "our", "ours", or "El Paso", we are describing
El Paso Corporation and/or our subsidiaries.

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
(UNAUDITED)

See accompanying notes.

1

EL PASO CORPORATION

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

See accompanying notes.

2

EL PASO CORPORATION

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

See accompanying notes.

3

EL PASO CORPORATION

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

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(1) Only individual line items in cash flows from operating activities have been
restated. Total cash flows from continuing operating, investing and
financing activities, as well as discontinued operations, were unaffected.

See accompanying notes.

4

EL PASO CORPORATION

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

See accompanying notes.

5

EL PASO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION AND SIGNIFICANT EVENTS UPDATE

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the U.S. 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 this Quarterly Report on Form 10-Q along with our 2003 Annual Report
on Form 10-K, which includes a summary of our significant accounting policies
and other disclosures. The financial statements as of March 31, 2004, and for
the quarters ended March 31, 2004 and 2003, are unaudited. We derived the
balance sheet as of December 31, 2003, from the audited balance sheet filed in
our 2003 Annual Report on Form 10-K. 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 businesses,
information for interim periods may not be indicative of the results of
operations for the entire year. Our results for the quarter ended March 31, 2003
have been restated to reflect the accounting impact of a reduction in our
historically reported proved natural gas and oil reserves and to revise the
manner in which we accounted for certain hedges, primarily those associated with
our anticipated natural gas production. These restatements are further discussed
in our 2003 Annual Report on Form 10-K. In addition, the 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
stockholders' equity.

Business Update

In December 2003, our management presented its Long-Range Plan for the
Company. This plan, among other things, defined our core businesses, established
a timeline for debt reductions and sales of non-core businesses and assets and
set financial goals for the future. During 2004, and through the filing date of
this Form 10-Q, we have made significant progress in the areas outlined in that
plan, including:

- completing or announcing sales of assets and investments of approximately
$3.3 billion (see Note 4);

- retiring or refinancing approximately $1.8 billion of maturing debt and
other obligations($576 million through March 31, 2004) (see Note 12);

- eliminating debt of $887 million ($72 million through March 31, 2004)
through the sale of assets to which the debt related (see Note 12); and

- finalizing the Western Energy Settlement, which substantially resolved
our principal exposure relating to the western energy crisis and
successfully raising funds to satisfy a significant portion of our
current obligations under that settlement (see Note 13).

Liquidity Update

We believe that the restatements of our historical financial statements
discussed above would have constituted events of default under our $3 billion
revolving credit facility and various other financing transactions; specifically
under the provisions of these arrangements related to representations and
warranties on the accuracy of our historical financial statements and on our
debt to total capitalization ratio. During 2004, we received several waivers on
our revolving credit facility and various other financing transactions to
address these issues. These waivers continue to be effective. We also received
an extension of time from various lenders until November 30, 2004 to file our
second quarter 2004 Form 10-Q, which we expect to meet. If we are unable to file
our second quarter 2004 Form 10-Q by that date and are not able to negotiate an
additional extension of the filing deadline, our revolving credit facility and
various other transactions could be

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accelerated. As part of obtaining our waivers, we also amended various
provisions of the revolving credit facility, including provisions related to
events of default and limitations on our ability, as well as that of our
subsidiaries, to repay indebtedness scheduled to mature after June 30, 2005.
Based upon a review of the covenants contained in our indentures and the
financing agreements of our other outstanding indebtedness, the acceleration of
our revolving credit facility could constitute an event of default under some of
our other debt agreements. In addition, three of our subsidiaries have
indentures associated with their public debt that contain $5 million
cross-acceleration provisions. These indentures state that should an event of
default occur resulting in the acceleration of other debt obligations of such
subsidiaries in excess of $5 million, the long-term debt obligations containing
such provisions could be accelerated. The acceleration of our debt would
adversely affect our liquidity position, and in turn, our financial condition.

Our $3 billion revolving credit facility matures on June 30, 2005. The
facility is collateralized by our equity interests in Tennessee Gas Pipeline
Company (TGP), El Paso Natural Gas Company (EPNG), ANR Pipeline Company (ANR),
Colorado Interstate Gas Company (CIG), Wyoming Interstate Company (WIC),
Southern Gas Storage Company, ANR Storage Company, as well as our common
interests in Enterprise, as further described below. With the sale of a majority
of our interests in GulfTerra Energy Partners, L.P. (GulfTerra) to Enterprise
Products Partners, L.P. (Enterprise) in September 2004, which included all of
our Series C and some of our common units, our borrowing capacity under this
facility was reduced by approximately $456 million to approximately $2.5 billion
in October 2004. Upon the closing of the merger of GulfTerra and Enterprise, our
remaining interests in GulfTerra's common units were converted into Enterprise
common units, which continue to collateralize this facility. We are in the
process of negotiating the refinancing of this facility as the combination of a
$1.75 billion, three year revolving credit facility and a five year term loan of
up to $1.25 billion and currently expect to be successful in this refinancing.
In the event we are unable to refinance our revolving credit facility by June
30, 2005, we would be obligated to repay any outstanding amounts, and make
alternative arrangements for the letters of credit issued pursuant to this
credit facility. As of September 30, 2004, we had no borrowings outstanding and
had approximately $1.1 billion of letters of credit issued under this credit
facility.

Although we expect to successfully refinance all or a portion of our
existing revolving credit facility, if we were unsuccessful, we believe we could
adjust our planned capital expenditures and increase our planned asset sales to
meet any shortfall in liquidity, and at the same time provide for our
operations. Further, if we repaid our obligations under the revolving credit
facility, some of the assets that currently collateralize this facility,
including our equity interests in TGP, EPNG, ANR, CIG, WIC Southern Gas Storage
Company, ANR Storage Company and our common units in Enterprise, could be used
to support new financing transactions. Although we cannot guarantee the outcome
of future events, we believe that this available collateral would be adequate to
provide financing sufficient to meet our liquidity needs.

Various other financing arrangements entered into by us and our
subsidiaries, including El Paso CGP and El Paso Production Holding Company,
include covenants that require us to file financial statements within specified
time periods. Non-compliance with such covenants does not constitute an
automatic event of default. Instead, such agreements are subject to acceleration
when the indenture trustee or the holders of at least 25 percent of the
outstanding principal amount of any series of debt provides notice to the issuer
of non-compliance under the indenture. In that event, the non-compliance can be
cured by filing financial statements within specified periods of time (between
30 and 90 days after receipt of notice depending on the particular indenture) to
avoid acceleration of repayment. The holders of El Paso Production Holding
Company's debt obligations waived its financial filing requirements through
December 31, 2004. The filing of our second quarter 2004 Form 10-Q and the first
and second quarter 2004 Forms 10-Q for these subsidiaries will cure the events
of non-compliance resulting from the failure to file financial statements. In
addition, neither we nor any of our subsidiaries have received a notice of the
default caused by our failure to file financial statements. In the event of an
acceleration, we may be unable to meet our payment obligations with respect to
the related indebtedness.

Furthermore, the material restatements of our financial statements for the
period ended December 31, 2001 as was reported in our 2003 Annual Report on Form
10-K could cause a default under the financing agreements entered into in
connection with our $950 million Gemstone notes due October 31, 2004.
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Currently, $748 million of Gemstone notes are outstanding. However, we currently
expect to repay these notes in full upon their maturity on October 31, 2004.

Our subsidiaries are a significant potential source of liquidity to us, and
they participate in our cash management program to the extent they are permitted
to do so under their financing agreements and indentures. Under the cash
management program, depending on whether participating subsidiaries have short-
term cash requirements or surpluses, we either provide cash to them or they
provide cash to us. If we were to incur an event of default under our credit
facilities, we would be unable to obtain cash from our pipeline subsidiaries,
which are the primary source of cash under this program. Currently, one of our
subsidiaries, CIG, is not advancing funds to us via our cash management program
due to its anticipated cash needs. In addition, our ownership in a number of our
subsidiaries and investments serves as collateral under our revolving credit
facility and our other financings. If the lenders under the credit facility or
those other financings were to exercise their rights to this collateral, we
could lose our ownership interest in these subsidiaries or be required to
liquidate these investments.

If, as a result of the events described above, we were subject to voluntary
or involuntary bankruptcy proceedings, our creditors could attempt to make
claims against our subsidiaries, including claims to substantively consolidate
those subsidiaries. We believe that claims to substantively consolidate our
subsidiaries would be without merit. However, there is no assurance that our
creditors would not advance such a claim in a bankruptcy proceeding. If our
creditors were able to substantively consolidate our subsidiaries, it could have
a material adverse effect on our financial condition and our liquidity.

We believe we will be able to meet our ongoing liquidity and cash needs
through a combination of sources, including cash on hand, cash generated from
our operations, borrowings under our revolving credit facility, proceeds from
asset sales, reduction of discretionary capital expenditures and the possible
issuance of long-term debt, and common or preferred equity securities. However,
a number of factors could influence our liquidity sources, as well as the timing
and ultimate outcome of our ongoing efforts and plans.

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2. SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are discussed in our 2003 Annual Report
on Form 10-K. The information below provides updating information or required
interim disclosures with respect to those policies or disclosure where our
policies have changed.

Stock-Based Compensation

We account for our stock-based compensation plans using the intrinsic value
method under the provisions of Accounting Principles Board Opinion (APB) No. 25,
Accounting for Stock Issued to Employees, and its related interpretations. Had
we accounted for our stock option grants using Statement of Financial Accounting
Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, rather than
APB No. 25, the loss and per share impacts of stock-based compensation on our
financial statements would have been different. The following table shows the
impact on net loss and loss per share had we applied SFAS No. 123 for the
quarters ended March 31:

Consolidation of Variable Interest Entities

In January 2003, the FASB issued Financial Interpretation (FIN) No. 46,
Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51.
This interpretation defines a variable interest entity as a legal entity whose
equity owners do not have sufficient equity at risk or a controlling financial
interest in the entity. This standard requires a company to consolidate a
variable interest entity if it is allocated a majority of the entity's losses or
returns, including fees paid by the entity. In December 2003, the FASB issued
FIN No. 46-R, which amended FIN No. 46 to extend its effective date until the
first quarter of 2004 for all types of entities, except special purpose
entities. In addition, FIN No. 46-R limited the scope of FIN No. 46 to exclude
certain joint ventures or other entities that meet the characteristics of
businesses.

On January 1, 2004, we adopted this standard. Upon adoption, we
consolidated Blue Lake Gas Storage Company and several other minor entities and
deconsolidated a previously consolidated entity, EMA Power Kft. The overall
impact of these actions is described in the following table:

9

Blue Lake Gas Storage owns and operates a 47 Bcf gas storage facility in
Michigan. One of our subsidiaries operates the natural gas storage facility and
we inject and withdraw all natural gas stored in the facility. We own a 75
percent equity interest in Blue Lake. This entity has $12 million of third party
debt as of March 31, 2004 that is non-recourse to us. We consolidated Blue Lake
because we are allocated a majority of Blue Lake's losses and returns through
our equity interest in Blue Lake.

EMA Power Kft owns and operates a 69 gross MW dual-fuel-fired power
facility located in Hungary. We own a 50 percent equity interest in EMA. Our
equity partner has a 50 percent interest in EMA, supplies all of the fuel
consumed and purchases all of the power generated by the facility. Our exposure
to this entity is limited to our equity interest in EMA, which was approximately
$31 million as of March 31, 2004. We deconsolidated EMA because our equity
partner is allocated a majority of EMA's losses and returns through its equity
interest and its fuel supply and power purchase agreements with EMA.

We have significant interests in a number of other variable interest
entities. We were not required to consolidate these entities under FIN No. 46
and, as a result, our method of accounting for these entities did not change.
These entities consist primarily of 25 equity investments held in our Power
segment that have interests in power generation and transmission facilities with
a total generating capacity of approximately 8,100 gross MW. We operate many of
these facilities but do not supply a significant portion of the fuel consumed or
purchase a significant portion of the power generated by these facilities. The
long-term debt issued by these entities is recourse only to the power project.
As a result, our exposure to these entities is limited to our equity investments
in and advances to the entities ($1.7 billion as of March 31, 2004) and our
guarantees and other agreements associated with these entities (a maximum of
$221 million as of March 31, 2004).

During our adoption of FIN 46, we attempted to obtain financial information
on several potential variable interest entities but were unable to obtain that
information. The most significant of these entities is the Cordova power project
which is the counterparty to our largest tolling arrangement. Under this tolling
arrangement, we supply on average a total of 54,000 MMBtu of natural gas per day
to the entity's two 250 gross MW power facilities and are obligated to market
the power generated by those facilities. In addition, we pay that entity a
capacity charge that ranges from $25 million to $30 million per year related to
its power plants. The following is a summary of the financial statement impacts
of our transactions with this entity for the quarters ended March 31:

Accounting for Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, Accounting for Asset
Retirement Obligations. This standard required that we record a liability for
retirement and removal costs of long-lived assets used in our businesses. In the
first quarter of 2003, we recorded a charge as a cumulative effect of an
accounting change of approximately $9 million, net of income taxes related to
its adoption.

New Accounting Pronouncement Not Yet Adopted

In September 2004, the SEC issued Staff Accounting Bulletin No. 106. This
pronouncement will require companies that use the full cost method for
accounting for their oil and gas producing activities to include an estimate of
future asset retirement costs to be incurred as a result of future development
activities on proved reserves in their calculation of depreciation, depletion
and amortization. This pronouncement will also require these companies to
exclude any future cash outflows associated with settling asset retirement
liabilities from their full cost ceiling test calculation. This standard will
also require these companies to disclose the impact of

10

their asset retirement obligations on their oil and gas producing activities,
ceiling test calculations and depreciation, depletion and amortization
calculations. We will adopt the provisions of this pronouncement in the fourth
quarter of 2004 and are currently evaluating its impact, if any, on our
consolidated financial statements.

3. ACQUISITIONS AND CONSOLIDATIONS

Chaparral Investors, L.L.C. As discussed more completely in our 2003
Annual Report on Form 10-K, we acquired Chaparral in a series of transactions
(also referred to as a step acquisition). We reflected Chaparral's results of
operations in our income statement as though we acquired it on January 1, 2003.
Although this did not change our reported net income for the first quarter of
2003, it did impact the individual components of our income statement by
increasing our revenues by $76 million, operating expenses by $80 million,
earnings (losses) from unconsolidated affiliates by $55 million, interest
expense by $67 million and decreasing distributions on preferred interests in
subsidiaries by $18 million and other income by $2 million.

During the first quarter of 2003, as a result of an additional investment
in Limestone Electron Trust (Limestone), coupled with a number of developments
including a general decline in power prices, declines in our credit ratings as
well as those of our counterparties, adverse developments at several of
Chaparral's projects, our announced exit from the power contract restructuring
business and generally weaker economic conditions in the unregulated power
industry, we determined that the fair value of Chaparral (based on its
discounted expected net cash flows) was less than our carrying value of the
investment. As a result, we recorded an impairment of $207 million on Chaparral,
before income taxes, during the quarter ended March 31, 2003.

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4. DIVESTITURES

Sales of Assets and Investments

During 2004, we completed and announced the sale of a number of assets and
investments in each of our business segments. The following table summarizes the
proceeds from these sales:

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(1) Sales that have not been completed are estimates, subject to customary
regulatory approvals, final negotiations and other conditions.
(2) These sales were completed after March 31, 2004.
(3) These sales were completed as of March 31, 2004.
(4)We sold all of our Canadian onshore natural gas and oil properties in the
first quarter of 2004. We sold our interests in Nova Scotia in the third
quarter of 2004.
(5) The sales of 22 of these plants were completed after March 31, 2004.
(6)Proceeds exclude returns of invested capital and cash transferred with the
assets sold and include costs incurred in preparing assets for disposal.
These items decreased our sales proceeds $11 million for the quarter ended
March 31, 2004.

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(1) Proceeds include costs incurred in preparing assets for disposal and exclude
returns of invested capital and cash transferred with the assets sold. These
items increased our sales proceeds by $19 million for the quarter ended
March 31, 2003.

See Notes 6 and 17 for a discussion of gains, losses and asset impairments
related to the sales above.

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Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, we classify assets being disposed of as held for sale or, if
appropriate, discontinued operations if they have received appropriate approvals
by our management or Board of Directors and have met other criteria. The
following table details the items that have been reflected as current assets and
liabilities held for sale in our balance sheets as of March 31, 2004 and
December 31, 2003.

In August 2004, our Board of Directors authorized the sale of our Indian
Springs natural gas gathering and processing assets in our Field Services
segment. We currently expect to incur an impairment charge of approximately $13
million related to these assets, and will classify them as assets held for sale
subsequent to March 31, 2004.

Discontinued Operations

Petroleum Markets. During the first quarter of 2003, our Board of
Directors approved the sales of our Eagle Point refinery, our asphalt business,
our Florida terminal, tug and barge business and our lease crude operations. In
June 2003, our Board of Directors authorized the sale of our remaining petroleum
markets operations, including our Aruba refinery, our Unilube blending
operations, our domestic and international terminalling facilities and our
petrochemical and chemical plants. Based on our intent to dispose of these
operations, we were required to adjust these assets to their estimated fair
value. As a result, we recognized a pre-tax impairment charge of $350 million
during the first quarter of 2003 related primarily to our Eagle Point refinery
and several of our chemical assets. These impairments were based on a comparison
of the carrying value of these assets to their estimated fair value, less
selling costs. We also recorded realized gains of approximately $55 million in
the first quarter of 2003 from the sale of our Corpus Christi refinery and
Florida terminalling and marine assets.

In the first and second quarters of 2004, we completed the sales of our
Aruba and Eagle Point refineries for $880 million and used a portion of the
proceeds to repay $370 million of debt associated with the Aruba refinery. We
expect to complete the sale of our remaining petroleum markets operations in
2004. In addition, in the first quarter of 2004, we reclassified our petroleum
ship charter operations from discontinued operations to continuing operations in
our financial statements based on our decision to retain these operations. Our
financial statements for all periods presented reflect this change.

Coal Mining. In 2002, our Board of Directors authorized the sale of our
coal mining operations. These operations consisted of fifteen active underground
and two surface mines located in Kentucky, Virginia and West Virginia. The sale
of these operations was completed in 2003 for $92 million in cash and $24
million in notes receivable, which were settled in the second quarter of 2004.
We did not record a significant gain or loss on these sales.

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In the second quarter of 2004, our Board of Directors approved exiting our
Canadian and other international natural gas and oil operations. We will report
these operations as discontinued operations beginning in the second quarter of
2004, which will not have a material impact to our balance sheet.

Our petroleum markets and coal mining operations are classified as
discontinued operations in our financial statements for all of the historical
periods presented. All of the assets and liabilities of these discontinued
businesses are classified as current assets and liabilities as of March 31,
2004. The summarized financial results and financial position data of our
discontinued operations were as follows:

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5. RESTRUCTURING COSTS

As a result of actions taken in 2003 and 2004, we incurred organizational
restructuring costs included in our operation and maintenance expense. By
segment, these charges were as follows:

Our 2004 restructuring costs consisted of employee severance costs which
included severance payments and costs for pension benefits settled and curtailed
under existing benefit plans. During the first quarter of 2004, we eliminated
approximately 350 full-time positions from our continuing businesses and
approximately 1,100 positions related to discontinued businesses. As of
September 30, 2004, substantially all of the 2004 employee severance, retention
and transition costs had been paid.

Our 2003 restructuring costs were incurred as part of our ongoing liquidity
enhancement and cost reduction efforts. Employee severance costs included
severance payments and costs for pension benefits settled and curtailed under
existing benefit plans. The contract termination costs consisted of $44 million
related to amounts paid for canceling or restructuring our obligations for
chartering ships to transport liquefied natural gas (LNG) from supply areas to
domestic and international market centers.

Office Relocation and Consolidation

In May 2004, we began consolidating our Houston-based operations into one
location. We anticipate the consolidation will be substantially complete by the
end of 2004. As a result, we will establish an accrual to record a liability for
our obligations under the terms of the vacated leases in the period that the
space is available for subleasing. We currently lease approximately 912,000
square feet of office space in the buildings we are vacating under various
leases with terms that expire in 2004 through 2014. We estimate the total
accrual for our liability will be approximately $80 million to $100 million. At
the time the decision was made to consolidate our Houston-based operations,
approximately 26,000 square feet was vacant and available for subleasing at
which time we accrued an obligation of approximately $1 million. During the
third quarter of 2004, we vacated approximately 211,000 square feet and recorded
a liability of approximately $30 million. In addition, we subleased
approximately 125,000 square feet in the third quarter of 2004. Approximately $3
million in actual moving expenses related to the relocation will be expensed in
the period that they are incurred. These amounts will be reflected in our
Corporate operations.

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6. LOSS ON LONG-LIVED ASSETS

Our loss on long-lived assets consists of realized gains and losses on
sales of long-lived assets and impairments of long-lived assets, goodwill and
other intangibles that are a part of our continuing operations. During each of
the quarters ended March 31, our loss on long-lived assets was as follows:

Net Realized Loss

Our 2004 net realized loss was primarily related to an $85 million loss
associated with the sale of natural gas and oil properties in Canada in our
Production segment. Our 2003 net realized loss was primarily related to an $8
million realized loss related to the sale of an aircraft in our Corporate
operations, partially offset by a $4 million realized gain associated with the
sale of the Mt. Carmel power plant in our Power segment.

Asset Impairments

Our 2004 asset impairments primarily occurred in our Power segment, which
included a $98 million impairment related to the sale of our subsidiary, UCF,
which owns a restructured power contract and a $135 million impairment related
to our Manaus and Rio Negro power plants in Brazil. The impairments in Brazil
were primarily due to events in the first quarter of 2004 that may make it
difficult to extend their power sales agreements that expire in 2005 and 2006.
See Note 13 for a further discussion of these matters. Our Production segment
also incurred an $8 million impairment in 2004 on a Canadian asset that was not
part of our full cost pool. Our 2003 impairment charges related to the sale of
non-full cost pool assets in Canada and an impairment of LNG assets due to our
plan to reduce our involvement in this business.

7. CEILING TEST CHARGES

Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to determine whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties, net of related income tax effects.

For the quarter ended March 31, 2004, we recorded ceiling test charges of
approximately $24 million and $4 million related to our Canadian and Indonesian
full cost pools. During the first quarter of 2004, we sold all of our Canadian
onshore natural gas and oil properties. The ceiling test charge in Canada
related to our remaining operations in Nova Scotia where, in the first quarter
of 2004, we drilled an exploratory well that was not commercially viable.

We use financial instruments to hedge against the volatility of natural gas
and oil prices. The impact of these hedges was considered in performing our
ceiling test calculations and will be factored into future ceiling test
calculations. The charges for our international full cost pools would not have
materially changed had the impact of our hedges not been included in calculating
our ceiling test charges since we do not significantly hedge our international
production activities.

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8. INCOME TAXES

Our income tax benefit and effective income tax rate were $44 million and
23 percent for the quarter ended March 31, 2004, compared to an income tax
benefit and effective income tax rate of $106 million and 35 percent for the
quarter ended March 31, 2003. We compute our quarterly taxes under the effective
tax rate method based on applying an anticipated annual effective rate to our
year-to-date income or loss except for significant unusual or extraordinary
transactions. Income taxes for significant unusual or extraordinary transactions
are computed and recorded in the period that the specific transaction occurs.
During the first quarter of 2004, our overall effective tax rate on continuing
operations was lower than the statutory rate due primarily to the impairments of
certain of our foreign investments for which there is no corresponding tax
benefit.

For the year ended December 31, 2004 we currently expect our effective tax
rate to be significantly different from the statutory rate of 35 percent based
on the closing of the GulfTerra transaction in September 2004. The sale of our
interests in GulfTerra will result in a significant tax gain (versus a much
lower book gain) and significant tax expense due to the non-deductibility of
goodwill written off as a result of the transaction. We believe the impact of
this non-deductible goodwill will increase our tax expense (or reduce our tax
benefit) by approximately $139 million.

Proposed tax legislation has been introduced in the U.S. Senate which would
disallow deductions for certain settlements made to or on behalf of governmental
entities. If enacted, this tax legislation could impact the deductibility of the
Western Energy Settlement and could result in a write-off of some or all of the
associated tax assets. In such event, our tax expense would increase. Our total
tax assets related to the Western Energy Settlement were $400 million as of
March 31, 2004.

18

9. EARNINGS PER SHARE

Our basic and diluted loss per share were as follows for the quarters ended
March 31:

For both of the quarters ended March 31, 2004 and March 31, 2003, there
were a total of 16 million of potentially dilutive securities excluded from the
determination of average common shares outstanding because we had net losses
from continuing operations in these periods. The excluded securities included
stock options, trust preferred securities and convertible debentures.

10. PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of the derivatives used
in our price risk management activities as of March 31, 2004 and December 31,
2003. In the table, derivatives designated as hedges primarily consist of
instruments used to hedge our natural gas and oil production. Derivatives from
power contract restructuring activities relate to power purchase and sale
agreements that arose from our activities in that business and other
commodity-based derivative contracts relate to our historical energy trading
activities. Interest rate and foreign currency hedging derivatives consist of
instruments to hedge our interest rate and currency risks on long-term debt.

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

(1) Includes $864 million of assets from derivative contracts that we sold in
the second quarter of 2004. See Note 6 for a discussion of the impairment
related to this sale.

(2) During the quarter ended March 31, 2004, we entered into new cross currency
hedge transactions that convert E50 million of our fixed rate
Euro-denominated debt into $61 million of floating rate debt. After March
31, 2004, we entered into other cross currency hedge transactions that
convert another E50 million of fixed rate debt into $60 million of floating
rate debt.

(3) Included in both current and non-current assets and liabilities on the
balance sheet.

19

11. INVENTORY

We have the following inventory on our balance sheets:

12. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES

We had the following long-term and short-term borrowings and other
financing obligations:

Long-Term Financing Obligations

From January 1, 2004 through the date of this filing, we had the following
changes in our long-term financing obligations:

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

(1) This debt was consolidated as a result of adopting FIN 46 (see Note 2).

(2) This debt was eliminated when we sold our interest in Mohawk River Funding
IV.

(3) This debt was eliminated when we sold our interests in UCF.

In October 2004, we entered into an agreement, effective August 2004, with
two affiliates of Enron that would liquidate two existing swap agreements in
exchange for approximately $213 million of 6.5%, one year notes. The transaction
is pending approval by the bankruptcy court. As of March 31, 2004, the balance
of these swaps was a liability of $245 million, which is reflected in other
current and other non-current liabilities in our balance sheet.

Credit Facilities

We maintain a $3 billion revolving credit facility, with a $1.5 billion
letter of credit sublimit, which matures on June 30, 2005. This credit facility
has a borrowing cost of LIBOR plus 350 basis points, letter of credit fees of
350 basis points and commitment fees of 75 basis points on the unused amounts of
the facility. This revolving credit facility and other financing arrangements
are collateralized by our ownership in EPNG, TGP, ANR, CIG, WIC, ANR Storage
Company, Southern Gas Storage Company, as well as our common units in
Enterprise, as further described below. With the sale of a majority of our
interests in GulfTerra to Enterprise in September 2004, which included all of
our Series C and some of our common units, our borrowing capacity under this
facility was reduced by approximately $456 million to approximately $2.5 billion
in October 2004. Upon the closing of the merger of GulfTerra and Enterprise, our
remaining interests in GulfTerra's common units were converted into Enterprise's
common units which continue to collateralize this facility. Amounts outstanding
under the revolving credit facility as of March 31, 2004, are classified as non-
current in our balance sheet, based on the facility's maturity date. As of March
31, 2004, there were $600 million of borrowings outstanding and approximately
$1.1 billion of letters of credit issued under the facility. In September 2004,
we repaid the remaining $600 million outstanding under this facility. As of
September 30, 2004, our borrowing availability under this facility was $1.8
billion. We are in the process of negotiating the refinancing of this facility
as the combination of a $1.75 billion three year revolving credit facility and a
five year term loan of up to $1.25 billion and currently expect to be successful
in this refinancing.

The availability of borrowings under the revolving credit facility and
other borrowing agreements is subject to various conditions described below,
which we currently meet. These conditions include compliance with the financial
covenants and ratios required by those agreements, absence of default under the
agreements, and continued accuracy of the representations and warranties
contained in the agreements.

Restrictive Covenants

Our restrictive covenants are discussed in our 2003 Annual Report on Form
10-K. For an update of matters that have or could impact these covenants,
including the restatement of our historical financial statements and associated
waivers obtained, see Note 1, Liquidity Update of this Quarterly Report on Form
10-Q.

21

Letters of Credit

We enter into letters of credit in the ordinary course of our operating
activities. As of March 31, 2004, we had outstanding letters of credit of
approximately $1.2 billion. Of the letters of credit outstanding, approximately
$1.1 billion was outstanding under our revolving credit facility. Included in
this amount were $0.6 billion of letters of credit securing our recorded
obligations related to price risk management activities. Of the outstanding
letters of credit, $72 million was supported with cash collateral.

13. COMMITMENTS AND CONTINGENCIES

Legal Proceedings and Government Investigations

Western Energy Settlement. In June 2004, our master settlement agreement,
along with other separate settlement agreements, became effective with a number
of public and private claimants, including the states of California, Washington,
Oregon and Nevada to resolve the principal litigation, claims and regulatory
proceedings arising out of the sale or delivery of natural gas and/or
electricity to the western U.S. (the Western Energy Settlement). As part of the
Western Energy Settlement, we agreed, among other things, to make various cash
payments and modify an existing power supply contract.

We also entered into a Joint Settlement Agreement or JSA where we agreed to
provide structural relief to the settling parties. In the JSA, we agreed to do
the following:

- Subject to the conditions in the settlement; (1) make 3.29 Bcf/d of
primary firm pipeline capacity on our EPNG system available to California
delivery points during a five year period from the date of settlement,
but only if shippers sign firm contracts for 3.29 Bcf/d of capacity with
California delivery points; (2) maintain facilities sufficient to deliver
3.29 Bcf/d to the California delivery points; and (3) not add any firm
incremental load to our EPNG system that would prevent it from satisfying
its obligation to provide this capacity;

- Construct a new 320 MMcf/d, Line 2000 Power-Up expansion project and
forego recovery of the cost of service of this expansion until EPNG's
next rate case before the FERC;

- Clarify the rights of Northern California shippers to recall some of
EPNG's system capacity (Block II capacity) to serve markets in PG&E's
service area; and

- With limited exceptions, bar any of our affiliated companies from
obtaining additional firm capacity on our EPNG pipeline system during a
five year period from the effective date of the settlement.

In June 2003, we filed the JSA described above with the FERC in resolution
of the CPUC complaint proceeding discussed below. In November 2003, the FERC
approved the JSA with minor modifications. Our east of California shippers filed
requests for rehearing, which were denied by the FERC on March 30, 2004. Certain
shippers have appealed the FERC's ruling to the U.S. Court of Appeals for the
District of Columbia.

During the fourth quarter of 2002, we recorded an $899 million pretax
charge related to the Western Energy Settlement. In the second quarter of 2003,
we recorded an additional pretax charge of $104 million, based upon reaching
definitive settlement agreements, and also established an escrow account for
amounts to be funded by us under this settlement upon final approval by various
parties. As of March 31, 2004, we had funded $558 million to this escrow account
which was reflected as an increase in restricted cash in our balance sheet and a
reduction of our cash flows from investing activities. Included in this amount
were $74 million of proceeds from the issuance of common stock in January 2004.

22

Below is an analysis of our obligations related to the Western Energy
Settlement as of March 31, 2004 (amounts are discounted):

Once effective in June 2004, $602 million was released to the settling
parties, which includes the escrowed funds discussed above. The payment of $602
million will be reflected as a reduction of our cash flows from operations in
the second quarter of 2004. After the release of these funds, our remaining
obligation under the Western Energy Settlement consists of the price reduction
under a power supply contract over its remaining term and the 20-year cash
payment obligation indicated in the table above. In connection with the Western
Energy Settlement, we provided collateral in the form of natural gas and oil
properties to secure our remaining cash payment obligation. The initial
collateral requirement was approximately $592 million and will be reduced as
payments under our 20 year obligation are made in the future. For an issue
regarding the potential tax deductibility of our Western Energy Settlement
charges, see Note 8.

We are also a defendant in a number of additional lawsuits, pending in
several Western states, relating to various aspects of the 2000-2001 Western
energy crisis. We do not believe these additional lawsuits, either individually
or in the aggregate, will have a material impact on us.

CPUC Complaint Proceeding Docket No. RP00-241-000. In April 2000, the CPUC
filed a complaint under Section 5 of the Natural Gas Act (NGA) with FERC
alleging that EPNG's sale of approximately 1.2 Bcf of capacity to its affiliate,
EPME, raised issues of market power and was a violation of the FERC's marketing
affiliate regulations and asked that the contracts be voided. In the spring and
summer of 2001, hearings were held before an ALJ to address the market power
issue and the affiliate issue. On November 19, 2003, the FERC approved the JSA,
which is part of the Western Energy Settlement and vacated the ALJ's initial
decisions. That decision was upheld by the FERC in a rehearing order issued on
March 30, 2004. On April 9, 2004, certain shippers appealed both FERC orders on
this matter to the U.S. Court of Appeals for the District of Columbia Circuit.

Shareholder Class Action Suits. Beginning in July 2002, twelve purported
shareholder class action lawsuits alleging violations of federal securities laws
have been filed against us and several of our former officers. Eleven of these
lawsuits are now consolidated in federal court in Houston before a single judge.
The twelfth lawsuit, filed in the Southern District of New York, was dismissed
in light of similar claims being asserted in the consolidated suits in Houston.
The lawsuits generally challenge the accuracy or completeness of press releases
and other public statements made during 2001 and 2002. Two shareholder
derivative actions have also been filed which generally allege the same claims
as those made in the consolidated shareholder class action lawsuits. One, which
was filed in federal court in Houston in August 2002, has been consolidated with
the shareholder class actions pending in Houston, and has been stayed. The
second shareholder derivative lawsuit, filed in Delaware State Court in October
2002, generally alleges the same claims as those made in the consolidated
shareholder class action lawsuit and also has been stayed. Two other shareholder
derivative lawsuits are now consolidated in state court in Houston. Both
generally allege that manipulation of California gas supply and gas prices
exposed us to claims of antitrust conspiracy, FERC penalties and erosion of
share value. Our costs and legal exposure related to these lawsuits and claims
are not currently determinable.

Beginning in February 2004, seventeen purported shareholder class action
lawsuits alleging violations of federal securities laws were filed against us
and several individuals in federal court in Houston. The lawsuits generally
allege that our reporting of natural gas and oil reserves was materially false
and misleading. Each of these lawsuits recently has been consolidated into the
shareholder lawsuits described in the immediately preceding paragraph. An
amended complaint in this consolidated securities lawsuit was filed on July 2,
2004.

23

In September 2004, a new derivative lawsuit was filed in federal court in
Houston against certain of El Paso's current and former directors and officers.
The claims in this new derivative lawsuit are for the most part the same claims
made in the July 2004 consolidated amended complaint in the securities lawsuit.
The one distinction is that the new derivative lawsuit includes a claim for
compensation disgorgement under Sarbanes-Oxley Act of 2002 against certain of
the individually named defendants.

ERISA Class Action Suit. In December 2002, a purported class action
lawsuit was filed in federal court in Houston alleging generally that our direct
and indirect communications with participants in the El Paso Corporation
Retirement Savings Plan included misrepresentations and omissions that caused
members of the class to hold and maintain investments in El Paso stock in
violation of the Employee Retirement Income Security Act (ERISA). That lawsuit
recently was amended to include allegations relating to our reporting of natural
gas and oil reserves. Our costs and legal exposure related to this lawsuit are
not currently determinable; however, we believe this matter will be covered by
insurance.

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

Will Price (formerly Quinque). A number of our subsidiaries are named as
defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et
al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs
allege that the defendants mismeasured natural gas volumes and heating content
of natural gas on non-federal and non-Native American lands and seek to recover
royalties that they contend they 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 practices. No monetary relief has been specified in
this case. Plaintiffs' motion for class certification of a nationwide class of
natural gas working interest owners and natural gas royalty owners was denied on
April 10, 2003. Plaintiffs were granted leave to file a Fourth Amended Petition,
which narrows the proposed class to royalty owners in wells in Kansas, Wyoming
and Colorado and removes claims as to heating content. A second class action has
since been filed as to the heating content claims. Our costs and legal exposure
related to these lawsuits and claims are not currently determinable.

MTBE. In compliance with the 1990 amendments to the Clean Air Act, we used
the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our
gasoline. We have also produced, bought, sold and distributed MTBE. A number of
lawsuits have been filed throughout the U.S. regarding MTBE's potential impact
on water supplies. We and our subsidiaries are currently one of several
defendants in over 50 such lawsuits nationwide, which have been consolidated for
pre-trial purposes in multi-district litigation in the U.S. District Court for
the Southern District of New York. The plaintiffs generally seek remediation of
their groundwater, prevention of future contamination, a variety of compensatory
damages, punitive damages, attorney's fees, and court costs. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

Government Investigations

Power Restructuring. In October 2003, we announced that the SEC had
authorized the staff of the Fort Worth Regional Office to conduct an
investigation of certain aspects of our periodic reports filed with the

24

SEC. The investigation appears to be focused principally on our power plant
contract restructurings and the related disclosures and accounting treatment for
the restructured power contracts, including in particular the Eagle Point
restructuring transaction completed in 2002. We are cooperating with the SEC
investigation.

Wash Trades. In June 2002, we received an informal inquiry from the SEC
regarding the issue of round trip trades. Although we do not believe any round
trip trades occurred, we submitted data to the SEC in July 2002. In July 2002,
we received a federal grand jury subpoena for documents concerning round trip or
wash trades. We have complied with those requests. We are also cooperating with
the U.S. Attorney regarding an investigation of specific transactions executed
in connection with our production hedges.

Price Reporting. In October 2002, the FERC issued data requests regarding
price reporting of transactional data to the energy trade press. We provided
information to the FERC, the Commodity Futures Trading Commission (CFTC) and the
U.S. Attorney in response to their requests. In the first quarter of 2003, we
announced a settlement between EPME and the CFTC of the price reporting matter
providing for the payment by EPME of a civil monetary penalty of $20 million,
$10 million of which is payable in 2006, without admitting or denying the CFTC
holdings in the order. We are continuing to cooperate with the U.S. Attorney's
investigation of this matter.

Reserve Revisions. In March 2004, we received a subpoena from the SEC
requesting documents relating to our December 31, 2003 natural gas and oil
reserve revisions. We have also received federal grand jury subpoenas for
documents with regard to these reserve revisions. We are cooperating with the
SEC's and the U.S. Attorney's investigations into the matter.

CFTC Investigation. In April 2004, our affiliates elected to voluntarily
cooperate with the CFTC in connection with the CFTC's industry-wide
investigation of activities affecting the price of natural gas in the fall of
2003. Specifically, our affiliates provided information relating to storage
reports provided to the Energy Information Administration for the period of
October 2003 through December 2003. On August 30, 2004, the CFTC announced they
had completed the investigation and found no evidence of wrongdoing.

Iraq Oil Sales. In September 2004, The Coastal Corporation (now known as
El Paso CGP Company, which we acquired in January 2001) received a subpoena from
the grand jury of the U.S. District Court for the Southern District of New York
to produce records regarding the United Nation's Oil for Food Program governing
sales of Iraqi oil. The subpoena seeks various records relating to transactions
in oil of Iraqi origin during the period from 1995 to 2003. Recent press reports
indicate that other government entities, including various Congressional
committees, are investigating the Oil for Food Program. We received inquiries
from one of these committees.

On September 30, 2004, the Special Advisor to the Director of Central
Intelligence issued a report on the Iraqi regime, including the Oil for Food
Program. In part, the report found that the Iraqi regime earned kick backs or
surcharges associated with the Oil for Food Program. The report did not name
U.S. companies or individuals for privacy reasons, but according to various news
reports congressional sources have identified The Coastal Corporation and the
former chairman and CEO of Coastal, among others, as having purchased Iraqi
crude during the period when allegedly improper surcharges were assessed by
Iraq.

We are continuing in the process of collecting and reviewing documents
responsive to the subpoena.

Carlsbad. In August 2000, a main transmission line owned and operated by
EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico.
Twelve individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Probable Violation and Proposed Civil Penalty to EPNG. The Notice alleged five
violations of DOT regulations, proposed fines totaling $2.5 million and proposed
corrective actions. EPNG has fully accrued for these fines. In October 2001,
EPNG filed a response with the Office of Pipeline Safety disputing each of the
alleged violations. In December 2003, the matter was referred to the Department
of Justice.

After a public hearing conducted by the National Transportation Safety
Board (NTSB) on its investigation into the Carlsbad rupture, the NTSB published
its final report in April 2003. The NTSB stated that it had determined that the
probable cause of the August 2000 rupture was a significant reduction in pipe
wall thickness due to severe internal corrosion, which occurred because EPNG's
corrosion control program

25

"failed to prevent, detect, or control internal corrosion" in the pipeline. The
NTSB also determined that ineffective federal preaccident inspections
contributed to the accident by not identifying deficiencies in EPNG's internal
corrosion control program.

On November 1, 2002, EPNG received a federal grand jury subpoena for
documents related to the Carlsbad rupture and cooperated fully in responding to
the subpoena. That subpoena has since expired. In December 2003 and January
2004, eight current and former employees were served with testimonial subpoenas
issued by the grand jury. Six individuals testified in March 2004. On April 2,
2004, we and EPNG received a new federal grand jury subpoena requesting
additional documents. We have responded fully to this subpoena. Two additional
employees testified before the grand jury in June 2004.

A number of personal injury and wrongful death lawsuits were filed against
EPNG in connection with the rupture. All of these lawsuits have been settled,
with settlement payments fully covered by insurance. In connection with the
settlement of the cases, EPNG contributed $10 million to a charitable foundation
as a memorial to the families involved. The contribution was not covered by
insurance.

Parties to four of the settled lawsuits have since filed an additional
lawsuit titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas on
November 20, 2002, seeking additional sums based upon their interpretation of
earlier settlement agreements. This matter has been settled and dismissed. In
addition, a lawsuit entitled Baldonado et. al. v. EPNG was filed on June 30,
2003 in state court in Eddy County, New Mexico on behalf of 23 firemen and EMS
personnel who responded to the fire and who allegedly have suffered
psychological trauma. This case was dismissed by the trial court. The appeals
court initially issued a notice dismissing all claims. This decision was
appealed and the appeals court has agreed to hear this matter. Briefs will be
filed by the end of this year. Our costs and legal exposure related to the
Baldonado lawsuit are not currently determinable, however we believe this matter
will be fully covered by insurance.

In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business. There are also other regulatory
rules and orders in various stages of adoption, review and/or implementation,
none of which we believe will have a material impact on us.

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As this information becomes available, or other relevant developments occur, we
will adjust our accrual amounts accordingly. While there are still uncertainties
related to the ultimate costs we may incur, based upon our evaluation and
experience to date, we believe our current reserves are adequate. As of March
31, 2004, we had approximately $1.2 billion accrued for all outstanding legal
matters, which includes the accruals related to our Western Energy Settlement.

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 March 31,
2004, we had accrued approximately $401 million, including approximately $394
million for expected remediation costs and associated onsite, offsite and
groundwater technical studies, and approximately $7 million for related
environmental legal costs, which we anticipate incurring through 2027. Of the
$401 million accrual, $158 million was reserved for facilities we currently
operate, and $243 million was reserved for non-operating sites (facilities that
are shut down or have been sold) and superfund sites.

Our reserve estimates range from approximately $401 million to
approximately $591 million. Our accrual represents a combination of two
estimation methodologies. First, where the most likely outcome can be reasonably
estimated, that cost has been accrued ($97 million). Second, where the most
likely outcome cannot be estimated, a range of costs is established ($304
million to $494 million) and if no one amount in

26

that range is more likely than any other, the lower end of the range has been
accrued. By type of site, our reserves are based on the following estimates of
reasonably possible outcomes.

Below is a reconciliation of our accrued liability from January 1, 2004, to
March 31, 2004 (in millions):

Balance as of January 1, 2004............................... $412
Payments for remediation activities......................... (10)
Other changes, net.......................................... (1)
----
Balance as of March 31, 2004................................ $401
====

For 2004, we estimate that our total remediation expenditures will be
approximately $57 million. In addition, we expect to make capital expenditures
for environmental matters of approximately $86 million in the aggregate for the
years 2004 through 2008. These expenditures primarily relate to compliance with
clean air regulations.

Internal PCB Remediation Project. Since 1988, TGP, our subsidiary, has
been engaged in an internal project to identify and address the presence of
polychlorinated biphenyls (PCBs) and other substances, including those on the
EPA List of Hazardous Substances (HSL), at compressor stations and other
facilities it operates. While conducting this project, TGP has been in frequent
contact with federal and state regulatory agencies, both through informal
negotiation and formal entry of consent orders. TGP executed a consent order in
1994 with the EPA, governing the remediation of the relevant compressor
stations, and is working with the EPA and the relevant states regarding those
remediation activities. TGP is also working with the Pennsylvania and New York
environmental agencies regarding remediation and post-remediation activities at
its Pennsylvania and New York stations.

PCB Cost Recoveries. In May 1995, following negotiations with its
customers, TGP filed an agreement with the FERC that established a mechanism for
recovering a substantial portion of the environmental costs identified in its
internal remediation project. The agreement, which was approved by the FERC in
November 1995, provided for a PCB surcharge on firm and interruptible customers'
rates to pay for eligible remediation costs, with these surcharges to be
collected over a defined collection period. TGP has received approval from the
FERC to extend the collection period, which is now currently set to expire in
June 2006. The agreement also provided for bi-annual audits of eligible costs.
As of March 31, 2004, TGP had pre-collected PCB costs by approximately $121
million. This pre-collected amount will be reduced by future eligible costs
incurred for the remainder of the remediation project. To the extent actual
eligible expenditures are less than the amounts pre-collected, TGP will refund
to its customers the difference, plus carrying charges incurred up to the date
of the refunds. As of March 31, 2004, TGP has recorded a regulatory liability
(included in other non-current liabilities on its balance sheet) of $90 million
for estimated future refund obligations.

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 62 active sites 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 March 31, 2004, we
have estimated our share of the remediation costs at these sites to be between
$31 million and $45 million. Since the clean-up costs are estimates and are
subject to revision as more information becomes available about the extent of
remediation required, and because in some cases we

27

have asserted a defense to any liability, our estimates could change. Moreover,
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 PRPs has been considered,
where appropriate, in estimating our liabilities. Accruals for these issues are
included in the previously indicated estimates for Superfund sites.

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

Other

Enron Bankruptcy. In December 2001, Enron Corp. and a number of its
subsidiaries, including Enron North America Corp. (ENA) and Enron Power
Marketing, Inc. (EPMI) filed for Chapter 11 bankruptcy protection in New York.
We had various contracts with Enron marketing and trading entities, and most of
the trading-related contracts were terminated due to the bankruptcy. In October
2002, we filed proofs of claims against the Enron trading entities totaling
approximately $317 million. We sold $244 million of the original claims to a
third party. Enron also maintained that El Paso Merchant Energy-Petroleum
Company owed it approximately $3 million, and that EPME owed EPMI $46 million,
each due to the termination of petroleum and physical power contracts. In both
cases, we maintained that due to contractual setoff rights, no money was owed to
the Enron parties. Additionally, EPME maintained that EPMI owed EPME $30 million
due to the termination of the physical power contract, which is included in the
$317 million of filed claims. EPMI filed a lawsuit against EPME and its
guarantor, El Paso Corporation, based on the alleged $46 million liability. On
June 24, 2004, the Bankruptcy Court approved a settlement agreement with Enron
that resolved all of the foregoing issues as well as most other trading or
merchant issues between the parties. Our European trading businesses also
asserted $20 million in claims against Enron Capital and Trade Resources
Limited, which are subject to separate proceedings in the United Kingdom, in
addition to a corresponding claim against Enron Corp. based on a corporate
guarantee. After considering the valuation and setoff arguments and the reserves
we have established, we believe our overall exposure to Enron is $3 million.

In addition, various Enron subsidiaries had transportation contracts on
several of our pipeline systems. Most of these transportation contracts have now
been rejected, and our pipeline subsidiaries have filed proofs of claim totaling
approximately $137 million. EPNG filed the largest proof of claim in the amount
of approximately $128 million, which included $18 million for amounts due for
services provided through the date the contracts were rejected and $110 million
for damage claims arising from the rejection of its transportation contracts.
EPNG expects that Enron will vigorously contest these claims. Given the
uncertainty of the bankruptcy process, the results are uncertain. We have fully
reserved for the amounts due through the date the contracts were rejected, and
we have not recognized any amounts under these contracts since the rejection
date.

Duke Litigation. Citrus Trading Corporation (CTC), a direct subsidiary of
Citrus Corp. (Citrus) has filed suit against Duke Energy LNG Sales, Inc (Duke)
and PanEnergy Corp., the holding company of Duke, seeking damages of $185
million for breach of a gas supply contract and wrongful termination of that
contract. Duke sent CTC notice of termination of the gas supply contract
alleging failure of CTC to increase the amount of an outstanding letter of
credit as collateral for its purchase obligations. Duke has filed in federal
court an amended counter claim joining Citrus and a cross motion for partial
summary judgment, requesting that the court find that Duke had a right to
terminate it gas sales contract with CTC due to the failure of CTC to adjust the
amount of the letter of credit supporting its purchase obligations. CTC filed an
answer to Duke's motion, which is currently pending before the court.

28

Economic Conditions of Brazil. We own and have investments in power,
pipeline and production assets in Brazil with an aggregate exposure, including
financial guarantees, of approximately $1.5 billion. During 2002, Brazil
experienced declines in its financial markets, which contributed to
significantly higher interest rates in 2002 on local debt for the government and
private sectors, significantly decreased the availability of funds from lenders
outside of Brazil and decreased the amount of foreign investment in the country.
During late 2003 and 2004, Brazil's general economic conditions improved,
although Brazil continues to experience high debt and interest rate levels that
need to be improved in order to stabilize its economy. In addition, the
government may impose or attempt to impose changes that could affect our
investments, including imposing price controls on electricity and fuels,
attempting to force renegotiation of power purchase agreements (PPA's) which
provide for partial protection from local currency devaluation or attempting to
impose other concessions. These developments have delayed and may continue to
delay the implementation of project financings planned and underway in Brazil
(although we have raised $420 million of non-recourse debt on our Macae power
project through 2004). We currently believe that the economic difficulties in
Brazil will not have a future material adverse effect on our investment in the
country, but we continue to monitor the economic situation and potential changes
in governmental policy, and are working with the state-controlled utilities in
Brazil that are counterparties under our projects' PPA's to attempt to maintain
the economic returns we anticipated when we made our investments. Some of the
specific difficulties we are experiencing in Brazil are discussed below.

We own a 60 percent interest in a 484 MW gas-fired power project known as
the Araucaria project located near Curitiba, Brazil. The project company in
which we have an ownership interest has a 20-year PPA with a regional utility
that is currently in international arbitration and in litigation in Curitiba
courts. A Curitiba court has ruled that the arbitration clause in the PPA is
invalid, and has enjoined the project company from prosecuting its arbitration
under penalty of approximately $173,000 in daily fines. The project company is
appealing this ruling, and has obtained a stay order in any imposition of daily
fines pending the outcome of the appeal. Our investment in the Araucaria project
was $181 million at March 31, 2004. Based on the future outcome of our dispute
under the PPA, we could be required to write down the value of our investment.

We own two projects located in Manaus, Brazil. The first project is a 238
MW fuel-oil fired plant known as the Manaus Project, which has a net book value
of $34 million at March 31, 2004 and the second project is a 158 MW fuel-oil
fired plant known as the Rio Negro Project with a net book value of $40 million
at March 31, 2004. The Manaus Project's PPA currently expires in January 2005
and the Rio Negro Project's PPA currently expires in January 2006. In the first
quarter of 2003, the Manaus Project began experiencing delays in payment from
the purchaser of our power, Manaus Energia S.A. In the fourth quarter of 2003,
all of the contractual issues were resolved and a payment schedule was
established and is being followed for all payments in arrears. These past due
payments were collected as of March 2004. As of March 31, 2004, our accounts
receivable on the Manaus Project is $4 million. In addition, we have filed a
lawsuit in the Brazilian courts against Manaus Energia on the Rio Negro Project
regarding a tariff dispute related to power sales from 1999 to 2003 and have an
additional long-term receivable of $32 million which is a subject of this
lawsuit. As a result of changes in the Brazilian political environment in early
2004, Manaus Energia issued a request for power supply proposals for 450 MW to
525 MW of net generating capacity from 2005 to 2006. The bid qualifications
issued by Manaus Energia may prohibit us from supplying power from our Manaus
and Rio Negro projects. We have filed both administrative and legal challenges
to these bid qualifications and intend to submit a bid. A non-governmental
organization has obtained a preliminary injunction enjoining Manaus Energia from
proceeding with the bid process until a decision on the merits of their
complaint is made. Based on the expected results of the bid process and its
impact on the future outcome of any negotiations to extend the term of the
PPA's, we recorded an impairment charge of approximately $135 million in the
first quarter of 2004. Based on the future outcome of the lawsuit related to the
$32 million receivable, we could be required to provide an allowance for the
receivable discussed above.

We own a 50 percent interest in a 404 MW dual-fuel-fired power project
known as the Porto Velho Project, located in Porto Velho, Brazil. The Porto
Velho Project has two PPA's. The first PPA has a term of ten years and relates
to the first phase of the project. The second PPA has a term of 20 years and
relates to the

29

second 345 MW phase of the project. We are negotiating certain provisions of
both PPA's with EletroNorte, including the amount of installed capacity, energy
prices, take or pay levels, the term of the first PPA and other issues. Although
the current terms of the PPA's and the proposed amendments do not indicate an
impairment of our investment, we may be required to write down the value of our
investment if these negotiations are resolved unfavorably. Our investment at
March 31, 2004, was $291 million.

We own a 895 MW gas-fired power project known as the Macae project located
near the city of Macae, Brazil with a net book value of $732 million at March
31, 2004. The Macae project revenues are derived from sales to the spot market,
bilateral contracts and minimum capacity and revenue payments. The minimum
capacity and energy revenue payments of the Macae project are guaranteed by
Petrobras until August 2007 under a participation agreement. Recently Petrobras
has requested that certain provisions of the participation agreement,
particularly the terms of the capacity payment, be renegotiated and we have
begun early discussions with Petrobras. While the current terms of the
participation agreement do not indicate an impairment of our investment, a
renegotiation of the participation agreement could reduce our earnings from this
project beginning in 2005 and we may be required to write down the value of our
investment at that time.

While the outcome of these matters cannot be predicted with certainty we
believe we have established appropriate reserves for these matters. However, it
is possible that new information or future developments could require us to
reassess our potential exposure related to these matters and adjust our accruals
accordingly. The impact of these changes may have a material effect on our
results of operations, our financial position and our cash flows in the periods
these events occur.

Guarantees

We are involved in various joint ventures and other ownership arrangements
that sometimes require additional financial support that results in the issuance
of financial and performance guarantees. See our 2003 Annual Report on Form 10-K
for a description of each type of guarantee. As of March 31, 2004, we had
approximately $256 million of both financial and performance guarantees not
otherwise reflected in our financial statements. We also periodically provide
indemnification arrangements related to assets or businesses we have sold. As of
March 31, 2004, we had accrued $78 million related to these arrangements.

14. RETIREMENT BENEFITS

The components of net benefit cost (income) for our pension and
postretirement benefit plans for the quarters ended March 31 are as follows:

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

(1) As permitted, the amortization of any prior service cost is determined using
a straight-line amortization of the cost over the average remaining service
period of employees expected to receive benefits under the plan.

We made $15 million and $19 million of cash contributions to our
Supplemental Executive Retirement Plan and other postretirement plans during the
quarters ended March 31, 2004 and 2003. We expect to contribute an additional $2
million to the Supplemental Executive Retirement Plan and $48 million to our

30

other postretirement plans in 2004. We do not anticipate making any other
contributions to our other retirement benefit plans in 2004. We are currently
evaluating the impact of the Pension Funding Equity Act enacted in 2004 on our
projected funding.

On December 8, 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 was signed into law. Benefit obligations and costs
reported that are related to prescription drug coverage do not reflect the
impact of this legislation. In addition, we are currently evaluating new
accounting standards that become effective in the fourth quarter of 2004 that
may require changes to our net benefit cost and to previously reported benefit
information.

15. CAPITAL STOCK

Common Stock

In January 2004, we issued 8.8 million shares of common stock for $74
million to satisfy the remaining stock obligation under our Western Energy
Settlement.

Dividends

During the quarter ended March 31, 2004, we paid dividends of $23 million
to common stockholders. We have also paid dividends of $77 million subsequent to
March 31, 2004. The dividends on our common stock were treated as a reduction of
paid-in-capital since we currently have an accumulated deficit. In addition, El
Paso Tennessee Pipeline Co., our subsidiary, paid dividends (2.0625% per quarter
8.25% per annum)of approximately $6 million in each quarter of 2004 on its
Series A cumulative preferred stock.

16. SEGMENT INFORMATION

During 2004, we reorganized our business structure into two primary
business lines, regulated and unregulated, and modified our operating segments.
Historically, our operating segments included Pipelines, Production, Merchant
Energy and Field Services. As a result of this reorganization, we eliminated our
Merchant Energy segment and established individual Power and Marketing and
Trading segments. All periods presented reflect this change in segments. Our
regulated business consists of our Pipelines segment, while our unregulated
businesses consist of our Production, Marketing and Trading, Power, and Field
Services segments. Our segments are strategic business units that provide a
variety of energy products and services. They are managed separately as each
segment requires different technology and marketing strategies. Our corporate
operations include our general and administrative functions as well as a
telecommunications business, and various other contracts and assets, all of
which are immaterial. These other assets and contracts include financial
services, LNG and related items. During the first quarter of 2004, we
reclassified our petroleum ship charter operations from discontinued operations
to our continuing corporate operations. Our operating results for all periods
presented reflect this change.

We use earnings before interest expense and income taxes (EBIT) to assess
the operating results and effectiveness of our business segments. We define EBIT
as net income (loss) adjusted for (i) items that do not impact our income (loss)
from continuing operations, such as extraordinary items, discontinued operations
and the impact of accounting changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of consolidated
subsidiaries. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. We believe EBIT is
useful to our investors because it allows them to more effectively evaluate the
performance of all of our businesses and investments. Also, we exclude interest
and debt expense and distributions on preferred interests of consolidated
subsidiaries so that investors may evaluate our operating results without regard
to our financing methods or capital structure. EBIT may not be comparable to
measures used by other companies. Additionally, EBIT should be considered in
conjunction with net income and other performance measures

31

such as operating income or operating cash flow. Below is a reconciliation of
our EBIT to our loss from continuing operations for the quarters ended March 31:

The following tables reflect our segment results as of and for the quarters
ended March 31:

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

(1) Includes our Corporate and telecommunications activities and eliminations of
intercompany transactions. Our intersegment revenues, along with our
intersegment operating expenses, were incurred in the normal course of
business between our operating segments. We record an intersegment revenue
elimination, which is the only elimination included in the "Corporate"
column, to remove intersegment transactions.

(2) Revenues from external customers include gains and losses related to our
hedging of price risk associated with our natural gas and oil production.
Intersegment revenues represent sales to our Marketing and Trading segment,
which is responsible for marketing our production.

(3) Relates to intercompany activities between our continuing operations and our
discontinued petroleum markets operations.

32

Total assets by segment are presented below:

17. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

We hold investments in various unconsolidated affiliates which are
accounted for using the equity method of accounting. Below is summarized
financial information of our proportionate share of unconsolidated affiliates.
This information includes affiliates in which we hold a less than 50 percent
interest as well as those in which we hold a greater than 50 percent interest.
We received distributions and dividends of $94 million for the quarter ended
March 31, 2004 and $83 million for the quarter ended March 31, 2003 from our
investments. Our proportionate share of the unconsolidated affiliates in which
we hold a greater than 50 percent interest had net income of $14 million and $9
million for the quarters ended March 31, 2004 and 2003.

33

Our income statement reflects our earnings (losses) from unconsolidated
affiliates. This amount includes income or losses directly attributable to the
net income or loss of our equity investments as well as impairments and other
adjustments to income we record. The table below reflects our earnings (losses)
from unconsolidated affiliates for the quarters ended March 31:

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

(1) We have also recorded minority interest expense in 2004 of $10 million
related to the effective 50 percent general partner interest in GulfTerra
acquired by Enterprise in December 2003.

(2) This impairment resulted from other than temporary declines in the
investment's fair value based on developments in our power business and the
power industry (see Note 3).

(3) This impairment resulted from a write-off of notes receivable and accruals
on contracts due to ongoing difficulty at the project level.

We enter into a number of transactions with our unconsolidated affiliates
in the ordinary course of conducting our business. The following table shows
revenues and charges resulting from transactions with our unconsolidated
affiliates for the quarters ended March 31:

GulfTerra

Prior to September 30, 2004, our Field Services segment managed GulfTerra's
daily operations and performed all of GulfTerra's administrative and operational
activities under a general and administrative services agreement or, in some
cases, separate operational agreements. GulfTerra contributes to our income
through our general partner interest and our ownership of common and preference
units. We do not have any loans to or from GulfTerra.

We had the following interests in GulfTerra as of March 31, 2004:

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

(1) We had $181 million of indefinite-lived intangible assets related to our
general partner interest and $96 million recorded as minority interest
related to Enterprise's effective 50 percent ownership interest in the
general partner as of March 31, 2004. Additionally, we had approximately
$480 million of goodwill associated with our Field Services segment which
was eliminated as a result of the completion of the Enterprise transaction
discussed below.

34

(2) The remaining units are owned by public holders, including the partnership
employees and management, none of which individually own more than 10
percent.

(3) As of March 31, 2004, we owned all of the Series C units of GulfTerra.

In September 2004, in connection with the closing of the merger between
GulfTerra and Enterprise, we completed the sale of substantially all of our
interests in GulfTerra, as well as certain processing assets to affiliates of
Enterprise. Our total gross cash proceeds from the sale were approximately $1.03
billion and we will record a gain of approximately $19 million as a result of
this transaction including the elimination of approximately $480 million in
goodwill associated with our Field Services segment. Of the $480 million of
goodwill that was eliminated, approximately $397 million will not be deductible
for tax purposes. As a result, we will recognize a significant tax gain and tax
expense associated with the transaction in the third quarter of 2004. The assets
sold were our interest in the general partner of GulfTerra, 10.9 million Series
C units, 2.9 million GulfTerra common units, and nine processing plants located
in South Texas. In addition to the cash proceeds, we received a 9.9 percent
interest in the general partner of the combined organization, Enterprise
Products GP, LLC. Our remaining GulfTerra common units were exchanged for
approximately 13.5 million common units in Enterprise as a result of the merger.

Our segments also conduct transactions in the ordinary course of business
with GulfTerra, including sales of natural gas and operational services. Below
is the summary of our transactions with GulfTerra for the quarters ended March
31:

For a further discussion of our relationships with GulfTerra, see our 2003
Annual Report on Form 10-K.

35

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

The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our 2003 Annual Report on Form 10-K,
and the financial statements and notes presented in Item 1 of this Form 10-Q.

Our results for the quarter ended March 31, 2003 have been restated to
reflect the accounting impact of a reduction in our historically reported proved
natural gas and oil reserves and to revise the manner in which we accounted for
certain hedges, primarily those associated with our anticipated natural gas
production as further discussed in our 2003 Annual Report on Form 10-K.

OVERVIEW

Business Update

In December 2003, our management presented its Long-Range Plan for the
Company. This plan, among other things, defined our core businesses, established
a timeline for debt reductions and sales of non-core businesses and assets and
set financial goals for the future. During 2004, and through the filing date of
this Form 10-Q, we have made significant progress in the areas outlined in that
plan, including:

- completing or announcing sales of assets and investments of approximately
$3.3 billion (see Note 4)

- retiring or refinancing approximately $1.8 billion of maturing debt and
other obligations, ($576 million through March 31, 2004) (see Note 12);

- eliminating debt of $887 million ($72 million through March 31, 2004)
through the sale of assets to which the debt related (see Note 12); and

- finalizing the Western Energy Settlement, which substantially resolved
our principal exposure relating to the western energy crisis and
successfully raising funds to satisfy a significant portion of our
current obligations under that settlement (see Note 13).

Liquidity Update

We believe that the restatements of our historical financial statements
discussed above would have constituted events of default under our $3 billion
revolving credit facility and various other financing transactions; specifically
under the provisions of these arrangements related to representations and
warranties on the accuracy of our historical financial statements and on our
debt to total capitalization ratio. During 2004, we received several waivers on
our revolving credit facility and various other financing transactions to
address these issues. These waivers continue to be effective. We also received
an extension of time from various lenders until November 30, 2004 to file our
second quarter 2004 Form 10-Q, which we expect to meet. If we are unable to file
our second quarter 2004 Form 10-Q by that date and are not able to negotiate an
additional extension of the filing deadline, our revolving credit facility and
various other transactions could be accelerated. As part of obtaining our
waivers, we also amended various provisions of the revolving credit facility,
including provisions related to events of default and limitations on our
ability, as well as that of our subsidiaries, to repay indebtedness scheduled to
mature after June 30, 2005. Based upon a review of the covenants contained in
our indentures and the financing agreements of our other outstanding
indebtedness, the acceleration of our revolving credit facility could constitute
an event of default under some of our other debt agreements. In addition, three
of our subsidiaries have indentures associated with their public debt that
contain $5 million cross-acceleration provisions. These indentures state that
should an event of default occur resulting in the acceleration of other debt
obligations of such subsidiaries in excess of $5 million, the long-term debt
obligations containing such provisions could be accelerated. The acceleration of
our debt would adversely affect our liquidity position and in turn, our
financial condition.

Our $3 billion revolving credit facility matures on June 30, 2005. The
facility is collateralized by our equity interests in TGP, EPNG, ANR, CIG, WIC,
Southern Gas Storage Company, ANR Storage Company, as well as our common units
in Enterprise, as further described below. With the sale of a majority
36

our interests in GulfTerra to Enterprise in September 2004, which included all
of our Series C and some of our common units, our borrowing capacity under this
facility was reduced by approximately $456 million to approximately $2.5 billion
in October 2004. Upon the closing of the merger of GulfTerra and Enterprise, our
remaining interests in GulfTerra's common units were converted into Enterprise
common units, which continue to collateralize this facility. We are in the
process of negotiating the refinancing of this facility as the combination of a
$1.75 billion, three year revolving credit facility and a five year term loan of
up to $1.25 billion and currently expect to be successful in this refinancing.
In the event we are unable to refinance our revolving credit facility by June
30, 2005, we would be obligated to repay any outstanding amounts, and make
alternative arrangements for the letters of credit issued pursuant to this
credit facility. As of September 30, 2004, we had no borrowings outstanding and
had approximately $1.1 billion of letters of credit issued under this credit
facility.

Although we expect to successfully refinance all or a portion of our
existing revolving credit facility, if we were unsuccessful, we believe we could
adjust our planned capital expenditures and increase our planned asset sales to
meet any shortfall in liquidity, and at the same time provide for our
operations. Further, if we repaid our obligations under the revolving credit
facility, some of the assets that currently collateralize this facility,
including our equity interests in TGP, EPNG, ANR, CIG, WIC, Southern Gas Storage
Company, ANR Storage Company and our common units in Enterprise, could be used
to support new financing transactions. Although we cannot guarantee the outcome
of future events, we believe that this available collateral would be adequate to
provide financing sufficient to meet our liquidity needs.

Various other financing arrangements entered into by us and our
subsidiaries, including El Paso CGP and El Paso Production Holding Company,
include covenants that require us to file financial statements within specified
time periods. Non-compliance with such covenants does not constitute an
automatic event of default. Instead, such agreements are subject to acceleration
when the indenture trustee or the holders of at least 25 percent of the
outstanding principal amount of any series of debt provides notice to the issuer
of non-compliance under the indenture. In that event, the non-compliance can be
cured by filing financial statements within specified periods of time (between
30 and 90 days after receipt of notice depending on the particular indenture) to
avoid acceleration of repayment. The holders of El Paso Production Holding
Company's debt obligations waived its financial filing requirements through
December 31, 2004. The filing of our second quarter 2004 Form 10-Q and the first
and second quarter 2004 Forms 10-Q for these subsidiaries will cure the events
of non-compliance resulting from the failure to file financial statements. In
addition, neither we nor any of our subsidiaries have received a notice of the
default caused by our failure to file financial statements. In the event of an
acceleration, we may be unable to meet our payment obligations with respect to
the related indebtedness.

Furthermore, the material restatement of our financial statements for the
period ended December 31, 2001 as was reported in our 2003 Annual Report on Form
10-K could cause a default under the financing agreements entered into in
connection with our $950 million Gemstone notes due October 31, 2004. Currently,
$748 million of Gemstone notes are outstanding. However, we currently expect to
repay these notes in full upon their maturity on October 31, 2004.

Our subsidiaries are a significant potential source of liquidity to us, and
they participate in our cash management program to the extent they are permitted
to do so under their financing agreements and indentures. Under the cash
management program, depending on whether participating subsidiaries have
short-term cash requirements or surpluses, we either provide cash to them or
they provide cash to us. If we were to incur an event of default under our
credit facilities, we would be unable to obtain cash from our pipeline
subsidiaries, which are the primary source of cash under this program.
Currently, one of our subsidiaries, CIG, is not advancing funds to us via our
cash management program due to its anticipated cash needs. In addition, our
ownership in a number of our subsidiaries and investments serve as collateral
under our revolving credit facility and our other financings. If the lenders
under the credit facility or those other financings were to exercise their
rights to this collateral, we could lose our ownership interest in these
subsidiaries or be required to liquidate these investments.

37

If, as a result of the events described above, we were subject to voluntary
or involuntary bankruptcy proceedings, our creditors could attempt to make
claims against our subsidiaries, including claims to substantively consolidate
those subsidiaries. We believe that claims to substantively consolidate our
subsidiaries would be without merit. However, there is no assurance that our
creditors would not advance such a claim in a bankruptcy proceeding. If our
creditors were able to substantively consolidate our subsidiaries, it could have
a material adverse effect on our financial condition and our liquidity.

Despite the events and factors described above, we believe we will be able
to meet our ongoing liquidity and cash needs through a combination of sources,
including cash on hand, cash generated from our operations, borrowings under our
revolving credit facility, proceeds from asset sales, reduction of discretionary
capital expenditures and the possible issuance of long-term debt, and common or
preferred equity securities. However, a number of factors could influence our
liquidity sources, as well as the timing and ultimate outcome of our ongoing
efforts and plans.

CAPITAL STRUCTURE

Our 2003 Annual Report on Form 10-K includes a detailed discussion of our
liquidity, financing activities, contractual obligations and commercial
commitments. The information presented below updates, and you should read it in
conjunction with, the information disclosed in that Form 10-K.

During the first quarter of 2004, we continued to reduce our debt as part
of our Long-Range Plan announced in December 2003. Our activity during the
quarter ended March 31, 2004 is as follows (in millions):

Short-term financing obligations, including current
maturities................................................ $ 1,457
Long-term financing obligations............................. 20,275
Securities of subsidiaries.................................. 447
-------
Total debt and securities of subsidiaries as of
December 31, 2003................................ 22,179
-------
Principal amounts borrowed.................................. 50
Repayments/retirements of principal(1)...................... (576)
Sale of entity(2)........................................... (72)
Redemptions and eliminations of securities of
subsidiaries.............................................. (13)
Other....................................................... 19
-------
Total debt and securities of subsidiaries as of
March 31, 2004................................... $21,587
=======

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

(1) Amount includes $250 million repayments under our revolving credit facility
and excludes $370 million repayments of long-term debt related to our Aruba
refinery classified as part of our discontinued operations prior to the sale
of this facility in early 2004.

(2) Amount relates to the sale of Mohawk River Funding IV.

For a further discussion of our long-term debt and other financing
obligations, and other credit facilities, see Item 1, Financial Statements, Note
12.

38

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW OF CASH FLOW ACTIVITIES FOR THE QUARTERS ENDED MARCH 31, 2004 AND 2003

For the quarters ended March 31, 2004 and 2003, our cash flows are
summarized as follows:

During the first quarter of 2004, we generated cash from several sources,
including our principal continuing operations as well as through asset sales in
both our continuing and discontinued operations. We used a major portion of that
cash to fund our capital expenditures and to make payments to retire long-term
debt. Overall, our cash sources and uses are summarized as follows (in
billions):

Cash inflows
Cash flows from continuing operations..................... $0.5
Net proceeds from the sale of assets and investments...... 0.4
Net discontinued operations activity(1)................... 0.6
----
Total cash inflows..................................... 1.5
----
Cash outflows
Additions to property, plant and equipment................ 0.4
Payments to retire long-term debt(1)...................... 0.6
Net payments of restricted cash........................... 0.1
----
Total cash outflows.................................... 1.1
----
Net increase in cash................................. $0.4
====

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

(1) Excludes payments of approximately $370 million related to long-term debt at
our Aruba refinery classified as part of discontinued operations.

As of September 30, 2004, we had available cash on hand and borrowing
capacity under our revolving credit facility totaling $3.3 billion. A more
detailed analysis of our cash flows from operating, investing and financing
activities of our continuing operations and cash flow from discontinued
operations is as follows.

Cash From Continuing Operating Activities

Overall, cash generated from our continuing operating activities was $0.5
billion during the first quarter of 2004 versus $0.1 billion during the same
period of 2003. The $0.4 billion quarter over quarter increase in operating cash
flow was due primarily to the significant amount of working capital used in 2003
to meet collateral and margin call requirements relative to 2004. During 2003,
increases in natural gas prices and our

39

credit rating downgrades caused us to use approximately $0.4 billion of
operating cash flow to fund margin calls.

Cash From Continuing Investing Activities

Net cash used in our continuing investing activities was $0.1 billion for
the quarter ended March 31, 2004. Our investing activities consisted of the
following (in billions):

Production exploration, development and acquisition
expenditures.............................................. $ 0.3
Pipeline expansion, maintenance and integrity projects...... 0.1
Restricted cash activity.................................... 0.1
Proceeds from the sale of assets and investments............ (0.4)
-----
Total continuing investing activity............... $ 0.1
=====

Cash received from the sale of assets and investments was primarily from
the sale of natural gas and oil properties. For the remainder of 2004, we expect
our total capital expenditures to be approximately $1.7 billion, which includes
approximately $0.6 billion for our Production segment and $1.0 billion for our
Pipelines segment.

Cash From Continuing Financing Activities

Net cash provided by our continuing financing activities was $0.1 billion
for the quarter ended March 31, 2004. Cash provided from our financing
activities included $0.6 billion of cash contributed by our discontinued
operations and other financing activities of $0.1 billion. Cash used in our
financing activities included net repayments of $0.6 billion made to retire
third party long-term debt.

Cash from Discontinued Operations

During the first quarter of 2004, our discontinued operations generated
$0.6 billion of cash. We generated $0.2 billion in cash in these operations and
received proceeds from asset sales of $0.8 billion, offset by payments of
long-term debt of $0.4 billion.

40

COMMODITY-BASED DERIVATIVE CONTRACTS

We utilize derivative financial instruments in our hedging activities,
power contract restructuring activities and in our historical energy trading
activities. The following table details the fair value of our commodity-based
derivative contracts by year of maturity and valuation methodology as of March
31, 2004:

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

(1) Includes $242 million of intercompany derivatives that eliminate in
consolidation and had no impact on our consolidated assets and liabilities
from price risk management activities for the quarter ended March 31, 2004.

(2) Includes $864 million of assets from derivative contracts that we sold in
the second quarter of 2004. See Item 1, Financial Statements, Note 6, for a
discussion of the impairment related to this sale.

(3) Exchange-traded positions are traded on active exchanges such as the New
York Mercantile Exchange, the International Petroleum Exchange and the
London Clearinghouse.

Below is a reconciliation of our commodity-based derivatives for the period
from January 1, 2004 to March 31, 2004:

41

The fair value of contract settlements during the period represents the
estimated amounts of derivative contracts settled through physical delivery of a
commodity or by a claim to cash as accounts receivable or payable. The fair
value of contract settlements also includes physical or financial contract
terminations due to counterparty bankruptcies and the sale or settlement of
derivative contracts through early termination or through the sale of the
entities that own these contracts.

During the first quarter of 2004, we sold a restructured power contract
with a fair value of $75 million in conjunction with the sale of our interest in
Mohawk River Funding IV. During the second quarter of 2004, we sold a
restructured power contract with a fair value of $864 million in conjunction
with the sale of our interest in Utility Contract Funding. See Item I, Financial
Statements, Notes 4 and 6, for additional information on these sales.

The change in fair value of contracts during the year represents the change
in value of contracts from the beginning of the period, or the date of their
origination or acquisition, until their settlement or, if not settled, until the
end of the period.

42

SEGMENT RESULTS

Below are our results of operations (as measured by EBIT) by segment.
During 2004, we reorganized our business structure into two primary business
lines, regulated and unregulated, and modified our operating segments.
Historically, our operating segments included Pipelines, Production, Merchant
Energy and Field Services. As a result of this reorganization, we eliminated our
Merchant Energy segment and established individual Power and Marketing and
Trading segments. All periods presented reflect this change in segments. Our
regulated business consists of our Pipelines segment, while our unregulated
businesses consist of our Production, Marketing and Trading, Power and Field
Services segments. Our segments are strategic business units that provide a
variety of energy products and services. They are managed separately as each
segment requires different technology and marketing strategies. Our corporate
operations include our general and administrative functions as well as a
telecommunications business and various other contracts and assets, all of which
are immaterial to our results in 2004. The other assets and contracts include
financial services, LNG and related items. During the first quarter of 2004, we
reclassified our petroleum ship charter operations from discontinued operations
to our continuing corporate operations. Our operating results for all periods
presented reflect this change.

We use earnings before interest expense and income taxes (EBIT) to assess
the operating results and effectiveness of our business segments. We define EBIT
as net income (loss) adjusted for (i) items that do not impact our income (loss)
from continuing operations, such as extraordinary items, discontinued operations
and the impact of accounting changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of consolidated
subsidiaries. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. We believe EBIT is
useful to our investors because it allows them to more effectively evaluate the
performance of all of our businesses and investments. Also, we exclude interest
and debt expense and distributions on preferred interests of consolidated
subsidiaries so that investors may evaluate our operating results without regard
to our financing methods or capital structure. EBIT may not be comparable to
measures used by other companies. Additionally, EBIT should be considered in
conjunction with net income and other performance measures such as operating
income or operating cash flow. Below is a reconciliation of our consolidated
EBIT to our consolidated net loss for the quarters ended March 31:

43

OVERVIEW OF RESULTS OF OPERATIONS

In the first quarter of 2004, our consolidated EBIT from continuing
operations was $233 million of which $206 million was our segment EBIT. During
the quarter, our Pipelines, Production and Field Services segments contributed
$517 million of combined EBIT. These positive contributions were partially
offset by EBIT losses of $311 million in our Power and Marketing and Trading
segments. The following overview summarizes the results of operations of our
operating segments.

Pipelines The Pipelines segment generated EBIT of $386 million,
which was generally consistent with our expectations for
the period.

Production The Production segment generated EBIT of $95 million,
which was below our expectations for the period,
primarily due to ceiling test and other charges of $130
million. These charges were primarily associated with
our Canadian operations, the majority of which were sold
during the period. Our production volumes were also
below expectations for the period and our production
costs were higher. However, offsetting these impacts
were higher than expected commodity prices and lower
than expected depreciation costs due to the impact of
the reserve and hedge restatements in periods prior to
2004.

Marketing and Trading The Marketing and Trading segment generated an EBIT loss
of $172 million, which was significantly below our
expectations. The performance was driven primarily by
mark-to-market losses in our natural gas portfolio as
natural gas prices increased in the period, partially
offset by mark-to-market income in our major tolling
contract. Our natural gas portfolio exposure was
impacted by the hedge restatement in periods prior to
2004, resulting in a mark-to-market position that will
result in losses as natural gas prices increase.

Power The Power segment generated an EBIT loss of $139
million, which was below our expectations for the
period, primarily due to asset impairments of $246
million. These impairments were primarily related to two
of our plants in Brazil due to events in the first
quarter of 2004 that may make it difficult to extend
their power sales agreements that expire in 2005 and
2006, and due to certain of our domestic operations
which are being sold.

Field Services The Field Services segment generated EBIT of $36
million, which was consistent with our expectations for
the period and impacted by the significant asset sales
activity in the segment in 2003.

For the remainder of 2004, we expect the trends discussed above to
continue, given the historic stability in our pipeline business and the current
favorable pricing environment for natural gas. We expect our EBIT to decline in
our Field Services segment in the fourth quarter of 2004 as a result of the
completion of sales of our interests in GulfTerra and a majority of our
remaining processing assets. In our Power segment, we expect to generate
additional EBIT losses as a result of liquidating our power contract
restructuring derivatives and as we continue to sell our domestic power plant
portfolio. Internationally, we continue to foresee challenges in our operating
areas, particularly in Brazil where we have significant power investments.
Finally, we anticipate our Marketing and Trading segment's EBIT will continue to
be volatile due to unpredictable changes in natural gas and power prices as they
relate to our historical trading portfolio as we transition toward a core
marketing business.

Our earnings in each period were impacted both favorably and unfavorably by
a number of factors affecting our businesses that are enumerated in the table
below. The discussion that follows summarizes these factors and their impact on
our operating segments and our corporate activities. For a more detailed
discussion

44

of these factors and other items impacting our financial performance for the
quarters ended March 31, see the individual segment and other results included
in Item 1, Financial Statements, Notes 5, 6, 7 and 17.

The following is a discussion of the year over year results of each of our
business segments as well as our corporate activities, interest and debt
expense, distributions on preferred interests of consolidated subsidiaries,
income taxes and the results of our discontinued petroleum markets and coal
operations.

REGULATED BUSINESSES -- PIPELINES SEGMENT

Our Pipelines segment owns and operates our interstate natural gas
transmission businesses. For a further discussion of the business activities of
our Pipelines segment, see our 2003 Annual Report on Form 10-K. Below are the
operating results and analysis of these results for our Pipelines segment for
the quarters ended March 31:

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

(1) Throughput volumes for the quarter ended March 31, 2003 exclude volumes
related to our equity investment in Portland Natural Gas Transmission System
which was sold in the fourth quarter of 2003, and exclude intrasegment
activities. Throughput volumes includes volumes related to our Mexico
investments which were transferred from our Power segment effective January
1, 2004.

45

Operating Results (EBIT)

The following factors contributed to our overall EBIT decrease of $43
million for the quarter ended March 31, 2004 as compared to the quarter ended
March 31, 2003:

The renegotiation or restructuring of several contracts on our pipeline
systems will continue to unfavorably impact our operating results and EBIT for
the remainder of 2004, among other items noted below. Guardian Pipeline, which
is owned in part by We Energies, is currently providing a portion of its firm
transportation requirements and directly competes with ANR for a portion of the
markets in Wisconsin. Additionally, ANR will continue to experience lower
operating revenues and lower operating expenses for the remainder of 2004 based
on the termination of the Dakota contract on its system. However, the
termination of this contract will not have a significant overall impact on
operating income and EBIT.

The impact of the termination of EPNG's risk sharing mechanism in December
2003 will continue to reduce its comparative EBIT for the remainder of 2004.
However, with the completion of Phases I and II of EPNG's Line 2000 Power-up
project in February and April of 2004, EPNG is now able to re-market the 110
MMcf/d capacity obligation for former full requirements customers. EPNG is at
risk for the permanently released portion of such capacity and it must
demonstrate that sales of the capacity do not adversely impact its service to
firm customers.

Our operating results in future periods will also be impacted by other
factors in addition to those noted above. ANR has entered into an agreement with
a shipper to restructure another of its transportation contracts on its
Southeast Leg as well as a related gathering contract. We anticipate this
restructuring will be completed in March 2005 upon which ANR will receive $26
million.

UNREGULATED BUSINESSES -- PRODUCTION SEGMENT

Our Production segment conducts our natural gas and oil exploration and
production activities. Our operating results are impacted by a variety of
factors including the ability to locate and develop economic natural gas and oil
reserves, extract those reserves with minimal production costs and sell the
products at attractive prices.

46

Operational Update

Our long-term strategy includes developing our production opportunities
primarily in the U.S. and Brazil, while prudently divesting of our production
properties outside of these areas. In the second quarter of 2004, our Board of
Directors approved exiting our Canadian and other international natural gas and
oil operations. We will report these operations as discontinued operations
beginning in the second quarter of 2004. As of September 2004, we have sold all
of our Canadian operations and substantially all of our operations in Indonesia.
Our operations in Canada included activities in Nova Scotia where, in the first
quarter of 2004, we drilled an exploratory well that was not commercially viable
and therefore recorded a $24 million ceiling test charge. In July 2004, we
acquired the remaining 50 percent interest in UnoPaso, which increased our
operations in Brazil.

Through September 2004, we have spent $616 million in capital expenditures
for acquisition, exploration, and development activities. Based on the finding
and development costs experienced in our 2004 drilling program, we expect our
domestic unit of production depletion rate to increase from $1.58 per Mcfe
during the first quarter 2004 to $1.64 Mcfe for the second quarter of 2004 and
to $1.74 per Mcfe for the third quarter of 2004.

For the first quarter of 2004, our total equivalent production declined
approximately 37 Bcfe or 30 percent compared to the same period in 2003. This
decline was caused by asset sales in 2003 primarily in Oklahoma and New Mexico,
normal production declines and disappointing drilling results. For the first
nine months of 2004, our production averaged approximately 845 MMcfe/d; however,
for the month of September 2004 daily production averaged approximately 765
MMcfe/d. At the end of the first quarter of 2004, we sold our production
operations in western Canada which had an average daily production of
approximately 50 MMcfe/d. As mentioned above, in July 2004, we acquired the
remaining 50 percent interest in our UnoPaso investment in Brazil. Prior to this
acquisition, we treated our interest in UnoPaso as an equity method investment
and, therefore, did not include our proportionate share of its production in our
average daily production amounts. Subsequent to the acquisition of the remaining
interest, we began consolidating the operations of UnoPaso, which is producing
an average of approximately 55 MMcfe/d. Our production levels are dependent upon
the amount of capital allocated to our Production segment, the level of success
in our drilling programs and any future asset sales or acquisitions.

Earlier this year, we completed a restatement of our historical financial
statements to reflect significant revisions of our proved natural gas and oil
reserves and to revise our accounting treatment for the majority of our
production hedges. The impact of these restatements on our Production segment in
2004 include lower depreciation expense due to the higher ceiling test charges
in the restated periods and higher realized prices due to the restatement of the
hedges, which were all at hedged prices below market prices in 2004.

Production Hedging

We primarily conduct our hedging activities through natural gas and oil
derivatives on our natural gas and oil production to stabilize cash flows and
reduce the risk of downward commodity price movements on our sales. Because this
hedging strategy only partially reduces our exposure to downward movements in
commodity prices, our reported results of operations, financial position and
cash flows can be impacted significantly by movements in commodity prices from
period to period. For a further discussion of our hedging program and additional
hedges put in place in May and August 2004, refer to our 2003 Annual Report on
Form 10-K.

In October 2004, we entered into additional transactions in our Marketing
and Trading segment designed to provide protection to El Paso from natural gas
price declines in 2005. These "put" contracts will not be treated as hedges for
accounting purposes, but will provide El Paso with a floor price of $6.00 per
MMBtu on 54 TBtu of our natural gas production in 2005.

Further, we are reviewing a separate strategy under which we would
designate certain of the natural gas derivatives that are currently marked to
market in our Marketing and Trading segment as hedges of our natural gas
production. Transactions of this type would be treated as hedges for accounting
purposes and

47

would generally have the effect of hedging a portion of our natural gas
production volumes at current market prices, while reducing the earnings
exposure in our Marketing and Trading segment to future natural gas price
changes. These derivative hedge designations would have no impact on the
company's overall cash flow in any period, but would impact the timing of
recognizing the changes in the fair value of these derivatives in El Paso's
overall operating results.

Operating Results

Below are the operating results and analysis for our Production segment for
the quarters ended March 31:

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

(1) Production costs include lease operating costs and production related taxes
(including ad valorem and severance taxes).

(2) Includes ceiling test charges, restructuring costs, asset impairments and
loss on long-lived assets.

(3) Transportation costs are included in operating expenses on our consolidated
statements of income.

(4) Prices are stated before transportation costs.

Quarter Ended March 31, 2004 Compared to Quarter Ended March 31, 2003

For the quarter ended March 31, 2004, EBIT was $354 million lower than the
same period in 2003. The decrease is due to lower realized natural gas prices
and lower production volumes as a result of asset sales, normal production
declines and disappointing drilling results. Also contributing to lower EBIT
were higher operating expenses due to higher ceiling test and other charges in
2004.

Operating Revenues. The following table describes the variance in revenue
between the quarters ended March 31, 2004 and 2003 due to: (i) changes in
average realized market prices excluding hedges, (ii) changes in production
volumes, and (iii) the effects of hedges on our revenues.

For the quarter ended March 31, 2004, operating revenues were $286 million
lower than the same period in 2003 due to lower market prices for natural gas
and oil and lower production volumes, partially offset by a decrease in losses
from our hedging program. The decline in natural gas volumes was primarily due
to the sale of properties in 2003 in New Mexico, Oklahoma, offshore Gulf of
Mexico and western Canada as well as normal production declines and
disappointing drilling results.

Average realized natural gas prices for the first quarter of 2004,
excluding hedges, were $1.02 per Mcf lower than the same period in 2003, a
decrease of 15 percent. However, partially offsetting the decrease in revenues
were $5 million of hedging losses in 2004 as compared to $26 million of hedging
losses in 2003 relating to our natural gas hedge positions. We expect to
continue to incur hedging losses in 2004 based on current market prices for
natural gas relative to the prices at which our natural gas production is
hedged.

Operating Expenses. Total operating expenses were $74 million higher for
the first quarter of 2004 as compared to the first quarter of 2003 primarily due
to higher ceiling test and other charges, partially offset by lower
depreciation, depletion, and amortization expense, lower production costs, and
lower general and administrative expenses.

Ceiling test and other charges increased by $117 million in 2004. During
2004, we incurred an $85 million loss associated with the sale of our Canadian
operations, a $24 million impairment related to an exploratory well drilled in
Nova Scotia that was not commercially viable and an $8 million impairment
related to a non-full cost pool asset in Canada.

49

Total depreciation, depletion, and amortization expense decreased by $15
million in the first quarter of 2004 as compared to the same period in 2003.
Lower production volumes in 2004 due to the asset sales and other production
declines discussed above resulted in a decrease of $46 million. Partially
offsetting this decrease were higher depletion rates due to higher finding and
development costs and a lower reserve base, which contributed an increase of $29
million in our depreciation, depletion, and amortization expense.

Production costs decreased by $19 million in the first quarter of 2004 as
compared to the same period in 2003 due to a decrease in production taxes
resulting from high cost gas well tax credits in the first quarter of 2004 and
due to lower commodity prices in 2004 compared to 2003. Production taxes
decreased $0.14 per Mcfe in 2004. However, our total production costs per Mcfe
remained the same between the first quarter of 2004 and 2003 as average lease
operating costs increased $0.14 per Mcfe in 2004 primarily due to lower
production volumes discussed above.

General and administrative expenses decreased by $7 million, but increased
$0.06 per Mcfe, in the first quarter of 2004 as compared to the same period in
2003. The total dollar decrease was primarily due to lower corporate overhead
allocations as we reduced corporate expenses, while the increase on a per unit
basis was due to lower production volumes.

UNREGULATED BUSINESS -- MARKETING AND TRADING SEGMENT

Earlier this year, we completed a restatement of our historical financial
statements to reflect significant revisions of our proved natural gas and oil
reserves and to revise our accounting treatment for the majority of our
production hedges. This restatement impacted our 2004 operating results by
changing the accounting for many of our natural gas hedging contracts. This
change will result in increased earnings volatility in the future related to
these derivative contracts as natural gas prices change. For a further
discussion of the restatement, refer to our 2003 Annual Report on Form 10-K.

As discussed in our Production segment, in October 2004, we entered into
additional transactions designed to provide protection to El Paso from natural
gas price declines in 2005. These "put" contracts will provide El Paso with a
floor price of $6.00 per MMBtu on 54 TBtu of our Production segment's natural
gas production in 2005. Under these contracts, we will generally have
mark-to-market earnings if the current and future price of natural gas declines
in any given period and losses if the current and future price of natural gas
increases in any given period.

Further, we are reviewing a strategy under which certain of our fixed price
natural gas derivatives that are currently marked to market would be designated
as hedges of the natural gas production in our Production segment. Transactions
of this type would generally be treated as hedges for accounting purposes and
would have the effect of hedging a portion of the natural gas production volumes
in our Production segment at current market prices while reducing our earnings
exposure to future natural gas price changes. These derivative hedge
designations would have no impact on El Paso's overall cash flow in any period,
but would impact the timing of recognizing the changes in the fair value of
these derivatives in El Paso's overall operating results.

50

Our operations primarily consist of the management of our trading portfolio
and the marketing of our Production segment's natural gas and oil production.
Below are our segment operating results and an analysis of these results for the
quarters ended March 31:

MARKETING AND TRADING SEGMENT RESULTS

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

(1) Gross margin consists of revenues from commodity trading and origination
activities less the costs of commodities sold, including changes in the fair
value of our derivative contracts.

For the quarter ended March 31, 2004, our gross margin improved by $231
million compared to the same period in 2003. This improvement was due primarily
to a $314 million decrease in the fair value of our derivatives, principally our
natural gas contracts, during 2003 compared to a $148 million decrease in the
fair value of our trading positions during 2004. We sell natural gas at a fixed
price in many of our trading contracts. The increase in natural gas futures
prices in the first quarter of 2003 was more significant than the increase in
the first quarter of 2004, resulting in a decrease in the fair value of these
derivatives in the first quarter of 2003 that was greater than the same period
in 2004. Also contributing to this improvement was $34 million of losses related
to the early termination of some of our derivative and non-derivative contracts
in 2003, compared to less than $1 million in 2004. Our non-derivative contracts
also had settlement losses of $33 million in 2004 compared to $48 million in
2003, which primarily related to demand charges we could not recover on existing
transportation contracts. In 2003, we were actively liquidating the derivative
and non-derivative positions in our trading portfolio. In 2004, we refocused our
efforts on managing the existing positions in our portfolio and, as a result,
began to experience the benefits of previous contract terminations through lower
demand charges. These improvements were partially offset by a $15 million
increase in the fair value of our Midwest derivative tolling agreement in 2004
compared to a $38 million increase in 2003. This tolling contract is sensitive
to changes in forecasted power prices relative to forecasted natural gas prices
in the Midwest. We expect the fair value of this contract to be volatile over
its entire contract term, which extends through 2019.

For the quarter ended March 31, 2004, our operating expenses decreased by
$35 million compared to the same period in 2003. This decrease was primarily due
to $11 million of amortization expense on a Western Energy Settlement obligation
that was transferred to our corporate operations in late 2003. Also contributing
to the decrease was a $10 million decrease in corporate overhead allocations and
an $8 million decrease in operating expenses of our London office, which was
closed in 2003.

51

UNREGULATED BUSINESSES -- POWER SEGMENT

Our Power segment has three primary business activities: domestic power
plant operations, domestic power contract restructuring activities and
international power plant operations. Below are our segment operating results, a
summary of the operating results of each of its activities and an analysis of
those results for the quarters ended March 31:

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

(1) Gross margin consists of revenues from our power plants and the initial net
gains and losses incurred in connection with the restructuring of power
contracts, as well as the subsequent revenues, cost of electricity purchases
and changes in fair value of those contracts. The cost of fuel used in the
power generation process is included in operating expenses.

Domestic Power Plant Operations

Our domestic power plant operations relate to the ownership and operation
of power plant assets in the U.S. For the quarter ended March 31, 2004, the EBIT
generated by our domestic power plant operations was $262 million higher than
the same period in 2003. This increase was primarily due to a decrease in the
amount of impairments in 2004 compared to 2003. In 2003, we recognized a $207
million impairment on our investment in Chaparral and an $86 million loss due to
the write-off of receivables as a result of the transfer of our interest in the
Milford power facility to the plant's lenders. In 2004, we recognized
impairments of $11 million on our domestic power plants included as assets held
for sale to adjust the carrying value of these plants to the expected sales
price. Offsetting this net increase was a decrease in operating income in 2004
of $19 million from our East Coast Power facility which was sold during 2003.
The majority of our domestic plants were sold in the second and third quarters
of 2004.

Domestic Power Contract Restructuring Business

Our domestic power contract restructuring business relates to the continued
performance under our previously restructured power contracts. For the quarter
ended March 31, 2004, the EBIT generated by our domestic power contract
restructuring business was $102 million lower than the same period in 2003. This
decrease was due primarily to the announced sale of Utility Contract Funding and
its restructured power contract and related debt, which resulted in a $98
million impairment loss during the first quarter of 2004. In August, 2004, our
Board of Directors approved the sale of wholly owned subsidiaries Cedar Brakes I
and II which own restricted power contracts that are recorded at market value.
Should we sell these entities for less than their market value, we will record a
loss in the period the sale is final. Also contributing to EBIT for the quarters
ended March 31, 2004 and 2003 were increases of $19 million and $20 million in
the fair value of our restructured power contracts.

52

International Power Plant Operations

Brazil. During the first quarter of 2003, we conducted a majority of our
power plant operations in Brazil through Gemstone, an unconsolidated joint
venture. In the second quarter of 2003, we acquired the joint venture partner's
interest in Gemstone and began consolidating Gemstone's debt and its investments
in the Macae, Porto Velho and Araucaria power plants. As a result, our first
quarter 2004 consolidated operating results include the revenues, expenses and
equity earnings from Gemstone's assets. Our first quarter 2003 operating results
include the equity earnings we earned from Gemstone.

For the quarter ended March 31, 2004, the EBIT loss generated by our
Brazilian power plant operations was $78 million compared to EBIT of $22 million
in the same period in 2003. Our 2004 EBIT loss was primarily due to $135 million
of impairments of the Manaus and Rio Negro power plants due to events in the
first quarter of 2004 that may make it difficult to extend their power sales
agreements that expire in 2005 and 2006. These losses were partially offset by
$42 million of operating income from our Macae power plant and $7 million from
our Porto Velho power plant in 2004. Our 2003 EBIT was primarily due to $17
million of equity earnings from Gemstone, which primarily included the operating
results from the Macae, Porto Velho and Araucaria power plants above and the
cost of the debt held by Gemstone.

Other International. For the quarter ended March 31, 2004, the EBIT
generated by our other international power operations was $5 million lower than
the same period in 2003. The decrease was primarily due to a decrease in EBIT
from our Central American and European power plants, which primarily resulted
from increased fuel and maintenance expenses.

Other Power Operations

Our other power operations consist of the indirect expenses and general and
administrative costs associated with our domestic and international operations,
including legal, finance and engineering costs, and the costs of carrying our
power turbine inventory. Direct general and administrative expenses of our
domestic and international operations are included in EBIT of those operations.
In the first quarter 2004, our general and administrative expenses remained
relatively consistent with the same period in 2003.

We are currently in the process of selling a number of our domestic and
international power assets. As these sales occur and as sales agreements are
negotiated and approved, it is possible that impairments of these assets may
occur, and these impairments may be material.

UNREGULATED BUSINESSES -- FIELD SERVICES SEGMENT

Our Field Services segment conducts our midstream activities which include
gathering and processing of natural gas. Until September 2004, our assets
principally consisted of our general and limited partner holdings of GulfTerra,
a publicly traded master limited partnership in which our subsidiary served as
the general partner, and consolidated processing assets in south Texas and south
Louisiana. In September 2004, we sold substantially all of our remaining
interests in GulfTerra as well as our south Texas processing plants to
Enterprise as part of the merger transaction between GulfTerra and Enterprise.
Following these sales, substantially all of our gathering and processing
business will be conducted through our remaining ownership interests in the
merged partnership. For a discussion of our ownership interests in GulfTerra and
our activities with the partnership, see Item 1, Financial Statements, Note 17.

Investment in GulfTerra

We recognize earnings and receive cash from GulfTerra in several ways,
including through a share of the partnership's cash distributions and through
our ownership of limited, preferred and general partner interests. During 2003,
the primary source of earnings in our Field Services segment was from our equity
investment in GulfTerra. Our sale of an effective 50 percent interest in
GulfTerra's general partner in December 2003 as well as the completion of the
sale in September 2004 of our remaining interest in the general partner of
GulfTerra (upon which we received cash and a 9.9 percent interest in the general
partner of Enterprise Products GP, LLC) has and will continue to result in lower
equity earnings in 2004. In addition, we have

53

agreed to provide a total of $45 million in payments during the three years
after the merger becomes effective. Prior to completion of the sale of
substantially all of our interests in GulfTerra to Enterprise, we received
management fees under an agreement to provide operational and administrative
services to the partnership. These management fees increased as a result of
GulfTerra's asset acquisitions in 2002 and 2003. Upon the closing of the merger
of GulfTerra and Enterprise, these fees and many of the internal costs of
providing these management services were eliminated. We are reimbursed for costs
paid directly by us on the partnership's behalf. For the quarters ended March
31, 2004 and 2003, we were reimbursed approximately $22 million and $24 million
for expenses incurred on behalf of the partnership. During 2004, our earnings
and cash distributions received from GulfTerra were as follows:

For a further discussion of the business activities of our Field Services
segment, see our 2003 Annual Report on Form 10-K. Below are the operating
results and analysis of these results for our Field Services segment for the
quarters ended March 31:

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

(1) Gross margins consist of operating revenues less cost of products sold. We
believe this measurement is more meaningful for understanding and analyzing
our operating results because commodity costs play such a significant role
in the determination of profit from our midstream activities.

For the quarter ended March 31, 2004, our EBIT was $9 million higher than
the same period in 2003. The effect of lower natural gas prices in 2004 relative
to liquid prices in our processing operations increased EBIT by $13 million;
however the effect of sales of our gathering and processing assets reduced EBIT
by $6 million.

Overall, margins decreased in the first quarter of 2004 by $2 million as
compared to the same period in 2003 due primarily to a reduction of $14 million
from asset sales in 2003, partially offset by a $13 million increase at our
remaining processing facilities. In these processing operations, while NGL
prices remained relatively flat in 2004 compared to the same period in 2003, we
experienced an increase in margin because of lower natural gas prices in 2004.
These lower natural gas prices increased our margin per unit at our processing
facilities in south Texas and increased the amount of NGLs extracted compared to
2003.

54

Operating expenses for the quarter ended March 31, 2004 were $12 million
lower than the same period in 2004 primarily as a result of asset sales. In
August 2004, our Board of Directors authorized the sale of our Indian Springs
natural gas gathering and processing assets in our Field Services segment. We
currently expect to incur an impairment charge of approximately $13 million
related to these assets.

CORPORATE, NET

Our corporate operations include our general and administrative functions
as well as a telecommunications business and various other contracts and assets,
including financial services and LNG and related items, all of which are
immaterial to our results in 2004. During the first quarter of 2004, we
reclassified our petroleum ship charter operations from discontinued operations
to our continuing corporate operations. Our operating results for all periods
reflect this change.

For the quarter ended March 31, 2004, EBIT in our corporate operations was
$174 million higher than the same period in 2003 due to the following:

We have a number of pending litigation matters, including shareholder and
other lawsuits filed against us. We are currently evaluating each of these suits
as to their merits and our defenses, Settlements and/or adverse rulings against
us related to these and other legal matters would impact our future results.
Additionally, during 2004, we hedged an additional E100 million of our
Euro-denominated debt, which we expect will continue to reduce our exposure to
foreign currency fluctuations. As discussed in Item 1, Financial Statements,
Note 5, we incurred relocation charges of approximately $30 million in the third
quarter of 2004 related to the consolidation of our Houston-based operations. We
estimate the total accrual for our liability will be approximately $80 million
to $100 million.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter ended March 31, 2004, was $9
million higher than the same period in 2003. Below is an analysis of our
interest expense for the quarters ended March 31:

55

Interest expense on long-term debt for the quarter ended March 31, 2004,
was $26 million higher than the same period in 2003. The increase was due to
higher average debt balances from the issuance and consolidation of debt during
2003 and the first quarter of 2004, net of retirements, resulting in increased
interest of $28 million.

Interest expense on our revolving credit facility for the quarter ended
March 31, 2004, was $8 million higher than the same period in 2003. This
increase was due to $20 million in commitment fees on letters of credit
outstanding and amortization of debt issue costs. Partially offsetting this
increase was lower interest expense of $12 million due to lower average
borrowings under these facilities in the first quarter of 2004 compared to 2003.
Our average revolving credit balances, which were based on daily ending
balances, were approximately $638 million, with an average interest rate of
4.65% during the first quarter of 2004.

Other interest for the quarter ended March 31, 2004, was $20 million lower
than the same period in 2003. The decrease was primarily due to a $7 million
decrease in 2004 as a result of the write-off of unamortized financing costs
during 2003 due to the retirement of the Trinity River financing arrangement, a
$6 million reduction in interest expense from the retirement of other financing
obligations, $2 million due to lower interest paid on customer deposits and a $2
million reduction in affiliated interest expense on notes we had with Gemstone,
which were eliminated as a result of the consolidation of these investments in
the second quarter of 2003.

Capitalized interest for the quarter ended March 31, 2004, was $5 million
higher than the same period in 2003 primarily due to higher average interest
rates in 2004 than in 2003.

DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Distributions on preferred interests of consolidated subsidiaries for the
quarter ended March 31, 2004 were $15 million lower than the same period in 2003
primarily due to the refinancing and redemption of our Clydesdale financing
arrangement, the redemptions of the preferred stock on two of our subsidiaries,
Trinity River and Coastal Securities, and the reclassification of our Coastal
Finance I and Capital Trust I mandatorily redeemable preferred securities to
long-term financing obligations as a result of the adoption of SFAS No. 150 in
2003. Based on this reclassification, we began recording the preferred returns
on these securities as interest expense rather than as distributions of
preferred interests. The decrease was also due to the impact of the
consolidations of Chaparral and Gemstone as a result of our acquisitions of
these investments. Our remaining balance of preferred interests as of March 31,
2004 primarily consists of $300 million of preferred stock of our consolidated
subsidiary, El Paso Tennessee Pipeline Co.

INCOME TAXES

Income tax benefits from continuing operations and our effective tax rates
for the quarters ended March 31 were as follows:

Our effective tax rates were different than the statutory tax rate of 35
percent primarily due to:

- state income taxes, net of federal income tax benefit;

- foreign income taxed at different rates, including impairments of certain
of our foreign investments;

- earnings from unconsolidated affiliates where we anticipate receiving
dividends; and

- non-deductible dividends on the preferred stock of subsidiaries.

For the year ended December 31, 2004 we currently expect our effective tax
rate to be significantly different from the statutory rate of 35 percent because
of the closing of the GulfTerra transaction in September 2004. The sale of our
interests in GulfTerra will result in a significant tax gain (versus a much

56

lower book gain) and significant tax expense due to the non-deductibility of
goodwill written off as a result of the transaction. We believe the impact of
this non-deductible goodwill will increase our tax expense (or reduce our tax
benefit) by approximately $139 million.

Proposed tax legislation has been introduced in the U.S. Senate which would
disallow deductions for certain settlements made to or on behalf of governmental
entities. If enacted, this tax legislation could impact the deductibility of the
Western Energy Settlement and could result in a write-off of some or all of the
associated tax assets. Our total tax assets related to the Western Energy
Settlement were $400 million as of March 31, 2004. In such event, our tax
expense would increase.

For a further discussion of our effective tax rates, see Item 1, Financial
Statements, Note 8.

DISCONTINUED OPERATIONS

For the quarter ended March 31, 2004, our after-tax loss from our petroleum
markets discontinued operations was $55 million. The loss was primarily due to
losses of $40 million from the sale of our Eagle Point and Aruba refineries and
$8 million of severance costs for work force reductions as assets are sold.

For the quarter ended March 31, 2003, our after-tax loss from petroleum
markets discontinued operations was $225 million. The loss was primarily due to
impairments of $350 million on our Eagle Point refinery and several of our
chemical assets. The loss was partially offset by operating income from our
Eagle Point and Aruba refineries of $79 million and gains of $55 million from
the sale of our Corpus Christi refinery and the Florida terminalling and marine
assets.

In the second quarter of 2004, our Board of Directors approved exiting our
Canadian and other international natural gas and oil operations. We will report
these operations as discontinued operations beginning in the second quarter of
2004.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 13, which is incorporated herein by
reference.

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CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS

We have made statements in this document that constitute forward-looking
statements, as that term is defined in the Private Securities Litigation Reform
Act of 1995. Forward-looking statements include information concerning possible
or assumed future results of operations. The words "believe," "expect,"
"estimate," "anticipate" and similar expressions will generally identify
forward-looking statements. These statements may relate to information or
assumptions about:

- earnings per share;

- capital and other expenditures;

- dividends;

- financing plans;

- capital structure;

- liquidity and cash flow;

- credit ratings;

- pending legal proceedings, claims and governmental proceedings, including
environmental matters;

- future economic performance;

- operating income;

- management's plans; and

- goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we
believe the assumptions or bases underlying the forward-looking statements are
reasonable and are made in good faith, we caution that assumed facts or bases
almost always vary from actual results, and these variances can be material,
depending upon the circumstances. We cannot assure you that the statements of
expectation or belief contained in the forward-looking statements will result or
be achieved or accomplished. Important factors that could cause actual results
to differ materially from estimates or projections contained in forward-looking
statements are described in our 2003 Annual Report on Form 10-K filed with the
Securities and Exchange Commission on September 30, 2004.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

This information updates, and you should read it in conjunction with,
information disclosed in our 2003 Annual Report on Form 10-K, in addition to the
information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.

There are no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our 2003 Annual Report on
Form 10-K, except as presented below:

MARKET RISK

We are exposed to a variety of market risks in the normal course of our
business activities, including commodity price, foreign exchange and interest
rate risks. We measure risks on the derivative and non-derivative contracts in
our trading portfolio on a daily basis using a Value-at-Risk model. We measure
our Value-at-Risk using a historical simulation technique, and we prepare it
based on a confidence level of 95 percent and a one-day holding period. This
Value-at-Risk was $33 million as of March 31, 2004 and $34 million as of
December 31, 2003, and represents our potential one-day unfavorable impact on
the fair values of our trading contracts.

INTEREST RATE RISK

As of March 31, 2004, we had $1.6 billion of third party long-term power
purchase and power supply derivative contracts. In the second quarter of 2004,
we sold one of the contracts held by Utility Contract Funding, which had a fair
value of $864 million as of March 31, 2004. The sale of this derivative and the
planned sale of Cedar Brakes I and II, which hold two of our power derivative
contracts, will substantially reduce our exposure to interest rate risk related
to these contracts.

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ITEM 4. CONTROLS AND PROCEDURES

During 2003, we initiated a project to ensure compliance with Section 404
of the Sarbanes-Oxley Act of 2002 (SOX), which will apply to us at December 31,
2004. This project entailed a detailed review and documentation of the processes
that impact the preparation of our financial statements, an assessment of the
risks that could adversely affect the accurate and timely preparation of those
financial statements, and the identification of the controls in place to
mitigate the risks of untimely or inaccurate preparation of those financial
statements. Following the documentation of these processes, which was
substantially concluded by December 2003, we initiated an internal review or
"walk-through" of these financial processes by the financial management
responsible for those processes to evaluate the design effectiveness of the
controls identified to mitigate the risk of material misstatements occurring in
our financial statements. We also initiated a detailed process to evaluate the
operating effectiveness of our controls over financial reporting. This process
involves testing the controls for effectiveness, including a review and
inspection of the documentary evidence supporting the operation of the controls
on which we are placing reliance.

In September 2004, we completed investigations surrounding matters that
gave rise to a restatement of our historical financial statements for the period
from 1999 to 2002 and the first nine months of 2003. These investigations
identified a number of internal control weaknesses which we reported as material
control weaknesses in our Annual Report on Form 10-K.

The following are the internal control deficiencies identified as a result
of our SOX implementation and from the independent reviews that led to the
restatements of our historical financial statements, which we have previously
disclosed:

- A weak control environment surrounding the booking of our natural gas and
oil reserves in the Production segment;

- Inadequate controls over access to our proved natural gas and oil reserve
system;

- Inadequate documentation of policies and procedures related to proved
natural gas and oil reserves booking;

- Inadequate documentation of accounting conclusions in prior periods
related to complex accounting standards;

- Lack of formal documentation and communication of policies and procedures
with respect to accounting matters;

- Ineffective monitoring activities to ensure compliance with existing
policies, procedures and accounting conclusions (in some cases as a
result of inadequate staffing);

- Lack of formal evidence to substantiate monitoring activities were
adequately performed (e.g. monitoring activities, such as meetings and
report reviews, were not always documented in a way to objectively
confirm the monitoring activities occurred);

- Inadequate change management and security access to our information
systems (e.g., program developers were allowed to migrate system changes
into production and passwords for some of our applications did not adhere
to the corporate policy for effective passwords);

- Lack of proper segregation of duties related to manual journal entry
preparation and procurement activities (e.g., our financial accounting
system was not designed to prevent the same person from posting an entry
that prepared the entry and a buyer of goods could also receive for the
goods); and

- Untimely preparation and review of volume and accounting reconciliations.

We have communicated to our Audit Committee and to our external auditors
the deficiencies identified to date in our internal controls over financial
reporting as well as the remediation efforts that we have underway. Our
management, with the oversight of our Audit Committee, is committed to
effectively remediate known deficiencies as expeditiously as possible and
continues its extensive efforts to comply with

60

Section 404 of SOX by December 31, 2004. Consequently, we have made the
following changes to our internal controls:

- Added members to our Board of Directors, including our Audit Committee,
and our executive management team with extensive experience in the
natural gas and oil industry;

- Formed an internal committee to provide oversight of the proved natural
gas and oil reserve estimation process, which is staffed with appropriate
technical, financial reporting and legal expertise;

- Continued use of an independent third-party reserve engineering firm,
selected by and reporting annually to the Audit Committee of the Board of
Directors, to perform an independent assessment of our proved natural gas
and oil reserves;

- Formed a centralized proved natural gas and oil reserve evaluation and
reporting function, staffed primarily with newly hired personnel that
have extensive industry experience, that is separate from the operating
divisions and reports to the president of Production and Non-regulated
Operations;

- Restricted security access to the proved natural gas and oil reserve
system to the centralized reserve reporting staff;

- Revised our documentation of procedures and controls for estimating
proved natural gas and oil reserves;

- Enhanced internal audit reviews to monitor booking of proved natural gas
and oil reserves;

- Implemented standard information system policies and procedures to
enforce change management and segregation of responsibilities when
migrating programming changes to production and strengthened security
policies and procedures around passwords for applications and databases;

- Modified systems and procedures to ensure appropriate segregation of
responsibilities for manual journal entry preparation and procurement
activities;

- Formalized our account reconciliation policy and timely completed all
material account reconciliations; and

- Developed and implemented formal training to educate company personnel on
management's responsibilities mandated by SOX Section 404, the components
of the internal control framework on which we rely and the relationship
to our company values including accountability, stewardship, integrity
and excellence.

We are in the process of implementing the following changes to our internal
controls and expect to have them implemented by December 31, 2004:

- Improved training regarding SEC guidelines for booking proved natural gas
and oil reserves;

- Formal communication of procedures for documenting accounting conclusions
involving interpretation of complex accounting standards, including
identification of critical factors that support the basis for our
conclusion;

- Evaluation, formalization and communication of required policies and
procedures;

- Improved monitoring activities to ensure compliance with policies,
procedures and accounting conclusions; and

- Review of the adequacy, proficiency and training of our finance and
accounting staff.

Many of the deficiencies in our internal controls that we have identified
are likely the result of significant changes the company has undergone during
the past five years as a result of major acquisitions and reorganizations. As we
continue our SOX Section 404 compliance efforts, including the testing of the
effectiveness of our internal controls, we may identify additional deficiencies
in our system of internal controls that either individually or in the aggregate
may represent a material weakness requiring additional remediation efforts.
61

We did not make any changes to our internal controls over financial
reporting during the quarter ended March 31, 2004, that have had a material
adverse affect or are reasonably likely to have a material adverse affect on our
internal controls over financial reporting. However, we have made significant
changes to improve our internal controls during the quarter ended March 31,
2004, and subsequent to that date.

We also undertook a review of our overall disclosure controls and
procedures. Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information required to be
disclosed by us in the reports that we file or submit under the Securities
Exchange Act of 1934 is accumulated and communicated to our management,
including our principal executive and principal financial officers, or persons
performing similar functions, as appropriate to allow timely decisions regarding
required disclosure.

As a result of the deficiencies described above, we concluded that our
disclosure controls and procedures were not effective at March 31, 2004.
However, to address the deficiencies in our internal controls, we expanded our
disclosure controls and procedures to include additional analysis and other
post-closing procedures to ensure our disclosure controls and procedures were
effective over the preparation of these financial statements. Consequently, we
concluded that our disclosure controls and procedures over the preparation of
these financial statements were effective.

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PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Note 13, which is incorporated herein by reference.
Additional information about our legal proceedings can be found in Part I, Item
3 of our Annual Report on Form 10-K filed with the Securities and Exchange
Commission on September 30, 2004.

ITEM 2. UNREGISTERED SALES OF EQUITY 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

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.

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.

63

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.

EL PASO CORPORATION

Date: October 27, 2004 /s/ D. Dwight Scott
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: October 27, 2004 /s/ Jeffrey I. Beason
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

64

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.