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 SEPTEMBER 30, 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 December 16,
2004: 643,194,441

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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 September 30, 2004, and
for the quarters and nine months ended September 30, 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 all periods presented have
been reclassified to reflect our Canadian and certain other international
natural gas and oil production operations as discontinued operations. Also, our
results for the quarter and nine months ended September 30, 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 and oil production. These restatements are further discussed in our
2003 Annual Report on Form 10-K. Finally, 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, eliminating, or refinancing approximately $4.2 billion of debt
and other obligations ($2.6 billion through September 30, 2004) (see Note
11);

- 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 12); and

- entering into a new credit agreement in November 2004 to refinance our
previous revolving credit facility with an aggregate of $3 billion in
financings consisting of a $1.25 billion, five-year term loan; a $1.0
billion, three-year revolving credit facility; and a $750 million,
five-year funded letter of credit facility (see Note 11).

Liquidity Update

During 2004, we received waivers and amendments to our then existing
revolving credit facility and various other financing arrangements to address
events that we believe would have constituted an event of default; specifically
under the provisions in those arrangements related to the timely filing of our
financial statements, representations and warranties on the accuracy of our
historical financial statements and on our

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debt to total capitalization ratio. We have filed our financial statements
within the time frames granted by these waivers.

In November 2004, we replaced our previous revolving credit facility which
was scheduled to mature in June 2005, with a new credit agreement with a group
of lenders for an aggregate of $3 billion in financings. The new credit
agreement consists of a $1.25 billion, five-year term loan; a $1 billion,
three-year revolving credit facility under which we can issue letters of credit;
and an additional $750 million, five-year funded letter of credit facility. The
letter of credit facility provides us the ability to issue letters of credit or
borrow any unused capacity as term loans. The new credit agreement is
collateralized by our interests in El Paso Natural Gas Company (EPNG), Tennessee
Gas Pipeline Company (TGP), ANR Pipeline Company (ANR), Colorado Interstate Gas
Company (CIG), Wyoming Interstate Company Ltd. (WIC), ANR Storage Company and
Southern Gas Storage Company.

Our new credit agreement provided approximately $220 million in net
additional borrowing availability (after repayment of an existing obligation of
approximately $229 million and various other items) as compared to our previous
revolving credit facility. Upon closing of the new credit agreement, we borrowed
$1.25 billion under the term loan and utilized the $750 million letter of credit
facility and approximately $0.4 billion of the $1 billion revolving credit
facility to replace approximately $1.2 billion of letters of credit issued under
our previous revolving credit facility.

El Paso CGP Company, our subsidiary, has not yet filed its financial
statements for the third quarter of 2004, as required under several of its, and
its affiliates', financing arrangements. We believe El Paso CGP's financial
statements will be filed prior to any notice being given or within the allowed
time frames under those arrangements such that there will be no event of
default.

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.

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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 income (loss) and income (loss) per share had we applied SFAS No.
123:

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:

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

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facility. We own a 75 percent equity interest in Blue Lake. This entity has $9
million of third party debt as of September 30, 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
$33 million as of September 30, 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. As
of September 30, 2004, these entities consisted primarily of 21 equity
investments held in our Power segment that had interests in power generation and
transmission facilities with a total generating capacity of approximately 7,800
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 ($1.6
billion as of September 30, 2004) and our guarantees and other agreements
associated with these entities (a maximum of $104 million as of September 30,
2004).

During our adoption of FIN No. 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 through 2019. 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
nine months ended September 30, 2004 and 2003, and as of September 30, 2004 and
December 31, 2003:

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
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.

9

Goodwill and Other Intangible Assets

Our intangible assets consist of goodwill resulting from acquisitions and
other intangible assets. The net carrying amounts of our goodwill as of
September 30, 2004, and the changes in the net carrying amounts of goodwill for
the nine months ended September 30, 2004, for each of our segments are as
follows:

In September 2004, we completed the sale of substantially all of our
interests in GulfTerra Energy Partners (GulfTerra), as well as certain
processing assets in our Field Services segment, to affiliates of Enterprise
Products Partners, L.P. (Enterprise). As a result of these sales, we determined
that the remaining assets in our Field Services segment could not support the
goodwill in this segment, and therefore, we fully impaired this amount in the
third quarter of 2004. See Note 16 for a further discussion of the impact of the
Enterprise transactions on our goodwill and other intangible assets during the
third quarter of 2004.

New Accounting Pronouncements Not Yet Adopted

Accounting for Natural Gas and Oil Producing Activities. 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. It will also
require these companies to exclude future cash outflows associated with settling
asset retirement liabilities from their full cost ceiling test calculation.
Finally, this standard will require disclosure of the impact of a company's
asset retirement obligations on its oil and gas producing activities, ceiling
test calculations and depreciation, depletion and amortization calculations. We
will adopt the provisions of this pronouncement in the first quarter of 2005 and
are currently evaluating its impact, if any, on our consolidated financial
statements.

Accounting for Inventory Costs. In November 2004, the FASB issued SFAS No.
151, Inventory Costs, an amendment of ARB No. 43, Chapter 4. This statement
clarifies the types of costs that should be expensed rather than capitalized as
inventory. This statement also clarifies the circumstances under which fixed
overhead costs associated with operating facilities involved in inventory
processing should be capitalized. The provisions of SFAS No. 151 are effective
for fiscal years beginning after June 15, 2005, and may impact certain inventory
costs we incur after January 1, 2006. We are currently evaluating the impact, if
any, of this standard on our consolidated financial statements.

Accounting for Stock-Based Compensation. In December 2004, the FASB issued
SFAS No. 123R, Share-Based Payment: an amendment of SFAS No. 123 and 95. This
standard requires that companies record the fair value of their stock-based
compensation arrangements as a liability or as a component of equity on the date
they are granted to employees. The classification of these arrangements as
liabilities or as a component of equity is based on whether the obligations can
be settled in cash and/or in stock. Regardless of their treatment as liabilities
or equity, these amounts are to be expensed over the vesting period of the
arrangements. This standard is effective for interim periods beginning after
June 15, 2005, at which time companies can select whether they will apply the
standard retroactively by restating their historical financial statements or
prospectively for new stock-based compensation arrangements and the unvested
portion of existing arrangements. We will adopt this pronouncement in the third
quarter of 2005 and are currently evaluating its impact on our consolidated
financial statements.

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Accounting for Deferred Taxes on Foreign Earnings. In December 2004, the
FASB is expected to issue FASB Staff Position (FSP) No. 109-2, Accounting and
Disclosure Guidance for the Foreign Earnings Repatriation Provision within the
American Jobs Creation Act of 2004. FSP No. 109-2 will clarify the existing
accounting literature that requires companies to record deferred taxes on
foreign earnings, unless they intend to indefinitely reinvest those earnings
outside the U.S. This pronouncement will temporarily allow companies that are
evaluating whether to repatriate foreign earnings under the American Jobs
Creation Act of 2004 to delay recognizing any related taxes until that decision
is made. This pronouncement will also require companies that are considering
repatriating earnings to disclose the status of their evaluation and the
potential amounts being considered for repatriation. The U.S. Treasury
Department has not issued final guidelines for applying the repatriation
provisions of the American Jobs Creation Act, and we continue to evaluate this
legislation and FSP No. 109-2 to determine whether we will repatriate any
foreign earnings and the impact, if any, that this pronouncement will have on
our 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 first quarter of 2003.

Gemstone. As discussed more completely in our 2003 Annual Report on Form
10-K, we acquired all of the outstanding third party interests in Gemstone for
approximately $50 million in April 2003. The results of Gemstone's operations
have been included in our consolidated financial statements beginning April 1,
2003. Had the acquisition been effective January 1, 2003, our revenues,
operating income, and net income for the quarter ended March 31, 2003 would not
have been significantly different, and basic and diluted earnings per share
would have been unaffected.

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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 as of September 30, 2004.
(3) The sales of 21 of these plants were completed as of September 30, 2004, and
three additional sales were completed in the fourth quarter of 2004.
(4) 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 by $64 million for the nine months
ended September 30, 2004. Proceeds also exclude any non-cash consideration
received in these sales.

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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 $56 million for the nine months ended
September 30, 2003.

See Notes 6 and 16 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 to be disposed of as held for sale or, if
appropriate, discontinued operations when they have received appropriate
approvals by our management or Board of Directors and when they meet other
criteria. These assets consist of certain of our domestic power plants and
natural gas gathering and processing assets in our Field Services segment. The
following table details the items that have been reflected as current assets and
liabilities held for sale in our balance sheets as of September 30, 2004 and
December 31, 2003.

Discontinued Operations

International Natural Gas and Oil Production Operations. During 2004, our
Canadian and certain other international natural gas and oil production
operations were approved for sale. As of November 2004, we have completed the
sale of all of our Canadian operations and substantially all of our operations
in Indonesia for total proceeds of approximately $389 million. During the nine
months ended September 30, 2004, we recognized approximately $98 million in
losses based on our decision to sell these assets. We expect to complete the
sale of the remainder of these properties in early 2005.

Petroleum Markets. During 2003, our Board of Directors approved the sales
of our petroleum markets businesses and operations. These businesses and
operations consisted of our Eagle Point and Aruba refineries, our asphalt
business, our Florida terminal, tug and barge business, our lease crude
operations, 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 pre-tax impairment
charges of approximately $1,337 million during the nine months ended September
30, 2003 related to these 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 $59 million in
the first nine months of 2003 from the sale of our Corpus Christi refinery, our
asphalt assets, our 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
recorded realized losses of approximately $37 million in the first nine months
of 2004, primarily from the sale of our Aruba and Eagle Point refineries. 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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The petroleum markets, coal mining and our other international natural gas
and oil production operations discussed above, 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 September 30, 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 for the nine months ended September 30:

Our 2004 restructuring costs consisted of employee severance costs which
included severance payments and costs for pension benefits settled under
existing benefit plans, as well as office relocation and consolidation costs. As
of September 30, 2004, substantially all of the employee severance, retention
and transition costs had been paid. For further information on our office
relocation and consolidation costs, see the discussion below.

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 were recorded in the
first quarter of 2003 and 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 announced that we would begin consolidating our
Houston-based operations into one location. This 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 we no longer utilize the leased space. 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 lease obligation, net of estimates for
sub-lease payments, will be approximately $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 $32 million. In addition, we subleased approximately 210,000
square feet in the third and fourth quarters of 2004. Actual moving expenses
related to the relocation will be expensed in the period that they are incurred.
All amounts related to the relocation will be expensed in our corporate
activities.

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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 intangible assets that are a part of our continuing operations. During
each of the periods ended September 30, our loss on long-lived assets was as
follows:

Net Realized (Gain) Loss

Our 2004 net realized gains are primarily related to an $8 million gain on
aircraft sales associated with our corporate activities. Our Power segment also
recorded net gains of approximately $5 million related to the sales of 6 of our
domestic power plants. These gains were partially offset by an $11 million loss
on the sale of our South Texas processing assets in our Field Services segment.
Our 2003 net realized gain was primarily related to a $14 million gain on the
sale of our north Louisiana and Mid-Continent midstream assets in our Field
Services segment, a $6 million gain on the Table Rock sulfur extraction facility
in our Pipelines segment, and a $5 million gain on the sale of non-full cost
pool assets in our Production segment. Partially offsetting these gains were $10
million of losses related to the sale of Mohawk River Funding I in our Power
segment and $8 million of losses related to the sales of assets associated with
our corporate activities in 2003.

Asset and Goodwill Impairments

Our 2004 asset and goodwill impairments primarily occurred in our Field
Services and Power segments. Our Field Services segment recorded a $480 million
impairment of its goodwill that resulted from the sale of substantially all of
our interests in GulfTerra, as well as our processing assets in south Texas to
affiliates of Enterprise in the third quarter of 2004 (see Note 16). We also
recorded $7 million of impairments in the second quarter of 2004 in our Field
Services segment, primarily related to miscellaneous assets that will no longer
be used because of various asset sales. Our Field Services segment also recorded
a $13 million impairment in the third quarter of 2004 on our Indian Springs
natural gas gathering and processing assets to adjust the carrying value of
these assets to their expected sales price. In the first quarter of 2004, our
Power segment recorded a $135 million impairment related to our Manaus and Rio
Negro power plants in Brazil and a $98 million impairment related to the sale of
our subsidiary, UCF, which owns a restructured power contract. The impairments
in Brazil were primarily due to events in the first quarter of 2004 that may
make it difficult to extend the plants' power sales agreements that expire in
2005 and 2006. See Note 12 for a further discussion of the matters related to
Brazil. Our Power segment also recorded $62 million of impairments on our
domestic power plants to adjust the carrying value of these plants to their
expected sales price. Of the $62 million of impairments, $52 million was
recorded in the third quarter.

Our 2003 impairment charges primarily related to our telecommunications and
LNG operations, both included in our corporate activities. Our
telecommunications operations recorded charges of $396 million, which included a
$269 million impairment charge (including a $163 million writedown of goodwill)
related to our investment in the wholesale metropolitan transport services,
primarily in Texas and an impairment of our Lakeside Technology Center facility
of $127 million based on probability-weighted scenarios of what the asset could
be sold for in the current market. We also recorded $37 million of impairments
on our LNG assets and a $22 million impairment on turbines classified as
non-current assets in our Power segment as a result of our plan to reduce our
involvement in that business.

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7. INCOME TAXES

Income taxes included in our income (loss) from continuing operations for
the periods ended September 30, were as follows:

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 nine months of
2004, our overall effective tax rate on continuing operations was significantly
different than the statutory rate due primarily to the GulfTerra transaction and
impairments of certain of our foreign investments. The sale of our interests in
GulfTerra associated with the merger between GulfTerra and Enterprise in
September 2004 resulted in a significant taxable gain (compared to a lower book
gain) and significant tax expense due to the non-deductibility of a significant
portion of the goodwill written off as a result of the transaction. The impact
of this non-deductible goodwill increased our tax expense by approximately $139
million. See Note 16 for a further discussion of the merger and related
transactions. Additionally, on the impairment of certain of our foreign
investments, primarily during the first quarter of 2004, we received no U.S.
federal income tax benefit. The combination of these items resulted in an
overall tax expense for a period in which there was a pre-tax loss.

In 2004, Congress proposed but failed to enact legislation which would
disallow deductions for certain settlements made to or on behalf of governmental
entities. We expect Congress to reintroduce similar legislation in 2005. 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 approximately $400
million as of September 30, 2004.

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8. EARNINGS PER SHARE

We have excluded 17 million and 16 million of potentially dilutive
securities for the quarters ended September 2004 and 2003, and 16 million of
potentially dilutive securities for the nine months ended September 30, 2004 and
2003, from the determination of diluted earnings per share (as well as their
related income statement impacts) due to their antidilutive effect on income
(loss) per common share. The excluded securities included stock options, trust
preferred securities and convertible debentures.

9. PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of the derivatives used
in our price risk management activities as of September 30, 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 $942 million of derivative contracts sold in connection with the
sales of UCF and Mohawk River Funding IV in 2004.

(2) In December 2004, we designated other commodity-based derivative contracts
with a fair value loss of $592 million as hedges of our 2005 and 2006
natural gas production, and, as a result, we will reclassify this amount to
derivatives designated as hedges in the fourth quarter of 2004. As of
September 30, 2004 these contracts had a fair value loss of $567 million.

(3) During the nine months ended September 30, 2004, we entered into new cross
currency hedge transactions that convert E100 million of our fixed rate
Euro-denominated debt into $121 million of floating rate debt.

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

10. INVENTORY

We have the following inventory recorded on our balance sheets:

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11. 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 No. 46 (see Note 2).

(2) In the fourth quarter of 2004, we entered into an agreement with Enron that
liquidated two derivative swap agreements (reflected in other current and
other non-current liabilities in our balance sheet as of September 30, 2004)
in exchange for approximately $213 million of 6.5% one year notes.
Subsequent to the closing of our new credit agreement, these notes were paid
in full.

(3) Proceeds from the $1.25 billion term loan under the new credit agreement
entered into in November 2004.

(4) This debt was eliminated when we sold our interests in Mohawk River Funding
IV and UCF.

(5) In December 2004, we repurchased these 4% yield-to-maturity zero-coupon
debentures. The amount shown as principal is the carrying value on the date
the debt was retired as compared to its maturity value in 2021 of $196
million.

21

Credit Facilities

During 2004, we received waivers and amendments to our then existing
revolving credit facility and various other financing arrangements to address
events that we believe would have constituted an event of default; specifically
under the provisions in those arrangements related to the timely filing of our
financial statements, representations and warranties on the accuracy of our
historical financial statements and on our debt to total capitalization ratio.
All conditions to these waivers have now been met.

In November 2004, we replaced our previous revolving credit facility, which
was scheduled to mature in June 2005, with a new credit agreement with a group
of lenders for an aggregate of $3 billion in financings. As of September 30,
2004, we had no outstanding borrowings, but had $1.1 billion of letters of
credit issued under our previous revolving credit facility. The new credit
agreement provides approximately $220 million in net additional borrowing
availability (after repayment of our Lakeside Technology Center obligation of
approximately $229 million and various other items), as compared with the
borrowing availability under our previous revolving credit facility. This new
credit agreement consists of a $1.25 billion five-year term loan; a $1 billion
three-year revolving credit facility; and a $750 million, five-year funded
letter of credit facility. Certain of our subsidiaries, EPNG, TGP, ANR and CIG,
also continue to be eligible borrowers under the new credit agreement.
Additionally, El Paso and certain of its subsidiaries have guaranteed borrowings
under the new credit agreement which is collateralized by our interests in EPNG,
TGP, ANR, CIG, WIC, ANR Storage Company and Southern Gas Storage Company.

Upon closing of the new credit agreement, we borrowed $1.25 billion under
the term loan and utilized the $750 million letter of credit facility and
approximately $0.4 billion of the $1 billion revolving credit facility to
replace approximately $1.2 billion of letters of credit issued under our
previous revolving credit facility. The term loan bears interest at LIBOR plus
2.75 percent, matures in November 2009, and will be repaid in increments of $5
million per quarter with the unpaid balance due at maturity. Under the new
revolving credit facility, which matures in November 2007, we can borrow funds
at LIBOR plus 2.75 percent, or issue letters of credit at 2.75 percent plus a
fee of 0.25 percent of the amount issued. We pay an annual commitment fee of
0.75 percent on any unused capacity under the revolving credit facility.
Finally, under the terms of the new credit agreement, certain lenders funded a
$750 million letter of credit facility that provides us the ability to issue
letters of credit or borrow any unused capacity under the letter of credit
facility as term loans with a maturity in November 2009. We pay LIBOR plus 2.75
percent on any amounts borrowed under the letter of credit facility, and 2.85
percent on letters of credit and unborrowed funds.

Restrictive Covenants

Our restrictive covenants includes restrictions on debt levels,
restrictions on liens securing debt and guarantees, restrictions on mergers and
on the sales of assets, capitalization requirements, dividend restrictions and
cross default and cross-acceleration provisions. A breach of any of these
covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries. Under our new credit agreement the
significant debt covenants and cross defaults are:

(a) El Paso's ratio of Debt to Consolidated EBITDA, each as defined in the
new credit agreement, shall not exceed 6.50 to 1.0 at any time prior
to September 30, 2005, 6.25 to 1.0 at any time on or after September
30, 2005 and prior to June 30, 2006, and 6.00 to 1.0 at any time on or
after June 30, 2006 until maturity;

(b) El Paso's ratio of Consolidated EBITDA, as defined in the new credit
agreement, to interest expense plus dividends paid shall not be less
than 1.60 to 1.0 prior to March 31, 2006, 1.75 to 1.0 on or after March
31, 2006 and prior to March 31, 2007, and 1.80 to 1.0 on or after March
31, 2007 until maturity;

(c) EPNG, TGP, ANR, and CIG cannot incur incremental Debt if the
incurrence of this incremental Debt would cause their Debt to
Consolidated EBITDA ratio, each as defined in the new credit
agreement, for that particular company to exceed 5 to 1;

22

(d) the proceeds from the issuance of Debt by our pipeline company
borrowers can only be used for maintenance and expansion capital
expenditures or investments in other FERC-regulated assets, to fund
working capital requirements, or to refinance existing debt; and

(e) the occurrence of an event of default and after the expiration of any
applicable grace period, with respect to Debt in an aggregate
principal amount of $200 million or more.

In addition to the above restrictions and default provisions, we and/or our
subsidiaries are subject to a number of additional restrictions and covenants.
These restrictions and covenants include limitations of additional debt at some
of our subsidiaries; limitations on the use of proceeds from borrowing at some
of our subsidiaries; limitations, in some cases, on transactions with our
affiliates; limitations on the occurrence of liens; potential limitations on the
abilities of some of our subsidiaries to declare and pay dividends and potential
limitations on some of our subsidiaries to participate in our cash management
program, and limitations on our ability to prepay debt.

El Paso CGP Company, our subsidiary, has not yet filed its financial
statements for the third quarter of 2004, as required under several of its and
its affiliates financing arrangements. We believe El Paso CGP's financial
statements will be filed prior to any notice being given or within the allowed
time frames under those arrangements such that there will be no event of
default.

Letters of Credit

We enter into letters of credit in the ordinary course of our operating
activities. As of September 30, 2004, we had outstanding letters of credit of
approximately $1.2 billion, of which $1.1 billion was outstanding under our
previous revolving credit facility and $65 million was supported with cash
collateral. Included in this amount were $0.8 billion of letters of credit
securing our recorded obligations related to price risk management activities.
Prior to the closing of our new credit agreement, we had approximately $1.2
billion of letters of credit issued pursuant to our previous revolving credit
facility. We used the new $750 million letter of credit facility and
approximately $0.4 billion of the new $1.0 billion revolving credit facility to
replace these issued letters of credit.

12. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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

23

- 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, El Paso, the California Public Utilities Commission (CPUC),
Pacific Gas and Electric Company, Southern California Edison Company, and the
City of Los Angeles filed the JSA described above with the FERC. 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. During the nine months ended
September 30, 2003, we recorded additional pretax charges of $103 million based
upon reaching definitive settlement agreements. Charges and expenses associated
with the Western Energy Settlement are included in operations and maintenance
expense in our consolidated statements of income. In June 2004, the settlement
became effective and $602 million was released to the settling parties. This
amount is shown as a reduction of our cash flows from operations in the second
quarter of 2004. Of the amount released, $568 million has been previously held
in an escrow account pending final approval of the settlement. The release of
these restricted funds is included as an increase in our cash flows from
investing activities. Our remaining obligation as of September 30, 2004 under
the Western Energy Settlement consists of a discounted 20-year cash payment
obligation of $386 million and a price reduction under a power supply contract,
which is included in our price risk management activities. 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
collateral requirement is being reduced as payments under the 20 year obligation
are made. For an issue regarding the potential tax deductibility of our Western
Energy Settlement charges, see Note 7.

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
raised issues of market power and was a violation of the FERC's marketing
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. In November 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 in March 2004. In
April 2004, certain shippers appealed both FERC orders on this matter to the
U.S. Court of Appeals for the District of Columbia Circuit. Oral argument before
the court of appeals was held in October 2004.

Shareholder Class Action Suits. Beginning in July 2002, 12 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 12th 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.

Beginning in February 2004, 17 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

24

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 in July
2004.

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 the Sarbanes-Oxley Act of 2002 against certain
of the individually named defendants.

Our costs and exposures in these lawsuits are not currently determinable.
We are currently evaluating each of these cases as to their merits, our
defenses, their possible settlement and potential insurance recoveries.

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
was subsequently 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.

Retiree Medical Benefits Matters. We currently serve as the plan
administrator for a medical benefits plan that covers a closed group of retirees
of the Case Corporation who retired on or before June 30, 1994. Case was
formerly a subsidiary of Tenneco, Inc. that was spun off prior to our
acquisition of Tenneco in 1996. In connection with the Tenneco-Case
Reorganization Agreement of 1994, Tenneco assumed the obligation to provide
certain medical and prescription drug benefits to eligible retirees and their
spouses. We assumed this obligation as a result of our merger with Tenneco.
However, we believe that our liability for these benefits is limited to certain
maximums, or caps, and costs in excess of these maximums are assumed by plan
participants. In 2002, we and Case were sued by individual retirees in federal
court in Detroit, Michigan in an action entitled Yolton et al. v. El Paso
Corporation and Case Corporation. The suit alleges, among other things, that El
Paso violated ERISA, and that Case should be required to pay all amounts above
the cap. Historically, amounts above the cap have been approximately $1.8
million per month. Case further filed claims against El Paso asserting that El
Paso is obligated to indemnify, defend, and hold Case harmless for the amounts
it would be required to pay. In February 2004, a judge ruled that Case would be
required to pay the amounts incurred above the cap. Furthermore, in September
2004, a judge ruled that pending resolution of this matter, El Paso must
indemnify and reimburse Case for approximately $1.8 million in monthly amounts
above the cap. Our motion for reconsideration of these orders was denied in
November 2004. These rulings have been appealed. In the meantime, El Paso will
indemnify Case for any payments Case makes above the cap. While the outcome of
these matters is uncertain, if we were required to ultimately pay for all future
amounts above the cap, and if Case were not found to be responsible for these
amounts, our exposure could be as high as $400 million.

Natural Gas Commodities Litigation. Beginning in August 2003, several
lawsuits were filed against El Paso and El Paso Marketing L.P. (EPM), formerly
El Paso Merchant Energy L.P., our affiliate, in which plaintiffs alleged, in
part, that El Paso, EPM and other energy companies conspired to manipulate the
price of natural gas by providing false price reporting information to industry
trade publications that published gas indices. In December 2003, those cases
were consolidated with others into a single master file in federal court in New
York for all pre-trial purposes. In September 2004, the court dismissed El Paso
from the master litigation. EPM and approximately 27 other energy companies
remain in the litigation. Our costs and legal exposure related to these lawsuits
and claims are not currently determinable.

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

25

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 in
April 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.

Bank of America. We are a named defendant, along with Burlington
Resources, Inc., in two class action lawsuits styled as Bank of America, et. al.
v. El Paso Natural Gas Company, et. al., and Deane W. Moore, et. al. v.
Burlington Northern, Inc., et. al., each filed in 1997 in the District Court of
Washita County, State of Oklahoma and subsequently consolidated by the court.
The plaintiffs seek an accounting and damages for alleged royalty underpayments
from 1983 to the present on natural gas produced from specified wells in
Oklahoma, plus interest from the time such amounts were allegedly due, as well
as punitive damages. The plaintiffs have filed expert reports alleging damages
in excess of $1 billion. While Burlington accepted our tender of defense in 1997
pursuant to the spin-off agreement entered into in 1992 between EPNG and
Burlington Northern, Inc., and had been defending the matter since that time, it
has recently asserted contractual claims for indemnity against us. We believe we
have substantial defenses to the plaintiffs' claims as well as to the claims for
indemnity. The court has certified the plaintiff classes of royalty and
overriding royalty interest owners, and the parties are proceeding with
discovery. In March 2004, the court dismissed all claims brought on behalf of
the class of overriding royalty interest owners, but denied defendant's other
motions for summary judgment. In September 2004, the court granted several
motions made by Burlington that have the effect of partially reducing the
plaintiffs' claims, but denied Burlington's motion to preclude interest payments
on any amounts found to be owing to plaintiffs. The written order on such
motions has not been issued yet and in the interim, the case is being reassigned
to another trial judge due to conflict issues. It is anticipated that this
matter will be scheduled for trial during 2005. A third action, styled Bank of
America, et. al. v. El Paso Natural Gas and Burlington Resources Oil & Gas
Company, was filed in October 2003 in the District Court of Kiowa County,
Oklahoma asserting similar claims as to specified shallow wells in Oklahoma,
Texas and New Mexico. Defendants succeeded in transferring this action to
Washita County. A class has not been certified. We believe we have substantial
defenses to the plaintiffs' claims as well as to the claims for indemnity. In
December 2004, EPNG and El Paso Production Company were served with another
purported royalty class action lawsuit alleging the failure to pay royalties on
oil produced from the South Erick Field in Beckham County, Oklahoma commencing
in 1957. We believe that EPNG and El Paso Production are entitled to a defense
and indemnity in this action from Burlington under the spin-off agreement of
1992. 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

26

impact on water supplies. We and our subsidiaries are currently one of several
defendants in 59 such lawsuits nationwide, which have been or are in the process
of being 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
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 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 hedges of our natural gas and oil production.

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 with the CFTC of the price reporting matter providing for
the payment of a civil monetary penalty by EPM 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 of this matter.

Storage Reporting. 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. In August 2004, the CFTC announced they had
completed the investigation and found no evidence of wrongdoing. In November
2004, ANR and TGP received a data request from the FERC in connection with its
investigation into the weekly storage withdrawal number reported by the EIA for
the eastern region on November 24, 2004, that was subsequently revised downward
by the EIA. Specifically, ANR and TGP provided information on their weekly EIA
submissions for the weeks ending November 12, 2004 and November 19, 2004.
Neither ANR nor TGP's submissions to the EIA were revised subsequent to their
original submissions. Although ANR made a correction to one daily posting on its
electronic bulletin board during this period, those postings are unrelated to
EIA submissions. In December 2004, ANR received a similar data request from the
CFTC. We are cooperating with the CFTC's request.

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 Nations' 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. In November 2004, we
received an order from the SEC to provide a written statement and to produce
certain documents in connection with the Oil for Food Program. We have also
received an inquiry from the United States Senate's Permanent Subcommittee of
Investigations related to a specific transaction in 2000.

27

In September 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 cooperating with the U.S. Attorney's, the SEC's and the Senate
Subcommittee's investigations of this matter.

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. In June 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 "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.

In November 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. In April 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.

A lawsuit entitled Baldonado et. al. v. EPNG was filed in June 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. Plaintiff's filed their brief and request for
oral argument in November 2004. EPNG will file its brief 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. Parties to four of the settled lawsuits filed an additional lawsuit
titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas in November
2002, seeking additional sums based upon their interpretation of earlier
settlement agreements. This matter has been settled and dismissed.

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

28

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
September 30, 2004, we had approximately $522 million 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 September
30, 2004, we had accrued approximately $389 million, including approximately
$381 million for expected remediation costs and associated onsite, offsite and
groundwater technical studies, and approximately $8 million for related
environmental legal costs, which we anticipate incurring through 2027. Of the
$389 million accrual, $145 million was reserved for facilities we currently
operate, and $244 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 $389 million to
approximately $550 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 ($81 million). Second, where the most
likely outcome cannot be estimated, a range of costs is established ($308
million to $469 million) and if no one amount in 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
September 30, 2004 (in millions):

Balance as of January 1, 2004............................... $412
Additions/adjustments for remediation activities............ 8
Payments for remediation activities......................... (32)
Other changes, net.......................................... 1
----
Balance as of September 30, 2004............................ $389
====

For the remainder of 2004, we estimate that our total remediation
expenditures will be approximately $18 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.

29

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 September 30, 2004, TGP had pre-collected PCB costs by approximately $124
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 September 30, 2004, TGP has recorded a regulatory
liability (included in other non-current liabilities on its balance sheet) of
$95 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 61 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 September 30, 2004,
we have estimated our share of the remediation costs at these sites to be
between $31 million and $46 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 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.

Rates and Regulatory Matters

Proposed Release Regarding Pipeline Integrity Costs. In November 2004, the
FERC issued an industry-wide Proposed Accounting Release that, if enacted as
written, would require our interstate pipelines to expense rather than
capitalize certain costs that are part of our pipeline integrity program. The
accounting release is proposed to be effective January 2005 following a period
of public comment on the release. We are currently reviewing the release and
have not quantified the impact this release will have on our consolidated
financial statements.

Inquiry Regarding Income Tax Allowances. On December 2, 2004, the FERC
issued a notice of inquiry in response to a recent D.C. Circuit decision that
held the FERC had not adequately justified its policy of providing a certain oil
pipeline limited partnership with an income tax allowance equal to the
proportion of its limited partnership interests owned by corporate partners. The
FERC seeks comments on whether the court's reasoning should be applied to other
partnerships or other ownership structures. We own interests in non-taxable
entities that could be affected by this ruling. We cannot predict what impact
this inquiry will have on our interstate pipelines, including those pipelines
that are not owned by a corporate entity, such as Great Lakes Gas Transmission
Limited Partnership which is jointly owned with unaffiliated parties.

30

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 (EPM) owed it approximately $3 million, and that EPM 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, EPM maintained that EPMI owed EPM $30
million due to the termination of a physical power contract, which is included
in the $317 million of filed claims. EPMI filed a lawsuit against EPM and its
guarantor, El Paso, 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 for which final payments were made in the third
quarter of 2004. 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 that time.

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 its 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.

Investments in Brazil. We own and have investments in power, pipeline and
production assets in Brazil with an aggregate exposure, including financial
guarantees, of approximately $1.6 billion as of September 30, 2004. During 2002,
Brazil experienced higher interest rates on local debt for the government and
private sectors, which 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 and interest
rate levels decreased. 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 its economic situation. Some of the specific
issues 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 Araucaria project has a
20-year power purchase agreement (PPA) with a government-controlled regional
utility. In December 2002, the utility ceased making payments to the project
and, as a result, the Araucaria project and the utility are currently involved
in international arbitration over the PPA. A Curitiba court has ruled that the
arbitration clause in the PPA is invalid, and has enjoined the project

31

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 $184 million at September 30, 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 $35 million at September 30, 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 $39 million
at September 30, 2004. Manaus Energia purchases power from both projects through
long-term PPAs. However, the Manaus Project's PPA currently expires in January
2005 and the Rio Negro Project's PPA currently expires in January 2006. 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. Several non-governmental organizations
obtained a preliminary injunction enjoining Manaus Energia from proceeding with
the bid process until a decision on the merits of their complaint was made, but
that injunction has now been lifted, and Manaus Energia received bids in
December 2004. We continue to negotiate PPA term extensions and have received an
offer from Manaus Energia to extend the term of the Manaus and Rio Negro PPAs.
Also, 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 that has resulted in a long-term receivable of $32 million which is
a subject of this lawsuit. Based on the bid process and the expected outcome of
our negotiations to extend the term of the PPAs, we recorded an impairment
charge of approximately $135 million in the first quarter of 2004. We also
recorded a $32 million charge in operation and maintenance expense in our Power
segment in the third quarter of 2004 as a valuation allowance for our overall
exposure in these two projects. We recorded this valuation allowance based on
our current expectation of recoverable amounts based on further negotiations
that have taken place in the fourth quarter of 2004.

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 PPAs. 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 second 345 MW phase of the project. We are negotiating certain
provisions of both PPAs 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 PPAs 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 was $284 million at September 30, 2004. In October 2004, the project
experienced an outage associated with one of its steam turbine generators, which
resulted in a partial reduction in the plant's capacity. We expect to replace or
repair the steam turbine during 2005.

We own a 895 MW gas-fired power plant known as the Macae project located
near the city of Macae, Brazil with a net book value of $707 million at
September 30, 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. 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.

32

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 September 30, 2004, we had
approximately $55 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
September 30, 2004, we had accrued $78 million related to these arrangements.

13. RETIREMENT BENEFITS

The components of net benefit cost (income) for our pension and
postretirement benefit plans for the periods ended September 30 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.

(2) We recognized curtailments in 2004 and 2003 related to a reduction in the
number of employees that participate in our pension and other postretirement
plans, which resulted from our various asset sales and employee severance
efforts in 2004 and 2003.

We made $59 million and $72 million of cash contributions to our
Supplemental Executive Retirement Plan and other postretirement plans during the
nine months ended September 30, 2004 and 2003. We expect to contribute an
additional $2 million to the Supplemental Executive Retirement Plan and $10
million to our 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 will adopt a new accounting standard
in the fourth quarter of 2004 that we believe will not materially affect our
previously reported benefit information and our net benefit cost for the year
ending December 31, 2004.

Retirement Savings Plan

As of June 25, 2004, participants in our retirement savings plan were
temporarily suspended from making future contributions, or transferring other
investment funds, to the El Paso Corporation Stock Fund. This temporary
suspension was necessary because El Paso was not current with all of its SEC
filings. The suspension will be lifted after we become current with our SEC
filings.

33

See Note 12 for an additional matter that could impact our retirement
benefit obligations.

14. CAPITAL STOCK

Common Stock

In January 2004, we issued 8.8 million shares of common stock for $74
million, less issuance costs of $1 million, to satisfy the remaining stock
obligation under our Western Energy Settlement.

Dividends

During the nine months ended September 30, 2004, we paid dividends of $75
million to common stockholders. We have also paid dividends of approximately $25
million subsequent to September 30, 2004. The dividends on our common stock were
treated as a reduction of paid-in-capital since we currently have an accumulated
deficit. On November 18, 2004, the Board of Directors declared a quarterly
dividend of $0.04 per share on the company's outstanding stock. The dividend
will be payable on January 3, 2005 to shareholders of record on December 3,
2004. In addition, El Paso Tennessee Pipeline Co., our subsidiary, pays
dividends (2.0625% per quarter, 8.25% per annum) of approximately $6 million
each quarter on its Series A cumulative preferred stock.

15. 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 continuing corporate operations. During the second quarter of 2004, we
reclassified our Canadian and certain other international natural gas and oil
production operations from our Production segment to discontinued operations in
our financial statements. Our operating results for all periods presented
reflect these changes.

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

34

such as operating income or operating cash flow. Below is a reconciliation of
our EBIT to our income (loss) from continuing operations for the periods ended
September 30:

The following tables reflect our segment results as of and for the periods
ended September 30:

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

(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 operations.

35

36

16. 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. The summarized financial
information below includes our proportionate share of the operating results of
our unconsolidated affiliates, including 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.

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

(1) Includes net income of $3 million and $1 million for the quarters ended
September 30, 2004 and 2003, and $24 million and $6 million for the nine
months ended September 30, 2004 and 2003, related to our proportionate share
of affiliates in which we hold a greater than 50 percent interest.

37

Our income statement reflects our share of net earnings from unconsolidated
affiliates, which includes income or losses directly attributable to the net
income or loss of our equity investments as well as impairments and other
adjustments. The table below reflects our earnings (losses) from unconsolidated
affiliates for the periods ended September 30:

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

(1) 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).

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

(3) These impairments resulted from the anticipated sales of these investments,
which were substantially completed in the third quarter of 2004.

(4) This impairment resulted from the anticipated loss from the sale of East
Coast Power, L.L.C., which was completed in the fourth quarter of 2003.

We received distributions and dividends from our investments of $72 million
and $116 million for each of the quarters ended September 30, 2004 and 2003, and
$240 million and $273 million for the nine months ended September 30, 2004 and
2003.

Related Party Transactions

We enter into a number of transactions with our unconsolidated affiliates
in the ordinary course of conducting our business. The following table shows the
income statement impact on transactions with our affiliates for the periods
ended September 30:

38

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 contributed to our
income through our general partner interest and our ownership of common and
preference units. We did not have any loans to or from GulfTerra.

In September 2004, in connection with the closing of the merger between
GulfTerra and Enterprise, we sold to affiliates of Enterprise substantially all
of our interests in GulfTerra, which had a carrying value of approximately $519
million. This value included an indefinite lived intangible asset of $181
million and minority interest of $84 million directly related to our GulfTerra
interests. In the transaction, we sold our interest in the general partner of
GulfTerra, 10.9 million GulfTerra Series C units, 2.9 million GulfTerra common
units and miscellaneous administrative assets to Enterprise for $870 million of
cash and 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. As of September 30, 2004, we have approximately $256
million of investments in unconsolidated affiliates on our balance sheet related
to Enterprise. Concurrent with the sale of our investment, we also sold nine of
our processing plants located in south Texas to Enterprise for $156 million of
cash.

As a result of the Enterprise transactions, we recorded a $511 million gain
in earnings from unconsolidated affiliates from the sale of our interests in
GulfTerra, an $11 million loss on long-lived assets from closing adjustments
related to the sale of our south Texas processing assets and a $480 million
impairment of the goodwill associated with our Field Services segment in the
third quarter of 2004. See Note 2 for a further discussion of the goodwill
impairment. The net income statement impact of the Enterprise transactions was a
pre-tax gain of $20 million. Approximately $397 million of the goodwill
impairment will not be deductible for tax purposes and, as a result, we
recognized tax expense of approximately $146 million associated with the
Enterprise transactions in the third quarter of 2004.

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 periods ended
September 30:

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

39

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.

During the second quarter of 2004, we reclassified our Canadian and certain
other international natural gas and oil production operations from our
Production segment to discontinued operations in our financial statements for
all periods presented. In addition, our results for the quarter and nine months
ended September 30, 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.

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 Item 1, Financial Statements, Note 4);

- retiring, eliminating, or refinancing approximately $4.2 billion of
maturing debt and other obligations ($2.6 billion through September 30,
2004) (see Item 1, Financial Statements, Note 11);

- 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 Item 1, Financial
Statements, Note 12); and

- entering into a new credit agreement in November 2004 to refinance our
previous revolving credit facility with an aggregate of $3 billion in
financings consisting of a $1.25 billion, five-year term loan; a $1.0
billion three-year revolving credit facility; and a five-year, $750
million funded letter of credit facility (see Item 1, Financial
Statements Note 11).

Liquidity Update

During 2004, we received waivers and amendments to our then existing
revolving credit facility and various other financing arrangements to address
events that we believe would have constituted an event of default; specifically
under the provisions in those arrangements related to the timely filing of our
financial statements, representations and warranties on the accuracy of our
historical financial statements and on our debt to total capitalization ratio.
We have filed our financial statements within the time frames granted by these
waivers.

In November 2004, we replaced our previous revolving credit facility which
was scheduled to mature in June 2005 with a new credit agreement with a group of
lenders for an aggregate of $3 billion in financings. The new credit agreement
consists of a $1.25 billion, five-year term loan; a $1 billion, three-year
revolving credit facility under which we can issue letters of credit, and an
additional $750 million, five-year funded letter of credit facility. The letter
of credit facility provides us the ability to issue letters of credit or borrow
any unused capacity as a term loan. The new credit agreement is collateralized
by our interests in EPNG, TGP, ANR, CIG, WIC, ANR Storage Company and Southern
Gas Storage Company.

Our new credit agreement provides approximately $220 million in net
additional borrowing availability (after repayment of an existing obligation of
approximately $229 million and various other items) as compared

40

with our previous revolving credit facility. Upon closing of the new credit
agreement, we borrowed $1.25 billion under the term loan, utilized the $750
million under the letter of credit facility and approximately $0.4 billion of
the $1 billion revolving credit facility to replace approximately $1.2 billion
of letters of credit issued under our previous revolving credit facility. We
will use the proceeds from the $1.25 billion term loan to repay certain
financing obligations (see Item 1, Financial Statements, Note 11), manage our
liquidity, prepay upcoming debt maturities, and provide for other general
corporate purposes.

The availability of borrowings under the new credit agreement and other
borrowing agreements is subject to various conditions as further described in
Item 1, Financial Statements, Note 11, 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. As of September
30, 2004, our ratio of Debt to Consolidated EBITDA was 4.74 to 1 and our ratio
of Consolidated EBITDA to interest expense and dividends was 1.92 to 1, each as
defined in the credit agreement.

El Paso CGP Company, our subsidiary, has not yet filed its financial
statements for the third quarter of 2004, as required under several of its, and
its affiliates', financing arrangements. We believe El Paso CGP's financial
statements will be filed prior to any notice being given or within the allowed
time frames under those arrangements such that there will be no event of
default.

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 new credit agreement, proceeds from asset
sales, reduction of discretionary capital expenditures and the possible issuance
of long-term debt, 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 nine months ended September 30, 2004, we continued to reduce our
overall debt and securities of subsidiaries as part of our Long-Range Plan
announced in December 2003. Our activity during the nine months ended September
30, 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 and other increases.............. 64
Repayments/retirements of principal(1)...................... (1,705)
Sales of entities(2)........................................ (887)
Other....................................................... (58)
-------
Total debt and securities of subsidiaries as of
September 30, 2004............................... $19,593
=======

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

(1) Amount excludes $370 million of 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) This debt was eliminated when we sold our interests in Mohawk River Funding
IV and Utility Contract Funding.

For a further discussion of our long-term debt and other financing
obligations, and other credit facilities, see Item 1, Financial Statements, Note
11.

41

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW OF CASH FLOW ACTIVITIES FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004
AND 2003

For the nine months ended September 30, 2004 and 2003, our cash flows are
summarized as follows:

During the first nine months 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 from continuing operations
Cash flows from operating activities...................... $ 0.6
Net proceeds from the sale of assets and investments...... 1.8
Net change in restricted cash(1).......................... 0.5
Cash provided from discontinued operations................ 1.0
-----
Total cash inflows from continuing operations.......... 3.9
-----
Cash outflows from continuing operations
Additions to property, plant and equipment................ (1.3)
Payments to retire long-term debt......................... (1.7)
-----
Total cash outflows from continuing operations......... (3.0)
-----
Cash flows from discontinued operations
Cash from operations...................................... 0.2
Net proceeds from sale of assets.......................... 1.2
Payments to retire long-term debt......................... (0.4)
Cash provided to continuing operations.................... (1.0)
-----
Total net cash inflows from discontinued operations.... --
-----
Net increase in cash................................. $ 0.9
=====

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

(1) Amounts consist primarily of the release of escrowed funds related to the
Western Energy Settlement.

As of November 30, 2004, we had available cash on hand and borrowing
capacity under our new credit agreement totaling $2.7 billion.

42

Cash From Continuing Operating Activities

Overall, cash generated from our continuing operating activities was $0.6
billion during the first nine months of 2004 versus $1.7 billion during the same
period of 2003. The $1.1 billion decrease in operating cash flow was largely due
to a payment of $0.6 billion to settle the principal litigation under the
Western Energy Settlement in the second quarter of 2004, $0.3 billion of greater
cash recoveries in 2003 for margin calls compared to 2004 and the loss of cash
generation related to assets sold during the last year.

Cash From Continuing Investing Activities

Net cash provided by our continuing investing activities was $1.0 billion
for the nine months ended September 30, 2004. Our investing activities consisted
of the following (in billions):

Production exploration, development and acquisition
expenditures.............................................. $(0.6)
Pipeline expansion, maintenance and integrity projects...... (0.7)
Restricted cash activity(1)................................. 0.5
Proceeds from the sale of assets and investments............ 1.8
-----
Total continuing investing activities............. $ 1.0
=====

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

(1) Amounts consist primarily of the release of escrowed funds related to the
Western Energy Settlement.

For the remainder of 2004, we expect our total capital expenditures to be
approximately $0.7 billion, which includes approximately $0.3 billion for our
Production segment and $0.4 billion for our Pipelines segment.

Cash From Continuing Financing Activities

Net cash used by our continuing financing activities was $0.7 billion for
the nine months ended September 30, 2004. Cash used in our financing activities
included net repayments of $1.7 billion made to retire third party long-term
debt and cash dividend payments of $0.1 billion to shareholders. Cash provided
from our financing activities included $1.0 billion of cash generated by our
discontinued operations, as further discussed below, and $0.1 billion from the
issuances of common stock. We reflect the net cash generated by our discontinued
operations as a cash inflow to our continuing financing activities.

Cash from Discontinued Operations

During the first nine months of 2004, our discontinued operations
contributed $1.0 billion of cash. We generated $0.2 billion in cash in these
operations, received proceeds from the sales of assets primarily related to our
Eagle Point and Aruba refineries and our western Canada production operations of
approximately $1.2 billion, and repaid $0.4 billion of long-term debt related to
the Aruba refinery.

43

COMMODITY-BASED DERIVATIVE CONTRACTS

We use 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
September 30, 2004:

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

(1) Includes $251 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 nine months ended September
30, 2004.

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

(3) In December 2004, we designated other commodity-based derivative contracts
with a fair value loss of $592 million as hedges of our 2005 and 2006
natural gas production and, as a result, we will reclassify this amount to
derivatives designated as hedges in the fourth quarter of 2004. As of
September 30, 2004 these contracts had a fair value loss of $567 million.

Below is a reconciliation of our commodity-based derivatives for the period
from January 1, 2004 to September 30, 2004:

44

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

(1) Includes $861 million and $75 million of derivative contracts sold in
connection with the sales of Utility Contract Funding and Mohawk River
Funding IV in 2004. See Item I, Financial Statements, Notes 4 and 6 for
additional information on these sales.

(2) In the second quarter of 2004, we reclassified a $69 million liability from
our Western Energy Settlement obligation to our price risk management
activities.

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.

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.

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
activities include our general and administrative functions as well as a
telecommunications business and various other contracts and assets. 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. In the
second quarter of 2004, we reclassified our Canadian and certain other
international natural gas and oil production operations from our Production
segment to discontinued operations in our financial statements. Our operating
results for all periods presented reflect these changes.

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

45

such as operating income or operating cash flow. Below is a reconciliation of
our consolidated EBIT to our consolidated net income (loss) for the periods
ended September 30:

OVERVIEW OF RESULTS OF OPERATIONS

For the nine months ended September 30, 2004, our consolidated EBIT from
continuing operations was $1,117 million of which $1,138 million was our segment
EBIT. During the nine months, our Pipelines, Production and Field Services
segments contributed $1,644 million of combined EBIT. These positive
contributions were partially offset by combined EBIT losses of $506 million in
our Power and Marketing and Trading segments. The following overview summarizes
the results of operations by operating segments compared to our internal
expectations for the period.

Pipelines Our Pipelines segment generated EBIT of $962 million,
which was generally consistent with our expectations for
the period.

Production Our Production segment generated EBIT of $558 million,
which was above our expectations for the period. 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 on our full
cost pool assets, more than offset lower than expected
production volumes and higher than expected production
costs.

Marketing and Trading Our Marketing and Trading segment generated an EBIT loss
of $462 million, which was a greater loss than our
expectations. The performance was driven primarily by
mark-to-market losses in our natural gas portfolio due
to natural gas price increases in the period. Our
natural gas portfolio exposure was also impacted by the
hedge restatement in periods prior to 2004, resulting in
a mark-to-market position that generates losses if
natural gas prices increase.

Power Our Power segment generated an EBIT loss of $44 million,
which was below our expectations for the period,
primarily due to asset impairments and other charges,
net of realized gains and losses, of $362 million. These
impairments and charges were primarily related to events
at two power plants in Brazil in

46

2004 related to difficulties in extending their power
sales agreements that expire in 2005 and 2006, and due
to certain of our domestic operations which were sold or
are being sold.

Field Services Our Field Services segment generated EBIT of $124
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. However, this volatility should decrease as a result of the
designation of certain of our derivatives as hedges of our Production segment's
natural gas production in the fourth quarter of 2004.

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 of these factors and other items impacting our financial performance
for the nine months ended September 30, see the discussions of the individual
segment and other results that follow, as well as Item 1, Financial Statements,
Notes 5, 6, and 16.

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

(1) Includes a net gain of $500 million on the sale for our GulfTerra interests
and other assets to Enterprise and a related goodwill impairment of $480
million in the third quarter of 2004. See Item 1, Financial Statements,
Notes 2, 6 and 16 for a further discussion of these sales, gains and
impairments.

(2) Includes $55 million of accretion expense and other charges and is included
in operations and maintenance expense in our consolidated statements of
income.

The following is a discussion of the comparative quarterly and nine month
period results, including a discussion of the items above, for 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 operations.

47

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 periods ended September 30:

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

(1) Throughput volumes exclude volumes related to our equity investments in the
Portland Natural Gas Transmission System and EPIC Energy Australia Trust
which were sold in the fourth quarter of 2003 and second quarter of 2004. In
addition, volumes exclude intrasegment activities. Throughput volumes
includes volumes related to our Mexico investments which were transferred
from our Power segment effective January 1, 2004.

Operating Results (EBIT)

Some of the key issues affecting our Pipeline segment operations for the
periods ending September 30, 2004 include the impact on revenues and operating
expenses of our efforts to recontract available capacity, the benefit from
selling excess fuel over the amount needed to operate the facilities and higher
operating costs, mainly higher allocated corporate overhead. Additionally, in
2003 we completed our settlement of energy disputes in the Western United States
referred to as the Western Energy Settlement.

The following factors contributed to our overall EBIT decrease of $33
million for the quarter ended September 30, 2004 and EBIT increase of $87
million for the nine months ended September 30, 2004 as compared to the same
periods ended September 30, 2003:

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

(1) Consists of costs of operations, electric and power purchase costs, overhead
allocation and environmental costs.

(2) Consists of individually insignificant items across several of our pipeline
systems.

The renegotiation or restructuring of several contracts on our pipeline
systems including our contracts with We Energies 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

48

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 gasification facility contract on its system.
However, the termination of this contract will not have a significant overall
impact on operating income and EBIT.

Included in contract modifications/terminations above are the impact of the
expiration of EPNG risk sharing provisions, which provided revenue net of
sharing obligation. The provisions expired at the end of 2003, and will continue
to unfavorably impact our comparative EBIT, for the remainder of 2004. In
addition, while the impact of EPNG's capacity pool obligation for former full
requirements (FR) customers terminated with the completion of Phases I and II of
EPNG's Line 2000 Power-up project in 2004, EPNG remains at risk for that portion
of capacity which was turned back to it on a permanently released basis. EPNG is
able, however, to re-market that capacity subject to the general requirement
that EPNG demonstrate that any sale of capacity does not adversely impact its
service to its firm customers.

Our pipeline 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
approximately $26 million, at which time this amount will be reflected in
earnings.

In September 2004, we incurred significant damage to sections of our TGP
and SNG offshore pipeline facilities due to Hurricane Ivan. Cost estimates are
currently in the $80 to $95 million range with damage assessment still in
progress. We expect insurance reimbursement for the cost of the damage with the
exception of our share of a $2 million deductible applied on a corporate-wide
basis.

In November 2004, the FERC issued an industry-wide Proposed Accounting
Release that, if enacted as written, would require our interstate pipelines to
expense rather than capitalize certain costs that are part of our pipeline
integrity program. The accounting release is proposed to be effective January
2005 following a period of public comment on the release. We are currently
reviewing the release and have not determined the impact, if any, this release
will have on our consolidated financial statements.

UNREGULATED BUSINESSES -- PRODUCTION SEGMENT

Our Production segment conducts our natural gas and oil exploration and
production activities with a long-term strategy of developing production
opportunities primarily in the U.S. and Brazil. In July 2004, we acquired an
additional 50 percent interest in UnoPaso to increase our production operations
in Brazil. Our operating results are driven 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 our products at attractive
prices.

We are currently divesting our international production properties that are
not part of our long-term strategy and, as of November 2004, have sold all of
our Canadian operations and substantially all of our operations in Indonesia.
Beginning in the second quarter of 2004, these operations have been treated as
discontinued operations as further discussed in Item 1, Financial Statements,
Note 4. All periods reflect this change.

Production and Capital Expenditures

For the nine months ended September 30, 2004, our total equivalent
production has declined approximately 95 Bcfe or 30 percent as compared to the
same period in 2003 primarily due to normal production declines, asset sales and
disappointing drilling results. We expect our fourth quarter of 2004 production
to average approximately 765 MMcfe/d and our 2004 annual production to average
approximately 810 MMcfe/d. The 2004 projected annual production average excludes
approximately 15 MMcfe/d related to our discontinued operations. Our expected
fourth quarter 2004 production levels in the Gulf of Mexico will be negatively
impacted by Hurricane Ivan that occurred in September 2004. This hurricane
caused us to shut-in production and also caused damage to third party facilities
that process or transport our production. We

49

continue to experience reduced production levels in this region as a result of
the damage and do not expect to return to full production until mid-2005.

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. Future trends in production will be 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.

Through September 2004, we have spent $588 million in capital expenditures
for acquisition, exploration, and development activities. Based on the results
to date of our 2004 drilling program, we expect our domestic unit of production
depletion rate to increase from $1.74 per Mcfe for the third quarter of 2004 to
$1.80 per Mcfe for the fourth quarter of 2004.

Production Hedging

We hedge our natural gas and oil production through the use of derivatives
to stabilize cash flows and reduce the risk of downward commodity price
movements on our sales. Our current hedging strategy only partially reduces our
exposure to downward movements in commodity prices and, as a result, our
reported results of operations, financial position and cash flows continue to be
impacted by movements in commodity prices from period to period. In December
2004, we designated certain of the derivatives in our Marketing and Trading
segment as hedges of 205 TBtu of our future natural gas production in order to
reduce the earnings volatility in our Marketing and Trading segment. These
derivative hedge designations will have no impact on El Paso's cash flow in any
period, but will impact the timing of recognizing earnings in El Paso's overall
operating results. Below are the hedging positions on our anticipated natural
gas and oil production as of the date of this filing for 2005 and forward. For
the fourth quarter of 2004, we have 1,615 Bbtu of anticipated natural gas
production hedged at an average price of $3.92/MMbtu.

Natural Gas

Oil

In addition to the hedges listed above, we further reduced our overall
exposure to commodity price fluctuations in future periods by entering into put
contracts in our Marketing and Trading segment in November 2004 which are
designed to provide protection on a consolidated basis from natural gas price
declines in 2005 and 2006. These "put" contracts do not qualify as accounting
hedges and will be marked-to-

50

market in the operating results of our Marketing and Trading segment. These
contracts will provide El Paso with a floor price of $6.00 per MMBtu on 60 TBtu
of our natural gas production in 2005 and 120 TBtu in 2006. El Paso paid a
premium of approximately $67 million, or $0.37 per MMBtu, for the transactions
and, as a result, will have no future cash margin requirements under the
contracts.

Operating Results

Below are the operating results and analysis of these results for each of
the periods ended September 30:

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

(1) Transportation and net product costs are included in operating expenses on
our consolidated statements of income.

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

(3) Includes ceiling test charges, restructuring charges, asset impairments and
gains on asset sales.

(4) Prices are stated before transportation costs.

Quarter Ended September 30, 2004 Compared to Quarter Ended September 30, 2003

EBIT. For the quarter ended September 30, 2004, EBIT was $35 million lower
than the same period in 2003. The decrease in EBIT was primarily due to lower
production volumes due to normal production declines and disappointing drilling
results. Partially offsetting these decreases were higher natural gas and oil
prices and lower operating expenses.

Operating Revenues. The following table describes the variance in revenue
between the quarters ended September 30, 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.

For the quarter ended September 30, 2004, operating revenues were $52
million lower than the same period in 2003 due to lower production volumes,
partially offset by higher natural gas and oil prices. The decline in production
volumes was primarily due to normal production declines in our offshore Gulf of
Mexico and Texas Gulf Coast regions and disappointing drilling results.
Production in the third quarter of 2004 was also impacted by Hurricane Ivan that
occurred in September 2004 in the Gulf of Mexico that caused us to shut-in
production and also caused damage to third party facilities that process or
transport our production. These declines were partially offset by production
increases as a result of our acquisition of the remaining third-party interest
in UnoPaso, which we consolidated in July 2004.

Average realized natural gas prices for the third quarter of 2004,
excluding hedges, were $0.45 per Mcf higher than the same period in 2003, an
increase of nine percent. In addition, our natural gas hedging losses decreased
from $4 million in 2003 to $3 million in 2004. We expect hedging losses to
continue for the remainder of 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 $12 million lower for
the third quarter of 2004 as compared to the third quarter of 2003 primarily due
to ceiling test charges incurred in Brazil in third quarter of 2003 and the
impairment of a non-full cost pool asset in the third quarter of 2003. These
decreases were

52

partially offset by slightly higher production costs and general and
administrative expenses in the third quarter of 2004 as compared to the same
period in 2003. During the fourth quarter of 2004, we expect to incur additional
depreciation of approximately $7 million related to the relocation of our
offices in Houston, Texas.

Total depreciation, depletion, and amortization expense remained unchanged
in the third quarter of 2004 as compared to the same period in 2003. Lower
production volumes in 2004 due to the production declines discussed above
reduced our depreciation, depletion, and amortization expense by $30 million.
Offsetting this decrease were higher depletion rates due to higher finding and
development costs which contributed an increase of $29 million.

Production costs increased by $3 million in the third quarter of 2004 as
compared to the same period in 2003 due to slightly higher production taxes and
lease operating expenses. On a per Mcfe basis, production taxes increased $0.05
in 2004 due to higher natural gas and oil prices. Additionally, our total
production costs per Mcfe increased $0.22 as lease operating expenses increased
$0.17 per Mcfe due to the lower production volumes discussed above.

General and administrative expenses increased $3 million in the third
quarter of 2004 as compared to the same period in 2003. The increase on a per
unit basis was primarily due to lower production volumes. For the fourth quarter
of 2004, we expect our corporate overhead allocations to be approximately the
same as the third quarter 2004 allocations.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September
30, 2003

EBIT. For the nine months ended September 30, 2004, EBIT was $385 million
lower than the same period in 2003. The decrease in EBIT was primarily due to
lower production volumes due to normal production declines, asset sales and
disappointing drilling results. Partially offsetting these decreases were higher
oil prices and lower operating expenses.

Operating Revenues. The following table describes the variance in revenue
between the nine months ended September 30, 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.

For the nine months ended September 30, 2004, operating revenues were $479
million lower than the same period in 2003 due to lower production volumes and
lower natural gas prices partially offset by higher oil prices and a decrease in
our hedging losses. The decline in production volumes was primarily due to
normal production declines in the offshore Gulf of Mexico and Texas Gulf Coast
regions, the sale of properties in New Mexico, Oklahoma, and offshore Gulf of
Mexico as well as disappointing drilling results. Our average production for the
nine months ended September 30, 2004 was also impacted by Hurricane Ivan that
occurred in September 2004 in the Gulf of Mexico. The hurricane caused us to
shut-in production and also caused damage to third party facilities that process
or transport our production. These declines were partially offset by production
increases as a result of our acquisition of the remaining third-party interest
in UnoPaso, which we consolidated in July 2004.

Operating Expenses. Total operating expenses were $76 million lower in
2004 as compared to the same period in 2003 primarily due to lower depreciation,
depletion, and amortization expense, lower production costs, and lower general
and administrative expenses. In addition, in 2003 we incurred a ceiling test
charge in

53

Brazil and recognized an impairment of non-full cost pool assets. Partially
offsetting these decreases were higher employee severance costs in 2004. During
the fourth quarter of 2004, we expect to incur additional depreciation expense
of approximately $7 million related to the relocation of our offices in Houston,
Texas.

Total depreciation, depletion, and amortization expense decreased by $28
million in 2004 as compared to the same period in 2003. Lower production volumes
in 2004 due to asset sales and other production declines discussed above reduced
our depreciation, depletion, and amortization expenses by $121 million.
Partially offsetting this decrease were higher depletion rates due to higher
finding and development costs which contributed an increase of $88 million.

Production costs decreased by $25 million in 2004 as compared to the same
period in 2003 primarily due to a decrease in production taxes resulting from
high cost gas well tax credits in 2004 and to lower production volumes in 2004
compared to 2003. On a per Mcfe basis, production taxes decreased $0.04 in 2004.
However, our total production costs per Mcfe increased $0.11 as lease operating
expenses increased $0.15 per Mcfe due to the lower production volumes discussed
above.

General and administrative expenses decreased $15 million in 2004 as
compared to the same period in 2003. The decrease was primarily due to lower
corporate overhead allocations. However, the costs per unit increased $0.11 per
Mcfe due to lower production volumes. For the fourth quarter of 2004, we expect
our corporate overhead allocations to be approximately the same as the third
quarter 2004 allocations.

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 has resulted in increased earnings volatility in our mark-to-market
portfolio in 2004 due to changes in natural gas prices. For a further discussion
of the restatement, refer to our 2003 Annual Report on Form 10-K.

In December 2004, to reduce the earnings volatility in our mark-to-market
portfolio, we designated certain of our fixed price natural gas derivatives as
hedges of the natural gas production in our Production segment. These
transactions will reduce our mark-to-market earnings exposure to future natural
gas price changes. These derivative hedge designations will have no impact on El
Paso's overall cash flow in any period, but will impact the timing of
recognizing earnings in El Paso's overall operating results.

In the fourth quarter of 2004, we entered into additional transactions
designed to provide overall protection to El Paso from natural gas price
declines in 2005 and 2006. These "put" contracts will provide El Paso with a
floor price of $6.00 per MMBtu on 60 TBtu of our Production segment's natural
gas production in 2005 and 120 TBtu in 2006. Under these contracts, we will
generally have 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. We paid a premium of approximately $67 million,
or $0.37 per MMBtu, for the transactions and, as a result, will have no future
cash margin requirements under the contracts.

54

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
periods ended September 30:

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.

Quarter Ended September 30, 2004 Compared to Quarter Ended September 30, 2003

For the quarter ended September 30, 2004, our gross margin decreased by
$202 million compared to the same period in 2003. This decrease was primarily
due to a $102 million decrease in the fair value of our derivatives, principally
our natural gas contracts, during 2004 compared to a $151 million increase in
the fair value of our trading positions during 2003. We sell natural gas at a
fixed price in many of our trading contracts. In the third quarter of 2004,
natural gas prices increased, resulting in a decrease in the fair value of these
derivatives, whereas in the third quarter of 2003, natural gas prices decreased,
resulting in an increase in the fair value of these derivatives. In addition,
our Cordova derivative tolling agreement's fair value decreased by $27 million
in 2004 compared to a $19 million increase in 2003. The Cordova power plant
sells the power it generates into a power market that was incorporated into the
Pennsylvania/New Jersey/Maryland (PJM) power pool in May 2004. We believe that
this will improve the Cordova power plant's ability to sell its power into the
marketplace and, as a result, will improve the liquidity of our tolling contract
with that power plant. This also changed the relationship between the forecasted
power and natural gas prices used to determine the fair value of our Cordova
tolling agreement. We believe that these changes will improve the overall value
of the contract and will reduce the volatility of the fair value of the contract
in the future. However, we continue to evaluate the impact that this change will
have on the fair value of the Cordova tolling agreement over its term, which
extends through 2019. Also contributing to the decrease in gross margin were
settlement losses on non-derivative contracts of $37 million in 2004 compared to
$36 million in 2003, which primarily related to demand charges we could not
recover on existing transportation contracts. Partially offsetting these
decreases was $69 million of net gains related to the early termination of some
of our derivative and non-derivative contracts in 2004, compared to $5 million
of losses in 2003. Our 2004 gain primarily related to the final receipt of $50
million of proceeds from the termination of an LNG contract at our Elba Island
facility and a $25 million gain on the termination of a power contract with our
Power segment. The $25 million gain was eliminated from El Paso's consolidated
results. We may incur future losses on the early termination of our derivative
and non-derivative contracts in connection with future asset sales by other
segments. Specifically, we are currently negotiating the assignment of our Cedar
Brakes I and II power supply agreements which, if completed, could result in
losses in the period the agreement is reached.

For the quarter ended September 30, 2004, our operating expenses decreased
by $28 million compared to the same period in 2003. This decrease was primarily
due to a $16 million decrease in operating expenses of our London office, which
was closed in 2003. Also contributing to the decrease was $11 million of
amortization expense on the Western Energy Settlement obligation that was
transferred to our corporate operations in late 2003.

55

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September
30, 2003

For the nine months ended September 30, 2004, our gross margin improved by
$163 million compared to the same period in 2003. This improvement was primarily
due to $69 million of gains related to the early termination of some of our
derivative and non-derivative contracts in 2004 compared to $46 million of
losses in 2003. Our 2004 gains resulted primarily from the termination of our
Elba Island LNG contract and a power contract with our Power segment, while our
2003 losses resulted from the active liquidation of the derivative and
non-derivative positions in our trading portfolio in 2003. Our non-derivative
contracts also had settlement losses of $105 million in 2004 compared to $131
million in 2003, which primarily related to demand charges we could not recover
on existing transportation contracts. We expect that these demand charges will
be lower than those in 2003 as we continue to experience the benefits of
previous contract terminations. Also contributing to this improvement was a $371
million decrease in the fair value of our derivatives, principally our natural
gas contracts, during 2003 compared to a $345 million decrease in the fair value
of our trading positions during 2004. Included in the 2003 fair value decrease
was $81 million of losses incurred on the settlement of our natural gas
contracts in the first quarter of 2003. These losses resulted from a high volume
of settlements and significant increases in natural gas prices during each of
the first three months of 2003. Partially offsetting these improvements was a
decrease in our Cordova derivative tolling agreement's fair value of $30 million
in 2004 compared to a $26 million increase in 2003.

For the nine months ended September 30, 2004, our operating expenses
decreased by $81 million compared to the same period in 2003. This decrease was
primarily due to a $37 million decrease in payroll and other general and
administrative expenses, including lower corporate overhead allocations that
resulted from our cost reduction efforts in 2003 and 2004 and a $30 million
decrease in operating expenses of our London office, which was closed in 2003.
Also contributing to the decrease was $33 million of amortization expense on the
Western Energy Settlement obligation that was transferred to our corporate
operations in late 2003. This amortization expense was offset by a $25 million
reduction in the accrual for the Western Energy Settlement obligation that
resulted from the finalization of the payment schedule under the definitive
settlement agreement in June 2003.

56

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 the operating results, a summary
of the operating results of each of its activities and an analysis of these
results for the periods ended September 30:

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

(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.

(2) 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 third quarter of 2003, we also recorded a $22
million impairment of a power turbine in these operations.

Domestic Power Plant Operations

As of September 30, 2004, we had interests in ten domestic power plants, of
which seven were classified as held for sale. Four of the power plants held for
sale are contracted to be sold to a subsidiary of AIG, and three of these sales
were completed in the fourth quarter of 2004. We plan on selling the remaining
three merchant power plants held for sale in the near term and, as a result of
the continuing negotiations of these sales, we determined that the carrying
value of the plants should be reduced to the expected sales proceeds in the
third quarter of 2004, which is included in the impairment discussion below.

Quarter Ended September 30, 2004 Compared to Quarter Ended September 30,
2003

Our domestic power plant operations generated an EBIT loss of $55 million
in 2004 compared to an EBIT loss of $10 million in 2003. In 2004, we recognized
impairments, net of realized gains and losses, of $57 million on our domestic
power plants to adjust the carrying value of these plants to their expected
sales price. Our remaining domestic power plants that are held for sale
generated EBIT of $10 million in 2004 compared to $5 million in 2003. We also
incurred a $25 million loss on the termination of a power contract with our
Marketing and Trading segment in the third quarter of 2004. This loss was
eliminated from El Paso's consolidated results. In 2003, we recognized $29
million of impairments on our East Coast Power facilities related to the sale of
these facilities in the fourth quarter of 2003. The East Coast Power facilities
also

57

generated $22 million of operating income during 2003. We also had $12 million
of equity losses on our investment in the Orlando power plant in 2003, which was
sold in July 2004.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003

For the nine months ended September 30, 2004, the EBIT generated by our
domestic power plant operations was $174 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, an $88 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 and $29 million of impairments on our East Coast
Power facilities. In 2004, we recognized impairments, net of realized gains and
losses, of $102 million on our domestic power plants to adjust the carrying
value of these held for sale plants to the expected sales price. Offsetting this
net increase was lower operating income in 2004 of $66 million from our East
Coast Power facilities which were sold during 2003 and lower operating income of
$9 million from our power plants that were sold during 2004. Our remaining power
plants that are held for sale generated EBIT of approximately $19 million in
2004 compared to $6 million in 2003. Also offsetting the increase was a $25
million loss on the termination of a power contract with our Marketing and
Trading segment. This loss was eliminated from El Paso's consolidated results.

Domestic Power Contract Restructuring Business

Quarter Ended September 30, 2004 Compared to Quarter Ended September 30,
2003

Our domestic power contract restructuring business relates to the continued
performance under our previously restructured power derivative contracts, which
are recorded at fair value. For the quarter ended September 30, 2004, the EBIT
generated by our domestic power contract restructuring business was $16 million
lower than the same period in 2003. This decrease was primarily due to an
increase of $21 million in the fair value of our restructured power contracts in
2004 compared to an increase of $41 million in 2003. This difference was
primarily due to lower accretion of the discounted value of these contracts in
2004 compared to 2003 due to the sale of Utility Contract Funding and its
restructured power contract in 2004.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003

For the nine months ended September 30, 2004, the EBIT generated by our
domestic power contract restructuring business was $137 million lower than the
same period in 2003. This decrease was primarily due to the sale of Utility
Contract Funding and its restructured power contract and related debt, which
resulted in a $98 million impairment loss during 2004. We also expect to sell
our wholly owned subsidiaries, Cedar Brakes I and II which own restructured
power contracts that are recorded at fair value. We expect to sell these
entities for less than their carrying value, which we anticipate will result in
a loss of approximately $220 million in the period the sales agreements are
finalized. Our EBIT was also lower in 2004 as compared to 2003 because the fair
value of our restructured power contracts increased by $110 million in 2003
compared to $79 million in 2004. This difference was primarily due to lower
accretion of the discounted value of these contracts in 2004 compared to 2003
due to the sale of Utility Contract Funding and its restructured power contract
in 2004.

International Power Plant Operations

Quarter Ended September 30, 2004 Compared to Quarter Ended September 30,
2003

Brazil. Our Brazilian operations include our Macae, Manaus, Rio Negro and
Porto Velho power plants. For the quarter ended September 30, 2004, the EBIT
generated by our Brazilian power plant operations decreased by $36 million
compared to the same period in 2003. We are in negotiations to amend or extend
the power agreements for our Manaus and Rio Negro power facilities. Based on the
status of these negotiations, we recorded a $32 million charge to operation and
maintenance expense in the third quarter of 2004 based on our current
expectations of the recoverability of our invested amounts in these facilities.
Also contributing to the decrease was a $2 million decrease in the operating
income at the Porto Velho power plant. In the fourth

58

quarter of 2004, the Porto Velho power plant experienced an equipment failure
that will temporarily reduce the gross capacity of the plant from 404 MW to 284
MW. We expect that this failure will reduce our EBIT for the fourth quarter of
2004 and for 2005.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003

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 interests
in the Macae and Porto Velho power plants. As a result, our operating results
during the first quarter of 2003 include the equity earnings we earned from
Gemstone, while our consolidated operating results for all other periods in 2003
and 2004 include the revenues, expenses and equity earnings from Gemstone's
assets.

For the nine months ended September 30, 2004, the EBIT generated by our
Brazilian power plant operations decreased by $137 million compared to the same
period in 2003. Our 2004 EBIT loss primarily resulted from $135 million of
impairments and a $32 million charge in operation and maintenance expense
related to our Manaus and Rio Negro power plants. We recorded these charges
based on the status of our expectations of the recoverability of our invested
amounts in these facilities based on the status of our negotiations to extend
their power sales agreements that expire in 2005 and 2006. Partially offsetting
these losses was $129 million of operating income from our Macae power plant and
$20 million from our Porto Velho power plant in 2004.

Our 2003 EBIT included $17 million of equity earnings from Gemstone, which
primarily included the operating results from the Macae and Porto Velho power
plants above and the cost of the debt held by Gemstone during the first three
months of 2003. During the second and third quarters of 2003, our Macae and
Porto Velho power plants generated operating income of $89 million and $17
million.

Other International. For the nine months ended September 30, 2004, the
EBIT generated by our other international power operations was $23 million lower
than the same period in 2003. The decrease was primarily due to a $24 million
gain on the sale of our CAPSA/CAPEX investments in Argentina in 2003. Also
contributing to the decrease was $11 million of EBIT generated by our
investments in Mexico in 2003, the majority of which were transferred to the
Pipelines segment effective January 1, 2004. Partially offsetting these
decreases was an $11 million increase in our equity earnings from an equity
investment in Pakistan in 2004 when compared to 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 includes
holding our general and limited partner interests in GulfTerra, a publicly
traded master limited partnership, and gathering and processing assets.
Following the sales of substantially all of our remaining interests in GulfTerra
as well as our south Texas processing plants to Enterprise as part of a merger
transaction between GulfTerra and Enterprise described further below, the
majority of our gathering and processing business will be conducted through our
remaining ownership interests in the merged partnership.

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. Additionally, prior to
these sales, we received management fees under an agreement to provide
operational and administrative services to the partnership. 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 have also

59

agreed to provide a total of $45 million in payments to Enterprise during the
three years after the merger becomes effective.

We are reimbursed for costs paid directly by us on the partnership's
behalf. For the nine months ended September 30, 2004 and 2003, these
reimbursements were $69 million and $68 million, of which $24 million and $22
million were incurred in the third quarter of 2004 and 2003.

During 2004, our earnings and cash distributions received from GulfTerra
were as follows:

For a discussion of our ownership interests in GulfTerra and our activities
with the partnership, see Item 1, Financial Statements, Note 16. 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 periods ended September 30:

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

(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.

60

For the quarter and nine months ended September 30, 2004, our EBIT was $29
million and $121 million higher than the same periods in 2003. Below is a
summary of significant factors affecting EBIT.

In September 2004, in connection with the closing of the merger between
GulfTerra and Enterprise, we sold substantially all of our interests in
GulfTerra, as well as our processing assets in south Texas to affiliates of
Enterprise. We recorded a $511 million gain on the sale of our interests in
GulfTerra, an $11 million loss on the sale of our processing assets and a $480
million impairment of the goodwill associated with our Field Services segment in
the third quarter of 2004. The full carrying value of the goodwill was impaired
because the remaining assets in our Field Services segment could no longer
support it. These transactions resulted in an overall pre-tax net gain of $20
million. For a discussion of the significant tax impacts of these transactions,
see the Income Taxes section below.

In the third quarter of 2004, we incurred an impairment charge of $13
million on our Indian Springs natural gas gathering and processing assets based
on anticipated losses on the sales of those assets. These assets were approved
for sale by our Board of Directors in August 2004. We recorded $80 million for
impairments in 2003 of equity investments in Dauphin Island and Mobile Bay based
on anticipated losses on the sales of these investments, which were completed in
the third quarter of 2004.

Processing margins increased primarily due to higher NGL prices relative to
natural gas prices, which caused us to maximize the amount of NGLs that were
extracted by our natural gas processing facilities in south Texas at an
increased margin per unit. In addition, margin attributable to the marketing of
NGLs increased as a result of lower fuel and transportation costs and the
availability of an NGL pipeline system in 2004 to move our liquids to the Mt.
Belvieu market. In the second quarter of 2003, the NGL pipeline system to Mt.
Belvieu was down for maintenance.

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.

61

For the periods ended September 30, 2004, EBIT in our corporate operations
were higher (lower) 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. Adverse rulings against us and/or
unfavorable settlements related to these and other legal matters would impact
our future results. Additionally, as discussed in Item 1, Financial Statements,
Note 5, we incurred relocation charges of approximately $29 million in the third
quarter of 2004 related to the consolidation of our Houston-based operations. We
estimate our total relocation charges will be approximately $100 million for the
year ended December 31, 2004.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter and nine months ended September
30, 2004, was $79 million and $123 million lower than the same periods in 2003.
Below is an analysis of our interest expense for the periods ended September 30:

Interest expense on long-term debt decreased due to retirements of debt
during 2003 and the first nine months of 2004, net of issuances. This decrease
in interest expense was partially offset by the reclassification of our
preferred securities as long-term financing obligations and recording the
preferred returns on these securities as interest expense. For further
information of this reclassification, see the discussion below. Interest expense
on our revolving credit facility decreased due to payments of $850 million on
the revolver during the first and third quarters of 2004. Partially offsetting
this decrease were higher commitment fees on letters of credit outstanding in
the third quarter of 2004 as compared to 2003. Other interest decreased due to
retirements and consolidations of other financing obligations. Finally,
capitalized interest for the quarter and nine months ended September 30, 2004,
was higher than the same period in 2003 primarily due to higher average interest
rates in 2004 than in 2003.

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DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Distributions on preferred interests of consolidated subsidiaries for the
nine months ended September 30, 2004 were $27 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 acquisition and consolidation of our Chaparral and Gemstone investments. Our
remaining balance of preferred interests as of September 30, 2004 primarily
consists of $300 million of 8.25% preferred stock of our consolidated
subsidiary, El Paso Tennessee Pipeline Co.

INCOME TAXES

Income taxes included in our income (loss) from continuing operations and
our effective tax rates for the periods ended September 30 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 benefits;

- 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.

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 nine months of
2004, our overall effective tax rate on continuing operations was significantly
different than the statutory rate due primarily to the GulfTerra transaction and
impairments of certain of our foreign investments. The sale of our interests in
GulfTerra associated with the merger between GulfTerra and Enterprise in
September 2004 resulted in a significant taxable gain (compared to a lower book
gain) and significant tax expense due to the non-deductibility of a significant
portion of the goodwill written off as a result of the transaction. The impact
of this non-deductible goodwill increased our tax expense by approximately $139
million. See Note 16 for a further discussion of the merger and related
transactions. Additionally, we received no U.S. federal income tax benefit on
the impairment of certain of our foreign investments, primarily during the first
quarter of 2004. The combination of these items resulted in an overall tax
expense for a period in which there was a pre-tax loss.

On October 22, 2004, the American Jobs Creation Act of 2004 was signed into
law. This legislation creates, among other things, a temporary incentive for
U.S. multinational companies to repatriate accumulated income earned outside the
U.S. at an effective tax rate of 5.25%. The U.S. Treasury Department has not
issued final guidelines for applying the repatriation provisions of the American
Jobs Creation Act. We have not provided deferred taxes on foreign earnings
because such earnings were intended to be indefinitely reinvested outside the
U.S. We are currently evaluating whether we will repatriate any foreign earnings
under the American Jobs Creation Act, and are evaluating the other provisions of
this legislation, which may impact our taxes in the future.

63

In 2004, Congress proposed, but failed to enact, legislation which would
disallow deductions for certain settlements made to or on behalf of governmental
entities. We expect Congress to reintroduce similar legislation in 2005. 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 approximately $400
million as of September 30, 2004.

For a further discussion of our effective tax rates, see Item 1, Financial
Statements, Note 7.

DISCONTINUED OPERATIONS

For the nine months ended September 30, 2004, the loss from our
discontinued operations was $150 million compared to a loss of $1,195 million
during the same period in 2003. In 2004, $78 million of losses from discontinued
operations related to our Canadian and certain other international production
operations, primarily from losses on sales and impairment charges, and $72
million was from our petroleum markets activities, primarily related to losses
on the completed sales of our Eagle Point and Aruba refineries along with other
operational and severance costs. The losses in 2003 related primarily to
impairment charges on our Aruba and Eagle Point refineries and on chemical
assets, all as a result of the decision by our Board of Directors to exit and
sell these businesses and ceiling test charges related to our Canadian
production operations.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 12, 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;

- 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.

65

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 $44 million as of September 30, 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 September 30, 2004 and December 31, 2003, we had $0.7 billion and
$1.7 billion of third party long-term restructured power derivative contracts.
During 2004, we sold the contract held by Utility Contract Funding, which had a
fair value of $865 million as of December 31, 2003. This sale and the potential
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 2004, we have been reviewing our internal controls over financial
reporting as part of our compliance efforts under Section 404 of the
Sarbanes-Oxley Act (SOX), as well as in connection with investigations into
matters that required the restatement of our historical financial statements for
the periods from 1999 to 2002 and the first nine months of 2003. Our SOX review
is being performed consistent with the guidance for independent auditors
established by the Public Company Accounting Oversight Board in Auditing
Standard No. 2, An Audit of Internal Control Over Financial Reporting Performed
in Conjunction with an Audit of Financial Statements. The project has entailed
the 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, financial management responsible for those
processes internally reviewed or "walked-through" these financial 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 involves testing the controls, including
a review and inspection of the documentation supporting the operation of the
controls on which we are placing reliance.

During our reviews, we identified a number of deficiencies in our internal
controls over financial reporting that we determined were material weaknesses in
our internal control structure. These deficiencies, which we have previously
disclosed, generally involved the control environment, information system
access, documentation and application of generally accepted accounting
principles, and deficiencies related to segregation of duties, account
reconciliations and change management over information systems. Our management,
with the oversight of El Paso's Audit Committee, has devoted considerable effort
to remediating the material weaknesses identified, and has made improvements in
our internal controls over financial reporting to address these weaknesses.
Specifically, in the quarter ending September 30, 2004, we implemented new
controls to improve our account reconciliation process, improve segregation of
duties and strengthen information system change management processes. We believe
that we have remediated the deficiencies in internal controls related to the
weaknesses previously identified. However, we continue to test to determine
whether the remediated controls are operating effectively. As of December 3,
2004, we have completed approximately 78 percent of the initial testing of our
internal controls over financial reporting related to our SOX review. We expect
to complete this testing by early February 2005, including any retesting, to
determine whether our internal controls are effective at December 31, 2004. We
are also currently finalizing a framework upon which we will evaluate and
classify the significance of deficiencies identified in our testing process.
This is an area that involves judgment, and where interpretation and guidance
continue to evolve. At this time, we have identified a number of deficiencies
and areas where we can improve our internal controls. Following the completion
of our testing procedures, we will assess whether there are any remaining
material weaknesses, represented by either individually material deficiencies or
an aggregation of significant deficiencies.

Our disclosure controls and procedures are designed to provide reasonable
assurance that information required to be disclosed in our reports filed under
the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the SEC rules. Our disclosure
controls and procedures are also designed to ensure that such information is
accumulated and communicated to our management to allow timely decisions
regarding required disclosure. Because we have not completed the testing of many
of the processes and controls intended to remediate the control deficiencies
identified in our reviews of internal controls, we were unable to conclude that
our disclosure controls and procedures were effective as of September 30, 2004.
However, we did perform additional procedures to ensure that our disclosure
controls and procedures were effective over the preparation of these financial
statements.

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PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Note 12, 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

Our Board of Directors, based upon a recommendation from the Governance
Committee (a committee comprised of independent directors), adopted a policy on
poison pills, or stockholder rights plans, and has amended our Governance
Guidelines to include the following policy:

POLICY ON POISON PILL PLANS

The company does not currently have in place any stockholders
rights plan (also known as a "poison pill"), and the Board currently
has no plans to adopt such a plan. However, if the Board is presented
with a set of facts and circumstances which leads it to conclude that
adopting a rights plan would be in the best interests of stockholders,
the Board will seek prior stockholder approval unless the Board, in
exercising its fiduciary responsibilities under the circumstances,
determines by vote of a majority of the independent directors that
such submission would not be in the best interests of the company's
stockholders in the circumstances. If the Board were ever to adopt a
rights plan without prior stockholder approval, it will be presented
to the stockholders for ratification within one year or expire within
one year, without being renewed or replaced. Further, if the Board
adopts a rights plan and the company's stockholders do not approve
such rights plan, it will terminate.

El Paso Corporation's Governance Guidelines and other information relating
to our corporate governance principals, including the Board of Director's
standing committee charters and El Paso Corporation's Code of Business Conduct,
Restated Certificate of Incorporation and By-laws can be found on our Web site
at www.elpaso.com.

2005 ANNUAL MEETING OF STOCKHOLDERS

We anticipate that our 2005 annual meeting of stockholders will be held in
late May 2005 and notified stockholders that proposals by stockholders that are
intended for inclusion in our proxy statement and proxy to be presented at the
2005 annual meeting of stockholders must be received by Friday, January 7, 2005,
in order to be considered for inclusion in the proxy materials. Such proposals
should be addressed to the Corporate Secretary of El Paso and may be included in
the proxy materials for the 2005 annual meeting of stockholders of El Paso if
they comply with certain rules and regulations of the Securities and Exchange
Commission and our By-laws governing stockholder proposals. In addition, for all
other proposals to be presented at the annual meeting that are not included in
the proxy statement and proxy to be timely, a stockholder's notice must be
delivered to, or mailed and received at, the principal executive offices of El
Paso not later than February 25, 2005. If a stockholder fails to so notify El
Paso of any such proposal prior to February 25, 2005, management of El Paso
Corporation will be allowed to use their discretionary voting authority with
respect to proxies held

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by management when the proposal is raised at the annual meeting (without any
discussion of the matter in its proxy statement). All proposals must be
submitted and received, in writing, by the dates noted above, to David L.
Siddall, Corporate Secretary, El Paso Corporation, 1001 Louisiana Street,
Houston, Texas 77002, telephone (713) 420-6195 and facsimile (713) 420-4099.

SUPPLEMENTAL BENEFITS PLAN

Effective December 17, 2004, an administrative amendment was made to the
Plan. The American Jobs Creation Act of 2004, or the Act, which imposes certain
restrictions on deferred compensation plans, such as the Plan, effective for
2005 and later years. Specific guidance regarding the terms and effect of the
Act is expected from the Internal Revenue Service, but may not be published in
time to amend the Plan prospectively, before the Act becomes effective. The
amendment to the Plan reserves our right to make changes to the Plan,
retroactively, to comply with the Act.

OFFICER INDEMNIFICATION AGREEMENTS

On December 17, 2004, El Paso executed indemnification agreements. These
agreements reiterate the rights to indemnification that are provided to certain
officers under El Paso's By-laws, clarify procedures related to those rights,
and provide that such rights are also available to fiduciaries under certain of
El Paso's employee benefit plans. As is the case under the By-laws, the
agreements provide for indemnification to the full extent permitted by Delaware
law, including the right to be paid the reasonable expenses (including
attorneys' fees) incurred in defending a proceeding related to service as an
officer or fiduciary in advance of that proceeding's final disposition. El Paso
may maintain insurance, enter into contracts, create a trust fund or use other
means available to provide for indemnity payments and advances. In the event of
a change in control of El Paso (as defined in the indemnification agreements),
El Paso is obligated to pay the costs of independent legal counsel who will
provide advice concerning the rights of each officer to indemnity payments and
advances.

We are filing as an exhibit to this report the indemnification agreement
for Mr. Foshee, which covers his director and officer positions and which
replaces his previously filed Director Indemnification Agreement. In addition,
we are filing as an exhibit to this report the form of indemnification agreement
and listing of senior officers and fiduciaries who are participants in that form
agreement.

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.

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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: December 17, 2004 /s/ D. DWIGHT SCOTT
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: December 17, 2004 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

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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.