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.

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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;

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(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

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- 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

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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 tr