EL PASO CORP/DE - 10-Q Quarterly Report

Back to GetFilings.com

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

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

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

FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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

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

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 November 19,
2004: 643,226,654

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

EL PASO CORPORATION

TABLE OF CONTENTS

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

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.

i

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)

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

(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 June 30, 2004, and for the
quarters and six months ended June 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 six months ended June 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 $3.4 billion of debt
and other obligations ($1.9 billion through June 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 to refinance our existing revolving
credit facility with an aggregate of $3 billion in financings consisting
of a $1.25 billion, five year term loan, a new $1.0 billion, three year
revolving credit facility, and a five year, $750 million funded letter of
credit facility, all of which will become available to us upon the filing
of this Quarterly Report on Form 10-Q (see Note 11).

Liquidity Update

We believe that the restatement of our historical financial statements
mentioned above would have constituted an event of default under our existing
revolving credit facility and various other financing transactions; specifically
under the provisions in these arrangements related to representations and
warranties on the accuracy of our historical financial statements and on our
debt to total capitalization ratio. During 2004, we received several waivers on
our existing revolving credit facility and various other financing arrangements

6

to address these issues. With the filing of these financial statements, we are
in compliance with our existing revolving credit facility and with the various
other financings on which we received waivers. Three of our subsidiaries have
indentures associated with their public debt that contain $5 million
cross-acceleration provisions. These indentures state that should an event of
default occur resulting in the acceleration of other debt obligations of such
subsidiaries in excess of $5 million, the long-term debt obligations containing
such provisions could be accelerated. The acceleration of our debt would
adversely affect our liquidity position, and in turn, our financial condition.
Our subsidiary, El Paso CGP Company, has not yet filed its financial statements
for the second quarter of 2004, as required under several of its financing
arrangements. We believe we will file El Paso CGP's financial statements prior
to any notice being given or within the allowed time frames under these
arrangements such that there will be no event of default.

Our existing revolving credit facility matures in June 2005. As of June 30,
2004, we had $600 million outstanding (which was repaid in September 2004) and
$1.1 billion of letters of credit issued under this facility. In November 2004,
we entered into a new credit agreement with a group of lenders for an aggregate
of $3 billion in financings that will become available to us upon the filing of
this Form 10-Q. This new credit agreement will replace our existing revolving
credit facility and will consist of a $1.25 billion, five year term loan, a new
$1 billion, three year revolving credit facility under which we can issue
letters of credit, and an additional five year, $750 million funded letter of
credit facility. The letter of credit facility will provide us the ability to
issue letters of credit or borrow any unused capacity as loans. The new credit
agreement will be 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 Gas Company (WIC), ANR
Storage Company, and Southern Gas Storage Company.

Our new credit agreement will provide approximately $220 million in net
additional borrowing availability as compared to our existing revolving credit
facility. Upon the closing of the new credit agreement, letters of credit of
approximately $1.2 billion issued under our existing revolving credit facility
will be supported by the $750 million letter of credit facility and by
approximately $0.4 billion of the new $1 billion revolving credit facility. We
will use the $1.25 billion term loan proceeds to repay certain financing
obligations, manage our liquidity, prepay upcoming debt maturities, and provide
for other general corporate purposes.

Our subsidiaries are a significant potential source of liquidity to us, and
they participate in our cash management program to the extent they are permitted
to do so under their financing agreements and indentures. Under the cash
management program, depending on whether participating subsidiaries have
short-term cash requirements or surpluses, we either provide cash to them or
they provide cash to us. If we were to incur an event of default under our
credit facilities, we would be unable to obtain cash from our pipeline
subsidiaries, which are the primary source of cash under this program. In
addition, our ownership in a number of our subsidiaries and investments
currently serves as collateral under our existing revolving credit facility and
our other financings, and will serve as collateral under the new credit
agreement. If the lenders were to exercise their rights to this collateral, we
could lose our ownership interest in these subsidiaries or be required to
liquidate these investments.

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, and common or preferred equity securities. However, a number
of factors could influence our liquidity sources, as well as the timing and
ultimate outcome of our ongoing efforts and plans.

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.

7

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

8

facility. We own a 75 percent equity interest in Blue Lake. This entity has $11
million of third party debt as of June 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 June 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 January 1, 2004, these entities consisted primarily of 25 equity investments
held in our Power segment that had interests in power generation and
transmission facilities with a total generating capacity of approximately 8,100
gross MW. We operate many of these facilities but do not supply a significant
portion of the fuel consumed or purchase a significant portion of the power
generated by these facilities. The long-term debt issued by these entities is
recourse only to the power project. As a result, our exposure to these entities
is limited to our equity investments in and advances to the entities ($1.7
billion as of June 30, 2004) and our guarantees and other agreements associated
with these entities (a maximum of $134 million as of June 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 six
months ended June 30:

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.

New Accounting Pronouncement Not Yet Adopted

In September 2004, the SEC issued Staff Accounting Bulletin No. 106. This
pronouncement will require companies that use the full cost method for
accounting for their oil and gas producing activities to include an estimate of
future asset retirement costs to be incurred as a result of future development
activities on proved reserves in their calculation of depreciation, depletion
and amortization. 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.

9

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.

10

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:

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

(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 June 30, 2004.
(3) These sales were or will be completed after June 30, 2004.
(4) The sales of 22 of these plants were completed after June 30, 2004.

11

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

(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 $52 million for the six months ended
June 30, 2003.

See Notes 6 and 16 for a discussion of gains, losses and asset impairments
related to the sales above.

12

Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets, we classify assets being disposed of as held for sale or, if
appropriate, discontinued operations if they have received appropriate approvals
by our management or Board of Directors and have met other criteria. The
following table details the items that have been reflected as current assets and
liabilities held for sale in our balance sheets as of June 30, 2004 and December
31, 2003.

In August 2004, our Board of Directors authorized the sale of our Indian
Springs natural gas gathering and processing assets in our Field Services
segment, which consisted primarily of property, plant and equipment. We will
classify these assets as held for sale and expect to incur an impairment charge
of approximately $13 million related to these assets in the third quarter of
2004 based on expected sales proceeds of approximately $74 million.

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 six
months ended June 30, 2004, we recognized approximately $93 million in asset
impairments and losses on these sales. We expect to complete the sale of the
remainder of these properties in 2004 and early 2005.

Petroleum Markets. During the first quarter of 2003, our Board of
Directors approved the sales of our Eagle Point refinery, our asphalt business,
our Florida terminal, tug and barge business and our lease crude operations. In
June 2003, our Board of Directors authorized the sale of our remaining petroleum
markets operations, including our Aruba refinery, our Unilube blending
operations, our domestic and international terminalling facilities and our
petrochemical and chemical plants. Based on our intent to dispose of these
operations, we were required to adjust these assets to their estimated fair
value. As a result, we recognized a pre-tax impairment charge of approximately
$987 million during the second quarter of 2003 related to our petroleum and
chemical assets. Our second quarter 2003 charge was in addition to the $350
million pre-tax impairment charge recognized during the first quarter of 2003
when we announced our intent to sell our Eagle Point refinery and several of our
chemical assets. These impairments were based on a comparison of the carrying
value of these assets to their estimated fair value, less selling costs. We also
recorded realized gains of approximately $52 million in the first six months of
2003 from the sale of our Corpus Christi refinery and Florida terminalling and
marine assets.

In the first and second quarters of 2004, we completed the sales of our
Aruba and Eagle Point refineries for $880 million and used a portion of the
proceeds to repay $370 million of debt associated with the Aruba refinery. 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.

13

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.

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 June 30, 2004. The
summarized financial results and financial position data of our discontinued
operations were as follows:

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 six months ended June 30:

Our 2004 restructuring costs consisted of employee severance costs which
included severance payments and costs for pension benefits settled and curtailed
under existing benefit plans. During the quarter ended June 30, 2004, we
incurred $6 million in severance and related charges in our Pipelines and
Production segments and in our corporate activities. As of September 30, 2004,
substantially all of the employee severance, retention and transition costs had
been paid.

Our 2003 restructuring costs were incurred as part of our ongoing liquidity
enhancement and cost reduction efforts. Employee severance costs included
severance payments and costs for pension benefits settled and curtailed under
existing benefit plans. During the quarter ended June 30, 2003, we incurred $31
million in severance and related charges across all of our segments. 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.

16

Office Relocation and Consolidation

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

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 June 30, our loss on long-lived assets was as follows:

Net Realized Gain

Our 2004 net realized gain was primarily related to an $8 million gain on
aircraft sales associated with our Corporate activities. 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 $8 million of losses
related to the sales of assets associated with our corporate activities in 2003.

Asset Impairments

Our 2004 asset impairments primarily occurred in our Power segment, which
included 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 these matters. Our Power
segment also recorded $10 million of impairments primarily in the second quarter
of 2004 on our domestic power plants to adjust the carrying value of these
plants to their expected sales price. We recorded $7 million of impairments in
the second quarter of 2004 in our Field Services segment, primarily related to
the abandonment of miscellaneous assets that will no longer be used after the
merger between GulfTerra and Enterprise. See Note 16 for a further discussion of
the merger.

Our 2003 impairment charges 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

17

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 a $31 million impairment on our LNG assets
related to our plan to reduce our involvement in that business.

7. INCOME TAXES

Income taxes included in our income (loss) from continuing operations for
the periods ended June 30, 2004 and 2003 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 six months of
2004, our overall effective tax rate on continuing operations was significantly
different than the statutory rate due primarily to impairments of certain of our
foreign investments for which there is no corresponding U.S. federal income tax
benefit combined with a loss before income taxes. This resulted in an overall
tax expense for a period in which there was also a pre-tax loss.

For the year ended December 31, 2004, our effective tax rate will be
significantly different from the statutory rate of 35 percent because of the
completion of the merger between GulfTerra and Enterprise in September 2004. The
sale of our interests in GulfTerra associated with the merger will result in a
significant tax gain (versus a much lower book gain) and significant tax expense
due to the non-deductibility of goodwill written off as a result of the
transaction. We believe the impact of this non-deductible goodwill will increase
our tax expense (or reduce our tax benefit) by approximately $139 million. See
Note 16 for a further discussion of the merger and related transactions.

Proposed tax legislation is being considered in Congress which would
disallow deductions for certain settlements made to or on behalf of governmental
entities. If enacted, this tax legislation could impact the deductibility of the
Western Energy Settlement and could result in a write-off of some or all of the
associated tax assets. In such event, our tax expense would increase. Our total
tax assets related to the Western Energy Settlement were approximately $400
million as of June 30, 2004.

18

8. EARNINGS PER SHARE

Our basic and diluted income (loss) per share were as follows for the
periods ended June 30:

For the quarters and six months ended June 30, 2004 and June 30, 2003,
there were 16 million of potentially dilutive securities excluded from the
determination of average common shares outstanding 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 June 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 Utility Contract Funding and Mohawk River Funding IV in 2004. See
Note 6 for a discussion of the net losses related to these sales.

(2) During the six months ended June 30, 2004, we entered into new cross
currency hedge transactions that convert E75 million of our fixed rate
Euro-denominated debt into $91 million of floating rate debt. After June 30,
2004, we entered into other cross currency hedge transactions that convert
another E25 million of fixed rate debt into $30 million of floating rate
debt.

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

19

10. INVENTORY

We have the following inventory recorded on our balance sheets:

11. DEBT, OTHER FINANCING OBLIGATIONS AND OTHER CREDIT FACILITIES

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

20

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 October 2004, we entered into an agreement, effective August 2004, with
two affiliates of Enron that liquidates two of our derivative swap
agreements in exchange for approximately $213 million of 6.5%, one year
notes. The transaction was approved by the bankruptcy court in November
2004. As of June 30, 2004, the balance of these swaps was a liability of
$234 million, which is reflected in other current and other non-current
liabilities in our balance sheet.

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

Credit Facilities

In November 2004, we entered into an agreement with a group of lenders for
an aggregate of $3 billion in financings that will become available to us upon
the filing of this Form 10-Q. These financings will replace our existing
revolving credit facility, and will provide approximately $220 million in net
additional borrowing availability (after repayment of our Lakeside Technology
Center obligation of approximately $229 million, fees, and other obligations),
as compared to the borrowing availability under our existing credit facility.
The new credit agreement is comprised of a $1.25 billion term loan, a $1 billion
revolving credit facility, and a $750 million funded letter of credit facility.
Certain of our subsidiaries, EPNG, TGP, ANR, and CIG will also continue to be
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.

Under the term loan we will borrow $1.25 billion at LIBOR plus 2.75
percent, which will mature 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 will pay an annual commitment fee
of 0.75 percent on any unused capacity under the revolving credit facility. As
discussed below, we will use a portion of the new revolving credit facility to
support existing

21

letters of credit under our current credit facility. The remaining amount under
this $1 billion revolving credit facility will initially be undrawn.

Upon closing of the new credit agreement, certain lenders will fund a $750
million letter of credit facility that will provide us the ability to issue
letters of credit or borrow any unused capacity under the facility as loans with
a maturity in November 2009. We will pay LIBOR plus 2.75 percent on any amounts
borrowed under the facility, and 2.85 percent on letters of credit and
unborrowed funds. We will initially use this letter of credit facility to
support currently outstanding letters of credit.

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

Restrictive Covenants

Our restrictive covenants 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) the ratio of Debt to Consolidated EBITDA, each as defined in the new
credit agreement, shall not exceed 6.50 to 1 at any time prior to
September 30, 2005, 6.25 to 1 at any time on or after September 30,
2005 and prior to June 30, 2006, and 6.00 to 1 at any time on or after
June 30, 2006 until maturity;

(b) the ratio of Consolidated EBITDA, as defined in the new credit
agreement, to interest expense and dividends paid shall not be less
than 1.60 to 1 prior to March 31, 2006, 1.75 to 1 on or after March 31,
2006 and prior to March 31, 2007, and 1.80 to 1 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;

(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.

Letters of Credit

We enter into letters of credit in the ordinary course of our operating
activities. As of June 30, 2004, we had outstanding letters of credit of
approximately $1.2 billion, of which $1.1 billion was outstanding under our
existing revolving credit facility and $62 million was supported with cash
collateral. Included in this amount were $0.6 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 will have approximately
$1.2 billion of letters of

22

credit. We will use the new $750 million letter of credit facility and
approximately $0.4 billion of the new $1.0 billion revolving credit facility to
support 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

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

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

During the fourth quarter of 2002, we recorded an $899 million pretax
charge related to the Western Energy Settlement. In the second quarter of 2003,
we recorded an additional pretax charge of $104 million based upon reaching
definitive settlement agreements. 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 June 30, 2004 under the Western
Energy Settlement consists of the discounted 20-year cash payment obligation of
$398 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 initial
collateral requirement was approximately $592 million and will be reduced as
payments under our 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.

23

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.

Shareholder Class Action Suits. Beginning in July 2002, twelve purported
shareholder class action lawsuits alleging violations of federal securities laws
have been filed against us and several of our former officers. Eleven of these
lawsuits are now consolidated in federal court in Houston before a single judge.
The twelfth lawsuit, filed in the Southern District of New York, was dismissed
in light of similar claims being asserted in the consolidated suits in Houston.
The lawsuits generally challenge the accuracy or completeness of press releases
and other public statements made during 2001 and 2002. Two shareholder
derivative actions have also been filed which generally allege the same claims
as those made in the consolidated shareholder class action lawsuits. One, which
was filed in federal court in Houston in August 2002, has been consolidated with
the shareholder class actions pending in Houston, and has been stayed. The
second shareholder derivative lawsuit, filed in Delaware State Court in October
2002, generally alleges the same claims as those made in the consolidated
shareholder class action lawsuit and also has been stayed. Two other shareholder
derivative lawsuits are now consolidated in state court in Houston. Both
generally allege that manipulation of California gas supply and gas prices
exposed us to claims of antitrust conspiracy, FERC penalties and erosion of
share value.

Beginning in February 2004, seventeen purported shareholder class action
lawsuits alleging violations of federal securities laws were filed against us
and several individuals in federal court in Houston. The lawsuits generally
allege that our reporting of natural gas and oil reserves was materially false
and misleading. Each of these lawsuits recently has been consolidated into the
shareholder lawsuits described in the immediately preceding paragraph. An
amended complaint in this consolidated securities lawsuit was filed 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 against certain of the individually named defendants
under the Sarbanes-Oxley Act of 2002.

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.

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

24

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 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.

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

Government Investigations

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

25

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.

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

Iraq Oil Sales. In September 2004, The Coastal Corporation (now known as
El Paso CGP Company, which we acquired in January 2001) received a subpoena from
the grand jury of the U.S. District Court for the Southern District of New York
to produce records regarding the United Nations' Oil for Food Program governing
sales of Iraqi oil. The subpoena seeks various records relating to transactions
in oil of Iraqi originating 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.

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 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

26

grand jury subpoena requesting additional documents. We have responded fully to
this subpoena. Two additional employees testified before the grand jury in June
2004.

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

Parties to four of the settled lawsuits have since filed an additional
lawsuit titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas in
November 2002, seeking additional sums based upon their interpretation of
earlier settlement agreements. This matter has been settled and dismissed. In
addition, a lawsuit entitled Baldonado et. al. v. EPNG was filed 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. Briefs will be filed by the end of this year.
Our costs and legal exposure related to the Baldonado lawsuit are not currently
determinable, however we believe this matter will be fully covered by insurance.

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

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As this information becomes available, or other relevant developments occur, we
will adjust our accrual amounts accordingly. While there are still uncertainties
related to the ultimate costs we may incur, based upon our evaluation and
experience to date, we believe our current reserves are adequate. As of June 30,
2004, we had approximately $518 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 June 30,
2004, we had accrued approximately $400 million, including approximately $391
million for expected remediation costs and associated onsite, offsite and
groundwater technical studies, and approximately $9 million for related
environmental legal costs, which we anticipate incurring through 2027. Of the
$400 million accrual, $149 million was reserved for facilities we currently
operate, and $251 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 $400 million to
approximately $573 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 ($85 million). Second, where the most
likely outcome cannot be estimated, a range of costs is established ($315
million to $488 million) and if no one amount in

27

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
June 30, 2004 (in millions):

Balance as of January 1, 2004............................... $412
Additions/adjustments for remediation activities............ 7
Payments for remediation activities......................... (20)
Other changes, net.......................................... 1
----
Balance as of June 30, 2004................................. $400
====

For the remainder of 2004, we estimate that our total remediation
expenditures will be approximately $39 million. In addition, we expect to make
capital expenditures for environmental matters of approximately $86 million in
the aggregate for the years 2004 through 2008. These expenditures primarily
relate to compliance with clean air regulations.

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

PCB Cost Recoveries. In May 1995, following negotiations with its
customers, TGP filed an agreement with the FERC that established a mechanism for
recovering a substantial portion of the environmental costs identified in its
internal remediation project. The agreement, which was approved by the FERC in
November 1995, provided for a PCB surcharge on firm and interruptible customers'
rates to pay for eligible remediation costs, with these surcharges to be
collected over a defined collection period. TGP has received approval from the
FERC to extend the collection period, which is now currently set to expire in
June 2006. The agreement also provided for bi-annual audits of eligible costs.
As of June 30, 2004, TGP had pre-collected PCB costs by approximately $123
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 June 30, 2004, TGP has recorded a regulatory liability
(included in other non-current liabilities on its balance sheet) of $92 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 June 30, 2004, we
have estimated our share of the remediation costs at these sites to be between
$31 million and $45 million. Since the clean-up costs are estimates and are
subject to revision as

28

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

In November 2004, the FERC issued an industry-wide Proposed Accounting
Release that, if enacted as written, will disallow the capitalization of 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 what
impact this release will have on our consolidated financial statements.

Other

Enron Bankruptcy. In December 2001, Enron Corp. and a number of its
subsidiaries, including Enron North America Corp. (ENA) and Enron Power
Marketing, Inc. (EPMI) filed for Chapter 11 bankruptcy protection in New York.
We had various contracts with Enron marketing and trading entities, and most of
the trading-related contracts were terminated due to the bankruptcy. In October
2002, we filed proofs of claims against the Enron trading entities totaling
approximately $317 million. We sold $244 million of the original claims to a
third party. Enron also maintained that El Paso Merchant Energy-Petroleum
Company owed it approximately $3 million, and that 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 Corporation, based on the alleged $46 million liability. On
June 24, 2004, the Bankruptcy Court approved a settlement agreement with Enron
that resolved all of the foregoing issues as well as most other trading or
merchant issues between the parties. Our European trading businesses also
asserted $20 million in claims against Enron Capital and Trade Resources
Limited, which are subject to separate proceedings in the United Kingdom, in
addition to a corresponding claim against Enron Corp. based on a corporate
guarantee. After considering the valuation and setoff arguments and the reserves
we have established, we believe our overall exposure to Enron is $3 million.

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

29

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 $1.5 billion as of June 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 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 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 $183 million at June 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 June 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 June 30, 2004. Manaus Energia purchases power from both projects through
long-term PPA's. 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 is free to proceed with
the bid. As a result of our negotiations to extend the term of the PPA's and
based the status of the legal challenges to Manaus Energia's bid process, we
believe, however, that it is uncertain as to whether the bid process will
proceed. If the bid process continues, the bid qualifications issued by Manaus
Energia may prohibit us from supplying power from our Manaus and Rio Negro
projects. Based on the potential results of the bid process and the expected
outcome of our negotiations to extend the term of the PPA's, we recorded an
impairment charge of approximately $135 million in the first quarter of 2004.
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 and have resulted in a long-term receivable of $32 million which is
a subject of this lawsuit. Based on the future outcome of this lawsuit, we could
be required to provide an allowance for the receivable.

We own a 50 percent interest in a 404 MW dual-fuel-fired power project
known as the Porto Velho Project, located in Porto Velho, Brazil. The Porto
Velho Project has two PPA's. The first PPA has a term of ten years and relates
to the first phase of the project. The second PPA has a term of 20 years and
relates to the second 345 MW phase of the project. We are negotiating certain
provisions of both PPA's with EletroNorte, including the amount of installed
capacity, energy prices, take or pay levels, the term of the first PPA and other
issues. Although the current terms of the PPA's and the proposed amendments do
not indicate an

30

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
$293 million at June 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. The time required to replace or
repair the steam turbine has not yet been determined.

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 $726 million at June 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.

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 former
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 the Employee Retirement
Income Security Act of 1974, or 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. However,
in September 2004, a judge ruled that El Paso, must indemnify Case for the $1.8
million monthly amounts above the cap. Both rulings have been appealed. We will
begin making the monthly payments of approximately $1.8 million in October 2004.
While the outcome of these matters is uncertain, if we were required to
ultimately pay for 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. At
this time, we believe amounts we have accrued for this matter are appropriate.

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

Guarantees

We are involved in various joint ventures and other ownership arrangements
that sometimes require additional financial support that results in the issuance
of financial and performance guarantees. See our 2003 Annual Report on Form 10-K
for a description of each type of guarantee. As of June 30, 2004, we had
approximately $188 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
June 30, 2004, we had accrued $78 million related to these arrangements.

31

13. RETIREMENT BENEFITS

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

We made $33 million and $58 million of cash contributions to our
Supplemental Executive Retirement Plan and other postretirement plans during the
six months ended June 30, 2004 and 2003. We expect to contribute an additional
$5 million to the Supplemental Executive Retirement Plan and $37 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 are currently evaluating new
accounting standards that become effective in the third quarter of 2004 that may
require changes to previously reported benefit information and to our net
benefit cost for the year ending December 31, 2004.

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 to satisfy the remaining stock obligation under our Western Energy
Settlement.

Dividends

During the six months ended June 30, 2004, we paid dividends of $49 million
to common stockholders. We have also paid dividends of approximately $51 million
subsequent to June 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.

32

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 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 June 30:

33

The following tables reflect our segment results as of and for the periods
ended June 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 petroleum markets operations.

35

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 (loss) of $8 million and $(2) million for the quarters
ended June 30, 2004 and 2003, and net income of $21 million and $5 million
for the six months ended June 30, 2004 and 2003, related to our
proportionate share of affiliates in which we hold a greater than 50 percent
interest.

Our income statement reflects our share of net earnings (losses) 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 June 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 6).

(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.

36

We received distributions and dividends from our investments of $74 million
for each of the quarters ended June 30, 2004 and 2003, and $168 million and $157
million for the six months ended June 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 June 30:

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

We had the following interests in GulfTerra as of June 30, 2004:

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

(1) As of June 30, 2004, Enterprise had an effective 50 percent ownership
interest in the general partner, which we have reflected in our balance
sheet as minority interest of $96 million. We also had $181 million of
indefinite-lived intangible assets related to the general partner interest
as of June 30, 2004.

(2) As of June 30, 2004, we owned 17.3 percent of the common units of GulfTerra.
The remaining units are owned by public holders, including the partnership
employees and management, none of which individually own more than 10
percent.

(3) As of June 30, 2004, we owned all of the Series C units of GulfTerra.

In September 2004, in connection with the closing of the merger between
GulfTerra and Enterprise, we completed the sale of substantially all of our
interests in GulfTerra, as well as certain processing assets to affiliates of
Enterprise. Our total gross cash proceeds from the sale were approximately $1.03
billion and we will record a gain of approximately $5 million as a result of
this transaction including the elimination of approximately $480 million in
goodwill associated with our Field Services segment. Of the $480 million of
goodwill that will be eliminated, approximately $397 million will not be
deductible for tax purposes. As a result, we will recognize a significant tax
gain and tax expense associated with the transaction in the third quarter of
2004. The assets sold were our interest in the general partner of GulfTerra,
10.9 million Series C units, 2.9 million GulfTerra common units, and nine
processing plants located in South Texas. In addition to the cash proceeds, we
received a 9.9 percent interest in the general partner of the combined
organization, Enterprise Products GP, LLC. Our remaining GulfTerra common units
were exchanged for approximately 13.5 million common units in Enterprise as a
result of the merger.

37

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 June 30:

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

38

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 historical 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 six
months ended June 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 $3.4 billion of
maturing debt and other obligations, ($1.9 billion through June 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 to refinance our existing revolving
credit facility with an aggregate of $3 billion in financings consisting
of a $1.25 billion, five year term loan, a new $1.0 billion three year
revolving credit facility, and a five year, $750 million funded letter of
credit facility, all of which will become available to us upon the filing
of this Quarterly Report on Form 10-Q (see Note 11).

Liquidity Update

We believe that the restatement of our historical financial statements
mentioned above would have constituted an event of default under our existing
revolving credit facility and various other financing transactions; specifically
under the provisions in these arrangements related to representations and
warranties on the accuracy of our historical financial statements and on our
debt to total capitalization ratio. During 2004, we received several waivers on
our existing revolving credit facility and various other financing arrangements
to address certain of these issues. With the filing of these financial
statements, we are in compliance with our existing revolving credit facility and
with the various other financings on which we received waivers. Three of our
subsidiaries have indentures associated with their public debt that contain $5
million cross-acceleration provisions. These indentures state that should an
event of default occur resulting in the acceleration of other debt obligations
of such subsidiaries in excess of $5 million, the long-term debt obligations
containing such provisions could be accelerated. The acceleration of our debt
would adversely affect our liquidity position, and in turn, our financial
condition. Our subsidiary, El Paso CGP Company, has not yet filed its financial
statements for the second quarter of 2004, as required under several of its
financing arrangements. We believe we will file El Paso CGP's financial
statements prior to any notice being given or within the allowed time frames
under these financing arrangements such that there will be no event of default.

39

Our existing revolving credit facility matures in June 2005. As of June 30,
2004, we had $600 million outstanding (which was repaid in September 2004) and
$1.1 billion of letters of credit issued under this facility. In November 2004,
we entered into a new credit agreement with a group of lenders for an aggregate
of $3 billion in financings that will become available to us upon the filing of
this Form 10-Q. This new credit agreement will replace our existing revolving
credit facility and will consist of a $1.25 billion, five year term loan, a new
$1 billion, three year revolving credit facility under which we can issue
letters of credit, and an additional five year, $750 million funded letter of
credit facility. The letter of credit facility will provide us the ability to
issue letters of credit or borrow any unused capacity as loans. The new credit
agreement will be collateralized by our interests in EPNG, TGP, ANR, CIG, WIC,
ANR Storage Company, and Southern Gas Storage Company.

Our new credit agreement will provide approximately $220 million in net
additional borrowing availability as compared to our existing revolving credit
facility. Upon the closing of the new credit agreement, letters of credit of
approximately $1.2 billion issued under our existing revolving credit facility
will be supported by the $750 million letter of credit facility and by
approximately $0.4 billion of the new $1 billion revolving credit facility. We
will use the $1.25 billion term loan proceeds to repay certain financing
obligations, manage our liquidity, prepay upcoming debt maturities, and provide
for other general corporate purposes.

Our subsidiaries are a significant potential source of liquidity to us, and
they participate in our cash management program to the extent they are permitted
to do so under their financing agreements and indentures. Under the cash
management program, depending on whether participating subsidiaries have
short-term cash requirements or surpluses, we either provide cash to them or
they provide cash to us. If we were to incur an event of default under our
credit facilities, we would be unable to obtain cash from our pipeline
subsidiaries, which are the primary source of cash under this program. In
addition, our ownership in a number of our subsidiaries and investments
currently serves as collateral under our existing revolving credit facility and
our other financings, and will serve as collateral under the new credit
agreement. If the lenders were to exercise their rights to this collateral, we
could lose our ownership interest in these subsidiaries or be required to
liquidate these investments.

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, and common or preferred equity securities. However, a number
of factors could influence our liquidity sources, as well as the timing and
ultimate outcome of our ongoing efforts and plans.

CAPITAL STRUCTURE

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

40

During the six months ended June 30, 2004, we continued to reduce our debt
as part of our Long-Range Plan announced in December 2003. Our activity during
the six months ended June 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.................................. 50
Repayments/retirements of principal(1)...................... (1,024)
Sales of entities(2)........................................ (887)
Other....................................................... (37)
-------
Total debt and securities of subsidiaries as of
June 30, 2004.................................... $20,281
=======

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

(1) Amount includes $250 million of repayments under our existing revolving
credit facility and 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.

CAPITAL RESOURCES AND LIQUIDITY

OVERVIEW OF CASH FLOW ACTIVITIES FOR THE SIX MONTHS ENDED JUNE 30, 2004 AND 2003

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

41

During the first six 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...................... $0.1
Net proceeds from the sale of assets and investments...... 0.2
Net change in restricted cash(1).......................... 0.4
Other..................................................... 0.2
----
Total cash inflows from continuing operations.......... 0.9
----
Cash outflows from continuing operations
Additions to property, plant and equipment................ (0.8)
Payments to retire long-term debt......................... (1.0)
----
Total cash outflows from continuing operations......... (1.8)
----
Cash flows from discontinued operations
Cash from operations...................................... 0.1
Net proceeds from sale of assets.......................... 1.2
Payments to retire long-term debt......................... (0.4)
----
Total net cash inflows from discontinued operations.... 0.9
----
Net increase in cash................................. $ --
====

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

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

As of November 15, 2004, we had available cash on hand and borrowing
capacity under our existing revolving credit facility totaling $2.2 billion.
Upon closing our new credit agreement effective with this filing, our net
available liquidity will increase by approximately $220 million.

Cash From Continuing Operating Activities

Overall, cash generated from our continuing operating activities was $0.1
billion during the first six months of 2004 versus $0.9 billion during the same
period of 2003. The $0.8 billion decrease in operating cash flow was due
primarily to a payment of $0.6 billion to settle the principal litigation under
the Western Energy Settlement in the second quarter of 2004.

42

Cash From Continuing Investing Activities

Net cash used in our continuing investing activities was $0.1 billion for
the six months ended June 30, 2004. Our investing activities consisted of the
following (in billions):

Production exploration, development and acquisition
expenditures.............................................. $(0.4)
Pipeline expansion, maintenance and integrity projects...... (0.4)
Restricted cash activity(1)................................. 0.4
Proceeds from the sale of assets and investments............ 0.2
Other....................................................... 0.1
-----
Total continuing investing activities............. $(0.1)
=====

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

(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 $1.2 billion, which includes approximately $0.5 billion for our
Production segment and $0.7 billion for our Pipelines segment.

Cash From Continuing Financing Activities

Net cash used by our continuing financing activities was $0.1 billion for
the six months ended June 30, 2004. Cash used in our financing activities
included net repayments of $1.0 billion made to retire third party long-term
debt. Cash provided from our financing activities included $0.9 billion of cash
generated by our discontinued operations as further discussed below. 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 six months of 2004, our discontinued operations
contributed $0.9 billion of cash. We generated $0.1 billion in cash in these
operations, received proceeds from the sales of the Eagle Point and Aruba
refineries of approximately $1.2 billion and paid long-term debt of $0.4 billion
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 June
30, 2004:

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

(1) Includes $269 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 six months ended June 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.

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

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

(1) Includes $861 million and $75 million of derivative contracts sold in
connection with the sale 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.

44

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, all of which
are immaterial. 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 June 30:

OVERVIEW OF RESULTS OF OPERATIONS

For the six months ended June 30, 2004, our consolidated EBIT from
continuing operations was $840 million of which $804 million was our segment
EBIT. During the six months, our Pipelines, Production and Field Services
segments contributed $1,165 million of combined EBIT. These positive
contributions were partially offset by EBIT losses of $361 million in our Power
and Marketing and Trading segments. The following overview summarizes the
results of operations of our operating segments.

Pipelines Our Pipelines segment generated EBIT of $694 million,
which was generally consistent with our expectations for
the period.

Production Our Production segment generated EBIT of $408 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, 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 $324 million, which was below 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 impacted by the hedge restatement in
periods prior to 2004, resulting in a mark-to-market
position that will result in losses if natural gas
prices increase.

Power Our Power segment generated an EBIT loss of $37 million,
which was below our expectations for the period,
primarily due to asset impairments of $281 million.
These impairments were primarily related to events at
two power plants in Brazil in the first quarter of 2004
that may make it difficult to extend their power sales
agreements that expire in 2005 and 2006, and due to
certain of our domestic operations which were sold or
are being sold.

46

Field Services Our Field Services segment generated EBIT of $63
million, which was consistent with our expectations for
the period and impacted by the significant asset sales
activity in the segment in 2003.

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

Our earnings in each period were impacted both favorably and unfavorably by
a number of factors affecting our businesses that are enumerated in the table
below. The discussion that follows summarizes these factors and their impact on
our operating segments and our corporate activities. For a more detailed
discussion of these factors and other items impacting our financial performance
for the six months ended June 30, see the individual segment and other results
included in Item 1, Financial Statements, Notes 5, 6, and 16.

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

(1) Includes $44 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 six month
period results, including a discussion of the items above, of each of our
business segments as well as our corporate activities, interest and debt
expense, distributions on preferred interests of consolidated subsidiaries,
income taxes and the results of our discontinued operations.

REGULATED BUSINESSES -- PIPELINES SEGMENT

Our Pipelines segment owns and operates our interstate natural gas
transmission businesses. For a further discussion of the business activities of
our Pipelines segment, see our 2003 Annual Report on Form 10-K.

47

Below are the operating results and analysis of these results for our Pipelines
segment for the periods ended June 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)

The following factors contributed to our overall EBIT increases of $163
million and $120 million for the quarter and six months ended June 30, 2004 as
compared to the same periods ended June 30, 2003:

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

(1) Transferred from our Power segment effective January 1, 2004.

The renegotiation or restructuring of several contracts on our pipeline
systems will continue to unfavorably impact our operating results and EBIT for
the remainder of 2004, among other items noted below.

48

Guardian Pipeline, which is owned in part by We Energies, is currently providing
a portion of its firm transportation requirements and directly competes with ANR
for a portion of the markets in Wisconsin. Additionally, ANR will continue to
experience lower operating revenues and lower operating expenses for the
remainder of 2004 based on the termination of the Dakota gasification facility
contract on its system. However, the termination of this contract will not have
a significant overall impact on operating income and EBIT.

EPNG's risk sharing provision, which provided revenue net of its sharing
obligations, expired at the end of 2003 and will continue to unfavorably impact
our comparative EBIT, as reflected above, for the remainder of 2004. The impact
of the capacity obligation for former full requirements (FR) customers reflected
above terminated with the completion of Phases I and II of EPNG's Line 2000
Power-up project in 2004. As a result, EPNG is now able to re-market this
capacity; however, it must demonstrate that such sales do not adversely impact
its service to its firm customers and it is at risk for portions of the capacity
that were turned back to EPNG on a permanently released basis.

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 November 2004, the FERC issued an industry-wide Proposed Accounting
Release that, if enacted as written, will disallow the capitalization of 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 of this release, if any, 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 we 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 six months ended June 30, 2004, our total equivalent production has
declined approximately 73 Bcfe or 32 percent as compared to the same period in
2003 primarily due to asset sales, normal production declines and disappointing
drilling results. Our average daily production through October 2004 has been as
follows:

January-October 2004........................................ 820 MMcfe/d
Month of October 2004....................................... 761 MMcfe/d

Our year to date 2004 and October 2004 production levels were negatively
impacted by hurricanes that occurred in September 2004 in the Gulf of Mexico.
The hurricanes caused us to shut-in production and also caused damage to third
party facilities that transport our production. We continue to experience
reduced

49

production levels in our offshore Gulf of Mexico operations as a result of the
damage to third party facilities and do not expect these facilities to return to
full production until mid-2005.

As mentioned above, in July 2004, we acquired the remaining 50 percent
interest in our UnoPaso investment in Brazil. Prior to this acquisition, we
treated our interest in UnoPaso as an equity method investment and, therefore,
did not include our proportionate share of its production in our average daily
production amounts. Subsequent to the acquisition of the remaining interest, we
began consolidating the operations of UnoPaso, which is producing an average of
approximately 55 MMcfe/d. 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 $616 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 $1.64 per Mcfe during the second quarter 2004 to
$1.74 per Mcfe for the third quarter of 2004 and 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 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 can be impacted significantly
by movements in commodity prices from period to period. For a further discussion
of our hedging program, refer to our 2003 Annual Report on Form 10-K.

In 2004, we have entered into the following additional hedges on our future
natural gas and oil production:

In addition, in the fourth quarter of 2004, we entered into additional
transactions in our Marketing and Trading segment designed to provide price
protection to El Paso from natural gas price declines in 2005 and 2006. These
"put" contracts will be marked-to-market in the operating results of our
Marketing and Trading segment and will not be treated as hedges for accounting
purposes in the operating results of our Production 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.

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

50

Operating Results

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

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

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

(2) Includes restructuring charges and gains on asset sales.

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

(4) Prices are stated before transportation costs.

51

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

EBIT. For the quarter ended June 30, 2004, EBIT was $108 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 June 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 June 30, 2004, operating revenues were $138 million
lower than in 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.

Average realized natural gas prices for the second quarter of 2004,
excluding hedges, were $0.61 per Mcf higher than the same period in 2003, an
increase of 11 percent. Our natural gas hedging losses remained unchanged at $4
million in 2003 and 2004. We expect hedging losses to continue in 2004 based on
current market prices for natural gas relative to the prices at which our
natural gas production is hedged.

Operating Expenses. Total operating expenses were $25 million lower for
the second quarter of 2004 as compared to the same period in 2003 primarily due
to lower depreciation, depletion, and amortization expenses, lower production
costs, and lower general and administrative expenses. We expect to incur higher
operating expenses in the fourth quarter of 2004 related to the relocation of
our offices in Houston, Texas.

Total depreciation, depletion, and amortization expense decreased by $10
million in the second 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 $43 million.
Partially offsetting this decrease were higher depletion rates due to higher
finding and development costs which contributed an increase of $31 million.

Production costs decreased by $10 million in the second quarter of 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 $0.03 in 2004. However, our total production costs per Mcfe
increased $0.10 as lease operating expenses increased $0.13 per Mcfe due to the
lower production volumes discussed above.

General and administrative expenses decreased $10 million in the second
quarter of 2004 as compared to the same period in 2003. The decrease was
primarily due to lower corporate overhead allocations. However, the cost per
unit increased $0.08 per Mcfe due to lower production volumes. For the remainder
of 2004, we will have higher corporate overhead allocations.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

EBIT. For the six months ended June 30, 2004, EBIT was $350 million lower
than the same period in 2003. The decrease in EBIT was primarily due to lower
production volumes due to normal production

52

declines, asset sales and disappointing drilling results. Partially offsetting
these decreases were lower operating expenses.

Operating Revenues. The following table describes the variance in revenue
between the six months ended June 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 six months ended June 30, 2004, operating revenues were $427
million lower than the same period in 2003 due to lower production volumes and
lower natural gas prices partially offset by 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.

Average realized natural gas prices for 2004, excluding hedges, were $0.24
per Mcf lower than the same period in 2003, a decrease of four percent. However,
partially offsetting the decrease in revenues due to lower prices were $9
million of hedging losses in 2004 compared to $30 million in 2003 relating to
our natural gas hedge positions. We expect hedging losses to continue in 2004
based on current market prices for natural gas relative to the prices at which
our natural gas production is hedged.

Operating Expenses. Total operating expenses were $64 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. Partially offsetting these lower costs were higher
employee severance costs in 2004. We expect to incur additional operating
expenses in the fourth quarter of 2004 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 $89 million. Partially
offsetting this decrease were higher depletion rates due to higher finding and
development costs which contributed an increase of $59 million.

Production costs decreased by $28 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 $0.09 in 2004.
However, our total production costs per Mcfe increased $0.06 as lease operating
expenses increased $0.15 per Mcfe due to the lower production volumes discussed
above.

General and administrative expenses decreased $18 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 $0.07 per
Mcfe due to lower production volumes. For the remainder of 2004, we will have
higher corporate overhead 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

53

many of our natural gas hedging contracts. This change will result in increased
earnings volatility in the future related to these derivative contracts as
natural gas prices change. For a further discussion of the restatement, refer to
our 2003 Annual Report on Form 10-K.

As discussed in our Production segment, in the fourth quarter of 2004, we
entered into additional transactions designed to provide 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 mark-to-market earnings if the current
and future price of natural gas declines in any given period and losses if the
current and future price of natural gas increases in any given period. 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.

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

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

For the quarter ended June 30, 2004, our gross margin improved by $134
million compared to the same period in 2003. This improvement was primarily due
to a $208 million decrease in the fair value of our derivatives, principally our
natural gas contracts, during 2003 compared to a $95 million decrease in the
fair value of our trading positions during 2004. We sell natural gas at a fixed
price in many of our trading contracts. The increase in natural gas futures
prices in the second quarter of 2003 was more significant than the increase in
the second quarter of 2004, resulting in a decrease in the fair value of these
derivatives in the second quarter of 2003 that was greater than the same period
in 2004. In addition, our Cordova derivative tolling agreement's fair value
decreased by $18 million in 2004 compared to a $31 million decrease 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

54

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 improvement in gross margin was $7 million of
losses related to the early termination of some of our derivative and
non-derivative contracts in 2003, compared to less than $1 million in 2004. In
2003, we were actively liquidating the derivative and non-derivative positions
in our trading portfolio. In 2004, we refocused our efforts to manage the
existing positions in our portfolio. 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. We also had settlement losses on
non-derivative contracts of $25 million in 2004 compared to $47 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.

For the quarter ended June 30, 2004, our operating expenses decreased by
$18 million compared to the same period in 2003. This decrease was primarily due
to a $19 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 $6 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. 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.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

For the six months ended June 30, 2004, our gross margin improved by $365
million compared to the same period in 2003. This improvement was primarily due
to a $522 million decrease in the fair value of our derivatives, principally our
natural gas contracts, during 2003 compared to a $243 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. Also contributing to this improvement was $41
million of losses related to the early termination of some of our derivative and
non-derivative contracts in 2003, compared to less than $1 million in 2004. Our
non-derivative contracts also had settlement losses of $68 million in 2004
compared to $95 million in 2003, which primarily related to demand charges we
could not recover on existing transportation contracts. Partially offsetting
these improvements was a decrease in our Cordova derivative tolling agreement's
fair value of $3 million in 2004 compared to a $7 million increase in 2003.

For the six months ended June 30, 2004, our operating expenses decreased by
$53 million compared to the same period in 2003. This decrease was primarily due
to a $34 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 $14 million decrease in operating
expenses of our London office, which was closed in 2003. Also contributing to
the decrease was $22 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.

55

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 June 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.

Domestic Power Plant Operations

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

Our domestic power plant operations relate to the ownership and operation
of power plant assets in the U.S. For the quarter ended June 30, 2004, the EBIT
generated by our domestic power plant operations was $43 million lower than the
same period in 2003. This decrease was primarily due to impairments of $34
million on our domestic power plants to adjust the carrying value of these
plants to the expected sales price in 2004. Also contributing to this decrease
was a decrease in operating income in 2004 of $25 million from our East Coast
Power facility which was sold during 2003. The majority of our domestic plants
were sold in the third quarter of 2004.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

For the six months ended June 30, 2004, the EBIT generated by our domestic
power plant operations was $219 million higher than the same period in 2003.
This increase was primarily due to a decrease in the amount of impairments in
2004 compared to 2003. In 2003, we recognized a $207 million impairment on our
investment in Chaparral and an $86 million loss due to the write-off of
receivables as a result of the transfer of our interest in the Milford power
facility to the plant's lenders. In 2004, we recognized impairments of $45
million on our domestic power plants to adjust the carrying value of these
plants to the expected sales price. Offsetting this net increase was lower
operating income in 2004 of $44 million from our East Coast

56

Power facility which was sold during 2003. The majority of our domestic plants
were sold in the third quarter of 2004.

Domestic Power Contract Restructuring Business

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

Our domestic power contract restructuring business relates to the continued
performance under our previously restructured power contracts. For the quarter
ended June 30, 2004, the EBIT generated by our domestic power contract
restructuring business was $19 million lower than the same period in 2003. This
decrease was primarily due to an increase of $39 million in the fair value of
our restructured power contracts in 2004 compared to an increase of $49 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.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003

For the six months ended June 30, 2004, the EBIT generated by our domestic
power contract restructuring business was $121 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 $69 million in 2003 compared to $58 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 June 30, 2004 Compared to Quarter Ended June 30, 2003

Brazil. Our Brazilian operations focus on our Macae, Manaus, Rio Negro and
Porto Velho power plants. For the quarter ended June 30, 2004, the EBIT
generated by our Brazilian power plant operations decreased by $1 million
compared to the same period in 2003. This decrease was due primarily to our
Porto Velho power plant, which generated operating income of $7 million in 2004
compared to $9 million in 2003. In the fourth 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 first six months of
2005.

Other International. For the quarter ended June 30, 2004, the EBIT
generated by our other international power operations was $20 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 $5 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 increase of $8
million in the equity earnings from two of our Asian equity investments in 2004
when compared to the same period in 2003.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 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 the second quarter of

57

2003 and the first six months of 2004 include the revenues, expenses and equity
earnings from Gemstone's assets.

For the six months ended June 30, 2004, the EBIT loss generated by our
Brazilian power plant operations was $28 million compared to EBIT of $73 million
in the same period in 2003. Our 2004 EBIT loss was primarily due to $135 million
of impairments of the Manaus and Rio Negro power plants due to events in the
first quarter of 2004 that may make it difficult to extend their power sales
agreements that expire in 2005 and 2006. These losses were partially offset by
$86 million of operating income from our Macae power plant and $14 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 quarter of 2003, our Macae and Porto Velho
power plants generated operating income of $41 million and $9 million.

Other International. For the six months ended June 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 $8 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 increase of $9
million in the equity earnings from two of our Asian equity investments 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
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 six months ended June 30, 2004 and 2003, we were reimbursed for
expenses incurred on behalf of the partnership of approximately $45 million and
$46 million, of which $23 and $22 were incurred in the second quarter of 2004
and 2003.

58

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 June 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.

59

For the quarter and six months ended June 30, 2004, our EBIT was $83
million and $92 million higher than the same periods in 2003. Below is a summary
of significant factors affecting EBIT.

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

(1) Our equity investments in Dauphin Island and Mobile Bay were impaired in
2003 based on anticipated losses on the sales of these investments. These
sales were completed in the third quarter of 2004.

Processing margins increased primarily due to the 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. In the third quarter of 2004 we expect to
incur an impairment charge of approximately $13 million on our Indian Springs
natural gas gathering and processing assets. These assets were approved for sale
by our Board of Directors in August 2004.

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.

60

For the periods ended June 30, 2004, EBIT in our corporate operations were
higher than the same period in 2003 due to the following:

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

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter and six months ended June 30,
2004, was $53 million and $44 million lower than the same periods in 2003. Below
is an analysis of our interest expense for the periods ended June 30:

Quarter and Six Months Ended June 30, 2004 Compared to Quarter and Six Months
Ended June 30, 2003

Interest expense on long-term debt decreased due to retirements of debt
during 2003 and the first and second quarters 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 a payment of $250 million on
the revolver during the first quarter of 2004. Partially offsetting this
decrease were higher commitment fees on letters of credit in the second 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

61

six months ended June 30, 2004, was higher than the same period in 2003
primarily due to higher average interest rates in 2004 than in 2003.

DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Distributions on preferred interests of consolidated subsidiaries for the
quarter and six months ended June 30, 2004 were $11 million and $26 million
lower than the same periods in 2003 primarily due to the refinancing and
redemption of our Clydesdale financing arrangement, the redemptions of the
preferred stock on two of our subsidiaries, Trinity River and Coastal
Securities, and the reclassification of our Coastal Finance I and Capital Trust
I mandatorily redeemable preferred securities to long-term financing obligations
as a result of the adoption of SFAS No. 150 in 2003. Based on this
reclassification, we began recording the preferred returns on these securities
as interest expense rather than as distributions of preferred interests. The
decrease was also due to the impact of the consolidations of Chaparral and
Gemstone as a result of our acquisitions of these investments. Our remaining
balance of preferred interests as of June 30, 2004 primarily consists of $300
million of 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 June 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 benefit;

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

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

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

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

Proposed tax legislation is being considered in Congress which would
disallow deductions for certain settlements made to or on behalf of governmental
entities. If enacted, this tax legislation could impact the deductibility of the
Western Energy Settlement and could result in a write-off of some or all of the
associated tax assets. In such event, our tax expense would increase. Our total
tax assets related to the Western Energy Settlement were approximately $400
million as of June 30, 2004.

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

DISCONTINUED OPERATIONS

The loss from our discontinued operations for the second quarter of 2004
was $29 million compared to a loss of $939 million for the same period of 2003.
The loss in 2004 related to impairment charges on our remaining Canadian
production operations that were discontinued during the second quarter of 2004.
The loss in 2003 was primarily due to impairments at our Aruba refining facility
that was approved for sale by our Board of Directors during the second quarter
of 2003.

62

For the six months ended June 30, 2004, the loss from our discontinued
operations was $138 million compared to a loss of $1,154 million during the same
period in 2003. In 2004, $69 million of losses from discontinued operations
related to our Canadian and certain other international production operations,
primarily from impairments, and $69 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 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.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 12, which is incorporated herein by
reference.

63

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS

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

- earnings per share;

- capital and other expenditures;

- dividends;

- financing plans;

- capital structure;

- liquidity and cash flow;

- credit ratings;

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

- future economic performance;

- operating income;

- management's plans; and

- goals and objectives for future operations.

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

64

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 $32 million as of June 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 June 30, 2004 and December 31, 2003, we had $0.7 billion and $1.7
billion of third party long-term restructured power purchase and power supply
derivative contracts. In the second quarter of 2004, we sold one of the
contracts held by Utility Contract Funding, which had a fair value of $865
million as of December 31, 2003. This sale and the planned sale of Cedar Brakes
I and II, which hold two of our power derivative contracts, will substantially
reduce our exposure to interest rate risk related to these contracts.

65

ITEM 4. CONTROLS AND PROCEDURES

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

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

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

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

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

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

- Inadequate documentation of accounting conclusions related to complex
accounting standards;

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

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

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

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

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

- Untimely preparation and review of volume and account reconciliations.

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

66

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

67

We did not make any changes to our internal controls over financial
reporting during the six months ended June 30, 2004, that have had a material
adverse affect or are reasonably likely to have a material adverse affect on our
internal controls over financial reporting.

We also reviewed our overall disclosure controls and procedures for the
quarter ended June 30, 2004. Disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by us in the reports that we file or submit under the Securities
Exchange Act of 1934 is accumulated and communicated to our management,
including our principal executive and principal financial officers, or persons
performing similar functions, as appropriate to allow timely decisions regarding
required disclosure.

As a result of the internal control deficiencies described above, we
concluded that our disclosure controls and procedures were not effective at June
30, 2004. However, we expanded our procedures to include additional analysis and
other post-closing procedures to ensure that the disclosure controls and
procedures over the preparation of these financial statements were effective.

68

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

We held our annual meeting of stockholders on November 18, 2004. Proposals
presented for a stockholders' vote included the election of twelve directors,
ratification of the appointment of PricewaterhouseCoopers LLP as independent
certified public accountants for the fiscal year 2004, and two stockholder
proposals.

Each of the twelve incumbent directors nominated by El Paso was elected
with the following voting results:

The appointment of PricewaterhouseCoopers LLP as El Paso's independent
certified public accountants for the fiscal year 2004 was ratified with the
following voting results:

There were no broker non-votes for the ratification of
PricewaterhouseCoopers LLP.

Two proposals submitted by stockholders were presented for a stockholder
vote. One proposal called for stockholder approval of expensing the costs of all
future stock options in the annual income statement. The second proposal called
for stockholder approval regarding Commonsense Executive Compensation. The first

69

stockholder proposal was approved and the second stockholder proposal was not
approved with the following voting results:

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b),
paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of our long-term debt not filed herewith for the reason that the
total amount of securities authorized under any of such instruments does
not exceed 10 percent of our total consolidated assets.

70

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: November 23, 2004 /s/ D. DWIGHT SCOTT
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: November 23, 2004 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

71

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.