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