EL PASO CORP/DE - 10-Q Quarterly Report

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

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FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-14365

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

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 7,
2003: 599,424,353

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EL PASO CORPORATION

TABLE OF CONTENTS

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

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

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. Also, when we refer to cubic feet measurements, all measurements
are at a pressure of 14.73 pounds per square inch.

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

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO CORPORATION

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

See accompanying notes.

1

EL PASO CORPORATION

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

See accompanying notes.

2

EL PASO CORPORATION

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

See accompanying notes.

3

EL PASO CORPORATION

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

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

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States 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 it along with our Current Report on Form 8-K dated
September 23, 2003 (which updated the financial statement information originally
presented in our 2002 Form 10-K to reclassify our petroleum markets business as
a discontinued operation), which includes a summary of our significant
accounting policies and other disclosures. The financial statements as of
September 30, 2003, and for the quarters and nine months ended September 30,
2003 and 2002, are unaudited. We derived the balance sheet as of December 31,
2002, from the audited balance sheet filed in our Current Report on Form 8-K
dated September 23, 2003. 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 our results of operations for the entire year. Our results
for all periods presented have been reclassified to reflect our petroleum and
coal mining operations as discontinued operations. In addition, 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.

2. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES

SIGNIFICANT EVENTS

Liquidity Update

In early 2003, following actions taken by rating agencies to downgrade the
credit ratings of our company and many of the largest participants in our
industry, we announced a plan to address the business challenges and liquidity
needs of our company. These initiatives, broadly referred to as our 2003
Operational and Financial Plan, were based upon five key points. The five key
points were:

- Preserve and enhance the value of our core businesses;

- Divest non-core businesses quickly, but prudently;

- Strengthen and simplify our balance sheet, while at the same time
maximizing liquidity;

- Aggressively pursue additional cost reductions; and

- Work diligently to resolve regulatory and litigation matters.

To date in 2003, our major accomplishments regarding these business objectives
have been as follows:

- We concentrated our capital investment in our core Pipelines, Production
and Field Services segments such that 91 percent of total capital
expenditures have been made in these businesses in the first nine months
of 2003;

- We completed or announced sales of assets and investments of
approximately $3.1 billion (see Note 4);

- We entered into a new $3 billion revolving credit facility that matures
in June 2005 and completed financing transactions of approximately $3.8
billion ($3.6 billion as of September 30, 2003) (see Note 16);

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- We retired approximately $5.8 billion of maturing debt and other
obligations ($4.7 billion as of September 30, 2003), including:

- the retirement of long-term debt of $2.9 billion ($2.2 billion as of
September 30, 2003);

- the net repayment of $650 million of outstanding amounts under our $3
billion revolving credit facility ($250 million as of September 30,
2003);

- the repayment of $980 million of obligations under our Trinity River
financing arrangement;

- the redemption of $197 million of obligations under our Clydesdale
financing arrangement, also restructuring that transaction as a term
loan that will mature in equal quarterly payments through 2005 (see
Notes 3 and 17); and

- the contribution of $1 billion to the Limestone Electron Trust, which
used the proceeds to repay $1 billion of its notes, and the purchase
and consolidation of the third party equity interests in our Gemstone
and Chaparral power investments (see Note 3);

- We refinanced a $1.2 billion two-year term loan issued in March 2003 in
connection with the restructuring of our Trinity River financing
arrangement to eliminate the amortization requirements of that loan in
2004 and 2005;

- We identified an estimated $445 million of cost savings and business
efficiencies to be realized by the end of 2004;

- We executed definitive settlement agreements in June 2003, which
substantially resolved our principal exposure relating to the Western
Energy crisis and raised funds of $347 million to satisfy a portion of
our obligation through the issuance of senior unsecured notes of El Paso
Natural Gas Company (EPNG) in July 2003 (see Notes 6 and 18);

- We initiated a tender offer in October 2003 to exchange common stock and
cash for our outstanding equity security units which would, if 100
percent of the units were tendered, result in a reduction of up to $575
million in our outstanding debt balances, an increase in stockholders'
equity of up to approximately $475 million and a reduction of cash of up
to approximately $112 million (see Note 16); and

- We initiated a program to supplement our capital spending on natural gas
and oil properties by an additional $350 million.

We believe the accomplishments to date demonstrate our ability to address
our liquidity issues and simplify and improve our capital structure. However, a
number of factors could influence the timing and ultimate outcome of these
efforts, including our ability to raise cash from asset sales, which may be
impacted by our ability to locate potential buyers in a timely fashion and
obtain a reasonable price or by competing asset sale programs by our
competitors, oil and natural gas prices, conditions in the debt and equity
markets, the timely receipt of necessary third party and governmental approvals
and other factors.

Our plans and objectives for the year are discussed more fully in our
Current Report on Form 8-K dated September 23, 2003.

SIGNIFICANT ACCOUNTING POLICIES

Our accounting policies are consistent with those discussed in our Current
Report on Form 8-K dated September 23, 2003, except as follows:

Accounting for Asset Retirement Obligations. On January 1, 2003, we
adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting
for Asset Retirement Obligations. SFAS No. 143 requires that we record a
liability for retirement and removal costs of long-lived assets used in our
business. This liability is recorded at its estimated fair value, with a
corresponding increase to property, plant and equipment. This increase in
property, plant and equipment is then depreciated over the remaining useful life
of

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the long-lived asset to which that liability relates. An ongoing expense is also
recognized for changes in the value of the liability as a result of the passage
of time, which we also record in depreciation, depletion and amortization
expense in our income statement. In the first quarter of 2003, we recorded a
charge as a cumulative effect of accounting change of approximately $22 million,
net of income taxes, related to our adoption of SFAS No. 143. We also recorded
property, plant and equipment of $188 million and asset retirement obligations
of $222 million as of January 1, 2003. Our asset retirement obligations are
associated with our natural gas and oil wells and related infrastructure in our
Production segment and our natural gas storage wells in our Pipelines segment.
We have obligations to plug wells when production on those wells is exhausted,
and we abandon them. We currently forecast that these obligations will be met at
various times, generally over the next 10 years, based on the expected
productive lives of the wells and the estimated timing of plugging and
abandoning those wells. The net asset retirement liability as of January 1, 2003
and September 30, 2003, reported in other current and non-current liabilities in
our balance sheet, and the changes in the net liability for the nine months
ended September 30, 2003, were as follows (in millions):

Liability at January 1, 2003................................ $222
Liabilities settled in 2003................................. (44)
Accretion expense in 2003................................... 13
Liabilities incurred in 2003................................ 1
Changes in estimate......................................... 8
----
Net liability at September 30, 2003.................... $200
====

Our changes in estimate represent changes to the expected amount and timing
of payments to settle our asset retirement obligations. These changes primarily
result from obtaining new information about the timing of our obligations to
plug our natural gas and oil wells and the costs to do so. Had we adopted SFAS
No. 143 as of January 1, 2002, our current and non-current retirement
liabilities on that date would have been approximately $200 million and our
income from continuing operations and net income for the quarter and nine months
ended September 30, 2002, would have been lower by $3 million and $10 million.
Basic and diluted earnings per share for the quarter and nine months ended
September 30, 2002, would not have been materially affected.

Accounting for Costs Associated with Exit or Disposal Activities. On
January 1, 2003, we adopted SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. SFAS No. 146 requires that we recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. We applied the provisions of SFAS
No. 146 in accounting for restructuring costs we incurred during 2003 (see Note
5). As we continue to evaluate our business activities and seek additional cost
savings, we expect to incur additional charges that will be evaluated under this
accounting standard.

Amendment of Statement 133 on Derivative Instruments and Hedging
Activities. In April 2003, the Financial Accounting Standards Board (FASB)
issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities. This statement amends SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities to incorporate several
interpretations of the Derivatives Implementation Group (DIG), and also makes
several modifications to the definition of a derivative as it was defined in
SFAS No. 133. SFAS No. 149 affects contracts entered into or modified after June
30, 2003. There was no initial financial statement impact of adopting this
standard, although the FASB and DIG continue to deliberate on the application of
the standard to certain derivative contracts, such as power capacity contracts,
which may impact our financial statements in the future.

Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity. In May 2003, the FASB issued SFAS No. 150, Accounting
for Certain Financial Instruments with Characteristics of both Liabilities and
Equity. This statement provides guidance on the classification of financial
instruments as equity, as liabilities, or as both liabilities and equity. In
particular, the standard requires that we classify all mandatorily redeemable
securities as liabilities in the balance sheet. We adopted the provisions of
SFAS No. 150 on July 1, 2003, and reclassified $625 million of our Capital Trust
I and

8

Coastal Finance I preferred interests from preferred interests of consolidated
subsidiaries to long-term financing obligations in our balance sheet. We also
began classifying dividends accrued on these preferred interests as interest and
debt expense in our income statement after July 1, 2003. For the quarter and
nine months ended September 30, 2003, total dividends were $10 million and $30
million. The third quarter of 2003 dividends of $10 million were recorded in
interest expense in our income statement. The first and second quarter of 2003
dividends of $20 million were recorded as distributions on preferred interests
in our income statement.

Goodwill. Our goodwill as of December 31, 2002 and September 30, 2003, and
the changes in goodwill for the nine months ended September 30, 2003, were as
follows (in millions):

During 2003, we impaired $163 million of goodwill related to our
telecommunications business in our corporate segment and disposed of $42 million
in goodwill primarily related to the sale of our financial services businesses
in our Merchant Energy segment.

Accounting for Guarantees. On January 1, 2003, we adopted Financial
Accounting Standards Board Interpretation (FIN) No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. FIN No. 45 requires that we record a liability for all
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at fair value when they are issued. There was no
initial financial statement impact of adopting this standard.

Stock-Based Compensation. We account for our stock-based compensation
plans using 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 SFAS No. 123, Accounting for
Stock-Based Compensation, rather than APB No. 25, the income and per share
impacts of stock-based compensation on our financial statements would have been
different. The following tables show the impact on net income (loss) and
earnings (losses) per share had we applied SFAS No. 123:

Accounting for Regulated Operations. Our interstate natural gas pipelines
and storage operations are subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and
Natural Gas Policy Act of 1978. Of our regulated pipelines, four follow the

9

regulatory accounting principles prescribed under SFAS No. 71, Accounting for
the Effects of Certain Types of Regulation, while three discontinued its
application in 1996. As a result of recent changes in our competitive
environment and operating cost structures, we continue to assess the
applicability of the provisions of SFAS No. 71 to our financial statements. The
outcome of this evaluation could result in the restoration of our application of
this accounting in some of our regulated systems or the discontinuance of this
accounting in others. We expect to complete our current evaluation of the
applicability of SFAS No. 71 by the end of the year. For a discussion of
differences in accounting for regulated operations, see our Current Report on
Form 8-K dated September 23, 2003.

3. ACQUISITIONS AND CONSOLIDATIONS

Acquisitions

During the second quarter of 2003, we acquired and began consolidating the
third party interests in our Chaparral and Gemstone investments, which we
historically accounted for as investments in unconsolidated affiliates. Each of
these acquisitions is discussed below.

Chaparral. As discussed more completely in our Current Report on Form 8-K
dated September 23, 2003, we entered into our Chaparral investment in 1999 to
expand our domestic power generation business. Chaparral owns or has interests
in 34 power plants in the United States that have a total generating capacity of
3,470 megawatts (based on Chaparral's interest in the plants). These plants are
primarily concentrated in the Northeast and Western United States. Chaparral
also owns several companies that own long-term derivative power agreements.

As of December 31, 2002, we owned 20 percent of Chaparral, and the
remaining 80 percent was owned by Limestone Electron Trust (Limestone). We
acquired Limestone's 80 percent interest in Chaparral during 2003 in two
transactions. First, in March 2003, we acquired an additional 70 percent
economic interest in Chaparral when we invested $1 billion in Limestone.
Limestone used these proceeds to retire notes that were previously guaranteed by
us. Although we increased our economic interest in Chaparral with this
investment in Limestone, we did not obtain any additional voting rights in
Limestone or Chaparral so we continued to account for our investment in
Chaparral using the equity method of accounting. In May 2003, we paid $175
million to acquire the remaining third party interest in Limestone, and all of
Limestone's and Chaparral's remaining voting rights. Upon this acquisition, we
began consolidating Chaparral's assets and liabilities. In addition, since we
acquired Chaparral in multiple 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 net income for the previously reported 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 (expense) by $2 million. Had we acquired Chaparral
effective January 1, 2002, the net increases (decreases) to our income statement
for the periods ended September 30, 2002, would have been as follows:

The $175 million we paid to acquire the remaining 10 percent interest in
Limestone along with the remaining voting rights of Limestone and Chaparral, was
negotiated based, in large part, on the terms of the original Chaparral
agreements. Under those terms, we had the option to either provide for a payment
to the third party equity holder in exchange for their remaining interests, or
allow the third party equity holders to liquidate the assets of Chaparral, the
proceeds of which would first be applied to the payment of the agreed

10

amount to them. If we had elected to allow the third party equity holders to
exercise their liquidation rights, Limestone would have controlled the
liquidation process and would not necessarily have been motivated to achieve the
maximum value for the assets. In order to protect our interests, maximize the
recoverable value of the assets and obtain the flexibility to manage the assets
of Chaparral, regardless of whether these assets were to be ultimately sold or
held and used in our ongoing business, we chose to redeem the third party equity
holder's interests for the agreed upon amount.

During the first quarter of 2003, as a result of our additional investment
in Limestone, coupled with a number of developments including a general decline
in power prices, declines in our own 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 evaluated
whether the carrying value of our investment in Chaparral was less than its fair
value. We also evaluated whether any declines that resulted from our analysis
would be considered temporary (expected to turn around within the next nine to
twelve months). Based on our analysis, 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 our
investment in Chaparral of $207 million, before income taxes, during the quarter
ended March 31, 2003.

The following table presents our initial allocation of the purchase price
of Chaparral to its assets and liabilities prior to its consolidation and prior
to the elimination of intercompany transactions. This allocation reflects the
allocation of (i) our purchase price of $1,175 million; (ii) the carrying value
of our initial investment of $252 million; and (iii) our first quarter 2003
impairment of $207 million (in millions):

Total assets
Current assets............................................ $ 312
Assets from price risk management activities, current..... 190
Investments in unconsolidated affiliates.................. 1,347
Property, plant and equipment, net........................ 561
Assets from price risk management activities,
non-current............................................ 1,085
Other assets.............................................. 451
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Total assets......................................... 3,946
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Total liabilities
Current liabilities....................................... 906
Liabilities from price risk management activities,
current................................................ 19
Long-term debt, less current maturities................... 1,415(1)
Liabilities from price risk management activities,
non-current............................................ 34
Other liabilities......................................... 352
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Total liabilities.................................... 2,726
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Net assets.................................................. $ 1,220
=======

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(1) This debt is recourse only to the project, contract or plant to which it
relates.

Our initial allocation of the purchase price was based on preliminary
valuations performed by an independent third party consultant. These preliminary
valuations were derived using discounted cash flow analysis and other valuation
methods. In addition, as part of our asset sale program, we are in the process
of obtaining bids from potential buyers for some of the assets we acquired. We
expect to finalize our purchase price allocation once we receive the final
valuation report from our consultant and have evaluated the bids we have
received. We believe we will complete our purchase price allocation by the end
of 2003.

Gemstone. As discussed more completely in our Current Report on Form 8-K
dated September 23, 2003, we entered into the Gemstone investment in 2001 to
finance five major power plants in Brazil. Gemstone had investments in three
power projects (Macae, Porto Velho and Araucaria) that had a total generating
capacity of 1,788 megawatts (based on Gemstone's interest in the plants).
Gemstone also

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owned a preferred interest in two of our consolidated power projects, Rio Negro
and Manaus. In January 2003, the third party equity investor in Gemstone,
Rabobank, notified us that it planned to remove us as the manager of Gemstone.
Instead of being removed, we elected to buy Rabobank's interest in Gemstone for
approximately $50 million in April 2003. Gemstone's results of operations have
been included in our consolidated financial statements since April 1, 2003.
Although our net income and basic and diluted earnings per share for the nine
months ended September 30, 2003 would not have been affected, our revenues and
operating income would have been higher by $58 million and $41 million had we
acquired Gemstone effective January 1, 2003. Had the acquisition been effective
January 1, 2002, our net income and our basic and diluted earnings per share
would have been unaffected, but our revenues and operating income would have
been higher by $56 million and $38 million for the quarter ended September 30,
2002, and $123 million and $90 million for the nine months ended September 30,
2002.

Our initial allocation of the $50 million purchase price to the assets
acquired and liabilities assumed upon our consolidation of Gemstone in April
2003 was as follows (in millions):

Fair value of assets acquired
Note and interest receivable.............................. $ 122
Investments in unconsolidated affiliates.................. 892
Other assets.............................................. 3
------
Total assets........................................... 1,017
------

Fair value of liabilities assumed
Note and interest payable................................. 967
------
Total liabilities...................................... 967
------
Net assets acquired......................................... $ 50
======

Our initial allocation of the purchase price was based on preliminary
valuations performed by an independent third party consultant. These preliminary
valuations were derived using discounted cash flow analysis and other valuation
methods. We expect to finalize our purchase price allocation once we receive the
final valuation report from our consultant, which we anticipate will be
completed by the end of 2003.

As mentioned above, prior to the acquisition, we recorded our investments
in Chaparral and Gemstone as investments in unconsolidated affiliates. We also
had other balances, including loans and notes with Chaparral and Gemstone, which
were eliminated upon consolidation. As a result, the overall impact on our
consolidated balance sheet from acquiring these investments was different than
the individual assets and liabilities acquired. The overall impact of these
acquisitions on our consolidated balance sheet was an increase in our
consolidated assets of $2.1 billion, an increase in our consolidated liabilities
of approximately $2.4 billion, including an increase in our consolidated debt of
approximately $2.2 billion, and a reduction of our preferred interests in
consolidated subsidiaries of approximately $0.3 billion.

Consolidations

During the second quarter of 2003, we amended several financing and other
agreements in connection with our new $3 billion revolving credit agreement (see
Note 16). These amendments were completed to accomplish several objectives,
including (i) simplifying our capital structure by eliminating several
"off-balance sheet" obligations and replacing them with direct obligations, and
(ii) strengthening the overall collateral package available to our financial
lenders. These amendments are discussed below.

Lakeside. We amended an operating lease agreement at our Lakeside
telecommunications facility to add a guarantee benefiting the party who had
invested in the lessor and to allow the third party and certain lenders to share
in the collateral package that was provided to the banks under our new $3
billion revolving credit facility. This guarantee reduced the investor's risk of
loss of its investment, resulting in our controlling the lessor. As a result, we
consolidated the lessor in the second quarter of 2003. The consolidation of
Lakeside resulted in an increase in our property, plant and equipment of
approximately $275 million and an increase in our long-term debt of
approximately $275 million. Additionally, upon its consolidation, we recorded an
asset

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impairment charge of approximately $127 million representing the difference
between the facility's estimated fair value and the residual value guarantee
under the lease. Prior to its consolidation, this difference was being
periodically expensed as part of operating lease expense over the term of the
lease.

Aruba. We amended an operating lease at our Aruba facility to provide a
full guarantee to the parties who invested in the lessor and to allow the third
party and certain lenders to share in the collateral package that was provided
to the banks under our new $3 billion revolving credit facility. This guarantee
reduced the investor's risk of loss of its investment, resulting in our
controlling the lessor. As a result, we consolidated the lessor during the
second quarter of 2003, increasing our total property, plant and equipment by
$370 million (prior to an impairment charge we recorded on these assets of $50
million) and increasing our long-term debt by $370 million. As a result of our
intent to exit substantially all of our petroleum markets operations, these
leased assets and associated debt were reclassified as discontinued operations.

Clydesdale. In 2003, we modified our Clydesdale financing arrangement to
convert a third party investor's (Mustang Investors, L.L.C.) preferred ownership
interest in one of our consolidated subsidiaries into a term loan that matures
in equal quarterly installments through 2005. We also acquired a $10 million
preferred interest in Mustang and guaranteed all of Mustang's equity holder's
obligations. As a result, we were required to consolidate Mustang in the second
quarter of 2003 which increased our long-term debt by $743 million and decreased
our preferred interests of consolidated subsidiaries by $753 million. The $10
million preferred interest we acquired in Mustang was eliminated upon its
consolidation (see Notes 16 and 17).

4. DIVESTITURES

During 2003, we completed or announced the sale of a number of assets and
investments in each of our business segments. The gains and losses on these
sales and any asset impairments recorded on these assets, investments and
operations are discussed in Notes 8, 11 and 21.

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(1)Excludes $18 million of costs incurred in preparing assets for disposal,
returns of invested capital and cash transferred with assets sold.

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(1) Amounts on sales that have been announced or are under contract for sale are
estimates, subject to customary regulatory approvals, final sale
negotiations and other conditions.

(2) These sales were completed in October 2003.

(3) This sale was completed in October 2003 and $70 million of the proceeds were
withheld pending the resolution of regulatory matters discussed further in
Note 18.

(4) We have entered into a non-binding letter of intent to sell these assets.

Each period, we evaluate our potential asset sales to determine if any meet
the criteria as held for sale or as discontinued operations under SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. To the extent
that all of the criteria of SFAS No. 144 are met, we classify an asset as held
for sale or, if appropriate, discontinued operations. For example, our Board of
Directors (or a designated subcommittee of our Board) is required to approve
asset dispositions greater than specified thresholds. Unless specific approval
is received by our Board (or a designated subcommittee) by the end of a given
reporting period to commit to a plan to sell an asset, we would not classify it
as held for sale or discontinued operations in that reporting period even if it
is management's stated intent to sell the asset. As of December 31, 2002, we had
$31 million of long-lived assets classified as held for sale and reflected in
current assets in our balance sheet, all of which had been sold as of September
30, 2003. As of September 30, 2003, we had $111 million of long-lived assets
classified as held for sale and reflected in current assets in our balance
sheet. We also had approximately $1.6 billion of assets classified as
discontinued operations as of September 30, 2003 (see Note 11).

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We continue to evaluate assets we may sell in the future, and have
announced that we intend to pursue the divestiture of our telecommunications
business and domestic power assets. These activities are ongoing, and we have
not entered into any definitive agreements. Furthermore, we are not certain what
form these possible divestitures may take (e.g. outright sale or joint venture
arrangement). As specific assets are identified for divestiture, we will be
required to record them at the lower of fair value or historical cost. This may
require us to assess them for possible impairment. The amounts of these
impairment charges, if any, will generally be based on estimates of the expected
fair value of the assets as determined by market data obtained through the
divestiture process or by assessing the probability-weighted cash flows of the
asset. For a discussion of impairment charges incurred on our long-lived assets,
see Note 8; for impairments on discontinued operations, see Note 11; and for
impairments on our investments in unconsolidated affiliates, see Note 21.

As of September 30, 2002, we had completed the following asset sales:

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(1)Net proceeds from this sale were approximately $556 million in cash, common
units of GulfTerra with a fair value of $6 million and the partnership's
interest in the Prince tension leg platform including its nine percent
overriding royalty interest in the Prince production field with a combined
fair value of $190 million.

(2)Excludes $105 million of costs incurred in preparing assets for disposal,
returns of invested capital and cash transferred with the assets sold.

5. RESTRUCTURING CHARGES

For the quarter and nine months ended September 30, 2003, we recognized
restructuring costs totaling $14 million and $114 million. These costs were
incurred as part of our ongoing liquidity enhancement and cost reduction
efforts. Of this amount, $10 million and $66 million related to employee
severance costs from reductions in our work force, of which approximately $51
million had been paid as of September 30, 2003. Through September 30, 2003, we
had eliminated approximately 2,600 full-time positions, including approximately
1,400 full-time positions related to our discontinued operations. Employee
severance costs included severance payments and costs for pension benefits
settled and curtailed under existing benefit plans. For the quarter and nine
months ended September 30, 2003, we also recorded $1 million and $10 million of
employee severance costs related to our discontinued operations, substantially
all of which had been paid as of September 30, 2003. During the first quarter of
2003, we also recognized charges of approximately $44 million associated with
our liquefied natural gas (LNG) business following our February 2003
announcement to minimize our involvement in that business. This charge related
to amounts paid for canceling our option to charter a fifth ship to transport
LNG from supply areas to domestic and international market centers and to
restructure the remaining charter agreements. We recorded all restructuring
costs as operation and maintenance expense in our income statement, and these
charges impacted the results in all of our business segments.

For the quarter and nine months ended September 30, 2002, we incurred $1
million and $64 million of restructuring charges. During 2002, we completed an
employee restructuring across all of our operating segments which resulted in
the elimination of approximately 808 full-time positions, including those

15

employees related to our discontinued operations. We incurred and paid $23
million of employee severance and termination costs. Employee severance costs
included severance payments and costs for pension benefits settled and curtailed
under existing benefit plans. We also incurred fees of $40 million to eliminate
the stock price and credit rating triggers related to our Gemstone and Chaparral
investments. These restructuring charges were reflected as operation and
maintenance expense in our income statement.

6. WESTERN ENERGY SETTLEMENT

In June 2003, we entered into two definitive agreements (referred to as the
Western Energy Settlement) 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 against us and our
subsidiaries relating to the sale or delivery of natural gas and electricity
from September 1996 to the date of the settlement. Subject to court and
regulatory approvals, the settlement will include payments of cash, the issuance
of common stock and the reduction in prices under a power supply contract.

These definitive settlement agreements modified an agreement in principle
reached on March 20, 2003, as discussed in our Current Report on Form 8-K dated
September 23, 2003, and resulted in an additional obligation and a pretax charge
of $123 million during the second quarter of 2003. The charge was primarily a
result of changes in the timing of settlement payments and changes in the value
of the common stock to be issued in connection with the definitive settlement
agreements. During the third quarter of 2003, we recorded a benefit of
approximately $20 million due to changes in our stock price, resulting in a net
charge for the nine months ended September 30, 2003, of $103 million. This net
charge was in addition to accretion expense on the originally recorded
discounted Western Energy Settlement obligation and other charges included as
part of operation and maintenance expense during 2003. For the quarter and nine
months ended September 30, 2003, these accretion and other charges were
approximately $12 million and $55 million. As of September 30, 2003, $616
million of the total Western Energy Settlement obligation of $1,035 million was
reflected as a current liability. The current portion includes a $193 million
obligation to issue approximately 26.4 million shares of our common stock. The
stock obligation will continue to impact our income statement, either positively
or negatively, based on changes in our stock price until the settling parties
elect to have the shares issued on their behalf. As of September 30, 2003, $10
million of the total obligation had been satisfied. Future payments will be
reflected in our cash flows from operations. In addition, in July 2003, EPNG,
our subsidiary, issued $355 million of senior notes, the net proceeds from which
will be placed in an escrow account (once established) to be used to satisfy a
portion of the overall obligation. For a further discussion of the Western
Energy Settlement, see Note 18.

As further described in Note 18, upon final approval of the settlement
agreements, we will be required to provide collateral for the $45 million per
year, 20-year obligation in the form of natural gas and oil reserves, other
assets to be agreed upon, cash and/or letters of credit. The initial collateral
requirement is estimated to be between $455 million and $592 million depending
on the type of collateral posted.

7. CEILING TEST CHARGES

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

For the quarter and nine months ended September 30, 2003, we recorded a
ceiling test charge of approximately $2 million primarily related to our Turkish
full cost pool. For the nine months ended September 30, 2002, we recorded
ceiling test charges of $267 million, of which $33 million was charged during
the first quarter and $234 million during the second quarter. The 2002 charges
include $226 million for our Canadian full cost pool, $24 million for our
Turkish full cost pool, $10 million for our Brazilian full cost pool and $7
million for Australia and other international production operations. Our ceiling
test charges were based upon the daily posted natural gas and oil prices at the
end of each period, adjusted for oilfield or natural gas

16

gathering hub and wellhead price differences, as appropriate. The 2002 charge
for our Canadian full cost pool primarily resulted from a low daily posted price
for natural gas at the end of the second quarter of 2002.

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

8. GAIN (LOSS) ON LONG-LIVED ASSETS

Our gain (loss) on long-lived assets consists of net realized gains and
losses on sales of long-lived assets and impairments of long-lived assets, and
was as follows:

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(1) These amounts exclude approximately $1.3 billion of asset impairments for
the nine months ended September 30, 2003, related to our petroleum markets
operations that were reclassified as discontinued operations.

Net Realized Gain (Loss)

Our 2003 net realized gains (losses) were primarily related to the sales of
Mohawk River Funding I in our Merchant Energy segment, the north Louisiana and
Mid-Continent midstream assets in our Field Services segment, the Table Rock
sulfur extraction facility in our Pipelines segment, non-full cost pool assets
in our Production segment and the sales of assets in our Corporate segment. Our
2002 net realized gains (losses) were primarily related to the sales of
expansion rights in our Pipelines segment, non-full cost pool assets in our
Production segment and the sale of the Dragon Trail processing plant in our
Field Services segment.

Asset Impairments

We are required to test assets for possible impairment whenever events or
changes in circumstances indicate that the carrying amount of these assets may
not be fully recoverable. One event that triggers this test is the expectation
that it is more likely than not that we will sell or dispose of the asset before
the end of its estimated useful life. Based on our intent to dispose of a number
of our assets, we tested those assets for recoverability during the first nine
months of 2003 and recorded the charges indicated in the table above. Our
corporate telecommunications charge includes an impairment of our investment in
the wholesale metropolitan transport services, primarily in Texas, of $269
million (including a writedown of goodwill of $163 million) 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. Our Merchant Energy charges were primarily a result of our plan
to reduce our involvement in the LNG business and our power assets, including

17

our turbines classified in long-term assets (see Note 15). For additional asset
impairments on our discontinued operations and investments in unconsolidated
affiliates, see Notes 11 and 21.

9. OTHER EXPENSES

Other expenses for the nine months ended September 30, 2003, were $129
million. These amounts include foreign currency losses of $73 million primarily
on our Euro-denominated debt and a $37 million loss on the early extinguishment
of our $1.2 billion bridge loan (see Note 16).

Other expenses for the quarter and nine months ended September 30, 2002,
were $14 million and $277 million. For the nine months ended September 30, 2002,
we incurred foreign currency losses of $45 million resulting from the impact of
foreign currency fluctuations on our Euro-denominated debt, a $56 million
impairment of our investment in the Costanera power plant, a cost-based
investment in Argentina, and a $90 million contract termination fee paid by our
Eagle Point Cogeneration facility (in our global power division of our Merchant
Energy segment) to our Eagle Point refinery (in the petroleum markets division
classified as discontinued operations). This payment was eliminated in
consolidation since the income associated with the petroleum markets division is
reflected in discontinued operations while the power division's expense is
included in Merchant Energy's operating results. Other expenses also included
$55 million of minority interest in our consolidated subsidiaries.

10. INCOME TAXES

Income taxes included in our income (loss) from continuing operations for
the periods ended September 30, 2003 and 2002 were as follows:

For the nine months ended September 30, our effective tax rates were
different than the statutory rate of 35 percent due to the following:

During the quarters and nine months ended September 30, 2003 and 2002, we
experienced a number of events that have impacted our overall effective tax rate
on continuing operations. These events included the treatment of our coal and
petroleum markets operations as discontinued operations (in which income taxes
are apportioned between continuing and discontinued operations) and the
abandonment of several foreign investments. These events, coupled with
relatively low pretax income in continuing operations, have caused, and may
continue to cause, variations in our effective tax rate.

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11. DISCONTINUED OPERATIONS

Petroleum Markets Operations

In June 2003, our Board of Directors authorized the sale of substantially
all of our petroleum markets operations, including our Aruba refinery, our
Unilube blending operations, our domestic and international terminalling
facilities and our petrochemical and chemical plants. The Board's actions were
in addition to previous actions approving the sales of our Eagle Point refinery,
our asphalt business, our Florida terminal, tug and barge business and our lease
crude operations. Based on our intent to dispose of these operations, we were
required to adjust these assets to their estimated fair value. As a result, we
recognized pre-tax charges during the first and second quarters of 2003 totaling
$1,366 million related to our petroleum markets assets, which included $929
million related to our Aruba refinery and $252 million related to the impairment
of our Eagle Point refinery. See Note 3 for a discussion of this lease. These
impairments were based on a comparison of the carrying value of our petroleum
markets assets to their estimated fair value. Our fair value estimates were
based on preliminary market data obtained through the early stages of the sales
process and an analysis of expected discounted cash flows. The magnitude of
these charges was impacted by a number of factors, including the nature of the
assets to be sold, and our established time frame for completing the sales,
among other factors.

19

In the second quarter of 2003, we entered into a product offtake agreement
with Vitol S.A. Inc. (Vitol) for the sale of a number of the products produced
at our Aruba refinery. As a result of this contract, Vitol became the single
largest customer of our Aruba refinery, purchasing approximately 75 percent of
the products produced at that plant. The agreement is for one year with two
one-year extensions at Vitol's option. We have the right to terminate the
agreement when the refinery is sold.

Coal Mining Operations

In the latter part of 2002 and the first quarter of 2003, we sold our coal
mining operations. These operations consisted of fifteen active underground and
two surface mines located in Kentucky, Virginia and West Virginia. Following the
authorization of the sale by our Board of Directors, we recorded impairment
charges of $37 million and $185 million in our loss from discontinued operations
during the third quarter and the nine months ended September 30, 2002.

Our petroleum markets operations and our coal mining operations were
historically included in our Merchant Energy segment, and are classified as
discontinued operations in our financial statements for all of the historical
periods presented. All of the assets and liabilities of the remaining
discontinued businesses are classified as other current assets and liabilities
as of September 30, 2003. The summarized financial results and financial
position data of our discontinued operations were as follows:

12. CUMULATIVE EFFECT OF ACCOUNTING CHANGES

On January 1, 2003, we adopted SFAS No. 143. As a result, we recorded a
cumulative effect of an accounting change of approximately $22 million, net of
income taxes (see Note 2).

21

On January 1, 2002, we adopted SFAS No. 141, Business Combinations, and
SFAS No. 142, Goodwill and Other Intangible Assets. As a result of our adoption
of these standards on January 1, 2002, we stopped amortizing goodwill, and
recognized a pretax and after-tax gain of $154 million related to the write-off
of negative goodwill as a cumulative effect of an accounting change in our
income statement.

In the second quarter of 2002, we also adopted DIG Issue No. C-16, Scope
Exceptions: Applying the Normal Purchases and Sales Exception to Contracts that
Combine a Forward Contract and Purchased Option Contract. One of our
unconsolidated affiliates, the Midland Cogeneration Venture Limited Partnership,
recognized a gain on a fuel supply contract upon adoption of this new rule, and
we recorded a gain of $14 million, net of income taxes, as a cumulative effect
of an accounting change in our income statement for our proportionate share of
this gain.

13. EARNINGS PER SHARE

We calculated basic and diluted earnings per common share amounts as
follows for the periods ended September 30:

For the quarter and nine months ended September 30, 2003, there were a
total of 42 million of potentially dilutive securities excluded from the
determination of average common shares outstanding because we had net losses in
these periods. For the quarter and nine months ended September 30, 2002, a total
of 16 million shares of potentially dilutive securities was excluded based on
our income levels. The excluded securities included

22

stock options, restricted stock, equity security units, shares we are obligated
to issue at the direction of the settling claimants under our Western Energy
Settlement, trust preferred securities and convertible debentures.

14. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of our price risk
management assets and liabilities as of September 30, 2003 and December 31,
2002:

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(1) Trading contracts are derivative contracts that historically have been
entered into for purposes of generating a profit or benefiting from
movements in market prices.

(2) Included in our trading and non-trading contracts at both September 30, 2003
and December 31, 2002 are $165 million and $123 million of intercompany
derivative positions, that eliminate in consolidation, and have no impact on
our consolidated price risk management activities.

(3) Net assets from price risk management activities include current and
non-current assets and current and non-current liabilities from price risk
management activities on the balance sheet.

As of September 30, 2003, other derivatives include $1,957 million of
derivative contracts primarily related to power restructuring activities, $1,010
million of which relates to contracts we acquired in connection with our
acquisition of Chaparral in the second quarter of 2003 and $947 million
associated with our power restructuring activities at our Eagle Point
Cogeneration and our Capitol District Energy Center Cogeneration Associates
facilities. As of December 31, 2002, other derivatives include $968 million of
derivative contracts associated with our power restructuring activities at our
Eagle Point Cogeneration and our Capitol District Energy Center Cogeneration
Associates facilities. For a further discussion of our Chaparral acquisition,
see Note 3, and for a further discussion of our power restructuring activities,
see our Current Report on Form 8-K dated September 23, 2003. The remaining
balances in other derivatives includes unrealized losses of $3 million and $9
million as of September 30, 2003 and December 31, 2002, that relate to
derivative positions that no longer qualify as cash flow hedges under SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities, because they
were designated as hedges of anticipated future production on natural gas and
oil properties that were sold during 2002.

In September 2003, we entered into several cross-currency fair value hedge
transactions which effectively hedged the currency risk on a portion of our
Euro-denominated debt through 2009. Collectively, these transactions swap E250
million of our fixed rate debt for approximately $275 million of floating rate
debt at a weighted average rate of LIBOR plus 3.6%. In October and November
2003, we entered into several additional cross-currency fair value hedge
transactions which effectively hedged the currency risk on a portion of our Euro
denominated debt through 2009. Collectively, these transactions swap E100
million of our fixed rate debt for approximately $115 million of floating rate
debt at a weighted average rate of LIBOR plus 4.11%. Also in October 2003, we
entered into several fair value hedge transactions which effectively converted
the fixed interest rate of 7.875% on $200 million of our debt to a weighted
average rate of LIBOR plus 4.14% through 2012.

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15. INVENTORY

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(1) We recorded these amounts as other non-current assets in our balance sheet.
In September 2003, we negotiated an expected settlement under which we will
transfer our ownership rights and obligations related to $100 million of our
power turbine inventories, resulting in a write-down of $22 million of this
inventory at September 30, 2003.

16. DEBT AND OTHER CREDIT FACILITIES

Our debt and other credit facilities consist of both short and long-term
borrowings and notes with our affiliated companies. During the first nine months
of 2003, we entered into a new $3 billion revolving credit facility, acquired
and consolidated a number of entities with existing debt, refinanced
shorter-term obligations with longer-term borrowings and redeemed and eliminated
preferred interests in our subsidiaries. A summary of our actions is as follows
(in millions):

Debt obligations as of December 31, 2002.................... $18,571
Acquisitions and consolidations:
Clydesdale restructuring.................................. 743
Gemstone acquisition(2)(3)................................ 1,013
Chaparral acquisition(3).................................. 1,565
Bank refinancings:
Lakeside lease............................................ 275
Principal amounts borrowed(4)............................... 4,050
Repayments/retirements of principal(4)...................... (2,989)
Reclassifications of preferred interests as long-term 625
financing obligations.....................................
Elimination of affiliate obligations........................ (326)
Other....................................................... 53
-------
Total debt obligations as of September 30, 2003........... $23,580
=======

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(1) Does not include $370 million of long-term debt related to our Aruba
refinery that is classified as part of our discontinued operations.

(2) This amount includes $75 million related to Macae which was consolidated as
a consequence of our acquisition of Gemstone.

(3) This is a non-recourse project financing or non-recourse debt related to our
power contract restructuring.

(4) Includes $500 million of borrowings and $750 million of repayments under our
revolving credit agreements.

24

As discussed further in Note 17, our Clydesdale and Trinity River
financings were restructured in 2003 resulting in their reclassification from
preferred interests of consolidated subsidiaries to long-term debt. The Trinity
River financing was redeemed with a portion of the proceeds from borrowings in
2003, specifically the $1.2 billion two-year term loan issued in March 2003,
which was then refinanced with the $1.2 billion 10 year loan issued in May 2003.
The Clydesdale financing was converted into a term loan maturing in equal
quarterly installments through 2005. The balance of the term loan was $521
million as of September 30, 2003. In November 2003, we made additional payments
of $107 million on this term loan. Additionally, we reclassified $625 million of
our mandatory redeemable preferred securities of Coastal Finance I and Capital
Trust I as a result of the adoption of SFAS No. 150 (see Notes 2 and 17).

Short-Term Debt and Credit Facilities

At December 31, 2002, our weighted average interest rate on our short-term
credit facilities was 2.69%. We had the following short-term borrowings and
other financing obligations:

Credit Facilities

In April 2003, we entered into a new $3 billion revolving credit facility,
with a $1.5 billion letter of credit sublimit, which matures on June 30, 2005.
Our $3 billion revolving credit facility has a borrowing cost of LIBOR plus 350
basis points, letter of credit fees of 350 basis points and commitment fees of
75 basis points on unused amounts of the facility. This facility replaced our
previous $3 billion revolving credit facility. Approximately $1 billion of our
other financing arrangements (including the leases discussed in Notes 3 and 11,
letters of credit and other facilities) were also amended to conform the
provisions of those obligations to our $3 billion revolving credit facility. The
$3 billion revolving credit facility and those other financing arrangements are
secured by our equity in EPNG, Tennessee Gas Pipeline Company (TGP), ANR
Pipeline Company (ANR), Wyoming Interstate Company Ltd. (WIC), ANR Storage
Company, Southern Gas Storage Company and our Series A and Series C units in
GulfTerra. The $3 billion revolving credit facility and other financing
arrangements are also collateralized by our equity in the companies that own the
assets that collateralize our Clydesdale financing arrangement. For a discussion
of Clydesdale, see Notes 3 and 17.

As of September 30, 2003, there were $1.3 billion of borrowings outstanding
and $1.0 billion of letters of credit issued under the $3 billion revolving
credit facility, all of which was borrowed by or issued on behalf of us. Amounts
outstanding under the $3 billion revolving credit facility as of September 30,
2003, were classified as non-current in our balance sheet, based on the maturity
date which is June 30, 2005. Subsequent to September 30, 2003, we repaid an
additional $400 million under our revolving credit facility. In addition, in
October 2003, we liquidated a portion of the collateral that supports the
revolver and related financing arrangements. The proceeds from the liquidation
will be used to reduce commitments and repay amounts outstanding under the $3
billion revolving credit facility and related financing arrangements. As a
result, there will be a $17 million reduction of the borrowing availability
under our $3 billion revolving credit facility.

We also maintained a $1 billion revolving credit facility, which expired on
August 4, 2003. EPNG and TGP were also borrowers under this facility.

The availability of borrowings under our $3 billion revolving credit
facilities and other borrowing agreements is subject to conditions, which we
currently meet. These conditions i