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                            El Paso Corporation
                          Moderator: Bruce Connery
                               March 31, 2003
                               10:00 a.m. EST

OPERATOR: Good morning, ladies and gentlemen. Welcome to the El Paso
Corporation fourth quarter 2002 earnings conference call. At this time, all
participants have been placed on a listen-only mode and the floor will be
open for questions and comments following the presentation. It is now my
pleasure to turn the floor over to your host, Mr. Bruce Connery. Sir, you
may begin.

BRUCE CONNERY, EL PASO CORPORATION: Thank you. Good morning and we
appreciate you joining our call.

In just a moment, I will turn the call over to Ron Kuehn, our chairman and
chief executive officer.

I need to make you aware that later on this morning, we will be filing our
10-K. You can access that 10-K either through the SEC website or through
our own website, which is elpaso.com in the "for investors" section.

Before we begin the call, we need to make aware you that we will make
forward-looking statements and projections made in reliance with the Safe
Harbor provisions of the Private Securities Litigation Reform Act of 1995.
The company has made every reasonable effort to ensure that the information
and assumptions on which these statements and projections are based are
current, reasonable and complete.

However, a variety of factors could cause actual results to differ
materially from the projections, anticipated results or other expectations
expressed in this call, including without limitation our ability to attract
and retain qualified members of the board of directors; the successful
recruitment and retention of a qualified CEO; the successful implementation
of 2003 operational and financial plans; the successful implementation of
the settlement related to the Western Energy crisis; and material and
adverse impacts from our proxy contest with Celene Zilca (ph); actions by
the credit rating agencies; the successful close of financing transactions,
including the extension of our bank facilities; our ability to successfully
exit the energy trading business; our ability to divest of certain non-core
assets; changes in commodity prices for oil, natural gas and power; general
economic and weather conditions in geographic regions or markets served by
El Paso Corporation and its affiliates, or where operations of the company
and its affiliates are located; the uncertainties associated with
governmental regulation; political and currency risk associated with
international operations of the company and its affiliates; inability to
realize anticipated synergies and cost savings associated with
restructurings and divestitures on a timely basis; difficulty in
integration in the operations of the previously acquired companies,
competition and other factors described in the company's and its
affiliates' SEC filings.

While the company makes these statements and projections in good faith,
neither the company nor its management can guarantee that anticipated
future results will be achieved. Reference must be made to those filings
for additional important factors that may affect actual results. The
company assumes no obligation to publicly update or revise any
forward-looking statements made herein or any other forward-looking
statements made by the company, whether as a result of new information,
future events or otherwise.

In this call, we will include certain financial information that's
calculated and presented on the basis of methodologies other than in
accordance with generally accepted accounting principles, GAAP. A
presentation of the most directly comparable financial measures calculated
and presented in accordance with GAAP and a reconciliation of the
differences between each non-GAAP financial measure used in this
presentation with the most comparable financial measure calculated and
presented in accordance with GAAP is provided on our website,

Prior to its 2003 annual meeting, El Paso will furnish to its shareholders
El Paso's definitive proxy statement relating to this meeting together with
a white proxy card. Shareholders are strongly advised to read this proxy
statement when it becomes available, as it will contain important
information. Shareholders will be able to obtain El Paso's proxy statement,
any amendments or supplements to the proxy statement and any other
documents filed by El Paso with the Securities and Exchange Commission or
free at the Internet website maintained by the SEC at www.sec.gov. Copies
of the proxy statement and any amendments and supplements to the proxy
statement will also be available for free at El Paso's Internet website at
www.elpaso.com, or by writing to El Paso Corporation Investor Relations,
P.O. Box 2511, Houston, Texas, 77252. In addition, copies of proxy
materials may be requested by contacting our proxy solicitors, McKenzie
(ph) Partners, Inc., at 800-322-2885 toll free, or by e-mail at

To the extent that individual customers, independent industry researchers,
financial analysts or El Paso commissioned research are quoted herein, it
is El Paso's policy to use reasonable efforts to verify the source and
accuracy of the quote. El Paso has not, however, sought or obtained the
consent of the quoted source to use such quote as proxy soliciting
material. This document may contain expressions of opinion and belief -
except as otherwise expressly attributed to another individual or entity,
these opinions and beliefs are the opinions and beliefs of El Paso.

Information regarding the names, affiliation and interest of individuals
who may be deemed participants in the solicitation of proxies of El Paso
shareholders is contained in schedule 14A filed by El Paso with the SEC on
February 18th, 2003 as amended by schedule 14A filed by El Paso on March
18th of 2003.

I'll turn the call over to Ron Kuehn.

you all for joining us.

In addition to Bruce, with me here today are others from our management
team including Brent Austin, president and chief operating officer, Dwight
Scott, our CFO, Rod Erskine, president of El Paso's production company, and
John Somerhalder (ph), president of El Paso's pipeline group.

In this morning's call, we will review 2002 results, and it is an
understatement to say that 2002 was a challenging year for El Paso. Some of
what has affected us can be blamed on an industry in turmoil, tougher
credit standards and other factors. However, some of our problems,
particularly our leverage, are the result of bad investment decisions. Yet
I believe today El Paso is meeting its challenges head on.

During 2002, we faced a variety of issues that ran the gamut. Our merchant
businesses experienced difficult conditions and we saw lower earnings as a
result. El Paso's credit ratings were downgraded below investment grade,
which resulted in about 1.7 billion of new liquidity demands. At the same
time, our ability to access the capital markets was limited. As a result,
we found ourselves in a position where we needed to sell assets in order to
meet our liquidity needs and pay off debt and other obligations.

The reason that we have been able to meet these challenges is that El Paso
has a world class asset base. With pooling restrictions associated with the
coastal merger behind us, we sold almost 4 billion of non-core assets in
2002. In February, we announced our five-point operational and financial
plan which was designed to move even more aggressively to restore value to
El Paso and we are making steady progress on that plan.

We have focused clearly on preserving and enhancing the value of our core
businesses - pipeline, production, midstream and non-merchant power. Our
pipeline and production businesses will spend about 87 percent of this
year's capital program, and John or Rod will give you an you update on how
their businesses are performing later on today.

We continue to divest our non-core businesses quickly and prudently. We
have signed agreements for or closed more than 50 percent or 1.7 billion of
the targeted 3.4 billion of asset sales that we expect for this year. We
intend to have more than 80 percent of this program completed or announced
by the end of the second quarter of this year. We sold our European gas
book, and as we said before, we will be exiting trading all together. We
anticipate that this will help us recover significantly larger amounts of
our cash collateral over time. These asset sales also have helped with our
goal of strengthening and simplifying the balance sheet, while maximizing
our liquidity.

As Dwight will go through with you in a moment, our liquidity is strong.

As of March 28th, we had 1.5 billion in cash on hand. Recently, we also
closed a 1.2 billion two-year secured loan that was used in part to retire
our Trinity (ph) River financing. We completed bond offerings by Southern
Natural Gas and ANR Pipeline for a total of 700 million, and we retired 1
billion of notes issued in connection with our Electron power financing.
All of these efforts improved the company's financial flexibility.

We are also addressing our costs. Costs have in large measure been at a
level associated with a company that was engaged in a myriad of activities
that we won't be associated with going forward. We have to bring our costs
in line with what we are going to be, not what we were. Last year, we
reduced annual expenses by 300 million. We have a plan in place to achieve
additional cost savings this year of at least 150 million. In addition, we
are undertaking a top-to-bottom analysis of the company to achieve further
cost reductions and emerge with the most effective cost structure possible
for our businesses.

The last part of our plan deals with regulatory and litigation matters. We
announced on March 20th that the company reached a comprehensive agreement
in principal to resolve the principal litigation and claims related to the
Western Energy crisis. We structured this settlement in a manner that will
minimize current demands on our liquidity. The after-tax charge for the
settlement is approximately $650 million, which was taken in the fourth
quarter of 2002. You will see this charge when Dwight goes through the
non-recurring items for the quarter.

We are also pleased that the FERC staff's comprehensive report on the
California energy crisis released last week did not open up any new issues
for El Paso. Although most energy companies are dealing with new show-cause
(ph) orders associated with the so-called gaming of the markets, El Paso
was conspicuously absent from the list. There is still much work to be
done, and as we look at what we are facing in 2003, there are further
challenges ahead. We have made good progress in reducing our fixed debt
maturities for this year and next. We are working hard on renegotiating all
of our credit facilities and believe that upon completion of these
discussions, we will reduce our debt further.

We have a debt-reduction plan in place, and we will keep you posted on the
progress on that.

Our commitment to our core businesses drives many of our decisions. We want
to make sure we are enhancing the value of these core businesses at every
opportunity. And as you know, the board is actively engaged in a search for
a permanent CEO. In the meantime, I am working hard every day with this
management team to see that El Paso's plans are executed. When we find a
new CEO, I will help to make that transition seamless and efficient.

While we still face challenges, we continue to make the right decisions and
take the right actions to ensure that we will return value to this company.

Now I'll turn it over to Dwight Scott, who will go through a financial
review of the fourth quarter and year-end earnings with you - Dwight?

Hello, everyone.

The fourth quarter of last year was an especially difficult one for the
company and its financial position. In my presentation, I'll review with
you the impact on the company of the credit downgrades in November, our
decision to exit trading and the related weakness in that part of our
business and the impairments of a number of assets that were originally
pursued in very different times.

Our company's financial position showed significant resilience during this
period, which you'll also see in parts of my discussion. I believe that El
Paso is dealing with the issues before us and that we have made tremendous
progress. However, we must rebuild investor confidence and trust, reduce
leverage and provide for the core earning strength of the company to be
realized. To address the first issue, we have attempted to provide detail
and explanation of our business and financial position in our 10-K filed

Throughout my discussion, I'll reference the section of the 10-K where more
information and explanation on the year can be found. In the 10-K, you will
find an index that should help you to review items of particular interest
in the footnotes. As we move through the year, we will continue to
communicate with the investment community to provide further clarity
regarding our plans to reduce leverage and improve earnings power.

I am speaking from a series of slides as opposed to the other speakers
today, so I would direct you to slide titled page 5, which is titled
summary income statement. As shown here, we will report a loss in the
fourth quarter of 2002 of $2.92 per share or approximately 1.7 billion and
a loss for the full year of 2002 of $2.62 per share or 1.5 billion. This
page reconciles from these losses to a pro forma loss in the fourth quarter
of 69 cents per share or 407 million, and pro forma earnings of 64 cents
per share or 361 million for the full year.

For the full year, the greatest non-recurring impact on our earnings came
from restructuring costs, asset impairments and loss on sale of assets of
$1.69 per share or approximately 950 million after tax. Offsetting these
charges were net gains from the sale of assets of 32 cents a share, or
approximately 180 million after tax.

I will address the fourth quarter charges in more detail in a later slide,
and more detail on all of this can be found in our 10-K, especially in
footnote four, restructuring and merger-related costs, and footnote five,
net gain loss on long-life assets.

In addition, the financial impact of the Western Energy settlement was
recognized in 2002 and resulted in a loss of $1.16 per share or
approximately 650 million after tax. Footnote two in our 10-K titled
"Western Energy settlement" provides more detail on this settlement and we
recently held a conference call to discuss the transaction. While the
settlement had a significant impact on our earnings in 2002, we believe
that it will resolve an important source of uncertainty surrounding the
company and will improve our capability to achieve financial and other
goals in 2003 and beyond.

The accounting changes shown on this page primarily reflect the
implementation of EITF-023 in the fourth quarter of 2002 and FAS 141-142 in
the first quarter of 2002. EITF-023 required energy trading companies to
mark to market only those financial instruments that qualify as derivatives
under FAS 133. I will discuss the impact of this change on a slide later.

FAS 141-142 addressed the treatment of goodwill and the implementation of
these guidelines and the first quarter of 2002 resulted in a gain for the
company. Our 10-K has several areas where more detail is available,
including footnote one, summary of significant events and accounting
policies, and footnote six, accounting changes. These charges, when
combined with the - all these charges when combined with the fourth quarter
decrease in fair market value of the trading book, which was 444 million
after tax, are consistent with the company's guidance of February 5th,

You've heard us discuss the ceiling test charges and the impairment of our
coal business in previous quarters. The currency lost on our
Euro-denominated financing is a good example of the impact of the reduction
of credit available to the company in 2002, as we were unable to hedge that
exposure effectively in the year. We had a further currency loss in the
fourth quarter of 50 million that we included in our interest expense.
Since we no longer expect to hedge this exposure, we treated the cost as

I ask you to turn to the next slide, fourth quarter2002 segment results.
The format that you see on this page is consistent with footnote 24, titled
"segment information" in our 10-K. That footnote is for the full year 2002.
In addition, much of this information is available in more detail in the
10-K under management's discussion and analysis of financial condition.

The pipeline group reported an operating loss for the fourth quarter of 103
million. Excluding the impact of the impairment of the investment in our
Australian pipeline assets and a portion of the costs of the Western Energy
settlement, the pro-forma EBIT of the group would have been 355 million.
This result is consistent with our expectation for the quarter and is
slightly below the fourth quarter of 2001. The production group reported
170 million of operating income in the fourth quarter, which is
approximately equal to its pro-forma EBIT of 178 million.

The fourth quarter was below expectations for production while our average
realized price for natural gas for the quarter was $3.61 in Mcf and was
below market price due to our hedged volumes. In addition, production
volumes were lower, primarily due to asset sales throughout the year in
2002. Depletion expense was also higher in the fourth quarter at $1.42 per

On our last call, Rod discussed the impact of the asset sales process and
reserve revisions on depletion rates. While we expect these higher rates to
continue into the first half of 2003, we believe that our drilling program
will result in lower rates later on in the year. The field services group
reported 177 million of operating income in the fourth quarter. Excluding
the impact of the gains related to asset sales, that's primarily the San
Juan gathering assets, the pro forma EBIT of the group would have been 27

The equity earnings and distributions from El Paso partners were consistent
with our plan, but the operating income from the processing business which
remains wholly owned by El Paso, was negatively impacted by high natural
gas prices. The merchant energy group reported a 1.5 billion operating loss
in the fourth quarter. Excluding the impact of asset impairments and costs
of Western Energy settlement, the pro forma EBIT of the group would have
been a loss of 648 million.

I'll discuss the impairments in some detail later, as well as the
performance of the merchant business as this is obviously a segment with
the most complexity within the company.

Corporate and other reported a 238 million operating loss in the fourth
quarter. Excluding the impact of an impairment of substantially all dark
fiber inventory held by the company, the pro forma EBIT would have been a
loss of 52 million. This loss is primarily attributable to our telecom
business. The business performs as we expected - is continuing to perform
as we expected but we will explore ways to reduce the impact of the ongoing
losses on the company in 2003.

If you'd turn to the next slide, which is titled "review of merchant
results for fourth quarter 2002," much of the information on this slide is
also available in our - in more detail on our 10-K under management
discussion and analysis of financial condition, as well as in some
supplemental disclosure that was attached to the press release today.

The power group reported 161 million operating loss in the fourth quarter.
Excluding the impact of impairments of our turbine inventory, our C.E.
generation, which is an investment we had in the power business that was
sold in the first quarter of this year, our investment in end cap and
certain of our other power assets, the pro forma EBIT of the group would
have been 97 million. Our domestic asset portfolio performed as planned,
though our equity contribution for the fourth quarter from Electron was a
loss compared to earnings in the fourth quarter of last year.

Our international business performed as expected for the quarter. Petroleum
LNG group reported a 75 million operating loss in the fourth quarter.
Excluding the impact of impairments of our investment in an MTBE plant and
several other smaller assets, the pro forma EBIT of the group would have
been 41 million. The fourth quarter was a very difficult market environment
for our Eagle Point and River refineries and for much of our other
petroleum business.

However, our LNG business reported a strong quarter due to the sale of our
Snovic (ph) contract on our co-point (ph) facility in the period. The
trading group reported a 1.2 billion operating loss in the fourth quarter.
Excluding the impact of the cost of the Western Energy settlement, the pro
forma EBIT of the group would have been a loss of 713 million. While the
loss in the fair market value of the trading book is not an adjustment to
pro forma EBIT, it resulted in a loss in the fourth quarter of
approximately 620 million.

In addition, we executed a number of transactions that reduced the size and
risk of our portfolio in the quarter, and these transactions resulted in an
operating loss.

In our 10-K, you will see that the value of our trading book is a $50
million liability at December 31, 2002. This is the result of a loss in the
quarter and the change in the accounting related to EITF-023. As far as I
know, we're the only company in our sector to implement this new rule prior
to 2003. The impact on our book is in three parts - 225 million of
reduction related to the movement of items that were valued on a mark to
market basis to accrual accounting, 118 million of reduction resulting from
the revaluation of our natural gas and storage inventory to historical
cost, and a balance sheet reclassification of our natural gas inventory of
254 million out of our trading book value.

More information on these adjustments can be found in our 10-K under
management's discussion and analysis, and in footnote one, summary of
significant events and accounting policies, and footnote six, accounting

Turn to the next slide, detailed fourth quarter 2002 impairments. I've
reviewed much of the information in this page on my previous discussion.
However, I will point out that more description of these and other charges
for the full year are available in the 10-K under management's discussion
and analysis, and in footnote four, restructuring and merger-related costs
and footnote five, net gain loss on long-life assets.

I've been asked several times recently about the potential for additional
non-recurring charges or impairments in 2003. While it's difficult to
predict when and how much we may take for any impairments or loss on asset
sales in the future, we have tried to provide some insight to the market
through our 10-K. We stated in our February call that we may report an
impairment loss upon consolidation of Electron. Our 10-K provides more
information on this in the management's discussion and analysis section.
But the principal issue is the current value of the assets relative to our
book value and goodwill upon consolidation.

While we have not completed our analysis, we may report a charge of 200
million to 300 million after tax upon consolidation based upon the fair
market value of the assets at the time. In addition, we expect to incur
losses upon the disposition of assets in 2003, and we currently expect
those charges to be in the range of 300 million to 375 million after tax.

Finally, we expect to consolidate our Lakeside telecom facility either upon
completion of our new credit facility or upon implementation of new
accounting rules. We expect that such consolidation will result in an
after-tax charge of between 75 million and 100 million.

Footnote one, summary of significant events and accounting policies in our
10-Kdiscusses this potential charge in greater detail.

Turn to the next page titled "overview of operating cash flow." This
information down on the next several pages is available in more detail in
the 10-K under management's discussion and analysis of financial condition,
and especially in the liquidity and capital resources section. I encourage
you to review that section of the document as we have provided information
on both historical and expected liquidity and cash flow in order to help
investors understand what has been a very important topic for the company.

As you can see, cash flow before working capital and non-working capital
changes was approximately $2 billion for the full year 2002, compared to
approximately 1.6 billion for the first nine months of the year. The fourth
quarter results were approximately 100 million to 150 million below our
expectations prior to the November downgrades. The shortfall is primarily
as a result of operating cash used in the trading book. As we experienced
the downgrade, we reduced the cash at risk in our book in the fourth
quarter in order to reduce potential cash collateral demand and risk
despite the fact that these sales resulted in a use of operating cash.

Working capital and non-working capital changes were approximately $1
billion above the expected amount for the year. These were a direct result
of the cash collateral requirements of the downgrade and the margin
requirements driven by higher natural gas prices. Net cash used in our
investing activities was 1.3 billion for 2002. Our investing activities
consisted primarily of cap-ex and equity investments of 4 billion offset by
cash, asset and equity investment sales of 2.9 billion.

If you turn to the next page on balance sheet, this information is also
available in more detail in the 10-K under management's discussion and
analysis in the liquidity and capital resources section. In addition,
footnote 18, debt and other financing obligations and other credit
facilities, footnote19, preferred interest of consolidated subsidiaries,
and footnote 20, commitments and contingencies, provide details on our
various on balance sheet and off balance sheet obligations.

Our debt increased by approximately $1 billion in the quarter due to the
cash requirements of a downgrade. We funded those cash needs through a
borrowing under our revolving credit facility of 1.5 billion, and that
amount remained outstanding under the 364-day facility. In the quarter, we
repaid approximately 300 million of our preferred interest and funded a
number of obligations under our guarantees. That's measured by our bank
facility. The net impact of those transactions was an increase in our
obligations senior to common stock to 24.9 billion, or 23.4 billion net of
available cash and restricted cash.

The debt-to-capital covenant in our major credit facilities requires that
the company maintain a debt-to-capital ratio of no greater than 70 percent.
This measure is essentially the ratio of total debt plus guarantees for
borrowed money to total capital. At the end of the year, that ratio was
approximately 63 percent. GAAP debt-to-capitalization on December 31 was 61
percent, and if you take total liability senior to common to total
capitalization, that was 72 percent.

We understand the need to reduce debt at the company and are working hard
to that end. We expect to reduce our obligations senior to common stock
throughout 2003 by approximately 2.5 billion and are working hard to exceed
that goal. However, as we simplify our balance sheet and move obligations
from the guarantee and preferred interest line to the debt line, we will
see an overall increase in reported debt to equity and preferred interest.

For instance, we recently paid $1 billion on the Electron maturity. The
impact on our balance sheet will be a $1 billion increase in debt since we
funded it with borrowings offset by a $1 billion reduction in our guarantee

If you turn to the next page which is an update on our liquidity, the chart
here shows the liquidity of the company over the last quarter has remained
relatively consistent. I will discuss the changes in our liquidity on the
next page, but would like to address our bank facilities here since they're
a big component of our liquidity.

We're working hard with the banks to create a new facility that will extend
our 364-day facility beyond its current 2004 maturity. We expect to be
successful in this process, but have the capability to draw the 1.5 billion
balance of the existing facility and make repayment in May 2004 if we are
unable to extend the maturity for whatever reason. It is unlikely that we
will extend any of our other bank facilities in this process as we
currently do not expect to need capacity beyond the facility's original

Next page is a reconciliation from January 31st, which is the last time we
gave an update on our liquidity. The first quarter has been an eventful one
for the company's liquidity position. We've been successful in increasing
our liquidity despite the further downgrades from the rating agencies in
the quarter, a period of unusual volatility in commodity prices, and over
1.25 billion of debt, preferred interest and guaranteed maturities.

Our business performed as expected. The core businesses, particularly
pipelines and production, benefited from a strong natural gas price
environment. We did not exceed our downgrade requirements of 2.2 billion,
of which 1. 8 billion had been paid at January 31, 2003, and our cash
demand due to gas price movement was consistent with our expectations and
that cash margin has been returned as gas prices have fallen.

We also completed a number of financings in the period - Ron discussed
those. All of these items demonstrate the strength of the assets of this
company. Since January 31, 2003, we have raised 2.3 billion of net proceeds
from financings and borrowings under our $1 billion credit facility. We
have received approximately 1.2 billion of cash from the sale of assets,
our cash flow from operations has been approximately equal to our cap-ex,
and we've used approximately 300 million of working capital. This results
in an available cash balance of 1.5 billion on March 28th, 2003.

Our 2003 sources and uses of cash which is the next slide, this information
is available in our10-K under management's discussion and analysis of
financial condition in the liquidity and capital resources section. This
chart is from our 10-K and reflects the impact of the activities taken by
the company in 2002 and in the first quarter of 2003 to provide liquidity
and reduced fixed debt obligations over the next several years.

The cash flow from operations is consistent with that we showed in February
and has been adjusted for the increased asset sales target, which is
principally the mid continent production assets. We've been asked a number
of times if we could reduce the amount of time that it would require to
recover the margins in the trading book. While we are working diligently to
do that, we do not currently have transactions in place that allow for us
to include a significant amount of that cash in our 2003 forecast.

The debt issuance assumed in this plan includes the 1.9 billion in the
first quarter of 2003, as well as a planned capital markets transaction to
repay the 1.2 billion term loan that we issued in the first quarter. This
transaction will enable us to reduce further our maturity demands over the
next several years.

Other financing activities here include some project financings on our
Brazilian operations, 67 million of which was completed in the first

We have discussed asset sales at length and have more information on
historical sales activity in our 10-K under footnote three titled mergers
and divestitures.

I'll discuss the debt and other repayment assumptions in greater detail on
the next page.

Capital expenditures remain in the 2.5 to 2.6 billion range in 2003. We are
reviewing all of our plans carefully in order to reduce these capital
expenditures, the minimum amount required to meet our plan. As we complete
this analysis, we will provide more detail to investors.

If you turn to the debt and other maturities slide, this information is
available also in more detail on the 10-K under management's discussion and
analysis, and footnotes 18, 19 and 20.

As can you see from the chart, capital markets debt maturities are
relatively small over the next several years. As debt maturities - matures
in our pipeline, we expect to refinance that debt at the individual
pipelines. Otherwise, we expect to meet these maturities from cash on hand
and internally generate cash flow.

Our bank facilities and our 1.2 billion term loan are our largest
maturities in 2003 and 2004. We expect to repay our $1 billion multi-year
facility upon its maturity in August of this year. I spoke earlier
regarding our plans on the $1.2 billion term loan and the $3 billion bank
facility. Our success in extending this maturity would provide greater
flexibility in 2004. In addition, we expect to formalize the maturity
schedule of our Clydesdale financing as part of the bank process.

Now I'll turn to 2003 expectations which is titled "2003 outlook update."
In February, we provided an expectation of EBITDA, EBIT, EPS and cash flow
from operations for 2003. While we expect to report approximately
break-even for full year 2003 on a GAAP basis, our current plans remain
consistent with the $1 per share of pro forma earnings that we discussed at
that time. This current plan reflects the lower production rate in our
production group due to the sale of the mid-continent assets in the first
quarter, and due to a decision to shift planned capital from the second
quarter to later quarters in the year. It also reflects the actual
production for the first quarter and the actual prices received for the
first four months of the year in our production group.

Other changes include higher cost of debt due to the recent downgrades and
the costs of the Western Energy settlement.

Finally, we have assumed a higher loss in trading as we will continue to
manage that business for cash as opposed to earnings.

As I discussed earlier, we expect to have a number of charges in the year
and we have attempted to reflect the range of those charges in this

Finally, we expect that the first quarter results will be consistent with
our plan. Early analysis shows a strong quarter from our pipeline,
production and petroleum groups, offset by weaker than expected results
from our trading activities.

And with that, I'll turn it over to John Somerhalder, who is the president
of our pipeline group.

Good morning.

The pipeline group again had good and solid results for the fourth quarter
and full year 2002. The pipeline group did have two large charges in the
fourth quarter of $412 million charge for the Western Energy settlement,
and a $153 million asset impairment charge for the company's pipeline
investment in Australia.

Absent those charges, the fourth quarter pro forma EBIT was $355 million.
That's very close to the 2001 fourth quarter EBIT of 362,even with the sale
of the CIG production properties in July of 2002, and the sale of our
interest and alliance pipeline in November of 2002.

The full-year results for 2002 on a pro forma basis, again absent those
charges I just talked about, was 1380, and that was slightly up from the
2001 pro forma results of 1372. We continue to see very strong pipeline
capacity values and improving capacity values even before this winter, when
we saw strong and high load factors. We had good recontracting results in
markets such as our New England market. Again, with the return to normal
weather, we saw very high load factors into almost all of our markets this
winter. Importantly, our pipelines, because of the hard work of all of our
employees, functioned very well and operated very well with these high load

It's not just this winter and the high load factors. Because over the last
several years, we worked very hard to connect new markets, a lot of those
power plants connect supply, put in strategic interconnects with other
pipelines, we continue to see and expect to continue to see high load
factors, especially with the need to refill storage, which is now at
historically low levels, as most of you know.

With those high load factors, we expect to see continued improvement in
capacity values. Earlier this year, I talked to you all about a number of
our expansion projects. Those included Phase V and Phase VI on Florida gas
transmission; south system I and II and a north system expansion on
Southern Natural Gas; an expansion of our Elba Island facility; expansions
for new power plants on ANR and TGP, including an expansion to serve Rio
Bravo in south Texas off of TGP; an expansion off of ANR in Wisconsin
called West Leg expansion; continued expansions of the CIG system to serve
markets in the front range; as well as a brand new pipeline of 540 million
a day Cheyenne Plains pipeline needed to move Rocky Mountain gas out of
that supply basin to markets. Also, expansions on EP&G as an example of the
bond debt expansion.

All of those projects continue to move forward with very strong support
from our shippers. The fundamentals of the natural gas business as Dwight
talked to you about earlier is very strong, and we expect to see continued
strong performance from the pipeline group.

With that, I'll turn it over to Rod Erskine to talk about production.


I continue to be very pleased with our E&P program, particularly in our
core deep drilling areas. In south Texas, our deep (INAUDIBLE) Vicksburg
development program continues to press well with rigs running in all of our
core fields. We're attempting to expand the trend into the basin to the
east. We are drilling three Wildcats that will confirm our postulation that
the prolific sands we are producing in our development fields are present
and gas bearing, and a new and deeper trend that has previously been
developed by the industry.

Our first well and our May prospect in Brooks County is down in its
production. We will reserve its production for a few weeks before beginning
to drill extension wells. Our Cascobel (ph) prospect about 10 miles east of
Monte Cristo is drilling at 15,000 feet with excellent mud log shows in the
upper and middle Vicksburg sands. Our seismic on this prospect indicates
the Vicksburg section to be exceptionally thick with a Jackson shale of
about 22,000 feet, which is our planned TD. This will be one of the deeper
wells drilled in south Texas, and we are optimistic about its potential.

Within the next few weeks, we'll spud another 22,000-foot Vicksburg
prospect at Maurina (ph) Lake. Success in any of these three wells could
open up a new trend into play.

We continue to have success in the deep well (INAUDIBLE) of rigs running
across the trend. At our dry hollow (ph) field that we thought was fully
developed, we had discovered - we have discovered a new fault plot and have
just completed our fifth well with initial potentials ranging from 5 to 25
million a day.

In our Ryan (ph) southwest beach area, we drilled our last several
development wells below the development targets to the curtasios (ph) at 17
to 19,000 feet. All of our deeper wells have encountered significant
additional Wilcox pay sands below the conventional targets at 13 to 14,000
feet. Our last well, the Robinson V, drilled to 19,300 feet and counted
over 150 feet of pay below 18,000. Completion operations are underway. This
is the deepest well ever drilled in Lavaca County and will be the deepest
producing horizon in the trend.

In Lark (ph), Louisiana, we continue to have several rigs running,
redeveloping the Legacy, Somatt (ph), Poston (ph), and Cotton Valley
fields. As we export our south Texas technology to north Louisiana, we
continue to make wells that are producing two to three times their rates of
previous wells in these fields.

In addition, we have a new (INAUDIBLE) lime discovery at Kings Dome in
north central Louisiana that appears very promising. We have steadily
increased the production rate of this discovery that we made in the third
quarter of last year. It is now produced at 25 million cubic feet a day for
over two months with no decline. Our first extension well will spud
shortly. We have a large100 percent acreage position around the well.

Our (INAUDIBLE) Gulf of Mexico program continues to perform above
expectations with our first five wells in 2003 resulting in three new
discoveries and one successful field wildcat. The discoveries are between
17 and 20,000 feet and are all at least 25 BCF in size with one over 200
BCF. Additional drilling will be required to determine the full extent of
the fields. Fast track development programs are underway. The field wildcat
at west cam 181 (ph) began producing last week at 15 million a day and 450
barrels of condensate. The production will slowly ramp up to 20 million
cubic feet a day.

The Jim Bob (ph) Mountain discovery in South Marsh Island is only in 12
feet of water and will be tied back to a nearby Chevron production
facility. The well has been tested at rates of 14 million a day, and 1300
barrels of condensate a day at 13,670 pounds flow and tubing pressure from
the lower pay sand at 20,100 feet limited by the rig test facilities. Local
analysis indicate the well can produce at up to 60 million a day and 4900
barrels of condensate. It should be on limited production within the next
six weeks. Full production rates will require installation of CO2 removal
facilities to reduce the 5 to 6 percent CO2 content to pipeline specs. We
own a working interest of 60 percent in this discovery. An extension well
for this discovery will begin shortly.

Our100 percent-owned Blue Devil discovery in South Timber (ph) layer
encountered 162 feet of gross, 80 feet of net gas pay at 17,100 feet. We
are refurbishing a jacket and deck (ph) from the inventory to fast track
this project, and anticipate this well to be on production by September 1st
at an estimated rate of 75 million cubic feet a day. An extension well will
be spudded immediately to determine the size of the discovery.

Our 50 percent owned Browning discovery in Hiata (ph) encountered 126 feet
of gross, 85 feet of net gas pay at 16,840 feet. We are currently digging a
well with significant prospective section to be encountered before reaching
the (INAUDIBLE) fault at 22,000 feet. This discovery is in 45 feet of water
and will be tied back to one of several nearby existing facilities to fast
track production. We anticipate it being on production by mid summer.

We were very successful in the Gulf of Mexico lease sale earlier this month
and were the high bidder on 17 blocks. If we are awarded these blocks, we
will increase our deep shelf prospect inventory from 45 to 60 prospects,
one of the largest in the industry.

In Canada, our decision to shift our emphasis from the shallow gas and oil
plays in Alberta to the deeper plays of British Columbia is beginning to
pay off, and the prolific sleigh (ph) point trend we're extended at north
and south of Apache's Lady Firm (ph) field with several discoveries. Over
the winter drilling season, we drilled six sleigh point discoveries with
only one dry hole to date. Two were non-operating with 25 percent working.
The other four were within our Lubbles(ph) field complex where we have
250,000 gross, 225,000 net acres. The four discoveries in this area were
all 100 percent working interest. The first well has been on production for
several months at 20 to 25 million cubic feet a day with no decline limited
by processing plant capacity, and we have booked 50 BCF of reserve for this
well. The well has a production capacity of 50 million cubic feet a day.

The production rates and reserve size of the other discoveries will require
extended production testing, which will be delayed by road travel bans
during break-up for several months. We will also need and acquire
processing space in several of the surrounding plants that handle this, our
gas, but initial log analysis and limited flow tests are very encouraging
with pay sections similar to our first level of well and Lady Firm.

Additionally, we have two sweet gas discoveries south of Port St. John in
the Cadac (ph). We have completed four wells that have accumulative
production capacity of 45 to 50 million cubic feet a day. We must construct
several miles of (INAUDIBLE) line to market the gas, but anticipate it
being on stream by mid summer. Extension wells to these 100 percent
discoveries are being planned. We would anticipate that by year-end, these
eight new discoveries would cumulatively increase our net production by
over 100 million cubic feet a day net. In spite of our excellent success
with the drill bit, our unplanned sale of mid-continent assets and the
delay of $150 million of capital spending in the second quarter to the
latter part of the year to improve liquidity will reduce our targeted
production to 550 BCF equivalent. Offsetting its production , oil and gas
prices continue to exceed our original plan process, resulting in earnings
very close to our original plan.

I'd like to turn it back to Ron for a summary.

Before we take questions, I have a few closing remarks.

RON KUEHN: I believe El Paso is a company of world class assets and people.
This is a company with a promising future despite its many challenges. A
lot remains to be done to reach our goals. To date, we have made
significant progress. We will continue to stay focused on our business plan
and not be distracted. I believe we are on the right track. We must
continue to be strong, focused, and flexible regarding our plan, and we are
all working hard to ensure that we emerge a stronger, more focused company.

With that, we will now move to the Q and A. Before doing that, I'd like to
remind all of you that the primary purpose of today's call is to talk about
our earnings, so we will only be answering questions relating to today's
presentation, and press release, and not related to proxy.

With that, we're ready for questions.

OPERATOR: Thank you, sir. The floor is now open for questions. If you do
have a question, press 1 followed by 4 on your touch-tone phone. To remove
yourself from the queue, please dial the pound sign. We do ask that while
you pose your question, that you please pick up the handset to provide
optimum sound quality. Once again, ladies and gentlemen, that is 1 followed
by 4. Please hold while we poll for questions. Thank you.

Our first question is coming from Ray Niles of Salomon Smith Barney.

RAY NILES, SALOMON SMITH BARNEY: Good morning. Thank you.

What I would like is if you can provide a little more color on some
specifics with change in value of the contracts of the trading book, and
also for the impairment of assets at Project Electron. For example, on the
contracts, was it related to long sparks, spread exposure or directional
gas price exposure, and then if you can tie it in to a sense as to what
further types of charges there could be.

Brent Austin.

In terms of more color on specific changes in the trading book, we
basically had two elements in the fourth quarter. One was our
implementation of EITF 02-3 so a significant component of the change was
related to that. Beyond that, we were basically marketing the portfolio to
fair value, and given the conditions in the industry, and particularly the
weakness of the number of counter parties and before liquidity in the
market, the change basically just reflects what we estimate to be fair
value for the quarter.

RAY NILES: So it's mainly liquidity and credit related to your counter

BRENT AUSTIN: Well, just reflecting market conditions for - you know, the
bid asked for a number of contractual positions. We've got about 40,000
contract positions at year-end in the book.

DWIGHT SCOTT: Ray, this is Dwight.

Just to add a couple of things there, we also took significant option value
out of the book as the market, you know, really hasn't stopped paying for
option value right now. That was a big component, and then we actually went
out and since we're exiting the business and we're no longer as active in
many of the markets where we have positions, we went out and brought in a
third party to evaluate our curves and all that together was what resulted
in the $620 million change in value.

RAY NILES: OK. Maybe a follow-up question. In terms of the EITF 0203
change, is that going to show up in accrual earnings or is that sort of
just gone from the book in this period and we won't really see a reversal
benefit in future periods?

UNKNOWN MALE #1: The positions that have gone from mark to market
accounting to accrual, the change in value on those positions will be
reflected on a quarterly basis, so the value isn't necessarily gone. It's
just not going to be recognized up front for the entire remaining value of
the life. It will just be spread out as accrued over the specific life of
that instrument.

RAY NILES: Thank you.

OPERATOR: Your next question is coming from Ron Barone of UBS Warburg.

RON BARONE, UBS WARBURG: Good morning. Two of the questions following up.

The quarterly burn rate for trading, the fixed quarterly burn rate, how
negative could that be going forward, number one, and number two, the book
is valued negative now. How bad could that get going forward? Can you give
us some idea, put some parameters around that?

DWIGHT SCOTT: It's a mark to market - there is still mark to market aspects
of the book, so it really depends on where the market goes as to where the
value goes going forward. The burn rate, as you recall, we're talking about
$90 million of loss for the year in our previous numbers. A range around
that, actually. I think we probably - we have seen a higher burn rate than
that in the first quarter, and that's why I said and we've tried to reflect
that in our adjusted estimates of $1. As we manage the business and try to
get the liquidity out of the business as quickly as possible, we're making
decisions that create losses from an earnings standpoint in order to get us
cash faster, and for instance, we may sell some power contracts that allow
us to reduce our collateral demand and reduce our long-term obligations in
the books that may result in a loss relative to their mark to market value
and, therefore, we could see higher losses - that's where we try to reflect
in our projections.

RON BARONE: Thank you.

OPERATOR: Thank you.

Our next question is coming from Carol Coale of Prudential Securities.


I wanted to specifically address your liquidity and your available credit.
I was a little confused on slide 14. Earlier, you were talking about
renegotiating your credit lines with the banks and we've got the $3
billion, 364-day revolver that matures in May and then there's the other
billion dollar line that matures I think this summer. Looking on 14, it
doesn't look like - you said you do not intend to renew the billion dollar
credit line and you're just working to renegotiate the 364-day term line?
That's the first part of the question. Second is, if you had to secure that
line, can you give us an idea of what assets are not encumbered at this
point in time that could be used as a secure asset under that credit?

UNKNOWN MALE #2: Let me address, Carol - your question actually highlights
something on this slide that is different than how we normally talk about
these lines.

We expect to extend - we're working on extending the maturity of our
364-day facility, which is the $3 billion facility. In this slide that is
showing as - the 1.5 is showing as due in 2004, but we title it multi-year
revolver so this is actually - this slide is incorrect. It should -
364-dayrevolver should be in the line below where it is, and those two are
switched. So our multi-year revolver, which is the one that's due in August
of this year, it is a billion dollar facility. We will repay - it is fully
drawn, half of which is drawn for cash and half of which is used for LC's.
We expect to repay that in August of this year. The $3 billion facility,
which is 1.5 billion of which is drawn, we are - we will either have to pay
that on its maturity in May of 2004 or we will be successful in extending
it. So this slide, you're right, it is inconsistent in wording from what we
normally say.

I would prefer not to discuss exactly what we are talking about with the
banks, but we do believe that we have within our indentures the capability
of providing collateral to the banks that will be fair to the banks and
allow us to get a good transaction for the company, but will also be fair
to our other security holders, our other bond holders within the company.
So without going into the detail of what we think we can and can't do, we
do believe that there's collateral that we can offer that makes the deal


OPERATOR: Thank you.

Our next question is coming from Anatol Feygin from J.P. Morgan.

ANATOL FEYGIN, JP MORGAN: One, Dwight, can you give us a feel for where
you're estimating interest expense to play out for 2003?

DWIGHT SCOTT: Well, Anatol, that's - let me just answer that. If you look
at the fourth quarter interest expense, that's why I mentioned that Euro
loss, the Euro dollar loss in the fourth quarter. Our fourth quarter
numbers are about on an annual basis what we would expect for the full year
next year with the exception of that non-cash Euro dollar exchange rate
loss of 50 million. There actually may be a little bit below what we expect
next year, but that's one way to look at it, at least.

ANATOL FEYGIN: Very good. Can you tell us why the Electron contribution was
actually a loss in the fourth quarter? We thought that that was pretty much
locked in for the full year.

UNKNOWN MALE #3: Let me make two points. One is the actual fee-based income
was - we did achieve that in the fourth quarter. The equity earnings that
we got as an owner of Electron were what was a loss.

UNKNOWN MALE #4: I can't recall the specifics. It was just a normal
operating expenses and part of the management (INAUDIBLE) to us.

UNKNOWN MALE #3: I think it was just the businesses had a loss in the
quarter, Anatol.

ANATOL FEYGIN: Great. One question, I guess, for Rod. The MMS has come out
with this proposal to give a credit for some of the type of drilling that
you guys do in the shallow waters, deep drilling. Can you give us a feel
for how much production that you currently have would qualify for that
royalty credit?

ROD ERSKINE: As it's currently proposed, the effective date won't be until
they finished all their comments, so it will only be effective for wells
that are drilled after probably two months from now. So none of our current
production will be affected. It will have a significant impact on our
programs for the rest of the year. We have a number of deep wells that
we'll be drilling over the next year, so this proposed rule, if it goes
into effect, will have a very positive impact on our deep shelf program.
We're the most active operator in that area.

ANATOL FEYGIN: Can you give me a feel for how much production is coming? I
appreciate that this production won't qualify, but just to get a sense for
the numbers involved, how much of the production is currently from those
types of wells?

ROD ERSKINE: Currently of our deep shelf program, we're making - we're
operating about 600 million cubic feet a day, and over half of it's come
from deep shelf wells now. And that number is steadily increasing. Our
shallow production continues to deplete, and we replaced that with mostly
deep shelf. Our entire development program for the Gulf of Mexico is
revolved around deep shelf.

ANATOL FEYGIN: And these would then qualify for 25 BCF or up to 25 BCF over
the life of the well?

ROD ERSKINE: Yes, almost all of ours would almost all be below the
17,000-foot depth, and so would qualify for the 25.


UNKNOWN MALE #4: 16 percent on an average gas price of five bucks, you're
talking 80 cents in Mcf for that production.

ANATOL FEYGIN: Right. Excellent.

One last question as a follow-up to Ray's question. Can you guys give us a
sense for the - as the book comes in, the issues that have been - the
contracts that have been written down to historical value, the accrual
--level of accrual earnings that will be recognized in 2003 that has been
written off on EITF 02 03,what that magnitude could possibly be?

UNKNOWN MALE #4: Yes, that is reflected in the total loss that we're
expecting from the trading business, so it's just part of that - of that -
that income is offsetting the loss, and it depends on, for instance, on
transmission capacity, it depends on what the basis spread is.

ANATOL FEYGIN: Sure. All right. Thanks very much, everyone. Thanks, Dwight.

OPERATOR: Thank you.

Our next question is coming from Scott Soler of Morgan Stanley.


Dwight, I've got two questions, first regarding earnings guidance of a
dollar for next year, just want to understand a few of the key assumptions
in the earnings guidance. On interest expense, question was asked, but what
I want to understand is, assuming you all do get your 3 billion dollar
revolver refinanced in the next couple weeks, is there an assumption for a
higher interest charge on the refinancing built in? And then on the
assumption on merchant energy EBIT, could you all - I forgot if you had
provided that already or not.

UNKNOWN MALE #5: Yes, in the February 8th call, what we did is we provided
EBITDA, EBIT for each of the business units, and then a total earnings
number. So that's where those are coming from.

And on the interest expense, yes, we have in our plan assumed that we would
pay a higher interest expense on our bank facilities and we've also
assumed, you'll recall this $1.2 billion term loan has a higher interest
expense on it than what our average interest rate is certainly.

SCOTT SOLER: OK. The second question is on page 10 of the presentation,
your non-equity-funded capital or debt is 24.9 billion of total
obligations. We were wondering either on the 10-K or on the follow-on Q's
that would come out probably second quarter, I'd assume, what do you all
have to lay out under FASB interpretation 46 in terms of things like
project finance debt, other - if there were - if there's any other debt
aside from the 24.9, is there any particular schedule you all will have to
provide in your K either tonight or in your Q mid year?

UNKNOWN MALE #5: Actually, the K will have a lot of information on that,
Scott, in the management discussion analysis in the liquidity section, in
the off balance sheet section. There are a number of places in the K where
we try to address that.

Specifically, your question about the implementation of the new accounting
rules, there are two places where that may impact us significantly. One is
on leases, on leveraged leases and we have two of those of any size, one is
on our Aruba refinery and one is on our Lakeside telecom facility. We have
in the 10-K a description of what the impact of bringing those on would be.
As I mentioned in my earlier statements to the extent that we change some
of the structures of those deals as part of our bank deal, they may come on
earlier anyway. It doesn't change the calculation you just talked about, at
least it doesn't change that page we just showed because the guarantees are
included in those guarantees from the banks.

In addition, we have talked about Electron, and Gemstone - to the extent
that we consolidate them, and we expect to consolidate Electron and it is
likely we will consolidate Gemstone, we will bring on any project financed
debt on Electron, that's that1.8 billion we talked about last time that we
were working on selling the assets and reducing that number. To the extent
that we're not successful in selling those assets, that non-recourse debt
would come on to our balance sheet.

Gemstone, we will probably consolidate it either through buying out the
equity or through this change in accounting. There is not significant debt
on those assets at the moment, though we are trying to put on some project
financings on those assets to reduce our exposure to Brazil.

SCOTT SOLER: So Dwight, even though you all have 2003 to adopt or to
implement FEN46, you don't see there's anything that your auditors might
come to you in the next few months and we say we think this, this and this
should be added? What you capture is what you feel is the total?

DWIGHT SCOTT: We tried to lay it out, Scott, as to what we think the
exposures are to the change. Jeff Beason (ph) is here with us. Is there
anything else in that note of any import?

JEFF BEASON (ph), EL PASO CORPORATION: Well, we've referred - we refer you
to the MB&A, but also to the first footnote in the financial statements.
There's a pretty good discussion of all the components that we expect to
implement with this new FEN46. The requirement of FEN46 is that we update
this new rule in our financial statements effective July 1st of this year,
and I think we've given you a pretty good indication of that in the 10-K.

SCOTT SOLER: OK. Thank you.

OPERATOR: Thank you.

Our next question is coming from John Olson of Sandlers Morris Harris.

JOHN OLSON, SANDLERS MORRIS HARRIS: Good morning, everybody. A couple of
quick ones, if I may.

The capital spending number of about 2.5, 2.6 this year, do you have any
idea where that number would be in '04 and '05? Can you take that lower?

DWIGHT SCOTT: John, it's Dwight.

As I said in my presentation, we're going through a process right now of
looking at those numbers very carefully. Since most of that cap-ex is in
our production and in our pipeline businesses, we're looking at where we
can reduce that in those two businesses particularly without significantly
impacting our plan cash flows and so forth, so we're working on a process
of reducing it not only for this year, but for further years. Also in that
number is a couple of hundred million dollars of maintenance capital in
assets that we're going to sell, so we would expect it to go down by that
amount just by virtue of selling the assets that we have on the block, but
when we get down below that 2.3 to 2.4 number, that's sort of part of the
same process we're going through for this year.

JOHN OLSON: OK. Secondly, Ron mentioned that I believe the number was - you
expected to have over 80 percent of your assets sales done by the end of
the second quarter, and that would imply another billion dollars will come
out in next 90 days here or so. Was that you'd be up to 2.7 billion by July

BRENT AUSTIN: Yes, that's what we expect, John. This is Brent.

Our program for the 2.9 that was up to 3.4 billion of non-core asset sales
for calendar year 2003 was specifically geared to be up fronted in that
kind of a mode, so we'll be through with - either closed or announced more
than 80 percent by the end of the second quarter, we have that expectation.

JOHN OLSON: OK. And final question - you mentioned a number of charges that
you expect to take this year, including Project Electron, equity and the
like. You mentioned losses on various asset sales of another 300 to 375
million after tax. Is that specifically identified with one sector like
power plants or anything else?

UNKNOWN MALE #6: John, I think the largest component of that would be an
expectation on expected losses on the disposition of some petroleum assets,
would be the largest segment there.

JOHN OLSON: OK. Thank you very much.

OPERATOR: Thank you.

Our next question is coming from Curt Louner from Credit Suisse First

CURT LOUNER, CREDIT SUISSE FIRST BOSTON: Just wanted to follow up on John's
last question.

How sensitive will the write-offs this year be to the selling prices of
some of the assets, say the ones with PPA's out of Electron related to the
goodwill in Electron, and I do have a follow-up after that.

UNKNOWN MALE #7: On the Electron question, what will happen is when we buy
out the equity there, we will revalue the assets within that business. And
actually in our 10-K, there's a much more detailed description of the
assets in that business in the front part of the 10-K this year. But we
will revalue those assets, and to the extent that we are paying more than
that fair market value of the assets, it will be attributable to goodwill.

To the extent that we didn't think that goodwill is impaired by the value
of the assets, we would have a write-off, and that's kind of the process
we'll go through. The PPA assets are obviously not sensitive to that
valuation, though what we have seen is discount rates have gone up as to
what people are willing to pay for that contracting cash flow. But there
are various assets within Electron including some that have long-term
holding contracts and we'll have to look at the counter parties that
they're totaling and see what their credit profile is and so forth. So it's
that process we'll be going through, Curt.

The rest of the write-off is absolutely sensitive to both when and for how
much we sell assets, and so to the extent that we achieve our asset sales
program without having to sell some of the assets we have less value, and
that would result in less write-off, and to the extent we get less value,
then we're projecting results with a greater write-off.

CURT LAUNER: Thank you.

If I could ask for John to give us an outlook for pipeline EBIT this year,
up, down, sideways, given what we know about the required capital
expenditures, the maintenance levels at the pipeline, there are some new
projects coming in. If I could just ask about that.

DWIGHT SCOTT: Yes, Curt, before John answers it, we're trying to be
sensitive to this new rule that came out, I guess Friday, about disclosure
and having GAAP discussions at the same time you're having EBIT
discussions. In our previous presentation on February 8th, we did give EBIT
guidance for the pipelines, and that's in there, and John can maybe talk
about where we are relative to what we thought in February.

JOHN SOMERHALDER (ph): Yes, as Dwight said, we did give that guidance. It
is fairly early in the year, but what I indicated earlier was that we have
seen higher load factors on our pipeline systems. That does show some
improved value already we've realized. As an example, on Tennessee, we have
enhanced fixed variable rates, so we've seen already some improved
benefits. So the general direction is positive from what we presented
earlier, but it's really a little early in the year to say more than that.

On capital, we're managing capital as best we can, and we have seen some
indications where we can control that and keep it at or slightly lower than
what we had anticipated before as well, so positive direction as far as
EBIT upward, a little bit of a positive direction as far as keeping capital
expenditures low.

CURT LAUNER: OK. Fair enough. And just one brief follow-up, if I could, on
the discussion you had earlier relative to cash levels at 328, the1.5
billion number. Is that an unrestricted cash number and there's some
additional cash that's restricted above that?

UNKNOWN MALE #7: Yes, Curt. This is what we call available cash, so it's
cash that we can send out a wire today if we needed to, and that's what we
consider our available cash.

CURT LAUNER: And that description compares to the 1.1 billion that we had
at year-end in the numbers?

UNKNOWN MALE #7: Yes, the reported number was 1.6 billion at year-end
versus the 1.1 of available cash at that time.

CURT LAUNER: OK. Thank you very much.

UNKNOWN MALE #7: Operator, let's take one more question.

OPERATOR: Thank you.

Our final question will be coming from John Edwards of Deutsche Banc.


Could you clarify for us the total inventory of production property, you
know, given the number of asset sales? I think we were guessing around 4.7

UNKNOWN MALE #8: You mean the reserves, John?


UNKNOWN MALE #8: Our year-end number, I believe, was 5.2 billion worldwide.

JOHN EDWARDS: Year-end, and then you've sold some down since then?

UNKNOWN MALE #8: Yes, we've sold some down since then. Mid-continent was a
little over 400 BCF, correct.

JOHN EDWARDS: Right. OK. And then could you clarify then what's your
weighted average interest rate going to be at this point?

UNKNOWN MALE #8: Our current weighted average rate for long term debt is
around 8 percent. Our short term debt, even at the higher cost, is LIBOR
based and would be below that. I do not have, John, exactly what's assumed
in our plan on our weighted average cost of interest here today.

JOHN EDWARDS: OK. And then could you just - in terms of the liquidity, help
us understand in terms of the collateral, do you expect to roll, you know,
back to El Paso, you know, from trading book and from production hedges?
Can you give us a little bit of clarification on that say this year and

UNKNOWN MALE #8: Sure. Our trading book, we have - including our production
hedges which show up in the trading book, we have about 1.2 billion of
current margin outstanding against that, plus a couple hundred million
dollars of LC capacity that we're using against that book, so that is the
amount of money that we would expect to come back over time as we liquidate
both the production hedges and the trading book, and then we have in
addition, a significant amount of collateral out against our petroleum
business, particularly our Eagle Point and Aruba refineries, and as we
either figure out a way to do that or sell those assets, that liquidity
should come back to us as well.

JOHN EDWARDS: How much should that be?

UNKNOWN MALE #8: I don't have the current number. It was 400 to 600 million
dollars, it ranges in that range.

UNKNOWN MALE #9: For all of petroleum.

JOHN EDWARDS: OK. And then last question, just - you mentioned the Cheyenne
Plains pipeline. What's the capacity and timing you expect on that project?

UNKNOWN MALE #9: The capacity on that pipeline is 540 million a day. It's
about a 330 or $340 million project. Most of those dollars would be spent
next year, and we would anticipate in service very early in 2005. If
there's a way for us to speed that up a little bit, we're looking at that,
but right now, early 2005 is the anticipated in-service date.

JOHN EDWARDS: OK. Thank you very much. I'll follow up with my other
questions later.

BRUCE CONNERY: OK. That will conclude the call. I'll remind you that we'll
be filing our 10-K later on this morning, and you can access that on our
website. Again, we appreciate you calling. Thank you.

OPERATOR: Thank you. This does conclude today's teleconference. You may
disconnect your lines at this time and have a great day.