EXHIBIT 99.2
TEXAS GENCO HOLDINGS, INC.
LEADER, MARIANNE PAULSEN
ID# 9660771
04/24/03
1ST QUARTER 2003 EARNINGS
CONFERENCE CALL Q & A
TEXAS GENCO HOLDINGS, INC.
ID# 9660771 PAGE 2
Marianne: Okay. Well, thank you, David. And Charlene,
I think we're ready to take some questions,
so if you'd please instruct the callers.
Operator: At this time, I would like to remind
everyone if you would like to ask a question
press star then the number one on your
telephone keypad. We'll pause for just a
moment to compile the Q&A roster. Your first
question comes from Kit Konolige of Morgan
Stanley.
Kit Konolige: Good morning. I was wondering if you could
give us a little more sense of any
indications along the way in the inspection
of unit one that would in which you would be
able to learn and give to us a sense of what
the issues are and whether the return to
service date could change.
David Tees: Yes. As part of our normal inspection - and
this unit was down for a normal refueling
outage, we inspected the reactor vessel and
looking at the bottom of the vessel we found
some residue that wasn't there 18 months ago
when we did the inspection and it was on a
couple of pipes that go up into the reactor
vessel. There was no indication of a leak.
All we did was find a residue, but when we
tested this residue we found mineral
contents, which pointed out that it was the
residue from reactor cooling water. And
since there was no evidence of where the
leak occurred but that this residue was
there we said we've got to shut - we did not
start up the unit, but we've got to do an
inspection.
So where we are at this time is preparing to
do the inspection to find out where the leak
is and also at the same time in parallel
with that we've contacted a lot of experts
in some companies that do repairs on these
type of penetrations. And we're having them
put together a plan on doing the repair
depending on where it might have occurred.
And there a lot of unknowns because I want
you to realize we have not identified
exactly where the leak is yet, if there is a
leak. And we haven't thus picked the exact
repair option. So we have a lot of
scenarios, but instead of just sitting
around and waiting until we identify where
the leak is we're trying to evaluate and do
a lot of scenario planning and saying, okay,
if it's in this area, we'll fix it and it'll
take this long. If it's in this area, we'll
fix it this way and it'll take that long. So
there is a lot of uncertainty in our
planning right at this time.
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But I think probably the approval we have to
get through the Nuclear Regulatory
Commission we have to get whatever problem
we find, whatever solution we come up with
we have to go to the NRC and get their
concurrence on this repair being proper
corrective action. So I believe that is one
of the big unknowns at this time is the
length of time it takes to do that.
Kit Konolige: And do you have a working sense of when you
would expect to have a diagnosis?
David Tees: No, not at this time.
Kit Konolige: So is it fair to say that when you talk
about returning in late summer that's kind
of the midpoint of a necessarily pretty wide
range?
David Tees: No, that's just based on our scenario
planning at this time
Kit Konolige: Okay. And final question, we understand
there's a call today with the NRC.
David Tees: If there is it's from the Nuclear Operating
Company that acts as our agents at the site
to run the facility. They're in constant
contact with the NRC evaluating all of the
work that we have going on for the
inspection at this time.
Kit Konolige: Okay. Thank you.
Operator: Your next question comes from Michael
Goldenberg of Luminus.
Michael Goldenberg: Hey. Good morning, guys.
David Tees: Morning.
Michael Goldenberg: Hey, just wanted first of all two quick
follow-up questions on Texas Genco, I mean,
on the STP nuclear plan. One is, I mean, is
it possible at all to break out those four
months into any sort of timeline however
fuzzy it may be in terms of kind of
diagnosis will take X weeks and then this
may take X weeks. Is that at all possible to
do that?
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David Tees: There's a bunch of different scenario plans
we've made and I don't think it's really
possible to break down every one of those
plans into its components of inspection and
application for approval and then the repair
process and testing and restart. I just
can't do that at this time.
Michael Goldenberg: And any - I mean, following up on Kit's
question, any sort of earliest time when we
may have a better idea of what exactly is
wrong with the unit?
David Tees: We will be putting out information as soon
as we find out and start on a plan, a
corrective action plan, we'll release that
information.
Michael Goldenberg: But, David, you can't give us any sense in
terms of weeks?
David Tees: Not at this time.
Michael Goldenberg: Okay. And just two questions on the
auctions. You have 750-megawatts of base
load in reserve. Given that, let's say that
unit one will be out for the summer or for
most of the summer, does that reduce the
amount of megawatts you're going to keep in
the backlog and you're going to take part of
that 750 and sell that or are you going to
sell less and keep the backlog at 750?
David Tees: Well, the 1250 reserve we keep - we do not
sell that on firm. We may sell it on an
interruptible basis or we may use it to
serve some of our gas entitlements in order
to get some margin upside. Remember we also
- we won't be short on capacity because we
have about 1000 megawatts that we'll have in
a mothball status this summer. And if we
have another outage we can bring it back
within say 72 hours.
Michael Goldenberg: But my question is more towards the fact
that - does that mean since the new - does
that mean for the next four months you'll be
selling less base load capacity.
David McClanahan: Michael, we've already sold all the base
load capacity we had intended to sell. We're
going to use some base load capacity that we
did not sell and that we reserved for just
this type of outage to serve the needs of,
you know, that we have. So we're not going
to sell anymore, but we had this 750 that we
hadn't sold that we're going to use to meet
our obligations.
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Michael Goldenberg Okay. But as far as the auction, that's
going to be - you said there will be two
important auctions that will be taking place
in the next six weeks.
David McClanahan: Those auctions are for the last four months
of the year.
Michael Goldenberg: Okay.
David McClanahan: And that will be held this summer. And the
auction that we're going to hold in May are
for capacity we're going to sell in 2004 and
2005, but it's not going to be all our
capacity; it's going to be just a small
portion of our capacity we're going to sell
forward.
Michael Goldenberg: Okay. Will any of the new capacity be
figuring in to that 2004 auction? I guess
what I'm trying to ask is given that the
unit is out maybe only for the next four
months are you going to be selling any of
that capacity today or you just going to
wait until the unit is back up?
David McClanahan: You know, we hadn't made that decision
whether we're going to sell any nuclear
capacity or we just sell coal and lignite
and gas for next year and 2005. We really
need to gain a little bit more insight into
unit one. But our expectation is it will be
back and that we will be selling a part of
our nuclear capacity.
Michael Goldenberg: Okay. Thank you very much. Good luck.
David McClanahan: Thank you.
Operator: Your next question comes from Nikola
Durovcevic from Seneca Capital.
Nikola Durovcevic: Hi, guys. Is it fair to say that the outage
of unit two in the first quarter of this
year is a one time kind of like event? And
if so, should we treat that $33 million
charge as a result of the outage as a
non-recurring item.
David McClanahan: Well, that's -
David McClanahan: Go ahead, David.
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David Tees: The extended outage on the unit two occurred
because of some very strange turbine
vibration problems and we did an extensive
amount of repair and this should not occur
at all in the future on that unit. We feel
like we have a permanent repair.
Nikola Durovcevic: So hence you could use that charge of $33
million as a non-recurring item for like
let's say if we were going - you know,
apples to apples for next year assuming same
exact assumptions you would have an
additional $33 million of EBIT.
David McClanahan: Well, I think you have to make that
assessment. Certainly we don't expect unit
two to go down for the same reason. Base
load, any type of generation you run you
have forced outages. You know, we've running
these plants for 100 years and you always
have unplanned outages, but we don't expect
unit two to be down again. We're certainly
hoping it's not going to be down.
Nikola Durovcevic: Right. But going back over the last, you
know, since 1988 since these plants were
built, 1988, 89, have you had these type of
charges in the amount of like 30 million or
so as a recurring type of a charge or this
is kind of like sporadic or is it the first
time actually it's happening?
David McClanahan: Well, if you look back at the South Texas
project, it came off an extensive outage in
1993 and it has run excellent since that
point in time. So it has a great track
record the last ten years. So this is an
infrequent and fairly unusual occurrence.
But having said that when you operate big
complex machines like that you have forced
outages and you repair them and then you put
them back in service. So it's not unusual.
Nikola Durovcevic: How often does the refuel - is refueling
performed at both units? And, you know, a
follow-up to that is when was actual unit
one scheduled to go into service if there
was no actual - if there was no problem
found, the leakage?
David McClanahan: First, typical refueling outages are every
18 months.
Nikola Durovcevic: Okay.
David McClanahan: And they're, you know, they're synchronized
so you don't have both units down at once.
Secondly is that unit one was due to
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come back from this refueling outage I think
late April, early May. It was going very
well. We were - so the outage was going
according to plan until this issue came up.
Nikola Durovcevic: Thank you.
Operator: Your next question comes from Jonathan
Rojewski of Goldman Sachs.
Jonathan Rojewski: Good morning, everyone.
David McClanahan: Good morning.
Jonathan Rojewski: Many of us are pretty familiar with this
outage related to sort of the boron/boric
acid deposits from the Davis Bessie plant. I
know that this is a different type of
reactor. I'm wondering, David, if you could
sort of explain to us without getting too
complicated how this scenario may be
different or is different than Davis Bessie
plant and whether or not any types of
repairs would be more or less complicated
due to the set up of the vessel head.
David Tees: I can give you my knowledge, which is not
100% of what they found at Davis Bessie, but
I do know that the leak that they had there
was in a flange on a pipe that enters the
top of the reactor vessel. And this leak of
reactor cooling water then formed boric acid
and caused some corrosion in the top of the
vessel head itself. When you have this type
of corrosion problem you have to have the
presence of the boric acid. You have to have
the steel and you have to have oxygen.
The leak that we found or the residue that
we found, we haven't really found a leak
yet, was on the bottom of the vessel itself.
And it was just a minute amount of material.
And so if it came from the inside of the
unit it wouldn't have been in presence of
oxygen, so we wouldn't anticipate the same
of type of damages that was found at Davis
Bessie.
Jonathan Rojewski: If you - if I'm thinking about how it - how
those are physically set up it seems a
little bit more difficult to come up with
where that - how that deposit would have
occurred on the outside of the reactor. Any
sort of initial thoughts from your team of
experts in how and where that might have
come from?
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David Tees: Well, there's a bunch of different scenarios
on where it could have come from and until
we get through with all of our inspections,
I don't think I'd like to speculate.
Jonathan Rojewski: Okay. That's fine. And then just a point of
clarification. You ran through some of the
generating costs in your prepared remarks. I
was wondering if you could review those
again relative to, I think, you said $16 to
17 per megawatt hour generating cost for the
base load that you have in reserve and then
you named a couple of others.
David Tees: I can give you some sample numbers from our
PUC auction. These numbers are posted with
the Texas...
David McClanahan: David, I think Jonathan was referring to the
cost to generate power out of our base load
we have in reserve versus the nuclear and
the gas fired capacity.
Jonathan Rojewski: That's right.
David Tees: Oh, okay. Excuse me. The - at the present
time based on the heat rate of our units and
the price we're paying for gas our
generation is running around $55 a megawatt
hour for natural gas. And the nuclear plant
runs between $4 and 5 a megawatt hour for
its generation cost and our coal and lignite
plants around $15 to 17 a megawatt hour.
Jonathan Rojewski: Okay. Exactly. Alright. Great.
Operator: Your next question comes from Philip
Brenneman of Monarch Capital.
Philip Brenneman: Hi, folks. Good morning.
David McClanahan: Morning.
Philip Brenneman: Couple of questions for you. Can you give us
an update on balance sheet notes payable
affiliated companies net both current and
long-term liabilities? Has there been any
change there since the last quarter?
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Gary Whitlock: As you know, this company in terms of
leverage has no leverage other than the
inter-company debt. That amount during the
first quarter tends to increase. As we
indicated last - I think in our call, was
approximately 150 million. It's a bit more
than that right now, but there are payments
that would come in, but I'd say on - you
know, the balance effectively is around -
will be around 150 to 200 million.
Philip Brenneman: Over what? The next few quarters?
Gary Whitlock: Right.
Philip Brenneman: Okay.
Gary Whitlock: As you know, Philip, maybe this is a good
time to answer the question that may be
asked around as we described in our January
call our plan is we are contemplating
putting a financing in Texas Genco that
would do two things. One, repay the
inter-company loan or the debt due to the
parent company and second really provide
independent liquidity for Texas Genco. We're
still contemplating that.
Philip Brenneman: Okay. You've kind of anticipated my next
question. Has the increase in cash flow
changed your perspective on where that might
be? You had indicated previously you thought
it might be 150 to 200. Is that your target
still?
Gary Whitlock: I think it is, Philip, still at that level.
Philip Brenneman: Okay. All right, and can you give me cash on
hand?
Gary Whitlock: Just a moment. I'll get it for you. Really
in terms of cash on hand, you know, this is
really - they are not an investor in the
money pool at the moment so, you know, then
again the first quarter is not a strong
quarter for the company.
Operator: Your next question comes from Paul Patterson
of Glen Rock Associates.
Paul Patterson: Good morning. I wanted to ask you guys how
much do you guys actually have invested in
STP unit one?
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David McClanahan: Let us get our book value. STP unit one
investment book value. We'll get that for
you, Paul, and give it before we get off the
line here.
Paul Patterson: And then to follow-up on the previous
question about the opportunity costs. It
sounds like, I guess, internally you'll be
replacing this outage with your lignite and
I guess to some degree your gas fired
generation. Is that correct?
David McClanahan: Yes.
David Tees: Yes.
Paul Patterson: But you'll be missing the opportunity of
producing power at $5 a megawatt hour. But
it isn't changing your guidance because,
essentially because you were pretty
conservative with respect to what your
expectations were for the capacity auctions.
Is that correct?
Gary Whitlock I think that's fair.
Operator: Your next question comes from Marc Lawrence
of Tyndall Management.
Marc Lawrence: Hi. I was wondering if you could give us an
idea of the seasonality of the business, you
know, based on your guidance for EBITDA or
whatever, just a crude break down quarter by
quarter, 10, 20, 30, whatever.
David McClanahan: Let us get that.
Gary Whitlock: Let us get it for you.
David McClanahan: We have it here.
Gary Whitlock: Probably about 60% in the third quarter. Let
us be a little more accurate than that, but
obviously the third quarter is the largest
quarter.
David McClanahan: We'll get those percentages so you can have
a better feel for that. Obviously the first
quarter is, as Gary said, is our seasonally
- one of our lowest. Third quarter's our
highest.
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Gary Whitlock: Marc.
Marc Lawrence: Yeah.
Gary Whitlock: Did you have another question as well?
Marc Lawrence: Yeah, I do. Are you going to get back to me
later or -
Gary Whitlock: Why don't we take the next one?
Marc Lawrence: Okay. Sure. I mean, my next question was
just how you look at the decision for how
much power to sell for '04 and '05,
essentially your view on hedging the high
gas prices. What's the company's logic and
does that have any - Is that influenced in
any way by change of control that's likely?
David McClanahan: Well, that's a good question. It's one that
we've thought a lot about during this high
price period we're in. We believe that there
is a - it's prudent to sell forward at this
time. We don't think you sell forward all
your power, but I think you use a percentage
of your power. There is no kind of
scientific way to do that. I think it's all
the judgment of management and that's a
process we're going through now and we'll
make that decision before May when we have
that auction.
Marc Lawrence: So what are the ranges you're considering
for May?
David McClanahan: You know, we haven't really narrowed down a
range. Certainly it'll be less than 50% and
probably a lot less than that.
Mark Lawrence: Okay. Great.
Gary Whitlock: Hey, Mark -
Operator: Your next -
Gary Whitlock: Marc, let me answer your other question. I
think the way I'd look at this is - let me
just give you ranges, second, third, and
fourth quarter. Second quarter and fourth
quarter are ranges 20 to 30% and then the
third quarter 50 to 60%. So those are sort
of the levels that I would look at. Hope
that's helpful.
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Operator: Your next question comes from David Grumhaus
of Copia Capital.
David Grumhaus: Good morning. Question in terms of your
average price per megawatt hour that you
realized in the first quarter for capacity
payments and what you're sort of assuming in
your guidance for the rest of the year.
David McClanahan: Actually if you look at the way that we sell
power, we sell power based on capacity
entitlements. We've locked in over 80% of
our capacity entitlements through auctions
to date, so we have a very clear vision into
the rest of the year from a capacity
entitlement revenue standpoint. I think the
big unknown is really unforced and - or
unplanned and forced outages. We make
assumptions as we always have of about how
our units will run. But it - we have a very
clear picture at this stage because we've
sold a lot of our revenue forward, our
capacity forward.
David Grumhaus: What was that locked-in price for the first
quarter?
David McClanahan: Well, of course it varies by the type of
entitlement you sell.
David Grumhaus: Okay.
David McClanahan: We sell three types of base load
entitlements. We sell three or four types of
gas fired entitlements, so they're each
different. The highest, as David said, is
our nuclear capacity because it has the
lowest energy price associated with it and
the PUC options in for the summer were a
little bit over $30 per KW per month. Our
coal and lignite sold in the mid to high 20s
as I recall. And some of those are in
different zones in Texas. And it also
depends on which zone you're in. Obviously
gas-fired capacity sells for significantly
less.
David Grumhaus: Okay. And when I think ahead to the April
auction, will those prices be up
significantly. I would assume they would.
David McClanahan: Our April auction was really only gas-fired.
We sold some capacity in March and the
capacity we sold in March came in above the
levels that we sold last December.
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David Grumhaus: Okay. Have you sold any power for next year
yet forward?
David McClanahan: No. No, we have not. Not for 2004.
David Grumhaus: Okay. Thank you.
Operator: Your next question comes from Zach Schreiber
of Duquesne Capital.
Zach Schreiber: Hi. It's Zach Schreiber from Duquesne
Capital Management. Can you hear me?
David McClanahan: Yes. Good morning, Zach.
Zach Schreiber: Hi. I just want to follow-up on Paul
Patterson's question. Is there any way you
can sort of just break down for us? If we
were to look at the first quarter, what the
impact was of the outage of the other South
Texas Project? How many megawatts that the
South Texas Project is that was down in the
first quarter. How many megawatts is South
Texas Project number one, what kind of
capacity factor are you assuming sort of 85,
90%? I would imagine if we could look at
sort of, you know, the megawatt hours that
you're not going to have what the margin
erosion is, which I guess is what you're
saying is it's about, you know, $12 or 13
per megawatt hour. I guess another question
would be is if the marginal costs of these
lignite units was $16 in the first place,
why are they being held in reserve and not
being sold on an interruptible basis to
begin with.
And then just on the positive side the sort
of capacity auction side, it sounds like
you've had a doubling in the capacity
auctions on a year-over-year basis - I'm
just trying to look at sort of the deltas in
the negative side to deltas in the positive
side that allow you sort of to maintain your
full year guidance in spite of - you know,
what looks like a pretty big negative on the
opportunity cost side. Trying to put some
numbers around the concepts that we've been
sort of talking about.
David Tees: Okay. Let me - hopefully I'll remember all
the questions, but the first one, I think,
on the - we own 30.8% of the facility, which
is two 1,250-megawatt units.
Zach Schreiber: Yes, sir.
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David Tees: So we get 370 megawatts out of each unit.
And you can pretty much, when they're in
operation their fully loaded average over
the last several years would be, up until we
had these forced outages, would be around,
when they're in operation 94% capacity
factor.
Zach Schreiber: Okay. Is there any way I can do the
arithmetic - I guess so, I mean, are you
saying that the sort of margin erosion from
a South Texas project on a per unit basis is
just the delta between the nuclear and the
coal and the lignite and coal?
David Tees: Yes. We sell entitlements in the four
different zones in Texas and the nuclear is
what we call the south base load product and
we sell it at a certain energy cost and we
have the Houston coal units and we have the
lignite units in the north. And so the big
delta there is serving nuclear with coal.
Zach Schreiber: And that 1,250 megawatts of reserve, how
much of that is gas and how much of that is
lignite and does the lignite cover 100% of
the South Texas project unit that's down.
David Tees: Yes. We have 750 megawatts of base load
Houston product that we keep in reserve and
we have 500 megawatts of gas. So it covers
the entire facility.
Zach Schreiber: And there no other contractual claims or any
other claims on that 750 megawatts of base
load Houston coal?
David Tees: No.
Zach Schreiber: Okay. And then on the revenue side can you
just talk about in terms of these capacity
auctions, I think you mentioned it looked
like a doubling kind of in the low 20s in
dollars per kW month in lignite and coal
into low 30s on the nuclear and it was
double the capacity auctions, you know, on a
year over year basis. What was embedded in
your original expectations of this $1.10,
$1.30 and, you know, just what portion of
your capacity are you effectively assuming
will receive this higher capacity auction
price. Is it just a portion that is
contractually hedge there or is there some
expectation that when the rest of the
unhedged capacity comes to the capacity
auctions or comes to market another way it
will receive that pricing?
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David Tees: Now let me see if I can answer that. We have
the Texas Public Utility Commission mandates
that we sell 15% of all of our capacity and
we have the option agreement with Reliant
Resources in which the other 85% must be
sold in the auctions less the 1,250
megawatts we keep in reserve. So we're
selling all of our, excuse me, 100% of all
of our products are put up for auction.
As far as the - what we've seen in the
differential on pricing, I can give you a
couple of examples.
Zach Schreiber: Could you?
David Tees: Excuse me?
Zach Schreiber: Yeah, that'd be great.
David Tees: The - in 2003 in the March auction - and
these number are all posted with the Texas
Public Utility Commission. We furnish these
publicly. In July - for July entitlements we
sold base load Houston at $24.50. Last year
in the March auction the same base load
Houston product we sold for $11.25.
Zach Schreiber: And this is - and that's on dollars of
revenue per kilowatt month.
David Tees: That's $11.25 per kilowatt month. And in the
north in July this year we sold at $27 a
kilowatt month in July and last year it was
at $15.76. In the south, which is the
nuclear we sold at July again at $32.75
kilowatt month versus 16.76 last year.
Zach Schreiber: And if we were to just look at all of your
capacity we should just take this sort of
break down of your capacity and allocate
these different metrics to the nuclear - to
the lignite in the different regions and
then assume that the back up lignite can
replace the nuclear. Is that the way to do
it? I mean - you're not contractually
precluded from the person or entity that
bought you the power i.e. [UNINTELLIGIBLE]
some green requirements of the state from
replacing nuclear with lignite are you?
David McClanahan: Oh, no. I mean, we run our fleet as a
portfolio. We serve our entitlements in the
cheapest way we can.
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Zach Schreiber: Got it.
David McClanahan: And so we can - you know, this is our fleet
to run and we run it on the most efficient
way. Now what you have to remember though
the summer months are the highest priced
capacity months. You'll see lower cost,
lower prices in the shoulder months than you
do in the summer. So you have to have a full
spectrum to be able to understand the full
revenue impact. But I think it's safe to say
that prices are up significantly as David
indicated. We had anticipated in our
guidance that prices would be up. We had
anticipated forced outages because you have
to be prudent. We're going to have forced
outages. We know that. That's just the way
power plants run. And we took all that into
consideration in coming up with our earnings
guidance.
We have seen a little bit better capacity
prices than we had originally anticipated,
but, you know, we have some issues with
South Texas that we need to have full
clarity in and so at this stage, we still
believe the $1.10 to $1.30 is appropriate.
Zach Schreiber: And - would that be - that would be
appropriate for how long a prolonged outage
for, you know, what you think now for the
summer - so you can do that $1.10, $1.30
assuming this plant doesn't come back until
Labor Day.
David McClanahan: Well, certainly our guidance contemplates
based on what David said, that this plant
wouldn't be returned until late summer. So
certainly it would cover that.
Zach Schreiber: So it covers late summer. Thanks so much.
David McClanahan: Thank you.
Operator: Your next question comes from David Frank of
Zimmer Lucas Partners.
David Frank: Oh, hi. Good morning.
David McClanahan: Morning, David.
David Frank: I just wanted to follow-up on Zach's
questions here. Of the 750 megawatts of
back-up base load generation I think you
said 500
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megawatts was gas and 250 lignite and coal.
David McClanahan: 750 lignite and coal.
David Frank: It's 750 lignite coal.
David McClanahan: Correct.
David Frank: And then I thought I heard someone mention
500 megawatts of gas somewhere.
David McClanahan: You did.
David Frank: Yes.
David McClanahan: We have 1250 in reserve, 750 is base load
coal and lignite, 500 is gas. The fact is we
even have more gas than that, but we have
mothballed some of our gas units because we
haven't sold them, but we could bring them
back if we wanted to, but clearly we have
1250 total in reserve.
David Frank: In reserve. And then you have mothballed you
have another, what is it? About 950?
David McClanahan: For the summer. We currently have about 3400
in laid up state.
David Frank: Right.
David McClanahan: We'll bring some of those back for the
summer because we've sold entitlements to
those units, but we're not - we don't need
and we haven't sold at least 900, a little
over 900 megawatts of gas-fired power and so
we'll leave it laid up.
David Frank: Okay. Well, I understand you're calling some
back because at least on a cash flow basis
it makes sense to run these units. So it
looks like you have about 2100, 2200
megawatts in reserve if you needed it in
total for the summer.
David McClanahan: Absolutely. The 1250 plus the 900, yes,
that's right.
David Frank: Okay. And my other question is why would you
sell any capacity forward for '04 or '05 if
someone else is going to own those plans?
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Is it just a prudent thing to do or are you
afraid that, you know, Reliant if they
needed probably greater than 50% of the
capacity to meet their own POLR
requirements -
David McClanahan: Well, obviously we don't know if Reliant
Resources is going to buy this company or
not or our interest in the company. We think
it's prudent to do it. I think that there
are lots of folks including Reliant
Resources that are looking to buy some power
for next year and beyond so I think overall
it's just a prudent thing to do until they
exercise their option we won't know if
they're going to buy it or not.
David Frank: Oh, so they could be one of the large
purchasers of the capacity for next year.
David McClanahan: Absolutely. As you know, Reliant Resources
has a very large retail load right here in
and around Houston, Texas where these plants
operate. So I would expect that they would
be a participant in any auctions we had like
that. Yes.
David Frank: Okay. And my last question is, I guess,
related to CenterPoint and that is can they
book ECOM earnings on purchased megawatt
hours or does that only the backup of ECOM
only relate to megawatt hours that are
actually physically generated?
David McClanahan: It's based on our generation, David.
David Frank: Okay. All right. Thank you very much.
David McClanahan: You're welcome.
Operator: Your next question comes from Debra Bromberg
of Jeffries and Company.
Debra Bromberg: Hi. My questions were answered. Thank you.
David McClanahan: Thank you, Debra.
Marianne: All right. I think we're going to take a
couple more questions and go ahead.
Operator: Your next question comes from Paul Cho of
Steadfast Financial.
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Paul Cho: Hi. Can you hear me?
Marianne Paulsen: Yes. Yes, we can.
Paul Cho: Hi. I just have a few quick questions. How
much - what was the megawatt hours generated
in the first quarter versus last year?
David McClanahan: Let us get those numbers.
Paul Cho: And while you're looking those up I was
wondering just going back to an earlier
question, what was the realized capacity
price in dollars per kilowatt month in the -
this quarter versus the previous year.
David McClanahan: In the what quarter?
Paul Cho: In this quarter versus previous year.
David McClanahan: In the first quarter.
Paul Cho: Yep. And if you don't have that handy, what
was your CFFO for the quarter?
David Tees: I'm getting it, just a second. The
generation for this first quarter of '03 was
about 9,267,000 megawatt hours.
Paul Cho: 9.2 million
David Tees: And the pricings - let me just give you some
examples - we'll look at say February the
base load Houston -
Paul Cho: Actually what I was looking for - at the
year-end results you gave sort of an all-in
capacity price. I was wondering if you had
that handy.
David McClanahan: You know, Paul, we don't.
Paul Cho: Oh, really.
David McClanahan: No. Not right now. We could try to get that.
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ID# 9660771 PAGE 20
Paul Cho: All right. That's not a problem. How many
megawatt hours did you sell in last year's
first quarter?
David McClanahan: That we generated?
Paul Cho: That you sold.
David McClanahan: Well, there's a difference between selling
and generating as you know.
Paul Cho: Right. I want to know how many you sold
actually.
David Tees: Our generation in last year was about
10,513,000 megawatt hours in the first
quarter.
David McClanahan: That was the generation. He's asking - now
how many did we actually sell? In the first
quarter we sold of this year we sold 9.3
million, the first quarter of last year we
sold 12.6 million.
Paul Cho: 9.3 this quarter and last year was 12.6.
David McClanahan: Correct.
Paul Cho: Okay. And what was your cash flow from
operations in the first quarter?
David McClanahan: I don't think we've disclosed that. It'll be
in our 10Q when that comes out here very
shortly.
Paul Cho: Okay. That's great. Thanks a lot for your
time.
Marianne Paulsen Okay. I think we'll have time for one more
question please.
Operator: Your last question comes from Jeff
Chrzanowski from Deutsche Bank.
Jeff Chrzanowski: Hi. Good morning. I just have, I guess, a
couple of questions surrounding operating
expenses. I was hoping you might be able to
put a - put some bounds on the potentially
higher operating expenses for over budget
that you may realize from this extended
outage.
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David Tees: As far as the maintenance cost for doing the
inspection and repair we're anticipating at
this time somewhere in the $5 - 6 million
range and so we would have 30% of that would
be our portion of it.
Jeff Chrzanowski: Okay.
David Tees: As far as maintenance and the repair cost.
Jeff Chrzanowski: And that, I guess, that would be what
perhaps is over what you have budgeted for
that or is that primarily within what you
expected it to be.
David Tees: That's over our budget.
Jeff Chrzanowski: Okay. And my -
David McClanahan: Of course, Jeff, you know, it's pretty early
in the game, but that's an early estimate.
Jeff Chrzanowski: Okay. My second question, I guess, is also
surrounding operating expenses. I was
wondering if you could just review for me
any upward pressure in operating expenses. I
believe that you were expecting some higher
insurance and pension costs and also what
potential cost savings you expect to realize
this year, too, because I know we'll be
realizing some savings from the mothballing,
but I have heard different numbers thrown
out, perhaps 10 million, perhaps 20 million
and I was wondering if you might be able to
narrow that down for me.
David McClanahan: Yeah. Hang on just a second here. Let us -
you know, the way we look at this is your
pension - you're going to have higher
pension and insurance cost certainly on the
order of $20 million or so and we believe
that we'll be able to offset those costs
through the early retirement program we
have, through the mothballing of units,
things of that type. So we believe we can
offset those costs. Now some of the
incremental costs that we might incur in
connection with the STP outage we have not
figured out how to offset those yet.
Jeff Chrzanowski: Okay. Thank you very much.
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David McClanahan: You're welcome.
Marianne Paulsen: Okay. Well, thank you very much. What I
would like to do before I close this call,
is at the very beginning in my introductory
remarks I'd said that we might - if we talk
about EBIT that we had provided a
reconciliation for that. In CenterPoint
Energy's conference call we will be talking
EBIT for the various segments including
Texas Genco and in CenterPoint Energy's
financial press release that we also issued
this morning there is a reconciliation in
that document in the financial statements,
which we will post and have posted on our
website at CenterPointEnergy.com.
With that, I think I will close the call and
thank you all for participating in the
conference call this morning. And we
appreciate your attention and support. So
have a great day. Talk to you later. Thanks.
Operator: This concludes today's Texas Genco first
quarter 2003 earnings release conference
call. You may now disconnect.
[END OF REPORT]