CenterPoint Energy Inc (CNP) 2003 Q1 法說會逐字稿

Good afternoon.

My name is Thea, and I will be the conference facilitator.

At this time I would like to welcome everyone to the CenterPoint Energy first quarter 2003 earnings conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers remarks, there will be a question and answer period.

If you would like to ask a question during this time, simply press star and the number one on your telephone keypad.

If you would like to withdraw your question, you may press star and the number two on your telephone keypad.

Thank you.

Miss Paulsen, you may begin, Ma'am.

Okay.

Thank you, very much.

This is Marianne Paulsen, Director of Investigator Relations for CenterPoint Energy.

I would like to first welcome you to our first quarter 2003 earnings conference call and thank you for joining us this morning.

As you may know, Texas Genco also released earnings today and had a conference call just prior to this one.

If you would like to listen to a replay of the Texas Genco conference call, you can go to the Investor Relations section of their website, www.txgenco.com.

On our call this morning, although we will comment on Texas Genco's result which are reported in CenterPoint Energy's electric generation segment, our primary focus will be on the other segments of the company.

On our call this morning, David McClanahan, President and CEO of CenterPoint Energy and Gary Whitlock, Executive Vice President and CFO, will lead the discussion.

In addition we have other members of management here who may assist in answering questions on CenterPoint Energy following the prepared remarks.

In discussing our results during this call, we will refer to earnings before interest and taxes, or EBITs which is a non-GAAP financial measure.

We have provided a reconciliation of EBIT to the most comparable GAAP financial measure in the financial statements included in our earnings press release that we issued this morning.

This press release is posted to the centerpointenergy.com website.

I also need to remind you that any projections or forward-looking statements made during this call are subject to the cautionary statements on forward-looking information in the company's SEC filing.

Before Mr. McClanahan begins, I would like to mention that a replay of this call will be available until 6:00 p.m.

Central time through Thursday May 1, 2003.

To access the replay, please call 1-800-642-1687 and enter the conference ID number 9662071.

You can also listen to an on line replay of the call via our website at www.centerpointenergy.com under the Investor's section.

With that, I would now like to turn it over to David McClanahan.

Thank you, Marianne.

Good morning, Ladies and Gentlemen.

Thank you for joining us this morning for our first quarter earnings call for CenterPoint Energy, and thank you for your interest in the company.

As Marianne mentioned, this morning we held a conference call for Texas Genco and discussed their business during that call.

So during this conference call, we will not go into great detail regarding Texas Genco.

In a few minutes, Gary will discuss the performance of each of our business segments and will talk about the various financings that we have completed in the first quarter.

But first I would like to give the financial highlights for the quarter and discuss some key activities that we accomplished since the beginning of the year.

As we reported this morning on a consolidated basis, CenterPoint Energy had income from continuing operations before the cumulative affect of an accounting change of $81 million or 27 cents per share.

This compared to 145 million or 49 cents per share for the first quarter of 2002.

I'm encouraged that we reported solid operational performance and increased operating income today.

However, the improvement from our businesses was not able to offset this substantial increase in our borrowing cost.

In the quarter we also recorded an after-tax, noncash gain of $80 million or 27 cents per share for the implementation of FAS number 143, which is the accounting for asset retirement obligation standard.

This gain resulted primarily from the elimination of plant removal costs, which had been previously reflected in our accumulated depreciation accounts and revised estimates for mine reclamation cost.

All of this gain related to Texas Genco.

After taking this gain into consideration on a reported basis, net income was $168.4 million or 56 cents per share.

Before Gary reviews the results of each of the business segments for the quarter, let me highlight some key achievements since the beginning of the year.

We amended our $3.85 billion bank credits facility in February, extending the term to mid 2005 and eliminating $1.2 billion in mandatory payments that we were facing this year.

We accomplished several important objectives.

First, the termination date of the facility was extended beyond the time we expect to Monday monetize Texas Genco and recover our stranded investment.

Second, we eliminated the mandatory payments which were due to occur in the first half of this year and were putting undue pressure on the company.

This significant achievement allowed us to overcome the immediate liquidity concerns and opened up access to the capital markets on much more reasonable terms.

In that regard, we successfully accessed the capital markets and issued securities totally over $1.5 billion at CenterPoint Energy Houston Electric and CERC, which is our gas, LDC and pipeline subsidiary.

We established a $200 million revolving credit facility at CERC, providing that subsidiary with liquidity and substantially eliminating it's reliance on the parent for working capital needs.

In early April we remarketed $175 million in pollution control bonds at CenterPoint Energy.

These were bonds we had purchased in November and December of last year when they were due to mature and had intended to remarket them once we gained better access to the market.

And finally, we permanently reduced the $3.85 billion dollar parent facility by $50 billion.

While small, this eliminated 12% of the warrants due to vest at the end of May.

These warrants were to be issued in connection with our amended bank agreement.

Gary will discuss this a little more a little later in the call.

In addition, early in the quarter, we distributed 19% of Texas Genco common stock to CenterPoint Energy shareholders.

This partial public float of Texas Genco shares will be used in calculating the fair market value of our generation assets in our stranded cost recovery proceeding next year before the Texas Public Utility Commission.

We also sold our remaining two investments in Latin America, a cogeneration facility and a small distribution company in Argentina.

Finally, we paid a quarterly dividend of 10 cents per share to CenterPoint Energy shareholders in March.

In arriving at this dividend level, our board considered our near term liquidity needs, as well as our earnings, cash flow, and the ultimate sustainability of our dividend level.

This morning we reiterated our 2003 earnings per share guidance of between 85 cents and $1 per share for CenterPoint Energy.

This guidance reflects our outlook for continued solid operational performance from our business units, as well as the higher borrowing cost that we face.

This morning Texas Genco also reconfirmed its previous guidance from 2003 earnings per share of between $1.10 and $1.30 per share.

Let me end by highlighting the status of several important components of our overall strategy.

We remain on track to deleverage our company through proceeds from the sale of Texas Genco and the recovery of stranded investment.

The Texas law that enacted electric deregulation in Texas and provides for full recovery of stranded investment remains intact.

The Texas legislature meets every other year and is currently in session.

There have been no bills introduced to date that would change any of the provisions that provide for our recovery of stranded investment.

This legislative session ends in early June.

We have now gained financial stability and turned our full attention to improving our businesses and earning our regulated rates of return.

We'll use the next 18 months or so to re-examine our key processes and business models, and make improvements.

We'll also continue to seek rate relief where warranted.

I'm convinced we'll be a stronger company and one ready to grow when we are finished with these efforts.

And finally, let me re-emphasize, our focus remains on our core electric gas and pipeline businesses.

We have a good balance mix of businesses, and one with a solid base from which to expand.

We are committed to keeping our focus on regulated businesses and businesses complimentary to our regulated businesses.

We look forward to strengthening our balance sheet, improving the performance of our businesses, and expanding where we can add to shareholder value.

Let me now turn the call over to Gary, who will discuss our operating results and financing in more detail.

Thank you, David.

First, let me say that we are very pleased with the progress being made by our businesses.

Each business continues to implement their respective strategy in support of our vision of being America's leading energy delivery company.

Our goal is to increase shareholder value through the achievement of operational excellence and improve productivity across our businesses, all the while continuing our strong tradition of safe and reliable service to our customers.

Now, let me review the operating results of our business segment.

Let me remind you that we report four core segments: The electric transmission and distribution segment, the electric generation segment, which is comprised of the operations of Texas Genco, the natural gas distribution segment, and the pipelines and gathering segment.

Since the restructuring of the electric market which began in January of 2002, this quarter is the first time that we can make meaningful quarterly comparisons for all four segments.

Let me begin with the electric transmission and distribution section.

The unbundled transmission and distribution business which remains regulated is reported in our electric transmission and distribution segment.

Also included in this segment are all the impact from the generation related regulatory assets recoverable by the regulated utility, including the ECOM true up.

ECOM stands for excess cost over market and refers to the stranded cost model developed by the Texas Public Utility Commission in connection with industry restructuring.

As you know, stranded investment will not be determined until 2004.

Therefore, for 2002 and 2003, the Texas electric restructuring law provides that a regulated utility may recover the difference between the market price of power sold at auction and the price of power in the PUC ECOM model, as part of the regulated utility's 2004 stranded cost proceedings.

This amount is noncash and is recorded as a regulatory asset.

In addition, the 2002 results included EBIT from nonrecurring transition revenues.

First let me discuss the results for the ongoing electric business, the unbundled transmission and distribution utility which excludes ECOM and nonrecurring transition revenues.

The transmission and distribution utility reported EBIT of $82 million in the first quarter of 2003, compared to $104 million for the same period of 2002.

Just to remind you, beginning with the opening of the retail market to competition in January 2002, the regulated utility has recovered its cost of service through an energy delivery rate.

I would add that under the Texas electric restructuring law, our regulated transmission and distribution utility cannot buy and resell electricity, and thus is not subject to any postrestructuring commodity risk.

The T and D utility was impacted by three primary factors during the first quarter: Strong customer growth, higher pension and insurance expenses, and reduced industrial revenue.

We added over 50,000 metered customers since last March, which is a 3% growth rate.

However, the increased revenue from growth in customers was offset by decline in revenue from industrial and commercial customers due to reduced billing demand.

Operating expenses for the TDU, excluding nonrecurring expenses associated with the transition, increased by $9 million, reflecting an increase in benefit expenses primarily related to pension and higher insurance costs.

In addition our continued focus on process improvements reduce the TDU's capital expenditures for the quarter by approximately $20 million versus the same quarter last year, while improving the reliability of our system.

The next component of this segment is EBIT from the ECOM true up.

We reported $132 million this quarter, which is a reduction of $9 million from last year's first quarter of $141 million.

The decrease in ECOM was expected since the prices that Texas Genco received in their capacity auction were higher this year.

And finally, included in last year's first quarter was nonrecurring EBIT of $14 million related to the transition to the deregulated electric's market.

Electric generation.

Our power generation operation in Texas is called Texas Genco, and is reported in our electric generation segment.

Just as a reminder, in 2003, Texas Genco will remain a fully consolidated entity of CenterPoint Energy and be reported in the electric generation segment, albeit with a minority interest of 19%, which is reflected in our financial results.

As you know, we expect Texas Genco to remain with CenterPoint Energy until 2004.

At that time Reliant Resources has an option to purchase the stock we hold.

If Reliant Resources does not exercise that option, we still intend to monetize these assets, if they are not part of our strategic direction, which as you know, is the focus on deregulated energy delivery business.

This segment reported a loss before interest in taxes of $17 million in the quarter compared to a loss of $52 million last year.

While prices were higher and revenues improved, Texas Genco did experience a net loss in the quarter for two primary reasons.

First, Unit Two of the South Texas project experienced an extended outage beginning in December of 2002 due to a mechanical failure, causing Texas Genco to operate higher energy cost units to meet its financial obligation.

As you know, Texas Genco owns a 30.8% interest in the South Texas project, which is a nuclear generating plant consisting of two 1,250 megawatt units.

The unexpected negative margin impact of $23 million attributable to this unplanned outage was the primary driver contributing to the loss in the first quarter.

The unit was restored to full power on March 14.

Second, the first quarter is typically not a strong quarter due to seasonal effects, such as lower sales volumes and planned maintenance at our generating unit.

Nonfuel operating expenses in the first quarter increased by $10 million.

A major contributor to this increase was the STP Unit Two turbine repairs related to the outage.

Our capital expenditures declined significantly for the quarter to $40 million compared to $94 million in 2002, as we are in the final stages of our Knox reduction environmental capital program.

Now, let me share with you what David Tees, President and CEO of Texas Genco discussed this morning regarding the recent outage of Unit One at the South Texas project.

During a routine refueling and maintenance outage in early April, engineers found a small quantity of residue from reactor cooling water at one location in the Unit One reactor containment building.

No other residue was found in Unit One or in the plant's twin Unit Two reactor when it was inspected during a refueling outage in the fall of 2002.

Upon discovery of the residue, STP officials immediately reported findings to the Nuclear Regulatory Commission.

STP's managers and engineers are conferring with industry experts to develop a corrective action plan.

The nuclear regulatory commission must approve any corrective action plan before it is implemented.

The unit will remain shut down until any necessary corrective action is completed.

While the unit remains out of service, Texas Genco will meet its existing power sales obligations from other generating units and/or from purchases from third parties.

Until inspections are completed and an acceptable corrective action has been developed, we're unable to predict the economic impact of this outage and when the unit will be returned to service.

A protracted outage at Unit One would adversely affect the company's operating results if the cost of the replacement power is materially greater than the cost of the power produced by STP.

Having said this, in order to mitigate the financial impact of forced outages on our generating unit, we maintain 750 megawatts of base load generation, and 500 megawatts of gas generation as an operating reserve.

This base load generation operates at an energy cost of $16 to $17 a megawatt hour, while nuclear generation operates at about 4 to $5 a megawatt hour, and gas generation is presently at $55 a megawatt hour.

We have developed a preliminary schedule for the inspection, repair and return of this unit based on various scenarios, even though there are a myriad of unknowns, because this is more prudent than waiting until our inspections have been completed.

We anticipate that this unit will return to service in late summer based on this very preliminary scheduling.

Now I'd like to turn to our natural gas distribution segment, which reported an improvement in earnings in the quarter of $24 million.

Earnings before interest and taxes for the first quarter of this year was $134 million compared to $110 million last year.

A key focus for 2002 was to obtain rate relief in our gas LDCs, especially in Arkla.

The implementation of rate increases produced revenue gains in the first quarter of $11 million.

We continued to increase the number of natural gas delivery customers.

Also revenue improved as a result of colder weather, particularly in Minnesota, contributing $7 million to EBIT.

In addition, we experienced improved margins from our unregulated commercial and industrial sales business.

These cost of revenue drivers were partially reduced by higher employee benefit cost and bad debt expense.

Additionally the cost associated with a receivables facility, which was modified in November 2002, reduced EBIT by $4 million.

Prior to the amendment, these costs were reported as interest expense.

We believe our rate relief actions and productivity initiatives reflect our strong commitment to improving the financial performance of Arkla, as well as our other gas distribution businesses, and we are starting to see very positive results.

Turning to our pipeline gathering businesses, we reported EBIT of $45 million for the quarter, compared to $38 million last year.

This is a business that continues to produce consistent earnings and stable cash flows, and we expect this trend to continue.

In total, our business segments produce EBIT of $357 million in the first quarter of this year compared to $344 million for the same period of last year.

We will remain focused on the continuous improvement of each of our operations and their financial performance, both by increasing revenues and enhancing our operational productivity this year and beyond.

Once we recover our stranded cost and monetize Texas Genco, our financial flexibility will improve and our regulated businesses will continue to produce strong and consistent earnings and precash flow for the benefit of our stockholders.

Now let me give you an update on our financing activities since the beginning of the year.

When we spoke to you in early February, we were in discussions with our bank group to modify the payment schedule and other terms of our $3.85 million bank credit facility.

On February 28th we announced that we had amend the facility.

We eliminated the $1.2 billion in mandatory payment, which was a major constraint to our ability to access the capital market.

We also extended the term of the facility to June of 2005, which is beyond the period in which we expect to monetize Texas Genco and securitize our stranded costs.

In the amendment, we agreed to provide the bank syndicate warrants as an incentive to the company to access the capital market in order to reduce the size of the facility.

These warrants are subject to a proportionate vesting schedule.

Once we amended the credit facility, we have been able to access the capital markets in size and at reasonable rates.

On March 13 we issued $762 million of general mortgage bonds at CenterPoint Energy Houston.

On March 19 we issued $650 million of senior notes at CenterPoint Energy Resources Inc..

On March 25 we established a one-year, $200 million revolving credit facility CERC PFC to provide that subsidiary with additional liquidity for working capital need.

On April 2 we remarketed two pollution control bonds at CenterPoint Energy, Inc. totaling $175 million.

On April 7 we increased the CERC senior notes issuance to a total of $762 million by adding $112 million of additional note.

In total, over the course of a month and a half, we have sold $1.7 billion of debt security, and put in place a new $200 million credit facility, all of which address maturing debt, refinanced higher cost debt, and/or significantly enhanced our liquidity.

With the proceeds of the debt issuance we called $312 million in higher coupon first mortgage bonds.

We repaid a $350 million revolver which expired at the end of March.

We repaid $150 million medium term note which matured on April 21.

We refinanced $360 million of a $500 million November 2003 maturity at CERC, and we reduced the $3.85 billion bank credit facility by $50 million, which eliminated 12.5% of the first [INDISCERNIBLE] of warrants.

So what's next?

Now that we've completed all these financings, we've gained valuable financial stability at CenterPoint Energy.

It allows us to consider additional financing alternatives.

We are going to continue to evaluate all options to raise capital, to eliminate the vesting of warrants, and remove a potential dividend restriction that might otherwise apply beginning in 2004.

However, the financing options we choose will be those that will be in the best interest of our shareholders.

In summary, our businesses perform well, we achieved financial stability, and we positioned ourselves to execute our strategic plan.

And with that, I'd like to thank you for your interest in CenterPoint Energy, and now I'll turn the call back over to Marianne.

Okay.

Thank you, Gary.

I think we're ready for the Q and A session right now.

So why don't you prompt the callers on questions.

Thank you.

At this time I would like to remind everyone that if you would like to ask a question, you may press star, then the number one on your telephone keypad.

We'll pause for just a moment to compile the Q&A roster.

The first question comes from David Frank with Zimmer Lucas Partner.

Hi, good morning.

Congratulations on a great quarter.

Thank you, David.

David, I'm sure a lot of the questions I have are going to be asked by other people this morning.

Could you just remind us what the rate base is at Houston Light and Power?

That is, what is the transmission and distribution rate base?

It's about 3.3 billion at our last rate case.

3.3 billion.

Correct.

And what is your authorized capital structure?

It's 40% equity, 60% debt.

Okay.

And the second question is, do you plan on eliminating any of the dividend restrictions for next as per the amended credit facility?

Well, we have two restrictions.

One is we have a limit, an overall limit of 40 cents per share, per year.

But there's a potential additional restriction of 50% of trailing 12 months earnings, if we do not pay down the banks by $400 million, of which half of it would come from equity or equity linked securities.

We are looking at this very hard.

Obviously, our desire is to eliminate that restriction.

We have until the end of the year to do that.

And we hope to accomplish that.

We really are looking at what's in the long-term best interest for our shareholders, and will make the decision based on that.

Thanks a lot.

Congratulations, again.

Thanks.

Our next question is from Paul Patterson, Glen Rock Associates.

Hi, how are ya?

Good, Paul.

I was wondering if you could just give us an idea about how much is invested in the South Texas nuclear project, Unit One, in particular?

Yes, we can.

I think, Paul, you may have asked that on the Texas Genco call and we failed to answer that.

And it is a little bit of a complex story, but there's probably a little less than $200 million in Unit One.

Okay.

So you only have $200 million invested in Unit One?

Remaining net book value.

Okay.

That's great.

And then, in terms of the $400 million of equity or equity linked securities, when do you think we'll get a clear picture on that?

Okay.

It's not really 400, it's 200, to eliminate any additional dividend restriction.

You know, we're looking at that.

We have until the end of the year, but we're obviously looking at the marketplace today and what type of securities might be attractive.

Okay, great.

Thanks a lot.

Our next question comes from Michael Goldenberg, Luminous.

Hey.

Good morning, guys.

Congratulations on a good quarter.

Thank you.

Hey, just a quick question on that whole dividend restriction thing.

This accounting benefit that you guys took, will that go towards the GAAPs PS?

Hang on just a minute.

I think it will.

That's the nod I'm getting.

I think we're going to have to check the specifics of that, you know.

I think so, but let us come back to you on that.

Okay.

And along the same lines, if you can answer the similar question for if you guys monetize Texas Genco, would you have to move that into discontinued ops, or would you be able to use Texas Genco's GAAP earnings against the dividend restriction?

Michael, that's a good question.

It's one that we continue to look at.

Until we actually have a determination that the option has been exercised, I think it would continue to be in, you know, continuing operations.

But if, in fact, the option is exercised, I think it would have to be moved to discontinued ops.

Okay.

And just two general questions.

One, as I'm looking at your ECOM true up, it seems to have pretty much been the same in Q1 '03 as it is in Q1 '02.

If I understand correctly how it works, it seems that that number is the difference between what you expect it to sell capacity for, and what you actually sold Texas Genco capacity for.

Since your capacity payments have increased considerably in the first quarter over the previous years, yet ECOM true up stayed the same.

Could you explain why, even though you've received much better capacity payments, you were still able to collect a high ECOM true up?

Yes, good question.

First, the way the ECOM true up works, you take the megawatt hour sales, megawatt hours you generated, times the PUC auction prices, less the amount of fuel cost used to generate those megawatt hours, and you compare that to the similar numbers that were used in the PUC ECOM model that was developed, as you know, several years ago.

In this particular case, I think the difference is that the fuel cost increased, as well as the revenues increasing, and the net impact was that ECOM was only reduced by a little less than $10 million.

Would something have to do with the fact that you just produced 3 million less megawatt hours?

Certainly megawatt hours and how much you generate has an effect on that calculation, yes.

One final question.

I heard you guys may have request some transitional increased charge once the ECOM true up charges runs out the end of December.

Correct me if I'm wrong if that's not the case.

If it is, could you please update us on where you are with PUC on that?

The way we interpret and read the legislation that enacted deregulation in Texas is, once you get a determination of stranded investment, then you can start to recover that stranded investment amount.

Now, as you know, we intend to seek a securitization order and sell securitized bonds, but during the interim, between the time that the PUC actually finds we have a stranded investment and we get that financing order to sell bonds, we will seek to have a transition charge, and charge that on our delivery rate.

Okay.

So you will collect the transition charge first.

And then once you securitize, then you will actually start matching up revenues and expenses?

But until then, you'll actually get an intermediate benefit?

That is our plan.

That is what we plan to seek.

When do you think you may get that motion under way?

I think it is going to be part of the stranded recovery proceeding that we file next year, and that is litigated at the Public Utility Commission next year.

I don't think we're going to get an early answer.

I think it will come out about the time our stranded investment amount is determined, which, as you know, the PUC has 150 days from January 12th, which is the day we expect to file to rule on our case.

Okay.

So sometime Q1, Q2 of '04?

Correct.

Thank you very much, gentlemen.

Congratulations.

Your next question comes from Jonathan Rojewski of Goldman Sachs.

Hello, everyone, again.

Following up on that line of questioning.

If we assume you get the final order from the commission, let's say midyear next year, that would -- and you get your securitization let's say, for simplicity's sake, at the beginning of 2005, that means you get six months of that CTC charge.

Should we be thinking about the magnitude of that recovery as, let's say, if you get $4 billion in total cost recovery, $2 billion -- let's say a billion and a half you get through the sale of the 81%, so then you're talking about another $2.5 billion that's recoverable for one-half of the year.

Is that how we should be thinking about that on a financial basis?

I think whatever the stranded investment amount is, I would expect we would only be recovering our carrying cost on that, and not any type of amortization.

Okay.

The principal would be through securitization, but the carry on that amount is what we would seek to keep us whole.

Okay.

And it wasn't clear -- it's not clear to me whether or not that is prescripted, or whether you need to actually get the commission's authorization in order to have that interim recovery.

I think the commission has to authorize it.

Clearly it's a rate change and the commission is going to have to act on our request, but we will seek to have that.

Okay, fine.

And then, as I'm looking at the electric generation, as well as the ECOM piece in the T and D financials here, if you're doing comparative purposes, '02 versus '03, are you guys doing this on a 100% both years, or have you adjusted for your 81% ownership in the '03 quarter?

The minority interest is taken out and is reflected in our financials.

But above the line it's 100%.

Okay.

And then I guess lastly, you guys remind me, because I think another company in the sector is dealing with trying to get some sort of waiver to pay their dividend, given that they have a negative retained earnings balance, and that seems to be your situation.

Do you guys have a waiver, or how are you guys being allowed to continue to pay the dividend in that situation?

When we received our order out of the commission in connection with the restructuring, they approved a payment of our dividends out of surplus, as opposed to retained earnings.

So I think we already have that approval.

Okay.

So you got that from the commission, you didn't need to get anything from the SEC?

No, from the SEC, I'm sorry, I was speaking about the SEC.

Okay, so the SEC is already --.

And how long does that last or what's the duration of that ruling?

We will renew -- these financing orders, I think, basically run through June of this year, so we'll renew that order later on this year.

Okay.

What would the term of that likely be upon renewal, a year at a time, six months at a time?

I think we would seek to have it run through early 2006, is what our plan is.

Okay.

So that's about three years.

Okay.

Thanks, David.

Ok.

Your next question is from Maura Shaughnessy with Massachusetts Financial Services.

Good morning, a few questions.

First, could you just outline the cap spending and DD&A in '03 and '04?

I'm going to ask Gary to do that.

2003?

And 2004, please.

2003, cap spending, including Texas Genco, is about $680 million. '04, just a moment, '04, obviously in '04, Texas Genco will only be with us for part of the year, so cap spending, about $580 million.

And Maura, if you look at the businesses on a go forward basis, our run rate for cap spending should be probably in the 25 to 550 million level.

Any thoughts on DD& A in the next two years?

Just a moment. 2003, about $617 million.

Just a second on 2004.

About $580 million, or so.

Okay.

Thanks.

Just in terms of, just on the release that I'm looking at, I don't see a balance sheet.

Can you give me a sense as to where the net debt position ended at the end of the quarter?

It's about -- total debt is about a little more than $11 billion, that includes securitization debt.

And the cash at the end of the quarter?

In terms of liquidity at the end of the quarter, if you look on -- let me answer now, if you were to look at today our liquidity position, it's very close to a billion dollars, a little bit less than a billion dollars.

If you look on a normalized basis, because we do have cyclicality in payment, we have approximately $650 million of liquidity.

Okay.

Just trying to understand the, and sorry for my ignorance on this question.

But let's assume, given the runup in TGN stock, that Reliant does not exercise its option next January.

In the way that the Texas commission will determine your -- the stranded cost situation, it can just use the 19% of TG& A that's out trading right now?

You don't need to sell the 100% to make the determination?

Is that correct?

Right.

Under the Texas deregulation law, there's a number of methodologies.

The company sought and received approval from the PUC to use the partial stock valuation methodology.

Which basically, they used the 19% valuation, gross it up to be equivalent to 100%, and then they can add up to a 10% premium to that, in terms of valuing the underlying assets of Texas Genco.

And we do not have to actually sell the stock to Reliant Resources in order to use that methodology.

And again, assuming Reliant does not exercise its option, how quickly do you think you would sell the remaining parts of TGN, or I guess, what is overall strategy if Reliant does not exercise its option?

We would seek to find buyers of the stock initially, just like we are now.

We think that, you know, this is a very attractive portfolio.

We think there would be other people interested in selling it.

If we found that wasn't the case after we did a fair amount of work on it, then we could always go back and sell it a unit at a time.

But our first choice would be to sell our 81% ownership interest, the stock interest we have in Texas Genco.

Okay.

Thanks very much for your time.

Your next question is from Jay Medea with [INDISCERNIBLE].

Hi.

Congrats on the quarter.

I just wanted to ask about the May 28 deadline.

Is that something you're considering possibly raising capital, paying down that $400 million to avoid?

Certainly, Jay, that is one of our options, and we're looking at that very closely.

Okay.

We've already paid down 50, so I know it's small, so we only have 350 left to deal with.

Okay.

But that might not be as important to you as the second one, the one that's by year end, because the one at year end also has the dividend restriction attached to it?

Would that be fair to say?

My view is they are both important.

Certainly the second one has an additional element of importance because of the dividend restriction.

But I think the first one is just as important, and we're focused on it as we speak.

Jay, this is Gary.

I think you also on the dividend restriction, just to be clear, the potential restriction that would come into play would be 50%, a dividend no greater than 50% of net income.

In our amended bank facility, the dividend is limited to no greater than 40%.

So therefore, from a practical perspective, a dividend restriction that would come into play only has applicability to the extent your earnings would be less on a trailing 12-month basis.

So that restriction might not carry any weight anyway?

That's correct.

Okay.

And as far as the Texas Genco -- I'm sorry, as far as the true up and stranded cost recovery situation, is there anybody out there that disagrees with your assessment of the Texas law or the implementation of that law?

Jay, not to my knowledge.

We've had, obviously, as a result of a lot of financing, we've had lots of different people, banks, investment banks, various lawyers, look at the law, and I have not heard anybody take issue with our interpretation.

Okay.

Thanks.

And then, final question is, at which point would you be able to raise the dividend over the 10 cent per quarter?

Would that be in 2005 when this current facility gets refinanced or expired?

Once we get this facility paid down, I'm sure we could get relief.

But yes, from a theoretical standpoint, it's June of '05.

But I would expect this would be redone before then, as soon as we get our stranded investment back and we pay down these banks, we'll kind of redo all of our bank agreements.

Oh, I see.

Thanks.

Congratulations again.

Thank you, Jay.

Your next question is from Chris Melendez from UBS Principal Finance.

Good morning.

Is it unreasonable to assume that the lost margin associated with the Unit Two outage at STP would be similar for a similar period of time for a Unit One outage?

I would suggest it's kind of the best thing that's out there right now.

However, energy prices move around.

In the first quarter, we had some high gas prices, especially in February.

They have come down some, but they are still pretty high.

I think it's not a bad way to look at it, but certainly, you know, it depends on the energy prices over the next three months.

Okay.

Thanks for that.

Your next question is from Jay Dobson, Deutsche Bank.

David, two conceptual or hypothetical questions for you.

On STP, I know it's early yet, but any capital you spend to repair the plant, I assume you'd have no avenue for recovery of that capex, it wouldn't get tossed into the stranded cost or the sort of regulatory issues you'll deal with in January of '04?

No, it will not be part of our stranded investment true up, no.

Okay.

Fair enough.

Onto ECOM issue versus the transition charge you'll be requesting.

Conceptually, should we think of those as being about the same size, or would you actually have some leakage once ECOM and TTM is gone and the transition charge is in effect, such that there would still, although a much smaller impact, still be a bit of a drag on '04 earnings?

Certainly once we get to the middle of the year and we get this charge in place, I think we would be kept whole from just a carrying cost standpoint.

But the first part of the year, there will not be anything there.

ECOM will be gone and we will not have this temporary CTC.

Certainly there's going to be some leakage in the first six months of the year.

Great.

Thank you so much.

Your next question is from Vadula Murti with SAC Capital.

Good morning.

Good morning, Du.

To kind of get back in terms of this dividend restriction, you implied that, in fact, if you think that earnings are not going to go below 80 cents, then the restriction doesn't even come into play.

So if that's the case, is there still any kind of a requirement to need to do $200 million of equity or equity link as part of this, or could you avoid that entirely?

Well, I think we don't want to be faced with that restriction if we don't need to be faced with it.

Certainly we're -- we would rather have only the 40 cent cap to deal with and not have to worry about the trailing 12 months.

As I just mentioned to Jay, the first six months of next year, without this interim and temporary CTC, our earnings will be under some pressure.

So we don't want to be faced with a potential limitation on dividends.

That's the reason we're so interested in getting it eliminated, if it makes sense for our shareholders to do that.

Okay.

And kind of following up on that part in terms of the potential earnings pressure, it would appear to me that basically here, if one wanted to try to kind of prognosticate, you know, first quarter of '04, the $132 million you have of ECOM would go away, as well as the $17 million loss at Texas Genco, so it would appear on an EBIT basis.

We would probably have a loss of about, about $115 million would be dropping out year over year.

Would that be accurate?

Certainly we would not have the ECOM.

We expect that in the first quarter we'll still have the Texas Genco reflected in our earnings.

You know, we hope that that's -- they have a good first quarter of next year, but they would still -- Texas Genco, I don't expect that we will close a sale even if Reliant Resources exercised their options before the second quarter.

But I thought you would consider those as discontinued ops and basically set those aside.

I think if it is -- you're right.

If the exercise -- if the option has been exercised, they would go to discontinued ops.

But I think the way the limitation works, it's GAAP income.

It is GAAP income.

And so discontinued ops is still income.

Okay.

And then that would also answer the earlier question with regard to the accounting gain you have here in the first quarter, any other charges or gains that happen along the way, because those would be considered GAAP?

That's exactly right.

Okay.

So we should be watching very carefully any possible accounting gains or charges between now and the end of the year on a GAAP basis?

Yes, I think that's a fair statement.

Thank you.

Thank you.

Your next comes from Phyllis Gray with Dwight Asset Management.

Good morning.

I was hoping you could give me a monthly estimate of the replacement costs for the nuclear unit that's out.

Well, it really depends on the energy prices, but let me kind of just review how we operate Texas Genco.

We have 750 megawatts of base load capacity that we do not auction.

We keep it in reserve really for unplanned forced outages.

The energy cost of producing power out of those plants is between $16 and $17 a megawatt hour versus the nuclear plant, which is between $4 and $5 a megawatt hour, so there's a $10, $12 differential there.

Now, we also sell power on an opportunity basis when they are running this base load, so we also lose the opportunity to sell, as well.

As I mentioned earlier to a question, the $23 million in revenues margin that we lost when STP Unit Two was down for the first two and a half months of the year is an indication of the impact that can be felt when you have a unit like this not operating, you're having to serve it with other units.

But it will really depend on where energy prices go, which, as you know, are highly dependent in Texas on where natural gas prices go.

Sure.

And then, could you give me an idea of what the monthly output in megawatt hours from the plant, or from your portion of the plant, is?

We have -- it's about 280,000 megawatt hours.

That's based on -- we own 385 megawatts of each one of those units and assume a very, very high capacity factor, because these units are base loaded, and they have a capacity factor in excess of 90%.

So you produce a lot of energy when those things are running.

Terrific.

Thanks so much.

Your next question is from David Graumhouse with Copia Capital.

Couple of quick questions.

In terms of thinking about interest expense for this year, are we fairly safe in, sort of, taking the expense for the first quarter and multiplying by four, or are there some things that may drive that up or down?

No, I think you're safe in making that assumption.

Okay.

Second question, I know that it had been noted in your 10-K, there was a $638 million difference between the book and regulatory value on the generation assets.

Is that an impairment that might have to be taken at some point, and is that potentially something that could affect GAAP earnings and dividend restriction?

Yes.

That has to be taken into account when we reconcile all of the dollars associated with Texas Genco.

As you know, we're depreciating Texas Genco assets.

The regulated book value was whatever it was at 12/31/01.

So the asset net book value continues to decline at Texas Genco.

It probably won't come exactly equal to each other, but they will get much closer than they are today.

Okay.

Great.

Thanks a lot.

Your next question is from Danielle Fife, Smith Barney.

Hello and congratulations.

Actually your earnings are well above what you anticipated originally.

Does that mean that your range is -- I mean, you are talking about the high end of the range in terms of earnings?

And also are you staying in the main area because of the potential impact of STP outage?

Well, our original earnings guidance of 85 cents to $1 per share, we still feel comfortable with that.

Certainly, the STP guidance of $1.10 to $1.30 was reflected in our guidance and we have confirmed that.

While we are pleased with the performance of our business units and what we've been able to accomplish, we're not ready to revise our earnings guidance.

We still believe 85 cents to a dollar is appropriate at this point in time.

We'll continue to look at that, and to the extent we believe it warrants a change, we'll do so.

In terms of the ECOM level, it was supposed to be declining very sharply, because you were, obviously, you obtained some much better prices.

Do you anticipate that this is also offset by outages at all, as it's an impact at all, or it doesn't at all, and you're still anticipating a sharp drop in ECOM?

We still anticipate ECOM will come down this year relative to last year.

But the bulk of it will be in the summer, in the peaking period?

There's a lot of moving parts there, because it's dependent on how much we generate, the fuel mix that we generate with.

It's really hard to give you an exact answer there.

Certainly $10 million was probably a little less than we thought it would decline, honestly.

As we move into the year, those numbers will be adjusted, but we think it will be lower, lower than last year, obviously.

The summer months, we have a lot higher capacity auction price, and you'll probably see even a further decline relative to last year because of that.

And, again, to make sure I'm not confusing two different things.

The ECOM level has nothing to do with outages or anything like that?

I thought it was a sort of mix of capacities that you could sell, so it must have a little bit of an impact on any kind of outages that you will incur.

Well, outages affect how ECOM is calculated, because the fuel cost--

Right.

--comes into play.

Yeah.

So it depends on what units you're running and the cost of producing power.

So it certainly impacts it, and I think you saw part of that impact in the first quarter.

Thanks.

Appreciate it.

Your next question comes from Angela Uttaro with Oppenheimer Funds.

Angela, your line is open.

Angela has withdrawn her question.

Your next question comes from Peter Hark with Salon Capital.

Good morning.

Good morning.

The guidance you gave for 2003 of 85 cents to a dollar, how much of that is ECOM earnings?

Well, last year we had $682 million of ECOM.

We believe that it is going to be substantially lower than that.

It didn't reveal itself in the first quarter, but we think that it is going to be substantially lower than that.

We haven't given any specific guidance on that number, and I hesitate to do so at this time.

Okay.

How about this?

Of the 3.3 billion of rate base at HL&P, how much of that is ECOM regulatory asset?

None of that is ECOM.

Those are all hard assets.

Okay.

What's the allowed return on the ECOM balance?

Today at the TDU, we earn 11 1/4% on equity.

We're not earning anything on ECOM through rates.

There is no earnings on that, but I guess I was thinking about, as we get into 2004 and we seek a temporary CTC, we'll certainly have to request a given level of return.

Gotcha.

I know you're going to try and fix the dividend restriction that comes up, but in lieu of that, just to get a better idea, what is your quarterly earnings profile?

I know it depends on a trailing 12-month earnings, so to the extent that you can maintain earnings above 80 cents.

So I'm trying to find out from here on out what the quarterly earnings profile looks like.

Okay.

We can get that for you.

Hang on just a second.

Peter, I think you can look at that in terms of cyclicality or the seasonality of this business.

In terms of ranges, 25 to 30% in quarter one, 20% quarter two, 40% quarter three.

Quarter three is our big quarter, most profitable quarter, and then 10 to 15 in the fourth.

That's sort of the range from a seasonality perspective.

Okay, great.

And then the last thing was on the $400 million required paydown in the fourth quarter, assuming you don't get to restructure that some way.

What are the options you're exploring for making good on that full payment?

I know $200 million comes from equity, or equity linked securities, I guess.

What other ways do you have of making the $400 million pay down?

We have, obviously, there's any number of options out there.

We believe that there's convertible securities option that's very attractive.

We think at the holding company you have options there, which are open to us now, which perhaps weren't open a few months ago.

At our subsidiaries, there's some small capacity there, as well.

Plus, as Gary mentioned earlier, we have some liquidity today that we're also looking at.

So we have a series of options there that we're exploring, and I think it's really trying to figure out what is the best way to do this, and what is in the interest of our shareholders to do it.

How might we keep track of your ability or your efforts, rather, to renegotiate that -- those paydowns and requirements on the dividend?

Remember, we have no requirement -- I mean, no mandatory.

It's at our option.

And I would -- you know, other than just kind of watching what we're doing, certainly I know each quarter to the extent we haven't got it done, next quarter we'll talk about it again.

But I think, you know, we're actively looking at our options there.

So I would say just continue to watch what we're doing.

Okay.

Great.

Thank you very much.

Thank you.

I think we have time for one more question.

The final question is a follow-up from Jonathan Rojewski with Goldman Sachs.

Hi, guys.

Real quick, because I know it's getting late.

Gary, you said 480 or 580 for depreciation amortization in '04?

Just a second.

Five, I think.

D&A in '04 is about $580 million.

If you subtract those two together, that's only a difference from 618 to 580 of 37 million.

And if you have all the depreciation that goes away from the Texas Genco, what is it that is increasing, or how is D&A increasing [INDISCERNIBLE] subsidiaries essentially close that gap?

That's just half a year.

Genco is with us for part of next year.

You're assuming three months of Genco?

Six.

Six months in '04?

Yeah.

Okay.

Six months in '04.

That's the difference.

Okay, great.

Thanks.

Thanks, Jonathan.

Okay.

Thank you.

Thank you very much for participating in the call this morning.

And we appreciate your attention and support, and have a good day.

Thank you for participating in today's CenterPoint Energy first quarter 2003 earnings conference call.

You may now disconnect.