CenterPoint Energy Inc (CNP) 2008 Q2 法說會逐字稿

Good morning, and welcome to CenterPoint Energy's second quarter 2008 earnings conference call with senior management.

During the Company's prepared remarks all participants will be in a listen-only mode.

There will be a question-and-answer session after managements' remarks.

(OPERATOR INSTRUCTIONS) I will now turn the conference over to Marianne Paulsen, director of investor relations.

Ms.

Paulsen?

Thank you very much, Tina.

Good morning, everyone.

This is Marianne Paulsen, director of investor relations for CenterPoint Energy.

I'd like to welcome you to our second quarter 2008 earnings conference call.

Thank you for joining us today.

David McClanahan, President and CEO, and Gary Whitlock, Executive Vice President and Chief Financial Officer, will discuss our second quarter 2008 results and will also provide highlights on other key activities.

In addition to Mr.

McClanahan and Mr.

Whitlock, we have other members of management with us who may assist in answering questions following their prepared remarks.

Our earnings press release and Form 10-Q, filed earlier today are posted on our website, which is www.CenterPointEnergy.com, under the investor section.

I would like 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 filings with the SEC.

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 Wednesday, August 13, 2008.

To access the replay please call 1-800-642-1687, or 706-645-9291 and enter the conference ID number 55421944.

You can also listen to an on-line replay of the call through the website that I just mentioned.

We will archive the call on CenterPoint Energy's website for at least one year.

And with that I will now turn the call over to David McClanahan.

Thank you, Marianne.

Good morning, ladies and gentlemen.

Thank you for joining us today and thank you for your interest in CenterPoint Energy.

I'm pleased to summarize our performance for the second quarter of 2008.

This morning we reported net income of $101 million for the second quarter, or $0.30 per diluted share.

This compares to net income of $70 million, or $0.20 per diluted share for the same period last year.

Operating income was $297 million for the second quarter of 2008 compared to $242 million for the second quarter of 2007.

Over the last few years, we've made strategic investments, particularly in our interstate pipeline and field services business units, which continue to contribute to the growth in our profitability.

These two segments had an excellent quarter, and our utilities also reported solid results.

Our overall financial results continue to demonstrate the benefits of our balanced portfolio of electric and natural gas assets.

Now let me review the performance of each of our business segments.

Houston Electric had operating income of $129 million in the second quarter, an increase of over 9% from the comparable period in 2007 when operating income was $118 million.

We continue to benefit from strong growth in our Houston service territory compared to other parts of the country, adding nearly 52,000 customers since last June.

While growth may moderate some the rest of the year, we still expect overall customer growth in 2008 to remain very strong.

We also benefited from increased customer usage this quarter due to warmer weather in our service territory, which was partially offset by higher transmission cost billed to us by other transmission providers and an increase in other operating expenses.

In addition, we recorded a $9 million gain on a land sale this quarter, while the second quarter of last year included a $17 million favorable settlement related to our final fuel reconciliation.

Over the last several years we have continued to invest in the number of new transmission project in our service territory.

In order to recover the increased costs related to them we plan to file a transmission cost of service reate increase next month, which we expect will result in an annual increase of approximately $15 million.

As you know, utilities in Texas can change their transmission rates to reflect new investments without going through a complete rate case, which mitigates the regulatory lag associated with transmission investments.

ERCOT has estimated that substantial new transmission and interconnection investments will be needed over the next five years to accommodate growth and relieve congestion in Texas.

We expect to make approximately $500 million to $1 billion in new transmission and interconnection investments in our service territory during this timeframe.

Houston Electric continues to pursue an advanced metering system and the implementation of an intelligent grid.

In May we filed an initial advanced metering deployment plan and surcharge request, which calls for installing up to 250,000 meters and related infrastructure over the next three years, at an estimated capital cost of approximately $250 million.

We have been exploring ways to settle the timing and nature of our deployment with the other parties in this proceeding, and have recently been granted a 60-day extension to the statutory deadline to allow for further discussions.

We expect a decision by the PUC on our plan before the end of the year.

In advance of receiving approval of our deployment plan, and at the request of the retail electric providers, we have reached an agreement for an accelerated meter deployment plan which is awaiting PUC approval.

This agreement would allow us to install up to 125,000 advanced meters related communications equipment and back-office systems at the request of retail electric providers who will provide funding in advance for all costs.

Subject to PUC approval of the agreement, installation of advanced meters for rep designated residential customers could begin as early as late this month.

Reps who participate in this voluntary program will have the opportunity to market and test new product and offerings and evaluate market response.

We would subsequently reimburse the amounts advanced by the reps to the extent the equipment is utilized in our advanced metering plan, and we recover the cost, either through a surcharge or through base rates.

Now let me turn to our natural gas distribution business.

This unit reported operating income of $4 million compared to $8 million for the same period of 2007.

Due to its seasonal nature, this business typically has minimal earnings in the second quarter.

We continue to benefit from solid customer growth, adding nearly 34,000 customers since last June.

We also benefited from a rate increase implemented in Arkansas last November.

Higher natural gas prices, however, led to an increase in bad debt expense, and we also experienced higher customer-related and support services costs.

We are continuing to pursue rate strategies to decouple our earnings from the volume of gas we sell, and to recover costs on a timelier basis.

This strategy encompasses mechanisms such as weather normalization clauses, revenue and cost of service adjustments, and decoupling.

These strategies are particularly important in the volatile and high natural gas price environment we are experiencing, and the increased focus on conservation and energy efficiency.

Last year we were successful in implementing rate decoupling in Arkansas, and this year we obtained a weather normalization in Oklahoma and have reached a settlement with most of the cities in our Texas Coast jurisdiction that includes an adjustment mechanism to recognize changes in the revenue, cost of service, and investment.

In jurisdictions where we do not have such mechanisms, we will continue to use weather hedges as appropriate.

Operationally, we continue to build on the momentum we gained last year from productivity improvements and an enhanced business model.

Our competitive natural gas sales and services segment reported an operating loss of $5 million for the second quarter of 2008, compared to a loss of $4 million last year.

Our core business of selling natural gas to commercial and industrial customers was comparable to last year.

In the second quarter of 2007, we recorded a $5 million write-down of inventory to the lower of cost of market and mark-to-market losses of $6 million resulting from derivatives we used to lock in economic gains of this business.

In the second quarter of this year we recorded $10 million in mark-to-market losses.

While the derivatives are mark-to-market each quarter the physical sales which are being hedged by the derivatives are accounted for on an accrual basis.

This tends to create quarterly fluctuations in earnings.

Upon settlement of both the physical sales and the derivatives, the locked-in economic margin will be realized and these losses will be offset.

Our primary focus is to grow this business by expanding our commercial and industrial customer base while capturing asset optimization opportunities when they become available in the marketplace.

Our interstate pipeline segment recorded strong earnings for the second quarter, with operating income of $101 million compared to $52 million last year.

Operating income for the second quarter included an $18 million gain from the sale of two gas storage development projects, increased ancillary services, and the completion of the first two phases of our 172-mile pipeline between Carthage, Texas, and our Perryville hub in northeast Louisiana.

Phase 1, with almost one billion cubic feet per day capacity, went into service in May of 2007.

In phase 2,, which brought the capacity to 1.25 billion cubic feet per day, went into service last August.

We placed phase 3 in service in April of this year, bringing the total capacity to 1.5 billion cubic feet per day.

Phases 1 and 2 have been running at nearly 100% capacity since they went into service, and phase 3 is now fully subscribed.

We recently held a nonbinding open season to gauge interest in additional pipeline capacity in this area.

We received substantial interest, and we are evaluating the economics of further expanding this pipeline by adding additional compression and/or looping the entire line.

We expect there will be substantial competition from others to serve the growing production in this area.

A second major project, the southeast supply header, or SESH, a joint venture with Spectra, is currently under construction and is expected to be in service later this year.

SESH will have capacity with one billion cubic feet per day of which 95% is already under contract with a solid group of shippers.

As most of you know the ultimate cost of this project is significantly higher than our original estimate.

Our investment in SESH is now expected to be approximately $600 million.

SESH is well positioned to serve the growing southeast market, and there are future expansion options if warranted by market demand.

Expansion of our core pipelines also remains a priority.

We have built a number of new laterals off our existing pipelines to serve new customer facilities.

In addition, producer drilling near our facilities remains high, particularly in the Woodford, Fayetteville and Hanesville shale areas and we continue to work with producers on getting this new natural gas production to market.

Now let me turn to our field services segment.

We reported operating income of $32 million for the second quarter of 2008, compared to $27 million for 2007.

This business unit continues to benefit from the strong drilling activity and increased production in the Mid-Continent area.

Our field services business also has a 50% ownership in natural gas processing facilities that continue to expand.

The equity income that we recorded from this joint venture increased to $4 million compared to $2 million in the second quarter of 2007.

Drilling in and around our existing gathering footprint in the Arkoma, Anadarko, and ArkLaTex Basins remains robust.

Further significant activity in the Woodford, Fayetteville and Hanesville shale areas have caused a substantial increase in project opportunities.

The drilling forecast for the shale plays, as well as our traditional basins, indicate that this trend will continue for a number of years.

We continue to take advantage of these market dynamics and have increased our growth capital budget for 2008 by approximately $125 million.

Going forward, natural gas development near our existing assets will remain very active, and additional facilities will be needed to get natural gas to market.

We expect to continue to pursue growth projects in our footprint in order to grow the profitability of this business.

In closing, I'd like to remind you of the $0.1825 per share quarterly dividend declared by our board of directors last month.

We believe our dividend actions continue to demonstrate a strong commitment to our shareholders and confidence the board of directors has in our ability to deliver sustainable earnings and cash flow.

Before I turn the call over to Gary let me thank our employees for all their hard work and preparation in connection with tropical storm Edouard.

As it turned out, we were fortunate that this storm had very little impact in our service territory, but our employees did a great job in making preparations in case it came through.

With that I'll now turn the call over to Gary.

Thank you, David, and good morning to everyone.

I would like to discuss a few items with you this morning.

First let me address recent credit rating agency actions.

Last month Fitch and Moody's issued summary opinions in which they confirmed their ratings on CenterPoint Energy, Houston Electric, and CERC, maintaining stable rating outlooks.

We continue to adhere to the financial discipline necessary to maintain and improve credit metrics while remaining focused on improving and growing the profitability of our businesses.

There are a number of financing developments that I wanted to share with you this morning, as well.

First, as David indicated, the SESH project is expected to be placed in service later this year, and we are working with our partners, Spectra Energy, to develop a permanent financing structure for the project.

Our goal is to complete the financing after SESH has been placed in service.

Both partners have been funding their respective shares of the construction costs so far.

Second, in May the parent company issued $300 million of senior notes due in 2018 with an interest rate of 6.5%.

The proceeds were used for general corporate purposes, including the cash payments made in connection with the conversion of our 3.75% convertible senior notes, which I will discuss in a moment.

Third, also in May, CERC issued $300 million of senior notes due in 2018 with an interest rate of 6%.

The proceeds were used to pay down debt.

The fourth financing development involves the retirement of the Company's convertible notes.

In 2003 we issued $575 million of 3.75% convertible senior notes due in 2023.

These securities were callable by the Company in May of this year, and in April we gave notice of a call for redemption.

As I mentioned in our last call, we began to see a number of holders convert these securities at the end of 2007, and by the date we delivered our call notice there were approximately $391 million of principal amount of notes that remained outstanding and were subject to the call.

Substantially all of these notes were submitted for conversion on or before the May 30th redemption date.

To settle the conversion of these remaining notes we issued approximately 12.2 million shares and paid cash of about $390 million, which was partially funded by our $300 million debt issuance.

Finally, I'd like to discuss our earnings guidance.

Considering our performance to date in various economic and operational assumptions, this morning in earnings release we announced that we now expect our 2008 earnings to be in the upper half of our guidance range of $1.15 to $1.25 per diluted share.

In providing our estimate for the year we have assumed normal weather in both the gas and electric utilities for the rest of the year.

In our guidance we have not attempted to predict the timing effects of mark-to-market or inventory accounting on the earnings of our competitive natural gas sales and services business.

As David indicated, these effects are timing related and ultimately do not impact the economics of the underlying transaction.

Finally, we have made certain assumptions, including the timing of asset in-service dates, as well as the timing and outcome of certain regulatory proceedings.

As the year unfold we will continue to update you on our earnings expectations.

Now let me thank you for your interest in the Company, and I'll turn the call back to Marianne.

Thank you, Gary.

With that we will now open the call to questions.

In the interest of time I would ask to you to please limit yourself to one question and a follow up.

Tina, would you please give tin instructions on how to ask a question?

(OPERATOR INSTRUCTIONS) And our first question will come from the line of Lasan Johong from RBC Capital Markets.

Congratulations on a good quarter.

I'm kind of curious about something.

If you take last year's third and fourth quarter earnings per share number it's about $0.60 and you've done $0.66 so far, that adds up to $1.26, and that's assuming no growth and no benefits going forward from any other customer issues.

It seems like to me the guidance range is somewhat on the low end.

What's it going to take the move the guidance up above the current range?

Lasan, I think that's a fair question and obviously we've looked at the same thing.

We believe that the range we've given, especially now that we've moved to the high end of our range, is the right call at this stage.

We've only gotten through six months of actual performance.

All our businesses are performing well, but we always have unknowns that crop up.

Weather is always an uncertainty, both at Houston Electric and the LDC, so I think we just need to get another quarter under our belt before we do any changing of our overall guidance.

I see.

The Houston weather was particularly hot in the month of late May and early June, but the end result wasn't as what I would have thought, given the weather.

Was there anything that was holding things back?

You mentioned transmission costs were higher.

How much higher was that cost that the results didn't reflect the full weather, from what I can tell?

Couple things going on.

One is that weather was warmer.

I think cooling degree days are like 11% above normal, so we had a good weather quarter.

We are experiencing some, what we call net key costs, which is what we get charged from other transmission providers versus what we charge, and that cost us about $5 million in the quarter.

We also have some increased operating expenses, primarily related to information technology and some other things, that cost another $5 million.

That's been a theme all year.

Growth helped some.

We probably got $5 million or $6 million from growth.

We really didn't see much conservation this quarter.

We'd seen some the first quarter of the year, but those are the big items that impacted us in the second quarter, Lasan.

Great.

If I may, just one last question.

How bad is the bad debt situation getting in the gas LDCs?

We're about $6 million year to date over last year.

Oh, okay.

Thank you.

You bet.

(OPERATOR INSTRUCTIONS) Our next question will come from the line of Carl Kirst with BMO Capital.

Guys, also nice quarter.

I don't want to be obtuse on the guidance but I just want to make sure I'm understanding.

Are you saying that within the forecast range you use, for instance first half of '08 you're using more GAAP numbers, and then you don't project sales, mark-to-market impacts, et cetera, going forward, or are you normalizing first quarter and second quarter for the asset sales, the mark-to-market impacts, et cetera?

Well, one is we don't try to estimate mark-to-market losses or gains or inventory write-downs.

As you know we've taken a fair number of mark-to-market losses this year.

But prices have really tumbled the last couple of weeks, and while obviously some of those losses will turn around, but we kind of ignore those, because we think those are purely timing.

So we're taking our performance to date, eliminating the mark-to-market impact and looking at our real performance the second half of the year as we have forecast it, and that's what we base our guidance on.

Okay.

And that is also normalized for asset sales?

Yes.

Okay.

I apologize.

Let me retell you what I meant by that.

We're including the gas storage sale that we had in the second quarter in our guidance.

You're including the gas storage?

Yes, we sold some gas storage development projects in the second quarter.

That's included in our guidance.

Okay.

But nothing going forward.

Okay.

Well, that's helpful and actually segues into the second question, because with respect to the idea of the -- we have this -- I guess the broader issue of the Perryville hub concept, then linking in with the Carthage to Perryville phase 4, I'm trying to figure out, one, does the sale of the storage have any impact, positive or negative, on the hub concept.

As you guys were out doing the Carthage to Perryville phase 4 was that hub concept something that was attractive to producers at the time?

And then maybe even just as you answer that, I would think that given the amount of gas that might be coming out, particularly in the Hanesville, that we can't stop at Perryville, so don't know if there are further long-haul expansion opportunities you can talk about?

I think the hub concept is an attractive concept.

We're interconnected to 16 pipelines right there at Perryville.

There's probably five or six bcf a day that's going to be going through that hub.

And we -- as you know, we have filed and have approved now at FERC a firm tariff now.

We only had an interruptible tariff up until just a few weeks ago, and we believe that's going to be attractive to a number of parties to make sure they have firm service rather than just interruptible service.

I don't know that impacts the additional capacity that's needed out at the Carthage area, out of the Hanesville area.

I think it makes it more attractive overall to get into Perryville, but our view is that we're going to -- there's going to be some pipeline capacity needed to get all that Hanesville, as well as Woodford gas to market.

It just so happens that's one of the things that we have an open season on, to gauge interest there, and I think there's a fair amount of interest shown by producers that need more outlook capacity.

Now, there's going to be a lot of competition for that -- any new pipe, but I think we've already built one in there, and we're right there in the thick of things.

Okay.

As far as the possibility of doing something further east?

You might very well have to get past Perryville, depending on which pipe you're talking about.

We also have an open season or had one in looking at additional pipeline capacity to get the Fayetteville shale gas out.

You might very well go to different interconnections other than Perryville with some of that gas, but I think there is going to be some pipe built beyond Perryville.

We haven't spent a lot of time and effort looking at that.

Great.

Thank you.

Our next question will come from the line of Barry Klein with Citi.

It's actually Faisel from Citigroup.

Had a question on the proposed buildout of transmission to tap some of the wind resources in west Texas, is there any interest by you guys or any plan by you guys to invest in or look at some of that transmission or for that matter maybe tie some of those projects into some of your territory in Houston?

We looked pretty hard at that, Faisel, and we decided that we really weren't interested in going out to west Texas and building a bunch of transmission.

We don't have any service territory out there.

We are interested, however, if any of that transmission comes into the Houston area, to build the part of it that is in our service territory.

There was a proposal to build a high-voltage line into Houston.

It wasn't adopted by the PUC.

But if they'd ever come back to that kind of proposal we'd be very interested in building the facilities that would have been tied into our own grid here in Houston.

But other than that, at least at this stage, we're not interested in it.

Okay.

As it turns out, as we look at what needs to be done, regardless of the wind investments, there's plenty of new investments that are needed over the next five years or so, just the normal growth, congestion, interconnections with new generators.

There's going to be a lot of activity right here in our service territory and I think we're going to have plenty of attractive investments.

Okay.

Then just looking at your press release, for both the electric transmission distribution and also interstate pipeline business, you reported that you had higher revenues from ancillary services on the electric transmission side and on the interstate pipeline side.

Can you describe what was going on there and what those services are being driven by?

On the ancillary services it's really the distribution side and a couple years ago we had had in place a number of new tariffs that really relate to connects, disconnects, things like that and those new tariffs are producing additional revenues for us.

So that's kind of business as usual.

It's just a new tariff structure.

On the transmission -- the pipeline side, those ancillary services are really off-system type of services because basis has remained high across our system.

So we have a fair number of shippers that are just crossing our system to get to another pipeline.

We have some system management type of revenues there which is -- takes into account balancing revenues and things of that sort.

We have a number of power plants on our system, as you know.

We've had fair amount of revenue related to those power plants this year, and there are also some commodity-type processing fees that we've also picked up.

So it's a myriad of things, all of them kind of relate to the marketplace we find ourselves in today.

Okay.

If I was looking at your -- the demand in your electric territory, if you were to adjust for weather, what do you see in terms of weather normalized demand for electricity on a per capita basis?

Is it down, up, flat?

What are we seeing with demand of these high prices?

We didn't see much in the second quarter, but if we look at it on a year-to-date basis it appears to us that consumption at the residential level is down 2% or so.

So it's not significant, and probably our models are not sophisticated enough to know if that 2% is really weather or conservation, but our expectation is, with the first part of the year when these high electric prices first came into play that customers started conserving, and we think we started seeing that in some of our consumption figures.

So we would expe -- although electric prices are starting to moderate a little bit as gas prices come down, I think that'll help some.

but so far this year we think it's in the 2% decline range.

Okay.

Great.

Thanks for the time, guys.

You bet.

Our next question will come from the line of Steve Gambuzza with Longbow Capital.

On the sale of the storage properties, was just curious why you decided to sell those.

It seemed like it was a good investment opportunity for you to develop them on your own.

Well, couple of reasons.

First is we do believe that there's some storage needed near our Perryville hub area, and these -- the folks we sold it to are committed to building that storage.

We do have an option to take some of that capacity for our own use, and I would expect we're going to do some of that.

I'm not sure how much of it we're going to take, but we felt we could get enough of the benefits from buying the capacity we need for our customers and for our own use as opposed to investing, which would be in the $300 million or $400 million range to develop these projects.

We had some other opportunities we were looking at, and we felt we could get just as much benefit through having somebody else develop it and us buy capacity.

And the gains that you called out in your earnings release, those are pretax numbers, correct?

Yes.

And you mentioned that you included the gain from the storage sale in guidance.

Did you include the gain from the land sale at Houston Electric in guidance also?

What we did is we simply took our performance to date, which included all of those things, and we said, now let's -- looking forward let's take our plan and normalized weather and see what we get.

But we did include all our performance to date.

Okay.

And it looks like the tax rate for the second quarter was 28%?

My recollection is you were guiding to something like 36% for the year.

Is that still the case?

Yes, we've got about 37% to 38% for the year.

I'd remind you the Texas -- there's an adjustment, the Texas Margins Tax, which used to be a deduction from operating income is about 2%.

That's now in the tax rate.

I think in the second quarter, though, I think it's 38%.

I think last year was 29% this year is 38%.

But I'll guide to you 37%, 38%, Steve, for the tax rate.

I just see -- oh, I'm sorry.

Thank you very much.

Our next question will come from the line of Daniele Seitz with Seitz Research.

Just wondering when the investments in the smart meters starting to [accrue] to the earnings, do you have a sense of that or is it when the whole 125,000 meters come in effect?

Well, the 125,000 meters, which is the advanced plan, really is going to be funded by some -- by that retail energy provider, so our actual investment will not start in earnest until 2009, and it would begin then, and we're still trying to work with the parties on the exact schedule and scope of that deployment, but I would guide you to 2009 before that would start.

And this will be automatically -- it will be almost like a rider allowed by the commission?

Is that the way you see it?

Yes, there will be a special tariff that would cover all our costs and return on our investment in these facilities.

So, yes, it would be a special tariff.

And in terms of '09 and '10 investments, do you have a sense for the magnitude of the investment for those two years?

Well, we -- in our plan we filed at the Public Utility Commission we said that we would spend $250 million over the first two to three years in that -- on those facilities.

And in terms of the -- the pipeline with Spectra, you said that there has been a bit of cost overrun related to the previous estimates.

Do you think that the return might also be a little bit more modest than the one you have on the pipeline, the Perryville pipeline?

Yes.

And a lot more?

Well, obviously, we're disappointed in the cost overruns.

I guess the whole industry has faced similar cost overruns.

Right.

But the return is going to be hurt because of these cost overruns.

It's just the math on it.

Now, as you know, these are long-lived pipes.

You amortize these costs over 40 years.

So it's not going to have a huge dramatic impact on operating income, but on a pure project-type return, there's no question this project isn't going to be as attractive as the Carthage to Perryville line.

Thank you very much.

Okay.

(OPERATOR INSTRUCTIONS) Our next question will come from the line of Mark Siegal with Canaccord Adams.

Good morning.

Just with regards to your AMI deployment that you already outlined, when is the 60-day extension run up?

I think now that the commission has -- they have until early December to make a decision.

There's a statutory timeframe of 150 days, and just so we didn't bump up against that, we extended that by 60, I think, which would extend it out to like December -- the first or second week in December.

Okay, great.

Then just on the potential accelerated deployment, do you expect to hear one way or the other at the next PUC meeting or how will that work?

I think they have it on their agenda for August 14th.

Okay.

Thanks very much.

Okay.

Our next question will come from the line of Lasan Johong with RBC Capital Markets.

Thank you.

I just want to ask a couple of follow-up questions.

There's been some discussion about reduction in capital spending from E&P companies.

Are you, A, feeling the effects, or seeing the effects, and, B, is it something we should be concerned about?

We have not seen any impacts of that in the shale plays or in the Mid-Continent area.

We see as much activity there as we've ever seen.

So your drilling expectations are still 400-well-type situations?

Yes, that's exactly right.

We expect that just our traditional wells will be in the 400 range.

Great.

And then the -- there's a lot of discussion and talk about wind becoming a major factor in the Texas power markets, and obviously wind is not extraordinarily predictable so there's a lot of concerns about the stabilization of the grid.

Is this something that concerns you, and if, so how do you mitigate the risk of very large quantities of wind being hooked up to the system?

It's something that certainly our transmission planners take into account, and you have to look at what -- how you back up wind, and there's going to be -- need to be a fair amount of gas-powered generation, I think, to back it up, Lasan.

And there are some other things that you can do on the grid to help with voltage and stabilization, but I think the big deal is how you deal with it, and what happened in April when we saw that wind fall off, we had a lot of loads that were acting as a resource and we called on them, and they fell off.

So, I think it can be dealt with.

I just think you have to plan around it.

Is there some opportunity for CenterPoint Energy to gather more fees or earn more money on this?

Well, I think there may be more investment that we have to make as a result of more wind coming in, and I think that there's also an issue around demand reduction and how we play in that game.

Certainly I think the advanced metering system will help with that kind of demand reduction.

It facilitates it at the residential level, so there could be some opportunities in that arena.

And the -- would the $500 million to $1 billion of additional transmission spending encompass part of these projects?

Well, we've estimated what we think we're going to have to spend over the next five years.

So not the demand side part, but certainly just looking at how you manage the grid, I think our transmission planners have taken some of that into account, yes.

I see.

And the other stuff that you've mentioned were things like hook up of new power plants and expansion of the grid, et cetera, correct?

Correct.

Excellent.

Thank you very much.

Thank you.

Our next question is a follow-up question from Carl Kirst with BMO Capital.

Very quickly, on the -- back on the Carthage to Perryville phase 4 now with good, strong, nonbinding support is there a timeframe where you think that that might actually go down into a binding open season?

I understand there's a lot of negotiations now and a lot of competition, but is that something that we might be able to see by year end, at least as far as entering into a binding open season?

How should we think about that on timing?

I think certainly by year end we'll have a lot better idea if that's going to be a real project for us.

We clearly -- we're talking with producers, we're looking at options there, but we're hopeful that by year end we'll have a lot more clarity around that.

Was there ever -- when you were first going out with producers, was there ever a specific magnitude discussed, half B a day, or what the -- ?

In a nonbinding open season you get lots of interest but there's substantially more than that, that was express.

Now, whether or not all that turns into real firm demand, but it was a couple of B's a day that were expressed.

We'll see how much of that is real.

Sure, absolutely.

Then lastly, and just ask it, any chatter on the Texas Supreme Court?

No, we -- we hadn't heard a thing and don't expect to for awhile.

Scott, you want to add anything?

No, not really.

The petitions for review and responses have been filed, and the next step is to see if the Supreme Court asks for a full briefing on this matter.

We wouldn't expect to hear from them until in the fall.

Okay.

Thanks, guys.

Thank you.

Our next question is a follow-up question from Steve with Longbow capital.

The comments around potential investment, you had prior -- you've given five-year CapEx guidance for Houston Electric and you -- previously you'd indicated some level of transmission expenditure.

Is this a reiteration of that or how much of what you just said is incremental to this forecast?

I think last year when we estimated transmission investment, '08 to '12, we had something like $250 million in our budget, and I think -- so I think we're seeing more transmission investment potential than we did last year.

There's no question.

It could be substantially more.

In that $500 million to $1 billion range, is that the range that you provided?

Yes.

Okay.

So it's approximately -- call it $250 million to $750 million of incremental.

Yes.

Great.

Thanks very much.

Okay.

And we have no further questions at this time.

I would like to turn the call back to Ms.

Paulsen.

Thank you very much, Tina.

I would like to thank everyone for participating in our call today.

We appreciate your support very much.

Have a great day.

Ladies and gentlemen, this concludes CenterPoint Energy's second quarter 2008 earnings conference call.

Thank you all for your participation, and you may disconnect.