CenterPoint Energy, Inc. (CNP) Q2 2008 Earnings Report, Transcript and Summary

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 management's remarks. [Operator Instructions]. I will now turn the call 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 Investors 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 PM 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 online 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 am pleased to summarize our performance for the second quarter of 2008. This morning we reported net income of $101 million for the first 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 unit, 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 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 costs billed to us by other transmissions providers and increase in other operating expenses. In addition, we have 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 a number of new transmission projects in our service territory. In order to recover the increased costs related to them, we plan to file a transmission cost of [ph] service rate increase next month, which we expect will result in an annual increase of approximately $15 million. As you now, 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 discussion. 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 rates in 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 products and offerings and evaluate market response. We would subsequently reimburse the amount advanced by the REP to the extent the equipment is utilized in our advanced metering plan and we recover the costs either through a surcharge or though 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 some 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 right 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 conversation 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 the 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 cost or market and mark-to-market losses of $6 million resulting from derivatives we use 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 marked 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 lock 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 industry customer base while capturing asset optimization opportunities when they become 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 I with almost 1 billion cubic feet per day capacity went into service in May of 2007 and Phase II, which brought the capacity to 1.25 billion cubic feet per day went into service last August. We placed Phase III 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 III is now fully subscribed. We recently held a non-bonding 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 are 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 of 1 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 not 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 Haynesville 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 existing gathering footprint in the Arkoma, Anadarko and ArkLaTex basins remains robust. Further significant activity in the Woodford, Fayetteville and Haynesville shale areas has caused a substantial increase in new 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 would 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 the 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 [ph] in which they confirmed their ratings on CenterPoint Energy, Houston Electric and CERC, maintaining stable rating outlook. We continue to adhere to the financial discipline necessary to maintain and improve our 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're working with our partner, 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 cost 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 uses 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 would like to discuss our earnings guidance. Considering our performance to date and various economic and operational assumptions, this morning in the earning 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 earnings 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 unfolds, we will continue to update you on our earnings expectations. Now let me thank you for your interest in the company and I will 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 you to please limit yourselves to one question and a follow up. Tina, would you please give the instructions on how to ask a question? Question And Answer

At this time, we will begin taking questions. [Operator Instructions]. And our first question will come from the line of Lasan Johong with RBC Capital Markets.

Congratulations on a good quarter. I'm kind of curious about something. If you take last year's second and fourth [ph] 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 of the customer issues. It seems like to me the guidance range is somewhat on the low end. What's it going to take to move the guidance up above the current range?

Lasan, I think that's a fair question. Obviously, we have looked at the same thing. We believe that range we've given and especially now that we have moved to the high end of our range is the right call at this stage. We have only gotten through six months of actual performance. All over businesses are performing well, but we always have unknowns that crop up. Weather is always an uncertainty, both a Houston Electric and the LDC. So frankly, 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 months 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 kind of 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?

A couple of things going on. One is that weather was warmer. I think like cooling degree days are like $0.11 above... 11% above normal. So we had a good weather quarter. We are experiencing some, what we call net tea cost [ph], which is the 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 or $6 million from growth and we really didn't see much conservation this quarter. We had 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 are about $6 million year-to-date over last year.

Okay, thank you.

You bet.

[Operator Instructions]. Our next question will come from the line of Carl Kirst with BMO Capital.

Guys, nice quarter. I don't want to be obtuse on the guidance, but I just want to make sure I am understanding. Are you seeing that within the forecast range you use, say for instance first half of '08 you are 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 [ph] inventory write-downs. As you know, we've taken a fair number of mark-to-market losses this year. Now prices have really tumbled the last couple of weeks, and obviously some of those losses will turn around. But we kind of ignore those because we think those are purely timing. So we are taking our performance today, eliminating the mark-to-market impact and looking at our real performance the second half of the year as we have forecasted, and that's what we base our guidance on.

Okay. And that is also normalized for asset sales?

Yes.

Okay. I just apologize. I just want --

Well let me re... tell you what I meant by that. We are including the gas storage sale that we had in the second quarter in our guidance.

Including the gas storage, okay.

We sell 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 quarter question, because with respect to the idea of the... we have the I guess the broader issue of the Perryville Hub concept then linking in with the Carthage, Perryville Phase IV. I guess I am trying 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 IV. Was that hub concept something that was attractive to producers at the time? And then maybe even just kind of as you answer that, I would think that given the amount of gas that might be coming out, particularly in the Haynesville that we can't stop at Perryville and 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 are interconnected to 16 pipelines right there at Perryville. There is probably 5 or 6 BCF a day that's going to be going through that hub. And as you know, we have filed and have approved now as 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. Now I don't know that that impacts the additional capacity that's needed out of the Carthage area, out of the Haynesville area. I think it makes it more attractive overall to get into Perryville. But our view is that we are going to... there is going to be some pipeline capacity needed to get all that Haynesville 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 is a fair amount of interest shown by producers that need more outlet capacity. Now there is going to be a lot of competition for that any new pipe, but I think we have already built one in there and we are right there in the thick of things.

Okay. And as far as the possibility of doing something further east?

You might very well have to get past Perryville depending on which pipe you are talking about. We also have an open season or had one in looking at additional pipeline capacity to get the Fayetteville Shale gas out. And you might get very well [ph] 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.

Actually, Faisel from Citigroup. Just... I had a question on the proposed build out 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 to 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 transmissions. 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 had ever come back to that kind of proposal, we would be very interested in building the facility that would been tied into our own grid here in Houston. But other than that, at least as this stage, we are not interested in it.

Okay.

As it turns out, as we look at what needs to be done regardless of the wind investment, there is plenty of new investments that are needed over the next five years or so just the normal growth congestion, interconnections with new generators. There is going to be a lot, lot of activity right here in the service activity and I think we are going to have plenty of attractive investments.

Okay. And then just looking at your press release for both the electric transmission and distribution and also the interstate pipeline, you reported that you had higher revenues from ancillary services on the electric transmission side and on the interstate pipeline side. Can you describe kind of 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 of years ago, we had in place a number of new tariffs that really relate to connects, disconnects and things like that. And those new tariffs are producing additional revenues for us. So that's kind of business as usual. It gives a new 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 taken to account the balancing revenues and things of that sort. We have a number of power plants on our system as you now. We have had a fair amount of revenue related to those power plants this year, and there are also some commodity type processing fees that we have 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. And if I was looking at your... the demand in your electric tertiary, if you were to adjust for weather, what do you see in terms of weather normalize the demand for electricity on a per capita basis? Is it down, up, flat? I mean what are we seeing with demand at these high prices?

We didn't see much in the second quarter, but if we look at it on year-to-date basis, it appears to us that consumption at the residential level is down 2% for sale. So, its not significant and probably our morals are not sophisticated enough to know effective percentage is really whether a conservation but our expectation is with the first part of the year when this higher electric process first came in deploy that customer started conserving and we thank we have started thing add in some of our consumption figure so we would expect all our electric prices is destroying the moderate low good as the end process is come down. I think that help some but so called this year we thank its been 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, I was just curious why you decided to sell those. It seemed like it was good enough an opportunity for you to develop on your own.

Well, a couple of reasons. First is we do believe that there is 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 are going to do some of that. I am not sure how much we are 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 3, $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.

Okay. And the gains you called out in your earnings release, those are pre-tax numbers, correct?

Yes.

Okay. And you mentioned that you included the gain from the storage sale and guidance. But do you include the again from the land sale of Houston Electric in guidance also?

Yes, what we did is we simply took 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.

Okay.

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, I think we've guided about 37 to 38% for the year. I'd remind you that Texas, there is an adjustment to Texas margin 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 will guide you to 37, 38%, Steve, for the tax rate.

I just see... I'm sorry, okay, thank you very much.

Yes.

Our next question will come from the line of Danielle Sietz [ph] with Sietz Research [ph].

Just wondering when the investments in the smart meter is starting to curl into 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 the retail energy providers. So our actual investment will not start in earnest until 2009. And it would begin in and we are 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 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 your... the gas [ph] 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 are disappointed in the cost overruns. I guess the whole industry has faced similar cost overruns. 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 is no question that 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 Siegel with Canaccord Adams.

Good morning. Just with regards to the your AMI deployment that you already outlined. When is the 60 day exemption run up?

I think now that the Commission... they have until early December to make a decision, there is a statutory timeframe of 150 days. And just so we didn't bump up against that, we extended that by 60 I think, which was extended out to like December, the of first or second week in December.

Okay, great. And then just on the potential accelerated deployment, do you expect one way or the other at the next PUC meeting or how will that work?

I think they have it on their agency 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 has 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 this something that 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 is as we have ever seen.

So you are 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 there is a lot of discussion and talk about wind becoming a major factor in the Texas power market. And obviously wind is not extraordinarily predictable. So there is a lot of concerns about the stabilization of the grid. Is this something that concerns you and if so, how do you mitigate the risks of very large quantities of wind being hooked up to the system?

Well it's something that certainly our transmission planners take into account. And you have to look at what... how you back out wind. And there is still... there is going to 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 windfall loss, 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 opportunities for CenterPoint to gather more fees or earn more money on this?

Well I think there may be more investment that we have to make as result of more wind coming in. And I think that there is 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 a demand reduction it facilitates at the residential level. So there could be some opportunities in that arena.

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

Well we have estimated what we think we are 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 the... our transmission planners have taken some of that into account, yes.

I see, I see. And the other stuff that you 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 follow-up question from Carl Kirst with BMO Capital.

Very quickly on the back on the Carthage to Perryville Phase IV now with good strong non -binding support, is there a timeframe where you think that that might actually go down into a binding open season? I mean I understand there is 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 would... 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 talked... we are talking with producers, we are looking at options there. But we are hopeful that by year end, that will... we'll have a lot more clarity around that.

Was there ever when you were first going with producers, was there ever a specific magnitude discussed, half fee a day [ph] or what the --

There is a... in a non-binding open season, you get lots of interest, but there is substantially more than that that was expressed. Now whether or not all that turns into real firm demand, but it was a couple of Bs a day that were expressed. We'll see how much of that is real.

Sure and absolutely. And then lastly and just asking, any chatter on the Texas Supreme Court?

No, we haven't heard a thing and don't expect to for a while. Scott, you want to add anything.

No, not really. The petitions for review have been filed and the next stop is to see if the Supreme Court asked for full briefing on this matter. We wouldn't expect to hear from there until in the fall.

Okay, thanks guys.

Thank you.

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

Hi, the comments around potential transmission investment, I know you had prior... you had given five year CapEx guidance for Houston Electric and you previously indicated some level of transmission expenditure. Is this kind of a reiteration of that or how much of what you just said is incremental to those forecasts?

Last year, when we estimated transmission investment '08 to '012, we had something like $205 million of... in our budget. And I think... so I think we are seeing more transmission investment potential than we did last year; there is no question. It could be substantially more.

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

Yes.

Okay. So it's approximately, call it, to 250 to 750 is incremental?

Yes.

Okay. Great. Thanks very much.

Okay.

And we have no further questions at this time. I would like to turn 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.