CenterPoint Energy, Inc. (CNP) Q4 2007 Earnings Report, Transcript and Summary

Good morning, and welcome to CenterPoint Energy's Fourth Quarter and Full Year 2007 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 remark. [Operator Instructions]. I will now turn the call over to Marianne Paulsen, Director of Investor Relations. Ms. Paulsen?

Thank you very much Luanne. Good morning everyone. This is Marianne Paulsen, Director of Investor Relations for CenterPoint Energy. I would like to welcome you to our fourth quarter and full year 2007 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 fourth quarter and full year 2007 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-K 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 Thursday, March 6th, 2008. To access the replay, please call 1-800-642-1687 or 706-645-9291 and enter the conference ID number 30804610. 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. 2007 was the good year for us, and I am pleased to summarize our performance. Let me begin with an overview of our fourth quarter 2007 results. This morning, we reported net income of $108 million for the fourth quarter of 2007 or $0.32 per diluted share. This compares to net income of $67 million or $0.20 per diluted share for the same period last year. Net income for the fourth quarter of 2006 included the impact from the form settlement of the company's ZENS tax issue, which reduced 2006 earnings by $12 million or $0.04 per diluted share. Operating income was $303 million for the fourth quarter of 2007 compared to $235 million for the fourth quarter of 2006. The increase in operating income for the quarter was driven impart by increased usage primarily due to favorable weather at Houston Electric, continued solid customer growth in our service territories, improved operating performance, and rate increases at out LDCs. The favorable results of our interstate pipelines in the fourth quarter of 2007 were driven primarily by the new Carthage to Perryville pipeline. Field services also reported solid operating results. Our competitive natural gas marketing business reported a decrease in operating income due to unfavorable market dynamics compared to the last two years. The same factors also impacted our full year 2007 performance. Overall 2007 was a very good year for us, and we continue to make progress in achieving our business and financial objectives. Net income for 2007 was $399 million or $1.17 per diluted share compared to $432 million or $1.33 per diluted share for 2006. In comparing 2007 to 2006, it is important to keep in mind that our 2006 full year results reflected the resolution of both the ZENS tax issues and Huston Electrics 2001 unbundled cost of service remand. Excluding all the impact of these two issues, our full year 2006 earnings would have been $1.11 per diluted share compared to our 2007 EPS of $1.17. Now let me review the performance of each of our business segments. Huston Electric had operating income of $400 million excluding income from the competitive transition charge and the transition bond companies. The comparable income for 2006 was $395 million. Results for 2007 included a $17 million favorable settlement related to the final fuel reconciliation of the former integrated utility, while 2006 included the write-off of $32 million related to the UCOS settlement. Growth and continued operating improvements allowed Houston Electric to offset a significant portion of the impact from the right settlement implemented in October of 2006. Customer growth remains strong; in fact 2007 marked the 11th consecutive year that customer growth was 2% or better. We also benefited from increased customer usage in large part due to favorable weather compared to 2006. We expect Huston Electric to continue to perform well in 2008. Customer growth in the Houston market has remained solid as compared to many other parts of the country. And in 2008, we expect to see our customer base continue to grow. In support of this growth, we anticipate that we will spend over $370 million in capital in 2008. As allowed under our rate settlement, we expect to file for a transmission cost of service rate increase in the $12 million to $18 million later this year. Houston Electric continues to pursue advanced multi functional smart metering and the implementation of an intelligent distribution grid. In 2007, we installed approximately 10,000 smart meters to evaluate system capabilities and identify any issues relating to system wide implementation. Results so far have been encouraging. In advanced metering rule setting the technical requirements for installing these types of systems and providing for an advanced metering surcharge has been approved by the Texas Public Utility Commission. The bulk of the benefits of implementing this new technology are expected to accrue to the market by providing opportunities for innovated service offerings by retail electric providers. In addition, we believe this system will ultimately result in savings to our electric unit primarily in the areas of meter reading, service connects and disconnects, faster service restoration and improved customer service. We continue to work on a deployment plan that would verify these benefits. Any deployment would be depended upon approval by the Texas PUC that is acceptable to the company. Now, let me turn to our natural gas distribution business. This unit reported operating income of $218 million, which was a $94 million improvement compared to 2006, for the first time in many years, we were closed to earning our overall authorized rate of returns and believe we have set to say that the stage to do so in the future. We are realizing the benefits from the changes that we made to improve the operational and financial performance of our gas LDCs. We continue to benefit from solid customer growth adding over 38,000 customers in 2007. We also experienced increased customer usage primarily due to a return to more normal weather. We implemented new rates in Arkansas last November, where we received the base rate increase of $20 million and implemented a decoupling mechanism that will stabilize revenues and earnings while helping to facilitate energy efficiency. We have hedged the weather for the current heating season, and we will continue to pursue right strategies and operational efficiencies in order to sustain and improve the financial performance of our gas LDC businesses. While we have seen some slowing of growth in our Minnesota market, growth remains solid in Texas. We expect to spend about $200 million in capital in 2008. Our competitive natural gas sales and services segment had a solid year. Operating income for 2007 was $75 million compared to $77 million in 2006. Market conditions during most of 2007 were less volatile than in 2005 and 2006. As a result, we did not have as many opportunities to create value from optimizing our pipelines and storage assets. Nevertheless, our base commercial and industrial sales business continues to do well; and we remain well positioned to take advantage of future market opportunities as they arise. I should point out however, that a number of new pipelines had been placed in commercial operations, which has had the effect of reducing bases differentials. In addition, seasonal price differentials have also narrowed; both of these developments reduced opportunities for assets optimization. Our focus is to profitably grow this business by expanding our commercial and investor customer base. Our interstate pipeline segment recorded strong earnings in 2007 with operating income of $237 million compared to $181 million in 2006. This increase was driven primarily by the completion of the first two phases of our new 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; and Phase II, which brought the capacity to 1.25 billion cubic feet per day, went into service in August. We plan to expand this project to a total of 1.5 billion cubic feet per day by adding additional compression and increasing operating pressure. We hope to have this third phase in service in the second quarter of this year. Phases I and II have been running at nearly 100% capacity on average since they went into service, which is clear evidence that this pipeline was needed. Our second major project is Southeast Supply Header or SESH, a joint venture with Spectra is currently under construction. SESH expects to invest approximately $1 billion in this pipeline and has signed a solid group of shippers for 95% of the 1 Bcf per day capacity. We expect this pipeline to be in service in the second half of this year. We have also built a number of new laterals of our existing pipeline to serve new customer facilities, such as AEP power plant in Arkansas. Producer drilling activity in the Woodford and Fayetteville Shale remains high, and we have recently announced an open season for new facilities, which would get these reserves to market. This open season will allow us to determine if there is a sufficient level of interest from the market to pursue development of a new pipeline. Our field services segment reported operating income of $99 million in 2007 compared to $89 million in 2006. This unit continues to benefit from strong drilling activity in the Mid-Continent area with over 400 new well connects added in 2007. This is the fourth year in row that we have experienced that level of new well connects. Fuel services 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 $10 million in 2007 from $6 million in 2006. Natural gas development near our existing assets remain very active, and additional facilities will be needed to get natural gas reserves to market. We are currently pursuing a number of projects. Last year we committed overall $100 million in capital expenditures for new projects. And we expect to spend at approximately at this level over the next year three years to five years. Now, let me provide you an update on our true-up appeal. I am sure you are aware that the third Court of Appeal issued its decision on our stranded cost true-up appeal last December. We are extremely disappointed that the Court of Appeal reversed portions of the District Court decision that would have allowed us to recover additional amounts related to our capacity auction true-up. The Court of Appeal also reversed part of the PUC's order that allowed us to recover the excess mitigation credit that we paid to Reliant Energy. The Court of Appeal did however uphold a ruling by the District Court that we would be entitled to recover the interest component of the excess mitigation credits that we paid to retail electric providers other than Reliant. In addition, the Court of Appeals ordered that a decision by the PUC on the tax issue that could result in a normalization violation be remanded back to the PUC. We and other parties filed motions for rehearing with the Court of Appeal. There is no statutory timeframe under which the court has to render its decision on these motions, but if our motion is not granted in full, we would then have 45 days to seek review by the Texas Supreme Court. In closing, I would like to remind you of the $0.1825 per share, quarterly dividend declared by Board of Directors on January 24. 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. Now, I'll turn the call over to the Gary.

Thank you, David and good morning to everyone. I'd like discuss a few items with you this morning. Let me first discuss our securitization. Earlier this month, we closed some $488 million of non-recourse transition bonds in order to recover the balance of the true-up costs that we have previously been collecting overtime via competition transition charge or CTC. We estimate the electric customers in our service territory will save over $100 million over the life of the bond. Because the weighted average interest rates on these bonds is well below the 8.06% rate that we had been earning on the unrecovered CTC balance. In fact, the weighted average interest rate is lower than the comparable rates on all prior securitization bonds sold to-date by Electric Utilities in Texas; all in all a very successful transaction. We replied the proceeds of this transition bond issuance to reduce our parent company's equity investment in CenterPoint Energy Houston Electric, and CenterPoint in turn has used these bonds to reduce debt. We have implemented a transition charge to recover the principle and interest on the bond. The transition charge replaces the higher CTC that we had been collecting. We were able to achieve the success, thanks to the leadership of Texas PUC Chairman Barry Smitherman and the other commissioners as well as the staff of the Texas PUC. We also acknowledge the hard work of the Texas legislative leadership, who supported the amendment of the law clarified that all true-up amounts are securitize-able. Now let me review some of our accomplishments in 2007 and discuss our financing goals and objectives in 2008 and beyond. In 2007, we took a number of steps to continue to strengthen our liquidity. Last June, we admitted our three bank credit facilities, which now totaled $2.45 billion and extended their maturities to 2012. Later in the year, we also extended the search receivables facility to October of 2008. The facility will range in size from $150 million to $375 million in order to efficiently track the projected receivable balance of CERC. Over the last four years, we have steadily and significantly strengthened our liquidity and enhanced our financial flexibility through the improvement in size, price and tenor of our working capital facility. In October, we closed on the sale of $500 million of CERC notes. Proceeds from these notes were used to retire $300 million of CERT debt that matured earlier this month and to pay down short-term debt. We have substantial liquidity available to us in the form of our current... of our committed bank line, which we expect to be more than ample to meet our needs during 2008 and beyond. This year we will continue to remain focused on improving and growing the profitability of our businesses. While at the same time adhering to the financial discipline necessary to maintain and improve our credit metrics. We expect that SESH joint venture with Spectra to be in service in the second half of this year. Both partners have been funding the construction cost so far, and we are jointly evaluating various financing alternatives at the joint venture level, which we expect to have in place at or near the time SESH goes into service. On another financing matter as many of you know, we have a series of convertible notes outstanding. In 2003, we issued a total of $575 million of 3.75% convertible senior notes in due in 2023. At the end of 2007, we began to see a number of holders convert these securities, and today approximately $173 million of principles amount of these notes have been converted. For the conversions that have taken place, we are obligated to pay the principle amount in cash, but have elected to pay the premium in CenterPoint Energy common stock. The remaining principle of $402 million of these notes will first become callable by the company in May of this year. Although we have made no determination as to whether or not call the notes as to first opportunity in May. If we call the notes at that time, it would likely prompt all or most of the holders to convert. Upon conversion, we are obligated to pay the principal in cash; we have the option to pay the premium over the original amount in cash or its stock. As David mentioned, each of our business units will continue to seek value creating investment opportunity. Ultimately, any permanent financing to fund our growth project will consider the optimum mix of debt and equity consistent with maintaining and enhancing the credit metric and credit rating to both the parent company and our utility subsidiaries. Finally, I'd like to discuss our earnings guidance. This morning in our earnings release, we announced that we expect our 2008 earnings to be in the 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 utility as well as certain assumptions regarding the effect of forward natural gas price movements on our storage and transportation assets, which impact the profitability of our competitive natural gas sales and services business. In addition, we have made certain economic and operational assumptions including the timing of that asset in-service date as well as the timing and outcome of certain regulatory proceedings. As the year unfolds, we will continue to update you on 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 yourself to one question and a follow-up. Luanne, would you please give the instructions on how to ask a question? Question And Answer

[Operator Instructions]. Our first question comes from Lasan Johong with RBC Capital Markets.

Good morning, congratulations on a good quarter and year. I wonder I have just a few questions about the guidance. What are your gas price assumptions and have you made provisions for increasing... potentially, I should say, increasing bad debt expense on the gas LDC given where gas prices are today?

Lasan, thank you for those comments. As I recall, we have gas prices in the $7 to $8 range. Obviously, it varies by month, but it's in that range. So, it's a little bit less than, I think that are being experienced in today's market. We encourage something like $45 million worth of bad debt expense in 07. We don't expect there to be a big decrease in that, but we are not projecting a significant amount of increase over the level, we experienced in 07. And we also... because of our Minnesota properties, really we had a fair amount of delinquent account there. We incurred quite a bit of credit and collection expense there. We think we are on top of that situation now and we don't think a lot of those costs would be repeated. So, I would say that we are not expecting a huge run up in bad debt expense, but it's something we've got to stay on top of. And we are in the $7 to $8 gas price range for next... for this year 08.

Okay. And then, I am assuming that the range of that $0.10 in the guidance has a lot to do with weather and volumes for fuel services and other demand base changes, correct?

It has all those and I would say that one of the biggest issues is also at our energy services business. Volatility in the marketplace can move those earnings around a lot, and so... and we have seen volatility really quiet down in these markets. As I said, we have a lot of new pipelines seasonal spreads have narrowed. So, we are projecting kind of... 08 to be... look a lot like 07, if it's not it could obviously affect our earnings.

Right, right, right. Just quickly on the leverage ratio and a number of shares and the converge, how much do you expect to issue on the converged as a... if you are assuming, you call that how much shares do you expect to issue. And then in relation to that, the leverage ratios are improving obviously and your financial metric are fine, but just optically your book ratio looks kind of high 84%. Any plans to kind of remedy all that?

This is Gary. Let me start with the converged. I think if you look at the converged that we... 173 million that has been converted today. We've issued about 5... little more than 5 million shares. And again of course assuming that we were to call or they were to be put to the remaining 402 million, if you assume a share price of 15.50 for example that would be about 10 million shares. So, as you know, Lasan, it depends on the...

Right.

The price of the shares at that point time.

Of course, yes.

So, you can sort of ratio that, but that's sort of the range. Of course, in terms of share count, when you think about of share count, those are already in the fully diluted shares.

Yes.

So,I think if you think of our share count going forward, basic today is about 320 and fully diluted is about 340 million or so, so I think about those sort of amount. Also want to dimension the tax rate to you. Going forward, I think you will assume a tax rate more normalized is around 35% to 36%. This year in the fourth quarter, we had a 28% rate, year-to-date 33%. And the reason for that in the fourth quarter, we had some adjustments related to some tax reserves related to a Texas based audit. As you know, our company like many others are audited both by the various states in which we do... where we operate, so going forward, think of a more normalized tax rate as well.

Right.

Hope that's helpful.

Yes, what about the book leverage ratio? I mean it's not really that critical, but...

Yes. I think, Lasan, on the book, you probably, I think you used the number that probably included the securitization there, but we've got to include the securitization debt. And we are still at about 80%. I think if you look at the leverage that we had this year, we increased debt this year a bit. But at the same time as you know in the very first quarter, we sold the securitization bonds and paid down debt of about $500 million. We also preplanned if you recall last year some debt that we paid down in CERC in the first quarter. So, I think if you look at the year, you are going to see the credit metric, which improved this year and each and every year and they will continue to improve in terms of the cash flow coverage. And you will see the leverage ratio at about the same level; and again we are planning a pretty significant CapEx program.

Lasan,I did say that there is no quick fix. As you know, this is a... as a result of our creation and the fact that we took some large write-offs in connection with our true-up case. And the good news is our coverage metric, I think still look very strong, but our peer book capitalization doesn't. But we are just going to have to work on that overtime if there is no quick fix to it.

Understood. One last question if I may; over the next several year, how much growth CapEx do you expect to spend to drive earnings? And can you kind of give us a sense of how large earnings they should grow over the next several years?

Well, this year we spend... we have a capital of budget of... little over... about $1 billion plus what we spent in SESH. If you look out over the next four years, we've got $800 million capital budget, but there is no new pipeline projects in that. That's really finishing what we have in the normal pipeline. If you look back, we spent $1 billion to $1.2 billion each of the last two years. So we've been growing and investing quite heavily. And I thank it's really going to depend on the opportunities out there. We are hoping to be able to get some new attractive projects, and we'll just have to wait and see. But our core expenditure is going to be at that $800 million range.

Can we calculate your situation as capital constraint, which is opportunity constraint?

Okay.

I don't think we are necessarily capital constraint at this stage. And we are actively seeking opportunities.

I mean that you have a lot of opportunities, but it's a matter of finding for money for it.

No, I don't think I'd characterize it that way. I think we are... if we find good opportunities, they are attractive, create shareholder value, I think we can find them. Obviously we've got to carefully look at how we finance them, but I feel pretty good that we could finance them.

That's great. Thank you David, thanks Gary.

You bet.

Your next question comes from Debra Bromberg with Jeffries & Company. Debra E. Bromberg - Jeffries & Company: Hi, just a couple of quick question here. The $1 billion cost estimate for SESH, is that an increase from your prior estimate, because I had about $700 million to $800 million for that?

I think last year we had talked around $900 million. It is up a little bit. We like... most pipelines these days. We are saving some cost increases in our construction. So, yes, that is up a little bit, Debra. Debra E. Bromberg - Jeffries & Company: And that... does that exclude the incremental capacity to be owned by Southern Natural Gas.

Yes, that only addresses the billion a day that would be owned by Spectra and CenterPoint. Debra E. Bromberg - Jeffries & Company: Do you expect that cost increase have any kind of impact on expected profitability or it's neutral?

Well, no; when costs go up, your profitability is going to be hurt, now the good news I guess if there is good news in it, these projects have a life of 40 or 50 years. So, your earnings are not going to be burdened a huge amount, but it clearly impact profitability. Debra E. Bromberg - Jeffries & Company: And just one other question on your AMI investment; did the PUC authorize the return on that yet?

I think in the rule, they said you would get your cost of capital in your last rate case. Debra E. Bromberg - Jeffries & Company: And can you remind us what that was?

Well, it depends; our last stated K within 2001, where we litigated it in the ROE was 11.25 based on 40% equity 60% debt. In our settled case, we really didn't have an ROE determined. So I think you would either... you go back to 2001 would be what we would suggest and but we are not really sure where that commission will come out on this. Debra E. Bromberg - Jeffries & Company: Great,Thank you.

Your next question comes from the Steve Gambuzza with Longbow Capital.

Good Morning.

Good Morning.

I had a question about the Appeal Court order and potential impact to your future cash flows related to what you were originally awarded at district court. I know it's in the 10-K you filed this morning; it says that unless portion of the Appeal Court order going reverse, you maybe required to refund the $130 million to $350 million? I was trying to replace that in the context of what was previously awarded to you by district court of 650, should we view this $130 million to $350 million as a reduction to this $650 million or is that... this is the refund you would need to make instead of getting any increment for cash flows?

It would be the latter.

Okay. So it is effectively like $800 million swing versus district court?

Well, district court, they clearly reversed the commission on $650 million plus interest now. The appeals court more or less wiped off a lot of that out. There is a bunch of different components here, but the net result is the appeals court would reduce what the commission's original order granted. And it really depends on which component that... if you look at this... what the Supreme Court would do, but if you look at the worst case, and that's what we put in the 10-K was the $357 million, which did not address the... or didn't assume the normalization violation got reversed.

Okay. So, basically the worst case scenario period was that, you don't get any additional refund, which you have never approved anyway.

Right.

And you have to refund somewhere around $350 million for them.

That would include the interest...

Up until as you would accrue like... as obviously the field process take two years if you accrue interest on that amount during the appeal?

Yes. We have described... we had estimate interest through the end of 07. So there would be additional interest in 08 and 09 depending on how it wanted to.

Okay. And I was wondering if you might be able to give some sense for what cash flow from operations you would expect in 2008?

Yes, hang on just...

Yes, it's Gary. Yes, cash flows from operations, we are going to continue to and this is a business as you now see to generate significant cash flow. I think if you look all in for the year, we are going find a CapEx program as David said a little more than $1 billion. So, we are going to... and then as you know we... I am going to describe it like this free cash flow after dividends and after securitization proceeds. And of course working capital is dependent on working capital changes, but if I assume neutral on working capital will actually generate positive cash flow this year. And as that really depends on working capital, but think of that it's about breakeven to slightly positive.

And that's excluding the securitization proceeds?

That includes the securitization of 500 million, yes.

Okay. And then finally, I noticed in the CapEx estimates for this 10-K they were relatively unchanged for Houston Electric versus last year, and so do you want to confirm that your estimates do not include the AMI deployment?

That's correct.

Okay. Okay, thank you very much.

You bet.

Your next question comes from Daniele Seitz with Dahlman Rose.

Thank you. You mentioned that there might be some pipeline opportunities after the one that is in construction. Can you elaborate at all or would those projects be somewhat smaller than the one that you have undertaken recently?

Well, we announced an open season couple of weeks ago. And this would be a pipeline that would probably less than Carthage to Perryville, certainly a lot smaller than SESH. I think we are talking about $250 million to $350 million type of capital related to that one although; there is a lot of work to be done there. But these are good solid projects giving reserves out of the Woodford and Fayetteville Shale areas. We are excited about these projects, but we have to win them, there is a lot of competition to get this thing in the aftermarket.

Great.And can you remind of the total investments in smart meters or something that it is and how long it will take to get to all of the system equipped?

We don't have a deployment plan yet that we are ready to discuss. But if you look at 2 million meters, the cost of the meters, the communication equipment, all of the information technology needs is between probably $750 million to $800 million, something like that, or $850 million. Now, there is an amount you have to put on top of that for some of the intelligent grid work, but if you're just talking about the advanced metering, it's a $750 million to $850 million number.

And it will take probably at least four years or something like that to implement or...

I would say a minimum of five, but most likely a little bit more than that. It really depends on the roll out and obviously how quick... obviously how quickly we start. But as I mentioned, part of our plan here is to develop a deployment plan that helps us verify the market benefits before you spend that kind of money. I mean this is an expensive system to deploy, and it's really about market benefit, not about the benefit that will accrue to our electric P&D business.

Thank you.

The next question comes from John Kiani with Deutsche Bank.

Good morning.

Good morning.

I have another question actually on AMI. I understand that obviously there are some additional steps and processes you are going to be going through with PUCT before you determine that the benefits and also the returns are going to be adequate enough to proceed forward? Can you just give us some additional color on the next steps and also roughly when you think you'll have a better idea if you will push into the more expensive phases of AMI?

I would expect certainly by mid-year, we would have a pretty good plan together that we would lay out, exactly the different phases of our deployment plan. We expect this to be a phase deployment.

Right.

So we can really verify our benefit as we go along. As you know, John, this is... it's not bleeding edge, but it's leading edge technology. It's costly, and we really just need to make sure that the market benefits are there. So far, I think we tell you and you've probably seen at our technology center. We are impressed with the technology so far. We are committed to doing it as long as we can put together a plan that make sense for the company and for all the market. We think Phase I would be a 1.5 to 2 year plan, where we kind of basically deploy enough meters to really their part of benefits. And then Phase II would be a more... a full scale requirement assuming those benefits were positive.

Okay, great. So, then by mid-year 08, we'll probably have a better... you'll have a better idea and we'll have a better idea about whether your kind of push forward with the next phase or not?

Right.

Okay, great. Thanks.

Your next question comes from Faisel Khan with Citi.

Good morning

Good morning

Is there anything that we should read into the commission's initial ROE that they gave to some of the transmission project that will be contemplated by the joint venture between Mid-America and AET [ph]?

Well, I don't know. It looks to me like they granted a return consistent with what, a difficult P&D company as getting and they haven't provided incentive type ROEs that we see it FERC. So, that's the way I have read, Faisel, but I mean you can read as much... as well as we can.

Is there any... is there any sort of read through in terms of what kind of returns you would get on your deployment program? Or are the risks different and the CapEx is different?

Are you referring to our AMI program?

Yes, that's right.

Well, one is I think there might very will be different risk in our program. This is new technology, there is risk of development. And the benefit don't accrue to us, they accrue to the market. So, we don't directly get the benefit with Texas market, and our... all the customers in this area get benefits. So, but I do think that the commission recognizes that, but I... and I think they are going to try that to limit the amount of risk we take, but to be very honest, I think that should be part of the recognition when we go forward this plan.

Okay. Do you think they are... given their desire to get this plan implemented, they could be constructive when it comes to offering is a fair return on those assets?

We certainly hope so.

Okay. In terms of your CapEx for 08, how much of that interstate pipeline CapEx in your 10-K for 08 is related to SESH?

I don't think there is anything in our capital program directly. I think that's... let me make sure that. I maybe have misspoken. Faisel, the capital under pipelines does not include SESH.

Okay.

There is $200 million... $209 million there. The... there is about $294 million that we have disclosed in the 10-K, but most of that money as you know, once we finance that asset joint venture level, we will get that money back, but we are funding that as we go along.

Okay. So, but that's not part of your capital... your CapEx plan in terms of the equity contributions you are making to SESH are not in that cap.

Correct.

Okay. Thanks for the time.

You bet.

Your next question comes from Patrick Forkin with Tejas Securities.

Good morning, with respect to your intelligent grid project, based on your comments over the last couple of calls, it seems like this being pushed out just a little bit. Is that a function of some pushback from the Utility Commission or the technology or none of the above?

It's not the utility commission. I think it's just trying to get a plan that works for our company and for the market, where... it has... we really expect to probably to be... to have a deployment plan filed by now. And it's taken a little bit longer than we thought. As you know, nobody else in the State has done it. Lots of folks around the country are looking at it, and I think because of the cost of it, and the potential... Because it is new technology, we have to be a little bit more cautious here than normal. We haven't done this before, I guess. We are building a transmission lines or substations, it wouldn't be an issue, but this is brand new technology that we need to be sure of.

Sure, fair enough. So, you think once again just to clarify you might have a deployment plan by the end of Q2?

Yes, I would say it about mid year, we should have a deployment plan out there. Let me just clarify, I think the Public Utility Commission is very supportive of us doing this. So, it is not the commission that's holding us back, but we clearly are keeping the commission informed and updated on how we are progressing. And we have to feel comfortable though as the company before we are ready to go to offset and follow on, because when we follow-on, we intend to go and do what we file. So, we have to be... we feel good about it.

Okay, very good. Thank you.

Your next question is a follow-up from Lasan Johong with RBC Capital Market.

Yes, great, thank you. We have started to notice that there are some transmission stabilization issues in Texas because of the ramp up in wind. Do you expect any problems going forward, and are you anticipating these issues and taking some contingency plans?

Not... we are not too worried about this. Obviously, in our area... we are doing some things around voltage control that we have in our plan over the next three or four years to ensure that there is no issue with the grid, and I am sure other utilities in Texas are doing the same thing. So, while it may cost a little money, I don't anticipate this is a big problem for us. Grid planning is something and watching voltage is something that all the technical folks are studying and looking at really close. So, when we get all this wind, it won't create problem. But there will be some additional investment required as result of it.

Okay, that's great. And just a quickly on... obviously there is a lot of discussion right now on recession in the country and what that might do to utilities? Is it somewhat... is Texas somewhat insulated because of the oil and gas business and the therefore in fact to you will be less than what we may assume for a national average?

Well, so far as that's what we have seen. We have seen some impact on what we call starter home markets here in and around eastern. But I think last year there were 38,000 new home starts and the projection for this year is something like 34 to 36. So, the experts that follow that are not projecting a big decline. But I think we have to watch it closely, but I think Texas is a little bit different than the rest of the country. Certainly, what we see in our business is a little slowdown, but not a big slowdown.

That's great. Thank you very much.

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

Hi. I was wondering if you could tell me what the gross and O&M expense that Houston Electric was in 2006... I am sorry, 2007 and what your outlook for O&M growth in the 08 might be?

I don't think we had much of any growth in O&M. There was very small amount. We are projecting at most the rate of inflation. And we believe there are some ways really improve the way we do business to actually beat that. So, O&M increases have not been real significant in the T&D business.

Okay, and then in your remarks on the competitive gas services business, I think you pointed out that some of the basis differentials and volatility that that you have experienced in prior period have started to abate as other pipeline have been constructed in the region. I was just wondering if that... if you noticed any impact of that dynamic at CenterPoint Energy gas transmission, where I think the company has posted very strong returns in 2006 2007 during the some part on why these deferential... is that dynamic present there as well or is that clearly a different issue?

No, as we put in our pipeline Carthage to Perryville, we saw basis shrink. And then there is another pipeline that went into service a little bit, I guess it was in late January, early February and we saw basis shrink again between that area and Perryville. We had seen some basis shrinkage also on our traditional CEGT pipeline. So, all these new pipelines that are being built are clearly going to impact basis, at least that's our expectations. In a kind, it depends on weather and demand and lot of us thanks, but everything else being equal additional pipeline means smaller basis.

Thank you very much.

Your next question is a follow-up from Faisel Khan with Citi.

Just a follow-up on that, but the lower basis doesn't change any of your earnings profile, your pipeline in the ground those are all long-term capacity agreement?

Well, we've tried to take into account Faisel this new dynamic with basis differentials. We do transport a lot of cross-haul across our system. And we make money every year through ancillary services for interruptible current services, and so it can't impact us. And we also have a park and loan service.

Sure.

That we make money at. So, it's not like we are insulated, but if you look at the bulk of our pipeline earnings, they come from selling long-term capacity earning a demand charge, our capacity charge and that's where the bulk of it is, but around the edges that we clearly make money and we are very aggressive at trying to market those services.

Okay, what would you say the benefit from those services were in the 2007 outside at the normal demand charge earnings?

I am going to be guessing now. I am thinking $20 million.

Okay.

Imean overall revenue, there is some cost to go along with that. It's in that range, I think.

Okay. And if you are looking over the long run, next three to five years, given your expected capital deployment plan than your pipeline expansion advance hearing distance, you guys have stated earnings growth assumption that you think about over the long run?

We put our aspirations. We want to grow this business 5% to 6% a year. And your LDCs and your electric businesses can grow as fast as customers base and rate base. And I think 3% or 4% is doable there. We have to have pipeline and gathering opportunities to get above that rate, but we have been able to do that for last few years, and we see opportunities out there, but we don't think we can grow this business at a double digit rate. But we think, 4%, 5%, 6% is in a realistic range.

Okay. Fair enough, thanks.

[Operator Instructions]. Your next question comes from Carl Seligson with NYACK Management.

Good morning.

Good morning.

Relative to the subject of energy efficiency and AMI, are there are any another plans historically on the phased-in installation of meters, such as a request for decoupling?

Carl, we are on the gas LDC side, obviously that's what we have requested, and we've been successful in a number of jurisdictions. We will look it that very hard when go in, in our next rate case on the electric side, which can't be before June of 2010. But decoupling is something I think on the electric side that will give some attention and we'll study that quite a bit as well. And we might very well look at how that impacts us and look at a decouple rate for electric as well. It works a little different in Texas obviously with this deregulated market here. So... but I think it's a fair question and decoupling, I think is now coming to the electric side. It's been on the gas side a while.

Okay, Thanks.

You bet.

Luanne, if there is one more question, we can take it. If not, we can end the call.

Okay, ma'am. We do have one question. It's a follow-up from Daniele Seitz with Dahlman Rose.

Follow-on; I was wondering are you recovering all the uncollectible on the natural gas distribution side in every jurisdiction?

Well, we certainly have a level of bad debt expense in our rates there. It's probably not at the level we incurred in 07. But we have a fairly significant level of bad debt already built into our rate. We earned pretty close to our authorized rate of return, as I indicated in my call. But, I would say that our base rates are probably a little bit short of what we actually incurred in 07. We hope though that comes down and it will get back to a more normal level.

Yes, but you don't have an automatic recovery of the uncollectible right now, I mean as a system?

That's correct.

Okay, great. Thanks a lot.

Okay. Thank you, Daniele.

Okay, thank you very much. I would like to thank everyone for participating in our call today. We appreciate your support very much. And have a great Day. Thank you.

This concludes CenterPoint Energy's fourth quarter and full year 2007 earnings conference call. Thank you for your participation.