CenterPoint Energy Inc (CNP) 2007 Q4 法說會逐字稿

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 managements' remarks.

(OPERATOR INSTRUCTIONS) I'll 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'd like to welcome you 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 p.m.

central time through Thursday, March 6, 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.

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 a good year for us and I'm 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 final settlement of the Company's [zinth] 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 in part 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 our 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.

These same factors also impacted our full-year 2007 performance.

Overall, 2007 was a very good year for us, and we continued 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 zinth tax issue and Houston Electric's 2001 unbundled cost of service remand.

Excluding all the impacts 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.

Houston 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 our 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 rate settlement implemented in October of 2006.

Customer growth remained 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 Houston 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 range 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.

An 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 innovative 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 man that would verify these benefits.

Any deployment would be dependent 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 close to earning our overall authorized rate of return and believe we have set the stage to do so in the future.

We are realizing the benefit from the changes that we made to improve the operational and financial performance of our gas LDCs.

We continued 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 a base rate increase of $20 million and implemented a decoupling mechanism that will stabilize revenues and earnings while helping to facilitate energy efficiency.

We've hedged the weather for the current heating season and we will continue to pursue rate 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 pipeline 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 have been placed in commercial operation, which has had the effect of reducing basis differentials.

In addition, seasonal price differentials have also narrowed.

Both of these developments reduce opportunities for asset optimization.

Our focus is to profitably grow this business by expanding our commercial and industrial 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 one, with almost one billion cubic feet per day capacity, went into service in May and Phase two, 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 one and two have been running at nearly 100% capacity on average since they went into service, which is clear evidence that this pipeline was needed.

A second major project, the 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 1bcf 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 off our existing pipelines to serve new customer facilities, such as an AEP power plant in Arkansas.

Producer drilling activity in the Woodford and Fayetteville shales 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 a row that we've experienced that level of new well connects.

Field 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 remained 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 over $100 million in capital expenditures for new projects and we expect to spend at approximately this level over the next three to five years.

Now let me provide you an update on our true-up appeal.

I'm sure you're aware that the third court of appeals issued its decision on our stranded cost true-up appeal last December.

We are extremely disappointed that the court of appeals reversed portions of the district court's decision that would have allowed us to recover additional amounts related to our capacity [auction] true-up.

The court of appeals also reversed part of the PUC's order that allowed us to recover the excess mitigation credits that we paid to Reliant Energy.

The court of appeals did, however, uphold a ruling by the district court that we would be entitled to recover the interest component of the excess mitigation credit that we paid to retail electric providers other than Reliant.

In addition, the court of appeals ordered that a decision by the PUC on a 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 appeals.

There's no statutory time frame under which the court has to render a decision on these motions, but if our motion is not granted in full, we would then have 45 days to seek review by the the Texas supreme court.

In closing I'd like to remind you of the $0.1825 per share quarterly dividend declared by our board of directors on January 24th.

We believe our dividend actions continued 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 Gary.

Thank you, David -- excuse me -- thank you, David, and good morning to everyone.

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

Let me first discuss our securitization.

Earlier this month we closed on $488 million of non-recourse transition bonds in order to recover the balance of the true-up cost that we had previously been collecting over time via a competition transition charge, or CTC.

We estimate that electric customers in our service territory will save over $100 million over the life of the bond because the weighted average interest rate 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 have applied 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 funds 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 this 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 to clarify that all true-up amounts are securitizable.

Now let me review some of our accomplishments in 2007 and discuss our financing goals and objectives for 2008 and beyond.

In 2007 we took a number of steps to continue to strengthen our liquidity.

Last June we amended our three bank credit facilities, which now total $2.45 billion, and extended their maturities to 2012.

Later in the year we also extended the CERC receivables facilities until October of2008.

The facility will range in size from $150 million to $375 million in order to efficiently track the projected receivables 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 facilities.

In October we closed on the sale of $500 million of CERC notes.

Proceeds from these notes were used to retire $300 million of CERC 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 the 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 at 3.75% convertible senior notes due in 2023.

At the end of 2007 we began to see a number of holders convert these securities, and to date, approximately $173 million of principle 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 to call the notes at the 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 principle in cash, but have the option to pay the premium over the original amount in cash or stock.

As David mentioned, each of our business units will continue to seek value-creating investment opportunities.

Ultimately, any permanent financing to fund our growth projects will consider the optimum mix of debt and equity consistent with maintaining and enhancing the credit metrics and credit ratings of 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 utilities, 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 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 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 you to please limit yourselves to one question and a follow up.

Luanne, would you please give the instructions on how to ask a question?

(OPERATOR INSTRUCTIONS) Our first question comes from Lasan Johong with RBC Capital Markets.

Good morning.

Congratulations on a good quarter and year.

Wanted to ask you 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 at 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 -- that are being experienced in today's market.

We incurred 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're 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 accounts there.

We incurred quite a bit of credit and collection expense there and we think we're on top of that situation now and we don't think a lot of those costs will be repeated.

So I would say that we're not expecting a huge run-up in bad debt expense, but it's something we've got to stay on top of and we're in the $7 to $8 gas price range for this year,

Okay.

And then I'm assuming that the range of that $0.10 of the guidance has a lot to do with weather and volumes for Field Services and other demand-based 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've seen volatility really quiet down in these markets.

As I said, we have a lot of new pipelines, seasonal spreads have narrowed.

So we're projecting '08 to 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 the number of shares and the converts.

How much do you expect to issue on the converts as they -- if you're assuming -- 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 metrics are fine but just optically your book ratio looks kind of high, 84%.

Any plans to remedy all of that?

This is Gary.

Let me start with the converts.

I think if you look at the converts that we've -- 173 million that have been converted today, we've issued a little more than five million shares.

Again, of course, assuming that we were to call -- or they were to be put to the remaining 402 million and if you assume a share price of $15.50, for example, that would be about ten million shares.

As you know, Lasan, it depends on the price of the shares at that point in time.

Of course.

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 share count, those are already in the fully-diluted shares, 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 I think -- think about those sort of amounts.

Also wanted to mention the tax rate to you.

Going forward, I think you'll assume a tax rates more normalized of about 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 state audit.

As you know, our Company, like many others, are audited both by the Internal Revenue Service and by the various states in which we do -- where we operate.

Going forward, think of a more normalized tax rate as well.

Hope that's helpful.

Yes, what about the book leverage ratio?

It's not really that critical, but --?

Yes, I think, Lasan, on the book -- I think you used a number that probably included the securitization debt, but yet exclude the securitization debt and we're 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 ponds and paid down debt of about $500 million.

We also prefunded, 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're going to see the credit metrics which improved this year and each and every year and they'll continue to improve in terms of the cash flow coverages, and you'll see the leverage ratio at about the same level.

And again, we're funding a pretty significant CapEx program.

Lasan, I'd just say that there's 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.

The good news is that our coverage metrics, I think, still look very strong but our pure book capitalization doesn't.

We're just going to have to work on that over time.

There is no quick fix to it.

Understood.

One last question, if I may.

Over the next several years, how much growth CapEx do you expect to spend to drive earnings, and can you give us a sense of how large your earnings base should grow over the next several years?

Well, this year we spent -- we have a capital budget of a little over -- about $1 billion plus what we spend in SESH.

If you look out over the next four years, we've got $800 million capital budgets, but there's no new pipeline projects in that.

That's really finishing what we have and then 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 think it's really going to depend on the opportunities out there.

We're hoping to be able to get some new attractive projects and we'll just have to wait and see.

But of course, expenditure is going to be at that $800 million range.

Can we characterize your situation as capital constrained versus opportunity constrained.

I don't think we're necessarily capital constrained at this stage and we're actively seeking opportunities.

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

No, I don't think I'd characterize it that way.

I think we're -- if we find good opportunities that are attractive, create shareholder value, I think we can fund 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.

Next question comes from Debra Bromberg with Jefferies & Company.

Hi, just a couple of quick questions 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.

Like most pipelines these days, we are seeing some cost increases in our construction, so yes, that is up a little bit, Debra.

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 SESH -- Spectra and CenterPoint.

Do you expect that cost increase to have any impact on expected profitability or it's neutral?

Well, no, when costs go up your profitability's going to be hurt.

Now, the good news I guess, if there's good news in it, these projects have an econom -- have a life of 40 or 50 years, so your earnings aren't going to be burdened a huge amount but it clearly impacts profitability.

And just one other question on your AMI investment.

Did the PUC authorize a return on that yet?

I think in the rule they said you would get your cost of capital in your last rate case.

Can you remind us what that was?

Well, it depends.

(LAUGHTER) Our last stated case was in 2001 where we litigated it and the ROE was 11.25 based on a 40% equity, 60% debt.

In our settled case we really didn't have an ROE determined.

So I think it would -- either you go back to 2001 would be what we would suggest and -- but we're not real sure where the commission will come out on this.

All right.

Thank you.

All right.

Your next question comes from Steve Gambuzza with Longbow Capital.

Good morning.

Good morning.

I had a question about the appeal court order and the potential impact here to your future cash flows related to what you were originally awarded by the district court.

I noticed in the 10-K you filed this morning it says that unless portions of the appeal court order ruling are reversed, you may be required to refund $130 million to $350 million.

I'm just trying to place that in the context of what was previously awarded to you by the district court of $650 million.

Should we view this $130 million to $350 million as a reduction to the $650 million or is that -- this is the refund you would need to make instead of getting any incremental cash flows?

It would be the latter.

Okay.

So it's effectively like an $800 million swing versus the district court?

Well, district court, they clearly reversed the commission on $650 million plus interest.

Now, the appeals court more or less wiped a lot of that out.

There's a bunch of different components here.

But the net result is the appeals court would reduce what the commission's original order granted us.

And it really depends on which components that -- if you look at this at what the supreme court would do, but if you look at the worst case -- that's what we put in the 10-K -- it 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 for you is you don't get any additional refund, which you've never accrued anyway, and you have to refund somewhere -- somewhere around $350 million plus interest?

No, that includes interest.

That would include interest through the end of the year.

Up until you -- as you say the appeal process takes two years, would you accrue interest on that amount during the appeal?

Yes.

We had tried -- we have estimate interest through the end of '07, so there'd be additional interest in '08 and '09, depending on how long it took.

Okay.

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

Hang on just a minute here.

Yes, it's Gary.

Cash flows from operations, we're going to continue to -- and this is a business, as you know, Steve, that generate significant cash flow -- I think if you look all-in for the year we're going to fund a CapEx program, as David said, a little more than $1 billion, so we're going to -- then, as you know we -- I'm going to describe it like this.

Free cash flow after dividends and after securitization proceeds and, of course, working capital -- dependent on working capital changes, but if I assume neutral on working capital we'll actually generate positive cash flow this year.

So it really depends on working capital, but think about -- it's about break-even to slightly positive.

And that's excluding the securitization proceeds?

That includes the securitization, the $500 million, yes.

Okay.

And then finally, I notice in the CapEx estimates for this 10-K they were relatively unchanged for Houston Electric versus last year and so I just 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 [approaching ETs] after the one that is in construction.

Can you elaborate at all or will those projects be somewhat smaller than the one that you have undertaken recently?

Well, we announced an open season a couple weeks ago and this would be -- this would be a pipeline that was probably less than Carthage to Perryville, certainly a lot smaller than SESH.

I think we're talking about $250 million to $300 million type of capital related to that one, although there's a lot of work to be done there.

But these are good, solid projects, getting reserves out of the Woodford and Fayetteville shell areas, and we're excited about these projects but we have to win them.

There's lots of competition to get this same gas to market.

Agreed.

And can you remind me of the total investment in smart meters, assuming that it is -- and how long it will take to get all of the system equipped?

We don't have a deployment plan yet that we're ready to discuss, b But if you look at two million meters, the cost of the meters, the communication equipment, all of the information technology you need, it's between probably $750 million to $800 million, something like that, or $850 million.

Now, there's an amount you;d have to put on top of that for some of the intelligent grid work, but if you're just talking about advanced metering, it's that $750 million to $850 number.

And it would 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 how qui -- 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.

This is an expensive system to deploy and it's really about market benefits, not about the benefits that will accrue to our electric T&D business.

Thank you.

Your 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 that you're going to be going through with the 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 extensive phases of AMI?

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

We expect this to be a phased deployment, so we can really verify benefits 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, as I think we've told you and you've probably seen at our technology center, we're impressed with the technology so far.

We're committed to doing this as long as we can put together a plan that makes sense for the Company and for all the market.

We think Phase one would be a one-and-a-half to two year plan where we basically deploy enough meters to really verify the benefits.

And then Phase two would be a full scale deployment, assuming those benefits were positive.

Okay, great.

So then by mid-year '08 we'll probably have a better idea -- you'll have a better idea and we'll have a better idea about whether you're going to push forward with the next phase or not?

Right.

Okay, great.

Thanks.

Your next question comes from Faisel Kahn with Citi.

Good morning.

Good morning.

Is there anything that we should read into from the commission's initial ROE that they gave to some of the transmission projects that were being contemplated by the joint venture between Mid-America and AET?

Well, looks to me like they've granted a return consistent with what a typical TND company is getting and they haven't provided incentive-type ROEs that we see at FERC.

So that's the way I read it, Faisel, but you can read those as much -- as well as we can.

But is there any read through in terms of what kind of return 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.

That's right.

Well, one is I think there might very well be different risks in our program.

This is new technology.

There's risk of development.

And the benefits don't accrue to us, they accrue to the market.

So we don't directly get the benefits.

It's the Texas market and all the customers in this area get the benefit.

So -- but I do think that the commission recognizes that and I think they're going to try to limit the amount of risk we take, but be very honest, I think that should be part of the recognition when we go forward with this plan.

Okay.

So you think they're -- given their desire to get this plan implemented, they could be constructive when it comes to offering you 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 the SESH?

I don't think there's anything in our capital program directly, is there?

I think that's --

let me make sure of that.

I maybe have misspoken.

Faisel, the capital under pipelines does not include SESH.

Okay.

There's $200 million -- $209 million there.

There's about $294 million that we have disclosed in the 10-K, but most of that money -- as you know, once we finance it at the joint venture level, we'll get that money back, but we're funding that as we go along.

Okay.

But that's not part of your capital -- your CapEx plan in terms of the equity contributions you're making to SESH are not in that cap --?

Correct.

Okay, understood.

That's 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 and based on your comments over the last couple of calls it seems like this is being pushed out just a little bit, is that a function of some push-back from the utility commission or the technology or none of the above?

It's not the utility commission.

I think it's just us trying to get a plan that works for our Company and for the market.

It has -- we really expect it 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.

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 hadn't done this before I guess.

If we were building 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 by 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're progressing and we have to feel comfortable, though, as a Company before we're ready to go to Austin and file one, because when we file one, we intend to go and do what we filed, so we have to be -- we have to feel good about it.

Okay.

Very good.

Thank you.

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

Yes, great.

Thank you.

We've started to notice that there's 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?

We're not too worried about this.

Obviously in our area we're 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'm sure other utilities in Texas are doing the same thing.

So while it may cost a little money, I don't anticipate this as 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 that when we get all this wind it won't create a problem, but there will be some additional investment required as a result of it.

Okay.

That's great.

And just quickly on -- obviously there's a lot of discussion can 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 therefore impact to you would be less than what we may assume for a national average?

Well, so far that's what we've seen.

I think -- we have seen some impact on what we call starter home markets here in and around Houston, But I think last year there were 38,000 new home starts and the projection for this year is something like 34,000 to 36,000, so the experts that follow this are not projecting a big decline.

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 growth in O&M expense at Houston Electric was in 2006 -- I'm sorry, 2007, and what your outlook for O&M growth in '08 might be?

I don't think we had much if any growth in O&M.

There was very small amount.

We're projecting at most, the rate of inflation and we believe there are some ways to 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 you experienced in prior periods have started to abate as other pipelines 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 and 2007, driven in some part on wide basis differentials.

Is that dynamic present there, as well, or is that a completely different issue?

No, as we put in our pipeline, Carthage to Perryville, we saw basis shrink and then there's 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 have 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 expectation.

And it depends on weather and demand and a lot of other things, but everything else being equal, additional pipelines means smaller basis.

Thank you very much.

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

Follow up on that, but the lower basis doesn't mean -- doesn't change any of your earnings profile, your pipelines in the ground, those are all long-term capacity agreements?

Well, we 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 interruptable services and so it can impact us, and we also have a park and loan service that we make money at.

So it's not like we're insulated, but if you look at the bulk of our pipeline earnings, they come from selling long-term capacity, earning a demand charge -- or capacity charge and that's where the bulk of it is.

But around the edges that we clearly make money in, we're very aggressive at trying to market that -- those services.

Okay.

What would you say the benefit from those services were for 2007, outside of the normal demand charge earnings?

I'm going to be guessing now.

I'm thinking $20 million overall revenues.

There's some costs that go along with that.

It's in that range, I think.

Okay.

And if you're looking over the long run, next three to five years, given your expected capital deployment plans and your pipeline expansion and the advanced metering systems, do you guys have a stated earnings growth assumption that you think about over the long run?

We've put out our aspirations.

We want to grow this business 5%, 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 the last few years and we see opportunities out there.

We don't think we can grow this business at a double-digit rate, but we think 4%, 5%, 6% is in the realistic range.

Okay.

Fair enough.

Thanks.

(OPERATOR INSTRUCTIONS) Your next question comes from [Carl Selickson] with Nyack Management.

Good morning.

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

Carl, we're -- on the gas LDC side, obviously that's what we're -- that's what we've requested and we've been successful in a number of jurisdictions.

We will look at that very hard when we 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 get 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.

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's one more question we can take it.

If not, we can end the call.

Okay, ma'am, you do have one question.

It's a follow up from Daniele Seitz with Dahlman Rose.

Small one.

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 debts already built into our rates.

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 that comes down and it'll get back to a more normal level.

Yes.

But you don't have an automatic recovery of the uncollectible right now as the system?

That's correct.

Okay, great.

Thanks a lot.

Thank you, Daniele.

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.