CenterPoint Energy Inc (CNP) 2006 Q3 法說會逐字稿

Good morning, and welcome to CenterPoint Energy's third quarter 2006 earnings conference call with senior management.

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

There will be a question-and-answer session after management's remarks. [OPERATOR INSTRUCTIONS].

I'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 to our third quarter 2006 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 third quarter results, and we'll 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 our prepared remarks.

Our third quarter 2006 earnings release and Form 10-Q filed earlier today are posted on our website which is www.CenterPointEnergy.com under the investor section.

I would like to remind you that any projections or forward-looking statements made during this call are subject to the cautionary statements on forward-looking information in the Company's filings with the SEC.

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

Central Time through Thursday, November 9th, 2006.

To access the replay, please call 1-800-642-1687 or 706-645-9291 and enter the conference ID number 7741030.

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.

David?

Thank you, Mary Ann.

Good morning, ladies and gentlemen.

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

Let me begin with our third quarter results.

This morning, we reported net income of $83 million for the third quarter of 2006, or $0.26 per diluted share.

This compares to net income of $50 million or $0.15 per diluted share for the same period last year.

Year-to-date, net income was $365 million or $1.14 per diluted share compared to $171 million or $0.51 per diluted share last year.

As a reminder, our 2006 year-to-date results include the impacts from the resolution of both the ZENS tax issue and Houston Electric's 2001 unbundled cost of service or UCOS recommand.

Excluding all the impacts related to these issues, our year-to-date earnings would have been $0.88 per diluted share.

Now I'd like to briefly describe the third quarter performance of each of our business segments.

More detail on our segment results can be found in our press release and in our Form 10-Q that we filed this morning.

I'm pleased to say that our businesses performed well in the quarter.

Unlike last year when two hurricanes impacted both our gas and electric businesses, this year was unaffected by extreme weather conditions.

Houston Electric had a solid third quarter, reporting operating income of $187 million excluding amounts related to its transition bonds compared to $174 million last year.

We continued to experience very strong customer growth, adding nearly 50,000 customers since September of last year. 2006 will mark the ninth consecutive year that customer growth was 2% or better in our Houston market.

Although weather was not an issue for us in the third quarter of this year, with Houston's temperatures being fairly normal, we did have a negative weather variance compared to last year when the weather was abnormally hot.

We estimate that weather had a $14 million negative impact relative to last year.

Our Pipeline and Field Services segment continued its trend of strong quarterly performance with operating income up over 30%.

Our Field Services business again benefited from strong drilling activity in the mid-continent area and our interstate pipelines enjoyed demand for transportation services comparable to last year.

Our Pipeline group also benefited this quarter from the sale of excess cushion gas which was no longer required as a result of improvements we made at one of our gas storage facilities.

Our Competitive Natural Gas business also had a very good quarter.

It reported operating income of $12 million compared to $4 million last year.

This business continues to benefit from natural gas price volatility and both locational and seasonal price differentials.

Operating income in the third quarter benefited from increased natural gas sales from inventory, and the positive impact of mark to market accounting primarily related to financial derivatives used to lock in basis differentials.

Partially offsetting these increases was a write-down of our natural gas inventory to market price due to a decline in gas prices at the end of the third quarter.

This was the third inventory write-down that we have recorded in as many quarters.

Since we have had futures sales through the use of financial derivatives, we should realize an increase in operating income in future periods.

Our Natural Gas Distribution business reported an $11 million operating loss, which was a $5 million improvement over last year.

It is important to remember that this is a seasonal business and the second and third quarters are typically the lowest earnings quarters of the year.

We continue to benefit from solid customer growth and the implementation of new rates.

Partially offsetting these benefits were increased bad debt expenses, which have plagued this sector for the last year or so.

Overall, I believe the Company had a solid third quarter and the strength of our geographic, regulatory, and business diversity was very apparent.

Now I'd like to provide an update on a number of regulatory matters.

First, in the third quarter, we entered into a settlement which resolved the Houston Electric rate case and the remand of the 2001 UCOS proceeding.

I am pleased to have these issues behind us, and we look forward to rate stability and certainty for the next four years.

Our focus now is to improve both operationally and financially.

We are also very close to having the Minnesota gas rate case completed.

Just about a year ago, we filed a $41 million rate request with the Minnesota Public Utilities Commission and implemented an interim rate increase of $35 million in January.

Last month, the commissioners took up this case and based on their deliberations, we believe they will grant a rate increase of about $21 million.

The final order should be issued before the end of the year.

We have been recognizing revenues at a slightly higher amount than we expect to be approved and made the appropriate adjustments in the third quarter.

We also have a request before the Minnesota Commission to recover about $45 million in purchased gas costs related to the first half of 2006 and prior years.

Of the total, about $21 million relates to gas costs for the years 2000 through 2004.

Because the Commission has already approved gas costs for these years, a waiver of the Commission rules will be required for the Commission to consider our request.

The remaining amounts to be recovered will not require any waiver since the Commission hasn't considered the gas costs for those years.

The only remaining major rate case that we currently foresee is in Arkansas.

We expect to file that request early next year.

We will continue to pursue the implementation of operational efficiencies and best practices in our regulated utilities and seek rate relief only when necessary.

Now, let me provide an update on some of our growth initiatives.

I'm pleased that we have several opportunities in our Pipeline and Field Services group.

Driven in large part by the current natural gas market dynamics, these growth opportunities have the potential to push this segment's earnings to a new level and have a very material impact on future CenterPoint earnings.

Last fall, our Pipeline group announced a project to construct a 172-mile pipeline between Carthage, Texas, and our Perryville hub in northeast Louisiana.

Last month, we received FERC approval and began construction in mid-October.

The first phase of this pipeline, with capacity of about 1 billion cubic feet per day, is expected to be in service in the first quarter of next year.

We expect a second phase to be placed in service next summer, bringing the capacity to a little over 1.2 billion cubic feet per day.

Based on strong interest for a third phase, we plan to expand this project to 1.5 billion cubic feet per day by adding compression.

Phase 3 is expected to be in service by the end of next year or early 2008 subject to the receipt of FERC approvals.

This is an excellent project in a capacity constrained area and is expected to provide attractive returns to the Company beginning next year.

Once fully in service, we expect that this project should add between 85 and $95 million of operating income per year.

A second major project is one we call the Southeast Supply Header, or SESH.

Last November, subsidiaries of CenterPoint Energy and Duke Energy signed a Memorandum of Understanding to evaluate market and develop this pipeline, which will connect our Perryville hub to Duke's partially owned Gulfstream Natural Gas System in southern Alabama.

In August, Florida Power and Light signed an agreement for about half of the planned 1 billion cubic feet per day capacity, subject to approval by the Florida Public Service Commission.

We continue to work with a number of other potential shippers for the remaining capacity.

We remain very positive about this project, which is expected to be in service in mid 2008.

Last June, we announced another joint project with Duke called the Mid-Continent Crossing, designed to provide primarily the East Coast markets with access to abundant supplies of natural gas located in the producing basins of the mid-continent, Rockies, and West Texas.

In order to evaluate the project's market potential, we conducted an extended open season that ended in July.

It is clear to us that additional pipeline capacity is needed to provide market access for the Barnett, Woodford, and Fayetteville shale reserves as well as some other mid-continent reserves.

It is still too early to know what the final scope of this proposed project might ultimately be.

We are currently focusing our commercial discussions on a 300-mile pipeline segment that would run from Arkansas to northern Alabama.

Our Field Services business is also enjoying gathering and processing opportunities related to the significant drilling occurring in the mid-continent area.

This business has been -- has seen an increase in the number of new wells it has added to its gathering system from a historical average of 250 per year to nearly 400 in each of the last two years, and is on a similar track in 2006.

This year, we have approved new growth projects of over $100 million.

We'll spend approximately $60 million of that amount this year and the rest next year.

This compares to average expenditures of $30 million or so in prior years.

We are also investing in new transmission infrastructure like Houston Electric's Hillje project, a high voltage line which is designed to improve reliability and relief congestion, both essential to electric service in Texas.

The line will extend from the South Texas Nuclear project -- or plant in Matagorda County in south Texas through the Hillje substation and ultimately to the W.A.

Parish substation in Fort Bend County, right outside of Houston.

Over the next five years, we expect to invest in a number of additional transmission projects in our certificated service territory.

We're very pleased with all of these growth projects and continue to seek additional opportunities that fit our energy delivery strategy.

Before I turn the call over to Gary, I'd like to remind you of the $0.15 per share quarterly dividend declared by our Board of Directors last week.

The dividend is payable on December 8th to shareholders of record as of November 16th.

We believe that our dividend demonstrates a strong committment to our shareholders.

As we have previously stated, our long term objective is to pay a dividend between 50 and 75 % of sustainable earnings.

Now I'll turn the call over to Gary.

Thank you, David, and good morning to everyone.

I'd like to discuss a number of items with you this morning, but let me apologize in advance that I do have a bit of a cough this morning so please hang with me.

Let me start with an update on the tax rate for the quarter and the expected tax rate going forward.

If you recall, I indicated to you in our last conference call that the effective tax rate should return to approximately 36% following the resolution of the ZENS issue.

However, there were two items that increased our effective tax rate to approximately 45% for the quarter.

The first was an increase of approximately $9 million related to an increase in deferred state income taxes.

The second is an adjustment to the tax reserve of approximately $6 million related to various legacy tax issues pending resolution with the Internal Revenue Service.

Certainly, there's been a lot of noise this year in our tax rate.

Not only with the ZENS issue, but with the settlement of various legacy tax issues with the IRS.

Obviously, this is a complicated area; however, our current projections indicate that our fourth quarter normalized tax rate should be in the range of 36 to 38%.

Now I'd like to elaborate a bit more on the Houston Electric rate case as it applies to earnings in the fourth quarter.

Annualized base rates were adjusted downward by $58 million effective October 10th, and we have started funding both the low income and energy efficiency programs.

Therefore, we expect the fourth quarter impact to be approximately $0.04 per diluted share.

However, I think it is important to note that with the rate stability and certainty provided by this settlement, we have the opportunity to capture the benefits of operational efficiencies, process improvements, and growth in our service territory.

Now let me discuss our financial priorities.

Our full attention remains 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.

As David mentioned, we continue to make progress in a number of excellent growth opportunities.

We plan to finance these opportunities as well as our ongoing capital requirements through internally generated cash flow, cash on hand and our existing credit facilities.

We also expect to join with other stakeholders and ask the Texas legislature to authorize securitization of the competition transition charge now being collected by Houston Electric.

Securitization would have the dual benefit of saving our customers money while accelerating the collection of the remainder of our true-up balance.

In addition, let me remind you that the Southeast Supply Header project with Duke will be financed at the joint venture level, which minimizes the contribution required by the Company.

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.

Let me close this morning with a discussion of our earnings guidance.

We expect 2006 diluted earnings per share to be in the range of $1.00 to $1.10 compared to our prior guidance of $0.90 to $1.00.

Let me point out that our guidance excludes the $0.33 per diluted share positive net impact of the ZENS tax issue.

Our guidance also excludes the one-time negative impact of $0.07 per diluted share from the resolution of the UCOS remand.

I would also like to remind you that there is no ongoing earnings impact from these two issues.

Included in our guidance is an estimated impact of the Houston Electric rate settlement and the CTC interest rate change, and we have made certain economic and operational assumptions, including the outcome of various other regulatory proceedings at our LDCs in considering our earnings estimate for the year.

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

Okay, we're ready to take questions.

In the interest of time, I'd 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?

[OPERATOR INSTRUCTIONS]. [Neal Troy], Pequot Capital.

Yes, hi.

Good morning.

Actually, it's David Frank.

How are you?

Good morning, David.

Hi.

David, a question on the transmission plans.

Have you looked at maybe JV'ing with anybody in the state?

Or -- I mean, is this a real potential source of growth we should look at for you?

Well, the way transmission is built in Texas is by the utilities that have certificated service territories; and certainly, there's going to be some additional transmission built in this state.

There's going to be some in our territory, but a lot of it's going to be built in West Texas and in north Texas.

We have some interest and -- investing in additional transmission.

We haven't had -- really looked at a joint venture or anything of that nature; but certainly, transmission's an area we have an interest in.

We have a good model here in Texas, and we'd like to do more of it.

Great.

And just as a quick follow-up, on the potential for the mid-continent pipeline, I think in the past you guys have said this would be a fairly large investment and might require the need to do equity, but listening to your call this morning, it sounds like you have more plans to use cash and credit for growth.

Is -- could there be a change in how I should potentially look at financing this plan if it does go through?

Well, I think you have to kind of look at what we see today at the mid -- in the Mid-Continent Crossing project.

We originally announced it could go as far as from West Texas all the way up to Pennsylvania.

I think we found that there's not enough interest for the full scope of that project at this stage.

We have found a lot of interest in certain regions that this pipeline would cross.

And as I mentioned, we're focused now on a segment that would go from the Arkansas area into some interstate pipelines going to the Northeast, probably interconnecting in northern Alabama.

So the project probably is much smaller than the potential that we had outlined earlier, and -- and it is a joint venture with Duke, so our part of it will be significantly less than if we were doing this on our own.

We would plan to do a significant amount of financing at the joint venture level, so I don't think that we're going to need a huge amount of financing; but certainly, we've got a lot of major projects on our plate and we'll just see how these things turn out over time.

Okay.

Thanks a lot.

Faisel Khan, Citigroup.

Good morning.

Good morning.

I wanted to follow-up on that mid-continent pipeline.

Do you have -- between you and Duke, do you guys generally have all of the rights of ways to construct that pipeline?

No, we don't.

We'd have to go out and get that pipeline, Faisel -- I mean get the right-of-way.

Okay.

I guess I'm sort of limited to two questions.

When do you start thinking about giving guidance for '07?

We -- typically, we give guidance when we announce the full year results which would be some time in February of next year.

Okay.

Fair enough.

Thank you.

Okay.

Michael Goldenberg, Luminous Management.

Good morning.

Good morning.

Just had a quick question on the guidance for 2006.

Can you spend a little more time talking about the reasons why you raised guidance?

If you -- when you originally put together your budget, the reasons that you're now moving up your guidance, are those things that are more one-time, such as weather, or has there been a fundamental shift in some of the drivers that will carry on going forward?

Well, first, weather has been unusually mild when it comes to our gas LDCs, so actually, we've -- against normal weather, we've lost about 20 to $25 million in revenues.

But we've had particularly good years in some of our Pipeline Field Services, Energy Services.

Some of those, I believe, will be there ongoing.

Some of them we're just taking advantage of opportunities that the marketplace gives us.

When we look -- we've had a good year-to-date result.

The first three quarters have been better than our expectations, so that's why we raised our guidance.

And we think we're going to have a good, solid year.

We -- but there's not anything fundamentally that's changed from our businesses from what we thought about the first of the year.

Any way to quantify the dollars of drivers that you believe have been fundamentally -- have fundamentally changed and will go on into the future?

I think you kind of have to do that yourself, Michael.

You look at our segment results and you'll see that certain segments are doing very well, and a lot of that is sustainable but some of it is not.

We haven't -- I hadn't sat down and done that analysis, but I think based on kind of our disclosure, you could figure it out.

Got you.

Well, congrats again.

Good luck.

Okay.

Thanks, Michael.

Daniele Seitz, Dahlman Rose.

Thank you.

I just was wondering in the transmission -- new transmission lines, what are the -- permits that you require and all of those that have already been obtained?

Well, the one project that I described was the Hillje project.

We have gotten that one approved the Public Utility Commission.

It's under construction.

It will be completed late this year, early next year.

That one is actually ahead of schedule.

We got the approvals for that really in record time before our Commission.

We have a little different way of doing transmission planning here in Texas.

ERCOT, the Electric Reliability Council of Texas, identifies along with utilities where there's congestion, where there's need for transmission, and they go along with the utility to the Public Utility Commission for approval of these projects, and that tends to speed it up some.

You still always have the issues around gaining right-of-ways and working with land owners.

We -- I think we did a particularly good job this past year, but those are issues that I think are the touchiest issues when it comes to building transmission and you just have to work hard at resolving those issues early in the process.

And you usually get return as you go?

I mean, sort of [equip or to not equip] -- as far as returns are concerned?

We have the opportunity as our transmission cost of service increases to request an increase in our transmission rate.

As part of our rate settlement, we agree to not seek a change in our transmission cost of service rate for two years, so it'll be 2008 before we could make a filing, but after that, you can make a filing up to I think twice a year.

Great.

Thanks a lot.

Scott Engstrom, Satellite Asset Management.

Good morning.

Good morning.

Question for you, Gary, on the '06 guidance.

There was -- you talked about what -- those two items that have been excluded.

There was also kind of the 21 million of tax reserve, I think, added back in the second quarter, which I believe is included.

Is the $1.00 to $1.10 then based on that 36% kind of going forward tax rate, or is that based on what we'll kind of actually have and excluding those two items?

No.

I think you're right.

The $0.88 includes that 21 million that you referenced, and going forward, the $1.00 to $1.10, our -- we're using 36 to 38% in that guidance forecast.

Okay.

But the -- so the actual though may be different than that 36?

Well, it's possible and again, as I mentioned, the noise that we've had really solving a number of legacy issues and for example, the two items I mentioned this time, an adjusted to our reserve on an audit issue and then the state tax.

I'm trying to give you what I think it is inclusive of the things at least we know about today.

Okay.

That's fine.

Follow-up question's on the LDC businesses.

Can you kind of give us maybe a spread between what you're -- what you have been earning either on a looking back 12 month basis, or based on the guidance you're using for '06 relative to your allowed rate of return and what that gap would be either on an EBIT or an earnings basis?

Scott, I think the -- the first thing you have to look at -- and let me give you just a few numbers that will help.

We're behind based on weather by a little over -- almost $25 million.

I think the specific kind of calculated number is 23, but around 20 to 25 million.

We've taken some restructuring charges this year of almost $11 million, and then we've had bad debt expenses that are higher than normal and I would say that's in the order of 5 to $10 million.

So if you kind of add up what -- which I think are anomalies, the weather, and these other items, you get something pretty close to 40 million to $50 million that we think the business could have produced had it not been for those items.

We have a couple of jurisdictions that continue to not earn their authorized rate of return.

Arkansas is one of them.

We indicated we're going to go in for a rate case there.

A number of our jurisdictions are doing just fine, and we just got a Minnesota rate case that -- we've been recording those revenues this year, so we're doing fine there, and in Houston and in many parts of Texas.

But we've got a couple of areas, in particular, Arkansas, that we are not earning our authorized rate of return, or really anywhere close.

Okay.

If you kind of added those back, though, would you estimate that would get you close -- closer to at least on a consolidated basis?

I realize it's different in the different jurisdictions, but kind of closer to where you're authorized?

I would say it would get close, but I'd have to look at Arkansas.

I don't think it would -- it'd get us all the way there because of the under earnings in Arkansas.

But for that, I would say yes.

Okay.

Thank you.

Charlie [Center], Morgan Stanley.

Good morning.

Good morning.

Question, you've taken about $37 million in year-to-date mark to market gains.

Is any of this expected to reverse?

And then also just the timing of the reversals of the 56 million of gas write-downs.

Is that going to be 4Q and 1Q, or is that the way to think about that, or just comments along those lines?

Yes.

Okay.

Do you want me to take it?

Yes, Gary, why don't you?

Yes, that's right.

I think we've had $56 million of inventory write-downs, about 9 of that is reversed through the this -- through the third quarter.

I think you have to think of that as reversing the rest of that is -- the business cycle is basically an April to May or the cycle that ends at the end of April sort of time frame, and so you have to look at the cycle.

So those things will reverse during that time frame.

We really can't commit as to whether -- it depends on gas prices of how much that will be in the fourth quarter, Charlie, and then how much of it will be in, I'll say, in the end of the first quarter.

Okay.

And then the mark to market gains?

There's -- is there any reason that that would reverse or that's just income that's just there and shouldn't reverse out later?

Well, no.

Both of these, whether it be -- yes.

Those will -- when the physical transaction is recorded, you'll record the actual, so I think both of those, whether it be from the derivative or from a physical sale, during that business cycle will all manifest itself in the income statement.

Okay.

I think in -- on the mark to market though, Charlie, I think what we'll do is we'll get the cash in future periods.

The income we've already recognized because we're marking those derivatives to market.

Okay.

So it's a cash settlement later on, not necessarily an income statement impact.

Okay.

So then it is a cash settlement, not an income statement then it wouldn't reverse, I guess?

Right.

I think it's already been reflected in the income statement.

Okay.

And then just any timing on the Southeast Supply Header as to when you think you might reach that -- kind of a decision to go forward or not go forward with that project?

Well, I think the only contingency at this part -- at this stage is the approval by the Florida Public Service Commission of FP&L's request.

As I understand it, they've made a formal request there and we expect it to be this fall at some point in time where that Commission takes action.

We also, obviously, are going to have to make our FERC applications.

We'll do that, I'd say, within the next month or so in order to get these certificates in time to get this thing built by mid-2008, but I think the key thing in front of us now is approval by the Florida Public Service Commission of FP&L's application.

Okay.

Thank you.

Steven Gambuzza, Longbow Capital.

Good morning.

Good morning.

Just a quick question with guidance you gave with respect to the Carthage to the Perryville project.

What is the -- now that you've updated, you upped the capacity for Phase 3, what would be the total project cost for Carthage to Perryville?

It's between 500 and 510 million.

Okay.

And you said the operating profit contribution should be somewhere between 85 and 95 million a year?

Correct.

Once you get all three phases in service, which won't be until 2008.

Okay.

And would you expect to earn, given the fact that you'll be project financing the other two potential pipeline projects?

Do you expect to earn slightly higher returns on capital at those projects?

I think it's hard to compare the two.

The dynamics are different.

The market's different.

The customers are different.

We obviously wouldn't be going into them if we didn't think we would earn an attractive return, but I don't think that you should assume we're going to earn better returns there --

Similar?

-- than on the Carthage.

Okay.

Thank you very much.

Okay.

Thank you, Steven.

Stephen Huang, Citadel Investment Group.

Hi, good morning.

Good morning.

Was wondering about your mid stream business.

You guys talked about $100 million of growth CapEx this year.

When we look at going forward, do you anticipate there's enough opportunities out there to see maybe 100 a year going forward, or --?

We certainly see levels at a much higher pace than we've seen in the past.

Whether it'll be $100 million per year, I don't know that we have that much insight, but we see lots of activity in the mid-continent area.

We don't really see that slowing down any time in the near term.

Certainly, the expenditures are going to be well north of our normal 30 to $40 million.

Whether it's $100 million every year, only time will tell, but we see lots of good prospects out there that we're going after.

Lots of competition, so it's not assured we'll get them, but we've got good relationship with our customers and we think we'll get our fair share of those new projects.

Okay.

And then when you look at the five year CapEx potential for electric transmission, how much do you think that your overall CapEx on that could be?

Including -- I mean, if you look at everything, including distribution and transmission, you're talking probably somewhere around $2 billion, maybe a little bit less, but it's $400 million a year, give or take, I would say.

That includes distribution?

Yes.

What if you only look at transmission, though?

Transmission is -- let me see if I can look at these numbers here.

It looks to me like transmission is probably a little less than $500 million in that time frame.

Okay.

And then the last question I had is what's your current ROE that you are making in Arkansas rolling 12 months?

Well, we're not -- I think the allowed return is 9.4 or so.

The problem is the way they set rates using what's called a modified balance sheet approach to rate base, it's very hard to earn that authorized rate of return and I think it's significantly less than that.

Okay.

Great.

Thanks.

Paul Patterson, Glenrock Associates.

Good afternoon.

Can you hear me?

Yes.

Good afternoon, Paul.

Just I was wondering on the -- you mentioned some opportunities at the electric business, I think, for cost savings with the settlement that you currently have.

And I was wondering if you could just elaborate on those a little bit and maybe quantify them.

The biggest one in terms of over the next three or four years comes from what we call the intelligent grid.

It's a rollout of technology where you can improve your meter reading and metering accuracy.

You can do outage detection.

You can do automatic connects and disconnects.

That's automation, and a fair amount of capital required to get that done, but certainly it has the potential to change your overall business model and the operating cost of running the business.

Plus, we continue just to look through our process improvement initiatives at better ways to operate the business that we've been operating now over 100 years.

We're still finding better ways to do things.

We've -- a couple of years ago, we implemented something that's called line soft.

It's a -- some software that helps us -- our engineers design our system more efficiently, requiring less dollars.

And we continue to find ways just to run our business better, but the big items will be technology driven.

But I think there's ways to find other cost savings as well.

Can you give us an idea about what kind of numbers we might be seeing in terms of -- or just sort of timing and how -- roughly speaking.

Obviously, you can't be too exact on it, but just an idea about how much you think you can take out in terms of cost?

Well, I'd be guessing to give you that at this stage, and I'd rather not do that.

We're in just the early stages of this work, so I'm hesitant to give you a number.

Okay.

Thanks a lot.

[OPERATOR INSTRUCTIONS].

Faisel Khan, Citigroup.

Yes, sorry, just a couple more questions.

On -- if I look at the year-over-year gathering volume, kind of [92 Bs to 97 Bs], kind of -- the 5% growth, is it fair to say that all of that gathering volume is basically fee based volume?

Yes.

We are almost all fee based, certainly in gathering.

We have a little, in our processing it's almost all fee based, but there is some percentage of proceeds there, but I would say all gathering is fee based.

Okay.

And then as you kind of connect new wells and the cost of tubulars has kind of gone up a little bit, do you expect to get -- to charge higher gathering rates for your new customers?

I mean, is that something that we should expect kind of going forward?

Well, certainly, we'll attempt to maintain our returns and when our costs go up, we'll try to reflect that in our rate.

I will say, though, you have to be competitive.

I think that the cost increases you described are going to be common to every gatherer out there, so I don't think it would put us at a disadvantage or an advantage, but I think we'd try to -- we'd try to raise rates if our costs go up, yes.

And then I just wanted to get kind of your thoughts about the potential for -- to maybe put some of your assets into an MLP.

Is that something you guys still think about?

And how would you think about that from an interstate pipeline perspective?

Can those -- do you think those eventually could become eligible to be put into a structure like that?

Well, one is we do think about it.

We have looked at it.

Field Services, it's obvious that you can do that.

You sell kind of part of your business if you -- when you do that, but you can do it.

And there's reasons to do it because of really cost of capital.

It just has a lower borrowing cost.

On the interstate pipelines, I think there's a risk there because of FERC regulation, but certainly you can do it, the real question is will the FERC ever look through the MLP and try to lower your rates because of -- you're not a tax paying entity?

They had provided some guidance with some recent cases there.

I think it clarified it and I think you could see more interstate pipeline go into MLPs as a result of that.

So even with the negotiated rate on a new pipeline, like for example your Carthage to Perryville pipeline, even though you negotiated that rate, there's still a risk that the -- FERC could lower the rate on that system.

Is that still -- I mean, is that a real risk?

Well, not -- I don't think on a negotiated rates there's a real risk, but the contracts don't run forever.

They are 10 or 12, maybe in some cases a little longer contracts, but once they expire, you'd certainly have that risk.

Right.

Fair enough.

Thanks for the time.

Okay.

Daniele Seitz, Dahlman Rose.

Thanks.

I just was wondering, you are mentioning the potential building of another pipeline going from the Barnett region.

Any sense of what the timing would be for that one and the cost?

We -- we don't.

I would say probably some time next year there'll be clarity around that.

We clearly are working on it, but I don't think we have enough definition there yet to venture a guess at cost.

Okay.

Great.

Thanks.

Scott Engstrom, Satellite Asset Management.

Your comment about the fourth quarter impact of the rate settlement, I think you said $0.04.

If my math is right that's kind of about 20 million of EBIT.

What would be -- based on the customer growth you've seen assuming normal weather and usage, what kind of would be the typical or what would be an offset for growth at [inaudible -- background noise] the fourth quarter?

I would say that fourth quarter is probably the lowest operating income quarter for the year in the electric utility, typically.

You'll see a little bit, but you won't see a lot there in the fourth quarter, so I wouldn't put a lot of weight on growth offsetting a whole bunch of that.

That $0.04 kind of takes all of that into account.

Oh, okay.

And I assume that the lower collection rate on the CTC as well?

Yes.

That's about $0.01.

That's an additional penny, Scott.

Oh, beyond the $0.04?

Right.

Okay.

The -- and then thinking about next year, I'm trying to ask a question without making you give guidance.

The full impact of the rate settlement offset by customer growth, normal usage patterns, and operating efficiencies that you're looking at, can you directionally say how that all folds together next year for HL&P?

Well, I think if you look at the rate impact, the direct revenues of 57, 58 million plus another 20 million of expenses, that's 78 or so.

We certainly don't expect that full 78 to impact our earnings next year.

We're going to -- there'll be ways to offset some of that impact.

Customer growth, if we continue to see the 2, 2.5%, that's north of $20 million of base revenues.

Now, we have to assume there's no usage decline overall either.

We've -- we saw some early signs with the high electric prices in Texas.

There could be some demand elasticity but that has waned some of late, so we're not -- we're not real sure we need to worry about that.

But I think customer growth is the biggest impact and then some of the cost savings we can implement.

Those won't all hit in '07.

Those will come in over the next two, three, four years.

Okay.

Great.

Thank you very much.

Okay, Luanne.

I think we'll have time for one more question.

Stephen Huang, Citadel Investment Group.

Hi.

I'm just following up on your advanced metering potential projects.

How big is that CapEx project?

I don't remember if you said what the number could be.

I think it's -- you have to look at it a combination of the metering cost as well as the BPL cost.

It's between 3 and $400 million, fully implemented.

Our game plan now, assuming that we do it, would be to do it over a four or five year period.

We're this month implementing 10,000 BPL meters that have advanced capability.

We'll be doing a lot of testing on those, making sure that we understand the capabilities before we move forward with a full deployment.

Okay.

And then that's -- if I remember correctly, your rate settlement allows you to go back in for this recovery; correct?

Right.

Yes.

The -- we have a right to recover any advanced metering cost based on the Commission's rules.

And I think they're just now starting to take those up.

But how should I think of how this is going to be earned upon?

Is this going to be like when you just put it in, you get to earn the CapEx?

You got to earn your ROE -- I guess, your black box ROE right away or how should I think of that?

I think -- we don't know the rules yet, but I would think that there won't be a great deal of lag there.

Usually, regulation, there is some lag, but it won't be having to wait to go in for a rate case.

It will be more timely recovery, so -- but we're just now getting into all of that in Texas and we're confident we're going to come up with a good rule but it's in the early stages.

Okay.

And then the last question I have was on the mid-con pipe, what type of size diameter are you guys looking at now?

Are we -- do you guys have enough interests where it'd still be the same size as the original project?

It could be anywhere from 36 to 42, but it's really way too early to be sizing that yet.

Great.

Thank you very much.

You bet.

Thank you.

Okay, thank you very much, everyone, for participating in our call today.

We appreciate your support very much.

Have a great day.

Thank you.

This concludes CenterPoint Energy's third quarter 2006 earnings conference call.

Thank you for your participation.