CenterPoint Energy Inc (CNP) 2010 Q3 法說會逐字稿

Good morning and welcome to CenterPoint Energy's third quarter 2010 earnings conference call with senior management.

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

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

(Operator Instructions) I will now turn the call over to Marianne Paulsen, Director of Investor Relations.

Ms.

Paulsen.

Thank you very much, Tina.

Good morning, everyone.

This is Marianne Paulsen, Director of Investor Relations for CenterPoint Energy.

I'd like to welcome you to our third quarter 2010 earnings conference call.

Thank you for joining us today.

David McClanahan, President and CEO will provide highlights on key activities and will also discuss our third quarter 2010 results.

Gary Whitlock, Executive Vice President and Chief Financial Officer, is also present, but will not provide formal remarks due to a case of laryngitis.

We also have other members of management with us who may assist in answering questions following Mr.

McClanahan's prepared remarks.

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

I would like to remind you that any projections or forward-looking statements made during this call are subject to the cautionary statements of 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 PM Central time through Thursday, November 4th, 2010.

To access the replay please call 1-800-642-1687 or 706-645-9291 and enter the conference ID number 11725228.

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 a 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.

Today, I'm first going to talk about new developments that occurred during the third quarter and provide some details around certain business operations that I believe are of interest to many of you.

Next I'll briefly describe our overall financial results, and then we will provide some details around the performance of each of our business units.

Let me begin with our true-up case.

There has not yet been a decision by the Texas Supreme Court on our true-up appeal.

While the Supreme Court has already ruled on some appeals that were heard after ours, we know our case is complex and are not surprised that the Court has yet to render a decision.

We still believe that there is a good chance that the Supreme Court will reach a decision before the end of this year.

In a related matter, we were pleased that last Friday the Texas Supreme Court rendered a favorable ruling in our competition transition charge, our CTC case.

This case was on appeal by several intervenor groups, challenging the interest rate used by the PUC in establishing the CTC as well as the PUC's decision to allow us to recover the cost of a third-party valuation panel.

The Supreme Court upheld the PUC's order.

Because our books reflect the PUC's original order, there is no financial impact as a result of this ruling.

As most of you probably know, we filed a Houston Electric rate case on June 30th.

Our rate request was for a $92 million increase in our distribution rates and an $18 million increase in our transmission rates.

Hearings were conducted the week of October the 11th.

As you would expect, most of the attention during the hearings was focused on our proposed capital structure and return on equity and our requested adjustments for our depreciation, pension expense and federal income taxes.

As a reminder, we requested a capital structure with a 50% equity component and an 11.25% return.

Each 5% change in equity capitalization has about a $20 million revenue requirement impact.

Each 0.25% change in the equity return has a $7 million impact on revenue requirements.

I would also note that there were no significant challenges to our overall investment in rate base or to our operating expenses.

We expect the administrative law judge's recommendation in late November and a final order by the Commission in late December or early January.

In a positive regulatory development, last month the PUC amended its rules relating to the transmission cost recovery factor or TCRF.

This amendment authorizes electric distribution utilities to defer for future recovery, increases in costs charged by other transmission providers until such costs are reflected in rates, thereby reducing regulatory lag.

This amendment is particularly important as new large transmission lines are being placed into service by other transmission providers.

We are progressing well in our implementation of an advanced metering system in our Houston Electric service territory.

We are currently installing over 80,000 smart meters per month and expect to have 1 million installed by January of next year.

To date, we have invested approximately $290 million and have received $58 million of the $200 million DOE grant.

In our gas distribution, business early next year we expect to begin installing remote electronic transmitters on the 1.2 million natural gas meters in and around our Houston service territory.

These devices, along with related communications infrastructure, will initially allow us to automate natural gas meter readings and ultimately enable other functionality in the years to come.

We expect to invest approximately $85 million on this project, which should be completed within 36 months.

Now let me turn to our field services business.

This has been our fastest growing business segment and we expect significant growth to continue for the next few years.

Our daily gathering volume has grown from an average of 1.2 billion cubic feet per day in the third quarter of last year to 2 billion cubic feet this year, an increase of nearly 70%.

Our gathering revenues are primarily fee based, but there is a portion related to sales of retained natural gas.

We retain gas from either a usage component of our contracts or from compressor efficiencies.

As a rule of thumb, we generally retain about 1.5% of all gathered volumes.

Activity in our traditional gathering basin continues to be below historical levels.

In these basins we both gather and process natural gas, and the majority of our processing comes from these areas.

Our operating margin, which is our reported revenue less natural gas expense, includes gathering and processing fees, as well as the sale of retained gas and natural gas liquids.

For the third quarter of this year, approximately $35 million or about 46% of our total operating margin was realized from our traditional basins on gathering volumes of approximately 77 billion cubic feet.

We estimate that the third quarter operating margin from our traditional basin has declined by about $4 million from the same period of last year primarily as a result of the decline in drilling and production in those basins.

Our largest gathering volumes have now shifted from the traditional basins to the shale plays.

In the shales our three largest customers are subsidiaries of Shell, EnCana and Exxon Mobil, the successor to our long time customer, XTO.

Gathering for Exxon Mobil is concentrated in the Fayetteville and Woodford shales while gathering for Shell and EnCana is concentrated in the Haynesville shale.

The majority of our activities and investments last year and this year have been in the Haynesville Shale where we have two major gathering systems.

The Magnolia system in north Haynesville is substantially complete with only well connectivity remaining.

Through September we have spent about $294 million of our projected $325 million budget for the original project's goal.

In addition, construction of the 200 million cubic feet per day expansion that Shell and EnCana requested is underway and should be in service in the first quarter of next year at a cost of approximately $60 million.

The Olympia system in southern Haynesville is also under construction.

This system is designed to gather and treat about 600 million cubic feet per day and will cost approximately $400 million of which $210 million has been spent through September.

Construction is going well and we expect to have the necessary treating plants in service before the end of the year and substantially all a facilities except for well connects completed in the first quarter of next year.

Shell and EnCana have contracted for a total of 1.5 billion cubic feet per day in capacity on the the Magnolia and Olympia systems and have the option to request expansions totaling in an additional 1.3 billion cubic feet per day.

Our total gathering volumes in the Haynesville Shale in Northwest Louisiana include some third-party volumes not related to Shell and EnCana.

Of the nearly 900 million cubic feet of daily volumes gathered in the third quarter, about 175 million cubic feet were not related to Shell and EnCana.

We have also seen some modest increases in gathering from other shale areas.

In total, our estimated daily volume from all the shale areas in the third quarter was approximately 1.1 billion cubic feet per day.

Operating margin from these areas was about $40 million or about 54% of our total margin on gathering volumes of approximately 103 billion cubic feet.

In the third quarter of last year, we had less than $10 million in operating margin from the shale areas.

We remain interested in investing and gathering facilities in other areas and continue to have discussions with producers in the Eagle Ford and Marcellus Shales.

Now let me review the Company's overall operating results for the third quarter.

We had a good solid quarter with most business units performing at or ahead of our expectations.

Operating income for the company was $327 million this quarter compared to $287 million last year.

Our net income was $123 million compared to $114 million last year.

However, earnings per diluted share declined by $0.02 to $0.29, as a result of the new shares that have been issued this year.

Let me give you a little more detail about the performance of our individual business units.

Houston Electric reported operating income of $178 million compared to $187 million in 2009.

As Gary explained last quarter, our rates now include a credit to customer bills to reflect the time value of the accelerated tax benefits we received in connection with the costs associated with Hurricane Ike.

The reduction in revenues from this credit was approximately $9 million to the third quarter and accounted for substantially all of the decline in Houston Electric's operating income this quarter.

Since the third quarter of last year, we have added approximately 21,000 customers to our system.

Customer growth is running at about 1%, or half of our historical growth rate.

We also experienced some increased operating expenses compared to last year.

Exceptionally warm weather this past summer did not have a significant impact compared to last year when weather was also warmer than normal.

Our gas LDCs typically report a loss in the third quarter due to the seasonal nature of the business.

However, the operating loss this year of $4 million was significantly less than the loss of $15 million last year.

This improvement was primarily due to rate increases and improved rate designs, which we have incorporated into our rate structures in several of our service territories.

The continued success of this unit is a reflection of the efforts we've devoted to improving our rate structure, as well as continued efforts to control operating expenses.

Our customer to employee ratio continues to improve as we maintain focus on productivity and efficiency.

Particularly noteworthy are our efforts to reduce delinquencies and bad debt expenses.

Our competitive natural gas sales and services business reported operating income of $7 million compared to an operating loss of $8 million last year.

Adjusting for mark-to-market impacts and the write-down of inventory to lower of cost to market, we would have had an operating loss of $6 million this year compared to a loss of $2 million last year.

This unit continues to be impacted by a significantly reduced locational and seasonal price differentials.

However, retail sales to commercial and industrial customers were slightly ahead of the third quarter of last year.

Our interstate pipelines reported operating income of $68 million compared to $64 million last year.

Our core business performed well and benefited from increased margins from Phase IV of our Carthage to Perryville line and deliveries to our power generation customers.

However, ancillary services continued to be impacted primarily due to a tightening of basis spreads across our system and reduced commodity prices.

Our equity income from SESH, our joint venture with Spectra, was $8 million for the third quarter of 2010 compared to a loss of $5 million last year.

The third quarter of last year included an $11 million non-cash charge to reflect SESH's discontinued use of regulatory accounts.

Our field services segment reported operating income of $40 million compared to $23 million last year.

Substantially all of the increase was a result of increased volumes associated with our new gathering systems in the Haynesville area.

Overall gathering volumes increased from 106 billion cubic feet in the third quarter of 2009 to 180 billion cubic feet this year, a 70% increase.

Operating expenses were higher this quarter due primarily to the new facilities placed in service in the shale areas.

Overall, we are pleased with our business performance through the third quarter and this morning we reaffirmed our 2010 earnings guidance in the range of $1.02 to $1.12 per diluted share.

This guidance reflects the earnings per share impact of the new shares we have issued earlier this year and an estimate of the shares that will be issued in our benefit and investor choice plans for the remainder of the year.

In closing I'd like to remind you of the $0.195 per share quarterly dividend declared by our Board of Directors on October 21st.

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.

With that I will now turn the call back to Marianne.

Thank you, David.

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.

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

(Operator Instructions) .

And our first question will come from the line of Lasan Johong with RBC Capital

Thank you.

A couple questions.

I noticed that on the release, Energy Services had very large increases in volumes and seemed like relatively speaking commensurate increases in margins as well and obviously a large part of that was an increase in customers, but is this signaling a change in your strategy towards Energy Services or is this just some coincidence for the third quarter and don't expect to repeat over the next several quarters?

Lasan, the Energy Services margins have maintained pretty much the wear they were last year.

We have added customers and our overall margin from our retail business is up year over year.

The big increase in natural gas expenses is really due to both volume increases, but to also natural gas price increases.

We lock in natural gas prices and you can't look at this as the current price of natural gas.

When we lock in the sale, like maybe six months ago, gas prices would have been different than they are today.

So I don't think you can read anything into that, to those ratios this quarter.

I see.

We're still constantly hearing about how there's a lot of liquids flowing through the system in the US.

Are you at all concerned that there's a price cliff coming on NGLs?

With the Eagle Ford, which is very liquids rich and Marcellus has a lot of liquids in it, I think there are those in the industry that are wondering whether or not there's going to be a flood of liquids on the market and where it's all going to go and what it's going to do to prices.

Now as you know in our Haynesville area, that is not a liquids rich area.

This is really dry gas.

So we're not affected by that.

We do have some processing in our traditional basins, and certainly a decline in price would impact us there, but that's not a very big part of our business.

Excellent.

Just recently Spectra -- actually DCP Midstream and Southern announced a project in the Eagle Ford area.

Are you seeing any areas where we can participate in those ongoing expansional infrastructures, also one announced in the Marcellus with Spectra and El Paso, are these things that you guys take a look at and passed on or is this something that you guys were never involved in or do you have similar opportunities you can access?

Can you talk more about your other opportunities that you mentioned?

Yes, Lasan.

The way we go about this, is we work with our producers and with producers that we don't necessarily gather for today, but we approach, and try to put together a project that would cover enough volumes to make it economic for the producers as well as advantageous to us.

So yes, we are absolutely talking to producers in the Eagle Ford and in the Marcellus, lots of people are doing the same thing.

There are others that have some existing infrastructure that they can build off of that we don't.

We don't have any infrastructure in either of those areas, but we're actively talking with producers and we'd like to get into some of those areas.

We'll just have to see if we're successful and getting a good project.

Great.

Thank you so much.

Okay.

I hope Gary feels better.

Our next question will come from the line of Carl Kirst with BMO Capital Markets.

Thank you so much.

Actually David, you guys have a good relationship obviously with Shell.

We've got a good acreage package down there at the Eagle Ford.

Given the amount of infrastructure that exists in the Eagle Ford there isn't an immediate need for incremental infrastructure, but when do you kind of get the sense that Shell might be needing something, i.e., when might they put out an RFP like the same process we saw in the Haynesville?

It's hard to say.

We obviously talk with those folks.

My expectation is we probably will not see that till sometime next year first or second quarter of next year, but that's just kind of our guess based on reading the tea leaves.

They're clearly going to develop that -- all that acreage, but I think they're being very methodical about it, but I don't think it's in the next few months.

Okay, but now that's helpful.

Maybe also one other one on field services.

Just with respect to what you currently are seeing here in the fourth quarter with respect to the basing out, if you will, of the traditional volumes, the traditional operating margin decline, at least back in September, we were sort of looking at a basing out and I guess the question is as the gas curve has continued to come down, are you still seeing sort of this basing out in fourth quarter and perhaps expectations of 2011 or are you starting to see the decline ramp back up again?

No.

When we look at the traditional volumes in the third quarter compared to the second quarter, they're pretty flat.

They kind of leveled out and clearly we had seen almost quarter after quarter a decline.

So that was the good news as we saw a flattening out.

Gas prices have fallen a lot.

We still see rigs in these traditional basins, so they're not gone, but I think at very low prices you might see another dip there, but at this stage, we think it's flattened out quite a bit from what we saw from the beginning of last year.

Great.

Appreciate the color and I'll throw in one last question maybe for Scott, just because of the Friday, last Friday Texas Supreme Court ruling on the CTC case.

Could you just remind us as we get closer to the end of year if the TSC were to, in fact, just go ahead and keep the appellate decision, from what I recollect we're talking about perhaps something on the neighborhood of a $35 million negative cash outflow up front and then something like maybe $10 million sort of less on a go forward basis relatively de minimus and I just want to make sure we're all on the same page on that.

Carl, if what we assume is that the Supreme Court were to affirm the Court of Appeals, the impact on us meaning the difference between what the PUC had originally approved plus interest since that time would be from somewhere in the $100 million to $400 million range, depending upon exactly how they handle tax normalization issues going forward, but the point that you raised is a good one.

The way that would work is, we would have to give back money that we had already received through the securitization process, and that rate payors, our customers, had paid, plus we would put in place an ongoing credit against our transition charges to refund the remainder of it.

I'd have to go back and do that math, but the amount of the $100 million to $400 million range that would have an immediate cash impact would be a very small percentage.

As I said, I haven't done that math recently, but it would probably be in the 15% range or so that would be the immediate cash impact with the remainder of it being spread out over the remaining life of the transition box.

Great.

Thanks, guys.

You bet.

Our next question will come from the line of Leon Dubov with Catapult.

Can you guys hear me?

Can you walk us through some of the reasons that in the past, you guys had chosen not to pursue an MLP structure for some of your gas assets, and need to talk about whether those reasons are still valid today or still relevant.

Yes.

We've looked at the MLP a number of times, Leon.

We consider it an alternative financing, and when we really looked at it, it was an alternative to equity financing at the parent.

We also as you know, we needed to strengthen our balance sheet in our judgment before an MLP would make a lot of sense.

We think we've done that now, but it's taken the last 12 months I think through the sale of these equity shares that everybody knows about that has really strengthened our balance sheet.

I think it's a viable alternative financing for us that we continue to have in our tool kit.

There are some other benefits perhaps that we continue to study and look at, but by and large, it's an alternative financing, and we just hadn't felt it was necessary up to this point in time, and I think it really depends on the kind of projects that we get going forward in fuel services and in pipelines as to whether or not we'll need one.

Okay.

Fair enough.

And also, could you walk us through some of the earnings drivers that you guys see kind of for next year, maybe by business segment, if you can.

Well, that may take a little longer than you thought or I think that we have here.

Let me just suggest a couple.

One is really in fuel services.

This is our growth engine.

It's where next year ought to be better than this year as we gather and treat more volumes in Haynesville and we hope to get some expansion down the road as well in that area.

So field services will be our primary growth vehicle.

I think on the electric side it really depends on this rate case.

This rate case is going to determine whether or not we have some growth there or not, and we'll know that by the end of this year.

We think we put on a really strong case in Austin, but we're just going to have to wait and see how all that turns out.

Our gas LDCs are doing great.

They've been doing fine for the last couple, two, three years and we expect that will continue.

On our Energy Services business we're really focused on our retail sales, sales to industrial and commercial customers and if we get some wholesale business because of price differentials, great, but we've refocused and we've got to just focus on making that margin from our end use customer.

Our pipeline group, they're having a good solid year and next year, we're going to have to overcome a few headwinds.

One is we have a big backhaul contract that is going to start playing out in the middle of the year.

We're working to offset that at this time.

Great.

Thank you very much.

I appreciate it.

You bet.

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

Are we on the electric operations at the end of September?

Okay, yes.

I'm sorry.

Which was the ROE for the 12 months ending September, 2010 on the electric side?

We don't have a 12 month trailing ROE there.

I can't give you that.

At the end of last year for the 12 months ended 2009 on a weather-adjusted basis it was about a little over 10% on a -- with weather in it was somewhere, 11.3% or so.

Also you mentioned that you changed the rate design in gas distribution.

Does that mean seasonality or it's just comes up through the same number anyway, it doesn't change the seasonality, does it?

Well, it does to some extent because we're trying to put more of our revenue recovery in the customer charge and the customer charge is the same every month.

So you tend to spread your revenue recovery over the 12 months and you'd have no volumetric risk when you get your increased revenue through customer charges.

That's one way.

The other way is through adjustments that allow us to basically adjust rates going forward for impacts of energy conservation and energy efficiency and we have that in some of our jurisdictions as well.

So it doesn't mean that the improvement of the third quarter was going to be taken away in following quarters.

That's what I was driving to.

No.

I don't think -- there's no reason it will be taken away, no, that's correct.

Okay.

That's what I was wondering.

Thank you.

Okay.

Our next question comes from the line of Stephen Wong with Carlson Capital.

Hi, good morning guys.

Good morning.

I'm sorry.

I was just on another call here and heard the back end.

You said next year there's a headwind from the pipeline on a backhaul contract.

Did you guys quantify how much that's worth?

Versus market rate?

Probably next year, if I'm not mistaken -- I'll have to look -- $10 million to $15 million range.

Pre-tax, correct?

Correct.

Okay.

And that starts in the middle of the year?

So would that be an annualized number, David?

No.

No, Stephen.

That's next year's impact I think.

Okay.

So half year impact.

Yes.

And then I don't know if you guys addressed this, but was there any discussion by EnCana with you guys I guess in regards to their drilling development?

It sounded like they're a little bit more cautious for their 2011 drilling program.

We saw that in their analyst call, their discussion about that.

We've had conversations with them.

I think in the Northwest Louisiana Haynesville, I think that's an area they're still very high on.

I think they may very well move some rigs out of the East Texas Haynesville area.

So we still feel pretty good about the production schedules they've given us in the past, but we do think that there are some rigs moving out of Haynesville, but Haynesville, where we are, it's a pretty -- the sweet spot in the Haynesville and there's still a lot of rig activity in there.

But I guess we know that they alleged a couple expansions this year but I guess based off, have you got any indications that a few further expansions may flow down?

No.

We hadn't gotten any indication one way or the other on that, Stephen.

Okay, great.

Thank you.

Okay.

We have a follow-up question from Lasan Johong with RBC Capital Markets.

David, this pipeline backlog contract expires, wouldn't you be replacing this with another contract?

Certainly we're looking to try to replace some of that revenue loss, absolutely, Lasan, but we have to accomplish it.

I'm assuming you're in discussions or negotiations with existing shippers.

That's an everyday event.

So, absolutely.

We're looking at ways to try to maximize the value of that pipe and where gas comes onto our system and there's lots of ways you can move gas around by displacement as opposed to actually moving it, backhauling it and that's what we're looking at and there's going to be some interest out there.

The question is can we get the same level of revenue that we have today?

Understood.

Just kind of a big picture item question.

I know you guys don't sell electricity directly to end consumers, but you see the flow of electricity in Houston and you certainly see the flow of gas in your LDC.

Can you kind of give a sense of where you think demand growth is going over the next 18 months or so?

Well, if you look at our LDCs, gas LDCs, we have a customer growth of about 0.5% there and on the electric side we've had customer growth of about 1%.

We've seen some pretty modest increase in deliveries on the commercial and industrial side of our electric business.

It is up year over year, but this is not a hockey stick kind of growth.

This is kind of a steady slow growth and there's no signs that we're going to have some huge burst of growth here.

I think it's going to be pretty modest.

So you think this recovery is going to be different than some of the other deeper recessions we've had in the 1970s and 1980s?

Well, the only thing I can say, we don't see an indication that we're going to get that big burst of growth.

Hopefully we're wrong.

Maybe it's something we don't see, but there's no indication certainly on the construction side, and we connect a lot of both commercial and residential customers, that would lead us to believe that.

Thank you.

(Operator Instructions).

And we have a follow-up question from the line of Carl Kirst with BMO Capital Markets.

Hey, guys.

Sorry, just going back to this backhaul issue and I want to make sure that I'm clear that the $10 million to $15 million for the half year impact is basically the quantification of that contract that's expiring and not necessarily the net impact, for instance, of where the contract is versus what we might call the current market.

Now that's purely contract expiration impact and we have to -- what Greg and his team's going to do is if out and try to offset this.

David, and I understand this is kind of a moving bogey every day with basis, but as we look at a relatively flat basis in the derivative market for 2011, what is -- what do you think if you had to do it today that market recontracting could be?

We're in discussions with lots of producers out there that still want to move gas and they're thinking about different directions to move gas.

So it's hard to handicap this one, Carl.

I would say that we hadn't given up.

We're still working hard at it.

Okay, no.

I appreciate your candor.

Let me say -- Carl, just a minute.

Let me ask Greg Harper who, as you know, heads up that group, to give you a little more information.

Hey, how you doing.

The original intent for this contract was to get our customers' gas moving, this Haynesville-driven gas, and to get to market before they would take on gas.

It turned into a forward haul on our CP4 project for about half the volume and then they had taken the other volume to another pipeline that they contracted on as well.

So there's producers looking to move their gas to markets.

We were able to get their gas moving early with this backhaul that they were producing and then they would be stepping into the forward haul once we got the facilities built which was the Phase IV project that went into service in February.

So it was a good way to get their gas moving.

It was a hedge for them on their other production for another competitor's pipe was to go into service, and still hasn't gone into service.

So there's a chance of extending the contract, kind of go when that other competitor's pipe goes in as well.

Okay, no.

Appreciate that.

And then one other question just to clarify.

I'm not sure, David, if I caught that correctly.

Did you say in your prepared comments that the warm weather in Houston did not give an uplift to the utility earnings?

Yes, that's right.

If you -- both periods, both 2009 and 2010, they were warmer than normal.

So when you look at it year-to-year, no uplift to speak of in the third quarter compared to the third quarter of 2009.

Relative, okay, yes.

I thought you meant on an absolute basis.

There was an uplift.

I know I was doing my part.

All right.

Thank you.

We appreciate that.

And we also have a follow-up question from Daniele Seitz with Dudack Research.

Do you think in your comments about EnCana, do you anticipate any changes in your CapEx expenditures for 2011, or are you still looking at about $1.3 billion?

Daniele, we're now right in the middle of putting together our new plans for the next five years and certainly next year we're looking at closely.

You can't really go by -- you have to adjust the numbers we had in the 10-K for the Shell EnCana contract we got after those numbers were published and we still have next year on the Olympia system we'll probably spend $100 million that we will spend close to $300 million this year, but we'll spend another hundred next year in the estimates that weren't in last year's 10-K and there will be other changes.

It will certainly be well north of a $1 billion I would expect.

Okay.

Thanks.

And we have no further questions at this time.

Okay.

Great.

Thank you so much, everybody.

I think it's about time we wrapped this call up.

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

We appreciate your support very much.

Have a good day.

Thanks.

This concludes the CenterPoint Energy's third quarter 2010 earnings conference call.

Thank you for your participation.

You may all disconnect.