CenterPoint Energy Inc (CNP) 2010 Q2 法說會逐字稿

Good morning and welcome to CenterPoint Energy's second 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, please go ahead.

Thank you very much, Tina.

Good morning, everyone.

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

I would like to welcome to you our second quarter 2010 earnings conference call.

Thank you for joining us today.

David McClanahan, President and CEO, and Gary Whitlock, Executive Vice President and Chief Financial Officer, will discuss our second quarter 2010 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 the Form 10-Q filed earlier today are posted on our website, which is www.CenterPointEnergy.com, under the investors section.

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

Before Mr.

McClanahan begins, I would like to mention that a replay of this call will be available until 6 PM Central time through Wednesday August 11th, 2010.

To access the replay please call 800-642-1687 or 706-645-9291 and enter the conference ID number 866031378.

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.

Today I am going to give my prepared remarks in a somewhat different fashion.

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

I will briefly describe our overall financial results and Gary will provide details regarding the performance of each of our business units.

Recently there have been three questions that I am asked most often when talking to analysts or shareholders about CenterPoint Energy.

First, what can you tell me about the Houston Electric rate case?

Second, how are your new investments in Field Services doing and what are the key sensitivities around profitability in that business?

Finally, is there anything new with the true up case?

Let me take the last one first.

There still has been no 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 the Court has yet to render a decision.

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

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

This filing was required as part of the settlement we reached in our last rate case over four years ago.

Our rate request has two pieces, a $76 million increase in our distribution rates, and an $18 million increase in our wholesale transmission rates.

Since our filing, we have determined that our present distribution rates will not produce quite as much revenue on a normalized basis as we first calculated.

And accordingly, the revenue deficiency in our filing may actually be another $15 million or so higher.

The increases we have requested in our base rates are influenced significantly by three factors.

First, we are shifting to base rates the investment we have made to date in our advanced metering system.

This increased our revenue requirement by about $38 million.

Secondly, we requested an increase in the equity component of our capital structure, from the 40% level currently in rates to 50%.

As a rule of thumb, each 5% movement in equity capitalization would have about a $20 million revenue requirement impact.

We have also requested an 11.25% return on equity.

This is the return set by the commission in our last fully litigated rate case in 2001.

For each 25 basis points change in ROE, the revenue requirement impact would be about $7 million.

In addition to these three factors, we have requested recovery of increased pension costs, as well as the amortization of pension costs we deferred over the last few years.

The impact of the pension costs is substantially offset by lower depreciation expense due to revisions we have requested in our overall depreciation schedule.

There have also been other typical increases in our cost of service since 2006 when our present rates were set.

As part of this filing, we also requested a distribution cost recovery mechanism that would allow us to annually adjust distribution rates to reflect changes in expense, capital investment, and customer usage.

The Commission currently has a rule making under consideration that encompasses some of these same principles.

Last Friday, the Commission severed this part of our rate application due to this rule making.

While we were aware that the timing of our request for the adjustment mechanism was not ideal due to the pending rule making, we felt it was important to include it in our filing.

We hope that the distribution rates that come out of our case will be the baseline for any future adjustment mechanism.

We expect the Commission will render a decision in our case around the end of this year.

Now let me turn to our Field Services business.

This is our fastest growing business segment, and one that is changing very rapidly.

I believe a good way to think about this business is to divide it into two pieces, our traditional basins where customers develop projects using vertical drilling and our shale plays where horizon drilling is the norm.

In our traditional basins, we both gather and process natural gas.

We typically have dedicated acreage are provisions in our contracts but no throughput guarantees.

The majority of our processing, whether from our wholly owned plants or our [Waspin] joint venture comes from our traditional basins.

for the first six months of this year approximately $66 million or nearly 60% of our total operating margin was realized from our traditional basins on gathering volumes of approximately 156 billion cubic feet.

For clarity, I would note that our operating margin is our reported revenues less natural gas expense.

This operating margin includes gathering and processing fees and the sale of retained gas and natural gas liquids.

We estimate that the year-to-date operating margin from our traditional basins is about $20 million lower than last year, primarily as a result of the decline in drilling and production.

However, we have seen some recent indications that this decline has begun to moderate.

Our gathering business in the shale plays is different.

In these areas, we have either volume commitments or rate of return guarantees and thus we're not exposed to the throughput risks of the traditional basins.

There are minimal amount of liquids in the natural gas we currently gather from the shales and therefore limited processing opportunities.

Our three largest customers in the shale plays are Shell, EnCana, and ExxonMobil, the successor to our long time customer XTO.

Gathering for ExxonMobil 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 investment this year have been in Haynesville, so let me focus on that area for a moment.

We have two major gathering systems in this region.

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

To date we have spent about $286 million of our projected $325 million budget for the original 700 million cubic feet per day system.

In addition, Shell and EnCana have made their first request for an expansion to this system for an additional 200 million cubic feet per day.

This expansion, which should cost approximately $60 million, is under way and should be in service in the first quarter of next year.

The Olympia system in southern Haynesville is under construction and is expected to be substantially complete except for well connects by the end of this year at a cost of approximately $400 million.

This includes the existing facilities we purchased at closing.

Construction on the trunk line is under way, and permits are pending for the necessary treating facilities.

Our gathering volume in the Haynesville area have increased substantially during the first six months of this year, and includes some third party volumes not related to Shell and EnCana.

In the second quarter, our average gathering volumes from the Magnolia and Olympia systems were about 500 million cubic feet per day.

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

In total, our estimated average daily volume year-to-date from all the shale areas was approximately 700 million cubic feet per day.

Operating margins from these areas was about $42 million, or about 35% of our total margin for the first six months of this year, on gathering volumes of approximately 128 billion cubic feet.

Once again, this margin includes both our gathering fees and sale of retained natural gas.

In the first six months of last year, we had only minimal operating margin from the shale areas.

We have been asked how to estimate the impact of changes in natural gas prices on the operating margins of our Field Services business.

As a reminder, our gathering revenues are primarily derived from fees, 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 currently retain about 1.5% of all gathered volumes.

For example, if we gather 100 billion cubic feet of gas, we retain 1.5 Bcf, thus a $1 change in the price of gas would impact our operating margin by approximately $1.5 million.

I have covered this fairly quickly, but we can spend more time during the Q&A session if further clarification is needed.

With respect to our operating results for the second quarter, we had a good solid quarter overall, with most business units performing at or ahead of our expectations.

Operating income was $263 million this quarter, compared to $253 million last year.

Our net income was $81 million or $0.20 per diluted share, compared to $86 million or $0.24 per diluted share in the second quarter of last year.

Gary will give you additional details regarding our segment results in a moment.

In closing, I would like to remind you of the $0.195 per share quarterly dividend declared by our Board of Directors on July 22nd.

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 flows.

With that, I will now turn the call over to Gary.

Thank you, David.

Good morning to everyone.

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

Houston Electric reported operating income of $122 million, compared to $129 million in 2009.

As part of our securitization of Hurricane Ike restoration costs late last year, we were required to implement a tariff that gave our customers credit for the time value of the accelerated tax benefits associated with those storm costs.

The credit mechanism chosen by the Commission resulted in a larger securitized amount but required a credit to customer bills during the life of the securitization bonds.

The reduction in revenues from this credit accounts for substantially all of the decline in Houston Electric's operating income this quarter.

Increased revenues associated with our customer growth of approximately 21,000, and higher income from our advanced metering system investments, offset our operating expense increases.

Our gas LDCs had another solid quarter and are having a very good year.

Operating income was $10 million compared to $2 million last year.

This increase was primarily due to rate changes, non-volume metric revenues such as reconnect fees and lower operating expenses.

The continued success of this unit is a reflection of the efforts we have devoted to improving our rate structure, as well as the continued focus on minimizing delinquencies and bad debt.

Our competitive natural gas sales and services business reported an operating loss of $6 million compared to operating income of $6 million last year.

Adjusting for the mark-to-market impacts associated with derivatives, this year's operating income would have been $2 million compared to $3 million last year.

While the second quarter is not typically a strong quarter for this unit, this year there was less market volatility and therefore fewer opportunities to optimized our transportation and storage assets.

Without such opportunities operating income would be primarily tied to margins from natural gas sales to commercial, industrial, and wholesale customers.

Finally, let me turn to our pipelines and Field Services segment.

Our interstate pipelines reported operating income of $67 million compared to $61 million last year.

Our core business performed well with increased margins from Phase IV of our Carthage to Perryville line and reduced operating expense.

However, all system sales declined due to a tightening of basis spreads across our system and ancillary revenues were also down.

Our equity income from SESH, our joint venture with Spectra was $4 million for the second quarter of 2010 compared to $9 million last year which included $5 million related to a reduction in estimated property tax and a one-time fee received in connection with the construction of the pipeline.

Our Field Services segment reported operating income of $31 million compared to $23 million in 2009.

Substantially all of the increase was a result of increased volumes associated with our new gathering systems in the Haynesville area and higher retained natural gas volumes and prices.

Although production from the traditional basins was down significantly, overall gathering volumes increased from a daily average of 1.1 Bcf in the second quarter of 2009 to 1.7 Bcf this year, a 53% increase due to increased production in the shale plays.

Natural gas prices received from the sales of retained gas were about $1 more than last year.

Now, before I talk about our second quarter financing activity, I would like to share with you some good news that we received yesterday.

Following the conclusion of its rating review, Moody's upgraded the rating of Houston Electric's debt and assigned it a stable outlook.

Houston Electric's senior secured ratings, which are the ratings assigned to Houston Electric's mortgage bond were upgraded to A-3 from BAA1, and the senior unsecured and issuer ratings were up graded to BAA2 from BAA3.

Houston Electric was the only one of our companies that was on Ratings Review and Moody's.

Moody's tends to have positive ratings outlooks on the parent company and on FERC.

We worked very hard to strengthen our balance sheet and are gratified by this action.

Turning to financing activity in the second quarter, on June 9th, we executed a $326 million equity offering consisting of 25.3 million share,s following the announcement of our second set of Field Services agreements with Shell and EnCana.

As has been our practice the last several years, we have raised another $55 million year-to-date by issuing approximately 4.4 million shares through our benefit and investor choice plans.

The proceed from the issuance of these shares are being used primarily to fund growth in our Field Services unit, and to strengthen our balance sheet.

We now estimate our 2010 capital budget to be approximately $1.4 billion, with more than $550 million of that amount being invested in our Field Services business.

As you know, over the last eighteen months, we have significantly improved our balance sheet through the issuance of new shares.

In addition, we have reduced our debt level, improved our credit metrics and credit rating, and remain in a very strong liquidity position.

Our overall business performance remained solid, and we will continue to generate significant cash flow from operations.

Therefore, absent a very significant new capital project, we feel we have the balance sheet strength and the financial flexibility to execute our business plan without any additional equity issuances other than the modest amount of new equity that we will continue to raise through our benefit and investor choice plan.

Finally, let me discuss our earnings guidance.

We're pleased with our overall business performance through the second 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 share impact of the new shares we issued this year and an estimate of the shares being issued in our benefit and investor choice plans.

In providing earnings guidance, we have taken into consideration our year-to-date performance as well as various economic, operational, and regulatory assumptions.

As you know, we routinely exclude the effects of mark-to-market and inventory accounting as they are timing related.

Also, we do not try to include any potential impact to income from our pending true up appeal, the change in the value of Time Warner stock and the related VIN securities or any mandated accounting changes that may occur during the year.

As the year progresses, we will keep you updated on our earnings expectation.

Now I would like to turn the call back to Marianne.

Thank you, Gary.

With that, we will now open the call to questions and in the interest of time I would ask you to please limit yourself to one question and a follow-up.

Would you please read the instructions on how to ask the questions.

(Operator Instructions).

Our first question will come from Carl Kirst with BMO Capital.

Thank you, good morning, everybody.

David, really appreciate the added color on the Midstream.

Maybe I can start there and with the track record that you are putting in place, getting Magnolia in service a little bit ahead of schedule, winning Olympia, how do we stand right now about the potential for exporting this franchise to other basins, whether it is with EC and Shell or any of the other players?

We continue to talk to all of our customers including Shell and EnCana about some of the basin that is we would like to get into, and Eagle Ford is probably one that gets the most attention, but we are in discussions and we hope to be successful there, but there is lots of competition for this business, and hopefully we're demonstrating though to our customers that we can do this well, meet their expectations and get it in on time and that's our goal there, but I would say we're just in discussions now.

We really have nothing to report at this time.

We're working hard on it.

And then maybe a follow-up just also on the pipeline side.

Looking at leased basis for Florida in July has widened out quite substantially.

Is that having any benefit onto SESH right now and if I recall correctly, there is some additional contracts to be layered on that come into service with SESH anyway, made mid-2011.

Is that correct?

Yes.

We have about 155 a day that is not -- wasn't sold, or it starts later, but we have already sold that on an interim basis through October, so we did that I think back in May, so we have no additional capacity that's on market there to my knowledge.

So the interim is sold out through October and the final remaining contracts come in service next year, is that --

That's right.

We still have about 80 a day that isn't sold on a long-term basis, but we know some of these contracts kind of come in over time and what, there is 75 coming in middle of next year on a long-term basis.

We still have that 80 we need to sell.

Great.

Thank you.

Our next question will comes from the line of Lasan Johong with RBC Capital Markets.

Thank you.

Gary, David, just going over this rate case --

We are Lasan.

Okay.

Rate case.

Going over the numbers again, $38 million for the Smart Meter, $40 million for the equity component to 50%, and 11.25% ROE, $7 million for 25 basis points.

I believe it was a 75 basis points increase.

Tina, we can hear him fine.

He can't be heard over the conference call network?

No ma'am.

We can hear him.

We'll try to answer your question.

We'll repeat your question.

Okay.

Wow.

Well, basically to cut the conversation short, it looks like the amount of rate increase you said you're requesting is $15 million, but I am looking at a number more like $21 million.

Does that mean that this other components are accounting for the difference?

As you know, we have got an $18 million transmission case and a $76 million distribution case.

I did mention that we think the $76 million is really more like $91 million, and the $18 million, so you add those two together and you get $109 million, a little bit of the transmission is embedded in our distribution because our distribution customers pay for that, but let's just say $105 million or so and what we tried to do is just give you the sensitivities.

Of that $105 million, $38 million is AMS, and we were required to reconcile our AMS investments, and we moved that into base rates, so that accounts for part of it.

$40 million accounts for the increase in the capital structure, the equity component, and now we firmly believe that the Commission at least some of the Commissioners have indicated that they think we need a thicker equity component, and we believe that, too, and we ask for 50%.

If we get 50%, that has that $40 million effect.

If we get 45%, we'll take $20 million off of that, and then the ROE is simply, we're giving sensitivities around that and you can guess kind of what the Commission might do there as well as we can, so these are the big components, but there were some other big components, but they were offset by other things we did that reduced expenses.

Net-net those are the big items, and I think those are the ones that our case is most sensitive to.

Understood.

On the Field Services business, NGL spreads have been going up and down like a yo-yo, and as of late it has been strengthening.

Obviously this doesn't necessarily have a direct impact on CenterPoint, but wondering if there is some sensitivities on the drilling front around movement in NGL and if are you seeing the effects of that, sorry, NGL pricing, and if you are seeing the effects of that and if you think there is an over abundance of NGLs coming down the line with the shale drilling?

We have seen natural gas prices higher this year than last year.

There is no question about it.

They have started to come down a little bit both from the in the second quarter from the first and we still see a little weakness there, still not to the levels they were in 2009.

We have seen some, and I will speak to our basins.

We have seen some traditional drilling this year.

There is probably 65 or 70 wells in our traditional basins that have been added to our systems.

That's more than last year.

I am not sure if that is what is driving that.

Certainly the Eagle Ford area is hot because of all the liquids and the oil in that play, and I think a lot of producers are moving into that area, but for that very reason.

We still see a fair amount of activity in the basins we traditionally gather.

Last question, is it fair to say that third quarter got off to a pretty good start in July?

We got good warm weather here in Houston, so that bodes well for the electric business as you know and our other businesses are doing fine.

We're optimistic.

Excellent.

Thank you so much.

Thanks, Lasan.

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

I was wondering on the pension costs and the reduction in depreciation?

I think pension was something like $26 million.

Amortization was $20 million, and the offset in depreciation was a little less than $40 million, like $38 million, $39 million.

Great.

And as far as the number of smart meters in storage so far and how much do you expect install next year and for the full year of 2010?

Yes.

We've got about a half a million meters installed now.

Our installation rate is about 80,000 per month.

So by the end of this year we'll have a little less than a million, and then we'll install close to a million next year, not quite, and then by probably the mid-2012 we'll be complete.

Just one quick one.

Can you put some details on the joint venture with FPL?

Yes.

We don't -- that's kind in abeyance right now.

It is not formally --

I was not sure, yes.

We are still looking at that Haynesville area.

If there is anything there now we think it is a smaller project that is really probably an expansion of our existing system, which doesn't really kind of fit with the joint venture, but we're still talking with them, and we're still watching the market.

As you know, we had an open season in Haynesville, and we're still talking to customers that responded to that open season, and have made no decisions yet around that.

It looks like a small project?

Yes.

We don't see a big new bullet pipe in the near term at least from our vantage point.

Thank you.

Our next question will come from the line of Paul Patterson with Glenrock Associates.

Good morning, guys.

Good morning.

Just really quickly, I am sorry if I missed this.

What was the ROE that you guys earned in the last twelve months, the actual earned ROE and is the capitalization ratio already up to 50%?

I will take the last one first.

We filed at about 46%, which was our actual equity structure.

We meant to take that up to 50%.

Our earned ROE was 11.13 for the last or for 2009.

That's the latest number I have.

If you adjust that for weather, it is about 9.8% on our actual cap structure, which was 46% equity.

Finally, you made some notable change in a relatively short time after you filed it.

What was it that caused it to move up, the rate increase?

We actually, Paul, haven't officially filed the errata yet to our case.

We'll probably do that next week.

In answering some interrogatories, we looked at how we normalize certain rate classes, and we have concluded we think we have overstated the amount of revenues that our current rates will produce.

That's still being studied pretty hard, and so we haven't filed it yet, but we feel pretty confident that we probably over stated it.

Now, it doesn't affect our request.

What we're requesting is the same.

It just affects the deficiency between what our current rates will produce versus what we requested, so it is not uncommon to have errata in these kind of cases.

Great.

Thanks a lot.

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

Good morning.

Good morning.

You guys held an open seasons for an expansion to Carthage and Perryville, I believe.

Can you update us how that went?

We held that open season.

The open season ended.

We are now talking with the customers that responded to that open season, but we have reached no conclusion yet around that.

Other than we don't think there is a big bullet pipe, new bullet pipe that we would be part of, but there could be some other things that come out of that, but we're just still talking, I guess I would say.

Do you think we would have an answer by the end of the year?

Well, we'll have an answer of some sort, yes, I think we will.

Yes.

Okay.

Fair enough.

Thank you.

Our next question will come from the line of Ali Agha with SunTrust.

Thank you.

Good morning.

Good morning.

Gary, what was the weather impact in this quarter and what was the delta year-over-year from weather?

There was no difference in weather between the second quarter of last year and the second quarter this year.

They were both a little warmer than normal.

I think if you looked at it from a normalized basis, we probably gained $9 million, $10 million from weather, but we gained the same amount in 2009, so really very little difference between years.

I see.

And, David, also if you can sum up for us once your current projects on the Field Services side are completed, can you just remind us what total capacity will you then have at that time and what will be the mix between the new versus the old and how should we compare that to what the full year 2010 may end up looking like?

Yes.

Let me try to attack those one at a time.

We currently have -- we're building 1.5 Bcf of system capacity in the Haynesville, and there is an additional expansion option that Shell and EnCana could elect on both those systems that could take that capacity to 2.8.

So we have 1.5 committed, and it could go to 2.8.

If you look at where we were in our traditional basins a year ago, we were gathering 1.1 Bcf a day, so the Shell plays are going to quickly be the biggest part of our system, and we have seen some erosion in our traditional basin, so I expect that we're going to see the shales overtake their traditional basins this year and then going forward, we're going to have more and more of our revenues are going to be from these throughput guarantee contracts and rate of return guarantee contracts.

I haven't done the mix, but we tried to give you a little flavor around, so far this year we've got 158 Bcf a year in total from traditional and 126 from shale plays.

My guess is, by the end of this year the shale plays will catch up and surpass the traditional basins or be very close to it.

Very helpful.

Last question.

Also to clear up, you talked about having a balance sheet now to meet the current needs.

Are there projects out there, potential projects, David or Gary, that announce that had may cause to you reconsider, perhaps raising more equity, sooner rather than later?

No.

I don't think there is anything sooner rather than later.

Look, as I said, we have strengthened our balance sheet.

We can execute our business plan at least at the visible plan that we have in front of us, certainly if there is a terrific new project we'll step back and look at our balance sheets to ensure that our credit ratings are secure and that we can execute our business plan, but I don't think there is anything in the foreseeable future or the near term, let's say that.

Okay.

Thank you.

Our next question will come from the line of Tom O'Neill with Green Arrow.

A quick question on the Houston rate case.

With the errata filing does that at all change the rest of the schedule or are we still on track for intervener and staff testimony?

I think it is next month?

Scott, what do you think about that?

We filed that errata on Monday.

The parties will discuss it with us, whether or not they think that's the kind of thing that would justify a change in the schedule.

I can't predict that right now.

Right now we're working on a schedule that calls for a decision by the Commission toward year end.

Okay.

And then just a question on the equity layer.

I know Chairman Smitherman made some comments in an open meeting with the equity layer for the TDUs, but has there been anything on the record from the other Commissioners?

I do not think -- not that I recall.

The comment that I recall is Chairman Smitherman's.

Okay.

Great.

Thank you.

Our next question will come from the line of Faisel Khan with Citigroup.

Good morning.

Good morning.

Gary or David, I think you talked about the $7 million deferred tax balance that was being credited to investors for the storm recovery costs.

Is that $7 million a quarter, is that right?

It is about $23 million a year.

There was about $6 million I think in the second quarter and a comparable amount in the first quarter, so about $23 million for the total year.

And that continues for the duration of the transition bonds?

That's correct.

Okay.

Declines.

Except it declines over time, yes.

Declines over time?

I think we have a schedule on that, that we provided?

It is in a filing.

Okay.

Got you.

And then on the incremental 200 million cubic feet a day that Shell and ENcana exercised their option on, is that recently?

Is that a new sort of announcement by you or is that something that we kind of expected along with the initial 700 million cubic feet a day ramp up?

Greg Harper, why don't you answer that question?

The expansion was executed in April, and that is 200 million of a Bcf potential expansion of the 700 million a day existing system that we're building, and then on the Olympia system, they had the option to expand it by 580 million a day.

Okay.

Got you.

And then last question.

On the -- what are your plans going forward with the DRIP?

Yes.

As I said earlier in terms of our benefit plans and our DRIP, we have raised about $55 million.

You really can't extrapolate that out because of the timing of those contributions, but think about 3 million shares for the balance of the year is what the price will be determined at that point in time.

Think about additional 3 million shares coming from the combination of our investor choice plan and our benefit plan.

Okay.

Great.

Thanks for the time.

Appreciate it.

Our next question will come from the line of Steve Gambuzza with Longbow Capital.

Good morning.

Good morning.

Just wanted to clarify the comment on future equity needs.

Is that -- I know you have a five year CapEx plan that was posted in your 10-K and there have been some adjustments to that for some announcements made since the 10-K was filed versus these expansion plans.

Was the comment of no new equity except via the dividend reinvestment plan, does that relate to that five year CapEx plan?

Yes, it does.

Okay.

So we should assume for modeling purposes that normal level of DRIP issuance to accommodate that CapEx to the extent there were large growth projects layered on top of that, that might require some equity, but absent those projects share change?

That's correct.

At that point we would evaluate it if we have a project significantly above and beyond that, but as you know, Steve, these businesses produce a lot of cash.

We're able to obviously retain earnings, and we have debt capacity, so we can execute our visible business plan.

Okay.

And I just can't recall what exactly is assumed in the five-year CapEx plan, versus the expansion options on these contracts, if your partners elect to go forward with the expansion that you just discussed on this call, do you think you're internally generated funds and debt issuance can accommodate those expansions?

Yes.

I think so.

Greg, do we have the expansion, any expansion options in our five year capital budget?

We built in several expansion options over the next five years, not the full elections, though.

Thanks very much.

Our next question will come from the line of Nathan Judge with Atlantic Equities.

Good afternoon.

My questions actually are centered around equity issuances and equity offerings as well.

With regard to the true up case, could you give us the sensitivity of what your plans would be if on both sides of the coin, if you win or if you lose and what that could potentially mean for equity offerings?

First of all, we'll see how that plays out.

Just to remind you, Nathan, to the extent there was to be some downside, this is not a significant cash need, an immediate cash need.

There will be some but it is not immediate because the refunds will be over the remaining life of the securitization bonds, so from that perspective.

To the extent I said before justice is served and we do receive a significant amount of dollars or dollars and then we have not determined at that point, certainly that's going to allow us to fund growth in the future and certainly with substitute for any need for equity to the extent we're able to execute on value creating growth in the future above and beyond our current plans.

Are you managing to a debt to equity ratio now, or is there a targeted internal ratio you're looking to achieve, or is the current ratio appropriate for the future?

I think over time we're going to continue to improve the overall ratio.

As you know, we still do have some holding company debt, although we'll be paying down or retiring some debt in September, so over the long-term and I think probably 60/40 is probably a better capital structure, but our utilities remain strong, and that's our focus, is to do our financing going forward at the utilities, so we'll over time reduce the debt at the parent company and finance at the utilities.

And just at the utility level, to get from that 46% equity ratio that you had actual in the rate case filing to the 50%, is there ability to take equity from the parent down to Houston Electric or how will that functionally be done?

I think we adjusted to dividends.

Okay.

So just not paying dividends up to the parent would get you up to that ratio quite quickly, then?

That's right.

Okay.

Just thank you very much for your patience.

One last question.

With regard to the DRIP, you mentioned 3 million.

Should we just annualize that i.e.

6 million annual basis going forward?

Well, I don't think you can think of it like that because it is variable depending on the timing of the contributions and the matches in our benefit plan, so as I said, we have issued I think about 4.5 million shares year-to-date.

You can't really double that, so I am giving you sort of an estimate of 3 million.

Again, that can be varied.

Think about 7.5 million shares for the full year.

The 7.5 million in 2011 and thereon.

I think if you think 2011, still some moving parts, but I think you have to think of that sort of number of shares.

Thank you very much.

Your next question will come from Yves Siegel with Credit Suisse.

Thank you.

Just two questions.

One on the option in the Haynesville to expand, is there a timeframe that or an expiration on that option?

Yes.

If both contracts or all four contracts with our customers were Olympia and Magnolia, our five-year window for expansion for those expansions to be elected and after that we would negotiate expansions after that for the 15 years.

Do you have a sense of what kind of gas prices they need versus the drilling activity just to maintain leases versus trying to get a little bit more aggressive what kind of gas prices they may need?

I really can't answer that, but I would point to EnCana's June slide presentation for their earnings call of what gas prices they like, and their drilling around that.

Okay.

And then thirdly and lastly lastly, as it relates to the question on trying to export your expertise in Field Services, how do you folks think about potential acquisitions?

Well, we're looking at them all the time with our customers, of course Shell and EnCana was a derivative of their acquisition of their existing facilities there that they were building to test their production, so we're always looking at acquisitions and our footprint and outside.

Okay.

Then this is my final thought, and I am curious on how you may or may not respond to it.

The questions, all the questions around the equity were if there was a big organic growth project, and so am I reading too much into the fact that you didn't mention acquisitions that maybe you're not warm on any or how would you respond to that?

Don't read anything into that.

I think if you think of an acquisition, you think of that as a major or significant project, whether it be organic or from another source.

Okay.

Thank you very much.

Our next question will come from the line of Scott Senchak with Decade Capital.

Thanks.

Sounds like your CapEx at the pipeline, some of these projects Carthage, Perryville, FPL, JV, maybe not be as big as you thought.

Is this CapEx guidance that you guys kind of have out there, did this include some of that stuff?

Does it need to come down a little bit or what should we be thinking as far as that?

It didn't include any major pipeline projects.

It does include some estimates of growth projects, and some of those did he deferred -- we don't think we're going to execute on this year, and they may be pushed out into the future, but I think it is still a fair representation of the future CapEx short of a big prong.

Okay.

Great.

Is there a level of kind of base maintenance kind of CapEx there that we should think about or does it work like that?

We do have like $90 million or so.

Yes, I would say that as we look forward, it ranges from $90 million to $75 million depending on the year, but that's kind of the maintenance capital.

Okay.

Great.

Thanks a lot.

(Operator Instructions).

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

Appreciate the time.

Most of my follow-ups are .

One quick clarification on CenterPoint Electric, the errata that's being filed, the $15 million and I apologize.

Is this coming from, David, did you say it was a customer class revenue recognition issue or from higher expense?

I just want to make sure I am completely understanding of

Carl, what we do when we prepare a case, and this is part of the rules that you have to go by, is you have to normalize your current revenues based on the year end number of customers and volumes and in normalizing one class, and it is really the large commercial class, we think we may have attributed too many revenues to the current rates.

I.e., we overstated what the current rates will produce.

Doesn't affect our request, but is it does affect how we look at the delta between current rates and what we requested.

As I said, we're still looking at that.

It is $15 million or so is our calculation.

If we get comfortable with that, we will file the errata early next week, and we feel pretty strongly we probably overstated it or I wouldn't mention it, and I just didn't want you guys to be think that we didn't tell you something here two or three days in advance of having to file it, but that's what it is.

It is simply we have to normalize revenues and in normalizing, we think we overstated the current rates.

Thanks for the clarification.

Okay.

Our next question is from Lasan Johong with RBC Capital Markets.

My question was asked and answered.

Thank you.

Thank you.

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

Just wondering if you can clarify what the Texas Commission is mulling over, is it the system of riders which would allow companies not to file as often and basically recover automatically some specific costs?

Daniele, it is Scott.

The Commission has before it a rule making, a proposed rule making that would provide for a periodic adjustment in distribution rates.

The proposal that the Commission issued centered around a periodic adjustment to reflect capital investment where as in our rate case we had asked for an adjustment that took into account not only capital but operating expenses as well.

We're in the early stages of the comment process on that rule making as you probably know the Commission issued a proposal.

People comment on it and the commission may choose to revise their proposal.

It has been published further and at some point adopted in final form.

This may take some twists and turns before we see what the commission wants to do with it.

We will urge them in the rule making proceeding to expand the adjustment mechanism to include expenses and other parties who will have different ideas about how the commission should do it.

I think what's driving this is just a recognition on the part of the commission that the process for setting rates in Texas could stand to be modernized a little bit.

Great.

You anticipate the finalization of the Olympia of all of the to come by year end?

I think that's a good guess, a rule making again doesn't have a fixed schedule upon which is has to play out.

A lot of it depends on how quickly the parties and/or the commission can come to a consensus on what ought to be done here.

I would say that's a good guess of how long it might take but I wouldn't be surprised if it played out a little longer than that.

Thank you.

I think that's about all the time we have left.

Thank you very much to everyone.

I would like to thank you very much for participating in the call today.

We appreciate your support very much.

Have a great day.

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

Thank you for your participation.