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CenterPoint Energy, Inc. (NYSE:CNP)

Q2 2010 Earnings Call Transcript

August 04, 2010 11:00 am

Executives

Marianne Paulsen - Director, IR

David McClanahan - President and CEO

Gary Whitlock - EVP and CFO

Scott Rozzell - VP

Analysts

Carl Kirst - BMO Capital

Lasan Johong - RBC Capital Markets

Daniele Seitz - Dudack Research

Paul Patterson - Glenrock Associates

Leon Duval - Catapult

Ali Agha - SunTrust

Tom O’Neal - Green Arrow

Faisel Khan - CitiGroup

Steven Gambuzza - Longbow Capital

Nathan Judge - Atlantic Equities

Yves Siegel - Credit Suisse

Scott Senchak - Decade Capital

Operator

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

Marianne Paulsen

Thank you very much Tina. Good morning everyone, this is Marianne Paulsen, Director of Investor Relations for CenterPoint Energy. I would like to welcome you to the 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 the 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 Investors section.

I would like to remind you that any projections or forward-looking statements made during this call are subject to the cautionary statements on forward-looking information in the company’s filings with the SEC. Before Mr. McClanahan begins, I would like to mention that a replay of this call will be available until 6:00 p.m. Central Time through Wednesday, August 11, 2010.

To access the replay please call 1800-642-1687 or 706-645-9291 and enter the conference ID number 86603138. 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 you, David McClanahan.

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 key sensitivities around profitability in that business? And 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 that there’s a good chance and 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 30. This filing was required as part of the settlement we reached in our last rate case over four years ago. Our rate request has 2 pieces, a $76 million increase in our distribution rates and an $18 million 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 filings, may actually be another $15 million or still higher. The increases we have requested in our base rates are influenced raised significantly by three factors.

First, we are shifting the 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 rate 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 point 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 cost 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 a part of this filing we also requested a distribution cost recovery mechanism that would allow us to annually adjust the 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 filings. 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 businesses. 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 our customers develop their projects using vertical drilling and our Shale plays where horizontal drilling is the norm.

In our traditional basins, we both gather and process natural gas. We typically have dedicated acreage provisions in our contracts, but no throughput guarantees. The majority of our processing whether from our wholly owned plants or our Watscom 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 margins 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 are not exposed to the throughput risk of the traditional basins.

There are minimal amount of liquids in the natural gas we currently gathered from the Shales and therefore limited processing opportunities. Our three largest customers in the Shale plays are Shale, Encana and Exxon Mobil, the successor to our long time customer XTO. Gathering for Exxon Mobil is concentrated in the Fayetteville and Woodford Shale while gathering for Shale in Encana is concentrated in the Haynesville Shale.

The majority of our activities and investments 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-connect activity remaining.

To date, we’ve spent about $286 million of our projected $325 million budget for the original 700 million cubic feet per day system. In addition, Shale 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 underway 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 connect 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 trump line is underway and permits are pending for the net gathering and treating facilities.

Our gathering volumes in the Haynesville area have increased substantially during the first six months of this year and includes some third party volumes not related to Shale 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 margins 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 margins from the Shale area. 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 contract or from compressor efficiencies.

As a rule of thumb we currently retain about 1% and 1.5% of all gathering volumes. So 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 both 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 the Board of Directors on July 22. We believe our dividend actions continue to demonstrate strong commitment to our shareholders and the confidence the Board of Directors has in our ability to deliver sustainable earnings in cash flows.

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

Gary Whitlock

Thank you David and good morning to everyone. Let me give you a little more details about the performance of our individual business units. Houston Electric reported operating income of $122 million compared to the $129 million in 2009. As part of our securitization of Hurricane Ike restoration cost 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 billed during the life of the securitization bond. The reduction in revenues from this credit, accounts for substantially all of 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 of the mark-to-market impact associated with the revenues 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 optimize our transportation and storage assets. Without such opportunities, operating income will be primarily tied to margins from natural gas sales to commercial, industrial and wholesale customers.

Finally, let me turn to our pipeline in field services segment. Our industry 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 the 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 the 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 play. 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 ratings 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 bonds were upgraded to A3 from Baa1 and its senior unsecured initial ratings were upgrading to Baa2 from Baa3.

Houston Electric was the only one of our companies that was on the ratings review at Moody’s. The Moody’s continues to have positive ratings outlook from the parent company and on (inaudible). We have worked very hard to strengthen our balance sheet and are gratified by this action.

Turning to financing activity in the second quarter on June 9, we executed a $326 million equity offering consisting of 25.3 million shares following the announcement of our second set of field services agreement with Shale and Encana. As has been our practice for last several years, we have raised another $55 million year-to-date by issuing approximately 4.4 million shares through our Benefit and Investor’s Choice plans.

The proceeds 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 18 months we have significantly improved our balance sheet through the issuance of the shares. In addition, we have reduced our debt level, improved our credit metrics and credit ratings and remained in a very strong liquidity position. Our overall business performance remains 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 equities that we will continue to raise through our Benefit and Investor’s Choice plans.

Finally, let me discuss our earnings guidance. We are pleased with our overall business performance in the second quarter and this morning we reaffirmed our 2010 earnings guidance in the range of $1.2 to $1.12 per diluted share. This guidance reflects the earnings per share impact of the new shares we have issued this year and an estimate of the shares being issued in our Benefit and Investor’s Choice plan.

In providing earnings guidance, we have taken into consideration our year-to-date performance as well as various economic, operational and regulatory assumptions. And 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 events securities or any mandated accounting changes that may occur during the year.

As the year progresses, we will keep you updated on our earnings’ expectations. Now, I would like to turn the call back to Marianne.

Marianne Paulsen

Thank you Gary. With that we will now open the call to questions. In the interest of time I will ask you to please limit yourself to one question and a follow-up. Tina would you please give the introduction on how to ask the questions.

Question-and-Answer-Session

Operator

At this time we will begin taking questions. (Operator Instructions) And our first question will come from the line of Carl Kirst with BMO Capital.

Carl Kirst - BMO Capital

Thank you, good morning everybody and David really appreciate that you added color on the midstream. Maybe I can start there and you know with the track record that you are putting in place getting Magnolia in the service 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 Encana Shell or within maybe other players.

David McClanahan

Yeah we continue to talk to all of our customers including Shell and Encana about some of the basins that we would like to get into and Eagleford is probably one that gets the most attention but we are in discussions and we hope to be successful there but there's lot of competition for this business and hopefully we are demonstrating to our customers that we can do this well, meet their expectations and give them on time and that's our goal there. But I would say we are just in discussions now. We really have nothing to report at this time. But we are working hard on it.

Carl Kirst - BMO Capital

Okay and then maybe then a follow-up just also on the pipeline side. Looking at least basis for Florida in July has widened out quite substantially. Is that having any benefit on to SESH right now and if I recall correctly there's some additional contract to be layered on to that come into service with SESH anyway maybe mid-2011 is that correct.

David McClanahan

Yeah we have about a 155 a day that's wasn't sold or it starts later but we've already sold that on an interim basis through October so we did that back in May. So we have no additional capacity that's on market there to my knowledge.

Carl Kirst - BMO Capital

So the interim is sold out for October and the final remaining contracts will come in service next year is that.

David McClanahan

That’s right and we still have about 80 a day that is installed on a long term basis. But we know some of these contracts kind of come in over time and what there's 75 that's coming in middle of next year on long term basis, we still have that 80 we need to sell.

Operator

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

Lasan Johong - RBC Capital Markets

Rate case, just going over the numbers again $38 million for the smart meter, $40 million for the equity component to 50%. 11.25%, are we at $7 million for 25 basis points, I believe it was a 75 basis point increase.

David McClanahan

We’ll try to answer your question, well, repeat your question.

Lasan Johong - RBC Capital Markets

Well, basically to cut the conversation short, it looks like the amount of the rate increase you said you are requesting is $15 million but I'm looking at a number more like $21 million, does that mean that this other components are accounting for the difference.

David McClanahan

Now as you know we 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 what $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 that $105 million or so and what we are trying to do just give you the sensitivities, of that $105 million, $38 million is AMS. And we were required to reconcile our AMS investments and we move that into base rates. So that accounts for a part of it.

$40 million accounts for the increase in the capital structure, of the equity components. 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 asked for 50%. If we get 50% that has that $40 million effect, if we get 45%, well, take $20 million off of that.

And then the ROE simply, we are giving sensitivities around that and you can guess kind of what the Commission might do there as well if we can. These are the big components but there were some other big components but they were offset by other things we did that reduced expenses. So net-net those are the big items and I think those are ones that our case is most sensitive to.

Lasan Johong - RBC Capital Markets

Understood, on the field service business NGL spreads have been going up and down like a yoyo and as of late its been strengthening obviously this doesn’t necessary have a direct impact on CenterPoint but wondering if there are some sensitivities on the drilling front around movements in NGL and if you have seen the effects of that. So NGL pricing and if you see the effects of that and if you think there's overall abundance of NGLs coming down the line with over Shale drilling.

David McClanahan

Well, we have seen natural gas liquids prices higher this year than last year, there's no question about it. I think they have started to come down a little bit both in the second quarter from the first and we still see a little weakness there. Still not to the levels they were in 09. We've seen some and I will speak to our basins we've seen some traditional drilling this year. There's probably 65 or 70 well in our traditional basin that have been added to our systems that’s more than last year. But I’m not sure if that's what’s driving that.

Certainly the Eagleford 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 for that very reason. But we still see a fare amount activity in the basins we are traditionally gathering.

Lasan Johong - RBC Capital Markets

Okay last question is it fair to say that third quarter got off to a pretty good start in July.

Gary Whitlock

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

Operator

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

Daniele Seitz - Dudack Research

I was just wondering how much we have the pension costs and the reduction in depreciation.

Gary Whitlock

I think pension was something like $26 million, amortization was $20 and the offset in depreciation was a little less than $40 million, like $38 million or $39 million.

Daniele Seitz - Dudack Research

Great and as far as number of small meters installed so far and how much do you expect to install next year and for the full year of 2010.

Gary Whitlock

Yeah we’ve got about a 1.5 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 1 million and then we’ll install a close to a 1 million next year not quite. And then by probably, the mid-2012 we will be complete.

Daniele Seitz - Dudack Research

Right and just one quick one can you put some details on the joint ventures with (SPL).

Gary Whitlock

Yeah you know we don't, that’s kind of in advance right now. It’s not formally.

Daniele Seitz - Dudack Research

Okay I was not sure, yeah.

Gary Whitlock

Yeah we are still looking at that Haynesville area. If there's anything there. Now we think it's a smaller project that's really probably an expansion of our existing system which doesn't really kind of fit with the joint venture. But we are still talking with them and we are still watching the market. As you know we had an open season in Haynesville and we are still talking to customers that responded to that open season have made no decisions yet around that.

Daniele Seitz - Dudack Research

But its looks like a smaller project.

Gary Whitlock

Yeah we don’t see a big new bullet price in the near term from ours advantage point.

Operator

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

Paul Patterson - Glenrock Associates

Just really quickly I am sorry if I missed this, what was the ROE that you guys earned in last 12 months, the actual earned ROE and is the capital, is the capitalization ratio already up to 50%.

David McClanahan

I will take the last one first. We’re about. We thought that about 46% which was our actual equity structure, we want 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. But if you adjust that for whether, it’s about 9.8% on our actual cap structure which was 46% equity.

Paul Patterson - Glenrock Associates

Okay great and then just finally you guys made some notable change in our growth rate for the time after you filed, what was it that caused it to move up the rating.

David McClanahan

We actually Paul haven’t officially filed it yet to our case. So we are going probably do that next week. Really in answering some interrogatories we looked at how we normalized certain rate classes and we 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've probably overstated it. Now it doesn't affect our request. You know what we are requesting is the same, it just affects the deficiency between what our current rates will produce versus what we requested. So it’s not uncommon to have a rate in these kind of cases.

Operator

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

Leon Duval - Catapult

You guys held an open season for an expansion Carthage and Perryville, can you update us on how that went?

David McClanahan

We held the open seas and the open seas in (inaudible) 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's a big bullet pipe, new bullet pipe that we would be a proud of but there could be some other things that come out of that but we are just, we are still talking I guess I would say.

Leon Duval - Catapult

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

David McClanahan

Well we will have an answer of some sort, yeah, I think we will.

Operator

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

Ali Agha - SunTrust

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

Gary Whitlock

There was no difference in weather between the second quarter of last year and the second quarter of this year. They were both a little warmer than normal. I think if you look at it from a normalized basis we probably gained 19 million from weather but we gained the same amount in ’09. So really very little difference between the years.

Ali Agha -SunTrust

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 would 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.

David McClanahan

Yeah let me try the impact of it one at a time. We currently have about, we are building 1.5 bcf of system capacity in the Haynesville and there's an additional expansion option that Shell Encana could elect on both those systems that could take that capacity to 2.8. So we got 1.5 committed and it could go to 2.8.

If you look at where we were in our traditional basin, a year ago we were gathering 1.1 bcf a day so the Shale plays are going to quickly be the biggest part of our system and we have things from erosion in our traditional basin. So I expect that we are going to see the Shales overtake the conditional basins this year and then going forward we are going to have more and more of our revenues are going to be from these throughput guarantee contracts and rate of return guaranteed contracts.

I haven’t done the mix but we try to give you a little flavor around so far this year we have got 158 bcf a year in total from traditional and a 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.

Ali Agha -SunTrust

Last question also to clear up you talked about having the balance sheet now to meet the current needs, are there projects out there, potential projects, David or Gary that you may force you to reconsider perhaps raising more equity, sooner rather than later?

Gary Whitlock

No I don’t think there's anything soon rather than later. Look as I have said he have strengthened our balance sheet. We can execute our business plan at least that the visible plan that we have in front of it. Certainly if there's a terrific new project, we will step back and look at our balance sheet to ensure that credit ratings are secure and then we can execute our business plan but I don’t think there's anything in the foreseeable future or the near-term let's say that.

Operator

Our next question will come from the line of Tom O’Neal with Green Arrow.

Tom O’Neal - Green Arrow

Just a quick question on the Houston rate case with the rate of filing, does that at all change the rest of the schedule, or are we still on track for being (inaudible) I mean next month?

David McClanahan

Scott what do you think about debt?

Scott Rozzell

We filed that on Monday. The parties will discuss it with us whether or not they think that that’s the kind of things that would justify a change in the schedule. I can't predict that right now but right now we are working on the schedule that calls for a decision by the Commission towards year end.

Tom O’Neal - Green Arrow

And then just a question on the equity layer, I know the Chairman of (inaudible) made some comments in an open meeting about the equity (layer) for the TDUs but has there been anything on the record from the other commissioners?

David McClanahan

Not that I recall. The comment that I recall is Chairman (inaudible).

Operator

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

Faisel Khan - CitiGroup

Gary I think or David you talked about the $7 million sort of deferred tax balance that has been credited to investors for the storm recovery cost. Is that $7 million a quarter, is that right?

David McClanahan

It’s about $23 million a year. So there was about $6 million I think in the second quarter and a comparable amount in the first quarter. So that $23 million for the total year.

Faisel Khan - CitiGroup

And that continues for this duration of this transition bond?

Gary Whitlock

That’s correct.

Faisel Khan - CitiGroup

Okay.

David McClanahan

It actually declines.

Gary Whitlock

It declines over time yeah.

Faisel Khan - CitiGroup

It declines overtime?

Gary Whitlock

Yeah, and I think we have a schedule on that, I don’t think we have provided, I mean its (inaudible) this is in the filings.

Faisel Khan - CitiGroup

Okay got you. And then on the direct incremental 200 million cubic feet a day that Shale Encana exercise their option on is that recently or is that a new sort of announcement by you or is that something that we kind of expect it along with the additional 700 million cubic feet of day ramp up?

David McClanahan

Greg Harper wants to answer that questions.

Greg Harper

The expansion was executed in April and we, that is 200 million of bcf potential expansion of the 700 million a day existing systems that we are building. And then on the Olympia system they have the option to expand it by 580 million a day.

Faisel Khan - CitiGroup

Okay, got you. And then, last question, on the, what are your plans going forward with the drip.

David McClanahan

As I said earlier, in terms of our benefit plans in our drip we've raised that 55 million, we 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, its what you, the price will be determined at that point in time but think about additional 3 million shares coming from the combination of our Investor’s Choice plan and our Benefit plan.

Operator

Our next question will comes from the line of Steven Gambuzza with Longbow Capital.

Steven Gambuzza - Longbow Capital

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 I guess adjustment for some announcements made since the 10-Q was filed versus these expansion plans. With the comment of no new equity except the dividend reinvestment plan, does that relate to that five-year CapEx plan?

David McClanahan

Yes, it does.

Steven Gambuzza - Longbow Capital

Okay, so we should assume for modeling purposes that a normal level of drip issuance to accommodate that CapEx, to the extent they were large growth projects layered on top of that that might require some equity but absent those projects is that going to change?

David McClanahan

Yeah, that’s correct, I mean, at that point we would evaluate it if we have a project significantly above and beyond that, but as you know, Steve we, these businesses produce a lot of cash, we are able to, obviously retain earnings and we have debt capacity so we can execute our visible business plan.

Steven Gambuzza - Longbow Capital

Okay and I just can’t recall what exactly is assumed in the five-year CapEx plan versus the expansion option on these contracts. So do that, if your partners elect to go forward with the expansion that you have just discussed on this call, do you think your internally generated funds and that issuance is going to accommodate those expansions?

Gary Whitlock

Yeah, I think so.

David McClanahan

Yeah, Greg you might, do we have the any expansion options in our five-year capital budgets.

Greg Harper

We've built in several expansion options being elected over the next five years, not the full escalations though.

Operator

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

Nathan Judge - 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 loose and what that could potentially mean for equity offerings?

Gary Whitlock

Well, first of all we will see how that plays out and again just to remind you Nathan through the extent there was to be some downside this is not a significant cash need, immediate cash, there will be some but its not immediate because the refunds will be over the remaining life securitization bond. So from that perspective, to the extent as I have said before justice is served and we do receive a significant amount of dollars then we have not determined at that point. Certainly that’s going to allow us to fund growth in the future and certainly we would substitute for any need for equity to the extent we are able to execute on value creating growth in the future, above and beyond our current plan.

Nathan Judge - Atlantic Equities

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

Gary Whitlock

Well I think over time we are going to continue to improve the overall ratio. As you know we still do have some holding company debt, although we are repaying down and we are tying some debt in September. So over the long term and well I think probably 60-40 is probably is a better capital structure. But our utilities remain strong and that's our focus is doing financing going forward at the utilities. So we have overtime reduced the debt at the parent company and finance of the utilities.

Nathan Judge - Atlantic Equities

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

Gary Whitlock

I think we’ve adjusted to a dividend.

Nathan Judge - Atlantic Equities

Okay, and so just not paying dividends up to parent would want to get you up to the ratio quite quickly then.

Gary Whitlock

Yeah that’s right.

Nathan Judge - Atlantic Equities

And just, thank you very much for your patience but one last question with regard to the drip, you mentioned $3 million, should we just annualize that i.e. $6 million on an annual basis going forward.

Gary Whitlock

Well, I don’t think you can think of it like that because its variable depending on the timing of the contributions and the matches in our benefit plans. So as I have said we’ve issued I think about 4.5 million shares year-to-date. You can’t really double that. So that's not giving sort of an estimate of 3 million. Again that can vary, so think about 7.5 million shares for the full year. That’s an estimate.

Nathan Judge - Atlantic Equities

The 7.5 million in 2011 and there on that number.

Gary Whitlock

Well I think if you think 2011, again still some moving parts. But its I think you have think of that sort of number of shares yeah.

Operator

Our next question will come from the line of Yves Siegel with Credit Suisse

Yves Siegel - Credit Suisse

Well, thank you just two questions, one is on the option in the Haynesville to expand. Is there a timeframe that or an expiration on that option.

Gary Whitlock

Yeah, both contracts or all four contracts with our customer for Olympia and Magnolia are five year windows for those expansions to be elected and then after that we would negotiate expansions after that with them for the 15 years.

Yves Siegel - Credit Suisse

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.

Gary Whitlock

You know Yves I have read, we can answer that by looking into our (inaudible) June slide presentation for the earnings call will give you a good idea of what gas prices they would like and when the drilling (inaudible) in that presentation.

Yves Siegel - Credit Suisse

And then thirdly and lastly, as it relates to the question I am trying to export your expertise in field services how do you folks think about potential acquisitions?

Gary Whitlock

We are looking at them the amount of time with our customers. And of course Shell and Encana is a derivative of an acquisition of their existing facilities there that they were building to test the production. So we are always looking at acquisitions with our footprint outside.

Yves Siegel - Credit Suisse

Okay, and this is my final thought and I am curious on how you may or may not respond to it. The questions, to all questions around the equity, if there was a big organic growth project and so am I reading too much into the fact that you didn’t mention acquisition that maybe you are not warm on any or I mean how would you respond to that?

Gary Whitlock

I don’t think, I don’t read anything into that, I think if you think of an acquisition, you can think of that as a major or significant project whether it be organic or from an other source.

Operator

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

Scott Senchak - Decade Capital

Hi, thanks sounds like your CapEx at the pipeline on some of these (inaudible) the SPL JV maybe not be as big as you thought, is this CapEx guidance that you guys kind of have up 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.

David McClanahan

No, I didn’t include any major, pipeline projects. It does include some estimates of some growth projects and some of those we deferred. We don’t think we are going to execute on this year and they maybe pushed out into the future. But I think it’s still a fair representation of the future CapEx short of a big project.

Scott Senchak - Decade Capital

Okay great, and is there like a level of kind of base maintenance kind of CapEx there that we should think about or (inaudible)

David McClanahan

We've been doing that like $90 million or so, yeah 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.

Operator

(Operator Instructions) Our next question will come from the line of Carl Kirst with BMO Capital.

Carl Kirst with BMO Capital

I appreciate the time, most of my follow ups are hit up, just one quick clarification CenterPoint Electric the rate that's being filed, the $15 million and I apologize, is this coming from Dave, did you say it was a customer class revenue recognition issue or from higher expense, I just want to make sure I’m completely understanding this.

David McClanahan

Now 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 volume and in normalizing one class and its 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.

That in effect is our request but does affect kind of how we look at the delta between current rates and what we requested. As I say we’re still looking at that, you know its $15 million or so, is our calculation. If we get comfortable with that we will file the (rata) early next week and we feel pretty strongly that we probably overstated it and I wouldn’t mention it and I just didn't want you guys to be and frankly we didn't something here two or three days in advance of having to follow it. But that's what it is, its simply we have to normalize revenues and in normalizing we think we overstated the current rates.

Operator

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

Lasan Johong - RBC Capital Markets

My question was asked and answered. Thank you.

Operator

And our next question will come from Daniele Seitz the Dudack Research.

Daniele Seitz - Dudack Research

I was just wondering if you could clarify what the Texas Commission is running over, if it’s a system of (inaudible) which would allow companies not to file assignment basically to cover some specific costs.

Scott Rozzell

Daniel its Scott, the Commission has prepared a rule-making a proposed rule-making that would provide for a periodic adjustment and distribution right. The proposal that the Commission issued centered around a periodic adjustment to reflect capital investment whereas 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 issues a proposal, people comment on it, the Commission then may choose to revise their proposal, its been published further and then at some point adopted in final form. This may take some twists and turns before we see what the Commission finally wants to do with it.

But we will urge them and the rule-making proceeding to expand the adjustment mechanism to include (mentors) and there are other parties who will have different ideas about how the Commission should do it. But I think what's driving this is just a recognition on the part of the Commission that the process for setting rights in Texas could stand to be modernized a little bit.

Daniele Seitz - Dudack Research

Great and you anticipate the finalization of (inaudible) to come largely by your hand.

Scott Rozzell

Well, I think that’s a good guess, rule-making again doesn’t have fixed schedule upon which it has to play out, a lot of it depends on how quickly the parties end or the Commission can come to consistent on what ought to be done here. I would say that that’s a good guess of how long it might take, but I wouldn’t be surprised if they play that a little longer than that.

Marianne Paulsen

Okay I think that’s about all the time we have left. So thank you very much to everyone. I would like to thank you very much for participating in our call today. We appreciate your support very much. Have a great day.

Operator

This concludes the CenterPoint Energy’s second quarter 2010 earnings conference call. Thank you all for your participation.

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Source: CenterPoint Energy, Inc. Q2 2010 Earnings Call Transcript
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