CenterPoint Energy Inc (CNP) 2009 Q1 法說會逐字稿

Good morning and welcome to CenterPoint Energy's first quarter 2009 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 would now like to turn the call over to Marianne Paulsen, Director of Investor Relations.

Ms.

Paulson?

Thank you very much, Tina.

Good morning, everyone.

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

I'd like to welcome you to our first quarter 2009 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 first quarter 2009 results and will also provide highlights on other key activities.

In addition to Mr.

McClanahan and Mr.

Whitlock, we have other members of management with us who may assist in answering questions, following their prepared remarks.

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

I would like to remind you 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 a replay of this call will be available until 6:00 p.m.

Central Time through Wednesday, May 6, 2009.

To access the replay, please call 1-800-642-1687 or 706-645-9291 and enter the conference ID number 94424104.

You can also listen to the online replay of the call through the website that I just mentioned.

We will archive the call on CenterPoint Energy's website for at least one year.

And with that, I will now turn the call over to David McClanahan.

Thank you, Marianne.

Good morning, ladies and gentlemen.

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

This morning, we reported net income of $67 million for the first quarter or $0.19 per diluted share.

This compares to net income of $122 million or $0.36 per diluted share for the same period of 2008.

Operating income for the first quarter of 2009 was $285 million, compared to $336 million for the same period of 2008.

While on its face this may look like a disappointing quarter, I believe we had better operating performance than the reported numbers would indicate.

Included in our earnings are mark-to-market charges and natural gas inventory writedowns of almost $25 million.

These charges are primarily a matter of timing and are expected to turn around as the year progresses.

We also incurred a charge of almost $12 million related to our ZENS securities as a result of the change in the value of the Time-Warner stock being greater than the associated derivative liability.

Without the impact from these items, our earnings would have been approximately $0.26 per diluted share, more in line with the first quarter expectations.

Let me give you a little more detail regarding the performance of each of our business segments, beginning with Houston Electric.

Our regulated transmission and distribution utility, Houston Electric, reported operating income of $37 million compared to $54 million in 2008.

The decline in operating income was the result of two primary factors.

The largest impact was from reduced throughput which had a negative impact of $18 million.

This was partially due to mild weather and partially due to conservation.

While I think it's too early to draw any longer term conclusion, it appears that our customers were more energy conscience in this first quarter.

The second factor was the increased pension expense of $5 million.

Partially offsetting these two factors was an increase in customers of nearly 35,000 since the first quarter of last year and increased transmission revenues, primarily from a tariff change implemented last fall.

Beyond this quarter, we do not expect pension expense to impact earnings at Houston Electric as we will be able to defer any increase for consideration in Houston Electric's next general rate case.

Under Texas law, an electric utility may elect to defer changes in pension expense over a base year which in our case was 2007.

We made this election in the first quarter of this year and will defer approximately $29 million in pension expense this year.

As many of you may be aware, Houston Electric is in the process of installing an advanced metering system as the result of a settlement agreement approved by the Texas PUC in December.

We've installed 10,000 smart meters in the first two months of the program and are on target to deploy approximately 145,000 smart meters by the end of the year.

Over the next five years, we will deploy approximately 2.4 million smart meters across our service territory at a capital cost of approximately $640 million.

We are recovering the cost through a surcharge that went into effect in February.

Because of the structure of this tariff and the timing of deployment, we expect the project will have a small negative impact on cash flow and a small positive impact on earnings in 2009.

Now, I'll turn to our natural gas distribution business.

This unit reported operating income of $118 million, a slight decline from the $121 million we reported for the first quarter of 2008.

Benefits from rate changes and miscellaneous revenues totaling approximately $13 million were more than offset by increased pension expense of $9 million and reduced customer usage which had a $6 million negative impact.

Unlike our electric utility, we are not able to defer the increases in our pension expense at our gas utilities.

We continue to pursue rate mechanisms to decouple revenues from the volume of gas sold to help mitigate the trends of reduced customer usage.

As an example, in our Texas coast jurisdiction, we recently gained an approval for an annual cost of service adjustment mechanism to recognize changes in usage, operating costs and rate base.

As we mentioned on our last call, we filed a request with the Minnesota Public Utilities Commission last November to increase our Minnesota rates by approximately $60 million and implemented a $51 million interim rate increase in January which is subject to refund.

As part of the filing, we asked to decouple revenues from the volume of gas sold.

We do not expect final action on our request until early next year.

Our competitive natural gas sales and services segment reported operating income of $2 million for the first quarter of 2009 compared to $6 million for 2008.

The decline in income was primarily a result of $6 million in writedowns of natural gas inventory to the lower of average cost or market.

In addition, we regarded mark-to-market charges of $19 million compared to charges of $22 million last year, associated with derivatives we use to lock in economic gains.

Excluding these charges, our energy services business was essentially unchanged from last year and consistent with our expectations for the quarter.

Now I'll discuss our interstate pipeline unit.

Interstate pipelines recorded operating income of $69 million for the first quarter of this year compared to $71 million for 2008.

Phase III of our Carthage to Perryville pipeline was put into service last April, resulting in higher operating income this quarter.

In addition, we had greater off system sales and incremental firm revenues related to new power generation facilities on our system.

These benefits were more than offset by increased expenses in part due to higher pension expense and reduced ancillary service revenues.

In early March, we announced that we had executed a definitive agreement with Chesapeake Energy Marketing to transport their growing Haynesville shale natural gas production through our Carthage to Perryville pipeline.

There are two aspects to this agreement.

The first part which began earlier this month provides for a 27-month backhaul agreement of up to 500 million cubic feet per day.

The second part is a long-term forward haul agreement which provides for 230 million cubic feet per day of firm transportation capacity or over 80% of the total capacity of the Carthage to Perryville Phase IV expansion which is projected to be in service in April of 2010.

This agreement is an example of our strategy of emphasizing firm, fee-based transportation revenues on our system.

This year, we expect 90% of our interstate pipelines margin to come from fee-based firm transportation services.

The other 10% will come from ancillary services such as park and loan service, treating and processing and balancing services.

As you know, these ancillary services are driven by market dynamics, natural gas prices and natural gas liquids prices, and provide upside beyond the more predictable and consistent fee-based revenue.

The Southeast Supply Header, or SESH, our joint venture with Spectra, was placed in commercial operation last September and began flowing gas primarily to the Florida Markets.

While SESH has contracted for all but 80 million cubic feet of the 1 billion cubic feet per day of capacity, some of that capacity commitments phase in over the first three years.

We had expected that most of the remaining available capacity would be sold on an interruptible basis, but market conditions limited such sales.

Now let me discuss our field services segment.

We reported operating income of $26 million for the first quarter of 2009 compared to $45 million last year.

Last year's operating income benefited by $17 million from the sale of non-strategic assets and the settlement of a contractual dispute.

Excluding these prior year gains, operating income for field services was essentially on par with last year.

Increased fee-based revenues from new wells added to our gathering system since last year offset the revenue declines we experienced from reduced natural gas and natural gas liquids prices.

We are projecting that fee-based revenues will account for approximately 75% of this year's margin.

The remaining portion is sensitive to commodity volumes and prices.

We have locked in prices for a substantial amount of the projected volumes that are sensitive to natural gas prices.

In addition to operating income, we also recorded equity income of $2 million from our jointly owned natural gas processing facilities compared to $4 million the previous year.

The decline was primarily due to lower liquids prices, which are about one half of last years price levels.

While drilling activity in the conventional basins is down over 50% year-over-year, activity in the unconventional shale areas, particularly the Haynesville, Woodford and Fayetteville shales has been minimally affected with producer activity remaining steady.

Most of our growth projects for this year are concentrated in these shale areas.

In closing, I'd like to remind you of the $0.19 per share quarterly dividend declared by our Board of Directors on April 23rd.

We believe our dividend actions continue to demonstrate a strong committment to our shareholders and the confidence that the Board of Directors has in our ability to deliver sustainable earnings and cash flow.

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

Thank you, David, and good morning to everyone.

Today, I would like to discuss a couple of items to review, beginning with the process of recovering our costs related to Hurricane Ike.

Earlier this month, a bill was passed by the Texas legislature and signed by Governor Perry that provides a legal basis for us to issue non-recourse storm cost recovery securitization bonds, similar to the three series of transition bonds we issued to recover stranded costs.

Storm costs recovery securitization bonds have the dual benefit of allowing us to recover our hurricane costs in a timely fashion and lowering the ultimate cost to consumers.

The legislation which also covers any future storms authorizes the Texas Public Utility Commission to review storm restoration policy and issue an appropriate financing order.

On April 17, we filed an application with the PUC detailing our storm restoration costs.

We requested recovery of $678 million which is composed of $608 million in system restoration costs and $70 million in regulatory expenses, certain debt issuance costs and carrying costs.

In the next two weeks, we expect to file an application for a financing order with the PUC to request permission to issue bonds to recover distribution system portion, estimated to be approximately $657 million.

We hope to complete the regulatory process and issue bonds late this summer.

We would recover the transmission portion, an estimated $21 million through our next transmission rate case.

This leads me to my second topic, our 2009 earnings guidance.

This morning in our earnings release, we announced that we reaffirmed our 2009 earnings guidance range of $1.05 to $1.15 per diluted share.

In providing our guidance, we considered various economic operational regulatory assumptions including recovery of costs associated with Hurricane Ike.

We have assumed normal weather in both the gas and electric utilities.

And we have not attempted to predict the effects of mark-to-market or inventory accounting on the earnings of our competitive natural gas sales and services businesses.

These effects are timing related and ultimately do not effect the economics of our underlying transactions.

In addition, we have excluded any impact to income from the change in value of Time-Warner stock and the related ZENS securities.

And we have assumed an effective tax rate of 39% for the full year.

At the year unfolds, we will continue to update you on these items as well as our earnings expectation.

Now I'd like to thank you for your interest in our company and I'll 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.

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

At this time, we will begin taking questions.

(Operator Instructions).

Thank you.

Our first question will come from the line of Danielle Seitz with Seitz Research Group.

Thank you.

I was wondering if you are looking at cost productions over in some of your businesses or should we look at the trend of operating cost as normal for the year?

Good morning, Danielle.

Hi.

I think I would necessarily try to take the first quarter and use that as a trend.

As you know, there's always noise in looking at just one quarter.

Sure.

We are trying to hold the line on expenses.

As you also know, I'm sure, about 60% of our costs are labor and benefits.

We don't have any significant changes planned there, but we absolutely are trying to control expenses where we can, delay expenditures that aren't absolutely necessary at this time, so we've got our eye on that ball.

Great.

Thanks.

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

Hi.

Could you give us an understanding of how much this conservation issue is bearing down on your numbers?

Is it most of the difference?

Is it a very small portion and how do you know that this is actually happening?

Good question, Lasan.

We're obviously focused on it.

As I said, about $18 million of revenues were lost from reduced usage.

Probably about $3 million or $4 million of that is related to our commercial and industrial class.

We've seen along the ship channel some cutback by our big industrial users.

And we have demand ratchets and over time that ratchets down a little.

The other say $13 million, $14 million is in fact the residential class.

We can explain part of that with weather, but not all of it with weather.

This winter, we had fewer HDD days, heating degree days.

But we say they're of a different quality because it was a very dry winter.

We had lots of space between cold days and we tend to not have as much heating load as a result of that.

I would say that at least half of it is conservation related and it could be a little bit more.

The first quarter is not a good time to be trying to draw any conclusions on the electric side because that's not our largest load time as you know.

Beginning late in the second quarter and then the third quarter are the times that we have our biggest electric sales.

That's what we're really focused on.

Our estimate for last year, 2008, was we saw about a 2% conservation impact in the residential area.

We had continued that we would see -- thought we would see some of that trend continue, but this was beyond our expectations so we're watching it closely.

I think it's too early to predict it to trend, but I think customers are conserving more than they had been.

Okay.

Just quickly on the continuous equity program, can you tell us why you want to do this as opposed to doing it in one shot?

Hi, Lasan.

Good morning.

This is Gary.

Good morning.

Just to remind you on the continuous offering program which is $150 million, as I said in last quarter's earnings call we think this is a tool that we've put in our tool box.

We've not issued to date.

But I want to remind you that we've raised approximately $30 million in the first quarter in equity around our savings plan -- our investor choice plan that we let you guys know about last year.

Lasan, I think our rationale remains the same in terms of the capital raise.

We think in terms of permanent financing, it's important to have the appropriate mix of debt and equity in our capital structure to execute our business plan.

We have a $1.1 billion capital plan reflecting, we think, some excellent projects with very solid returns.

Our financing plans for the accretive products include equity.

I think the question then is does a continuous offering program versus the marketed program.

We just think we reserve the right to do either, but certainly I think a continuous operating program is a tool in our tool box.

It's just a tool, but you aren't necessarily 100% committed to it?

What we're committed to is the capital structure that allows us to execute a business plan.

That's what we're really committed to.

Got you.

Thank you very much.

Thank you.

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

Good morning, everybody.

Good morning.

If I could start maybe just back on the conservation issue, lower usage per meter on both the LDC front and the electric front seem to be about 10%.

A little bit more than I think we had expected as well.

It's obviously too early to build that in.

The Summer is going to be the peak for the electric.

But can I ask you with respect to what you're using in your guidance range, what your expectations are for the rest of this year?

Let's take each one of them separately.

There's at least half of the electric residential conservation that we hadn't predicted for the first quarter, but we've taken that into account in reaffirming our guidance.

We're assuming that there will be a little conservation and weather will be normal, but we're not counting on 5% or 10% conservation, I'll assume you of that.

On the gas side, we expected a continuation of the trend that we had seen in the past which is about 2% a year reduction in residential usage.

I think the first quarter was a little bit more than that when you normalize it for weather, but not a huge amount different.

We're really right on I think our plan for the LDC.

As long as we continue to see this level, I think we'll be all right there.

Okay.

Appreciate the color there.

And then just a clarification here and understand there's a lot that goes into the guidance range as far as pluses and minuses, but just to make sure I'm on the same page.

When the pension deferral was noted that $29 million, is that relative to the $88 million that was talked about earlier in the year?

Or had the $88 million already excluded the $29 million that was going to be deferred?

No, the $88-million didn't.

You'd have to take the $29 million off the $88 million.

Okay, fair enough.

I'll jump back in queue.

Thank you.

Our next went will come from the line of Scott [Sinjack with Decade].

My question was about the pension, but just another thing -- can you just explain the precedence in the state for filing for a pension deferral again?

Back in 2005, there was a change to the Public Utility Regulatory Act which provided that utilities may set up a reserve for changes in pension expense from their last rate case or if it wasn't specified in the rate case, then the first year after a rate case.

We had our last rate case in 2006.

It was a settled case so we had no details.

And therefore, 2007 was the base year that we work off of so any changes from the base year, you can set up a reserve for and ask for a request.

In '08, it was actually a less than the amount in '07.

Obviously with this change, it's a big change and we decided, let's go back and just catch up for '08.

We did that in the first quarter of '09 and now we're deferring all of these dollars going forward until the next general rate case.

Okay.

Great.

Thank you very much.

Our next question will come from the line of Leon [Duval with Cattapult].

My questions have been answered.

Thank you.

Our next question will come from the line of Scott [Engstrom with Blinnhine Capital].

Question, the tax rate looked a little high to me in the quarter.

I wondered if that was due to the ZENS writedown or if you could just discuss that?

If you have changed your expectation for a tax rate on the year?

And then also maybe just a little reminder on some of the ZENS accounting issues, will the index security catch up with the writedown on the common or could you just talk about that for a second?

Okay, this is Gary.

In terms of the tax rate, we've previously indicated 37% to 38% rate for the full year.

Really the changes have been based on more knowledge around the unitary tax allocations.

Of course when you get through the previous tax year, you're able to understand those tax allocations or unitary tax allocations in the states that we do business.

In this quarter, we actually had a $4 million catch up related to the unitary tax allocation and the Texas margins tax as well.

Based on that, we looked at the rate going forward and in terms of providing guidance to you, we think 39% is more in line to use this year.

It's really driven by then the allocations related to unitary tax.

In terms of ZENS, the real driver there and again -- remind you of the ZENS security, this is our lowest cost debt in our capital structure.

It will be with us until 2029.

The accounting for it is really related to the Time-Warner shares and the evaluation of this derivative.

I wouldn't describe them as timing, but they move based on the mark-to-market if you will of the Time-Warner shares will depend on the value of the Time-Warner stocks.

There are two of those stocks, maybe three, if they spin off AOL at some point.

I think you need to exclude those.

They're non-operational.

They will move and certainly could come back and frankly be favorable for the year, but I think it's best to exclude them.

They don't really impact the economic -- when you look at ZENS from an economic perspective at least.

And if you go back and look at the history, some years there's a small loss.

Some years there's a small gain.

I think Time-Warner stock has been under a lot of pressure and it got pretty low.

And it got a little bit disconnected to the opposite direction of where the derivative was going.

Hopefully this will get back in line in the future, but I think it's really hard to tell around just what's going to happen to these Time-Warner stocks.

You're saying based on history, there's a decent chance that they will move back, but there's nothing that guarantees they would be moved back more in line?

That's correct.

And you're saying the tax rate in this quarter, there is a $4 million catch up from '08, is that what you were saying?

There's a $4 million, as you know, as you go through the determination of unitary tax, you really need to know the revenue in each of those jurisdictions.

And yes, there's a $4 million -- you could call it a catch up, but an adjustment to insure that we have those allocations correct.

Okay.

And therefore, going forward that's why I've guided you to for this year, using a 39% tax rate.

Look, certainly we're going to try and improve upon that as we do the best tax management we possibly can, of course, but that's where we are at the moment.

And then just last follow-up on that.

All other things being equal then, you would expect the tax rate to be lower in 2010 versus '09 based on this unitary tax catch up?

Yes, I would hope, yes.

I think the short answer is yes, because you would expect to come back in line with a normalized rate which is, to remind you, is your corporate income tax rate plus the tax rate in the various states in which we do business.

And of course, Scott, as you know, that's subject to change, depending on the amount of business we do in each state.

Right.

Thanks very much guys.

Appreciate it.

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

Good morning, guys.

Good morning.

On the Carthage to Perryville expansion, the Phase IV, 80% is signed up with Chesapeake.

Right.

Given that's the expansion, do you just roll those volumes until your current rates and then what would that mean for the return on capital for that project?

What we do is -- those are negotiated contracts so it's really whatever the market will bear more than anything.

I think our max rate on our system is $0.25, but these are negotiated rates and the cost of that Phase IV expansion is about $80 million.

We spent a little bit in '08.

I think we'll spend a little less than $60 million this year, but it's a good solid project to get almost 275 million of additional capacity.

Is it fair to say the return on expansion will be better than the initial buildout of the pipeline?

Yes, I think that's right.

I'd have to double check, but instinctively I feel like that's right.

Okay.

From your comments on the electric side of the equation, on the T& D business, it is fair to say that -- given that most of your demand is in the summer that during the summer, the demand is fairly in-elastic to cooling degree days versus in the winter where it's more of a heating degree day driven phenomenon which is a little bit flexible for demand?

Once it reaches a given temperature and a given humidity, I think you're right.

It doesn't matter what the cooling degrees days are.

Once it's 95 and 95% humidity, I think the air conditioners stay on.

Like in the wintertime in Minnesota, once it gets cold, heaters don't go off that much, but there is some demand elasticity.

Last summer, we saw -- when electric rates spiked because of natural gas prices were up so high, they were $0.15 to $0.17 a kilowatt hour, we thought we detected some conservation on the part of our customers which was truly response from these higher electric rates.

Electric rates have since gone down significantly.

Today they are probably more $0.12 range so you can see they've declined a lot.

And I think that will also have some impact this coming summer.

Okay.

Understood.

Thanks for the time.

Our next went will come from the line of Steve [Gambuzza] with Longbow Capital.

Good morning.

Good morning.

The operating profit that you generated in field services quarter, would you expect that to be a reasonable quarterly run rate for the year or do you expect performance to deviate substantially one way or the other?

Field services is pretty consistent from quarter to quarter, unless you have significant changes in liquids prices or commodity prices.

It's not a -- I don't think it's a bad run rate.

I don't think you necessarily -- we use that as a guide but it's not a bad rate.

It's pretty consistent quarter to quarter.

At least the fee-based portion of your business should be running at around that quarterly run rate?

There's no sharp acceleration or fall off in the back half of the year?

No.

Other than we continue to add volumes to our system and as we add volumes, you have some increase in your fee-based revenues.

We have certainly seen increases in fee-based revenues since last year.

It's gradual over the year as these wells come on.

I expect we'll continue to see some increase in fee-based revenues this year, because we've got a lot of new projects we're working on.

What was the capital spending in fuel services in the quarter?

Just a second and we'll get it.

Perhaps while you're looking for that just any comments -- I think you said last call or in the end of '08 that you expect 2009 would shape up to be a very strong year in field services, but there was a tremendous amount of uncertainty around 2010.

I'm just curious if you have gotten anymore color as to your view of the market and how it might develop in 2010?

Okay, the CapEx was about $38 million in the first quarter.

2009, we've got four or five very large projects.

We have the largest capital program that we've had since I've been around here, almost $270 million in field services, really related to these big projects in the shale areas.

Those are very attractive projects for us.

And as long -- and we stay in very, very close contact as you'd expect with producers because we're basically following the producers.

When they have wells that are ready to go to market, we got to be there with them.

But if they slowdown, we slowdown.

So far, we think we're going to spend on the order of that $270 million.

It could be a little less if some of the well drilling slows down.

As we look out to 2010, it's a little bit harder but we see a lot of activity in these shale areas and that's where we think we'll continue to get new projects.

I think we've got something like $140 million of projected capital expenditures in 2010.

You can see we're a lot less than we were in '09 and it's because we're completing some of these larger projects.

Okay.

Thank you.

The SESH results for the quarter where you had basically an operating -- if you strip out the charge, the profit was around $3 million.

Right.

Is that the run rate we should expect for SESH?

I hope not.

We don't think so.

That rate, as you know, there's probably 20% of that Bcf of day capacity that is not getting a demand capacity payment for this year.

Because it phases in over the first one or two years, three years.

We had expected that we were going to be able to sell quite a bit of that on an interruptible basis or a short-term firm.

But the Florida Markets, demand is down over there and there's lots of gas coming into that area.

I think the basis has been really squeezed and we just don't see as much activity there yet.

If you have a good, hot summer, things could change a lot.

I don't think I would guide you to using the first quarter as a trend line.

We'll just have to wait and see how this year unfolds.

Can we say that at a minimum, it should be that and if you're able to market some excess capacity you'll do better?

I would hope that at a minimum, it's at least that and yes.

Okay.

Is the project finance or the SESH financing that you discussed in the past, can you talk about the status of that?

Yes.

Gary is going to take that.

If you look at that -- obviously this project's fairly new into service and we're working with Spectra, Steve, at the moment.

As you know, those markets have been a bit choppy, I'll call it the project finance markets although stabilizing a bit.

We're still in the process of evaluating that, both the need to do the financing and when to do it and what the rates would look like, and really sitting down with our partner and talking that through.

No news at the moment on that one.

And finally, the deferral of pension expense for Houston Electric, was that part of your original guidance?

Or is that something you've elected to do subsequent to issuing guidance?

I think when we say it's part of our original guidance and again we had a range.

We were certainly at the time looking into what we could defer so we had some expectation, but we don't -- there are moving parts in that guidance.

I would say a portion of it certainly was in the guidance, but perhaps not all of it.

But the way to think about it is you identified when you reported Q4 what you expected the total pension expense to be the increase.

And now there's some portion of that total increase -- the total increase hasn't changed.

It's just that there's some portion of that you can defer?

No, that's exactly right.

If you'll recall, what we said at the time -- and by the way, we're still working hard on our gas jurisdictions in terms of deferral there as well.

What we said is we wanted to be conservative so we gave you the outward number, I believe it was $88 million is now $59 million based on the amount that we're able to defer.

We're going to continue to work on the gas side of this as well, so we want to be conservative when we gave you that guidance.

The equity increase in the quarter was around $30 million?

Around $30 million.

That's correct, mainly driven by our savings plan.

Should we think about that as -- my understanding was your total equity plan for the year was $150 million.

Should we think of that as going towards that amount or would this be incremental to the $150 million that you intended to achieve through a drip issuance?

I think -- we said really two things in terms of -- not to repeat myself on our overall objectives for our capital structure to support our business plan, but they were additive to each other.

In other words, we have two obviously you could do a marketed transaction.

We could do the continuous offering in our tool box, but it's additive in terms of our benefit programs.

But you can't -- don't take the $30 million and extrapolate that each quarter because it depends on when those or how those plans are funded at certain times.

This was mainly the savings plan in this quarter.

I was taking it as you put out a CapEx forecast for '09 and based on that CapEx forecast, you had a certain external financing requirement.

And that external financing requirement included around $150 million of equity.

It includes $150 million of equity and it includes also the equity we raised normally through our benefit plans.

Thank you very much for your time.

You bet, Steve.

Our next question will come from the line of Debra Bromberg with Jefferies.

Good morning.

Good morning.

The O& M at the electric company looks like it increased about $20 million in the quarter.

But I think you said that pension was about $5 million of that so I was just wondering what the key drivers were for the other $15 million.

Then also just as a follow-up on the pension, I think last quarter I'd asked about how much of the $88 million of higher pension expense was expected at the electric company and you had estimated about $41 million.

It sounds like that amount is lower now as you take the $29 million deferral and the $5 million that you booked in the quarter, it looks like it's closer to $34 million.

I just want to make sure I'm not missing something on that.

The numbers you quoted are correct.

The latest numbers are I think a refinement of the earlier numbers.

Because now we're expecting to do $29 million and we expensed $5 million.

But as you know, we had a catch up from '08 when we made this election so that's the difference between the $41million and the $35 million.

I think and there's a whole bunch of nickels and dimes, but I think transmission cost is the biggest.

It's almost $9 million of that and that's a big part of the increase.

Besides the pension, there's a bunch of just small things and nothing else jumps off the page at you.

Is the higher transmission cost within expectations because I know you recover some of that rate.

It's pretty close.

We have to estimate what the key cost matrix is for the year which gives us how much others will bill to us and so it's close.

It's a little bit higher than we thought, but it's pretty close.

Okay.

Thank you.

Our next question will come from the line of Mark Rogers with Gagnon Securities.

Thank you.

My question is regarding your smart meter rollout.

I was just wondering how you have modified your schedule, either decelerated or accelerated the schedule since you've decided to go with smart meters?

And then I have a follow-up.

The schedule we're on today is the schedule we got agreement with all of the parties to our case last fall and it's one the PUC approved.

It's not any different.

We're going to roll this thing out over five years.

This year it will be 145,000 and then ratably after that.

I think that we're really on schedule with what we said we're going to do.

Okay.

As uncertainty seems to loom over this space regarding technology standards and communication protocols, I was wondering if the argument with the standards committee evolves into deciding one technology or platform is simply better or is worthy of stimulus dollars over another, what is the flexibility that you have in going back to your vendors, asking them if they have a compliant technology platform and if they don't canceling that contract?

There's probably a lot in there that I can't answer, but we've pushed for open architecture of all these systems so we can have interchangeable vendors.

There are going to be -- and we're using the communication protocols that lots of other folks are looking at and using.

There is a lot of discussion around trying to standardize more around this.

We know that and we're following it closely and we're part of those discussions.

But I don't think there's anything there that is going to impact our rollout that we've seen anyway.

Okay, and then if I may just one quick follow-up.

If you could define some of your major use cases that you're hoping the initial 10,000 or if you will 140,000 by year-end smart meters have proven out, what would those be?

I'm not sure --

In other words, what are your smart meters trying to achieve?

They are going to be fully two way communicable.

We're going to automatically read all these 145,000.

We're going to take 15 minute interval readings and those readings are going to be available through a portal, through retail energy providers so they can provide time of day rates.

And they can start -- we can start seeing exactly how customers will respond.

We're going to provide small little devices in homes that can be communicated with by the meter that can keep track of usage and part of the home area network.

There's lots of things on that front.

We're providing -- we're facilitating all of this.

There's going to be other parties that have to participate as well.

As you know, we don't sell electricity, we deliver electricity.

Somebody else is going to have to provide the time of use rates, but we're going to make all of the data available so that they can do it and customers can take advantage of it.

Great.

Thank you.

Our next question will come from the line of Amit [Sakiar] with Deutsche Bank.

My questions have been asked and answered.

Thank you.

Thank you.

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

Appreciate the time guys.

Just two very quick ones on SESH.

Gary, you just -- wasn't sure if you were going this way or not, but just on the project financing side.

Without the short-term capacity being sold just yet, is the project financing really more a matter of what the bond market rates are doing or is it really more getting that capacity sold?

No.

I think it's really both, Carl.

I think clearly, the market although a bit better, I think is really the optimum financing sector.

I think we have to make that determination.

I think it's a combination of the two.

Clearly, we need to have -- if we're going to sell bonds, we need to have probably a bit more clarity as to what the profitability will be, both in the near term and more importantly the longer term depending on the tender of the bonds.

I think that's certainly a variable.

I think certainly the market is improving in our ability to go to market.

I think they're connected to each other and that's the work we're doing now with our partner at Spectra.

Fair enough and then just a quick clarification.

The equity earnings that are reported and discussed, are those pre-tax or is that after-tax?

Just trying to figure out where that's --

That's pre-tax.

Great.

Thanks guys.

(Operator Instructions).

Thank you for your cooperation.

Our final question will come from the line of Paul [Patterson with Glenrock] Associates.

Can you hear me?

Yes.

Now we can, Paul.

Okay.

Just want to revisit the pension.

You deferred $29 million, is that correct?

No, not yet.

We expect as we go throughout this year, that's what would have been expensed and now we will be able to defer it and ask for recovery in a future rate case.

Okay.

On the -- you said you might do this on the natural gas side as well?

We're working hard with our regulators and with other legislators to see if we can get something going on this front.

We have a little bit of that already when we have automatic cost adjustment clauses, where if we have an increase in pension in a given year we get to increase or reflect that in our rates the following year.

But in our biggest jurisdictions which are in Texas and Minnesota, we don't have those kind of features.

We're looking to try to work something on that front and see if we can get a similar treatment.

It would appear to me if the electric utilities in Texas can do it, why can't the gas utilities.

And that's what we're talking to regulators about.

I think in Minnesota, we're right in the middle of a rate case and we're going to be able to make sure they are fully aware of the increased costs there and hopefully get those reflected in our base rate so once the new rates are set.

Okay.

Thank you very much.

Okay.

Thank you very much, Paul.

Okay.

Thank you very much, everyone.

I would like to thank you for participating on our call today.

We appreciate your support very much.

Have a great day.

Ladies and gentlemen, this concludes CentralPoint Energy's first quarter 2009 earnings conference call.

Thank you for your participation.