CenterPoint Energy Inc (CNP) 2006 Q2 法說會逐字稿

Good morning and welcome to CenterPoint Energy's second quarter 2006 earnings conference call with senior Management.

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

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

To ask a question, please press star one on your touch tone keypad.

To withdraw your question, press star two.

I will now turn call over to Marianne Paulsen, Director of Investor Relations.

Ms. Paulsen?

Thank you very much, Luanne(ph).

Good morning, everyone.

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

I'd like to welcome you to our second quarter 2006 earnings conference call.

Thank you for joining us today.

David McClanahan, President and CEO and Gary Whitlock, Executive Vice President and Chief Financial Officer, will discuss our second quarter 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 our prepared remarks.

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

I would like to remind you that any projections or forward-looking statement 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 Thursday, August 10, 2006.

To access the replay, please call 1-800-642-1687 or 706-645 -9291 and enter the conference ID Number 2870044.

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

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

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

David?

Thank you, Marianne.

Good morning, ladies and gentlemen.

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

For the last six months or so, a number of analysts who follow the Company have commented on the overhang associated with two issues facing CenterPoint.

The ZENS tax issue and Houston Electric's rate review.

I'm very pleased to report that we have entered into settlements that we believe will resolve both of these issues.

Last month, we announced an agreement with the Internal Revenue Service that will resolve the tax treatment of the Company's ZENS securities.

As a result of this settlement, which is subject to approval by the joint committee on taxation of the U.S.

Congress, we reduced our previously accrued tax and related interest reserves by $119 million, adding $0.38 per diluted share to second quarter earnings.

This settlement resolves the tax deductions related to these securities through their maturity date which should eliminate any future tax concerns.

Gary will explain this settlement in a little more detail in a few minutes.

Earlier this week, we filed a stipulation and agreement with the Public Utility Commission of Texas that would resolve Houston Electric's pending rate case.

Under the terms of this settlement, Houston Electric will reduce it's base rate revenues by $58 million per year.

We also agreed to increase our spending on energy efficiency programs by $10 million per year bringing our total annual expenditures for these programs to $23 million.

In addition, we will fund $10 million annually for programs providing financial assistance to qualified low income customers in our service territory.

One of the most important aspects of the settlement is that it provides for a four year rate freeze.

During this freeze, we will be permitted to seek limited rate changes related to third party transmission costs, as well as any tariff changes related to the recovery of the stranded cost trueup amounts, our commission initiatives such as system hardening and advanced metering.

The obvious benefit of this freeze is that it provides for rate certainty and stability through the end of this decade, and allows us to focus on running one of the best pure T&D utilities in America.

As part of this settlement, we also resolved a pending matter at the PUC with respect to the remand of the 2001 unbundled cost of service proceeding.

This proceeding involved the establishment of Houston Electric's initial energy delivery rate in the Texas restructured Electric market.

As part of the process, we were permitted to use a forward-looking test year as opposed to the typical historical test year.

The order issued by the Commission in this case was appealed by a number of parties and the Court remanded the case back to the PUC to resolve an issue related to several forward-looking transmission projects with a rate base impact of $57 million.

Recently, the Commission ordered it's staff to calculate the impact of simply removing these costs from rate base, retroactive to January 2002 when the new cost rates went into effect.

While we were surprised and disappointed with the Commission 's treatment of this issue on remand, we decided to put this issue behind us as part of an overall settlement.

We agreed to provide an $8 million a year credit for four years and took a $32 million pretax charge to second quarter earnings.

The PUC will have to approve all aspects of this settlement which we expect to occur later this year.

We're looking forward to getting this in place and focusing on Houston Electric's future.

Now let me turn to our second quarter earnings.

This morning we reported net income for the second quarter of 2006 of $194 million or $0.61 per diluted share.

This compares to net income of $54 million or $0.16 per diluted share for the same period last year.

As I indicated earlier, our 2006 results include the impacts from the resolution above the ZENS tax issue and Houston Electric's 2001 new cost remand.

The resolution of the ZENS issue resulted in a positive $0.38 per diluted share impact while the settlement of the 2001 new cost remand had a negative $0.07 per share impact.

Without the impact from these two settlements, earnings would have been $0.30 per diluted share.

Now I'd like to briefly describe the performance of our businesses.

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

Despite the impact of the 2001 new cost remand settlement , Houston Electric had a solid second quarter.

Favorable weather, continued strong customer growth of nearly 60,000 since June of last year and lower expenses produced a very good quarter.

Our pipeline and field services segment continued it's trend of strong quarterly performances.

Our field services business benefited from strong drilling activities in the mid continent area and our Interstate Pipelines enjoyed increased demands for both cross system transportation and ancillary services, especially it's park and loan service.

These activities are driven in large part by high natural gas prices and significant basis and inter-month natural gas price differentials.

Our competitive natural gas business also had a very good quarter.

This performance was somewhat masked by a writedown of our natural gas inventory due to a decline in gas prices at the end of the second quarter.

I'd like to point out that we recorded this writedown to current market prices based on further decline in natural gas prices since the first quarter.

We had a small writedown in the first quarter as well.

However, since we have hedged future sales for the periods when we expect this inventory to be delivered, we should realize an increase in operating income in those future periods.

This business continues to benefit from gas price volatility and wide basis differentials.

The only business segment that had disappointing results was our natural gas distribution business.

Decreased customer usage, the impacts of high natural gas prices, and some unusual expenses produced a quarter that was less than last year.

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

I think it's also worth noting that we have incurred a substantial amount of restructuring cost in the first half of this year designed to improve the long term operating performance of this business.

Overall, I believe the Company had a solid second quarter and the strength of our geographic regulatory and business diversity was clearly evident.

For those of you that have followed the Company for some time, I believe you would agree that we have revolved the key issues that face the Company from it's inception.

We've exited the generation business, recovered a substantial amount of our stranded cost, paid down debt, and resolved a number of legacy issues like the ZENS taxes.

We're now fully focused on the future and building value for our shareholders.

I continue to be excited about opportunities that will provide both significant growth potential for our business as well as improvements in the way we operate these businesses.

We have several growth opportunities in our pipeline and field services group driven in large part by the current natural gas market dynamics.

These growth opportunities have the potential to push this segment's earnings to a new level.

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

The first phase of this pipeline is expected to be in service in the first quarter of next year pending approvals by the FERC later this year.

We expect a second phase to be placed in service mid next year bringing the capacity to about 1.275 billion cubic feet per day.

Based on strong interest for a third phase of this project, we plan to expand this project to 1.5 billion cubic feet per day through the installation of additional compression which we expect to be in service by the end of next year subject to the receipt of FERC approvals.

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

Last November, subsidiaries of CenterPoint Energy and Duke Energy signed a Memorandum of Understanding to evaluate market and develop a potential new Southeast pipeline connecting our Perryville hub to Duke's partially owned Gulf stream natural gas system.

We continue to work with a number of potential shippers and believe we are close to signing an anchor shipper for the pipeline.

We remain very optimistic about the ultimate prospects for this project.

The current design capacity is 1 billion cubic feet per day with a scheduled in service date of mid-2008.

In June we announced another joint project with Duke called the Mid Continent Crossing designed to provide the Northeast to Midwest and Southeast markets, access to abundant supplies of natural gas located in the producing basins of the mid continent, Rockies and West Texas.

This project is in the early stages of development with an extended open season that ended earlier this week.

There are a number of companies contemplating projects similar to ours and it's still too early to know the final scope of our project or which project will ultimately be built, but we remain optimistic about the Mid Continent Crossing and are actively pursuing this project along with Duke.

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

The dividend is payable on September 8th to shareholders of record as of August 16.

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

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

Now I'll turn the call over to Gary.

Thank you, David and good morning to everyone.

I'd like to discuss a number of items with you this morning.

Let me start with a review of the impact of the ZENS settlement, not only to earnings this quarter but going forward as well.

As we described in our press release this morning, and in the Form 8-K we filed on July 20th, we have reached an agreement with the IRS on the terms of a settlement regarding the tax treatment of the ZENS and our former ACES securities.

In addition, we signed a closing agreement for the tax years 1999 through 2029 with respect to the ZENS.

These agreements are subject to approval by the joint committee on taxation which we are hopeful will occur by year-end.

As a result of these agreements, we have reduced our previously accrued tax and related interest reserves by by $119 million or $0.38 per diluted share.

In addition, we will make payments totaling $64 million for previously accrued taxes associated with ACES and ZENS and we will reduce the level of our future interest deductions associated with the ZENS securities.

Many of you have asked us how should we think of ZENS going forward?

As you know, we have been adding to the tax reserves since late 2004.

This agreement now eliminates the need for any future tax reserves related to the ZENS issue; therefore there is no ongoing impact to earnings.

Second, we have consistently stated that the ZENS securities will remain a part of our capital structure as long as they are beneficial to our company.

These agreements now clarify the ongoing tax treatment of the securities which will allow the Company to benefit from current tax deductions although in a reduced amount.

Obviously, we are pleased to resolve this very complicated legacy tax issue.

Next, I'd like to address our effective tax rate for the second quarter of 2006 and future periods.

The large reversal of the ZENS tax reserve combined with the settlement of a number of other tax issues totaling about about $21 million has skewed the second quarter 2006 tax rate.

For future periods the effective tax rate should return to approximately 36%.

Now I'd like to elaborate a bit more on the Houston Electric rate case settlement.

As Dave had mentioned, this past Monday we filed with the Texas PUC a stipulation and agreement that would settle the Houston Electric rate case and our 2001 new cost remand with all 20 parties.

The ALJ's will now set a procedural schedule after which we would expect the stipulation and agreement to be approved the Commission with rates going into effect shortly thereafter.

The UCOS impact is a pretax $32 million revenue reduction recorded in the second quarter.

From a rate implementation and cash flow standpoint, this reduction will occur through retail and wholesale delivery rate credits of approximately $8 million a year until $32 million is credited.

With respect to the rate case, base rates will be adjusted to reduce base revenues by approximately $58 million annually shortly after the new rates are approved the Commission.

The energy efficiency and low income programs that David mentioned will also begin to be funded at the same time.

This is a black box settlement addressing revenue requirement reductions only.

There are no changes in depreciation rates, storm reserve accruals nor is there a stated ROE or capital structure included in the agreement.

However, the settlement allows us to amortize $4 million per year over seven years for Hurricane Rita expenses and an estimated $2 million per year over four years for rate case expenses.

The key component to this settlement is that base rates will be frozen at the new level through June 30, 2010.

At the same time, at that time, the freeze ends.

The TDU can file a rate case at any time thereafter and must file a rate case using a test year ended December 31, 2009, unless representative of the PU staff, PUC staff in our key city determine that such a filing is unnecessary.

During the freeze period the TDU maintains the ability to participate in and receive the benefits if any of PUC recovery mechanisms which may occur in advance metering or system hardening rules.

With the rate stability and certainty provided by this settlement, we will be working hard to capture operational efficiencies and implement process improvements.

These efforts along with the growth in our service area should provide us with an opportunity to achieve a fair return for our investors.

Another regulatory issue I'd like to discuss with you is the impact of the PUC's decision to change the rate of return used on the competition transition charge or CTC which at the end of June 2006 had a balance of $577 million.

The Commission has modified it's rule to provide for a lower rate than the 11.075% authorized when the CTC was implemented.

Under the revised rule, the rate has been reduced to 8.06% effective August 1.

The earnings impact for the remainder of 2006 is expected to be approximately $5 million or $0.02 per diluted share.

The earnings impact for the full year 2007 would be approximately $12 million or $0.04 per diluted share.

However, we continue to believe that the ultimate securitization of the CTC is in the best interest of all our customers.

Now let me discuss our financial priorities following the resolution of the legacy issues we discussed today.

Our full attention is focused on improving and growing the profitability of our businesses while at the same time adhering to the financial discipline necessary to maintain and improve our credit metrics.

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

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

If permanent financing becomes necessary, we will consider the optimum mix of debt and equity, and we remain committed to take the steps necessary to maintain and enhance the credit metrics and credit ratings of both the parent company and our utility subsidiaries.

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

We expect 2006 diluted earnings per share to be in the range of $0.90 to $1.

Let me point out that our guidance includes an estimated impact of the TDU's rate settlement and the CTC rate change but excludes the one-time impacts related to the resolution of ZENS and the UCOS case.

Furthermore, as I mentioned earlier, there is no ongoing earnings impact from these latter two issues.

Finally, in considering our earnings estimate for the year, we made certain the economic and operational assumptions including the outcome of various other regulatory proceedings at our LDC.

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

Thank you very much, Gary.

Before we take your questions, I'd like to point out that the residential customer number for the second quarter of 2006 had two transposed numbers.

The correct number is 1 million, 730 thousand ,130 for 3% growth, instead of 1 million, 703 thousand, 130 for 2% growth.

The Form 10-Q that we filed this morning does include the correct number.

And with that, we'd now like to take your questions.

In the interest of time, I'd ask you to please limit yourself to one question and a follow-up.

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

Certainly, ma'am. [OPERATOR INSTRUCTIONS] Your first question comes from Lasan Johong with RBC Capital.

Good morning.

Great quarter.

Gary or David, I'm a little puzzled on the guidance of $0.09 to $1.

To date it looks like CenterPoint achieved about $0.58 in earnings, and yet given the third and fourth quarters are, I think, supposed to be the higher quarters, I don't understand how you end up with a year at $0.90 even with the rate reduction and the reduced CTC rates.

Can you kind of walk me through how you get to 90 cents or $1?

Sure.

We're not going to give any particulars there, Lasan, but third quarter is a good quarter obviously for our electric business, but it's generally a very weak quarter for our LDCs.

It's typically that the second best quarter of the year overall, and the fourth quarter usually not a great quarter in terms of earnings for our TDU, so we hope that we're being conservative here.

We've had a, unlike the rest of the country a very mild July weather.

Almost all the country is under a heat wave, we're not, and we factored that into our guidance as well.

So we feel comfortable with the $0.90 to $1 but third and fourth quarter aren't the best quarters, the first quarter of the year typically is the highest earnings quarter for us.

I'm sorry.

Did you say Houston is not going through a heat wave?

No, it's not.

Our estimates is July has been below normal, because we've had a lot of rain down in Southeast Texas, unlike the rest of the country, so July is going to be a little milder than normal.

We don't have a real good estimate there but it's 5 million plus off of normal weather.

So we could make that up easily in August, September, those are very strong and hot months, but we just have to wait and see.

We're predicting, for our purposes of our guidance, beyond July that we're going to have normal weather, but we'll just have to wait and see.

Okay.

And then on the $8 million of refunds based on the UCOS, did you say that starts as of Jan 1, '07?

No.

That will start as soon as the settlement is approved, but it will have no earnings impact.

We've taken the full earnings impact already, Lasan, it's just going to be a cash flow.

I know.

Okay.

And then the Katrina and the rate case cost was 4 million and 2 million to be recovered over four years you said?

Seven years for Rita and four years for rate case.

Okay, great.

I've got a few more questions but I'll do follow-up.

Thank you.

Thanks.

Your next question comes from Daniele Seitz with Dahlman Rose.

Good morning.

Just was wondering if you could remind us of the topics numbers regarding each of the pipeline projects and also per year, if possible?

Our Carthage to Perryville pipeline, that project, based on it's expanded nature is going to to be 450 million plus or minus a few million.

I don't recall the exact number but it's pretty close to that.

It's now, as I said earlier, planned to to be 1.5 billion cubic feet per day, so we've expanded that project quite a bit since we started just based on demand.

Our Southeast supply header now planned at a billion cubic feet per day design capacity, we started out at less design capacity than that.

We are estimating it's going to be between 650 and $700 million of total capital there, but those numbers tend to move around a lot.

We're seeing some increases in pipe costs and we've had to make some adjustments to our inter connect assumptions.

We're going to inter connect with some 12 other pipelines along the way and some of those costs have increased a little bit.

The mid-continent crossing, I'm not going to -- I don't think we're prepared to make an estimate now because the scope of that project could be any various links of pipe.

It could be as probably as short, not that this is short, as 6, 700 miles to 1,800 miles so it's really hard at this stage until we get a better handle on really the demand that each leg of the way, so I would be reluctant to make an estimate this early.

That project, as you know, it's several years down years down the road before it comes into service but as soon as we get a better handle on the scope we'll certainly provide an estimate of capital cost.

And the reorganization of FERC, is that absolutely, I mean crucial for the timing I'm assuming those units come on line?

Yes.

It absolutely is, Daniel.

We're assuming we're going to get FERC approval this fall.

There is no indication otherwise.

I think that project has been moved along expeditiously through the FERC staff and we're very hopeful there.

Now, we have a short construction cycle.

We've got -- it's going to take only four or five months to build based on the number of contractors we're using, but certainly, FERC approval is key into getting the thing in service by the first quarter of next year, and the same on the additional compression that we're going to add to expand capacity.

That's key to getting that capacity in service by the end of next year.

Just one quick question.

On the gas and LDC, have you seen any elasticity in demand recently?

We're seeing some, certainly some response to high natural gas prices.

It's not perhaps as high as some areas of the country, but certainly what we've seen historically is declining usage about 1% per year just based on improved appliance efficiencies, house envelopes, stuff like that, but we're seeing a little bit more than that of late.

Part of that, we believe, is the result of really all the advertising and public notices we did last year about high natural gas prices and the impact on customers bills.

The real issue with our gas LDC's really is a combination of weather and natural gas prices.

Year-to-date, we estimate that weather, against normal weather, it's been over a $20 million impact.

We've had over -- we've had about 6, $7 million worth of impact in bad debt expenses, so just weather and bad debt is almost $30 million, plus we've had about about $11 million worth of restructuring charges which are going to reap benefits in the future and we wrote off some rate case expenses instead of amortizing them was $3 million so that's about 40 plus million dollars that are unusual this year.

Right.

Thank you very much.

Your next question comes from John Kiani with Deutsche Bank.

Good morning, John.

Just a few questions on the southeast supply header and mid continent crossing pipeline projects.

Can you provide a little more color on the potential timing of an anchor shipper contract for the Southeast supply header?

I think we hope to have that certainly solidified some time this summer.

Okay, great.

And then, what about any additional comments on the mid continent potential project after the Monday conclusion of the open season?

As you would expect, just because the open season ends doesn't mean your conversations with potential shipper ends, and so we're still talking with a number of parties and we are just trying to assess just what should the scope of this project be, and you do that based on really what shippers are willing to sign up for and the length of the contracts they are willing to execute, so I think it's too early to tell.

There's clearly, there's three other projects besides ours that are trying to move this same gas.

What we do believe is that there needs to be more pipeline capacity to take that, the gas and all of these areas of Texas and Oklahoma to market.

You've got the Barnett Shale, you've got the Wolford Shale, you've got the Fayette(ph) Shale, you've got Boser Sands, there's just a lot more gas there than I think we thought even a couple years ago, so all that gas has to get to market besides the gas out in Permian(ph) Basin and the Rockies, and I think there needs to be additional pipeline capacity.

We're just trying to work to make sure we get a chance to build it.

Great and that makes a lot of sense and one more quick question.

Can you please go through the timing of roughly when you'll realize the incremental $17 million or it looks like it was about $0.05 a share from the inventory writedown?

Just through the remainder of this year?

Well, some of that might come about early next year, January or February, although we certainly will see some of it turn around later this year.

Some of it will carryover and some of it will be in this year.

Okay, great.

Thank you very much.

Your next question comes from Steven Gambuzza with Longbow Capital.

Good morning.

In your comments, you mentioned that securitization of the remaining CTC balance would be in the best interest of your customers.

I was just wondering if you could comment on the potential timing of that, how you'd go about seeking approval to securitize that balance and if you might wait until your current appeals process is over on the existing or the other stranded costs related issues that are currently pending?

Well, you might recall, we had thought that this should be securitized from inception.

We argued that and the Commission determined that the current law does not provide for securitization of these type of costs.

So it would take a change in the statute or a settlement of perhaps the overall outstanding issues to get this securitized.

So it would be some time next year certainly if legislation would be passed, the Texas legislature goes into service, not service, goes into convene, goes into session, thank you, Scott, next January and so it would be some time certainly probably mid year before this could get done at the earliest.

And if the appeals court, if you're ultimately successful in recovering the amounts that the District Court in Texas says you're entitled to, do those or does that amount qualify for securitization or would that also be -- would that kind of fall in the same bucket as the existing CTC?

It's a mix.

Some of that definitely would qualify for securitization and some wouldn't.

What we would hope and what we continue to hope is through an agreement of the parties, we'll get to securitized a lot more rather than less.

Okay, thank you very much.

Your next question comes from Faisel Khan with Citigroup.

Good afternoon.

Hi, how are you doing, Faisel?

All right.

Just a follow-up on John's question on the storage, the $17 million reflected writedown of the inventory, is that just a mark to market charge in the quarter?

Is that what it is?

Well, it's not a mark to market from an accounting standpoint.

We buy inventory.

We buy gas, put it in inventory to satisfy forward contracts.

Sure.

And under accounting rules and it just so happened that at the end of June, gas dipped below $6, like $5.60 for a matter of a few days.

Well, today it's back up to almost 8 bucks, but we had to write down the gas we had in inventory to $5 and some cents.

$5.70.

%5.70, so, it's not a mark to market but it's just a writedown and when that gas comes out inventory and we're going to sell it later this fall and early in the winter, we'll basically realize a higher margin than we otherwise would because we've written it off.

Got you..

Okay.

And then on the -- I'm getting to a really low effective income tax rate on, when I take out the one-time items.

Is there something I'm missing here, I have like a 13% effective income tax rate for the quarter when I take out all of the one-time items.

As I mentioned, the one-time items you need to take out of course is the ZENS.

And, we also, in my comments I disclosed, we also had had $21 million of other items that you would need to take out as well, Faisel.

Okay.

I think the more important thing to look at is on a go forward basis, with this noise out of the system around ZENS, and obviously resolution of other issues, you're looking at a tax rate that returns to a normal rate of about 36%.

Okay, but if I take out the one-time items you talked about what should my effective tax rate be for the quarter on an adjusted basis?

Probably about 31%.

Sort of that range.

There's a little bit of noise in there, but again, Faisel, I think the more important thing is looking at the tax rate going forward because we really relieved the Company of these obviously number of issues.

Oh, no, I understand that.

I was trying to get to an adjusted number for the quarter.

I think the main one you take out the 21 million I mentioned and the ZENS, it's the best way to do it ,and then there's some swings and round abouts in there, but it's a little more -- I think you'll get a little more than 30%.

Okay, I Got you..

And then on the Perryville to Carthage pipeline, you increased that capacity to one half BCF a day.

Do you have incremental firm storage committments on that increased amount?

We don't have storage committments.

Sorry, transportation.

Yes.

We're working with a series -- we held an open season for that incremental capacity.

We received a significant amount of interest and we're in the process now of sending out precedent agreements to sign that capacity up.

Okay.

And then just one more question on the order that came back from the PUCT on the CTC formula.

Is that something that you would still think about appealing in terms of how they got to that formula?

I think the appeals date passed last week.

Okay.

Fair enough.

Thank you for your time.

Okay.

Your next question comes from Debra Bromberg with Jeffries & Company.

Hi, good afternoon.

Hi, how you doing, Debra?

Most of my questions were asked but I just had two real quick ones.

You had previously estimated that your amortization of deferred financing costs for this year would be about 48 million, and if you annualize the first quarter's amount, it looks like more than 56 and then following on that, could you provide any kind of guidance for 2007's amortization?

Let us take a quick look at this.

We've given you, I think if you look at the amortization of the financing cost, just one second.

Let me just double check my numbers.

I think first half of the year it was 28.

Yes. 28.

Just give me a second.

Okay, I think what we've done, we've got the transition bonds in here.

Look, I think you're looking at a number on the deferred financing cost that's going to range for the year our forecast is about $47 million.

Okay.

And could you provide any kind of guidance for 2007?

Since there was a big drop?

It's about obviously those would continue to go down and I think you're looking at around $38 million next year.

Great.

These are pretty calculable and we can certainly make sure we're clear on that.

Okay, and separately, the settlement agreement has a suspension of the TCOS rider for two years.

Do you see any kind of impact over the next couple of years from suspending that because you've had transmission costs increase a little bit the last two years.

We clearly looked at that before we agreed to it, and we've got a big transmission project we're building now but we've taken that into account, so given what we know now about our transmission investments, we think we're going to be fine.

After a two year suspension we can obviously go in and ask for a TCOS change.

But more importantly, I think is that we can't control what everybody else is doing in the State and to the extent that other transmission providers raise their rate.

We have the opportunity after February of next year to go in for a TCRF increase.

So we don't have to bear the risk of other folks increased transmission costs.

Okay, so for TCRF, you can go in as early as February '07 ?

After February of next year if their increases by third party transmission providers we can go in then, yes.

It's only our internal -- our own transmission cost that we have to wait a couple years and we have a pretty good handle on that and we've already taken that into consideration.

Okay, great.

Thank you.

Your next question next question come Scott Ingstrom with Satellite Management.

Good morning, guys.

Excuse me, lady, sorry, Marianne.

Good morning, Scott.

Question, just trying to scrub for the ZENS again.

The 119 million it says tax and interest.

Is that, say if I'm trying to scrub that out.

Is another way of what you're saying, Gary, is you start with the 78 million of pretax and apply a 31% tax rate to that?

Is that an easy way to scrub that out?

Say that again, Scott?

Well the income statement shows 78 million of pretax for the quarter and I'm wondering, to scrub out the ZENS impact in the quarter should I just use the 31% tax rate you talked about?

Would that do it?

Yes.

What you'd do I think is take or add back the -- add back the ZENS, the 119 and of course then in the tax rate of remember I said earlier that we also had $21 million of other items there, so if you want to scrub it out you really could apply what you just said 31% if you wanted to get -- I think if we did the math for you I think you'd probably get to about $0.24 versus $0.30 for the quarter.

Okay. $0.24 solely excludes the 21?

I think, yes.

That would exclude ZENS and that would exclude the other tax items that we referred to.

Okay.

And then depending on how people want to treat them, I mean, there's the 32 million of the UCOS, the 17 million mark to market and then at FAS distribution you had the 5 million staff reduction and 3 million for rate case writeoff, that kind of all ends around another 11.5, $0.12 using mid 30s- type tax rate.

Does that sound right?

Yes.

I'd have to run the math but it sounds about right.

Okay.

So kind of depending on what you would say is ongoing or one-time, somewhere between the mid 20s and mid 30s is kind of an ongoing quarter for you guys, $0.30 that is?

Mid $0.02 to mid $0.30?

Yes.

I think that's fair. $0.24 if you kind of take the quarter and adjust the taxes and these unusual items and obviously if we didn't have some of these other costs, it would have been higher, so I think it would be north of 24 on a normalized basis.

And with the mark to market charge, on the inventory I guess it's not a mark to market but the inventory charge is that 17 million, is that large for any given quarter or should we expect larger changes, smaller changes?

Is it going to be a source of volatility on earnings going forward ?

Well it's a factor of two things I guess, stating the obvious.

One is how much inventory we have and we have a fair amount of inventory now, about 11BCF.

And secondly, it's the change in gas price is from quarter to quarter and we had a pretty big -- we had over $1 I guess or $1.40 change from the end of the first quarter to the end of the second quarter, and there's going to be a fair amount of volatility, we think, in gas prices.

We've seen it the last year or so.

But we've captured some value here by selling gas forward and the differentials between say May and January and February of next year were $4 and $5, so we tried to capture that value and that's the reason we have this much inventory.

So that will change from period to period, but I think you can expect some volatility due to these inventory adjustments.

But Scott, again, I think it's volatility but I do think you have to look at it within the time frame of when that business is complete.

In other words, there is a cycle that basically completes itself as you get into January and February of next year.

So in an environment where natural gas prices are decreasing, certainly for the accounting perspective, you could have writedowns of your inventory to lower of cost or average market.

But again, look at the change because it's not really volatility in the business when you look at it through the cycle of the business.

I agree.

That's why I was wondering internally do you look at these as sort of more noise on a quarter to quarter basis and would you -- is that something you're going to break out for us on a quarterly basis so we might view it that way as well ?

I think that's exactly the way you ought to do it, Scott because that's the way we view it and that's the reason we provide the data is that it is kind of noise but and I think you have to treat it as such.

Okay, great.

Thanks a lot.

Your next question comes from Paul Ridzon with KeyBanc.

Just to reiterate what you're including and excluding from guidance, you're including the lower rates whenever those kick in, you're including the lower costs or lower return on the CTC, and you're excluding the one-time ZENS benefit and the forward-looking credit to customers?

Correct.

The 32 million that we took for the UCOS, that's correct.

And then with regards to the ZENS, were you reserving dollar for dollar against the benefit you realized?

No.

So why are we having a zero earnings impact as a result of this?

Well again, if you'd think about, this is Gary.

If you think about the ZENS again in terms of that reserve, it really, the reserve is really related to the accounting treatment that would be applied if the contention that the IRS had in place which had to do basically with the characterization of the way you treated ZENS, current versus the deferred tax deduction, so on a forward basis, basically you're back to square one on ZENS.

We had the ZENS on our balance sheet, we pay a 2% cash interest, we have an additional tax deduction and we set up a deferred tax liability for that.

So it's really a cash flow, not an earnings issue going forward.

So you can exclude -- there's no ZENS impact going forward.

Relative to what you've been doing since '04?

Yes.

In other words once, the December, or late '04 when we started to reserve for the ZENS it had to do with the complicated accounting and it has to be applied under FAS 109 and other accounting pronouncements, which basically looks all the way forward to the end of the ZENS.

I mean, we could take the rest of the conference call going through that, but basically, the way to think about it is this issue has been removed from the Company subject of course to the final approval by the joint committee on taxation and then you will have the ZENS on our balance sheet which is effectively beneficial to us because it provides a tax deduction, current tax deduction that ultimately will be paid back over time.

So it's a working capital issue is the way I think about it.

So it's not an earnings issue going forward.

As you reiterate your guidance, what's your assumption with regards to approval of the settlement?

We made an assumption that we're going to get it approved later on this year.

It could be probably as early as in the September time frame.

Okay, thank you.

Your next question comes from Michael Goldenberg with Luminous Management.

Good morning.

Good morning.

Just had a question on -- I'm following the rate case.

Do you feel that with these increased in spendings per the rate case settlement you'll be able to offset that through internal programs?

Well, we're certainly looking at the way we do business here.

There's no question we're trying to make process improvements in our business, and we certainly hope we can make some improvements there but the thing you also have to think about, Michael, is our service territory, has been growing about 2.5% per year for the last almost ten years.

Now, we had a few more little higher growth this last quarter, or so because of the folks that came over from Louisiana, as a result of the hurricane, but 45, 50,000 new customers a year, that growth is certainly going to help too.

Uh-huh.

So should we expect no considerable increase in O&M or O&M increases considerably lower than the 20 mill per rate case ?

Well, we're going to work hard to see if there's ways for us to improve the efficiency of our business.

I can't guarantee you that there won't be any O&M increases.

That depends on a lot of things.

Understood.

Thank you very much.

Okay.

Okay, I think we have time for one more question.

Yes, ma'am.

And our final question comes from Lasan Johong with RBC Capital.

Hi.

Wanted to ask the about the comment Gary made about financing using debt or equity.

Am I correct in assuming that if there is continually higher and higher needs for equity to keep your balance sheet in tow that the initial reaction would be to try and keep the dividend at $0.60 while earnings grow and use that as a first kind of line of defense and then if that does not hold the capital structure then you would go to the market for equity?

I don't think I would think about it that way, Lasan.

We've committed to our shareholders that we're going to move up the dividend as we improve earnings and we've got this earnings dividend pay out target of 50 to 75%, and it's our goal to try to move the dividend up, and so I don't think that that's going to have that big an impact on the financing of these projects.

We're going to be producing a fair amount of cash flow and we hope internal cash flow plus our credit facilities will be adequate, and you also have to kind of keep in mind that we have these other issues, the appeal of the stranded cost, that's a big number and other things, perhaps securitization around the CTC, so there's lots of ways that we may, lots of cash that we may get in a different way.

So we'll watch this closely.

We're not afraid of equity, but clearly we don't want to use equity unless we have to.

It's a balancing act between our balance sheet and credit metrics, so we take all that into consideration but we're not going to sell equity unless we need to, and, but that may be good news.

But how did do you define need to?

Need to because we've got so many good growth projects that we can't generate enough cash internally.

Got it.

Thank you.

Lasan, you know we're going to continue to look at our sources and uses and as David described those projects, the Carthage and Perryville are great projects and the timing of that in terms of cash of course is more back end loaded in terms of this year.

The others, of course we have opportunities, one is a joint -- both of the other two by the way are joint ventures, so we have a lot of flexibility around that, whereas David described, there are other potential sources of cash.

And we're going to remain very disciplined, as we said, in terms of our credit metrics and enhancing our credit, but at the same time, increasing the value of this company for our shareholders, and we're going to go about it very disciplined and the dividend is important to this Company and our shareholders, and as David described we're going to be very careful and disciplined as we go through this.

And it's all, in our view, good news by the way of what we have in front of us.

Understood.

Thank you very much.

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

We very much appreciate your support.

Have a great day.

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

Thank you for your participation.