CenterPoint Energy Inc (CNP) 2005 Q4 法說會逐字稿

Good morning.

And welcome to CenterPoint Energy's fourth quarter and full year 2005 earnings conference call with senior management. [OPERATOR INSTRUCTIONS].

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

Ms. Paulsen?

Thank you, LuAnn.

Good morning, everyone.

Again, I'm Marianne Paulsen, Director of Investor Relations for CenterPoint Energy.

I would like to welcome you to our fourth quarter and full year 2005 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 fourth quarter and full year results, and will also provide highlights 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 fourth quarter and full year 2005 earnings release, filed earlier today is posted on our web site, which is www.CenterPointEnergy.com under the investor section.

I would like to remind you that any projections or forward-looking statements made during this call are subject to the precautionary statements 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 p.m. central time Tuesday, March 7th, 2006.

To access the replay, please call 1-800-642-1687 or 706-645-9291, and enter the conference ID number 436-8643.

You can also listen to an online replay via the web site I just mentioned.

We will archive the call on CenterPoint's web site for at least one year.

I would now like to 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.

2006 marks the beginning of a new and exciting era at CenterPoint Energy.

The end of last year closed a difficult and challenging multi year transition that began in 2002 when CenterPoint Energy became an independent company.

At the time, we were heavily leveraged and needed to sell our generation assets and recover our stranded costs in order to recapitalize our business and in order to fully realize the potential of our existing businesses.

While there were a few twists and turns along the way, I'm very proud of what we accomplished during the last three years and I'm delighted to say our transition is behind us.

We are now in a position to devote our full attention to our future and maximizing the value of our businesses.

We have a diverse set of electric and gas businesses that we believe hold significant potential for future growth and the creation of shareholder value.

Now let me provide you with the brief overview of our consolidated results for the fourth quarter and calendar year 2005.

For the fourth quarter of 2005, we reported net income of $81 million, or $0.25 per diluted share.

This compares to net income of $100 million last year, or $0.29 per diluted share.

Income from continuing operations for the fourth quarter of 2005 was also $81 million, compared to $162 million or $0.46 per diluted share for the previous year.

The fourth quarter of 2004 reflected a number of nonrecurring or unusual items.

We recorded after tax income of $147 million related to interest on our authorized true up balance.

Of this amount, $124 million was for periods prior to the fourth quarter of 2004.

We also incurred an $83 million extraordinary charge to earnings related to the stranded cost trueup proceeding and realized $21 million of income from discontinued operations.

If you compare our operating performance in 2005 to the performance in 2004, excluding those items, then I believe the fourth quarter of 2005 was, indeed, a strong quarter.

Net income for the full year 2005 was $252 million or $0.75 per diluted share, compared to a loss of $905 million in 2004.

Income from continuing operations for 2005 was $225 million or $0.67 per diluted share compared to $205 million or $0.61 per diluted share for the previous year.

As you may recall, in 2004, we recorded $977 million write-down of regulatory assets related to our trueup proceeding, and $133 million net loss from continuing operations related to the sale of our generating assets.

Results for 2004 also included $62 million of after-tax income related to interest on our authorized trueup balance for periods prior to 2004.

In 2005, we recorded a positive adjustment of $30 million related to the 2004 writeoff of our regulatory assets.

Once again, if 2005 results are compared to 2004, without these unusual or one-time items, then I believe that 2005 can be viewed as an excellent year representing continued improvement in our operating performance.

Now, I would like to give you some highlights about the performance of each of our business segments.

I will begin with our pipeline and field services group, which had another outstanding year and had the most significant improvement in operating results of any of our business segments.

This group achieved operating income of $67 million in the fourth quarter of 2005, an increase of $10 million or 18% over the previous year.

Operating income for the full year 2005 was $235 million, an increase of $55 million or 31% over 2004.

Both our interstate pipelines and our field services operations contributed to the outstanding results of this segment.

Let me give you the results for each.

This is the first time we have given this level of detail for this segment, and I believe it is important, given the growing size of each of the business operations that make up this segment.

The Interstate Pipeline's recorded operating income of $46 million for the fourth quarter of 2004, which was a 10% increase over the prior year's quarter.

For the full year 2005, Interstate Pipelines achieved $165 million in operating income, which was a 28% increase over 2004.

These improvements were primarily driven by increased transportation across our system due to significant natural gas basis differentials, as well as increased balancing and ancillary services.

Our field services business also had an outstanding quarter and year.

This business includes our gas gathering and processing operations, as well as Service Star, a wellhead monitor and communications service.

Field services had operating income of $21 million for the fourth quarter of 2005, which was an increase of over 40% compared to the fourth quarter of 2004.

And for the full year 2005, field services recorded operating income of $70 million, which was an increase of over 37% compared to 2004.

These improvements were primarily driven by increased throughput due to increased well connects, increased ancillary services, and the benefits of higher commodity prices.

Next I would like to talk about a new segment that we broke out from the natural gas distribution segment for the first time this quarter.

This new segment, competitive natural gas sales and services is our non-regulated natural gas sales and marketing business, operated through CenterPoint Energy Services, or CES.

The opportunities and the challenges of this unit are significantly different than our regulated gas distribution systems.

Accordingly, last year we reorganized, and the management of this segment now reports directly to me.

Let me briefly describe its operations.

CES is engaged in the marking of physical natural gas supplies and services to nearly 7,000 retail and wholesale customers, ranging in size from small commercial customers to large utility companies.

CES maintains a portfolio of natural gas supply contracts, and utilizes its own and contracted pipeline capacity and storage to fulfill customers' requirements.

Its profitability is driven by growth in its customer base, and by optimizing its overall supply and asset positions to take advantage of market opportunities.

I'm pleased that this segment also achieved exceptional results last year.

Operating income for the fourth quarter of 2005 was $30 million compared to $16 million for the fourth quarter of 2004.

For the full year 2005, operating income was $60 million, compared to $44 million, for the previous year.

Much of the improvement in 2005 was driven by natural gas price volatility and increased wholesale activity.

While no one can predict how long the current dynamics in the natural gas markets will last, I'm pleased that we have positioned ourselves both through our pipeline group and CES to provide the services and the products that our customers need in this environment.

Now, let me turn to our regulated utility businesses which have been consolidated under the leadership of Tom Standish.

Our natural gas distribution segment, which, of course, now excludes competitive natural gas sales and services, reported operating income of $59 million for the fourth quarter of 2005, compared to $69 million for the prior year.

Improvements in operating margin that we achieved by adding almost 44,000 customers were more than offset by increased bad debt expense resulting from high natural gas prices and increased litigation reserves.

In 2005, the natural gas distribution segment achieved operating income of $175 million compared to $178 million the prior year.

The benefits from rate increases and customer growth were more than offset by the increases in bad debt expense, litigation reserves and depreciation expense.

We are working hard to improve the financial performance of this segment, and hope that the results of the rate cases we have pending and improvements in operations that we are pursuing will improve on a somewhat disappointing year in 2005.

Let me now discuss the performance of our electric transmission and distribution business, CenterPoint Energy's largest business segment.

Excluding the transition bond companies, the TDU reported operating income of $90 million for the fourth quarter of 2005, compared to $95 million in the prior year.

Houston Electric continues to enjoy solid customer growth, adding over 60,000 metered customers since December of 2004.

Our fourth quarter 2005 revenues also benefited from the implementation of the competition transition charge, or CTC, through which we are beginning to recover the portion of our trueup balance not recovered through the sale of the transition bonds.

Although this quarter we received about the same level of revenues from transmission cost recovery as we did in the prior year, we experienced higher transmission costs billed to us from other electric utilities, which was the largest single driver in the quarter's increase in operation and maintenance expenses.

We also experienced increases in tree trimming expenses, employee-related costs and franchise fees paid to the City of Houston under a new 30-year franchise agreement.

The TDU's operating income for the full year 2005 was $448 million, compared to $456 million for 2004.

In addition to the items that I talked about for the quarter, the TDU benefited from favorable weather in 2005.

However, 2004 results reflected the benefit of a $15 million positive adjustment to the final fuel reconciliation reserve and an $11 million gain from a land sale.

Overall, I believe that DU had another solid year in 2005.

The fourth quarter of last year also marked the culmination of three years of regulatory efforts to recover our standard cost true up balance.

In December we issued $1.85 billion of transition bonds to recover a significant portion of our authorized true up balance.

The fourth quarter was also the first full quarter following the implementation of the competition transition charge, through which we are recovering the remaining $596 million of our true up balance.

While we are pleased to have finally recovered a large portion of our true up balance, we are continuing to seek the reversal of certain disallowances by the PUC.

In August of last year, the district court affirmed most aspects of the PUC true up order but reversed two of the commission's ruling that would have the effect of restoring about $650 million, plus interest.

We and other parties subsequently found notices of appeal with the Third Court of Appeals.

We anticipate that the appeals process, if ultimately taken to the Supreme Court, may take up to two more years.

In summary, I'm very pleased with our overall performance.

We captured opportunities of a volatile natural gas environment.

We responded splendidly to back-to-back hurricanes impacting our Gulf Coast service territories and continued to focus on operational improvements and closed the year by recovering a large portion of our stranded costs.

I couldn't be more crowd of our employees and their dedication and commitment to our committee and to serving our customers.

Looking forward, we have a number of attractive opportunities as well as a few challenges.

Our pipeline group has announced two exciting projects.

The first involves the construction of 172-mile pipeline between Carthage Texas and our Perryville hub in northeast Louisiana, which will have an initial design capacity of almost 1 billion cubic feet per day.

The announcement last October was concurrent with the signing of a ten-year contract with XTO as the anchor shipper for the transport of 600 million cubic feet per day of their natural gas production.

We held an open season to solicit interest in the remaining 40% of the capacity of the new pipeline, and received significant interest.

We expect substantially all of the pipeline capacity will be under contract within the next few months.

The pipeline will cost approximately $400 million, and with timely receipt of permits we hope to start construction later this year.

This is some excellent project in a capacity constrained area, and is expected to provide attractive returns to the company.

In the second project, subsidiaries of CenterPoint Energy and Duke Energy signed a memorandum of understanding last November to evaluate market and develop a potential new southeast pipeline connecting our Perryville hub to Duke's gulf stream natural systems.

A nonbinding open season was held in December of last year, and there was exceptional interest shown in the project.

We are now in the process of negotiating definitive agreements, if sufficient binding agreements are concluded, this pipeline could go into service as early as mid-2008.

As with the Carthage to Perryville project, we anticipate attractive returns from this project.

Moving on to our electric transmission and distribution utilities, CenterPoint Energy Houston Electric announced last month a limited deployment in 2006 of intelligent grid technology, focused on enhancing the efficiency and the reliability of our utility operations.

This year's limited deployment, which we expect to cost about $11 million, involves installing, testing and monitoring, automated meter reading of 40,000 electric, and 23,000 gas meters, remote connection and disconnection of electric service, and automated outage detection and restoration.

Broadband over power line, or BPL will be used for the data communications network and IBM will act as our technology partner.

Our goal is to have fewer and shorter outages, better customer service, improved operating costs and security and higher productivity.

We might also consider consumer applications sometime in the future.

There are two significant regulatory proceedings facing Houston Electric later this year.

In December of last year, the PUC ordered Houston Electric to file a rate case by April of this year, to show that its rates are just and reasonable.

We are in the process of preparing this case, using more recent financial data than what was used by the PUC staff in its earnings monitoring analysis.

We expect to have settlement discussions with other parties in March, and hopefully avoid a costly and extended rate proceeding.

The commission also initiated a rule making regarding the appropriate rate of return to use in the competition transition charge.

As part of the final order in our CTC case, the commission ordered the use of an 11.075% return, which was Houston Electric's authorized weighted cost of capital.

The staff of the PUC have suggested that a debt rate would be more appropriate.

We filed our comments yesterday and strongly believe that the current rate should be considered for the reasons we laid out in our report.

For those of you who were interested, I invite to you review our filing.

We expect the commission will take action on this rule making in the second quarter although there's no statutory time frame for the commission to act.

This morning in our earnings release, we announced that we expect diluted earnings per share for this year to be in the range of $0.90 to $1.

It's important to point out that we have excluded from this guidance any impact related to the Company's zero premium, exchangeable subordinated notes, or ZENS, and any associated income tax consequences.

As we have previously -- disclosed previously, we are in a dispute with the IRS regarding the deductibility of interest and original issue discount in connection with these securities.

Last year, we recorded tax reserves equivalent to approximately $0.12 per diluted share related to this issue.

We are currently in the appeals process with the IRS, which is not expected to be concluded until the second half of the year.

In making our earnings estimate for the year, we made certain economic and operational assumptions, including the outcomes of the various regulatory proceedings at Houston Electric and our LDCs.

Before I turn the call over to Gary, I would like to remind you of the recent dividend action taken by our Board of Directors.

With the repeal of the Public Utility Holding Company Act, the prior restrictions on our dividend payments which required to us pay regular quarterly dividends last year will not affect our dividend decisions this year.

In January our Board of Directors declared a $0.15 per share quarterly dividend, with the intention of returning to our traditional practice of paying consistent, quarterly dividends.

An annualized dividend based on $0.15 per quarter represents a 50% increase over the $0.40 paid in 2005.

We believe that the increase in our dividend this year demonstrates our strong commitment to our shareholders who expect a competitive dividend.

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

Let me close by saying that we are making progress in implementing our strategy.

We are executing on the plans that we developed and communicated to you prior to the formation of CenterPoint Energy.

Our businesses are performing well, and continue to improve their financial and operating results.

We are focusing our attention on value enhancing opportunities, consistent with our strategy.

Now I will turn the call over to Gary.

Thank you, David and good morning to everyone.

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

Let me begin with a review of our income tax rate for the quarter and full year 2005, including the impact of the zero premium and exchangeable subordinated notes, or ZENS and the related issues going forward.

Our effective tax rate for the fourth quarter was 28% and 41% for the full year.

The fourth quarter tax rate was lower than the combined federal and state rate of approximately 36%, due to a number of favorable tax reserve adjustments, mainly related to various legacy tax issues that more than offset the addition of $10 million to the tax reserve related to ZENS.

The full-year tax rate of 41% included a $42 million unfavorable tax reserve related to the ZENS issue, offset by the favorable adjustments I just mentioned.

The total tax reserve at the end of the year for the ZENS issue was $121 million.

As I described last quarter, and as we have disclosed in our various filings, the IRS is proposing to disallow all deductions for interest and original issued discounts or OID relating to ZENS.

The contention of the IRS is that the OID and the interest actually paid on these securities is not currently deductible, but instead must be added to the basis and the Time Warner stock that we own.

This would have the effect of recharacterizing ordinary interest deductions to capital losses, or reduced capital gain.

Currently the company does not expect to have adequate capital gains to offset the projected capital losses; therefore, under the accounting rules, we are required to reserve for this item.

The company disagrees with the IRS and we are contesting the issue.

The issue is currently in the IRS appeals process and we are hopeful that we can reach a resolution before year end 2006; however, we can not predict with certainty either the timing or the result of the appeal.

So what does this mean?

First, it is important to note that the issue and the reserve calculation is complex, and is affected by a number of variables, including the market price of Time Warner stock, the amount of ZENS OID, which increases quarterly, and the Company's assessment of available capital gains.

Second, this issue could have either a positive or a negative effect on the Company's earnings, based on the variables I just described and the the timing and the outcome of the resolution with the IRS.

Therefore, as David referenced in his discussion this morning, we have excluded the impact of ZENS from our 2006 earnings guidance.

Now, let me update you on the completion of the sale of transition bonds and the use of proceeds.

Houston Electric closed on the sale of $1.85 billion of transition bonds on December 16, 2005.

The proceeds were used to repay in full the $1.31 billion borrowing under the back stop facility which was used to repay the high interest rate term loan at Houston Electric.

The remaining amount was paid as a dividend to the parent company, and was primarily used to repay short-term borrowings and to fund a pension plan contribution.

Following the payment of the dividend to the parent company, Houston Electric's capital structure is approximately 50% debt and 50% equity, which is more typical for a regulated utility.

As David said in his remarks this morning, we have successfully completed our transition which began more than three years ago.

Following our separation from Reliance in September of 2002, we have reduced our debt levels, excluding transition bonds from a high of almost $11 billion, to $6.4 billion at year end, including paying down $1.9 billion of debt in 2005 which included Houston Electric's high interest rate term loan.

Obviously, our interest expense going forward will now be significantly reduced from the 2005 and prior year levels.

We have also contributed $551 million to our pension plan over the last two years.

In addition, we have significantly enhanced our liquidity due to the improvement in size, price and tenor of our working capital facility, and, intact, we are seeking to improve our existing credit facilities by increasing, the size, extending the maturity dates and improving the pricing and terms.

All of these actions reflect the consistent and significant steps in risk profile in both the parent company and our utility subsidiaries.

We are pleased that each of our utility subsidiaries has investment grade ratings with a stable outlook.

We have achieved not only financial stability during this time frame but the financial flexibility needed to invest in and grow the profitability of our businesses.

Now let me discuss our financial priorities as we move from our transition phase and turn our full intention to improving and growing the profitability of our businesses.

As David mentioned, we have a number of excellent growth opportunities.

We plan to finance these opportunities as well as our ongoing capital requirements through internally generated cash flow and if required, 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.

And now let me thank you for your interest in the Company and turn the call back to Marianne.

Marianne, let me make one correction from something I said earlier.

In reviewing the results of our pipeline business, I reported $46 million of operating income for the fourth quarter of 2004.

I should have said the fourth quarter of 2005.

I apologize for that mistake.

Thank you for that clarification.

And thanks, Gary for your remarks.

We would now like to take some of your questions, LuAnn, would you please give the instructions on how to ask a question?

Thanks.

At this time we will begin taking questions. [ OPERATOR INSTRUCTIONS ] Thank you.

Your first question comes from Lasan Johong with RBC Capital Markets.

I'm wondering about the pipeline projects a little bit more.

I'm hoping to get a little more color on this.

What is the commercial date of operations for the Carthage to the Perryville connection?

It depends on when we get our permits.

If we get them in a timely manner, it could be in service for this upcoming winter season.

But it just depends on with we get those permits.

It could be early next year so April or May of next year.

Hopefully it will be earlier in the year.

I see.

And on the Duke pipeline what is the projected capacity?

How much is it going to cost?

And what is the -- you set the commercial date of operation is mid '08?

Yes that's what we are projecting to date.

The size is really undetermined at this time.

We've gotten a lot of interest then we'll size this pipeline to the interest that is out there.

It could be probably as small as 750 or 800 million a day, up to a billion.

And so we'll just wait and see how much binding agreements we get in hand.

I see.

And yesterday the ROE on both was around, what, 12%?

You know the way we do this analysis is we look at a traditional pipeline capital structure, and make sure we meet the hurdle rates based on -- based on that, on that kind of analysis.

So these are solid pipeline returns.

Thank you.

Your next question comes from John Kiani with Credit Suisse.

Good morning.

Good morning.

You mentioned in the $0.90 to $1 of EPS guidance for '06, that you made some type of an adjustment for the regulatory issues, both the rate case and perhaps the you costs.

Does that mean it was a partial year adjustment, assuming that obviously, the -- both of these issues won't be resolved on a full-year basis in '06?

That's correct, John.

We -- we have assumed -- made some assumptions as to when it would be impacted, but it's to the a full-year impact.

It's only a partial year.

Got it.

And is there any way you can give a little more color on -- is it, perhaps a half a year?

Is it one quarter of an impact?

Based on the timing or magnitude standpoint.

I would suggest to you, it's a little bit more than a half year.

We made some assumptions around settlements, and for purposes of this estimate --

Mm-hmm.

It's -- it's a little more than a half year, I would suspect.

Okay.

Great.

Thank you.

Your next question comes from [Josh Levins with Lord Abbett.]

Good morning.

Good morning.

My question is more an industrial organization question.

Yesterday an article in the "Wall Street Journal" speculated that there might be consolidation in the T & B businesses in Texas.

What is your speculation, and the likelihood that such consolidation will take place in the state.

Well, I think I read the same article you did.

And it's really hard to say.

I think there's some synergies in consolidation that could be attractive to our customers, but that type of consolidation is hard to achieve, because if you pay -- if there's any premiums involved in a consolidation, you have to get back the premium through cost savings and not through rates.

So I think it's easy to say it's a little harder to do, but having said that, I think there are always potentials for those types of things to occur.

Okay.

And is your assessment of the likelihood of that kind of consolidation, has that changed over the past few months or basically unchanged?

I don't think it's changed much.

I think we're seeing a lot of activity in the utility sector since the repeal of FUCA, although I think most of these transactions that I have seen announced have probably been done even with PUCA in effect, but I think there is more activity.

I think everybody, all companies are looking at their strategies and their growth potential, and trying to determine if there's ways to enhance the value to the shareholders.

So I think we're all looking and we're all trying to see if anything makes sense.

All right, thank you.

Your next question comes from the Scott Engstrom with Satellite Asset Management.

Good morning.

Good morning.

A question on the competitive business segment that you broke out, Dave you describe it as a services businesses in the press release, though, it talks about the benefits realized from the basis differentials, which would make it sound a little bit more opportunistic.

Could you give us a big picture, is it more services?

Is it more commodity opportunistic?

How should we be thinking of this?

We -- in our main business, it's selling gas.

We sell natural gas to small, commercial, all the way up to big utilities, and we tend to aggregate and we have diversity of our customer base.

And we, perhaps go after some of the smaller customers compared to big -- big marketers.

But in having this type of business, you have to own pipeline capacity, or contract for pipeline capacity, you have to contract for storage to meet the swing needs of your customers, and that creates opportunities, especially when basis widens.

And what we saw last year is basis widened a lot in certain areas of the country.

We happened to own capacity on pipelines that benefited from that.

So we're able to -- to take advantage of those type of opportunities.

Our core business, though, is selling natural gas, but because of the -- the assets we own and operate, it creates these type of opportunities I have just described.

Okay.

One reason I ask is looking at the gross margin, it's just a little bit over 2% last year, and a little higher than that in '04.

And I'm just wondering, was that basis -- is that a normalized kind of gross margin that we could think of, if you grow the business, at around a 2% gross margin business?

That may be a little low.

The reason is, we have a lot of wholesale business in last year, and that tends to be a lot lower margin business than -- than selling to commercial and industrial customers, but I -- I haven't gone back to recalculate that.

Probably some where a little north of 2% is probably reasonable.

And the other thing I wanted to mention, you had some mark-to-market impact as well.

Is that a substantial number for the year that you went against you?

I think it's around $7 million that went against us.

And that was really related to this basis differential widening.

We hedge our position, but the way accounting works, we weren't able to match some of these derivatives against our physical position; therefore you have the mark-to-market.

That was a little unusual for us because real -- really because the basis differentials widening so much last year.

And can I ask also how much the positive tax benefits you realized in the fourth quarter was from the release of the reserves?

Let me ask Gary to give you that.

Well, as I mentioned in my comments in -- you are talking about the fourth quarter, there was $10 million.

We had a charge for the ZENS -- really, I'm reflecting this for the full year.

The full year was -- excuse me, $42 million charge for the ZENS so 41% tax rate, so the reserves basically offset that amount because our rate should be around 39, circa 40%.

So you need the legacy issues.

Right.

So it was roughly $40 million then for the year.

Yeah, in other words our normalized rate looks to be around -- should be around 39%, that sort of zip code.

Okay.

And there are adjustments to it that brought it back to that level, offsetting the ZENS charge.

And I assume that's kind of the rate you are using for the guidance for next year?

I think on a go forward basis, what you need to assume is that the go forward rate is, again, approximately 39%, and as David and we described this morning, we are excluding the ZENS from that.

Certainly there could be some additional legacy issues that are resolved as with any company of our size, but I think you start to think about the base earnings being tax effected at 39%.

And is there a number that you guys put together for the year to sort of quantify the impacts of the hurricanes across the business?

We didn't have a huge amount of impact.

It's only a few million dollars, to be very honest.

The reason is that Houston Electric, we defer most of those could have and they go against our storm reserve.

In our gas sales receipts, some of it is deferred but there wasn't a lot of damage.

Most of the costs will come as we reconstruct our system, mainly in Mississippi.

We abandoned a lot of service lines in the areas where the houses were just destroyed.

When we go back in, if those houses are rebuilt, we'll simply replace that -- the main and those service lines.

So from an earnings impact, I think it was very immaterial.

Great.

Thanks so much for everything.

Last question, any change in shares outstanding or embedded in the guidance you gave for next quarter.

You know that's something that we don't really disclose, just because it would suggest what we are going to do with financing.

So there's not a lot of change, though.

Okay.

Thank you very much.

Your next question comes from Paul Patterson with Glenrock.

Good morning, guys.

Can you hear me?

Yep.

I wanted just to follow up on Scott's question on the basis of differential.

Is the basis differential benefit that you guys received in 2005, are you guys looking at the same sort of benefits in 2006 in your guidance?

No.

We're not -- you know, we're not assuming that 2006 will be a repeat of 2005.

We are using more -- what I call conservative and perhaps a little bit more traditional basis differentials.

Now, we continue to see basis differentials wider than normal, but they don't -- they are not at the level they were in 2005.

So I think we have -- we have assumed that while maybe not absolutely normal, certainly not at the same levels that we saw in 2005.

Okay.

Great.

And then just a follow-up on the -- I think you guys said in your remarks that you guys were preparing to file an adjusted return on equity, financial -- updated financial information with respect to what your returns would be in the electric business, in the TD business.

Could you tell us what you think that impact might be?

We haven't -- we're in the midst of preparing our case.

We haven't settled in on the exact ROE that we're going to request there.

I think that the current rates are based on -- on 11.25% ROE and 40% equity level.

Certainly we're going to go in and ask for an equity level at the actual we have in that business, which is about 50% equity, and it may not get to 11.25, but it's going to be between 10.5 and 11.25.

I don't know where exactly our expert has come out yet.

We are still -- that's still in process.

Okay.

So in other words, with about a 50% equity ratio, you guys have the earnings somewhere in that range, you think?

Well that's what we are going to base our filing on.

Okay.

You know, this is a -- you know, this is a case where we have to prove that either our rates are just and reasonable, or we have to be prepared to reduce our rates.

Our maybe increase them.

I'm not sure where it will come out, to be very honest.

There could be increases in certain parts of our rates and this could be decreases in others.

We're still in the midst of preparing all that data.

So I'm not sure where it's going to come out, but in terms of just the ROE and the percentage of equity, as I described.

Okay.

Great.

And then finally, the CTC, do you think that's 2006 guidance assume that you continue to get that 11 plus percent return on that?

You know, we have made certain assumptions around both Houston Electric's case and the CTC.

I really would like for to you look at our comments, if you are really interested, our brief, because I think we make a very -- persuasive argument about why it's right to leave that rate alone.

Now having said that, we have suggested in our filings, if you are going to go to an alternative, meaning if they want to and feel like they have to, the current weighted cost of capital for the utility should be used, as opposed to one that was developed in 2001.

Now we still believe the 2001 11.075 is the appropriate rate, but if you change, we are suggesting the only alternative, reasonable alternative would be to update our overall cost of capital.

And that's what you are assuming in guidance, correct?

I better not comment on exactly what we put in there.

Okay.

Thanks a lot, guys.

Okay.

Your next question comes from Deborah Bromberg with Jefferies & Company.

Ma'am, your line is open.

My question was answered.

Thank you.

Your next question comes from [Patrick Rosetti with Prudential Equity Group. ]

Good morning.

Where are we with the restructuring and the ZENS?

Well, one is I think we have to -- to see where we come out in the appeals process with the IRS because that determines kind of where you can go.

Obviously, if you are going to lose this issue, then ultimately, you will want to take the ZENS out.

That's my view anyway because the benefits of these securities are in large part related to the tax benefits that we are getting and if you don't believe you are going to come out and be successful there, then I think you ultimately have to take the ZENS out and that takes some time and effort, and -- but that's the primary issue.

There are synthetic ways probably you can do it and not just going out and buying the securities but to take it out in a synthetic way that has the impact of taking them out and we're looking at all of those options but the key is to reach agreement with the IRS on this issue.

Obviously, this is not an issue that was created by CenterPoint.

It started a long time ago.

It's a carryover legacy issue.

But I do know at the time that the securities were sold, this issue was thoroughly vetted.

We understood the concerns, but we feel very strongly that we have a strong position here, and that -- you know that we ought to prevail.

Okay.

Thanks.

Is there a timing or just a general time range on the IRS decision?

They said sometime prior to the end of the third quarter, that this will all be wrapped up.

Now we are still working hard to try to accelerate that and we've had a number of discussions with them, but I can't predict exactly how long this is going to take, but that's our assumption, is sometime in the -- sometime in the second half of the year, probably before the end of the third quarter.

Okay.

And I got a little lost on the tax rates.

What -- what is the tax rate at CenterPoint assuming, let's say the ZENS never existed.

Yeah, this is Gary again --

Yeah, hi, Gary.

How are you doing?

I was going to correct that.

I think I said 39%.

I think the way to look at CenterPoint, I'm going to call it consolidated tax rate, when you take into consideration where we do businesses where there are estate taxes and all in and all done with permanent differences.

You really ought to look at a 36% rate.

Okay.

And then from that, of course, absent any resolution of other related issues and we want to paint a picture that those are large, but as you know, we used to be part of this Reliant organization, which included foreign assets and a number of things.

So those things are playing out.

But the main moment digs in, so it would be plus or minus to ZENS on the tax rate.

You had said something earlier, not to spend too much time on it.

But as David said, the process just to be clear with Internal Revenue Service is that we are in the appeals process.

That follows an exam.

So there was an examination and then we're taking it to an appeals process.

It means there are two appeals officers, these are very sophisticated folks that understand these complicated issues and we have strong merit in our case and David described the time frame.

I would not reach conclusions that that you would reach a takeout scenario at this point.

It really says let's let this work through, and then all the variables I discussed, which includes the price of Time Warner shares, the amount of OID, the amount of available capital gains for the company.

So -- that's why we think it's frankly good to exclude that and we'll keep everyone updated quarterly as this moves forward.

We have a lot of merit in our position and we always seek to settle regulatory proceedings, frankly whether it be with Internal Revenue Service or any other party.

So that's where we are on that.

Okay.

Thank you very much.

Your next question comes from Jonathan Rojewski with [Seacap Capital].

Apologize.

I have a pretty bad cold.

If you can't understand me, I will repeat it.

I was wondering, back on this pipeline issue, I think Gary, you mentioned something about financing potentially for those.

But I wonder if you could give us a little bit more color on how you are looking at financing those projects relative to cash flow and debt and whether or not you would issue equity to do that to sort of help solidify your balance sheet.

Yeah, look, Jonathan, first of all, I hope all is well with you.

I haven't talked to you in a while.

But if you look at these projects, we are extremely pleased with the projects in terms of the returns that we will have.

So this is a high-class problem, number one.

Number two is that we have paid down debt substantially.

We have a lot of flexibility and frankly, we'll look at what the optimum structure is.

On the second project, which is where the joint venture was due, frankly, we'll work with our partner to determine the optimum financing of how much equity we would want to put in that and perhaps the structure, but it will be a 50/50 joint venture and we have a lot of options around that.

In terms of the XTO project, which is a superb project, the Carthage to Perryville project, whatever the optimum will be.

We won't say we will he will equity into that but certainly our credit metrics and the continued focus on our credit is important.

So we will just have to make those determinations.

We also generated a lot of positive cash flow ourselves.

So we'll use a combination of that and determine the best mix of that as we go through the year.

Okay.

And then just -- just to review -- the first one was about $400 million?

That's correct.

And then the second one, which I don't think you gave us -- an estimate on the size, but not necessarily the cost.

Yes.

Now it depends on the size of the pipe but it would be between 400 to $500 million, probably.

Okay.

Realistically.

All right.

Great.

And then my second question is, relative to the proceeding to reset the allowed return on non-securitized cost balance, is that going to be a separate proceeding that we can follow or is that part of the whole general rate case?

No, I say it's a separate rule making now.

And they will go through the fuel making and then depending on what they do, they will have to initiate a second proceeding to actually affect the rates in the various company CTC.

So I think they first go through the rule making and then they take on individual company cases and tariffs.

Okay.

We'll keep an eye on that.

That thank you for your answers.

You bet.

Your next question comes from David Grumhaus with Copia Capital.

Good morning.

A question for you.

In your guidance for '06, have you made any adjustments for the warm weather thus far?

Well, part of our range there assumes that you can have some negative weather impacts and you are right, January was very, very mild, and it affected both our gas cell D.C.s and our electric company.

We have taken all of that into account, but we don't assume that it's going to be mild the whole year but that --

But I guess the question: You have taken the guidance down specifically for the warm weather in the first two months?

Or does the range of guidance just -- you know at the bottom end of the range, it would reflect the warmer weather in January?

I -- I would -- I would say it's more of the latter.

Okay.

You know we've got a wider range here to reflect the fact that weather can be mild.

Okay.

Finally, in terms of thinking about interest for '06, can you give us any guidance there at the very least, give us some help on the deferred financing costs?

I know you broke it out on the table in the release, but is the fourth quarter rate a good number or will that come down now that the Buffet loan has been paid off.

Hi, David, this is Gary.

It will come down.

You have to take that out so you could not take the fourth quarter and annualize it.

At this point, we have no short-term or floating borrowings at all.

I think if you look at our debt, you can pretty well calculate that number.

Let me give you two things.

One, which we disclosed as well, non-cash interest expense going forward.

Off obviously it's down from this year.

It’s 72.

It will be about $48 million, the total interest expense, about $48 million would be non-cash interest and I think if you took the rest of our debt and being of course this will be plus or minus, depending if there's some swings in terms of working capital needs during this time frame, but if you look at our debt that we have now, you are looking at a run rate of about -- this would include the non-cash I'm just talking about.

This will be a run rate of about $110 million a quarter.

And that excludes the non-cash of 48?

No, that includes it.

Okay.

Includes.

Okay.

And I think you can do these calculations pretty easily in terms of the debt we have on each of the companies.

Right.

I hope that helps.

That's very helpful.

Thank you.

Your next question comes from Paul Ridzon with KeyBanc.

Most of my questions have been answered, but what was the magnitude of the litigation reserve at the gas dispo and what was that for?

It was about $11 million.

And there's a number of things that as you might recall in Minnesota, we have a number of things going on up there in connection with operations in late '04 and '05 and we made some estimates on what it will take to resolve those issues.

And then I know you kind of answered this.

I just want a little more clarification.

For the weather impact, are you assuming some cost cutting going forward to offset January and February?

Or just the $0.10 swing kind of incorporated the full range?

Well, we certainly -- we certainly do look at our cost, especially when we have months or quarters that are negative to weather.

But there are just a certain amount of swing you have in these businesses.

They are very labor intensive, as well.

So I think the $0.10 takes into account those swings.

Okay.

Thank you very much.

Your next question comes from Faisel Khan with Citigroup.

Good afternoon.

Most of my questions have been answered but I just wanted to follow up on something you said on AMI.

You said $11 million will be spent on 40,000 meters?

On our intelligent grid?

Yes.

We have $11 million in a pilot program, which will include automated meter reading for 40,000 electric and 22,000 or something gas, but it also tests the connect and disconnect of electric consumers.

It tests some automated outage detection and restoration, and it also starts putting in this back bone which is broadband over power line communication system in that area as well.

So -- but it's $11 million for all of that.

Well, what would full deployment of an AMI system on your electric grid, what would that cost you?

And what are the type of things that you need to do to be able to push that sort of project through?

Well, of course, it's our decision whether or not we want to do that or not, but the competitive marketplace, however, is starting to demand more realtime information, and certainly, we could provide realtime metering with this type of deployment.

We've got some new protocols coming in as to how long we have to connect and disconnect the customer and certainly that's going to be -- this pilot will address whether or not we can do that on a more costly, efficient basis.

And it also supports the competitive marketplace.

As I recall, a full deployment is about $200 million, or plus or minus in our service territory, and we got this planned over a five-year window.

We could obviously accelerate that if we want to, but that's the kind of order magnitude and the time frame we are talking about.

And how would you -- and how would you -- what kind of earnings -- what kind of income scheme would you derive off of that?

Off of that deployment?

I mean is it regulated returns or is it --

Regulated returns, yes.

Okay.

Fair enough.

Thank you.

Okay.

We are running up against our time here so if we could take one more question that would be great.

Your final question comes from Zack Schreiber with Duquesne Capital.

Last but not least.

Just a question, maybe you covered this on the call.

What is the cumulative tax benefits that you have taken on the ZENS since they were issued back in, I think, it was 1998 or 1999?

We have a reserve of $121 million, a tax reserve on our books.

But that's how much you reserved but how much have you taken?

How does the reserve compare to the benefits you have taken?

I think that represents about 80% of the benefit we have taken or something of that order; is that right, Mr. Brian?

That's correct.

Okay.

So it's substantially all, if not quite all of it.

And on the -- on the return issue, on the non-securitized costs didn't we already go through this, like three different times, like 12 months ago, a year and a half ago that we kind of swung back and forth a couple of times at the Commission as what the return would be in the non-securitized trend of cost?

Yes, we have.

I think we pointed out in the brief that the commissioner has taken it up on six different occasions.

Got it.

Okay.

And in terms of the general rate case, are you expecting and relying on a settlement?

Because it sounded like that that's what was embedded in the $0.90 to $1, was sort of a larger than a half year impact, so maybe you could -- you don't -- you ding yourself for a high percentage of the year impact or maybe less than what a fully litigated outcome would be, is that what you are getting at?

We always tried to settle these cases rather than fully litigate it and there are certainly some reasons why you would want to do that with this case.

For surprises of our -- purposes of our guidance, we simply had to make some assumptions and we -- made some assumptions that whatever rate increase we assume is going to be in effect for a little more than half a year, went from a practical standpoint, that would mean you settled it as opposed to fully litigated it, but that's simply a way for us to reflect it in our earnings guidance.

If we don't settle it, -- we do know this, whatever we have assumed is going to be different from what they do.

We think we have provided a reasonable and I think conservative approach, but we'll just have to wait and see.

Just to be clear, your thought on the settlement is for a rate decrease, not a rate increase; is that correct?

We have assumed there will be some rate decrease, yes.

Okay.

Got it.

Thanks so much.

Okay.

Okay.

Thank you very much, everyone.

I would like to end the call by saying thanks again for your support and have a great rest of the day.

This concludes CenterPoint Energy's second quarter and full-year 2005 earnings conference call.

Thank you for your participation.