CenterPoint Energy Inc (CNP) 2003 Q2 法說會逐字稿

Good morning.

My name is Lisa and I will be your conference facilitator today.

At this time, I would like to welcome everyone to the CenterPoint Energy second-quarter 2003 earnings conference call.

All lines have been placed on mute to prevent any background noise.

After the speakers' remarks, there will be a question-and-answer period. (CALLER INSTRUCTIONS) Miss Paulsen, you may begin your conference.

Thank you very much, Lisa.

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

I would like to welcome you to our second-quarter 2003 earnings conference call.

Thank you very much for joining us today.

As you may know, Texas Genco also released earnings today and had a conference call this morning as well.

If you would like to listen to a replay of the Texas Genco conference call, please go to the Direct Investor Relations section of their website, www.TexGenco.com.

On our call this morning, although we will comment on Texas Genco's results, which are reported in CenterPoint Energy's electric generation segment, our primary focus will be on the other segments of the company.

On our call this morning, we have David Tees, President and CEO of CenterPoint Energy and Joe McGoldrick, Vice President of Strategic Planning.

In addition we have other members of management here who may assist us in answering questions on CenterPoint Energy following the prepared remarks.

Our second-quarter earnings release which we issued this morning is posted on the CenterPoint Energy website, which is www.CenterPointEnergy.com under the investors section.

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

Before Mr. McClanahan begin, I would like to mention that a replay of this call will be available until 6:00 p.m.

Central time through Tuesday, August 5, 2003.

To access to replay, please call 1-800-642-1687 and enter the conference ID number 1553874.

You can also listen to an online replay of the call via our website under the investors section, which we will archive for at least one year.

And with that, I would now like to turn it over to David McClanahan.

Thank you, Marianne.

Good morning, ladies and gentlemen.

Thank you for joining us this morning for our second-quarter earnings call and thank you for your interest in the company.

This morning I will give the highlights for the second-quarter financial results and discuss some key activities in developments.

Following me, Joel McGoldrick, our Vice President of Strategic Planning, will discuss the performance of each of our business segments.

Gary Whitlock, our CFO, who normally handles this report, is on vacation this week.

As we reported this morning, on a consolidated basis, CenterPoint Energy had income from continuing operations of $83 million, or 27 cents per diluted share.

This compares to $86 million or 29 cents per diluted share for the second (technical difficulty) 2002.

Despite the small decline due to increased interest costs, I'm very pleased with our performance for the quarter.

Each of our business segments reported improved operating results versus the second quarter of last year.

We continued to make good progress toward implementing our strategic priorities and positioning the company for the future.

We also made substantial progress in improving our financial stability and liquidity.

As we discussed during last quarter's conference call, we amended our bank credit facility in February, which allowed us to overcome our immediate liquidity concerns and opened up access to the capital markets on much more reasonable terms.

During the first quarter, we successfully raised over $1.4 billion in the capital markets.

We also established a $200 million revolving credit facility at our gas LDCs and pipeline subsidiary, providing that subsidiary with additional liquidity in substantially eliminating its reliance on the parent for working capital needs.

During the second quarter, we continued the momentum and raised almost $1.5 billion in the capital markets.

As a result of these capital market activities, we have reduced our bank credit facility by $1 billion.

By paying the facility (technical difficulty) we eliminated all the warrants which were to be issued in connection with the bank credit facility and eliminated a potential second (technical difficulty).

One common dividend restrictions would cap our quarterly dividend payment at 10 cents per share remains in place.

During the quarter, we continued to pursue the divestiture of non-strategic assets.

We completed the company's exit from Latin America with the sale of the company's 90 percent interest in Edese, a small electric utility company in Argentina.

In addition we are in negotiations to sell our energy management services business, which provides district cooling to businesses in the downtown Houston area.

We have reclassified this business as an asset held for sale and recorded an asset impairment based on the expected sales price.

As a result, we recorded an after-tax loss in the second quarter of $16 million, which is reflected in discontinued operations.

On the regulatory front, the Texas Public Utilities Commission established March 31, 2004 as the date that CenterPoint Energy Houston Electric will file it's true up application for recovery of its stranded costs in regulatory assets.

Although this date is later than our requested date of January 12, we now have a firm date to work with.

The company plans to use the partial stock valuation method to determine the market value of its generating assets.

A partial stock valuation period will now began on October 8, and run for 120 trading days ending on March 30, 2004.

We have also filed a petition with the PUC to terminate the excess mitigation credit which have been in place since January of 2002.

These credits resulted from an order by the PUC to 2001 to reverse the amount of stranded cost mitigation that the company had realized to that time.

The PUCs view in 2001 was that we would not have stranded costs in 2004.

We now believe it is clear that we will have stranded costs and that continuation of excess mitigation credits will unnecessarily increase the amount of our stranded investments.

Through these excess mitigation credits, the company currently credits almost $19 million per month to retail energy providers.

One of our ongoing efforts is to ensure that our gas distribution companies are earning a fair return on investment.

To that end, during 2002 we received approximately $50 million in rate relief, primarily in Arkansas and Oklahoma.

As a continuation to that strategy, in January of this year we filed for a $4.7 million rate increase in Louisiana, and last month we filed for a rate increase of approximately $17 million with the city of Houston.

We plan to file a similar rate release request with the surrounding cities after the rates have been finalized for the city of Houston.

I would like to bring you up-to-date on the status of two unit outages at Texas Genco.

First, you may recall that FTP Unit 1 was taken out of service for a scheduled refueling in March of this year.

Prior to its planned restart in April, a small amount of boric acid residue was discovered the bottom of the reactor vessel.

This discovery resulted in extending the outage until STP determined the source of the residue and corrected any associated problems with the unit.

The repairs at the plant are complete and STP has reloaded fuel into the reactor.

STP presented a report on the repair of Unit 1 to the NRC on July 17, and last night Nuclear Regulatory Commission officials and STP Management held a public meeting near the plant.

STP Management presented a summary of the July 17 report and stated that the plant was safe to restart.

knowledge to the strong support they had received from the NRC and industry experts from around the world in developing inspection and repair procedures for the two cracked bottom mounted instrument tubes that had been the source of the residue.

The repair consisted of removing part of the cracked tubes and seal welding new tubes to the outside of the reactor vessel, thus restoring the pressure boundaries.

The NRC's special investigative team which has been at the site since the discovery of the residue was first reported, stated that the plant had performed a thorough examination of the vessel and had applied an acceptable repair.

They further stated that the leaks could not have been detected at an earlier time and that there was a very low risk of any safety problems with the cracked tubes that were found.

The NRC team stated that the plant would receive their formal answer to our startup request by Friday, August 1.

The plant is in the final stages of preparing to return to service, and we anticipate this to occur later on this summer.

I would like to point out that STP has adjusted the planned refueling outage scheduled for Unit 1, moving the next plant outage from 2004 into 2005.

A second outage occurred on July 15 when a ruptured steam line forced an unplanned shutdown of Unit 8 at our WA Parish Coal facility.

This is a 610 mw baseload unit located southwest of Houston.

A thorough root cause analysis process is underway and a detailed repair plan is nearly complete.

At this point, we estimate that the unit will be out of service through September.

And finally this morning we reaffirmed our 2003 earnings-per-share guidance of 85 cents to one dollar.

This guidance reflects our outlook for continued solid operational performance from each of our business units.

Now I will ask Joe McGoldrick to update you on the performance of each our business units.

Thank you, David.

Before I review the quarter's result by segment, let me point out that beginning this quarter we're reporting operating income for our segments instead of EBIT, which we had reported since the first quarter of 2002.

We are making this change to streamline our disclosure in light of new SEC regulations.

We had a very positive quarter for each of our business segments.

Those segment include the electric transmission and distribution segments, the electric generation segment, natural gas distribution segments, and pipelines and gathering segments.

Let me began our review of the electric transmission and distribution segment.

The unbundled transmission and distribution business, which remains regulated, was reported in our electric transmission and distribution segment.

Also included in this segment is ECOM, which I will explain the minute.

First, let me discuss the results for the ongoing electric business, the unbundled transmission and utility or TDU, which excludes ECOM.

The TDU business within the segment reported operating income of $134 million in the second quarter of 2003, compared to $105 million for the same period of 2002.

TDUs positive results for the quarter were primarily driven by revenue increases from strong customer growth and warmer weather.

We added over 51,000 metered customers since last June, or approximately three percent growth.

And the warmer weather increased revenue by approximate $5 million.

Operating strengths for the TDU declined in the quarter due to savings realized from reduced staffing, the nonrecurrence of transition expenses related to the transition to a deregulated market in last year's quarter, and continued process improvements.

These items more than offset higher pension and insurance costs in the quarter.

In addition, our process improvement efforts contribute to the TDU's $18 million reduction in capital expenditures versus the same quarter last year.

At the same time, the reliability of our system has improved.

The next component of the electric transmission and distribution segment is operating income from ECOM.

ECOM stands for excess cost over market and refers to the stranded costs models developed by the PUC in connection with industry restructure.

Under the Texas electric restructuring law, a regulated utility may recover ECOM in its 2004 true up proceedings.

As David mentioned earlier, PUC suddenly established March 31, 2004 as the company's stranded cost true up filing date.

The company calculates ECOM true up in accordance with the PUC's true up rule, and records on its growth as non-cash operating income and as a regulatory asset for 2002 in 2003.

A breakdown on the calculation in the rule shows the ECOM true up is the difference between one, a gross margin calculated using the option prices from the state mandated auctions and actual generation in fuel expense; and two, the gross margin derived from the PUC's ECOM model.

For the second quarter of 2003, this resulted in ECOM of 101 million, a decrease of 69 million from the second quarter of last year.

So, to summarize this segment, the regulated TDU business continues to benefit from one, solid customer growth; two, operating improvement to cost savings which are mitigating increases of pension, employee benefit and insurance costs; and 3, ECOM, which continues to provide non-cash earnings through the end of this year.

The next segment is our electric generation segment, Texas Genco.

For reporting purposes, Texas Genco will remain a fully consolidated entity of CenterPoint Energy and we report the 19 percent we distributed to shareholders in January, 2003 as minority interest in our financial results.

As you know, we expect Texas Genco to remain with CenterPoint Energy through at least a portion of 2004, when Reliant Resources has an option to purchase of stock we hold.

Texas Genco's operating income for the second quarter of 2003 was $50 million, a substantial improvement compared to a loss of $29 million last year.

As we discussed in Texas Genco's call this morning, the primary driver of the improved second-quarter performance was higher capacity option revenues resulting from a much improved pricing environment in ERCOT.

As was the case in the first quarter, this positive pricing environment is primarily due to increased natural gas prices.

On the expense side, operation and maintenance expenses in the second-quarter increased by $26 million over the second quarter of last year.

Approximately $6 million was associated with higher pension employee benefits, $6 million was scheduled plant outages, $4 million was repairs to Unit 1 at STP, and $5 million associated with the timing of technical support costs.

These increased operating expenses were partially offset by lower state franchise taxes.

Capital expenditures for Texas Genco declined for the quarter to $33 million compared to $90 million in the second quarter of 2002.

Primarily due to reduced environmental expenditures related to our NOx reduction program.

So, to summarize our electric generation segment, we are happy to report a significant turnaround in short period of time, as evidenced by a $79 million positive swing in operating income, in this segments first income producing quarter and continued strong capacity option results.

Now, I wouldn't turn to our natural gas distribution segment which reported an improvement in operating income in the quarter of $10 million as operating income grew to $21 million compared to $11 million last year.

Key focus for us last year was to obtain rate relief in our gas LDCs, especially at Arkla.

Those efforts are bearing fruit as the implementation of rate increases produced revenue gains in the second quarter of $9 million.

In addition, we continue to increase the number of natural gas delivery customers, which increased almost 38,000 since the second quarter of last year.

We also experienced improved margins from our commercial and industrial sales business.

These positive revenue drivers were partially reduced by higher employee pension and benefit expenses and higher insurance costs.

Additionally, the costs associated with a receivables facility, which was modified in November, 2002, reduced operating income by $3 million because prior to the modification, these costs were recorded as interest expense.

We believe our rate relief actions and productivity initiatives reflector strong commitment to improving the financial performance of our gas distribution business and we're starting to see very positive results.

Turning to our pipeline and gathering businesses, we reported operating income of $42 million for the quarter compared to $39 million last year, resulting primarily from an increase in revenues from our gas gathering business.

This segment continues to produce consistent earnings and stable cash flows quarter after quarter, and remains an integral part of our strategy.

In total, then, our business segments produced operating income of $346 million in the second quarter of this year, compared to $289 million for the same period last year.

We remain focused on a continuous improvement in each of our operations and our financial performance, by increasing revenues and enhancing our operational productivity this year and beyond.

And with that, I would like to turn the call back over to David for some final comment before we take your questions.

Thank you, Joe.

In summary, we are very pleased with the progress being made by our businesses. (technical difficulty) continues to implement their respective strategies in support of our vision of being America's leading energy delivery company.

We have improved our financial stability and liquidity and have positioned ourselves to execute our strategic plan.

Our goal is to increase shareholder value through achievement of operational excellence and improve productivity across our businesses, all the while continuing our strong tradition of safe and reliable service to our customers.

Let me end by highlighting the status of several important components of our overall strategy.

We remain on track to deleverage our company through proceeds from the sale of Texas Genco and the recovery of stranded investment.

The Texas law that enacted electric deregulation in Texas and provides for recovery of stranded investment remains intact.

We now have a firm date for filing our stranded cost true up proceedings.

Our recent success in financings allows us to turn our full attention to improving our businesses and earning our regulated rates of return.

We will use the next 18 months or so to re-examine our key processes and business models and make improvements.

We will also continue to see rate relief, where warranted.

I am convinced we will be a stronger company, and one ready to grow, when we finish with these efforts.

Finally, let me reemphasize our focus remains on our core electric gas and pipeline businesses.

We have a good, balanced mix of businesses and a solid base from which to expand.

With that, I would like to thank you for your interest in the company and now I will turn the call back to Marianne.

Thanks, David.

We're now going to open it up for questions.

And so Lisa, I would appreciate it if he would provide everybody the instructions on how to ask a question.

(CALLER INSTRUCTIONS) David Frank from Zimmer Lucas Partners.

Question -- it says according to the press release, CenterPoint booked 233 million of ECOM in the first half of '03.

Could you provide us with a forecast of total expected ECOM for 2003?

David, we don't provide that estimate.

Obviously it will depend on the ECOM model prices and the actual prices as that realize in our PUC auctions.

As we talked in the Texas Genco call earlier this morning, we have completed now all of the auctions for the year, but gas prices and other things that affect the energy component of these prices will determine in part what ECOM is as we go forward.

So we have not made those estimates and we will just have to wait and see how it turns out.

And I want to ask, does CenterPoint have a strategy for getting ECOM securitized?

Have you considered approaching the legislature about reopening SP 7, or some other method?

I think you are referring to a question about whether or not ECOM is truly subject to securitization.

I think that issue has been raised.

Under the PUC rule that is in effect today, ECOM is subject to securitization.

I think a point has been raised whether the law specifically provides for it, and the law does not address it specifically.

It doesn't preclude it, but it doesn't address it specifically.

I would add, though, I think is in everybody's best interest, because we can get lower costs through securitization that in fact we securitize everything that we can.

So today the rule is in effect.

We will follow the rule and I'm not sure why anybody would want to change it.

Okay, which rule is that you're referring to?

That is the PUC rule on the true up proceedings, and it describes specifically how you calculate the ECOM true up, and it provides what is recoverable through stranded investment and securitization.

Okay, because I know the Texas Court of Appeals Third District at Austin came out with a ruling, and they were pretty specific in saying that it delineated ECOM from stranded costs, and went on to say that ECOM and other positive balances associated with other true up items are not securitizable.

It seemed pretty specific, but maybe I need to check the PUC rule.

David, I think that that was not part of their ruling.

There was some discussion, what they called Dicta as part of the order, but it was not ruling and in fact the PUC rule, which is in effect a law once they pass it, specifically provides that ECOM is securitizable.

Okay.

I will check that.

Thank you very much.

Jonathan Rojewski of Goldman Sachs.

Based on the modified timeline here for the filing of the true up application, could you just run through for everybody again what the timeline is going to be for resources option?

And also going forward, for when you may actually get the securitization proceeds based on that new application date?

resources has an option that runs in January 10 through July 24 of next year, so they have a two-week period during which they have to exercise the option if they want to buy Texas Genco.

So no changes there?

No changes there.

We filed on March 31 our true up application.

The PUC has a maximum of 150 days under the law to reach a decision on that application.

So that would put you at approximately August 31, is when the PUC should have their true up order, final order out.

We then would file for our financing order to securitize the stranded costs and that we would do as soon as practical after we get that true up order.

But I guess from a practical standpoint, we are looking at late 2004 or early 2005 to issue these securitization bonds.

Okay.

And then in terms of the timing you have discussed previously for the sale and closure receivable of proceeds from the sale to Reliant Resources, assuming that they exercise the option during that time period, any changes there?

No.

We have to get approval from -- there is about three jurisdictions.

The NRC is one.

They have to approve the transfer of the license.

We have always planned to start that process early, so that would not be a critical path.

Under a recent SEC financing order that CenterPoint received, the SEC will also have to approve the sale, unless we get Texas Genco certified as a D.W.G., which we're planning undoing.

The PUC recently said it was okay with them.

We will now file with the FERC to get Texas Genco classified as a D.W.G.

And then we have the typical Hart-Scott-Rodino approvals which we don't anticipate would be an issue.

So we have always said that could take anywhere from 90 days to 150 days, and so it is going to take a little time to get all those approvals done, but certainly by mid-year if they exercise it, we would hope that that would be closed.

So the list then, David, the NRC, SEC, Hart-Scott-Rodino and I didn't hear you mention the Texas PUC.

Are they precluded from approving that?

I do not think the Texas PUC has to approve the sale.

Brent Foret of Cato Peabody.

I just need some clarification regarding the dividend situation.

How long are you tied to the current dividend rate?

The dividend rate is a provision under our present bank credit facility, which runs through June of 2005.

June of 2005, and after that period time you can make determination whether to increase the dividend or not?

Correct.

Michael Goldberg of Luminous Management.

Just wanted to get a couple of clarifications.

First of all, on the retail fallback, what is the amount of money that ROI should supposedly pay you?

Is it like a 150 million or something?

It will depend on how many retail customers, residential and small commercial customers they have retained.

I think the estimate that I have seen ranges from 150 to $175 million, but it is a calculated number by taking the retained amount of residential and small commercial times what is $150 in the law.

It could be less, but that is the maximum it could be.

Now that will go against the true up, right, should you get that paid?

Reliant Resources is obligated to pay us that amount, but it also reduces the true up amount at the PUC, CenterPoint Energy is not out any money.

No, but that's when saying.

When you get the cash from RRI, that will go to offset the amount you'll securitize?

Michael, that is right.

So it is a wash.

And you expect that payment in January '04, is that correct?

When do we expect the payment?

I think the PUC has to rule and and indicate when what amounted it is, and after that is determined that is when it will be paid.

I think it will be in connection with the true up proceedings.

So as a now it would be more like March '04?

I would say more like late summer of '04.

Okay.

You touched upon capital spending.

I was wondering has the plant changed since last 10-K?

For the next two, three years, or is your expected CAPEX pretty much in line as to what you stated previously?

We have made a couple of minor changes.

I think we had them in our 10-Q, but I think you can look at the 10-K estimates and they are pretty well in keeping with what we thought at that time.

The only area that I think has increased a little bit is in Texas Genco, it went up 8 or $10 million, but as I recall, next year we have a capital budget of about $700 million and we have not changed that estimate materially.

By the way, speaking of Texas Genco, is this September timeframe for Parish to come back, is that best case scenario, conservative, aggressive, or you think there's not much variability?

We are in the early stages there.

We clearly had already started buying equipment and we have engaged contractors, but we have to get in there and really take the plant apart in a certain part and then put it back together.

So we think we know exactly how we will do that, but you have to get in there and actually do the work before you know exactly what you have.

We feel as comfortable as we can at this time that this is a reasonable schedule.

We think it is not particularly optimistic or conservative.

It is hitting it right on the middle.

I appreciate that.

Just one more final question.

There is now a timing mismatch between RRI's purchase option, which is January 10, and true up proceeding, which was moved to March 31.

Just wondering if in your eyes it presents any sort of a risk?

Personally to me it doesn't seem to be large, but can you talk about what potential implications of timing mismatch could be and if you view it as a risk or not?

Yes, the real timing goes to the price that RRI would pay us versus what the market value would be determined by the PUC.

We use the same methodology in the options as does the PUC, but the period changes.

For the option, the period starts on July 22, or started on July 22, and runs through January 10, and you take the highest 30 consecutive trading days, and plus you can add a 10 percent premium to that and that is the price that resources would pay.

The PUC true up starts on October 8, and runs through March 30, so the real risk is that the highest 30 consecutive trading days do not overlap, and CenterPoint Energy has some risks, it can be upside or downside, but it is not assured now that they are one in the same, which obviously we always wanted but it turns out we have a few days difference now.

So that is the risk is that we get paid something different then the market value that the PUC uses.

So the only potential downside is if RRI buys at the base price 24, and then by March 31 the average price has shifted to like 27?

Right?

That would be a downside?

Right.

But there is an upside of like right now if Texas Genco goes up to 27, and RRI will have that price for January 24 -- January 10, but then the price can slip to 24 by March 31, and then you would actually benefit.

Well, that is the way the rule would work.

It is not a given day.

It is during the period.

It's a certain number of consecutive days, but using your example is that if the period doesn't overlap and resources pays the equivalent of $27 a share and PUC uses 24, that is right.

Thank you very much.

Ali Agha with Burnham Securities.

Just a couple of question.

First off, as it relates to the ECOM calculation, now that the PUC has pushed back the true up to March 31, does the ECOM calculation still end in calendar '03 or do you pick it up one quarter next year as well?

I think that the calculation will end at the end of '03.

I see.

And with regards to the other point about the excess mitigation. credit termination, could you give us some timeline how that process is supposed to play out and when you expect a definitive answer back from the PUC?

The PUC just set the procedural schedule for that.

Let me see if I can call that up here and make sure I will tell you the right dates here.

There is in August 26 deadline to determine whether or not this proceeding will go to the office of administrative hearing, and that is in fact set the schedule.

If it goes there for a full hearing, then it is going to be towards the end of the year at the very earliest before we get anything out of the PUC.

There is no schedule beyond that.

There is no statutory schedule that they have to abide by.

They understand the significance of this and we think they will be diligent in taking it through the process.

But later on in August there is a number of deadlines with respect to when intervenors have to file and the staff does have to buy August 13 recommend what their position is on this particular issue.

And just to clarify that on August 22 they decide it does not go to the next level, then does the issue just go away?

They would then take it up at the PUC without going to administrative hearing and we think they would take that up in the middle on September.

I see, so either way the PUC does have to officially rule of his?

Yes, they are going to have to take action one way or the other.

My final question relates to going back to Texas Genco, as the time period gets closer for RRI's decision on exercising the option, can you proactively start to act on the other alternatives you mentioned in the Genco call that you are going to hire a financial adviser and start the process, but are you basically just frozen until RRI decides, or can you do something proactively to try to make that timing as little as possible?

I think we can do a lot of work internally.

We can have data rooms prepared.

We can be completely ready in the event that RRI doesn't exercise.

I don't think we can actively be trying to sell it until the decision by RRI is completed.

So I think we are not going to do a lot externally.

We will be fully prepared so on January 25, if they decide not to do it, we will be off and running.

Phyllis Gray the White Asset Management.

Could you tell me what your cash from operations for the first half was?

Let's see here.

Phyllis, I just was reminded we haven't actually published our balance sheet or cash-flow statement.

It will be in the 10-Q that will be out in just a few weeks, so I think we had better hold off answering that until we get that in final form and published.

David Gomhoth , Copia Capital.

Two questions for you.

First, with regards to interest expense, it looks like year-to-date it has been about $440 million.

With all the financings that you have done, should we look to that number to basically double over the second half or will there be some improvement or some worsening in it?

And secondly when we think ahead to '04, obviously at some point you'll get some proceeds from Texas Genco, but barring that do you expect that number to be significantly different then '03?

I think for the rest of this year it will be pretty close if you just double the year-to-date number.

That will get you a pretty close answer.

It won't be exact but it will be certainly very close.

Next year there's lots of factors, but certainly Reliant Resources, if they execute the option, then interest expense will go down.

I do not expect that we're going to get the securitization proceeds on stranded investments until toward the end of the year at the earliest, so that would not make a substantial impact on 2004.

The main driver there will be the sale of the assets and really whether or not Reliant Resources execute the option.

But there are no excess bank fees or anything like that that might fall away next year and not be in that number?

No, not next year because our bank facility runs through June of 2005, so we are amortizing these bank fees over the life with that facility.

So they will not fall away until '05.

Second question for you, there has been some discussions -- there are some concerns about once you get the securitization proceeds about that cash being trapped down at the utility and unable to pay down the parent company debt.

Can you give us some thoughts about how you're going to work around that so that obviously you don't have excess cash at the utility and excess debt at the parent?

Good question.

I think there has been, David.

First, we have a loan at the utility of $1.3 billion loan that we plan to use part of the proceeds to pay that down.

Unfortunately that does not come due until November of '05.

But a big part of the proceeds will pay down and this is a very high-cost debt, last fall.

We have intercompany loans between the parent and Houston Electric, and certainly we will pay off those intercompany loans.

We can dividend a substantial amount of proceeds and still stay within the 30 percent equity limit that the SEC imposes on each one of our subsidiaries, but perhaps more importantly whenever there is a payable from Houston Electric to the parent in connection with the Texas Genco securitization proceeds, and we will -- that is another way to basically push cash proceeds from the parent up to -- from Houston Electric up to the parent.

And you still think you'll be in a position where when you face a rate case that you won't have a utility with 80 percent equity as opposed to 40 or 50, that the rates would normally be calculated on?

We really target Houston Electric at the 40 percent equity level for rate making purposes.

They set rates based on a 40 percent equity level, and so that is our target.

And we think that in fact we can dividend all the proceeds we need up to the parent and stay within our target there.

One of the things you might remember is ECOM, which is recorded at the electric utility, is earnings.

So basically you just dividend the ECOM up to the parent at the end of this period, once you get your proceeds under stranded investments back.

So we have looked at it hard and we don't think there is an issue in terms of trapping some cash at the electric utility that we can't have, get access to do pay down debt at the parent company.

Zach Schreiber of Duquesne Capital.

Was just curious what the earned ROE was at the Houston utility for the last 12 months, including and excluding ECOM?

We don't really -- I haven't calculated it including the ECOM amount because there is a mismatch between where the investment is.

We filed for 2002, we filed our annual report with the PUC in May of this year.

I think showed we earned about 11.25, 11.3 on equity, which is right in keeping with our authorized returns.

And on that return equity was set as part of the whole unbundling process and the approval of the business separation plan and is not subject to any change during the pendency of the whole --

It was set in connection with establishing the new delivery rate for the electric utility, which was in mid '01.

I think it was in April or May of 2001, so it is not subject to change.

It will only change when we go back in to reset rates again at some point in time.

But that is I think pretty firm number.

Can you go in for any rate relief or are the TND rates totally set as per the regulatory approval of your restructuring plan under the auspices of Senta Bill 7 ph?

If we in fact would not be earning our authorized return, we could seek to change in rate there.

We have the full authority and full rights to do that.

There is no limitations on us seeking regulations.

And so that higher rate relief which is would be a margin squeeze for RRI, were you to be successful, right?

If we would increase our delivery rate, Reliant Resources as well as all other resell energy providers would pay more.

But as I said last year, we were earning our authorized return and we don't anticipate any type of filing in the near-term.

And that authorized return again excludes the whole ECOM calculation?

That is correct, no ECOM.

And from a securitization perspective, there has been some discussion as to whether or not any wires charges that could theoretically be implemented as part of an ultimate securitization of ECOM would be embedded within the price to beat, or would be additive to the price to beat?

Well, Reliant Resources probably is in a lot better position to answer that.

I think certainly the PUC has the right to increase the price to be for any increase in the stranded costs surcharge.

And I think that they've just recently passed a rule there, but I'm going to have to refer you to Reliant or somebody else, but certainly the PUC has the authority to do that and I think they have indicated they would.

But just as far as this whole excess mitigation credit goes, all that is cash or non-cash?

It is all cash.

It doesn't impact earnings, but it impacts cash.

So it is real cash and fake earnings.

So it is real cash and that effectively just gets lopped into the whole ECOM calculation for ultimate securitization?

No it really doesn't.

It is not like ECOM.

It is truly just a balance sheet item at this time, so it doesn't have any impact on earnings, but just affects our cash flow.

Okay, and hypothetically as far as the whole equity ratio cash trapped, as the utility goes, is the company willing to give greater details on all these intercompany loans, intercompany payables that could be effectively extinguished and be a mechanism for cash to flow up from the utilities to the parent company because it is such a vital issue.

It would be great if you could give us more information as to how the cash actually moves up.

I tell you, you will know the status at a point in time because we filed a Houston Electric 10-Q, and it will show the intercompany notes to the parent, but we have to wait and see what those notes are at the time that we actually get the money back or do the securitization.

Our forecast suggest that we don't have a major problem losing cash around between the companies.

A major problem doesn't mean --

I shouldn't say that.

We don't have a problem.

I chose my words wrong.

Is there any possibility of were there to be a problem getting a waiver from the SEC?

We have seen a couple companies get waivers on minimum equity ratios.

Is that part of your --

The SEC -- we presented the plan.

They (technical difficulty) equity ratios are today and they also look through to the end of this transition period and they know what they will be once we sell Texas Genco and we get through the securitization.

So we don't need a waiver.

They are fully aware of it and -- we have presented our financial forecasts showing what we will look like at the end of this transition period.

John Simmons with River Capital Advisors.

I noticed that the throughput of commercial industrial sales was up somewhat and then there was also a comment that margins in that business had expanded somewhat in the quarter.

Can you give any more detail or color on the growth of that business going forward and what, if any, price risk exposure you take?

Well, most of the commercial industrial, not all of it, is unregulated gas sales.

Primarily in our LDT footprint, but not completely in our LDT footprint.

Almost all of this is physical sales of gas.

We do, on behalf of our customers, enter into financial derivatives if our customers are wanting to lock in a given gas price, for example.

We sell some wholesale, but most of our business is retail.

I think most of the increases you saw in the throughput related to some wholesale transactions that were conducted in the second quarter.

It was physical gas.

It was not financial derivatives.

And as on most businesses, when you have the volatility that we saw in the gas markets, that creates some opportunities for a little larger margins than you otherwise would have, and so you saw some margin increase in the second quarter.

So this is more of a onetime growth and we shouldn't expect to see that level of increase going forward, I guess?

I would say that part of that absolutely is solid, but this is a business that we continue to put a lot of focus on, and we see that can add to the growth in the business.

But probably the type of -- the second quarter was a little bit unusual just because of the volatility in the gas markets.

Chris Melindas UBS Principal Finance.

You indicated that to sell Texas Genco that you would need NRC approval, SEC approval and Hart-Scott-Rodino.

How would that approval process or regulatory process change if you were to sell the plants individually at Texas Genco?

You don't have all of the same issues.

As a matter-of-fact, I'm not sure that if you sell the nuclear plant, you always have to go through the NRC.

That is in any case, so that is going to be there.

But if you sell the individual baseloads or gas-fired units, I don't think -- you don't have the same SEC requirements.

As long as -- if there we get EWG status, we don't even have to get the SEC approval.

So I think selling hard assets, you have a lot more streamlined regulatory approval process, but for the nuclear plant, you still have the NRC approval that is required.

Didn't you have to file with the Texas PUC indicating what method you were going to use to liquidate Texas Genco, and would you have to change that with the Texas PUC at all?

No, it wasn't -- we did tell them what we planned to do.

What we really have told the PUC is that we plan to use the partial stock methodology in determining the market value for stranded investment purposes.

If we don't sell it, we can still determine stranded investment, and we'd still use that same methodology.

So it is really not around how we liquidate it; it's how you determine the value of our generating assets.

That is helpful, thanks.

Chris Melindas with ABN Amro.

My question was actually along those same lines, so I will just elaborate slightly on it.

Is it your position that regardless of whether or not anybody purchases the entire Texas Genco from you, that you would want to use the partial stock valuation method for determining stranded cost and that the PUCT would allow you to use it?

Yes, Peggy, it is our determination at this point in time that we do want to use the partial stock valuation methodology, and I think the PUC in fact has accepted that.

As part of the approval of our business separation plan, they approved that.

If we wanted to change, I think we would have to refile our business separation plan and indicate that we were going to change methodologies.

At this time, we do not anticipate doing that.

Could we do it at the time?

Yes, but it would delay -- we would have to get some delays in our filing, and I don't think that is likely at all.

So it is our position today that we are going to use the partial stock valuation methodology and the PUC will accept it.

And if you were to change your mind on that point for whatever reason, would your change of heart on that really have to be after RRI had said yes or no?

I think that is right, because if they said yes, then we absolutely have to use partial stock.

If they said no, then I guess we could rethink it, but I think that is highly unlikely, but it would be under the scenario where they said they did not want to execute the option.

Mark Finn with T. Rowe Price.

Could you tell us what the remaining book value is in the CenterPoint Energy Management Services unit, and where that resides in the capital structure, that unit?

Let me give you a range here, Mark.

If I am not mistaken, it is in the 45 to $50 million book value range.

And it is in -- where is it recorded, Jim?

It rolls up in corporate and other.

Corporate and other books.

And a couple of follow-ups on the pipes and gathering.

Under pipes and gathering, you reduced your operation and maintenance expense from 38 to 30 on a year-over-year basis.

Can you tell us a little bit about how you did that?

That is a little bit of an anomaly.

We have a Pipeline Services division as part of our pipeline group, and they had a major project they did last year and they had a fairly large cost of sales of that project, which was also reflected in the revenue.

So net-net, it is not nearly the decline that it appears.

Yes, I noticed sequentially it was about the same as the first quarter.

I was just curious.

And one last question is, in the C&I gas supply business, could we infer that your customer count there and customer base is relatively steady?

There was some concern last fall when CenterPoint Energy Resources went to Ba1 that there would be some customer fallout.

And could you just comment on the stability of your customer base at that unit?

We have had a very stable customer base there.

We have not seen any fallout of any significance, to be very honest.

I think we have a pretty solid customer base there and have seen very little significant change.

It has mainly been up, not down.

Great, thanks a lot.

Mark, let me also mention that when you look at the balance sheet at the end of June, you will note that this management services has already been written down.

I was talking about the gross book value before the write-down.

Before, okay.

David Frank with Zimmer Lucas Partners.

I just wanted to follow-up on Zach's question on the utility he was asking about, the return on equity, and you guys highlighted your earning around the authorized return.

So I guess my question is, how does the utility that is currently earning that's allowed return profit from securitization of the proceeds that are going to pay down debt or buy back stock?

Because it would appear to me that if you do dividend money to the parent, you are obviously reducing your equity ratio and increasing your return, or if you pay back intercompany loan, you are effectively lowering your interest expense, which would push up your earnings.

And if you pay down that buffet loan, that's about $170 million a year.

So is there kind of a strategy for how you will capture and keep the savings associated with the securitization at the utility?

A couple of things.

Remember, I said the numbers excluded ECOM.

We recorded $697 million of ECOM last year, and (technical difficulty) this year.

That is outside that.

That is earnings on the utilities books they can clearly dividend up to the parent.

Secondly is the buffet loan was not taken out until late last fall, so it is not fully reflected in the earnings of the utility last year.

It will be going forward, and certainly it is going to depress, as you see in these results, the earnings.

And so we do, in fact, want to pay off that loan and it will, in fact, permit us to continue to enjoy our authorized return in doing that.

So I think there is lots of things going in and out of there.

You have to kind of model it to fully appreciate the inflows and outflows, but just keep in mind some of the financing did not occur until late last year.

Okay, and that ECOM, is that going to be treated as a dividend from the utility?

I'm not saying the cash will be trapped there, but would it still have the results of reducing the equity of the utility if it's a dividend?

You would, but whenever we look at the utility, we exclude the ECOM earnings as part of the retained earnings.

So the cap structure has more equity in it than just the utility itself would require, because of these ECOM earnings.

I guess the only thing that puzzles me, and according to the FERC, and I know you've got differences between GAAP and regulatory books now, but I think your total capitalization at the utility is somewhere around 3.5, maybe just south of 3.5 billion if you're taking in -- you're going to be hopefully taking in more than 3.5 billion of proceeds.

So at some lap it will the entire utility down to zero.

Yes, and obviously, we won't do that.

Our goal is to maintain the proper capital structure at the utility, which is in our view 40 percent equity which is the way the rates are set.

You could go a little lower than that if you had to, but certainly you can't get below 30 percent based on SEC rules.

Maybe we have to in some way try to get some more clarity around exactly the capitalization at the utility to give people more comfort on this, but we studied that pretty hard and we believe we can move the necessary money out of the utility to the parent, which will then pay down debt and maintain a proper capital structure at the electric utility.

Well, I guess it's a high-cost problem to have.

Yes, we're looking forward to those days, you know, to getting the money back and then having to worry about paying down the debt.

Thanks a lot.

I think we're running somewhat over time on this call, so I think we're going to end it right here.

And I wanted to thank all of you for participating in the conference call this morning.

We appreciate as always your attention and support, so have a great rest of the day.

Thank you.

This concludes today's conference.

You may now disconnect.

(CONFERENCE CALL CONCLUDED)