CMS能源 (CMS) 2003 Q4 法說會逐字稿

Good morning everyone, and welcome to the CMS Energy 2003 financial results and outlook call.

This call is being recorded.

Just as a reminder, there will be a rebroadcast of this conference call today beginning at 1:00 P.M.

Eastern Time, running through March 19.

The presentation is also being webcast.

An audio replay will be available approximately two hours after the webcast, and will be archived for a period of 30 days on CMS Energy's website in the Invest in CMS section.

At this time, I would like to turn the call over to Laura Mountcastle, Vice President Investor Relations and Treasurer.

Please go ahead.

Thank you.

Good morning and thank you for joining us.

With me today are Ken Whipple, Chairman and Chief Executive Officer;

Dave Joos, President and Chief Operating Officer; and Tom Webb, Executive Vice President and Chief Financial Officer.

First, I'll read our disclosure statement.

This presentation contains forward-looking statements.

Actual results may differ materially from those anticipated in such statements, as a result of various factors discussed in our SEC filings.

The presentation also includes non-GAAP measures when describing CMS Energy's results of operations and financial performance.

We have prepared a reconciliation of these measures to the most directly comparable GAAP measure in our earnings release, posted on our website at cmsenergy.com/invest.

A copy of this presentation is also posted on the website.

I will now turn the call over to Ken.

Thanks, Laura, and good morning, ladies and gentlemen, and welcome to our year end earnings call.

I'm going to start today's call with a brief look back on some of the major accomplishments in 2003, and then discuss our priorities for 2004.

Next, Dave will review the exceptional operating performance of our company and bring you up to date on the status of the regulatory issues that have been a focus with us: The gas rate case, securitization, stranded cost recovery and the resource conservation plan.

Tom Webb will then walk you through the financial results for 2003 and introduce our guidance for 2004.

Most of you already know this, but to spare any suspense there, we'll be discussing ongoing earnings of about 85 cents, up about 5%.

Then finally, I'll show you an outline of our 2004 financial report card before we open up the call for your questions.

Last year was an important turnaround for this company.

By most measures, 2003 was a solid year of financial and operating performance.

We strengthened the business by focusing on first things first.

Our top priorities had to be liquidity and cash flow, building what we called during the year with you all "liquidity peace", so that we could focus more on running the businesses.

I think our team did a spectacular job on that.

We did $3.8 billion of financing, extending debt maturities and lowering interest costs.

Some observers didn't think we could do that.

We also sold 15 nonstrategic assets raising about $850 million of net cash, a heroic achievement by our divestiture team.

We completed another internal cost reduction program that offset about $60 million of increased costs.

We lowered capital spending by about $300 million.

And in the process, we paid down more than $1 billion of debt and contributed $560 million to our Pension Fund, which is now fully funded for current obligations.

We reduced business risk further by getting out of the wholesale trading business, and we eliminated roughly $500 million of guarantees and other commitments.

We had another terrific year in operations, which Dave will cover with you in a minute.

And most important, we delivered on most of the financial commitments that we made to you, our shareholders, last year -- and I'll cover those briefly on the next slide.

As you might remember, our management team established this report card to track and measure our 2003 commitments.

We didn't bat 1,000, but we did pretty well.

For the second consecutive year, we reached our earnings target.

And as I mentioned a minute ago, our liquidity achievement, in total, far exceeded our expectations.

We did miss by about $50 million on the asset sales target, mostly because the year was only 12 months long.

What I mean by that is, a few of the sales are taking a little longer.

But as we'll discuss shortly, we expect to complete them this year.

On capital structure, as Tom will show you, the accounting standards people keep us all busy changing the definitions of debt and equity.

Nevertheless, on a comparable basis, we beat the debt to capital target of 75%.

That reflected the debt reduction, the big contribution to our pension fund that I mentioned, and our convertible preferred issue.

And obviously, of course, we have to keep this improvement going in the next few years.

Overall, we ended the year smaller but healthier, with a very good base to build on this year.

And our plan for 2004 has not changed.

The utility-plus focus is still the name of our game.

We'll continue to focus our efforts on growing our utility, which is the cornerstone of this company.

Also, though, we'll continue to optimize our investments in key non utility assets, assets like Jorf Lasfar in Morocco, Altolilah (ph), Tacarati (ph), and a select number of other enterprise businesses -- basically, the assets that provide good contractual cash flow from credit-worthy customers.

Our focus on cash flow and earnings can never let up.

And as I covered with you last year, our bonus program in 2003 for all salaried employees focused only on cash flow and earnings, and we're going to extend that successful program this year.

As Dave will cover with you, progress has been agonizingly slow on some of our regulatory issues.

We are not in control of the timing here, but we need to redouble our efforts to pick up the pace.

And though the timing on legal issues isn't within our control either, we need to continue progress on getting these behind us.

And finally, we wouldn't be anywhere as a company without our operational excellence.

We know we have to work hard to keep customer service at best in the business levels.

And with that, I'll turn to Dave to talk a bit about operational excellence.

Dave?

Thanks, Ken, and good morning to those on the call.

As Ken said, we had an exceptional year in operating performance.

Our power plants, both at the utility and in our independent power business, set a number of records.

At consumers, internal generation was the highest ever, as was the availability of our coal plants at 89%.

We also burned a record 71% western coal, which allowed us to keep our coal costs about $30 million lower than they were a decade ago.

Our Palisades nuclear plant also had an exceptional year, achieving its shortest ever refueling outage and its highest ever capacity factor during an outage year.

Palisades has now been on line continuously for 325 days, the second longest run in the plant's 34-year history.

It's currently operating at full power and expected to set an all-time continuous operating record on March 23rd.

Our non-utility fleet also had a record year, achieving over 90% -- or 92% availability.

On the distribution side of the utility, we were pleased that our gas business was, for the second straight year, awarded the JD Power Award for best customer service among Midwest gas utilities.

Our electric business was successful in achieving all ten performance standards recently established by the Michigan Public Service Commission.

These include metrics around service reliability, outage response, call center performance, meter reading and others.

Cost management was also excellent, including management of fuel and power supply costs, which, because our rates were frozen for the entire year, allowed us to offset sales losses due to mild summer weather and continued growth in customer shifting to third party suppliers under Michigan's Electric Choice Program.

Incidentally, like other utilities, we are currently experiencing about a 60% increase in the cost of eastern spot coal to over $50 a ton.

While we are over 90% contracted for this year, our production plan for 2004 does require the purchase of about a half million tons of eastern spot coal, so the higher price will result in an estimated $10 million of increased coal cost.

About 40% of that or $4 million pre-tax, would hit our income statement, due to the continuing cap on small customer rates.

The remainder will be recovered through our fuel cost adjustment clause.

Finally, our environmental program continued to meet or exceed expectations, including the performance of our newly-installed nitrous oxide removal systems.

Our regulatory agenda remained very full; and frankly, not as much progress was made as we had hoped on several key issues.

We were pleased that the Public Service Commission granted interim rate relief in December before the bulk of the winter heating season.

While it did appear somewhat meager at $19 million compared with the staff’s recommended $80 million relief, it's important to note that the Commission simultaneously approved an interim reduction in our book depreciation rate without reducing our customer rates, resulting in a $34 million annualized pre-tax earnings improvement.

Also, our filing and the staff's recommendation both assume that we would not continue our appliance repair program into 2004.

This program generates about $14 million in annual margin, and is allowed to continue through mid--year, pending expected passage of legislation that will allow it to continue indefinitely.

The annualized impact of these three items totals about $67 million.

Of course, the final rate order, which is expected in the second quarter, and the final order in our depreciation case, expected this fall, will affect the financial performance of the gas utility for 2004.

Most of you are likely aware that the administrative law judge hearing the gas rate case issued a disappointing proposal for decision late last week.

In a nutshell, he did not support any increase in rates.

His proposal was based on lack of support for the use of forward test year projections.

Instead, he focused on 2003 financial results for the gas utility, which were admittedly good, due to favorable winter weather and tight spending controls.

We can't predict what the Commission will do in this case, obviously.

While I am concerned about the law judge's proposal, I would also note that the Commission's decision on interim relief, with the same basic information in hand, was inconsistent with the law judge's recommendation, and we continue to believe that relief is merited, and trust that the final order will be fair.

On the securitization front, you will recall that we received an order last summer authorizing the company to issue $554 million of bonds, mostly associated with Clean Air Act related capital expenditures.

Unfortunately, the surcharge design in the order did not meet the test for bypassability, so that the bonds could not be marketed with a AAA rating.

While there was quite a delay between our rehearing request and the scheduling of hearings to consider these issues, both hearings are now underway and should result in a Commission order in the second quarter.

Assuming a favorable outcome, we would likely be in a position to market the bonds this fall.

Progress on stranded cost recovery has also been slow.

Hearings in our 2002 case, which were delayed through most of last year as we participated in an unsuccessful effort led by the NPSE staff to reach a settlement, are now underway.

Recall that our filing, which followed the methodology recommended by the Commission staff and endorsed by the Commission, resulted in estimated stranded costs of 35 million to 103 million, the lower number based on the assumption that costs associated with Clean Air Act compliance are recovered through securitization rather as part of stranded cost.

Also, we'll be filing our 2003 stranded cost case shortly.

Those of you who follow DTE will be aware that the Commission issued an interim order in their general rate case a few weeks ago.

In that case, they established for the first time a stranded cost surcharge, 4 mills, and also eliminated credits, averaging about 8 mills to the bills of customers participating in Michigan's Customer Choice Program.

Also, last Friday, the NPSE staff filed testimony in the DTE rate case that we view as positive with respect to addressing concerns with Michigan's Electric Choice law.

We are encouraged by these developments, and we plan to file shortly with the Commission to request similar interim treatment pending final decisions in our stranded cost cases.

I remind you that we have been conservative in our stranded cost recovery assumptions, and we have not accrued any regulatory assets for prior years recovery.

I'll be happy to discuss the situation further in response to questions you may have at the end of the presentation.

New to our regulatory agenda is a filing we made in mid-February asking Commission approval for a change in how we dispatch the Midland Pro Generation Venture and how we recover associated capacity payments from our customers.

We refer to this as a resource conservation plan.

In a nutshell, we are asking the Commission to allow us to dispatch the MCV based on the cost of natural gas, the fuel that the MCV burns, rather than on the coal-based energy payments the utility makes to the MCV under our purchase power agreement.

Because the cost of natural gas has escalated so dramatically in recent years while the utility has actually reduced its coal cost, the change is necessary to reduce substantial reduction in the financial performance of the MCV, which is 49% owned by the utility.

The good news is that our proposal does not require any increase in customer rates, and conserves an estimated 30-40 billion cubic feet of gas per year -- hence the title, "The Resource Conservation Plan".

Given the concern about gas supply costs and reliability in the state, we are optimistic that this proposal will be attractive to the Commission.

The agreement between the MCV and consumers would result in sharing of the estimated $60-80 million pre-tax annual savings associated with the initiative.

Obviously, the outcome and timing of regulatory relief on this issue is significant to our 2004 plan, which assumes approval in the second quarter.

We've asked the Commission for expedited relief on our request.

The Commission has set the prehearing conference for April 13th, at which time we'll have a better feel for the schedule.

Finally, we are currently preparing an electric rate case for filing later this year.

We plan to use a 2006 test year in our filing, and would expect to have an order in that case in time to implement new rates in January 2006, after the rate cap on residential electric rates ends.

As Ken said earlier, we fell just short of our goal of raising $900 million in net proceeds from asset sales in 2003.

That was not generally because assets sold for less than we planned, but because sales processes generally took longer to complete than planned, and several spilled over into 2004, including our power plant and pipelines in Australia.

For 2004, we have a much more modest asset sale plan.

The sale of the Gold Fields and Parmelia [PHONETIC] pipelines in Australia are well along.

We hope to close Parmelia in the second quarter and Gold Fields later in the year.

Many of you are aware that the Loy Yang -- of the Loy Yang sale development.

Now that the Australian Competition Commission objections are behind us, the biggest hurdle to completing this sale is a reasonable decision from the state of Victoria regarding stamp taxes due on the sale.

I continue to be optimistic that the sale will get done this year, but it's certainly been difficult and still somewhat uncertain.

Finally, we are working hard to sell our remaining two power plants in India, GVK and Neyveli, and our Seneca distribution utility on Marguerita Island off the coast of Venezuela.

It's a little too early to predict when those might close, but we're optimistic we can get them done this year.

In total, our cash plan assumes we raise about $160 million in net asset sale proceeds in 2004.

Now I'll turn the presentation over to Tom Webb to review our financial performance and guidance.

Tom?

Thanks, Dave.

As Ken mentioned, we made progress improving our financial health in 2003.

We delivered on our ongoing earnings target, but early on we recognized that our asset sales plan and pension costs likely would keep us from being profitable on a reported basis.

We did, however, beat our guidance, a loss of $1 a share established last summer.

As Dave mentioned, we ran out of time to complete our aggressive asset sale goal, but we blew away other liquidity goals.

Hard work on earnings, core working capital and capital spending made the difference.

For example, we established a tough low-capital spending target and then we beat it.

This performance allowed us to make further progress towards shaping up our balance sheet.

We reduced debt by $1.1 billion to $6.2 billion, and we cut our debt to capital ratio from 75% to 70%.

Please turn with me for a closer look at earnings.

Excluding asset sales and restructuring costs of 59 cents, pension settlement charge of 25 cents, accounting changes totaling 16 cents, and 11 cents for settlement of the CFTC investigation, ongoing earnings were 81 cents.

This is a bit better than the First Call average.

As expected, this is below results for 2002.

Before selling our Panhandle and field service businesses in 2003, we earned $1.53 a share in 2002.

Without Panhandle and other discontinued operation changes, earnings were $1.06.

Throughout 2003, we've worked hard to improve our business and the quality of our reporting.

We take seriously the Sarbanes-Oxley legislation, and we have scoured our books and processes for issues.

In doing so, we discovered that documentation from a few years ago was not up to snuff for nine derivative instruments at two of our minority-owned businesses in the Middle East.

Accordingly, we now have charged to net income rather than other comprehensive income, changes in fair value for these derivatives.

This reduced earnings by 22 cents in 2002.

Proper documentation now is in place.

Detail of the restatement is included in our 2003 10-K.

On a comparable basis to 2003, earnings were 84 cents in 2002.

Lower results for 2003 reflect higher interest expense of 25 cents, largely around the bridge financing that we completed last March, and dilution of 7 cents associated with more shares outstanding.

Revenue is down 3 cents, reflecting mild summer weather and more customers choosing alternative suppliers for power.

This was offset in part by the full year effect of higher gas rates approved in December of 2002.

We offset most of these declines with hard work to reduce fuel and power supply costs, good performance at our enterprise projects and other improvements, including lower taxes.

Now let's turn to our guidance for 2004, as Ken highlighted.

Because of losses associated with asset sales, we expect to report a loss of about 50 cents in 2004.

Again, that's on a reported basis.

The amount will depend a lot on the timing of planned asset sales.

For example, we hope to complete the sale of Loy Yang, as Dave mentioned, our IPP business in Australia, this year.

When this occurs, we'll need to recognize a charge to income of $110 million.

That's about 70 cents a share, and that allows to reflect the Loy Yang-related flowing currency translation account balance.

Excluding the adverse earnings impact from asset sales and certain legal costs, as well as favorable earnings from pre-2004 savings associated with expected securitization this year, we project ongoing earnings of about 85 cents a share.

This will be up 4 cents, or about 5% from last year.

In the next two slides, we'll go through our projections for the utility and the enterprises business unit.

In addition to the business unit's performance, interest expense will be down substantially, reflecting lower average debt and more favorable interest rates as a result of lower cost financing put in place last year.

You can see that on the right box of this slide.

At 7.8%, our average parent interest rate is 84 basis points below where we were last year.

At our utility business unit, earnings are forecast at $1.45 a share, down from $1.56 last year.

Higher interest expense associated with increased investment, coupled with share dilution, will reduce profit by 21 cents.

As we exit the electric rate freeze of the last 3.5 years, we're not able to retain fuel and power supply cost savings like those we accomplished in 2003.

We are permitted to defer certain capital expenditures in excess of depreciation; but in total, exiting the rate freeze will reduce earnings by 16 cents.

Higher depreciation, property taxes and other will add 1 cent of expense.

Planning for normal weather, organic growth and a rebound in the Michigan economy adds another 30 cents to earnings.

This ,however,is offset in part by more electric customers choosing alternative suppliers, resulting in a load loss in excess of 1,000 megawatts compared with 647 megawatts at the end of last year.

The full year effect of rate relief established on an interim basis late last year provides a further earnings improvement of about 8 cents.

At our enterprise business unit, we forecast earnings of 60 cents a share, that's down from 78 cents in 2003.

We expect lower project earnings, about half of which reflect foreign exchange gains in 2003 that we don't expect to be repeated this year.

This also reflects a planned outage at (indiscernible), the marked-to-market impact of certain derivatives and profits in 2003 not repeated in 2004 due to assets sold.

Lower taxes and cost reductions improved earnings 6 cents.

Importantly, our enterprises businesses will generate dividends of $100 million -- that's a third of total dividends to CMS.

In addition, our Atacama business in Chile may distribute $100 million to CMS after completing an important project financing.

We believe our earnings forecast is balanced.

But please turn with me to the next slide for a sample of changes that could impact our results.

Each 100 gigawatt hour change in electric deliveries can change our EPS by plus or minus 2 cents.

A 10 Bcf change in gas deliveries would change profits by 6 cents.

In our plan to conserve MCV gas resources, if that's approved and delayed by a quarter, we could lose earnings of 3 cents in the spring shoulder period, or 4 cents during the peak load summer months.

Should load loss associated with customers leaving for alternative suppliers change by 100 megawatts up or down, earnings would vary by about 4 cents.

Sensitivities to changes in commodity prices and interest rates also are shown on this slide.

We hope these rule of thumb estimates will help as you assess our business.

Let's turn from earnings to cash flow.

As shown on the right box of this slide, consumers will generate over $790 million of cash flow to cover most of its capital expenditures, interest and dividends.

With planned financing, we expect to end the year with 50 million of cash and $295 million of available bank facilities.

At the CMS parent, shown on the left, dividends from consumers and enterprises of about $300 million more than covered interest and preferred dividend requirements of $230 million.

Including asset sales and project distributions, we'll be able to further reduce parent debt and invest in consumers.

We expect to end the year with about $360 million of cash and an unused bank facility of $190 million.

But please keep in mind that we have $180 million note that matures on January 15th of 2005.

Efficient levels of capital expenditures have been an important part of our debt reduction plan.

Compared with the last three years, capital spending is down 29%.

This includes spending levels at consumers that are substantially below plans in place only 18 months ago.

Expenditures this year will be about $90 million higher than in 2003.

This is due largely to clean air requirements, refueling costs at Palisades, and maintenance at the utility.

In 2005, spending will be down by about $75 million.

By 2006, we estimate the need for higher investment related to NOx standards, as well as new mercury emissions standards.

Also, we assume we will move ahead with a 20-year life extension at our Palisades nuclear plant.

In addition, we'll install new fly ash handling equipment at our current plant, and conduct other routine plant outages.

Let's turn to capital structure.

As shown on the box on the right, we've reduced consolidated CMS debt from $8.3 billion in 2001 to $7.3 billion in 2002 and $6.2 billion last year.

That's a 25% reduction in two years.

For 2004, we target debt without securitization at $5.8 billion.

This would improve our debt to capital ratio from 78% in 2002 to 68% this year, as you see with the checks.

This reflects physical improvements; but as most of you know, new accounting standards now require that certain equity-related financing be treated as debt.

Based on these new accounting standards, we'll switch $664 million of trust preferreds from equity to debt.

As shown with the dotted lines in the box above, this will increase our reported debt for 2003 to $6.9 billion, and for 2004 to $6.5 billion.

Debt to capital would be 76% compared with 78% last year.

These will be our new reported measures.

This accounting change, however, does not impact our CMS indenture covenant.

At 72%, it's 3 points below the covenant of 75%.

This next slide shows near term debt maturities at the CMS parent.

We already have retired $242 million of debt due this year.

The next significant maturities are in the fourth quarter of this year and early in 2005.

For consumers, our next maturities are a year away, including a $300 million note on March 15 of 2005, and a $141 million note on June 15 of 2005.

Frequently, we are asked about how we'll continue to reduce debt at the parent.

With this slide, I'll highlight tools that allow us to cut our debt about in half over the next several years.

Over that time period, interest, as well as preferred and common dividends, shown in red, are covered by dividends from consumers and enterprise subsidiaries, and these are shown in the cross hatch portion of the green bar.

Several other tools provide cash to reduce debt.

Incremental asset sales and insurance settlements could generate between 2 and $300 million.

Project financing can provide additional cash.

We only have about $100 million in our plan, but work is underway to accomplish a bit more.

Tax sharing between consumers and the parent can provide substantial cash to reduce debt.

As consumers generates earnings, CMS can offset its interest expense and other losses against these taxable earnings.

Finally, the use of existing cash balances also can reduce debt.

Not shown on this chart is any change in equity.

As we've talked about over the past many months, CMS likely will issue stocks some time in the future.

This can be used to further reduce debt, or to grow the back-to-basics businesses.

Our debt reduction plan is well underway.

And on that note, I'd like to turn it back over to Ken.

Thanks, Tom.

And here's a look at our financial report card for 2004.

On ongoing earnings, as you've seen, we are looking at about 85 cents a share.

On the cash front, we've set two targets this year.

Our cash flow from operations before capital spending is pretty strong at $535 million.

Our capital expenditures will stay high, though, as you've seen, partly because of Clean Air requirements.

This will require a small financing of about $100 million at the utility, which is contained within our plan.

Our liquidity target remains the same as last year, but because we are able to rely more on our revolvers, we don't have to keep as much real cash around.

To reflect our continued focus on reducing debt and improving the balance sheet, we've added several targets this year.

The debt to capital and debt target is tied to the numbers that Tom showed you earlier.

And finally, we've also added an interest coverage ratio to the report card to reflect our focus on cash flow, as well as to respond to some of your requests.

And here we are back at the slide that I covered in the introduction, which outlines some of our important 2004 priorities.

It seems like an appropriate backdrop to leave on the screen as we open up the meeting for your questions, which we'd like to do now.

Thank you very much, Mr. Whipple.

The question and answer session will be conducted electronically.

If you would like to ask a question, please do so by pressing the star key followed by the digit 1 on your touch-tone telephone.

If you are using the speaker function, please make sure your mute signal is turned off.

We'll proceed in the order you signal us, and we'll take as many questions as time permits us.

Please press star 1 on your touch-tone telephone to ask a question.

If you do find that your question has been answered, you may remove yourself by pressing the pound key.

We'll pause for just a second.

Your first question comes from Asher Cab (ph) from Forsythe.

Please proceed sir.

: Good morning, and congratulations on a good year.

Good morning, thanks.

I wanted to just touch base on the gas recommendation by the ALJ.

I guess, reading the recommendation, it seems to be a very strong support in terms of its argument, and the way I see it, if I'm right, Judge Regis is probably one of the longest serving ALJ, and he's very well respected within the Commission.

And in reference to the strong points that he has raised in not using prospective tests here in terms of O&M spendings being cut after the last rate case decision and all that.

What can -- what are you going to be providing as part of the rebuttal testimony to sway the Commission in their ruling to basically give you the revenue requirement?

And secondly, can I just check with you what kind of rate increase have you built in in your forecast for '04?

This is Dave Joos.

Let me respond to that a little bit.

I certainly can't predict what the Commission will do with Judge Regis's recommendation.

And as I tried to highlight and you commented on in your question, clearly, his recommendation assumes that the Commission doesn't use any kind of projections in the course of determining what rate relief is appropriate.

We don't think that's proper, primarily because it's clear -- and we've made no bones about the fact that we've conserved cash and kept our expenditures down over the course of the past couple of years; however, we do need to spend more money on the gas system and respond to things like the new pipeline safety act and things of that nature.

And we're hopeful that the Commission will look at the facts and understand that additional relief is necessary, and make sure we can operate our system well and earn a fair rate of return.

The final analysis of the numbers, by the way, for 2003 -- we're going to be reporting to the Commission, I think, single digit numbers in terms of rate of return on equity, which is lower than the allowable that they set at 11.4.

So when we think all the facts are out on the table and when the Commission considers our circumstances and the need to increase expenditures on a go-forward basis, as I said in the comments, we trust that they'll deal with this issue fairly.

In terms of our assumptions for a 2004 plan, right now what we've assumed is a continuation of what's been done to date.

We -- of course, the Commission staff's recommendation is better than that; and, again, we think more relief than that is merited, but we've been somewhat conservative in our planning.

So the 8 cents that you're showing an increase, if I'm right, that was based on the -- if I heard it right, it was based on the gas, the rate relief (indiscernible) at the end of the year, if I heard it right.

That is just based on the interim becoming permanent?

Is that correct?

Well, and the combination of things -- the interim becoming permanent, a failure, or no movement by the Commission in terms of reducing our rates to reflect depreciation expense, and a continuation of the client service plan that, again, we expect through legislation we'll be able to do through the remainder of this year.

Okay.

And then I just wanted to mention, I guess you mentioned a little bit regarding filing your rate case, electric.

Could you tell us the timing, the parameters, and as you mentioned, taking the cue from the Detroit decision, what could you be asking for in terms of recovery on the regulatory asset size?

We haven't gotten far enough along with the development of our case yet to determine any specific numbers, so I certainly don't want to quote those.

As you know, the rate caps end for our residential customers, which is the last class of customers to have the rate caps end, at the end of 2005, so rate adjustments are appropriate for 2006.

And we think we'll need relief in 2006, as much as anything to reflect the fact that we've got significant increased investment that should go into the rate base.

And we'll be making some improvements on some injections of equity in the utility under our plan in that time frame as well.

Okay.

I appreciate your time.

Thanks a lot.

Thank you.

And your next question comes from Paul Devon (ph) from Value Line.

Please proceed, sir.

Hi, this is Paul Devon.

Hi, Paul.

Hi.

First of all, with the 2003 results, you showed 59 cents from asset sales and restructuring.

Can you break down that?

How much was asset sales and how much was restructuring?

Yes, I can.

59 cents that you see there is asset sales and impairment costs, and let's say a little over 20 cents.

And then the balance is in restructuring, including items like severance costs, some of the transition work and the closure of our MSNT (ph) operations and the like.

Okay.

Do you have a breakout for the fourth quarter as well?

Actually, don't have the fourth quarter handy here.

Okay.

And also you said that you will likely issue stock sometime in the future.

I mean, how soon could sometime in the future be?

Well, we don't really have a timetable on that.

That -- that -- I think you're referring to the discussion we had on our total forward plan that characterized this as a company that has to pay a dividend on an ongoing basis.

This is something that the Board looks at every quarter.

They -- I think they have said fairly strongly that they intend to resume the dividend as soon as it's prudent to do so, and only after that.

One of the things we want to make sure is that when we resume the dividend, that we are going to be able to do it on a long-term basis, not an in and out basis.

Okay.

Have you assumed any kind of equity issuance in your guidance for this year?

We've not made a specific assumption on that for this year, no.

Thank you.

Paul, just to follow up before you close off.

Also in our attachment to the earnings release, you can see just a little bit more detail on the fourth quarter for where asset sales were in restructuring.

Great, thanks.

You're welcome.

Your next question comes from Paul Ridzon from McDonald Investments.

Please proceed, sir.

Good morning, can you hear me?

Yeah, Paul, sure.

Question on O&M at the gas company, seems to be markedly up for the quarter.

I don't know if you covered this, I had to leave for a second.

But could you give some flavor there?

I think just a couple of the things that may help you out on there are things like, we had a payment for a GCR disallowance which we recorded with a reserve in the fourth quarter, and that was quite a big piece of that, that’s almost a nickel of that.

And then we had some higher fuel gas prices in there, as well as the absence of some benefits that we did pick up in 2002 fourth quarter.

One other thing that would be in that is also there were some taxes related to some credits that we had to not take credit for, if you will, going to the forward.

And those are the big pieces that's in that, that I think you're looking at.

And what was the absolute benefit of foreign exchange for 2003?

Well, in enterprises, where we have just about all of that, there's about 13 cents different, and if you're asking exactly how much is in '03, just about all of that was because good news in '03, because we don't have any improvement or decline projected as we go forward.

Just to clarify, the pickup in '03 was more a rolloff of bad things in '02?

Is that --

That's absolutely correct.

It's really the adds, it’s the benefit that we picked up in the prior year, with no change happening in this year coming up.

I'm sorry.

I was looking at the change 2002 to 2003.

Right.

You're on slide number 15, probably, that says "enterprises"?

Actually, looking at the earnings release where there's a 23 cent pickup on Argentine expropriation.

Right.

The key -- okay.

I'm sorry.

Your question is the twelve months in 2003 compared to 2002.

Actually, what was the absolute -- not the relative change but the absolute change in '03?

Right.

I don't know if we have the absolute number here.

Do we have that handy?

We'll look and see if we can come back.

We can show you the variance there.

But for '03 to '02, I don't have the two absolutes right in front of me.

Thank you very much.

You're welcome.

Your next question comes from Carrie Stevens from Morgan Stanley.

Please proceed.

A couple of questions.

First, I wanted to understand -- and maybe you went through this -- but I'm not aware of the $190 million from the Atacama distribution and escrow change.

What exactly is that escrow change?

I'm assuming that piece is about $90 million of that amount?

That's correct.

There are two items in there.

The distribution that we're projecting that will come from Atacama would be about $100 million, and the escrow change is simply freeing up escrows that we have in place as we go forward.

The main piece of that is really an investment in Chuehot (ph) that will occur and will no longer need to have the escrow set aside.

And total for that and then some other small items is $90 million.

All right.

That is kind of one-time in nature, like an '04 event?

That's correct.

Okay.

Could you comment, you kind of suggested that the ROE at the gas utility for '03 was high single digits, is that correct?

Yes.

What about at the consumers electric?

I think that number will be slightly above our target rate of return for 2003.

My recollection is that on a financial basis, about 12.28%, somewhat higher than that on a regulatory basis.

Okay.

And then kind of a longer term question.

With the growing CAPEX needs in '06 -- I'm just trying to get an idea of kind of what you -- how you think of the utility kind of on an '06 and forward basis.

Do you see it as self-funding, or do you see it as requiring dividends from the parent?

You mean requiring investment from the parent?

Yeah, requiring investment from the parent.

Well, Ken's talked about our back to basics strategy or utility-plus strategy, and clearly, one of the pieces of that strategy is to really focus on the utility.

It is going to require some additional investment.

We do want to grow the equity investment at the utility, and we fully expect that that growth and investment at the utility will be reflected in our rate case, and that we'll recover on that in 2006.

I can't speak to the specifics of when the utility becomes self-funding in that regard, but we'll certainly make a step forward as we increase the depreciation expense and the return on the equity investment from 2006 and beyond.

Okay, well I guess, asked another way -- should we assume that this level of investment of $150 million is consistent for '05 and '06 time frame?

No, that plan for '04 is really a one-time item.

I think we would expect, in fact, to invest more equity than that over time, to grow the equity base at the utility.

Ultimately, we'd like to be in the range of maybe 45 percent common equity at the utility, and we have got quite a ways to go to get there, and we certainly think that's what the Commission would like to see, too.

So we're thinking over the longer term that we'll be heading in that direction.

All right, just two follow-up questions.

Where are you right now with the equity at the utility?

We are -- if you're asking about where we are on a debt to capital basis, we’re at about 52% debt to capital.

At the utility, you said 45% equity is where you would like to be?

We're in the 30's right now in terms of common equity at the utility;

I don't have the number right at my fingerprints.

That's helpful.

And then just lastly, about kind of -- the numbers I see highlighted on the sources and uses is the -- this is at the parent -- 310 is in a bubble and that kind of looks like ongoing expectation of cash flow?

And then 230 of interest and preferred dividends, those are like the two ongoing pieces we should be thinking of?

That's a fair assumption.

But the way to think about that is from a dividend standpoint, something in the neighborhood of $300 million.

The tax sharing piece of that element will actually increase as we go through time, particularly in the next second, third and fourth years.

And then as you observed, the interest in preferred dividend side is a number that is probably at a high level right now at $230 million, and you can expect that to decline a bit as we are able to reduce that debt base.

And as we go forward, benefit a little bit more from the lower interest rates.

So the answer is yes, and with a little local color on that.

And before you go on with your next follow-up question, let me just take the opportunity to follow up on an earlier question regarding the enterprise foreign currency impacts.

The 23 cents that is shown on the schedule that you have is 13 cents positive in '03 and 10 cents negative in '02.

I'm sorry, go ahead.

No, I think you covered most of my questions before that.

Thank you.

Thank you.

Your next question comes from Ben Sung (ph) from Luminous Management.

Please proceed.

The first question, I guess, if I could get a little more detail on the foreign exchange rates.

Going forward, from '03 to '04, you showed a -- I guess a decline or sort of an elimination of a benefit of 12 cents.

Is that assuming that there's no further decline in the dollar, or is that assuming that there is a return of the dollar to prior levels?

It's assuming that we're generally at flat levels with where we were coming out of 2003.

As you know, we've had a situation here with the weakening of the dollar that for us -- for our exposure, was -- changed our impacts a little bit.

We expect that it's going to stay flat, but we could see some strengthening as we go forward.

We just hadn't assumed that.

Okay.

And then in terms of the -- (indiscernible) the one slide which shows, I guess, the debt reduction -- I don’t think I see a slide number here -- but in that slide, what sort of dividends -- dividend assumption are you assuming for the utility up to the parent?

We actually have an assumption in there, as you'd expect, so that we have provided for some use of cash that way, but we haven't declared that.

And it's something that I would rather refer to it as a decision of the Board at a future point, when they are satisfied that we can get there.

So that's one of the reasons why we -- frankly, why we didn't precisely scale that charge – (multiple speakers)

I apologize.

The assumption, I thought you were talking about a company dividend.

My mistake.

The utility dividend assumption is in there at $190 million a year on average.

Okay.

Great.

Thank you.

Apologies.

Your next question comes from Paul Patterson from Glenrock Associates.

Please proceed.

Good morning.

Hi, Paul.

Just wanted to touch base with you on -- most of my questions have been asked.

But you mentioned in your presentation that you're going to be filing an update I think in 2003 for stranded costs recovered?

Right.

I mean for 2003, stranded cost recovery?

That’s right.

And we heard from DTE that they've seen a large amount of customer switching accelerate in the second half, and I guess pretty much the fourth quarter of the year is my understanding.

I was wondering if you could give us a little flavor for what you've been encountering?

I think that's right.

We saw some acceleration in the fourth quarter, although at year end we were somewhat below, at 650 megawatts, what we had originally projected for 2003.

We've continued to see some acceleration of that in early 2004, and we're now over 700 megawatts.

It's a little bit hard to predict where that will go.

I certainly think that the Commission's actions that I referred to during comments in the Detroit Edison rate case, where they effectively established about a 1.2 cent surcharge through the elimination of credits and the addition of a formal stranded cost surcharge.

I certainly think that's going to significantly affect the rate of open access in their territory.

As I indicated, we are planning on filing, consistent with the type of relief they provided for Edison, to request interim treatment on our 2002 and 2003 stranded cost cases, which are running a little bit behind, schedule-wise.

And we would request that treatment consistent with what has been provided for Edison.

In the meantime, because we don't have a stranded cost surcharge, we are continuing to see load loss.

We are concerned about that, obviously, but also have not seen anywhere near the load loss that Edison experienced last year.

Do you think a similar treatment that DTE got, if you were to get the same thing, would pretty much satisfy you in terms of this issue?

Well, numbers-wise, our situation is somewhat different, because we haven't securitized the balance of our stranded costs which are reflected in our purchased power contracts as opposed to their securitization of their [INAUDIBLE] unit.

So I can't speak to numbers exactly how it would parallel, but I can say that philosophically, in looking at what the Commission has done in Edison's case, if similar philosophy were applied in our case, the numbers would be somewhat different, but we think that the treatment would certainly help with this issue of loss load.

Thanks a lot.

Your next question from Jeff Gildersleeve (ph) from Millennium Partners.

Please proceed.

Yes, good morning.

Hi, Jeff.

Just wanted to go back to the interest reduction as we go from '03 to '04.

It looks -- comparing your slide of the third quarter, the sources and uses slide, to the current slide, it seems that utility interest and preeferred dividends are at 260 for '04 and they were at 200 for '03?

And then 50 million of issue and redemption costs.

I was wondering if you could just reconcile -- I know there's some debt going on at the utility in '04, but why the big pickup there?

Well, if you're over at consumers, the key issue there will be the added investment that we are putting in place, which is taking the debt level up, and therefore, the interest that we'll have to have to support it.

And then, although not asked, if you look on the left side of the two charts and look at the parent, you see just the opposite happening.

You see a lot of that one-time costs that we would have had last year doesn't show up.

In fact, we've kind of folded it all together in interest and deferred dividends in the new slide, and you can see that at a substantially lower level, as we have been discussing last year.

And that just comes from the lower debt level and the lower cost financing that we put in place.

And keep in mind, we had the big bridge loan last year, which was pretty expensive, while we were getting ready for some of our asset sales.

Right.

So it looks like a reduction of consolidated, about $110 million.

And I guess looking at your plan of reducing debt going forward, we should expect that interest number to continue to fall?

You should expect to see that go down, but not as sharply, of course, as it did this year.

And you talked a little about the tax sharing and the ability to use that, given that the utilities have profitable results and you're able to realize more of the tax sharing.

Can you just quantify a little more how that acceleration moves through time?

As we go from this year, there's only 20 million to '04, and I guess it's supposed to pick up in '05-'06?

Yeah, I'm going to stay a little vague on that except to say that you'll see it accelerate as we go into '05, and even more in '06.

I guess I would ask you to think of it in terms of double digit numbers, but we're not ready to give that guidance by year just yet.

The reason for that is the tax situation changes a bit as we go through the years on the timing of asset sales and things we need to recognize.

So although we're pretty comfortable with what will happen over the next three or four years, it's difficult to predict when you get out to the second and third year exactly how much is going to happen in each year.

So look for a larger number, and certainly not triple digit.

Okay.

And what is -- have you quantified sort of the general range of that aggregate number for tax sharing?

Only to the extent that we put a little dotted box on the debt reduction slide and kept it a little bit vague.

If you're looking at that, I would suggest that in total over the period, you might see something between a general $3-400 million.

Okay.

Thank you very much.

You're welcome.

Your next question from Rich Hayden (ph) from Omega Advisors.

Good morning.

You have clearly conveyed the notion that management has the responsibility to pay kind of a dividend.

Will this dividend precede the equity issuance?

You're asking me -- this is Ken speaking.

You'd have to make a conclusion on what the market is going to do.

We're going to have to stay opportunistic.

It fits together, though, doesn't it?

And the ideal situation is you get a company strong enough so that you can resume a continuing dividend payment, and that is reflected in the price of the stock, which makes it more attractive to issue equity.

But that said, we're going to continue to be opportunistic as we have in the last couple of years.

When the market is right, and the view of our company is right, we'll do something.

Well, if you were looking at it today and just the whole thing as constant, would that be the plan, to initiate a dividend and then have equity issuance?

You can't say.

Again, you have to look at what the market is.

I don't think it's out of line that we would do something, as we've done in the last couple years if the market happened to be exactly right, even if it was a little before we resumed the dividend.

Okay.

We'll stay tuned.

Thank you, hope so.

Your next question from Jay Hatfield (ph) from Zimmer Lucas (ph).

Please proceed.

Good morning, how are you doing?

Hi, Jay.

I have a question about the EPS guidance.

The interest and other is a drag of $1.20.

And if I just take the 2.30 of dividends and interest and tax effect it, I only get 93 cents.

Is there a lower effective tax rate?

I was estimating 40 million of other corporate costs.

Can you give us some sense of how you reconcile from the interest and dividends to the $1.20?

Keep in mind, a little bit of interest would be in there from the utility covering related cost on MCV.

Okay.

How much is that?

I don't have that off the top of my head.

But what we've tried to give in the guidance here is a pretty reasonable and fairly precise number that really does recognize all the debt reduction that's behind us.

So the levels we're at, and pretty precisely at the interest rates that we have in place.

There's a little bit of financing going on through the year that might make it variable, but it's just not substantial.

Okay, yeah.

I can tie -- in fact, I've estimated right on top of that 230 million, I just can't get to the $1.20 in total loss.

Is there like a lower effective tax rate at the holding company?

Because I'm using a 35% tax rate.

No.

In fact, at present, if you use sort of our ongoing numbers, the effective tax rate has been a little bit higher, and we expect this year in 2004 the effective tax rate to be around normal levels.

Maybe just a hair -- a little bit lower.

Okay.

Corporate overhead then, how much is corporate cost at the holding company?

Hang on just a second .

Yeah, we'll have to get back to you on the pennies for that, how much that is.

Okay, great.

What you're looking at, though, is primarily the interest side of the equation.

It makes up, I'm going to say, certainly 90% of the variance that's in there, and so we'd be happy to circle back with you.

Okay, great.

I'll give you a call later.

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

Thank you.

Your next question from Tim Shiller (ph) from Pemco.

Please proceed.

My question has been answered.

Thank you.

Thanks for calling in.

All right.

With that, thanks, ladies and gentlemen, as usual, for your always terrific questions.

We look forward to updating you further as we move through another challenging but solid year for our business.

Thanks and goodbye.

This concludes today's conference.

We thank everyone for your participation.