新世紀能源 (NEE) 2007 Q1 法說會逐字稿

Good day, everyone and welcome to the FPL Group 2007 first quarter earnings conference call.

Today's conference is being recorded.

At this time for opening remarks, I would like to turn the call over to Mr.

Jim von Riesemann, Director of Investor Relations.

Please go ahead, sir.

Thank you.

Good morning and welcome to our 2007 first quarter earnings conference call.

Moray Dewhurst, Chief Financial Officer of FPL Group, will provide an overview of our performance for the quarter.

Also with us this morning are Lew Hay, FPL Group's Chairman and Chief Executive Officer, Jim Robo, President and Chief Operating Officer of FPL Group, Armando Olivero, President of Florida Power & Light Company and Mitch Davidson, President of FPL Energy.

Following Moray's remarks, our senior management team will be available to take your questions.

Let me remind you that our comments today will include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.

Any statements made herein about future operating results or other future events are forward-looking statements under the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995.

Actual results may differ materially from such forward-looking statements.

Discussion of factors that could cause actual results or events to vary is contained in the appendix herein and our SEC filings and in the investor section of our website at www.FPLGroup.Com.

And now I'd like to turn the call over to Moray Dewhurst, Moray?

Good morning.

FPL Group is off to an excellent start in 2007, delivering performance generally in line with or a bit better than our expectations.

FPL Energy had a very strong quarter, especially in comparison with very strong performance in last year's first quarter and FPL Energy's contribution to adjusted earnings again exceeded that of Florida Power & Light as it did in the first quarter of last year.

The outstanding performance at FPL Energy reflects the strength of our balanced business model.

We entered the year highly hedged and the existing portfolio delivered results comparable to last year's' outstanding performance while new assets and favorable conditions for our full requirements business led to strong growth overall.

Florida Power & Light's contributions were up modestly compared to last year.

Customer growth continues to be strong while usage growth was weak.

I will discuss these drivers in more detail in a moment.

Looking forward, we remain well positioned for continued earnings growth.

At this early stage in the year, we are not changing our official ranges for 2007 and 2008 adjusted EPS, which remain $3.35 to $3.45 and $3.60 to $3.80 respectively.

However, the general trend in the first quarter is clearly positive and leaves us more optimistic that we will do better than the midpoints in the respective ranges.

As a reminder, when we discuss FPL Group's earnings expectations, we assume normal weather and mark our currently open positions to the current forward curve.

We also exclude the effect of adopting new accounting standards, if any, and the mark to market effect of nonqualifying hedges, neither of which can be determined at this time.

Now let's look at the results of the first quarter.

In the first quarter 2007, FPL Group's GAAP results were $150 million or $0.38 per share compared to $251 million or $0.64 per share during the 2006 first quarter.

FPL Group's adjusted 2007 first quarter net income and EPS were $276 million and $0.70 respectively, compared with $231 million or $0.59 per share in 2006.

The primary difference between the reported results and the adjusted results is the negative mark in our non-qualifying hedge category, which I will discuss in greater detail later in the call.

Please refer to the appendix of the presentation for a complete reconciliation of GAAP results to adjusted earnings.

FPL Group's Management uses adjusted earnings internally for financial planning for analysis and performance, for reporting of results to the Board of Directors, and as input in determining where the performance targets are met for performance-based compensation under the Company's employee incentive compensation plan.

FPL Group also uses earnings expressed in this fashion when communicating its earnings outlook to analysts and investors.

FPL Group management believes that adjusted earnings provides a more meaningful representation of FPL Group's fundamental earnings power.

Please note that all prior period amounts have been adjusted to reflect the application in the fourth quarter of 2006 of an accounting standard change related to planned major maintenance activities which impacted the first quarter 2006 results by $0.01 per share.

FPL's overall performance for the first quarter was in line with our expectations.

On the good side, customer growth continued at a healthy pace, and weather related sales comparisons were also favorable, however, underlying growth in usage per customer was negative and mix effects were unfavorable.

O&M expense was roughly flat with last year's comparable period, although we expect O&M to be up for the full year.

AFUDC was higher, reflecting increased generation construction spending.

Generation expansion is an important part of supporting the strong growth we continue to experience in Florida.

In May, the 1144 megawatt natural gas fired unit Five at Turkey Point is expected to become operational, slightly ahead of schedule and under budget.

West County Energy Center is currently under construction, and the first of the two 1220 megawatt units is expected to be placed into service in 2009.

The Florida Public Service Commission is currently reviewing our proposal to build 1960 megawatts of solid fuel generation using ultra super critical pulverized coal technology in Glades County.

The Glades project would be the cleanest coal power in the nation with the highest level of efficiency and the lowest level of CO-2 emissions and will bring much needed fuel diversity in 2013 and beyond.

Approvals from both the PSC and the Governor's citing Board are required.

We believe this plan is the best practical solution available to FPL to improve fuel diversity, maintain system reliability and mitigate price volatility for our customers.

As a practical matter if the Glades project is not approved the likely result will be increased exposure to natural gas as other technologies cannot provide the magnitude of reliable base load capacity that will be needed in the middle part of the next decade.

For the first quarter, Florida Power & Light reported net income of $126 million compared with $122 million in last year's first quarter.

The corresponding contributions to EPS were $0.32 this year compared to $0.31 last year.

Customer growth continues strong for the first quarter of 2007, the average number of FPL customer accounts increased by 98,000 or 2.2%, slightly ahead of our long-term historical growth rate.

While housing starts have fallen dramatically from their peaks, they remain at levels that support good long-term growth and we continue to believe that as long as the Florida economy remains fundamentally healthy, we will continue to see good customer growth.

Our forecasts for 2007 and 2008 include about 2% customer growth.

Weather comparisons with last year's first quarter were favorable.

Underlying usage growth was negative 0.8%, which we attribute largely to price and/or income elasticity.

Since we observe a lag in customer response to price changes, the first quarter of this year still reflects the last of the increase that took effect at the beginning of 2006.

We will have a much better idea whether there has been any significant change in the drivers of usage growth in the second quarter when this lag effect will cease.

For the first quarter of FPL's 2007, O&M expense was $329 million, essentially flat with the year ago figures.

Higher customer service, nuclear, employee benefit and insurance costs were offset by lower distribution expenses.

Last year's first quarter saw unusually high distribution spending, driven by additional maintenance and repair activities after the 2005 hurricane season.

First quarter O&M trends are not representative of the likely full year impacts.

We continue to see increases in nuclear and fossil generation and employee benefits and of course our Storm Secure program as being the main drivers of a roughly 3% expected increase in full year base O&M.

Overall, our expectations for O&M are a little better but have not changed significantly since last Fall.

As we indicated last October, a key to our O&M trend in 2007 will be our Storm Secure initiative.

For the next few years, we expect to spend about $50 million of O&M per year in support of our storm hardening initiatives.

In addition, we expect to commit anywhere between 70 and $200 million per year in incremental capital.

Depreciation in the first quarter fell $7 million to $188 million with higher transmission & distribution depreciation offset by reductions in certain amounts recovered through the capacity clause.

Base depreciation increased by $4 million.

The table on chart nine summarizes the drivers of the earnings growth for Florida Power & Light, which netted to an increase of $0.01.

In the interest of time, I will not read each number for you.

For those of you without immediate access to the slides, they are available in the investor section of our website at www.FPLGroup.Com.

Let me turn now to FPL Energy where adjusted earnings growth was driven both by new assets and by our wholesale marketing activities.

Before getting into the details, let me first draw your attention to the significant negative mark in our non-qualifying hedge category.

Notwithstanding its negative effect on GAAP results, this reflects good news for FPL Energy.

During the quarter, the ten year natural gas drip rose strongly and forward spark spreads also expanded.

As a result, the value of our asset positions, which of course are not mark-to-market under GAAP, increased far more than the decrease in our hedges.

Our wind development continues to make very good progress, thus far in 2007, FPL Energy has well over 500 megawatts of new wind projects under construction.

We continue to be confident that we will be able to add at least 1,500 megawatts over the next two years and hope to be quite a bit above that figure.

Our commodity hedge position for 2007 remains essentially unchanged from three months ago while the hedging of 2008 expected output increased a bit.

Over 90% of our expected 2007 equivalent gross margin is protected against commodity price volatility, and for 2008, the comparable figure is 85%.

FPL Energy's 2007 first quarter reported results were $45 million or $0.11 per share, compared with $154 million or $0.39 per share in the prior period.

Adjusted earnings for the first quarter of 2007 which exclude the effect of non-qualifying hedges were $171 million or $0.43 per share, compared to $131 million or $0.33 per share.

FPL Energy's first quarter adjusted EPS growth was 30%.

New investment contributed $0.06 per share, primarily driven by roughly 850 megawatts of new wind relative to last year's first quarter.

The existing portfolio was flat quarter-over-quarter, which was better than we had expected, as last year's first quarter was very strong.

Within the existing portfolio, we experienced the anticipated expansion of margins associated with the rollover of old hedges to higher values, and this was enough to offset a number of negative comparisons, including reduced results from our main fossil assets which had exceptional performance in January and February of 2006, a refueling outage at Duane Arnold, and lower earnings from the wind portfolio.

The wind index in last year's first quarter was a bit above average.

This year it was a bit below.

Asset optimization and trading activities increased by $0.07 from last year's first quarter, driven primarily by our full requirements business.

Market conditions were very favorable for this piece of our portfolio.

Restructuring activities were flat compared with last year's first quarter and all other factors were a negative $0.03 per share, driven by additional interest expense in overhead, which reflects underlying growth in the business.

As many of you know, there's been a lot of movement in forward gas prices recently.

During the first quarter, the most notable feature was the movement in the back end of the gas curve, where forward prices for the years 2012 through 2017 increased roughly $1 per MMBTU.

Forward spark spreads also increased in ERCOT.

These effects are favorable to the value of FPL Energy's portfolio, and as I mentioned a moment ago, the increase in the value of the portfolio far outweighs the loss in value of our hedges since we are naturally long to both gas and spark spreads.

In fact, the warranted fair value of our open asset positions, calculated using the same methodologies we use for valuing non-qualifying hedges, has increased by several billion dollars during the quarter.

Of the $126 million non-qualifying hedge impact, $43 million represents the reversal of prior period NQH gains as underlying contracts went to delivery.

The remaining $83 million is the impact of changing forward prices.

Of this, nearly three quarters is attributable to longer term hedges associated with some of our Texas wind assets, which were put in place to support project financings.

Looking forward, we can expect greater volatility in the non-qualifying hedge category than we have typically seen in the past, because of the greater sensitivity of these longer term hedges to changes in the forward curves.

Very roughly, a $1 shift in the ten year gas curve will mean about a $60 million after-tax gain or loss in the non qualifying hedge category as a result of these long dated hedges.

Before leaving this topic, I should also remind you that hedging is never perfect and there is always residual risk even after a hedge is in place.

A hedge may only address some portion of an asset's commodity exposure.

For example, we may hedge the gas exposure of an asset while leaving the spark spread exposure open.

Thus, the hedging disclosure we provide should always be viewed as indicative of the general impact of our hedging activities, not as a perfectly precise indicator of future results.

With these caveats, however, we continue to be highly hedged against the major sources of commodity price volatility for 2007 and 2008, with more than 90% of expected equivalent 2007 gross margin protected.

The equivalent figure for 2008 is 85%.

The charts supporting these figures are contained in the appendix.

Also in the appendix is a bridge between actual 2006 and projected 2007 equivalent gross margin, which a number of you have requested.

As an additional reminder, the concept of equivalent gross margin is a non-GAAP one.

It is designed to help you in your analysis of the underlying economics of our business and is not intended to be a substitute for actual results.

Turning now to our updated outlook for 2007 and 2008 results, we are at this early point in the year not changing our previously disclosed expectations.

For 2007 we expected adjusted EPS to be in the range $3.35 to $3.45 and for 2008, $3.60 to $3.80.

Having said that, I should note that we are clearly off to a good start in 2007 and our prospects for 2008 are certainly slightly stronger than when we first discussed these ranges with you in the fall of last year.

For 2007, a strong start made by FPL Energy is tempered a bit by continuing uncertainty over trends in usage per customer at Florida Power & Light, which we discussed earlier.

We will know a lot more after the second quarter.

For 2008, we now expect some additional contribution from the acquisition of Point Beach, which was not factored into our expectations last fall.

However, as we noted when we announced the transaction, the impact in 2008 is only a few pennies and the major impact is not felt until 2009 and beyond.

Included in the appendix are updated gross margin hedging charts as well as the tie outs to expected net income contributions for FPL Energy.

Not surprisingly, our expected equivalent gross margin numbers are higher now than in January, especially for 2008, which includes the anticipated impact of Point Beach, but of course there are also increased operating expenses and depreciation as well.

Overall, we are well positioned and feel very comfortable with the ranges shown here with perhaps some bias to the positive.

Before we turn to your questions, we would like to spend a little extra time on the wind business.

Recent developments in the external environment have focused increased attention on this part of our portfolio and have highlighted its contribution to shareholder value.

At the same time, some observers have questioned whether our existing business model is the right one for the future.

Both market and political developments over the last several months have been favorable for renewable energy businesses generally, and it appears that more observers are coming to share the view we have held for many years that wind has a bright future and can add significant value as one part of the energy mix of the future.

At the same time, however, the increased focus on renewables has led to some degree of confusion and clearly there exists today a wide range of views, both about what the market-leading wind portfolio is worth and about what implications current valuations might have for FPL Group.

To try and help investors make sensible judgments, we realize we need to do a better job of explaining certain aspects of the wind business.

Today, we would like briefly to address four topics.

First the major drivers of wind project economics, second the profile of expected PTC generation over time, third, the contribution that wind makes to overall FPL Energy results, and fourth, our view of what I will call structural options such as separating the wind business from the rest of FPL Energy.

Let me start by reminding everyone of the major elements of wind economics.

While every project is different, and some will have values outside the ranges shown on this chart, the figures shown on chart 16 are typical for today's competitive climate.

Capital costs today are typically in the range of $16.50 to $18.50 per kilowatt depending upon location, terrain, equipment type and other factors.

This is up substantially from a few years ago and has generally been reflected in higher pricing.

For tax purposes, wind projects available for five years make its depreciation and the typical project will be in the range of 50 to 150 megawatts, although as you may know, our largest is over 700.

Average capacity factor is a critical element of wind economics and the range is wide, but most of our recent projects have expected capacity factors of 35% or more.

A project in the low 40s is excellent.

Obviously, capacity factor is a function of geography, and the particular local wind resource, and we devote a great deal of effort to modeling and estimating wind resource availability.

Wind of course has no fuel cost, and O&M is relatively small.

Most projects' production costs are somewhere in the range of $4 per megawatt hour.

Depending upon competitive factors as well as the projects' inherent economics, mostly driven by capacity factor, contracted pricing will typically be somewhere between $30 and $40 per megawatt hour.

Since competition is strong, a project with a high capacity factor will typically have a lower price and vice versa, all other factors equal.

Finally, all projects that go into operation prior to the end of 2008 are presently eligible for production tax credits, which today are equivalent to $20 per megawatt hour, escalating with general inflation and which apply to the first ten years of the project's life.

The combination of all these elements generally yields projects with prospective cash on cash internal rates of return of 10% or better with 10 to 12% being typical.

One key aspect of the wind business which appears to cause some confusion is the role that the production tax credits play in wind economics.

To repeat, each new project qualifies for ten years of PTCs assuming it goes into service during a qualifying time period.

Currently, new projects will qualify as long as they go into service prior to the end of 2008.

As most of you know, the PTC program has been extended on a number of occasions.

We view the PTC as an integral part of project economics.

In the typical contracted project, the value of the PTCs is effectively passed through to the customer since we are able to bid a lower price than would be the case in the absence of the PTCs while still earning an acceptable return.

Because the PTCs apply only to the first ten years of operation however, and since virtually all our PPAs are at a fixed price or fixed with escalation, one consequence is that the effective duration of the cash flow of a wind project is much shorter than that of a combined cycle plant.

We view this as a favorable characteristic since it effectively means we are recycling capital and delivering an attractive return to the shareholder relatively quickly.

This too is an integral part of the overall business economics.

We have observed two main approaches in external valuations of the wind business.

One applies a multiple to a forecast earnings or cash flow stream, including the effects of PTCs.

The other excludes the PTCs from the multiple valuation and values them separately, typically by direct discounted cash flow methods.

We believe either can work effectively, but obviously only if the right input data are used.

To assist modeling efforts, we have developed chart 17 shown here which indicates our current expectations of the future profile of PTC generation expressed as megawatt hours eligible for PTCs under three different scenarios.

The lowest curve assumes that we complete about 1,500 new megawatts in the 2007 and 2008 programs and then add nothing more.

The intermediate curve assumes this base, plus a subsequent annual program of 500 megawatts with all additional megawatts assumed to qualify for PTCs.

The upper curve assumes 750 megawatts per year from 2009 onwards all qualifying.

As we've said on many occasions, we believe growth of 500 to 750 megawatts per year, assuming continued public policy support, is a realistic and perhaps even conservative goal for our wind development capability.

Please note that these curves show only the expected megawatt hours eligible for PTCs in each year.

The total expected megawatt hours will naturally be higher.

From a valuation perspective, we believe that any approach that simply takes the discounted cash flow value of the lowest curve on the previous chart will result in values that are unrealistically low.

Such an approach would miss a significant portion of the growth potential of the business.

While it is certainly true that there is no guarantee that the PTC program will continue indefinitely, the fact that the value of the PTCs is embedded in our project economics suggests that if the PTC program were to be eliminated at some future date, the principal impact would be to cause a rise in the price of wind energy relative to alternatives, all else being held equal.

As long as there is continued policy support for renewables, for example, through renewable portfolio standards, and we see little prospect of this changing, there will still be a very attractive market for our wind business.

In addition, if market prices in the future come to reflect direct price for carbon, which appears increasingly likely, wind and other non-emitting technologies stand to gain.

In fact, one can think of the current PTC program as being an indirect way of building the value of zero carbon emissions into the economics of the business.

To apply a multiple based approach to the wind business, obviously requires a good starting point in terms of income or cash flow contribution.

As you know, we run the wind business as an integral part of FPL Energy's operations and therefore to estimate an EBITDA or net income contribution requires making some assumptions primarily around the appropriate allocation of G&A expenses to different parts of the portfolio.

Since many valuations analyses today are being done on the basis of projected 2008 values, in this chart, we have provided an estimate of the expected contribution of the wind portfolio in 2008 in a couple of different ways.

First, the straightforward expected contribution, taking into account reasonable estimates of when actual projects might come into service, and second, on a hypothetical basis, assuming that all the megawatts of the 2008 program were in service for the full year 2008.

This can be pulled to others, reflecting the annualized impact of the 2008 program, but expressed in 2008 dollars.

As you can see, the difference is significant, since the full effect of any year's build program does not flow through income until the following year.

I should emphasize that the numbers shown in this chart are both forward-looking and imply non-GAAP concepts, however they are prepared on a basis consistent with our regular earnings expectations calculations.

As you can see, the wind business is a very significant component of FPL Energy.

Even ignoring the PTCs which as I said earlier are an integral part of the economics of the business, we expect the wind business to account for close to 30% of FPL Energy' s EBITDA in this period and factoring the PTCs in on a grossed up basis the proportion is over 40%.

At the same time the rest of the portfolio is also a significant contributor to FPL Group's overall economic position.

Finally, a number of analysts and investors have asked about possible plans to separate the wind business completely or in part from the rest of FPL Energy or alternatively to separate FPL Energy from the rest of the enterprise.

The intent would be to highlight the separate economics and hopefully capture a higher multiple than is implicit in today's FPL Group valuation.

We have been examining a range of options along these lines for some time.

These include partial or complete spinoffs or IPOs as well as the possibility of a tracking stock.

Our conclusion to date has been that each of these options has significant drawbacks and it may be helpful to explain our reasoning.

In thinking about these structural options, it is important to remember that there are real, operational linkages between the wind business and the rest of the FPL Group portfolio.

In particular, operationally, we manage the entire non-nuclear generation fleet as a whole and there are real synergies that we derive from this that benefit all the assets both in terms of cost and in terms of reliability.

Commercially, our relationships with key suppliers are strengthened by the breadth of activities in which we engage, thus each of the structural alternatives we have looked at has had associated with it some degree of real value degradation, varying in extent, generally in line with how complete any separation of the wind business might be.

In addition, any structural alternative carries with it additional administrative costs and generally introduces challenging though not insurmountable issues associated with dual fiduciary relationships and of course a larger enterprise can utilize the production tax credits more efficiently.

For all these reasons our conclusion to date has been our current structure is preferable to the alternatives.

This could change as external circumstances change and we are certainly open to input on the subject, however we do recognize that investors' ability to value the enterprise appropriately is in part a function of the information we provide and therefore, we have concluded that it would be useful to provide additional data around the wind business.

We hope what we have shared today will make it easier for you to compare our wind business with other relevant benchmarks.

To summarize the 2007 first quarter, on an adjusted basis, FPL contributed $0.32, FPL Energy contributed $0.43 and corporate and other was a negative $0.05 contribution.

That is a total of $0.70 compared to $.59 in the 2006 first quarter on an adjusted basis.

To conclude, therefore, we are pleased with the start to 2007.

We look forward to continuing to deliver very strong results for our shareholders this year and beyond.

And now we'll be happy to take your questions.

Thank you.

Today's question and answer session will be conducted electronically.

(OPERATOR INSTRUCTIONS).

We'll go to our first question from Paul Patterson at Glenrock Associates.

Good morning, guys.

Good morning, Paul.

I just wanted to touch base with you on the full requirements contracts and your comment that the market conditions were particularly good.

It looks like the first quarter might have been better than all last year with respect to that business.

What led to those market conditions?

How long are those contracts roughly speaking, and how is the revenue recognized in them?

Good questions.

First of all, I should remind everybody that full requirements for us is a pretty small business, so but the timing and the shaping of a relatively small number of deals can have a significant impact on period to period comparisons and that's certainly true here.

Last year in the first quarter, this business essentially made no contribution that was largely due to the shape of specific projects or specific deals, so when you get to explaining why there's the difference you really almost have to get down to the individual deal because each deal has different explanations, but broadly speaking in terms of the market conditions, we had a number of situations where the load came in relatively modest because of the temperatures, so we ended up effectively being over hedged in a strong price environment so that will always produce a positive variance for this kind of business.

In a number of cases, we had lower than anticipated ancillary costs, so it's a variety of different things.

In terms of the revenue recognition, I mean, the revenue is recognized as delivered.

Okay.

One final comment.

Relevant to your question, I don't think we should expect the same level of contribution from this business in the remaining three quarters as we've seen in the first quarter.

And then just finally, the higher equipment costs and just in general, in the wind business, the level of attractiveness I guess that's associated with this business, what are your expectations if you see this much interest in the public policy, I guess one of the fundamental issues might be how much the equipment cost might rise.

Do you have any projections in '08 and '09 what these costs might go to?

Obviously that's a hard one to address directly.

I mean, there have been two major drivers of the increase that we've seen over the last few years.

The biggest one has just been rise in commodity prices, generally steel, in particular.

Hopefully we're starting to see that taper off and we won't see the same kinds of increases in the future.

We've also seen essentially just plain higher margins for the equipment manufacturers if you go back three or four years ago, most of the equipment manufacturers were really under considerable margin pressure, and obviously it's in our long-term best interest to have healthy suppliers, so I think there's plenty of competition among suppliers, so I'm optimistic that we won't see a lot of additional margin expansion.

We will certainly try and keep them competing effectively.

Okay, great.

Thank you.

We'll move next to Dan Eggers at Credit Suisse.

Good morning.

Thank you for all the extra wind detail.

It's very useful.

One of the topics out with the wind business is could you give a little more flavor for where you guys stand as far as ownership and retention of carbon exposure for these assets as we look out over the next several years?

I would love to do that; that actually was on my list for this earnings release, but we didn't quite get to it, so we will be coming out with that fairly soon, so I think we'll figure out a way to just send around an e-mail and put it on the website.

Okay.

Typically, the older contracted projects, the ones we were doing back in the 2000, 2003 period that, what I'll call most of the green attributes typically went to the customer so we would not see those come back until the contracts run-off in 20 years.

More recently, we have been successful in retaining a higher proportion of the green attributes per megawatt installed.

Okay, got it.

Just, you guys gave the grossed up, the EBITDA numbers on Page 18.

When we think about coverage ratios from a debt service perspective, we should probably make an adjustment to that grossed up PTC value to think about what a cash coverage EBITDA number would be?

Well, it really shouldn't affect your cash coverage numbers.

Okay, so that's not being -- that is or is not being grossed up for, that's the real cash number?

It's a pre-tax equivalent cash number.

If you're doing just pre-tax coverage ratios, then I think it's a fair comparison because the PTCs obviously come in as an after-tax cash credit, so you can do it either way if you want to do an after-tax cash coverage, then obviously you've got to take the after-tax value, which gets you down to the original real value of the PTC.

If you want to do a pre-tax value then the grossed up number is I think appropriate.

Okay, got it.

And one last question.

As you guys look at the 750 or more a year of construction, any feel for how much of that is going to be the Texas style contracts, going to be a little more market exposed versus some of the more historical contracts which would have been the 20 year type PPA deals?

I can't give you an exact mix.

We're very pleased with the projects that we've done in Texas.

I've mentioned before that it's those kinds of sort of hedged wind we have to have the right market structure and there's a few other places in the country where we could do that, but I think we're going to see a mix going forward.

We're certainly not going to move away from contracted projects.

We'll continue to do those but where there are specific market opportunities for the hedged projects we will do those as well, but I don't have a firm number mix in mind.

Okay.

Thank you, guys.

Thanks.

And next we'll move to John Kiani of Deutsche Bank.

Good morning.

Good morning, John.

Can you give us a little bit of a feel for any potential difference in realized price for wind projects that let's just say starting today, under the current forward natural gas strip that are contracted under the more traditional long-term PPAs with load serving entities versus some of the financial sales or forward sales you've done for some of the 3 to 5 year hedges?

John, I guess the way to think about that is if it's a hedge project, it's whatever the market price is, so in the case of the Texas project, you can look at around the clock prices there and that's kind of your growth price opportunity.

For contracted, so you're market price driven there.

Contracted projects are really in my mind a little bit more cost driven because of the nature of the competition.

We may be advantaged, but we are always facing very significant competition in every project that we bid on.

As a result, there is price pressure and so those projects tend to get bid down below what I'll call the true opportunity cost of the raw energy until you reach a point where one or other competitor is no longer happy with the implied internal rate of return.

So as I indicated in the slide discussing wind economics, that has typically for us resulted in 10% cash on cash IRR's.

But it will depend upon the specific circumstances.

So to the earlier question actually of the rising cost, capital cost for these projects, in a sense, the market's ability to absorb the rising cost in contracted, through contracts has been made easier by the fact that the opportunity cost of energy has been rising at the same time.

So from a customers' point of view, although the absolute cost has gone up, so has the opportunity cost of what they would be comparing it to in their Resource plan, so the rising price has somewhat offset the rising capital cost.

That's helpful, Moray, and then can you give us an update or do you have anymore recent color on a potential federal renewable portfolio standard?

Well, I would say there is a lot of discussion going on but we don't have any particular insight into what might come out of that.

We do feel that federal standard can be appropriate, but it needs to really be, to make it work, you want a national standard and a national market for the green attributes.

That will be the way that you will get the most activity for kind of the least cost, but there's a lot of different flavors of RPS being discussed in Congress and we don't have any particular insight as to which one may or may not emerge.

Great.

And then just one final quick question.

Back to your answer to Paul's question.

On some of the load serving contracts in the upside realized there, just to understand what you said, were you saying, Moray, that you're effectively ended up long because demand came in light so you sold into a rising price environment?

In a couple of instances.

I was trying to illustrate that these things go deal by deal, and in a couple of other deals it was really the lower ancillary cost that caused the good performance.

Typically, you can expect somewhere between margins of $2 to $4 per megawatt hour and I haven't checked the number but pretty clearly I'm sure if I did we would be much closer to the $4 end for the first quarter.

Thank you.

Next we'll go to Leslie Rich at Columbia Management.

Good morning.

Good morning.

As you look at the Glades project, I know Florida has often noted that it would like to diversify its fuel sources, but just wondering what public perception and response would be to building new coal in Florida, and separately on that issue, would you potentially be entitled to any sort of enhanced ROE or would that just be sort of added to rate base and with the construction work in progress kind of thing?

Well, I'll ask Armando to comment a little bit more but let me just kick it off by saying that very clearly, this is a challenging project to get approved to get permitted.

As important as we think it is for the long-term benefit of our customers, obviously coal provokes some pretty strong reactions from some people, so it won't by any means be easy.

It is a complex project in the first place, but let me let Armando talk a little bit more about that.

Hello, Leslie.

Hi.

As you know, the process has been considerably more contentious than for a natural gas fired plant but I think we have a pretty compelling story.

If we don't build the plant, we will be about 70% dependent on natural gas, a huge short position on natural gas and our customers will experience significant volatility in their bills going forward.

So, we think it's important that we lay out our very best case, and we really are in discussions with all the parties trying to make our point.

With regards to ROE, I think we have a ways to go between now and then and don't know that we're prepared to speculate on what that might be.

So what are the primary mileposts I guess, the Public Service Commission has to obtain if there's a need and then you need Governor Citing Board approval, what is sort of the timeline here?

The timelines are under the current schedule, and the Public Service Commission would issue an order on the need and the appropriateness of the costs and the structure that we're proposing by June 5, and then it would go to the governor and the cabinet sitting as the Power Plant Citing Board, we think probably some time in the first quarter of '08.

Some time January, February would be the most likely timeframe.

What is the cost?

You know what?

The cost of the first unit is about a little over $3 billion and the cost of the second one will be slightly less.

The total is about $5.5 billion, maybe a little bit more.

I think we said in the hearings approximately $5.7 billion includes all of the infrastructure costs by the way, includes about $500 million of transmission cost.

And Leslie, just to close out and be explicit, at this stage there is no sort of special treatment in terms of ROE, so if everything goes forward and the project is approved, it would be, the construction spending would be eligible for AFUDC and then it would go into rate base when the projects come on line in 2013 or 2014 just as normal and they would receive whatever ROE opportunity was available to the entire business at that point.

Okay, but if they decide that yes, we see that there's a need but no, this isn't the fuel source we want then you have to come up with sort of a Plan B which I guess would be gas?

That's correct.

Realistically, the only alternative in this timeframe is going to be incremental natural gas.

There just is nothing else that's reliable base load capacity that can meet this magnitude of need.

We have significant incremental demand side management programs built into the Resource plan, but that alone is not going to get us there.

Thank you.

If I may just add, 25 to 26% of the expansion plan includes energy conservation and renewables, so despite that big percentage, we still see the need.

Thank you.

We'll go next to Debra Bromberg at Jefferies & Company.

Hi, good morning.

Good morning.

Just a couple of questions on FPL Energy on the wind.

On the projects that you're building right now, should we be thinking of pricing in the $40-plus range per megawatt hour because with the capital costs coming up a bit, I guess I would have thought it might be a little bit higher than that.

No, that's reasonable.

Again, you may want to just mark out a pro forma model for an individual project and play around with different price and capacity factor assumptions and see how the IRR comes out.

Again to repeat, we are always going to be in a competitive situation so if you have a very high capacity, in fact good wind resource, you're probably going to end up seeing lower prices and vice versa.

And on the capacity factors, should we be assuming this range of 35 to 43% on some of the newer projects because I know with some of the older projects, I think they were closer to 30 to 35%, so are you seeing higher capacity factors on some of the newer ones or is the average capacity factor for the whole portfolio starting to trend up?

No.

It's the former.

Over time, we're getting better at picking places in the development phase and so the average expected capacity factor of new projects going into service, the last few years has been higher than the embedded average for the portfolio, so going back a number of years we've got a number of older projects that are just frankly not as good as the newer ones that we've been doing.

Okay, and just one non-wind related question if I could get it in quickly.

Sayreville, Bellingham, and Marcus Hook 50, should we assume that the output for those are sold under long-term contracts or should we assume that if there's spark spread expansion that you would benefit from that?

The latter is a better assumption.

Well, Bellingham and Sayreville were two where we restructured the contracts to give ourselves the (inaudible) jointly, to release the option value inherent in there, so at this stage, we retain kind of the upside on spark spreads for those.

Great.

Thank you.

We'll go next to Vedula Murti at Tribeca Global Management.

Good morning.

A couple of things, one, with regards to the wind projects at the end of the ten year life, it's my recollection that you know that's the production tax credit expires at a point in time.

Are there not opportunities as you get close to expiration to find ways to restructure the asset such that the tax credit can continue beyond a ten year term?

Vedula, I think you may be confusing two different things here.

At the end of the ten years, the PTC is what it is, so it's going to disappear.

The typical contracted project we will then have another let's say ten years of contracted life, so at that point, while certainly conceptually you're correct, it would be possible to restructure the contract.

The reality is in the current market conditions, that the customer will be looking at a deep-in-the-money position and so would not have a lot of incentive to give that up.

So while we might have a few at that point, the bigger opportunity will come late in the contract life, perhaps years 17 or 18, wherein the customer is looking ahead to a potentially significant increase in the price.

So, I don't think there's going to be a lot at year ten.

I think they are going to be more in the latter part of the second decade of most of those.

But you raise an important point, which is that there is significant long-term value to the projects that are already in existence and obviously the market, if you take the projects that we did in 2000, for example, the outlook for those projects in 2020 is quite different now than it was when we put them into service so there's some clear longer-term upside in all those projects.

Secondly, can you also talk about what is the actual useful life of these assets?

Obviously we have early ones from the '80s and that kind of thing, and with newer technology and maintenance and things of that nature, we've talked with useful life of coal plants being in the 50-60 year area.

What is the useful life of these assets?

Well it's funny that you should ask that question because we were having an internal discussion just last week on that very subject.

I think the first answer is of course nobody really knows, but if you look at expectations of life for most technologies at the time that they were introduced or put into service and what they turned out to be, they generally turned out to be quite a bit longer than those original expectations.

As you correctly pointed out, we've still got wind assets with technologies dating back to the '80s still working very effectively and producing cash flow.

So my own expectation, just thinking about with the nature of the assets, when you have a relatively simple steel tower with equipment on top is that that structure will be there for a long, long time and what will happen is you'll essentially replace components as you go, but I have to confess that at this stage clearly that's a little bit of speculation but we think they are going to be around for a long time.

My last question has to do with the proposed coal facility.

You may have addressed this in the past, but what do you currently see as potential range of cost estimates right now per installed KW given some of the environmental challenges and things of that nature?

Well, I guess the main point to be made about cost per KW for especially for coal projects and nuclear projects is they are going to be very site specific and situation specific, so as Armando indicated, that the total expected for the nearly 2000 megawatts here is approximately 5.7 billion, but that would not necessarily be representative of costs in other parts of the country, that also includes or reflects the fact that this will be, this will require significant transmission expansion in order to support it and that might not be true in other circumstances, but that's a decent number for our particular project.

Thank you very much.

Hang on a second, Lew wants to make a comment.

Vedula, I'd like to add something because you hear a lot of different numbers for coal plants and nuclear plants have been bandied about, and what we try to do is give a comprehensive full cost when we give numbers, so that will include things like Armando mentioned for our coal plant before, $0.5 billion of transmission, but we also are quoting the cost, basically when the plant is ready to go into service.

A lot of the cost estimates you hear thrown around are overnight costs that don't include all of the other elements of the infrastructure necessary really to get the power to the customers, and as Moray said, some of it is site specific.

If it's a greenfield site and it's coal, you need rail facilities, possibly port facilities, coal transportation facilities and things of that sort, where an existing site might not require that, so there's a number of things that drive a broad range, but I would encourage you all to focus on what the full cost is, not what an overnight cost is just for instance for the power island.

I appreciate the clarification.

Thank you.

We'll go next to Margaret Jones at Citigroup.

Hello.

I had two questions.

One of which you alluded to, but I'd like to address it specifically, which is what are the prospects for a decision to add more leverage to your business, either at FPL Energy or at FPL Group Capital, or somewhere else for that matter, if that's the concept, for example, at a holding Company for the wind business?

And my second question is, I noticed a headline last week that your Company is bringing a lawsuit against TXU, alleging that they made it difficult or impossible for you to deliver some power to them in Texas by causing congestion, so I wondered if you could comment on these two situations.

Yes.

Let me take the leverage issue first.

Just as a reminder for everybody, our basic approach to sort of balance sheet is driven off our desired credit position.

We're very comfortable with the credit position that we have and therefore, when we put together a financing plan designed to support investment growth, we look to come out with a set of credit metrics that are supportive of our overall target credit position.

We've been very successful in doing that over the last number of years.

One part of the way that we have done that is through project financing around some of the FPL Energy assets, and we will I'm sure continue to do some of that.

On the FPL side, through the current rate agreement, we operate the business with a pre-determined equity ratio, so that is sort of set by the rate agreement.

That could change after the end of the rate agreement at the end of 2009 but it is what it is between now and then, but the combination of those things has said that we would not expect to see major changes in leverage.

We think that that financial structure has been advantageous for us commercially, having the strong balance sheet and the credit strength has been a good thing for us commercially particularly at FPL Energy, and it's clearly good for Florida Power & Light as well so we don't see any reason to change that at the moment so we have no plans to radically increase the gearing.

On the second subject, the TXU lawsuit, this is a, I would characterize this as a relatively minor commercial dispute, but Jim may want to comment a little more.

Yeah, thanks, Moray.

I think fundamentally, our policy is not really to comment on matters in ongoing litigation.

I will say that what was in the press last week was a letter that we wrote to the PUC in response to a PUC inquiry, and so that's in the public domain but outside of that and what's in our K, we don't really plan on commenting.

Thank you.

And our next question comes from Jesse Laudon at Zimmer Lucas.

Good morning.

Good morning.

Just a quick question.

In the past you talked about some longer-term ways of I guess financing the wind CapEx as well as the recent nuclear or the pending nuclear acquisition.

Just wondering kind of whether a decision has been made on that or when the timing on a decision for that would be?

No decision has been made yet.

We are looking at the overall financing needs consistent with the kind of approach that I just mentioned in response to the previous question for the 2007-2008 period.

Looking out over that period, my guess, if I had to guess today, I would say that somewhere in there, there will probably be some incremental external equity of modest amount, but we're in pretty good balance overall.

I continue to be very pleased with the hybrid deal that we did last year and we may look to add more of those and I think given where markets are probably do that first, but a lot depends on obviously we haven't gone through the approval process for Point Beach yet so some of this is premature until we actually have the approvals that we need and the other big uncertainty is the exact magnitude of the '08 program.

Obviously the bigger the '08 program the more likely it is we would subsequently need some external equity to support that extra growth.

So, no real change yet.

The timing for when we would start settling in on some of those things is probably I would say in the late Summer, early Fall where we would be hopefully close to closing on Point Beach or at least have much greater clarity on the timeframe.

Just to clarify, you mean bigger '08 program, you mean if you have wind opportunities that are maybe towards the higher end of the 750 megawatt target?

And then just as a follow-up or a different question, you noted that you were kind of ahead of schedule and a little bit ahead of budget on your latest regulated power plant.

Can you just kind of refresh us on how much you have been able to save rate payers with kind of keeping construction costs down?

Yes.

On the first part of your question, the answer is yes.

On the second one, the underrun, on Turkey Point Five, it's modest probably on the order of 4 or 5% of the total that was expected to be about a $600 million project and it's probably going to come in 20 to $25 million under that.

Great.

Thanks.

Great quarter, guys.

Thank you.

I think we have time for a couple more.

All right we'll go next to Paul Ridzon at KeyBanc.

Moray, you said that the average capacity factor in the fleet is rising.

At what point do you think there could be scarcity of good sites that could reverse that trend?

Is that a couple years out?

Is that decades out?

I would say it's somewhere in between.

At least for the next several years, our ability to sort of stockpile 40% capacity factor sites doesn't seem to be constrained.

I think the constraints are much more in other parts of the business, the ability to get the magic confluence of customer and transmission and need more than they are the specific site, but I think at some point out there, clearly we are going to use up the very best sites, but it's a ways off.

And given the level and period that you have been doing this and the relationships you've built with the suppliers, what advantages do you bring when you go and bid for a site from a cost standpoint and what options do you have and how far out do you have them relative to your competitors as you understand them?

Well, that's a tough question to ask me to address in this setting.

Let's just say we're very comfortable with our competitive position.

Fair enough.

Thank you.

And we'll take our last question from [Ted Hein at Catapult.]

Good morning.

I was wondering if you guys can just give a little color on, you've talked about the potential opportunities with the wind business.

How much kind of recent market transactions have affected that, the Horizon transaction and the like and how you view your portfolio relative to some of those transactions?

Let me take the second part first just to follow on my non-answer to the previous question.

We prefer our portfolio.

We think it's better, and we think there are good sound reasons why.

Having said that, I will have to acknowledge that this is still fundamentally common technology which is well understood, so as in, at least in my view every other aspect of our industry, it is very hard for competitors to -- superior competitors to be greatly better than others in the space, so what that boils down to is to some extent a matter of judgment, but a few percentage points and internal rate of return is realistic but that in terms of value creation over the long haul can be significant.

To the first part of the question, I guess part of what we've been trying to do in this incremental wind disclosure is simply pick up on the fact that there have been some other transactions out there and frankly, we've just been getting a lot of questions from investors who would like to be able to compare our portfolio with those other transactions, so this is kind of like a first step in that direction and we'll certainly look for feedback from the marketplace as to whether we are missing the boat or hitting the mark, to mix metaphors.

Great.

Thanks a lot.

Thank you.

And Mr.

Dewhurst, I'll turn the conference back over to you for any closing remarks.

We thank you all for being with us this morning and look forward to talking to you again in July.

And that does conclude today's conference.

Again, thank you for your participation.