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FPL Group, Inc. (FPL-OLD)

Q1 2007 Earnings Call

April 30, 2007 9:00 am ET

Executives

Jim von Riesemann - Director, IR

Moray Dewhurst - CFO, VP-Finance

Lew Hay - Chairman and CEO

Armando Olivera - President of Florida Power & Light Company

Analysts

Paul Patterson - Glenrock Associates

Dan Eggers - Credit Suisse

John Kiani - Deutsche Bank

Leslie Rich - Columbia Management

Debra Bromberg - Jefferies & Company

Vidula Merke - Tribeca Global Management

Margaret Jones - Citigroup

Jesse Laudon - Zimmer Lucas

Paul Ridzon - KeyBanc

Ted Hein - Catapult

Presentation

Operator

Good day, everyone, and welcome to the FPL Group 2007, First Quarter Earnings 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.

Jim von Riesemann

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 Olivera, President of Florida Power & Light Company, and Mitch Davidson, President of FPL Energy.

Following Mr. 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.

A discussion of factors that could cause actual results or events to vary is contained in the appendix here-in and our SEC filings, and in the investor section of our website, www.fplgroup.com.

Now I would like to turn the call over Moray Dewhurst. Moray?

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Moray Dewhurst

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 a strong performance in last year’s first quarter. 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 ended 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 requirement 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 remained 335 to 345 and 360 to 380 respectively.

However, the general trend of the first quarter is clearly positive and leaves us more optimistic that we will be better than the mid-points in their 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 terms. We also exclude the effect of adopting new accounting, if any, and the mark-to-market effect of non-qualifying hedges, neither of which can be determined at this time. Now, let's look at the results for the first quarter.

In the first quarter of 2007, FPL Group's GAAP results were a $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 or $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 of performance, for reporting of results to the Board of Directors, and as input, determining whether 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 provide a more meaningful representation of FPL Group's fundamental earnings power.

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

FPL's overall performance for the first quarter was in line with our expectations. On the Group 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 1,144-megawatt natural gas power fired unit 5 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 1,220 megawatt units is expected to be placed into service in 2009. The Florida Public Service Commission is currently reviewing our proposal to build 1,960 megawatts of solid fuel generation, using ultra-supercritical pulverized coal technology in Glades County.

The Glades project would be the cleanest coal power plant in the nation with the highest level of efficiency and the lowest level of CO2 emissions, and will bring much needed fuel diversity in 2013 and beyond.

Approvals from both the PSC and the Governor’s Siting Board are required. We believe this plant 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 Glade’s 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 a $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 continued 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 peak, 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 forecast 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 observed a lag in customer response to price changes in the first quarter of this year, it 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 lagged effect will cease.

For the first quarter of FPL's 2007, O&M expense was $329 million, essentially flat with the same figures a year ago. 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 initiatives. 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 million and $200 million per year in incremental capital.

Depreciation in the first quarter fell $7 million to $188 million with higher transmission and distribution depreciation offset by reductions in certain amounts recovered through the capacity clause. Base depreciation increased by $4 million.

The table on chart 9 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, 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 10-year natural gas strip grow 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’s expected output will increase 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 years 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. Our refueling outage of Duane Arnold caused 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 years first quarter and all other factors were a negative $0.03 per share driven by additional interest expense and overhead, which reflects underlying growth in the business.

As many of you know, there has been a lot of movement in forward gas prices recently. During the first quarter, the most notable feature was the movement in the backend 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 out-ways 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 used 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 10 year gas curve will meet 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 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 chart 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 expect adjusted EPS to be in the range of $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.

In 2007, a strong start made by FPL Energy is tampered a bit by continuing uncertainty over trends and usage per customer at Florida Power & Light, which we discussed earlier. We (inaudible) 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 from 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 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 it's 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 renewables, energy businesses generally, and it appears that more observers are coming to share the view that 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 help sensible judgments, we realize we need to do a better job of explaining certain aspects of the wind business. Today, we would like to briefly 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 range as shown on this chart, the figures shown on chart 16, are typical for today's competitive climate. Capital costs today are typical 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, that has generally been reflected in higher pricing. For tax purposes, wind projects that are available for five years may cause 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 for wind economics and the range is wide, but most of our recent projects and expected capacity factors are 35% or more. A project in the low 40s is excellent. Healthier free 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 to 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, or 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 10 years of the project's life.

Combination of all these elements, generally yield 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 what the production tax credits play in wind economics. To repeat, each new project qualifies for 10 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, PTC program has been extended on a number of occasions.

We view the PTCs 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 at a lower price than would be the case in the absence of PTCs, while still earning an acceptable return. The PTCs apply only in the first 10 years of operation since virtually all our PPAs are at a fixed price or fixed with escalation. One consequence, is that the effective duration of the cash flows of wind projects are 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 1500 new megawatts in the 2007 and 2008 programs and then add nothing more. The intermediate curve assumes this space to pass 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 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 suggest 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, else being held equal. As long as there is continued policy support for renewables, (i.e. through renewable portfolio standards) 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 the 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 in to 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 a net income contribution requires making some assumptions, primarily around the appropriate allocation of G&A expenses to different parts of the portfolio. Since many evaluations and 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 straight forward 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 thought of as 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 years 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 employee non-GAAP concepts. However, they are prepared on the 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, is an integral part of the economics of the business. We expect the wind business to account close to 30% of FPL Energy's EBITDA in this period. In fact when the PTCs are 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 and 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 spin-offs or IPOs as well as the possibility of attracting stock. Our conclusion to-date has been that each of these options have significant drawbacks, and it maybe helpful to explain our reasoning.

In thinking about these structural options, it is important to know 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, but not insurmountable issues associated with dual fiduciary relationships. And of course the larger enterprise can utilize the production tax credits more efficiently.

For all these reasons our conclusion to-date has been that our current structure is preferable to the alternatives. This could change when external circumstances change, and we are certainly open to input on that 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 will be useful to provide additional data on the wind business.

We hope that 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, as it is a total of $0.70 compared to $0.59 in the 2006 first quarter on an adjusted basis. To conclude, therefore, we are pleased with the start of 2007. We look forward to continuing to deliver very strong results for our shareholders this year and beyond.

And now we will be happy to take your questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). We'll go to our first question from Paul Patterson at Glenrock Associates.

Paul Patterson - Glenrock Associates

Good morning, guys.

Moray Dewhurst

Good morning, Paul.

Paul Patterson - Glenrock Associates

I just wanted to touch basically on the full requirement contracts and your comment that the market conditions were particularly good. It looks like the first quarter might have been better than all of last year with respect to those businesses, I was wondering what kind of -- what led to those market conditions, how long are those contracts roughly speaking, and how is that revenue recognized in them?

Moray Dewhurst

Good question. First of all, I should remind everybody that full requirements for us is a pretty small business, so the timing and the shaping of relatively small number of deals can have a significant impact on period-to-period comparison and that’s certainly true here. Last year in the first quarter this business eventually made no contribution that was largely due to the shape of specific projects or specific deals. So, when you'd get to explaining why there is a difference, you really almost have to get down to the individual deal because each deal has different explanations. But clearly 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. And in a number of cases we had lower than anticipated ancillary cost, so it’s a variety of different things.

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

Paul Patterson - Glenrock Associates

Okay.

Moray Dewhurst

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.

Paul Patterson - Glenrock Associates

Okay and then just finally on the higher equipment cost, and just in general, in the wind business the level of attractiveness, I guess, is that associated with this business? What are your expectations, I mean, if you see this much interest in such public policy, I guess, one of the fundamental issues would be how much the equipment cost might rise? Do you have any projections in ’08, in ’09, what these costs might go to?

Moray Dewhurst

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 a rise in commodity prices, generally and steel in particular. Hopefully, we are starting to see that taper off and we won’t see the same kind of increases in the future. We’ve also seen essentially to explain 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 is plenty of competition among suppliers, so I am optimistic that we won’t see a lot of additional margin expansion. We will certainly try and keep them competing effectively.

Paul Patterson - Glenrock Associates

Okay, great. Thank you.

Operator

I will move next to Dan Eggers at Credit Suisse.

Dan Eggers - Credit Suisse

Hi, good morning.

Moray Dewhurst

Good morning.

Dan Eggers - Credit Suisse

Thank you first of all for the extra wind details. It was very useful. I guess one of the topics out with the wind business is, could you just give a little more flavor for where you guys stand as far as ownership or retention of carbon exposure for these assets lot out over the next several years?

Moray Dewhurst

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, we'll try to figure out a way to just send around an email and put it on the website.

Typically, the older contracted projects, the ones we were doing back in the 2003 period, what I’ll call it most of the green attributes typically went to the customer. So, we would not see those come back until the contracts run-off with 20 years. More recently, we have been successful in retaining a higher proportion of the green attributes per megawatt installed.

Dan Eggers - Credit Suisse

Okay, got it. You guys gave the grossed up 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 EBITBDA number would be?

Moray Dewhurst

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

Dan Eggers - Credit Suisse

Okay. So, user is not being grossed upward, that’s the real cash number?

Moray Dewhurst

It's a pre-tax equivalent cash number. If you are doing your pre-tax coverage ratios, then I think it’s a fair comparison, because PTC's 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 PTCs. If you want to do a pre-tax value then the grossed up number is I think appropriate.

Dan Eggers - Credit Suisse

Okay, got it. And I guess just one last question, as you guys look at the 750 or more year of construction, any feel for how much of that is going to be, the Texas Style contract is 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.

Moray Dewhurst

I can't give you an exact mix. We are very pleased with the projects that we've done in Texas. I'd mentioned before that, for those kinds of hedged win 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 are going to see a mix going forward. We are 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 or mix in mind.

Dan Eggers - Credit Suisse

Okay. Thank you, guys.

Moray Dewhurst

Thanks.

Operator

And next, we’ll move to John Kiani at Deutsche Bank.

John Kiani - Deutsche Bank

Good morning.

Moray Dewhurst

Good morning, John.

John Kiani - Deutsche Bank

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

Moray Dewhurst

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 round-the-clock prices there and that’s kind of your growth price opportunity. So, your market price is 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 costs of the raw energy, until you reach a point where one or another 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 IRRs, but it will depend upon the specific circumstances.

So, to the earlier question actually of the rising capital cost for these projects, in a sense the market's ability to absorb the rising cost 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 customer's point of view, although the absolute cost has gone up, so has the opportunity cost of what they would be comparing it to and their resource plans. So, the rising price has been somewhat offset by the rising capital cost.

John Kiani - Deutsche Bank

That's helpful, Moray. And then, can you give us an update, or do you have any more recent color on a potential federal renewal portfolio standard?

Moray Dewhurst

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 a federal standard can be appropriate, but to make it work, you want a national standard and a national market for the green attributes that would be the way that you would get the most activity out of that least cost. But there are 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.

John Kiani - Deutsche Bank

Great. And then just one final quick question, back to your answer to Paul's question on some of the load serving contracts and the upside realize there. Just to understand what you said. Were you saying Moray that you've effectively ended up long because demand came in light and you sold into a rising price environment?

Moray Dewhurst

In a couple of instances, I was trying to illustrate that these things go deal-by-deal. In a couple of other deals, it was really the lower ancillary costs, but of course the good performance. Typically, you can expect somewhere between margins of two to four bucks of megawatt hour, and I haven't check the numbers but pretty clearly I am sure if I did, we'd be much closer to the fore end of the first quarter.

John Kiani - Deutsche Bank

All right. Thank you.

Operator

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

Leslie Rich - Columbia Management

Good morning.

Moray Dewhurst

Good morning.

Leslie Rich - Columbia Management

If you look at the Glades project, I know Florida has often noted that it would like to diversify 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?

Moray Dewhurst

Well, (inaudible) I am under the comment a little bit more. But let me just kick it up 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 as a complex project in the first place, but let Armando talk a little bit more about that.

Armando Olivera

Hello Leslie.

Leslie Rich - Columbia Management

Hi.

Armando Olivera

As you know, the process has been contentious, considerably more contentious than for a natural gas-fired plant. But, I think we have a pretty compelling story. We don't build the plant. We will be about 70% dependent on natural gas, [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 ways to go between now and then. And don't know that we are prepared to speculate on what that might be.

Leslie Rich - Columbia Management

So what are the primary mileposts, I guess the Public Service Commission has to sustain if there is a need and then you need governor Siting Board approval. What is the timeline here?

Armando Olivera

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 are proposing by June 5th. And then it would go to the governor in the cabinet sitting at the Power Plant Siting Board. We think probably that some time in the first quarter of '08, or some time January, February would be the most likely timeframe.

Leslie Rich - Columbia Management

What is the cost?

Moray Dewhurst

Yeah, the cost of the first unit is about little over $3 billion and the cost of the second one will be slightly less. Yeah, the total is of about $5.5 billion, may be a little bit more.

Armando Olivera

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

Moray Dewhurst

And Leslie, just to closeout, and be explicit. At this stage there is special treatment in terms of ROE. So everything goes forward and the project is approved, the construction spending would be eligible for AFUDC, and then it would go into rate base when the projects come on line in 2013, 2014 just as normal. And they would receive whatever ROE opportunity was available for the entire business at that point.

Leslie Rich - Columbia Management

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

Moray Dewhurst

That's correct. As I said, realistically the only alternative in this timeframe is going to be incremental natural gas. There just is nothing else that's reliable baseload capacity that can meet of 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.

Leslie Rich - Columbia Management

Okay. Thank you.

Armando Olivera

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

Leslie Rich - Columbia Management

Thank you.

Operator

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

Debra Bromberg - Jefferies & Company

Hi, good morning.

Moray Dewhurst

Good morning.

Debra Bromberg - Jefferies & Company

Just a couple of questions on FPL Energy, on the wind. On the projects that you are 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?

Moray Dewhurst

No, that's reasonable. Again, you may want to just mock 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 factor, good wind resource, you are probably going to end up seeing lower prices and vice versa.

Debra Bromberg - Jefferies & Company

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 out?

Moray Dewhurst

No it's the former, all the time we are getting better at picking places in the development space and so the average expected capacity factor in new projects going into service in the last few years has been higher than the embedded average for the portfolio. So going back for 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.

Debra Bromberg - Jefferies & Company

Okay. And just one non-wind related question, if I could get in quickly. Sayreville, Bellingham and Marcus up 50ish. Should we assume that the output for those are sold under long term contracts or which we assume that if there is some spark spread expansion that you would benefit from that?

Moray Dewhurst

The latter is a better assumption, oil, well both Bellingham and Sayreville were two, where we restructured the contracts to give ourselves and the uptick jointly to release the option value inherent in there. So at this stage, we retain the upside on spark spreads for those.

Debra Bromberg - Jefferies & Company

Great. Thank you.

Operator

We will go next to Vidula Merke at Tribeca Global Management.

Vidula Merke - Tribeca Global Management

Good morning

Moray Dewhurst.

Good morning

Vidula Merke - Tribeca Global Management.

Couple of things. One with regards to the wind projects at the end of the 10 year life, it's my recollection that even though the production tax credit expires at that point in time. Are there not opportunities as you get close to exploration, to find ways to restructure the assets, such that the tax credit can continue beyond the 10 year term?

Moray Dewhurst

Vidula, I think you maybe confusing two different things here. At the end of the 10 years, PTC is what it is. So, it's going to disappear. For a typical contracted project, we will then have another 10 years of contracted life. So at that point, while certainly, conceptually you are correct, it would be possible to restructure the contract. The reality is and the current market conditions, the customer would be looking at a deep in the money position and so we would not have a lot of incentives 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, when the customer is looking ahead to a potentially significant increase in the price. So, I don't think there is going to be a lot at year 10, I think there are going to be more in the latter part of the second decade of most of those.

But, you raised 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 is some clear longer term upside in all those projects.

Vidula Merke - Tribeca Global Management

Secondly, can you also talk about what is the actual useful life of the gases, obviously we have early ones in the 80s and that kind of thing with newer technology and with maintenance and things of that nature, I mean, we’ve talked the useful life of coal plants being in the 50-60 year area. What do you see as the useful life of these assets?

Moray Dewhurst

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 expectations just thinking about with the nature of the assets when you have a relatively simple steel tower with equipments on top is that structure will be there for a long, long time, and what will happen is you will 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.

Vidula Merke - Tribeca Global Management

And 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 a potential range of cost estimates right now for installed KW given some of the environmental challenges and things of that nature?

Moray Dewhurst

Well, I guess that main point to be made about capital cost per KW 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 include or reflect the fact that this will require significant transmission expansion in order to support it that might not be true in other circumstances. But that's a decent number for our particular project.

Vidula Merke - Tribeca Global Management

Thank you very much.

Moray Dewhurst

No hang on a second. Lew wants to make a comment.

Lew Hay

Vidula, I would like to just add something because you hear a lot of different numbers for coal plants and nuclear plants being bantied 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 more of this is site specific and if it’s a Greenfield site and it’s coal, you need real 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, and not what an overnight cost is, just for instance, the power island.

Vidula Merke - Tribeca Global Management

I appreciate the clarification. Thank you.

Operator

We’ll go next to Margaret Jones at Citigroup.

Margaret Jones - Citigroup

Hi, hello. I had two questions, one of which you’ve 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?

Moray Dewhurst

Let me take the leverage issue first. Just as a reminder for everybody, our basic approach is that the balance sheet has driven up our desired credit position. We are very comfortable with the credit position that we have, and therefore when we put together a financing plan, it is 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 am sure continue to do some of that.

On the FPL side, through the current rate agreement, we operate the business at a predetermined equity ratio or that is offset 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 both things, as said that, we would not expect to see major changes in leverage, but we think that, that financial structure has been advantageous for us commercially by 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 erratically increase the gearing.

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

Jim von Riesemann

Yes, thanks Moray. I think fundamentally, our policy is not really to comment on matters of 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, what's in our K, we don't really plan and comment.

Margaret Jones - Citigroup

Thank you.

Operator

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

Jesse Laudon - Zimmer Lucas

Hi, good morning

Moray Dewhurst

Good morning

Jesse Laudon - Zimmer Lucas

Just a quick question, in the past you talked about some longer-term ways of I guess financing the capital wind CapEx as well as the recent nuclear, the dependent nuclear acquisition. Just wondering kind of whether the decision has been made on that, or when the timing on the decision for that would be?

Moray Dewhurst

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 previous question for the 2007, 2008 period. Looking out over that period, if I had to guess today, I would say that somewhere in there, there would probably be some incremental, external equity and modest amount, but we are in a pretty good balance overall. I continue to be very pleased with the hybrid deal that we did last year and we may well look to add more of those and I think, given where the markets are, I probably would do that first. But a lot depends on, obviously we haven't gone through the approval process from Point Beach yet. So some of this is pretty mature 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, so we would subsequently need some external equity to support that extra growth.

So, no real change here. 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 hopefully will be close to closing on Point Beach or at least have much greater clarity on the timeframe.

Jesse Laudon - Zimmer Lucas

So, just clarify, what you mean of the bigger DOA program, you may have wind opportunities towards the higher end of the 750 megawatt target?

And then, just as a follow-up or a different question. You noted that you are kind of ahead of schedule on, a little bit ahead of budget on your latest regulatory power plant. Can you just refresh us on how much you’ve been able to do repairs while keeping construction cost down?

Moray Dewhurst

Yes. On the first part of your question, the answer is yes. On the second one, under run on 30.5, it’s a modest probably on the order of 4% or 5% of the total it was expected to be about a $600 million project and that's probably going to come in $20 million to $25 million under that.

Jesse Laudon - Zimmer Lucas

Great, thanks. Great quarter guys.

Moray Dewhurst

Thank you. I think we have time for a couple more

Operator

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

Paul Ridzon - 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 of years out is that decades out?

Moray Dewhurst

I would say it’s somewhere in between. At least for the next several years our ability to sort of stock pile 40% capacity factor size doesn’t seem to be the constraint. 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 the need more than that are the specific sites. But I think at some point out there, clearly we are going to use up the very best sites, but it’s always [up].

Paul Ridzon - KeyBanc

And given your level and period days you've been doing this and the relationships you 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?

Moray Dewhurst

Well, that’s a tough question to ask me to address in this setting. Let me just say, we are very comfortable with our competitive position.

Paul Ridzon - KeyBanc

Fair enough. Thank you.

Operator

And we’ll take our last question from [Ted Hein, Catapult].

Ted Hein - Catapult

Good morning.

Moray Dewhurst

Good morning.

Ted Hein - Catapult

I was wondering if you guys could 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, say Horizon transaction and the like? And how do you view your portfolio related to some of those transactions?

Moray Dewhurst

Let me take the second part, first, just to follow up my answer to the previous question. We prefer our portfolio. We think its 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, at least in my view, every other aspects of our industry, it is very hard for superior competitors to be greatly better than others in the space. So, what that blows down to is to some extent of a matter ofjudgment, but a few percentage points in internal rate of return I think is realistic. But that in terms of value creation of 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're just being getting a lot of questions from investors and would like to be able to compare our portfolio with those other transactions. So, this is kind of a first step in that direction and we'll certainly look for feedback from the marketplaces as to whether we are missing the buzzer or hitting the mark to maximize the force.

Ted Hein - Catapult

Great. Thanks a lot.

Moray Dewhurst

Thank you.

Operator

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

Moray Dewhurst

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

Operator

And that does conclude today's conference. Again, thank you for your participation.

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