新世紀能源 (NEE) 2010 Q3 法說會逐字稿

Good day, everyone, and welcome to the NextEra Energy third quarter 2010 earnings release conference call.

Today's conference is being recorded.

At this time for opening remarks I would like to turn the call over Rebecca Kujawa, Director of Investor Relations.

Please go ahead, ma'am.

Thank you, Operator.

Good morning, everyone, and welcome to our third quarter 2010 earnings conference call.

Lew Hay, NextEra Energy's Chairman and Chief Executive Officer, will provide an overview of NextEra Energy's performance and recent accomplishments.

Lew will be followed by Armando Pimentel, our Chief Financial Officer, who will discuss the specifics of our financial results.

Also joining us this morning are Jim Robo, President and Chief Operating Officer of NextEra Energy; Armando Olivero, President and Chief Executive Officer of Florida Power & Light Company; and Mitch Davidson, President and Chief Executive Officer of NextEra Energy Resources, which we will rerefer to as Energy Resources in this presentation.

Following our prepared remarks, our Senior Management team will be available to take your questions.

We will be making statements during this call that are forward-looking.

These statements are based on our actual or current expectations and assumption that are subject to risks and uncertainties.

Actual results could differ materially from our forward-looking statements.

If any of our key assumptions are incorrect or because of other factors discussed in today's earnings news release, in the comments made during this conference call, in the risk factor section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found in the Investor section of the website, www.NextEra Energy.com.

We do not undertake any duty to update any forward-looking statements.

Please also note that today's presentation including references to adjusted earnings, which is a non-GAAP financial measure.

You should refer to the information contained in the slides accompany this is presentation for definitional information and reconciliations of the non-GAAP measure to the closest GAAP financial measure.

With that, I will turn the call over the Lew Hay.

Lew?

Okay.

Thank you, Rebecca, and good morning everyone.

NextEra Energy continued to deliver solid results in the third quarter of 2010, increasing adjusted earnings per share by more than 5% over the prior year quarter from $1.38 to $1.45.

The most significant development during the quarter was the settlement agreement we reached with the principle parties involved in our rate case.

We believe this agreement is in the best interest of all of the parties involved, especially the approximately 8.7 million Floridians we serve.

FPL's typical residential customer bill was already the lowest of all 55 utilities in the State of Florida and under the terms of this agreement, which is awaiting approval by the Florida Public Service Commission, retail base rates would remain frozen through 2012.

Armando Pimentel will discuss the elements in greater detail.

For my part, I want to thank those who represent Florida's electric consumers for working with us to craft an agreement that should provide financial stability for customers and the Company alike.

Our investments in Florida's electrical infrastructure which this rate settlement will allow us to continue, have provided significant benefits for our customers.

Compared to the national average, our bills are 24% lower, our operating and maintenance costs are 34% lower, our reliability is 46% higher and our fleet is cleaner, producing electricity with 35% fewer carbon dioxide emissions, 55% fewer sulphur dioxide emissions and 75% nitrogen oxide emissions .

In other developments at FP,L we continued to make progress on our third combined cycle unit at the West County Energy Center, which is expected to come online around the middle of 2011.

When complete, the West County Energy Center will be one of the largest and cleanest fossil fuel facilities in the United States.

In addition, we have begun construction activities of our Cape Canaveral plant.

The modernized Canaveral and Riviera Beach facilities, which are schedule to come online in 2013 and 2014, respectively, are designed today have a heat rate below 6500 compared to a current industry average of more than 10,000.

They are expected to be among the most efficient natural gas plants in the nation with significant customer benefits in terms of fuel and other savings.

Environmentally, the new units are expected to be far cleaner than the units they replace, reducing the rate of sulphur dioxide emissions by 98%, the rate of nitrogen oxide emissions by 93%, and the rate of particulate emissions by 89%.

At Energy Resources we have added approximately 1260 megawatts of new wind capacity since the end of the second quarter of 2009, and expect that at year-end 2010, we will continue to be the nation's leader in wind energy generation.

Looking ahead, while we clearly see some uncertainty in the renewables development business, we continue to see profitable growth opportunities in both the wind and solar businesses.

To that end, we are cautiously optimistic that in 2011 we will add approximately 700 to 1000 megawatts of wind assets to the portfolio.

Now also encouraging is the renewed interest we are seeing in differential membership transactions, otherwise known as tax equity deals, which had all but vanished during the recession.

During the quarter we entered into an innovative transaction that will allow us to reduce the amount of production tax credits that we may have otherwise deferred on our balance sheet in the future.

On the solar front, our 250-megawatt genesis solar project has received the majority of the necessary permits and approvals, including all required approvals from the State of California.

Genesis will be located in one of the best solar resource regions in the United States and we will deploy the same proven solar trough technology in use at our SEGS and Martin facilities.

On the national policy front, I wish I could say that everyone in Washington shared our commitment to expanding the renewable energy industry.

But, as we have seen this summer and fall, the Clean Energy Policy has been caught up by gridlock in Washington.

As long as this uncertainty hangs over the electric power industry, capital that would otherwise be usefully deployed will continue to sit on the sidelines.

This will not only jeopardize the nation's lead in renewable energy technologies that we helped pioneer, such as wind power, but it will cost the economy thousands of jobs at a time when we need them the most.

Of course, even in the absence of new legislation, it appears that is the Environmental Protection Agency will be putting a defacto price on carbon through the enforcement of regulations governing sulphur dioxide, nitrogen oxide, mercury and coal ash.

At a time when analysts and others are predicting that the industry will retire tens of thousands of megawatts of coal fire generation, NextEra Energy remains in the enviable position of producing only 4% of it's power from coal.

With that, I will now turn the call over to

Thank you, Lew, and good morning, everyone.

I would like to share a couple of additional accomplishments before we get into the financial details of the quarter.

During the quarter we continued to execute well against our financing plan, issuing a mixture of debt and equity securities from both international and domestic sources of capital.

As Lew mentioned, during the quarter we completed another differential membership transaction relating to 309 megawatts of wind energy projects in North Dakota and Iowa.

This transaction represents a unique structure for Energy Resources in which a differential part membership investor makes an initial up-front payment and will make additional payments over time tied to the energy production of the wind projects.

This structure allows us to raise tax equity for existing projects that have been previously financed with project debt.

We continue to seek opportunities to minimize the growth of deferred production tax credits, or PTCs, on our balance sheet, and the availability of this structure would allow us to receive compensation for future PTCs before we would have otherwise been able to monetize them.

We would consider using this structure again in the future.

In September we sold 20-year FPL Group Capital senior notes with a principle amount of JPY10 billion, at the same time, FPL Group Capital entered into swaps to hedge against currency movements and fixed the interest rate associated with the notes.

Net proceeds were $120 million.

As we highlighted at the investor conference, we believe we are very well diversified in terms of primary markets and regions when it comes to raising debt.

We will continue to be credit globally and execute those transactions that we consider to be most favorable.

Also in September we sold $402.5 million of equity units, which consist of a contract to purchase NextEra Energy common stock in the future and an interest in a five-year FPL Group Capital debenture.

We were pleased with the terms and note that this issuance is consistent with the equity plan we discussed with investors in May.

And lastly in October, we entered into approximately $750 million of forward-starting interest rate swaps, designed to lock in rates for future debt issuances, which are expected to refinance scheduled maturities of FPL Group Capital debentures in 2011 and 2013.

Long-term interest rates are at historically low levels, and we plan for these instruments to allow us to hedge a portion of our future debt refinancings.

Earlier this month, the Texas Public Utilities Commission granted our certificate of convenience and necessity, or CCN, for a 36-mile portion of the CREZ Transmission Project, awarded to our subsidiary Lone Star Transmission.

THE CCN gives us assurance that we will get recovery on this portion of our investment and it clears the way for us to begin construction on this portion of the line.

We requested that this section be evaluated separately in the expectation that it would allow us to expedite the process for this portion of the line.

We are optimistic that we will get the CCN for the balance of the 300-mile project by the end of this year.

In the third quarter of 2010, NextEra Energy's GAAP net income was $720 million, or $1.74 per share.

NextEra Energy's adjusted 2010 third quarter adjusted earnings and adjusted EPS were $602 million and $1.45 per share.

The difference between the GAAP results and the adjusted results is the exclusion of the mark in our non-qualifying hedge category and the exclusion of net other than temporary impairments on certain investments, or OTTI.

For the third quarter, Florida Power & Light reported net income of $308 million, or $0.74 per share.

Before we get into the details of the quarter, I would like to spend a couple of minutes on the rate case settlement agreement.

As Lew mentioned, but it bears repeating, we strongly believe this agreement is positive for our customers and our investors alike.

Under the term of the agreement, retail base rates would remain frozen, as specified in the agreement, through the end of 2012, and the authorized regulatory ROE, or return on equity, would remain at 10% plus or minus 100 basis points.

FPL would be permitted to recover the base revenue requirements associated with West County Energy Center Unit 3 through the capacity clause up to amount of the projected fuel savings attributable to the unit.

This mechanism allows for current cash recovery without an expected increase in the customers' total bill.

We currently estimate that the 2011 fuel savings will be roughly in line with, but slightly less than, the revenue requirements for the plant based on current commodity prices and generation mix.

This settlement would allow FPL the flexibility to vary the annual amortization of theoretical depreciation reserve surplus or depreciation credit to keep FPL's earned regulatory ROE within the approved range of 9% to 11%, subject to certain annual and total caps.

The $267 million annual cap on the depreciation credit applies to each year of the agreement, but any unused amount in a given year could be carried forward and would be available for use in subsequent years.

No more than $776 million of the depreciation credit could be taken during the term of the agreement.

The agreement has the support of the Attorney General's Office, the Office of Public Council and the other principle parties in our rate case as well as the recommended approval of the PSC staff.

Given all of this, we believe approval is the most probable outcome and this forms the basis for our accounting for the quarter.

As such, on a year-to-date basis, and as a result of favorable weather, we have not recorded any depreciation credit in order to be in compliance with the regular ROE provisions of the settlement agreement.

The table shown here summarizes the earnings drivers for Florida Power & Light for the just-completed quarter.

In total, earnings decreased by $0.01 per share, the increase in base revenues related to West County Energy Center units 1 and 2, weather and the impact of our base-rate increase were roughly offset by the increase in depreciation expense.

Not only as a result of the addition of the West County units but also due to the reduction of surplus depreciation amortization which increases net depreciation expense consistent with the pending settlement agreement.

We are continuing to see some improvement as it relates to our customer metrics.

The table in the upper left shows the change in retail kilowatt-hour sales versus last year's comparable period.

Overall, retail kilowatt-hour sales grew by 3% and improvement due primarily to higher weather-related usage, but also for modest growth in customers.

Non-weather-related, or underlying usage growth, mix and all other, was essentially flat.

As depicted in the graph in the upper right hand corner, during the third quarter of 2010, we had approximately 27,000 more customers than we did in the comparable period of 2009.

We continue to be cautiously optimistic that our customer growth is returning and we are encouraged that we continue to see modest increases in customer counts.

The graph on the bottom left of the page shows inactive and low usage customers, which we believe depicts the level of empty homes in our service territory.

Although inactive accounts are down relative to last year, they remained relatively flat as compared to the second quarter.

Low usage accounts continued to decline during the third quarter.

The chart on the bottom right depicts the level of new housing starts for single-family homes and FPL service territory.

Housing starts are a fairly good leading indicator of certain additions to the customer base roughly a year out.

After experiencing rapid declines during the recession, the volume of housing starts appears to have stabilized.

However, the current volume of permits remains low, or about 12% of what it was at the height of the housing boom that preceded the recession.

We continue to see some improvements in many of our customer metrics and for the longer term believe Florida will continue to be a very attractive destination to which people will move.

In fact just this month, Florida was selected as the second most popular state to which baby boomers would like to move according to a Harris Pole survey.

However, in the short-term we remain cautious about the strength of the economy.

Let me now turn to energy resources.

Since the end of the second quarter of 2009, we have added approximately 1260 megawatts of new wind generation and continue be the nation's leading producer of wind power.

In addition, we have continued to make progress on our solar development pipeline.

During the quarter, our Genesis solar thermal project received approvals from the California Public Utilities Commission and the California Energy Commission.

Genesis has also been selected by the Bureau of Land Management as a fast track project and we are hopeful that the project will receive BLM approval in next couple of weeks.

These approvals are major milestones in the development of this roughly $1 billion project, which we expect to be brought online in 2013 and 2014.

This project has been many years in the making and we are very encouraged to see state and federal agencies working together to bring the benefits of this lean energy project to the citizens of California.

Energy Resources reported third quarter 2010 GAAP earnings of $386 million, or $0.93 per share.

Adjusted earnings for the third quarter, which exclude the effect of non-qualifying hedges and net OTTI were $267 million, or $0.64 per share.

As we mentioned in the first quarter we have changed the methodology for allocating interest and shared costs to affiliates and it's historical figures have been changed to reflect the change.

Energy Resources third quarter adjusted EPS was up $0.05 relative to last year's comparable quarter.

New wind investments contributed $0.05 per share, of this roughly $0.03 reflects our ability to recognize a state investment tax credit on some of our wind projects.

As always, we will continue to seek opportunities for enhanced economics in states with incremental incentive.

We continue to estimate that we will elect to take convertible investment tax credits, or, as we call them, CITCs, on approximately 600 megawatts of new wind generation to be placed in service in 2010.

In aggregate, the existing portfolio contributed $0.05 relative to the prior year.

Our existing wind assets contributed $0.04, driven primarily by a better wind resource.

Performance from our existing merchant assets was down by $0.01, while contracted assets realized a $0.02 increase due to the commencement of long-term contracts on the Marcus Hook 750 and Blythe facilities.

During the third quarter evaluation of our shale gas well drilling program, we determined that we would not move forward on a subset of future drilling opportunities, whose output we had previously hedged.

As we have previously communicated, upon approval of a well-drilling program, we hedged the anticipated production from those wells in order to lock in a substantial amount of the well's economics.

Our decision to not proceed on these specific wells resulted in a $0.04 after-tax gain when we exited the hedge position.

Consistent with what we discussed at our investor conference earlier this year, we continue to be interested in natural gas infrastructure opportunities.

The customer supply and proprietary power and gas trade and businesses were down by $0.04 relative to the prior year, primarily due to lower contributions from power and gas trading.

As we have said before, opportunities in this part of the business fluctuate based on a number of factors, and while last year's quarter was up $0.07 compared to 2008, this year's third quarter did not have as many opportunities for us to pursue.

To be consistent with the information we provide to you on the gross margin hedge slides, Gexa is included in customer supply businesses for presentation of comparable earnings.

The customer supplied businesses continue to do very well on a year-to-date basis.

All other factors were negative 5%, $0.05 primarily due to higher interest expense.

Although our expected gross margin is very well hedged, the current commodity price backdrop has an impact on our business.

This manifests itself in two ways.

First in the portion of our existing asset that is uncontracted and unhedged, which is roughly 8% of our existing asset gross margin in 2011 and 17% in 2012.

Secondly, as we have discussed before, it is one of several items that affects counterparties interest in signing long-term contracts, for renewable generation.

In the forecast we presented at the investor conference in May of this year, the 10-year natural gas strip has declined 16% while a 2011 calendar strip has declined by 21%.

In the near-term our open gross margin is relatively modest, and as such, there's not much of a significant direct effect on our gross margin as it relates to our existing assets, but there is some impact.

Additionally, indirectly, the lower power and gas price affect our expectations around the currently uncontracted wind assets that we expect to contract under long-term power purchase agreements.

Let me discuss that in a little more detail as we turn to our hedging status for 2011 and 2012 and expected equivalent gross margins.

Over the last couple of years, we have increased the percentage of our business that is hedged in the near-term, mainly as a result of what we believe would be a more uncertain commodity price environment.

In addition, we continue to take steps to minimize the risks and improve the visibility of the earnings and cash flow profile for the portfolio.

As I mentioned earlier, contracts that were effective this year, on approximately 1190 megawatts, representing both Blythe and Marcus Hook 750, helped earnings for the quarter.

Additionally, since the beginning of 2008, we have signed approximately 2110 megawatts of wind PPAs and approximately 350 megawatts of solar PPAs.

For 2011, we are 92% hedged on expected equivalent gross margin on our existing assets.

Across all of the Energy Resources businesses, the midpoint of our total expected equivalent gross margin has decreased by approximately $155 million since the second quarter.

I do not focus too much on this midpoint, but I know that many of you do, so I have chosen it here as a frame of reference.

The three main drivers of this decrease are in our new asset additions, in our existing wind assets and in our power and gas trading business.

As we do every year at this time, we have moved the new assets expected to be in service by 2010 up to the appropriate categories of existing assets, and so what you see now in the new investment line are the expected results of the assets we expect to place in service in 2011.

For these 2011 asset additions our gross margin estimate is down approximately $65 million since the second quarter due primarily to lower estimated CITC elections associated with reduced new build wind assumptions and solar assumptions.

Net of the positive impact of the 2010 asset additions that moved into existing assets, the contracted wind assets gross margin is down approximately $35 million, primarily due to the sustained lower power and natural gas prices on uncontracted assets that I spoke about just a minute ago.

Finally, the power and gas trading business is down roughly $55 million due to our expectation in the near-term that the low volatility and low price environment will mean that there are less opportunities for this business.

Turning to the 2012 gross margin, we are 83% hedged on expected equivalent gross margin on our existing assets.

Although there are many puts and takes when comparing 2011 to 2012, I wanted to highlight a few of the more significant items.

Please note that we did not include the impact of any new wind or solar generation that we expect to build in 2012.

Although the operating earnings impact for the new investments put in place in 2012 could be modest as a result of the expected commissioning dates, we do expect to qualify for CITC on a good portion of our 2012 wind and solar development, but that margin is not included in this slide.

As we did last year, we will add 2012 new asset information as the year gets closer.

In the new investment line, you will only see the full earnings impact from the new wind and solar assets we expect to build in 2011.

Our contracted wind segment is expected to be down roughly $20 million compared to 2011, which is roughly the difference between the expiration of PTCs and expected PPA pricing on new contracts for the currently uncontracted assets, as well as PPA price increases embedded in our current PPAs.

Our contracted other segment is expected to be roughly flat due to the full-year effect of the Uprate we expect to complete at our Point Beach Nuclear Facility in Wisconsin, net of the expiration of some power sales contracts on two of our gas-fired facilities in the northeast.

Our hedged wind and merchant northeast other categories are expected to be down approximately $45 million each due to the roll off of higher priced hedges.

Our gas infrastructure business reflects our shale gas drilling program and the majority of this margin is currently hedged.

The targets for the customer supplied business in power and gas trading reflect a modest increase over reduced 2011 expectations.

I would like to provide a brief update on our wind development plans for the remainder of 2010 and 2011.

For 2010 we currently have approximately 680 megawatts of new wind already in service or under construction and likely to be commissioned.

Although some megawatts may rollover to the first part of 2011.

We are mindful that this is likely the toughest wind development market in some time.

For 2011, we remain cautiously optimistic that we will add between 700 to 1000 of wind generation.

Although we have had some success this year in signing long-term PPAs, we continue to see some sluggishness as relates to securing long-term PPAs.

At the same time, we are seeing reductions in the cost to build new wind projects so the average economic returns we are expecting are still attractive.

We would like to provide a little more clarity on 2010 and 2011 adjusted EPS guidance.

Will be approve we expected adjusted earnings per share to be within the lower half of the previously disclosed range of $4.25 to $4.65.

In the quarter FPL lowered it's surplus depreciation amortization, which has the effect of increasing net depreciation expense by approximately $0.12 of adjusted EPS.

This reduction is consistent with the settlement agreement.

Looking at the longer term picture though, the current reduction in earnings as a result of higher depreciation expense in 2010 provides us a bit more certainty regarding our 2012 earnings and returns at FPL.

If the settlement agreement is ultimately rejected, which we believe to be a low probability based on the support it is receiving from interveners, 2010 results could be at the high-end of the original range due in large part to additional surplus depreciation and amortization which FPL would likely record.

Turning now to 2011, we last indicated that our 2011 adjusted earnings would be roughly in line with the 2010 range.

Since then, we have had a number of positive and negative developments that effect our adjusted earnings per share expectations.

On the positive side, the rate case settlement agreement would allow for substantial recovery of West County Unit 3 in 2011 on a cash basis.

However, at Energy Resources, the factors that I just discussed related to 2011 gross margin have negatively effected the earnings outlook.

First, as we noted in the updated 2011 gross margin estimates, we are now expecting fewer CITC elections than we previously expected.

This revision is a result of our view that the wind development market will continue to be challenging next year.

Second, based simply on the fact we have some uncontracted wind assets and a declining commodity price environment, we need to reduce gross margin expectations.

In addition, the timing of expected PPAs has been slightly extended.

And third, we think there should be reduced expectations related to our proprietary trading business in 2011.

As we have shown you before, these businesses go into the year largely unhedged unlike our existing assets, and it makes sense for us to reduce expectations in this area based on what we perceive as the near-term opportunities in the market.

Incorporating all of these factors, we now believe that we can narrow the range of our 2011 adjusted earnings per share estimate to between $4.25 to $4.55.

We continue to feel comfortable with the 5% to 7% average annual increase in adjusted EPS through 2014 from a 2009 base, although we do not expect that average to necessarily be the actual increase in each year-to-year period.

We also continue to be open to asset acquisitions that fit our portfolio and investment profile and there are quite a number of those opportunities at this time.

While we look at most opportunities, we remain committed to our disciplined approach to capital deployment.

Over time, we have strived to be in a strong financial position, which enables us to take advantage of those opportunities that meet our criteria.

As always, these potential opportunities are not reflected in the specific development targets we have provided to you.

To summarize the 2010 third quarter on an adjusted basis, FPL contributed $0.74 per share, Energy Resources contributed $0.64 per share, and Corporate and Other contributed $0.07 per share, primarily as a result of an adjustment related to previously deferred taxes.

That is a total of $1.45 compared to $1.38 per share in the 2009 third quarter, or about a 5% increase year-over-year, Thank you for listening, and with that, I'll turn the call over the questions.

Thank you.

(Operator Instructions).

We will go first with Daniel Eggers of Credit Suisse.

Good morning, guys.

Good morning, Dan.

I was just following up on a couple of the wind comments.

Number one, of the 680 megawatts you guys will have or expect to have done this year, how much of that is under PPA relative to being contracted?

It's roughly half, Dan.

So half is contracted and half is --?

Yes, it is roughly half.

And then if we look to next year's plan of 700 to 1,000, what is going to be your threshold for the need for PPAs relative to the decision to deploy capital?

Well, when we, and as we have said before, when we go into these decisions on a year-ahead basis, we are trying to deploy capital either where we already have a long-term power purchase agreement, which we do for roughly 250 megawatts or so of the 2011 development plan.

But we try to do it in those areas where we think there's a high likelihood, either before construction begins, during construction or a short time afterward, that we will get a power purchase agreement.

That has not changed.

I have talked about that a little bit before.

Many of our projects do not have a long-term power purchase agreement when we begin.

In the past, many of them did have a power purchase agreement, or we expected to get a power purchase agreement by the time construction ended.

But here in the last 12 to 18 months, the process has been a little slower.

So, it doesn't mean we are not going to deploy capital if we don't have a long-term power purchase agreement in hand, but it does mean we're going to be a little more cautious than we have in the past, because it has taken a little longer in some cases to get an agreement than we originally believed.

Okay, and then if I think about the qualification for converting to the refund ITCs, how are you guys committing to the capital or committing to projects today to be able to ensure that you hit the year-end 2010 deadline to be able to qualify for both 2011 and 2012?

Well, there's a -- Dan, there's a couple of ways to actually qualify for CITC in 2011 and 2012, right?

One of them is a Safe Harbor provision in the rules, and the other one is actually the start of construction.

We are going to use both of those to qualify a majority of our projects, wind and solar projects, in 2011 and 2012, and for solar, actually in 2013 and 2014.

We have talked about the Genesis project, obviously there are others that we have in our pipeline that we have not discussed.

And that's something that we pay a lot of attention to.

We -- as you can imagine as the leader in the industry, we have access to, and have been able to, have discussions with a lot of the folks that are writing these rules.

So at this point, we feel the fairly comfortable that a significant portion of our development plans in 2011 and 2012 for wind, and 2013 and 2014 for solar will qualify for CITC.

Okay.

Just one last question, on the 2011 guidance, you guys -- should we -- is it fair to assume that you are placeholding a 10% earned ROE at the utility to get to the midpoint of next year's number?

It -- I mean it would be fair to assume anything that you think is fair.

But we are not going to comment on what we believe the ROE would be.

We may in the future, but clearly, if the settlement agreement is approved, we would be required to stay within the 9% to 11%.

If we are under, and this is in the agreement, if we are under the 11%, we would have to use amortization or the depreciation credit to get us up, not necessarily -- that doesn't necessarily mean we have to get to 11%.

If we are over 11%, we would not be able to use any depreciation credit to keep us over 11%.

Let me just go back on something I just said, because as I said the last part of it, I misspoke on the first part.

If we are under 9%, we are required to use amortization credit to get us up to 9%, and if we are over 11% we can't use any to keep us over 11%.

Okay.

Thank you.

Next we'll go to Greg Gordon of Morgan Stanley.

Thanks.

So I just wanted to clarify two things.

First, you maintained your guidance range for the overall amount of renewables you are going to build next year, but I presume presumptively you have lowered the amount you are going to do within that range because you have lowered the amount of CITC you think you are going to get from new projects next year, is that correct?

That's correct, Greg.

Okay.

And then, second, your presumption that the midpoint of your gross margin range at merchant business and a 10% ROE equals the midpoint of your guidance range is not something that you are willing to comment on right now?

I am sorry, Greg, did you --?

Just based on your answer to the last question, I think the investors rightfully presume that if you were in the midpoint of your ROE band, and you were in the midpoint of the gross margin guidance you gave for 2011, that would probably approximate the midpoint of your earnings per share guidance.

You just said that, given that the deal is still pending, you are just not willing to corroborate that?

No, no I was trying to answer another question that I thought Dan was trying to get to.

I think a presumption by investors and analysts that the midpoint of 10% was in our previous guidance, I think is appropriate.

You are trying to link that previous guidance, ie, at 10%, and also 2011 earnings.

Let me kind of explain it this way, and maybe it will be helpful to you and others on the call.

The amount of gross margin reduction for what I will call the lower build in 2011 for both wind and solar is roughly $0.10.

And you can take the gross margin number, you can tax effect it, it is roughly $0.10, and again that would be a reduction.

The reduction in the lower commodity prices from -- due to our on contract wind assets and slightly extending the term of the merchant time that those projects will be in a merchant state is roughly $0.07.

The reduction in power and gas trading -- proprietary power and gas trading that I mentioned in 2011 is also $0.07.

In this call, I also said that the amount of fuel savings attributable to West County 3 are roughly in line with, but slightly less than, the revenue requirements, which is roughly -- the revenue requirements are roughly $100 million.

If you add all of that together, right, and again, I am going just from the revenue line, I'm not really focused on the bottom-end.

But if you add all of that together, you roughly get a net $0.10 deduction from whatever midpoint you started with, right, if you add all of that together.

What we've actually done is we have brought the midpoint down of our 2011 guidance down $0.05, from $4.45 to $4.40, that's the way I look at it.

I was -- okay, that makes a lot of sense, and that was actually more detail than I was asking for.

Let me rephrase the question.

If I take the midpoint of your current 2011 earnings guidance --.

Yes.

-- and I presume that is -- assumes that you earned 10% ROE at the utility more or less, and that you are at the midpoint of the gross margin guidance range for the merchant power business.

As a starting point.

I think you can -- that is the question, Greg, asked.

I think the assumption of using 10% is a reasonable assumption.

What I was trying to point out to Dan, is that the range is 9% to 11%.

If we get under 9%, we would be required to use a lot of -- we'd be required to use amortization to get up to 9%.

Now, in my comments today, I also indicated that we had not taken any depreciation credit year-to-date for 2010, and we can use a total of $776 million during the three-year period of the pending settlement agreement.

So I don't think I have to connect the dots necessarily, but that should give everyone an indication of where the ROE range would be, it would be a little smaller than 9% to 11%, for 2011.

Okay.

Thank you very much.

Next we'll go to Steve Fleishman of Bank of America Merrill Lynch.

Hi.

Just to clarify for 2011, how much CITC election do you effectively have in for that year.

Steve, we haven't said, but this year -- last year we had a little over 800 megawatts.

This year we have roughly 600 megawatts.

I think the expectation is that next year we will have under 600 megawatts of CITC.

So I think that if you use a range that's roughly 400 to 550 megawatts of CITC, I think that would be reasonable.

Okay.

And can you just remind us, from a sensitivity standpoint, given that the wind outlook generally is unknown to some degree, what's the earning sensitivity to let's say 100 megawatt change from that assumption?

100 megawatt change in CITC?

Correct.

That number was at the top of my mind.

Hold on just a second.

Roughly $12 million after tax for every 100 megawatts.

Okay.

Is CITC.

So, about $0.03?

Yes.

A little less, but yes.

Okay, so in a worst case that you had no wind growth, it would -- we're talking at most $0.15?

If you had no wind growth from -- give me your calculation.

CITC -- well 500 megawatts at $0.03 each.

Right.

Yes, that's true.

Okay.

And then just with respect to -- .

Steve, this is Lew, I'm sorry to interrupt, but I just want to make one comment about the uncertainty on wind.

And Armando said it is clearly a tougher market right now than what we might have experienced a few years ago.

But I want to point out that even in the frothiest times of the wind market, we didn't have 250 megawatts of PPAs as of the end of the third quarter, when we're looking out at the next year.

So some of you who aren't as familiar with the wind development business, a lot of times we would have a lot of things in the works but we didn't have deals signed up at that point.

And so I would not -- I want to make sure nobody is looking at what we just reported as being a big negative.

It is a tough market out there, but we gave you our best estimate as to what we are seeing, and I think you could argue there's more variability about it than maybe what was happening in the frothiest markets.

But we have a fair amount of visibility.

So I wouldn't discount the guidance we just gave you.

Okay.

No, I wanted to gauge that sensitivity relative to worst case as relative to merchant power market risk that's out there as well.

So, okay.

And then I guess one other question with respect to the future growth.

Are you still assuming the CITC elections continue longer-term, beyond 2012 there's some extension?

We -- well, internally we are, but if you, as I mentioned back at the investor conference, and the only reason this is -- this is important for other reasons, but one of the reasons that it is important is the 5% adjusted EPS growth rate from a 2009 base to 2014.

As I indicated at the investor conference, if you remove that assumption, ie, there is no CITC on wind assets in 2013 and 2014, at that point, we would still fall well within the 5% to 7%.

I have redone the calculation just in the last couple of days.

You still fall between the 5% to 7%.

Okay.

How much on contracted wind do you have today?

Right now?

For 2011?

Yes.

How much we -- hold on a second.

How much do you have on contracted as a portfolio right now?

How much contracted wind do we have in the entire portfolio?

I'm sorry, uncontracted.

Uncontracted, sorry.

Is roughly -- it is -- no, it is between 300 and 350 megawatts currently, that has been constructed and does not have a PPA.

Okay, great.

Thank you.

Next we'll go to [Jeff Cobolo of Dukane Capital].

Good morning.

It is John, actually.

How are you?

Good.

I was looking at your growth rate, Armando, and obviously in the release you reiterated that 5% to 7% growth through 2014 off the 2009 base.

And one thing I am trying to better understand is, if I look at the 2012 portfolio, financial information slide, for example, and I look at the different components of the non-regulated portion of the business, obviously the contracted wind and the contracted other portions of that business have longer-term contracts or PPAs associated with it.

But what I am trying to better understand is, the hedged wind in Texas, for example, and then the merchant portion of it, which includes Seabrook and the main hydro assets and the spark spread assets and what not, and then some of the gas infrastructure E&P investments that you have been making, and also the power and gas trading, and power supply base businesses, that portion of the non-regulated businesses, obviously has commodity exposure as you discussed, that you hedge but obviously more on a shorter-term basis.

So if the growth rate is 5% to 7% out through 2014, obviously you have only provided hedge information out through 2012, how do we think about what your expectation is that you're embedding for commodity prices in 2013 and 2014, or this portion of the portfolio that is commodity exposed to get to that 5% to 7% range.

Are you assuming current forward curves, are you assuming a discount to current forward curves, how do we think about that?

John, on that specific question, we mark to the forward curves at the end of every quarter.

For purposes of the quarterly information that we provide to you, although we do it at the end of every quarter, it is a couple of weeks before the quarter that we take the forward curve.

So whatever the forward is we built in here.

And, again, I will remind you.

I said it during the presentation, but it bears repeating.

For 2012, what you do not see on there are any contributions from 2012 assets.

Got it.

So the 5% to 7% growth rate, when you rethink that on a quarterly basis or whenever you look at reaffirming that, for the portion that's beyond 2012, so 2013 and 2014, you just take the forward curve and use that and see where that lines up with that 5% to 7% growth rate.

Is that correct?

Yes.

Great.

Thank you.

Next we will go to Jonathan Arnold of Deutsche Bank.

Good morning, guys.

Good morning.

Just hoping to -- sorry to come back to this uncontracted question, but the answer you just gave of 300 to 350 currently that is constructed, does that intersect at all with the 680 that is under construction or in some sort of either in construction or completed?

No, no, there's two numbers, right?

There's currently constructed and uncontracted is roughly 350 megawatts.

It is a little less than that.

The last time I mentioned that number it was 400 megawatts.

The amount that we would expect to have at the end of the year, ie, because you are referring the 680 megawatts, some of those 680 megawatts do not have current contracts.

So, unless -- and it could, but unless something -- unless we get a contract by the end of the year on some of those projects, the end of the year we'll roughly have 700 megawatts of uncontracted wind plants that have been constructed.

And that is different -- just to add to that, we have roughly 1,700 megawatts of uncontracted but hedged wind projects out in Texas.

Now when we built those, those weren't ever expected to be contracted.

So the 700 that I am talking about for the end of the year, are those that we do expect to get contracts on, but we do not have contracts on, or we do not expect to have contracts on at the end of the year.

Is that helpful?

Yes?

It is.

Thank you.

So there's the 680 is a separate bucket effectively from the 350?

It is a separate -- .

Half of the 680 gets added to the 350, and that's your -- .

Right.

So there has been a number of questions asked today, and I thought we were all on the same page, so let me try it again.

It was either Dan or Greg that asked about the 680, and I said roughly half of that is under contract.

Right?

Let's just say it is 350 under contract, 350 isn't, right?

You add that to the 350 that I have already told you that's not an issue, that's not contracted, and you get roughly 700, again, assuming we don't get anymore contracts by the end of year, which I hope that we do.

That's very clear.

Thank you, Armando.

And then, I just wanted -- on the utility I wanted to ask something about the -- your comments on customers and growth.

I noticed you changed the presentation this quarter to look at the trailing 12 customers rather than sequential quarter, but as we looked back to June, it looked like you only added maybe 3,000 customer in the third quarter, which has obviously slowed down -- .

We -- .

Can you talk about that a little bit?

Yes.

Historically, probably, I don't know, towards the end of 2008 or 2009, before that time we had always shown this customer growth chart the way you're seeing it now.

We compared the average customers this quarter to the average customers to the year-ago quarter.

We had always done that, but when we got to the period of significant customer reductions, or at least significant for us, we wanted to provide investors some additional information.

Because it was almost -- it was less meaningful to look at what happened a year ago when we were getting significant changes every month.

And so for the last probably 12 to 18 months, and it might be a little shorter than that, we switched over to, let's just tell you what has happened with sequential quarters.

Now, you might argue with us, I think we have a little more stability now, and because we have a little more stability now, we have gone back to what we were doing before because it is a better comparison than just the sequential quarter, primarily because of the seasonality in the business.

So that's why we have gone back to it.

To answer your question, one of your questions -- maybe I answered some already, we have on a sequential basis about 3,000 more customers at the end of September 2010 than we had at June of 2010.

I realize that.

I just felt -- that felt like it was a slowing pace rather than a continued improvement, maybe that's just the seasonality.

It absolutely is the seasonality.

If I go back to -- these are rough numbers, a year ago September on a sequential basis, we had lost 2,000 customers.

In 2008, September, again a sequential basis, we had lost 11,000 customers.

In September of 2007, when things were still going pretty darn good, on a sequential basis we had only added 10,000 customers.

So I am not necessarily disappointed by the 3,000 customers.

I am pretty happy with the 27,000 quarter-to-quarter.

We haven't seen that type of quarter-to-quarter growth, 27,000, since the June 2008 quarter.

Okay.

Thanks a lot.

Next we will go to Ted Heyn of Catapult.

Good morning.

Morning.

Armando, a quick question on the comment you made on, if the settlement were not approved that you would actually be at the high end of your guidance, did I hear that correctly?

For 2010?

Ted, you did hear correctly.

And the reason for that is under -- if the settlement isn't approved, which, by the way, I think would be an -- and I truly mean this, would be an absolute travesty for our customers in Florida, because it is a great deal to have these fixed rates through the end of 2012.

But if the settlement is not approved, because of the significant positive weather that we have had this year, and you would go back to the rate case settlement.

And again if the settlement isn't approved, we still have to deal with the motion for reconsideration, but let's put that aside for a second.

The very real issue for us -- we think that would be a win-able case for us, but putting that aside, if you go back to the rate case, you essentially would have to amortize $224 million on a pre-tax basis, that's a credit to depreciation expense for the entire year, on a pre-tax basis.

In addition to the favorable weather that we've had at Florida Power & Light Company, which is roughly $0.17, $0.18, $0.19 on a year-to-date basis.

So you can see that when you put all of that together, you would get towards the very high end of the $4.25 to $4.65 range.

That's not what -- let me just say, that is not what I would like to see.

That's not what we are hoping for.

But I guess that highlights the fact that this settlement allows you some flexibility, and essentially you're -- in an indirect way, you are banking the good weather, and it is actually, while 2010 will be coming down, that lever will be available for you in either 2011 or 2012 to help facilitate earnings growth.

I think my comment was -- I think that's a fair way to look at it.

Clearly, what the long-term agreement does is give our customers significant benefits and certainty, but it also provides the Company some financial certainly during these times.

Okay.

And then just one more question on this.

When you walk through the drivers of what's coming down for 2010, you highlighted it looks like about $0.24 of negative drivers from the resources side, and saying it is a net $0.10 positive, so that implies that the fuel savings from West County is about $0.14?

Is that the right way to think about it?

I think you meant 2011, is that right, Ted?

2011, yes, I apologize.

I think that's a reasonable way to look at it.

Okay.

Does that $0.14 include any use of the depreciation lever from the settlement?

Or is that solely the fuel savings from West County 3?

I think you should think of it solely as the fuel savings from West County 3.

The guidance that we have given you for 2011 of $4.25 to $4.55 clearly has an estimate in there for what we believe we would need to use of that depreciation credit, which would be consistent with the pending settlement agreement.

Okay.

But it seems like, if those are the real drivers, if the $0.14 is really related to the fuel, it looks like maybe you're saving most of your dry powder on the amortization side till 2012, is kind of what I am getting at.

It seems like this will allow you to have a significant --or a decent growth rate at the utility, with all of the accounting mechanisms and fuel savings and stuff like that.

Is that a good way to think about it?

I guess I would think about it just a little differently, Ted.

This is a great deal for our customers.

And at the same -- it provides them significant stability -- financial stability all the way through the end of 2012, and it continues to allow us to put some assets that will longer-term save our customers a lot of money.

In return for that, the settlement provides some financial stability for us during these times, and potentially keep us from filing a new rate case during these times.

So there's clearly some puts and takes in the agreement.

Overall, as I have said before, and as Lew has said before, this is a positive vote for our customers, and for the Company, and it does provide both stability through 2012.

Okay.

Thank you.

And the other thing -- this is Jim Robo.

The other thing I would add, just for 2012 at the utilities, you also have the full-year impact of West County 3, not just the half-year impact.

You also have the benefit of both the up rates, as well as the AFUDC on Canaveral and Riviera.

So there are several growth drivers for utility in 2012 versus 2011.

Got you.

That's helpful.

And then just one more quick question, on the analyst day, when you talked about the 5% to 7% growth rate through 2014, it seemed like you were actually saying that that was conservative, and that if you did the math you could potentially exceed that.

With the adjustments that you have made to the near-term forecast, is that still valid, or are you now feeling that the 5% to 7% is less conservative?

Yes, I didn't say conservative.

I think the questions that were presented was, well, gee whiz, you have a growth rate of earnings at FPL of X, of Y, you've got a growth rate of energy resources going from X to Y, and what I said was, you have to also account for the fact that we have dilution, we have other expenses going into this, but that I felt comfortable with the 5% to 7%.

It was clearly towards the high-end, but I also said that there was a significant amount of execution to do that from 2010 through 2014, and that I was concerned with the state of the economy.

What has happened since then is, some of those things have kind of played themselves out.

We are now talking about reduced build, at least from what we had in our plan, next year, although we are still in the range of 700 to 1,000 megawatts of wind.

So some of those things have kind of played out.

Now's not the time for me to discuss whether we are at the top-end or at the bottom-end.

We feel comfortable with the range that we provided, and I will repeat what I said back then, that in this economy, there remains a significant amount of execution risk on our part.

But I am -- as I look at the details of the capital investments that we have to make, both at the Florida Power & Light Company side and at the Energy Resources side, including transmission development in Texas, I feel pretty -- I feel like there's some darn good opportunities for us to invest capital at some very attractive rates from now through 2014.

And I feel comfortable with the range, but we shouldn't forget that there is still execution risk.

And -- this is Jim Robo again, let me just add that there have been several questions around 2013 and 2014.

I think it is important to remember -- and Armando just mentioned one of the drivers for 2013 and 2014, which is the transmission -- the $800 million of transmission investment in Texas.

But we have $2.5 billion of solar investment that is about to become under construction with signed contracts that come online in 2013 and 2014.

Those are significant earnings drivers for Energy Resources in the 2013 and 2014 period, and aren't reflected in anything you see in the 2011 and 2012 hedging charts.

Next we will go to Ashar Khan of Visium Asset Management.

I think all of my questions have been answered.

Thank you.

Next we will go to Jay Dobson of Wunderlich Securities.

Good morning.

Most of my questions have been answered, but, Armando or Lew, I didn't know if you could talk about the approval of the skid of the settlement and what sort of timing -- I know there's a number of issues at play there, but what we should assume on timing?

This is Armando Olivera, confuse you with both Armando's here.

It is currently scheduled for the November 9 agenda conference.

So all the matters that have been deferred have now been brought forward and put on that agenda.

It will be a function of whether the District Court of Appeals has ruled by that date or not.

If it doesn't rule by that date, there are several more dates left in the year, and of course, the Commission could always opt to have a special agenda to get this approved.

We feel pretty good, there's a lot of -- all of the parties really are pretty actively supporting the agreement and asking the Commission to vote on it as soon as possible.

Great.

Thank you, and then back to the other Armando, on the wind slide you talked about construction costs coming down.

Just maybe give us a little clarity on that, and how that plays into construction costs?

Well, we have seen, really since 2008, we've seen construction costs in this industry come down.

And I would continue to say, as I've said before, that there's more downward pressure on costs than there is upward pressure.

Here over, I would say over the last six to nine months, I have seen some pretty significant decreases.

There's still differences, as we have mentioned before, in different regions of the country, but the west, particularly the California region, is generally more expensive than the midwest or some other areas that we're building.

But if we were to put together the same kind of example that we put together for investors before, which is generally a midwest-type of example, I think the last time -- midwest type of cash flow earnings example, I think the last time we put it together, the range -- the kW range was somewhere between 1,800kW and 2,000 kW.

If I were to put that together now, the range would probably be 1,600kW to 1,800kW.

So, I mean we are seeing cost decreases, and that's very helpful when you are dealing with a challenging environment because it allows you to protect the earnings that you expect from these investments.

That's great.

Really helpful.

And last, on the drilling program, just if you could give us a little better understanding of the decision process.

So you decided to go forward with the drilling, you hedged, then you decided not to go forward, so then you unwound the hedges.

Can you give us a little understanding into what happened there, and what caused you, after deciding to go forward, not to decide to go forward.

Yes, it -- on a quarterly basis, we go through and we take a look at that business, just like we do many of our other businesses, and in this particular circumstance, we had hedged the wells, or we had hedged the expected production from the wells.

And as we looked at the economics and the declining natural gas environment, we believe that it made more sense for us to take the capital that we had allocated to those wells, and put it to use in other places.

And so that meant that we were able to flatten out the hedges, and when we flattened out the hedges, at least internally, we take all of our documentation pretty seriously.

These are non-qualifying hedges, which may not mean a whole heck of a lot to you, but it is sort of like internal hedge accounting, and our documentation, once we flattened out the hedges for these particular hedges, required us to take the gain in this case.

It would have required us to take the loss if it was a loss.

But it was a gain, and we made the right economic decision, and we moved on.

This was a small -- it was $0.04 or so for the quarter, but it was a small subset of wells that we were dealing with.

It is a business that we continue to be very happy to be in, and with the hedges that we have in place, we feel pretty good about the remaining investment.

That's not to say that in the future we may not change our mind on some of those.

But it is a business that we have gotten a heck of a lot of knowledge from, as well as some pretty good returns on.

Got you.

But we should generally anticipate that when you decide to go forward, although you're going to review it, it is a decision that you're going to go forward with.

So we should -- I don't want to say $0.04 non-recurring, but we should not expect you are going to have these hedge gains on a regular basis?

That is correct.

Great.

Thank you very much.

That concludes today's question-and-answer session.

Now for closing remarks, I'd like to turn the conference back over to Ms.

Rebecca Kujawa.

Thank you, everyone, for joining us today, and we look forward to talking with you again soon.

That concludes today's conference.

Thank you for your participation.