新世紀能源 (NEE) 2014 Q3 法說會逐字稿

Good day, everyone, and welcome to the NextEra Energy and NextEra Energy Partners Conference Call.

Today's conference is being recorded.

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

Thank you, Hannah.

Good morning, everyone, and welcome to the Third-Quarter 2014 Combined Conference Call for NextEra Energy and for NextEra Energy Partners.

With me this morning are Jim Robo, Chairman and Chief Executive Officer of NextEra Energy; Moray Dewhurst, Vice Chairman and Chief Financial Officer of NextEra Energy; Armando Pimentel, President and Chief Executive Officer of NextEra Energy Resources; all of whom are also officers of NextEra Energy Partners, as well Eric Silagy, President and Chief Executive Officer of Florida Power and Light Company.

Moray will provide an overview and our executive team will then be available to answer your questions.

We will be making forward-looking statements during this call based on expectations and assumptions which are subject to risks and uncertainties.

Actual results could differ materially from our forward-looking statements if any of our key assumptions are correct or because of other factors discussed in today's release in the comments made during this conference call, in the risk factors section of the accompanying presentation, or in our latest reports and filings with Securities and Exchange Commission, each of which can be found on our website, www.nexteraenergy.com and www.nexteraenergypartners.com.

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

Today's presentation also references to non-GAAP financial measures.

You should refer to information contained in the slides accompanying today's presentation for definitional information and reconciliations of the non-GAAP measure the closest GAAP financial measure.

With that, I will turn the call over to Moray.

Thank you, Amanda.

Good morning, everyone.

NextEra Energy had a very good third quarter with strong performance at both FPL Energy Resources.

Our Florida Power & Light earnings per Share increased approximately 6% over the prior year comparable quarter, driven roughly equally by our continued commitment of new capital to the business and by growth in wholesale power sales.

Operationally, our performance was strong, despite a challenging periods of summer weather, as our investments in our transmission and distribution network are helping us deliver improvements in our system reliability.

We continue to make good progress on the third of three generation modernization projects at Port Everglades, which remains on track to achieve commercial operation in mid 2016.

Our gas reserves petition advanced through the regulatory process and we expect the Public Service Commission to consider the matter in early December, which we expect will permit a decision either late this year or early next year.

Also during the quarter, the Florida Supreme Court unanimously affirmed the Commission's decision to approve our 2012 rate case settlement.

The Court's order comprehensively rejected all the arguments raised by the Office of Public Counsel and made it very clear that, as long as the PSC follows appropriate procedures, as it did in 2012, it has wide latitude to determine whether a settlement agreement is in the public interest, taking account of all the prevailing facts and circumstances.

We believe this is a very positive development that will encourage and support efforts to negotiate future settlement agreements that, like the 2012 agreement, have new and innovative elements in them.

Energy Resources had an outstanding quarter.

Adjusted earnings per share increased roughly 16% over the prior-year comparable quarter, primarily as a result of additional investments in our contracted renewables business.

The business enjoyed great success in terms of new renewables origination activity, signing contracts for a total of approximately 445 megawatts of new wind and solar projects.

Beyond this, we see strong prospects assigning another 600 megawatts to 800 megawatts by the end of the year.

It was an excellent quarter for new origination activity, with very strong near-term prospects.

At NextEra Energy Partners, operational performance during the quarter was solid and cash available for distribution was line with our expectations.

Yesterday, the NEP Board declared an initial quarterly distribution of $0.1875 per common unit or $0.75 per common unit on an annualized basis.

Just as important, we have made excellent progress around key decisions that will affect the future growth prospects for NEP.

The Conflicts Committee of the NEP Board, composed of independent directors, reached agreement with a sponsor to acquire two additional assets from the Energy Resources portfolio.

More generally, we completed the first phase of our ongoing analysis of future growth and concluded that it is in the interest of both the shareholders of NEE and the LP unitholders of NEP to undertake a short-term acceleration of the NEP growth profile, while still preserving the expectation of continued long-term growth in the 12% to 15% a year range for many years to come.

I will provide more details on each of these later in the call.

Overall, we're very pleased with our progress this quarter.

Now let's look at the results for FPL.

For the third quarter of 2014, FPL reported net income of $462 million or $1.05 per share, up $0.06 per share year over year.

Continued investment in the business and an expansion of wholesale operations were the two principal drivers of growth.

FPL's capital expenditures were approximately $670 million in the quarter and we expect our full-year capital investments to be roughly $3.1 billion.

Regulatory capital employed grew 5.2% over the same quarter last year.

Our principal current generation initiatives at Port Everglades Energy Center, which will deliver fuel efficiency savings and emissions reductions to our customers when it enters service in 2016.

This approximately $1 billion project remains on schedule and on budget.

We are also focused on investing in our transmission and distribution networks to improve his resilience during severe weather, such as hurricanes, as well as to provide increased reliability to our customers on a daily basis.

As I mentioned, earlier this year presented one of the more challenging periods of summer weather and what we are seeing in terms of our ability to improve our already outstanding reliability is encouraging.

Comparing against years that have had similarly challenging weather, we estimate that the reliability of our network, measured in terms of system unavailability, has improved by 10% to 15%.

This means fewer minutes of interruption for our customers and lower outage repair costs for the Company.

Our reported ROE for regulatory purposes for the 12 months ended September 2014 will be approximately 11.4%.

As you may recall from prior quarters, this includes the impact of transition costs associated with our enterprise-wide productivity initiative, Project Momentum, incurred late last year.

The impact of the 2013 transition costs will roll off our reported regulatory ROE as we move through the year, since the regulatory ROE is measured on a 12-month trailing basis.

Absent these costs, regulatory ROE would've been 11.5% and this remains our target for the full year 2014.

As a reminder, under the current rate agreement, we record reserve amortization entries to achieve a predetermined regulatory ROE for each 12-month trailing period; in this case, the 11.5% that I previously mentioned, excluding special charges such as the Project Momentum transition costs.

During the third quarter, we reversed all $131 million of reserve amortization that we had taken this year through June.

The need for reserve amortization is generally the lowest in the third quarter since the third quarter is typically our strongest in terms of revenue.

Our non-fuel O&M expenses in the third quarter of this year were actually lower than the in third quarter of 2013, reflecting the excellent results of our productivity improvement initiative, Project Momentum.

Relative to our expectations at the time we first discussed Project Momentum in the spring of 2013, we are seeing earlier delivery of results and likely greater overall savings.

Incidentally, our ability to shift focus to a comprehensive multi-year effort like this is just one example of the benefits that will flow to customers over time for the settlement agreement, like our 2012 rate agreement.

During the fourth quarter, we expect to further reduce the amount of reserve amortization by reversing some of the amortization that was taken in 2013, the first year of the settlement agreement.

As a reminder, we utilized $155 million of reserve amortization during 2013.

Assuming normal weather and operating conditions, we expect to be able to reverse one third to half of that amount in the fourth quarter.

The economic recovery in Florida remains solid.

The focused effort of the State's leadership on economic development, along with a consistent improvement in the business climate, has helped to drive growth in employment.

The number of jobs in Florida as of September was up 206,000, compared to a year earlier, an increase of 2.7%.

Nearly 700,000 jobs have now been added since the bottom of the downturn in 2009.

Florida's seasonally adjusted unemployment rate in September was 6.1%, down 0.8 percentage points from a year ago.

As an indicator of new construction, new building permits remain at healthy levels, albeit lower than their recent peak.

The Case-Shiller index of South Florida shows home prices up 10% from the prior year and mortgage delinquency rates continue to decline.

Turning now to our customer usage metrics, FPL's average number of customers in the third quarter increased by 82,000 or 1.8%, with an estimated impact on sales of 1.2%.

Similar to prior quarters, the estimated impact on sales is slightly lower than the customer count growth, because the remote connect and disconnect capability, enabled by our smart meter program, continues to account for a portion of that customer growth and these new customers are disproportionately low usage and residential.

We began deploying the remote connect and disconnect switches in the third quarter of 2013 and were fully deployed by the end of the fourth quarter.

Consequently, we expect the growth and customer count year over year to revert in coming quarters to an underlying rate of about 1.3% to 1.5% or 60,000 to 70,000 customer additions annually.

Overall usage per customer grew by 1.9%, of which weather accounted for roughly 0.8%.

Weather-normalized usage per customer increased 1.1%, compared to the same quarter last year.

This was a very strong rebound from the year-over-year decline in the second quarter, but as we have often said, this measure can be volatile on a quarterly basis.

Through the period of the rate agreement, our expectations of underlying usage growth are unchanged at approximately 0.5% per year.

The average number of inactive accounts in September declined 20.8% from the prior year and the percent of inactive accounts is now at a level well below the 20-year average.

As of September, the 12-month average of low usage customers fell to 8%, down from 8.3% in September of 2013.

Before leaving FPL, let me update you on the two capital initiatives that we discussed in the spring of last year that have been pushed back a bit.

First, we are continuing to monitor the actual emissions profile of our (technical difficulty) unit in Broward County.

Based on the results of this testing, we will determine what the most cost-effective upgrade path will be for our customers.

We continue to expect the need to modernize and upgrade these assets, but the exact size and scope of the project remains uncertain.

Construction is not likely to start before 2016.

Second, since completing our first 110 megawatts of solar in Florida, we've been working hard to identify ways in which we can cost-effectively introduce more solar capacity into our system.

Distributed solar, especially residential, remains extremely high cost relative to our efficient generation fleet and will only serve to drive up customer rates if pursued in any quantity.

Even utility scale solar, which is by far the most cost efficient way of adding renewable energy in our service territory, is not yet at a stage to be generally cost effective across our entire service territory.

However, we have continued to work to identify specific opportunities and now believe we can bring forward three roughly 75-megawatt solar PB projects that can take advantage of the 2016 ITC window, leverage available land, transmission capacity, as well as prior permitting and development work and that will prove cost effective for our customers.

We expect to bring these projects into service in 2016.

Moreover, we continue to believe that, with reasonably foreseeable continued improvements in solar economics, there could be greater potential for utility scale solar by the end of the decade.

Let me now turn to Energy Resources, which reported third-quarter 2014 GAAP earnings of $204 million or $0.46 per share.

Adjusted earnings for the third quarter were $231 million or $0.52 per share.

Before reviewing the details, let me provide a reminder about the interrelationship between Energy Resources and NEP.

As you know, the launch of NEP closed on July 1. Energy Resources will continue to consolidate NEP for accounting purposes, but beginning with this quarter, you will see a deduction for income representing NEP LP unitholders interest in NEP's results.

Energy Resources adjusted EPS increased by $0.07 per share year over year.

The contribution from new wind and solar additions placed into service during or after the third quarter of 2013 was $0.09 per share and this continued growth in our contracted renewables business was the primary driver of Energy Resources growth.

Our customer supply and trading business had a modest positive increase in contribution of $0.03 per share, driven mostly by favorable summer results in retail and wholesale full requirements.

A mild summer is typically favorable for these parts of the portfolio.

Wind resource came in at roughly 95% of the long-term average, which was roughly comparable to last year and the existing asset portfolio added $0.01 per share overall.

Offsetting these gains was a $0.03 per share decline in contribution from our gas infrastructure business, due to increased depreciation expense, primarily related to higher depletion rates, while other factors reduced results by $0.03 per share.

For the full year, we continue to expect to elect CITCs on roughly 265 megawatts for our Mountain View solar project and the portions of Genesis and Desert Sunlight solar projects that are expected to enter service in 2014.

This equates to roughly $60 million in adjusted earnings, down from roughly $70 million in 2013 on 280 megawatts of solar projects.

As I mentioned earlier, the team has driven significant growth in our portfolio of contracted renewables opportunities.

Let me spend a bit of time now on where each program stands.

Our total 2013 to 2016 US solar program is now roughly 1,400 megawatts.

This includes roughly 304 megawatts newly added to the backlog since the last call and is approximately 300 megawatts better than the high end of our expectations at the time of the March 2013 Investor Conference.

All of these new projects are expected to be in operation by the end of 2016.

There are also a number of other projects that we continue to pursue and we now believe that our total 2013 to 2016 US solar program could be 1,600 megawatts to 1,800 megawatts.

Turning to our wind programs, our US development program for 2013 to 2015 is now nearly 1,900 megawatts, this includes 91 megawatts newly added to the backlog since the last call.

Based on everything we see at the moment, we now believe our total 2013 to 2015 US wind program could exceed our previously stated range of up to 2,500 megawatts.

In Canada, we added a new approximately 50 megawatt project to the backlog, which we expect will enter operations in 2016.

Since the last call, we brought into service roughly 75 megawatts of solar, 199 megawatts of US wind and 133 megawatts of Canadian wind, a total of over 400 megawatts.

Not only are these very attractive assets in their own right, but we also believe we have unlocked the potential to better highlight their value by isolating a portion of the portfolio and making the cash flows visible to investors through the creation of NEP.

Let me now review the highlights for NEP.

During the third quarter, NEP's initial portfolio delivered cash available for distribution, or CAFD, of $27 million, which was in line with our expectations.

Full financial results will be available when we file the 10-Q.

The assets operated well and wind and solar resource were near normal.

Overall, there's nothing at this time that causes us to change the expectations that we have previously shared for these assets for the 12-month period ending June 30, 2015.

As I mentioned earlier, NEP has entered into agreements to expand its portfolio through two project acquisitions from NextEra Energy.

The first of these is Palo Duro, an approximately 250 megawatt wind project in Texas that will sell 100% of its output under a 20-year PPA.

It is expected to enter service in the fourth quarter of 2014.

Palo Duro is not part of the ROFO portfolio.

We expect to earn PTCs on the project and to enter into a differential partnership or tax equity structure that we expect will make the project very attractive to NEP investors.

In essence, we expect our tax equity partners to make a portion of their contributions to the project through ongoing payments in exchange for receiving PTCs.

We expect this to result in an overall project cash flow profile that fits the NEP model.

The second acquisition is Shafter, a 20-megawatt solar project in California that will sell 100% of its output under a 20-year PPA.

Its expected to enter service in the second quarter of 2015 and is a part of the ROFO portfolio.

NEP expects to acquire both projects in the first quarter of 2015 for total consideration of approximately $291 million, plus the assumption of approximately $250 million in tax equity financing, which is expected to close in December for Palo Duro and subject to working capital adjustments.

The $150 million of primary proceeds retained from the IPO will support a portion of the acquisition.

The remaining consideration of roughly $141 million will be financed in the short-term through the utilization of NEP's revolving credit facility, in addition to cash on hand at the time of the transactions.

Since the revolver is not expected to be utilized for longer-term capital requirements, we expect to replace this interim financing with equity and potentially, incremental project debt at some point in 2015.

NEP expects the impact of these acquisitions to increase 2015 adjusted EBITDA and CAFD by roughly $60 million to $70 million and $15 million to $25 million, respectively, and to increase the annual run rate of adjusted EBITDA and CAFD by roughly $65 million to $75 million and $20 million to $30 million, respectively.

We expect additional acquisition opportunities to become available as well, and I will talk more in a moment about our current thoughts on overall expected growth.

Turning now to the consolidated results for NextEra Energy.

For the third quarter of 2014, GAAP net income attributable to NextEra Energy was $660 million or $1.50 per share.

NextEra Energy's 2014 third-quarter adjusted earnings and adjusted EPS were $688 million and $1.55, respectively.

Adjusted earnings from the corporate and other segment decreased $0.01 per share compared to the third quarter of 2013.

The development of both Sabal Trail Transmission pipeline and Florida Southeast Connection pipeline continue to progress well through their respective processes.

Florida Southeast Connection filed its FERC certificate application in September 2014, and Sabal Trail continues to refine the route with the expectation to file its FERC certificate application in November 2014.

Both projects expect FERC authorization by year end 2015 to support commercial operation by mid 2017.

During the quarter, we completed the formation of our Mountain Valley pipeline joint venture with EQT Corporation.

In addition, the joint venture completed a binding open season for the roughly 300 mile natural gas pipeline designed to connect the Marcellus and Utica shales with markets in the Southeast region of the US, in order to support growing demand and improvements in reliability.

After concluding the open season, the project has secured approximately 2 Bcf per day of 20-year firm capacity commitments.

Based on our expected ownership share, the expected size of our capital opportunity is approximately $1 billion to $1.4 billion.

Both companies have received Board approval to move ahead with the project.

Looking ahead, at NextEra Energy, we continue to expect full year EPS to be in the range of $5.15 to $5.35 and this range includes the negative impact of about $0.15 associated with the launch of NEP that we discussed in the second-quarter earnings release.

Having completed a closer review of the 2015 outlook, we now see a range of $5.40 to $5.70 as being reasonable.

We expect to see a few cents of drag associated with the combination of the accelerated transfer of assets to NEP, which I will discuss further in a moment, as well as higher capital spending associated with a more rapid evolution of the energy resources backlog.

The accelerated transfers would give us more equity than we need to maintain our target credit metric, other things being equal, and we can utilize this extra equity to support the additional Cap Ex without recall to the equity market.

These effects are reflected in the $5.40 to $5.70 range.

In the slides accompanying today's presentation, we have also provided new disclosure for expectations for the energy resources portfolio, focusing on our expectations for adjusted EBITDA and cash flow for 2015.

Please note that this view of 2015 does not yet reflect the impact of the anticipated accelerated growth at NEP.

For 2016, we are maintaining our current expectations of $5.50 to $6, for the moment, and we expect to be able to provide an update with the fourth quarter earnings release in January.

As always, our expectations are subject to the usual caveats, including but not limited to, normal weather and operating conditions.

Starting in 2016, we expect to see, reflected in GAAP income, the effects of asset transfers to NEP.

Because of the subordination provisions governing NEEs LP unit, gains on these transfers are currently deferred until one year after NEP pays distributions at a level $1.13 corresponding to the high splits in the IDR structure.

At that point, we expect to start amortizing any gains from sales of assets to NEP over the life of the assets.

Looking beyond 2016, while we are not yet in a position to provide a specific numerical range for earnings, it is clear from the development of our capital deployment initiatives, that we are well-positioned to sustain our strong growth profile.

We expect to be able to sustain the 5% to 7% per year growth in EPS of a 2014 base, at least through 2018, assuming all our capital initiatives continue along their current path.

In addition, everything we see suggests that our operating cash flow will continue to grow more rapidly than EPS during this period and we expect average growth of operating cash flow in the 8% to 10% per year range through 2018.

With the proposed acceleration in the growth of NEP, which I will detail in a moment, we should also see the IDR cash flow stream at NEE grow rapidly, so that by 2018, this could amount to somewhere between $75 million and $100 million per year.

This is included in our overall expectations of cash flow growth.

Turning now to NEP, we expect the initial portfolio to deliver roughly $270 million to $280 million of adjusted EBITDA in the first 12 months, yielding cash available for distribution or CAFD of nearly $85 million to $95 million.

For the full year 2015, taking into account all the asset acquisitions we are now contemplating, we expect the NEP portfolio to generate adjusted EBITDA of $400 million to $440 million and CAFD of $100 million to $120 million.

This would support a distribution level at an annualized rate of $1.125, which corresponds to the upper tier of the IDR splits, at the end of 2015 or possibly slightly earlier.

Again, the disclosure in the appendix does not yet reflect the impact of this acceleration of growth at NEP since we have not yet determined the specific projects that will be made available to NEP.

We expect to update our disclosure when a more specific plan is in place.

After 2015, we currently see 12% to 15% per year growth in LP distributions as being a reasonable range of expectations for at least the next five years.

Let me now spend a moment explaining our logic for accelerating the short-term growth of NEP and why we think it would be good both for NEP, LP unitholders and for NextEra shareholders.

We have spent the last few weeks examining in more detail different scenarios for NEP acquisitions of energy resources projects.

We've also spent considerable time asking questions of our investors and considering their input.

While we retain accountability for our decisions, we recognize that many investors have been thinking about the same issues and we value the input we have received.

We recognize that, other things equal, if there is value to be created by transferring an asset to NEP, in general, it will be better to do so earlier rather than later, subject to the project being sufficiently far along in development and construction to fit the NEP competitive model.

At the same time, NEP's competitive positioning is strongly supported by the long runway of growth that it can reasonably expect to offer investors, given the large portfolio of energy resources projects that it can hope to acquire.

As we have studied the portfolio more closely and considered how it may evolve, we have come to the conclusion that we can support a short-term acceleration of growth, while still preserving reasonable expectations of growth in the 12% to 15% per year range for several years thereafter.

We think this profile is more attractive to NEP investors than simply continuing the 12% to 15% growth rate and maintaining more assets in the energy resources portfolio for a longer period of time.

Two factors in particular have changed since we launched NEP.

First, as we've discussed, we've been working on a tax equity structure that we now think will enable us to make some projects available to NEP earlier than we had previously expected, and, of course, the Palo Duro project discussed earlier is an example of this.

Second, again as discussed earlier, the development pipeline and backlog at Energy Resources have continued to evolve a very positive fashion over the last few months and nothing has changed our view that the longer-term prospects for renewables development in the US, particularly with the prospect of EPA regulation of carbon dioxide emissions, are very favorable.

These factors, in our judgment, support an acceleration of NEP growth.

From an NEP LP unitholders perspective, there are two other secondary factors that also support this proposed shift.

First, investors have noted that NEP currently offers limited liquidity, simply because of its size, and accelerating the growth in the short-term should improve liquidity.

Second, although the initial portfolio is broad and diverse, accelerating the growth will enable the portfolio to become broader and more diversified, which again, should be a positive for NEP investors.

Finally, from a NextEra Energy shareholder perspective, accelerating the growth of NEP will also mean that the upper tier of the IDR splits will be reached more rapidly than we had originally thought.

While this doesn't change the fundamental value proposition, we think it will serve to highlight a portion of the NEE value proposition, which perhaps today is not widely recognized among NEE investors.

We estimate that the IDR cash flow stream could be worth $5 to $10 per share later in the decade.

For all these reasons, we have concluded that accelerating the growth of NEP over the next 12 months or so, while still retaining reasonable expectations of sustained growth in the 12% to 15% per year range for several years thereafter, makes sense for both sets of investors.

At this point, we are not prepared to discuss the specific assets that NEP expects to acquire, as we are still working through the details.

However, this accelerated growth profile is still likely to be dominated by the same kinds of high-quality long-term contracted renewables projects that characterize the initial portfolio.

Longer-term, it may well make sense to broaden the NEP portfolio into new asset classes but, for the short-term, we believe continuing to focused primarily on renewables projects makes sense.

To sum up, both NEE and NEP had excellent quarters.

Current performance is strong.

The outlook, at least through 2016, is highly visible and we continue to believe that we have some the best long-term growth prospects in our industry.

All of this is supported by a very strong financial position, which we expect to maintain.

Our fundamentals are excellent and our growth initiatives continue to evolve in a very positive fashion.

With that, we will now open the line for questions.

Since this is a combined conference call for NextEra Energy and NextEra Energy Partners, it will be helpful if you could be clear which entity you're referring to in your questions.

Thank you.

(Operator Instructions)

We'll take our first question from Stephen Byrd from Morgan Stanley.

Moray, I wanted to explore the PTC structure that you outlined that could permit perhaps more assets to be dropped down to NEP earlier than we had expected.

Can you generally speak to the -- you mentioned some of the assets could be eligible.

Is this something we should be thinking of as fairly broadly eligible for your assets with PTCs, or is it a more limited field of assets?

Just trying to sort of generally get a feel for how significant this structure is.

Sure.

The first point to be made is it applies to new projects going forward.

So anything that's already in the portfolio either has a structure against it or probably is fairly far along in its 10-year window of eligibility and it wouldn't make sense for us to go back to some of those.

But potentially for all PTC projects going forward, subject to available market capacity, this could be applicable.

Now when I say available market capacity, the tax equity market is a relatively specialized part of the overall capital access possibilities that we have available to us and the capacity of that can vary from year-to-year.

So depending upon just how much capacity there is would determine really how much we could do in any particular year.

But I think it could be quite broadly applicable going forward.

That's helpful.

Just looking at the wind business, obviously you've had some great progress in terms of additional contracts and it looks like the outlook is positive for additional contracts.

Could you speak broadly to which parts within the US, which regions look most attractive in terms of growth?

Is it more the upper Midwest, more Texas, or which parts of the country are you and your colleagues seeing the most opportunities in?

Sure.

I'm going to ask Armando to offer a little more color, but broadly speaking, our development efforts have been and will continue to be concentrated on the best wind resource areas, because that drives the best economics.

That tends to be all up and down the middle part of the country, but Armando can speak more specifically to some of the areas we're focus on.

Sure.

I think its, number one, its the middle part of the country.

I call it the Midwest, but I'm not a geography teacher.

When I talk about the Midwest, it's a very broad section starting up in the Dakotas, going all the way down to the Texas region, including a little bit of Colorado.

But I would include the Northeast in that, so it's a wide area.

We've developed very well in that area in the past and we continue to do well.

I think what you'll see as some of the newer projects come forward that we do have now some projects actually out in California, some wind projects that are starting to make sense.

We continue to look at the Canadian development for new projects and just this past quarter, were able to sign another 50-megawatt PPA.

Stephen, just to add on, we have traditionally not focused a great deal of effort on the Northeast and the East Coast and that continues to be the case.

The development challenges are greater, our projects tend to be smaller, and the wind resource tends to be weaker.

So the overall economics get much more challenging, so we tend to go where the economics are most favorable.

Great thank you very much.

We'll take our next question from Dan Eggers with Credit Suisse.

It was a very good job with the pipeline additions on the renewable side at NEER.

Can you maybe talk a little more, A, on the wind side, if you're going to qualify for the PTCs or if you need an extension on PTCs to hit the upper end of the new guidance range?

On the solar additions, what markets you're seeing better opportunity or you've been able to add more significant backlog?

Sure again I'll ask Armando to comment.

Good morning, Dan.

Everything that we announced today on the wind side, including the potential to go over the high end of the range, would be built in 2015 or by the end of 2015.

We feel very comfortable that they would all qualify for the production tax credits.

Interestingly enough, I'd say over the last two to three months, we've started to get into discussions with some customers that are looking for to 2016 wind.

Now obviously, those contracts, if we sign them with those customers, would be PTC-contingent.

But everything we've talked about today would be built by the end of 2015 and would qualify for the PTC.

In terms of solar, I'd say it's just about everywhere.

We're seeing good activity all away from the South.

From the South, I would mean anywhere from Texas all the way really to the Southeast United States.

But we're also seeing interest, really because of the improvement in economics, the reduction in the panel prices and reduction in the balance of plant, we're seeing interest all the way up to the Canadian border, which is a positive.

The contracts we announced today, we announced, I think, roughly, 304 megawatts of new projects.

Those projects span from California all the way to the Southeast United States.

Okay, very good.

Moray, on the 375 megawatts projects at the utility, can you remind us how those will go into rates or how you will get recovery on those in the midst of the four-year deal you have in place?

We would not be looking for any adjustment the rate agreement, so we will live with the base rates that we have in place.

Okay, very good.

Thank you.

Next, we'll take a question from Stephen Fleishman with Wolfe Research.

Just first question and not sure if you can answer this now, but you mentioned the 5% to 7% long-term earnings growth, but 8% to 10% long-term cash flow growth.

Could you maybe give us some sense, or if Jim's there, when you're thinking about dividend policy?

Are you going to focus more on earnings growth or cash flow growth?

If you recall the logic that got us to the current target 55% payout ratio, it was fundamentally based on a shifting portfolio mix.

So, with the portfolio shifting to a higher concentration of regulated and long-term contracted assets, we felt that supported and justified a slightly higher payout ratio then we had in the past.

If you carry that logic forward, while the same trend continues from 2014 on, it's really at a slower pace.

So at this point, I don't see a particular logic for recommending a change in that payout ratio, with one possible exception, which I'll come back to in a minute.

But assuming we go on, that obviously means dividend growth roughly in line with EPS growth.

The exception that I have noted on a couple of occasions is, should we, at some point in the future, get to a position where our capital deployment opportunity set starts to slow down, then the rapid growth in the cash flows would quickly move us into a free cash flow positive position.

If we saw that being a sustained phenomenon for multiple years, then in that circumstance, I think we would be inclined to recommend an increase in the payout ratio.

So I think those are the two broad policy things to keep in mind.

Obviously, we are always sensitive to the overall dividend position and how it compares with other companies that we're competing for capital against.

So we'll always be taking that into account.

But from a policy perspective, those are the two points I would make.

Okay.

Maybe this is for Jim, just historically, while you've talked about the 5% to 7% growth, I think Jim's said several times he'd disappointed if you didn't hit the upper end of that.

Is that still the view, and just with all these kind of different moving parts, it seems like you're executing really well on the growth investment.

Is that going to show up into what you've said on getting to the higher-end?

Steve, I will continue to say that I'll be disappointed if we don't, in 2016, earn at the top end of the range at $6.

We'll be giving an update on that 2016 guidance in January, as Moray said earlier on the call.

Okay.

One last quick thing, on the Florida solar, and you might've answered this, but how would those projects work?

Would you just do them and still the utility under just the current rates, or would you look for like the solar clause or something of that sort?

That would be recovered within the current base rates.

Obviously, we've got to make sure that they are the most cost-effective solution for our customers.

We're pretty close on that and we think that we can demonstrate that's the case because in these kind of specific projects where we've already done a lot of work and they happened to be in particular locations that work from a transmission perspective.

If we can do that, we would expect to go ahead and construct them and demonstrate that net-net they're a good deal for our customers for a total build perspective, in which case, they should roll into base rates going forward.

Okay great, thank you.

We'll take our next question from Julien Dumoulin-Smith with UBS.

Just following up on the latest NEP/GP guidance, the $200 million that was depicted for the end of the decade, is that consistent with the 12% to 15%?

To the extent to which it is, can you give us a sense for dropdown assumptions, et cetera, that would be baked in?

Julien, I'm not quite sure I follow the question.

Today, we talked about $75 million to $100 million around the 2018 time.

If you carry the growth forward, a couple more years, yes, I think you can reasonably see getting to the $200 million a year level.

I believe that was the number that I mentioned in a speech I gave at [Platte's] the other day.

So its really just about an extension of the growth profile.

As I said in the prepared remarks, we are, right now, really working through what are the specific assets that it makes most sense to make available to NEP for the short-term acceleration.

But the longer-term growth profile and expectations continue to be supported by all the projects in the Energy Resources portfolio that we talked about in the past, including potentially contracted fossil assets and including potentially pipeline projects.

Or to be more specific, what about the dropdown multiples that you're thinking about broadly?

Is it still kind of in that 9 to 11 range?

As a broad generalization, yes, although one of the things that I've observed as we've gone through these first transactions is that EBITDA multiples are not necessarily a very good metric for thinking about dropdown valuation, because the profile of projects can be quite different.

It depends if you have a project where you have CITC, for example, whether it's pre or post the tax effect.

But we haven't really changed our view of the long-term valuation, which as I said on several occasions, is going to depend upon the individual project, first and foremost.

Got you.

Secondly, you've talked about disproportionate cash flow growth.

Obviously, some discussions have laid around large utility acquisitions.

What are you thinking about use of cash flow structurally?

Is that the business orienting towards more resources like businesses or are we talking about more utility growth in the future, be it outside of FPL or within it, et cetera?

As is actually implicit in part of my answer to Steve's question earlier, both sides of the house continue to have very strong growth prospects.

As we go forward, the balance is remaining roughly equal and we still continue to become a little bit more regulated and long-term contracted, but not greatly so over the next few years.

We will continue to pursue the opportunities that we see in the existing portfolio as much as we can.

In terms of third-party acquisitions or corporate large-deal acquisitions, as we've said before we are, in principal, open to the possibility.

We don't need to do a big deal to continue to be very successful.

We're going to be very disciplined if we do look at anything, but it's not fundamental to our strategy.

Got you.

A quick clarification of Dan's last question, the solar PV side, while you might not be filing for it in the immediate sense, once you're through the current stay out, those would indeed roll into base rates?

Sure.

Assuming that they, indeed, act to reduce total customer bills over the long-term, then they would roll into rate base and they'd be reflected in our filings in 2016 assuming we file as we expect to in 2016 and for whatever new rates would go into effect in 2017.

Great, excellent.

Thank you

We'll take our next question from Shahriar Pourreza, Citigroup.

Just on the solar in Florida, when you mentioned it's the most cost-effective solution for the ratepayers, are you referring to the projects being at retail rate parity, or are we talking more and LCOE reaching like a natural gas high heat rate peaking asset?

Can you just maybe comment on what you mean by cost-effective?

Sure.

The way to think about cost-effectiveness for these projects is to think of them in the context of a constantly evolving integrated resource plan.

So solar in Florida, obviously, has energy value.

It also has capacity value based on its coincidence or degree of coincidence with the load curve.

So essentially, what we do is, in the IRP, we plug in different combinations of potential future generation and figure out, on a present value basis, which of those are cheaper for our customers.

So if we can get to the stage where, as we think we now can, with these three specific projects, we can introduce them into the mix and have the overall present value, as seen through the customers' eyes, lower.

That's a good thing for our customers and something that we want to go ahead with.

Got you.

With the latest solar projects you've added to your pipeline and then maybe comments that solar could become very economical at the end of the decade, can you just maybe talk about the current LCOE trend versus a higher heat rate peaking asset, with and without the investment tax credit?

I can try, but it's very hard to think about LCOE because you really need to think, as I just described for the FPL situation, in how these assets work into an integrated system.

So you're really not or you shouldn't compare assets side-by-side.

That would maybe be appropriate if you were thinking about building a new system from scratch, but in all cases, we're talk about introducing new capacity into an existing system.

With that as a caveat, however, I would say that we are getting to the stage where potentially by the end of the decade, assuming that we revert to the 10% ITC that's an embedded part of the tax code, that in many regions the southern part of the country we could see something that is competitive on an energy basis with a combined cycle unit.

Whether or not that makes it fully competitive on an integrated basis then depends upon capacity value and shape of the load curve, a whole variety of other things in the region that we're talking about.

Got you.

That's very helpful, actually.

Lastly, on the rate basing of the E&P reserves, is there any potential in how large this could be relative to what FPL's gas needs are?

I think for the next few years, we're going to be limited more by the pragmatic factors than theoretical long-term potential.

In theory, if we could get to 30%, 40%, 50% of the gas burn, I think that would be a very attractive proposition from a customer perspective, but I think it's going to take us time to get there.

First of all, we've got to get the initial deal approved and up and running and show that works as we anticipate it will and then I think we want to build on that at a moderate pace and demonstrate that the overall strategy is effective.

I think the other factor that could be limiting here is simply the available opportunity set.

FPL is looking for something a little different in gas reserves than where the general market is.

By that I mean FPL was really, obviously, focused on dry gas.

A lot of the plays that are being pursued out there tend towards the wetter or oilier spectrum.

So there may be some limitations, just driven by the availability of set.

All that has, in my mind, says that I think we have realistic odds of scaling the thing up to the point where, within the next few years, we can commit several hundred million dollars of capital each year to it.

Beyond that, it's too far for us to look right now.

Terrific.

Thank you very much.

We'll take our next question from Greg Gordon with ISI Group.

Sorry to beat a dead horse on the regulated utility side, but just following up on the solar question, presumably you're making headroom in undercurrent base rates through the continued improvement in costs under project momentum, such that you would still expect to be able to earn inside the ROE range until you roll these into base rates?

Yes, that's generally true; not just of these assets, but more generally infrastructure CapEx that needs to be recovered in terms of the current base rate agreement.

Our ability to invest, for example, in our reliability initiatives is conditional upon our ability to manage the O&M effectively.

So the fact that we've been very effective there and, as I said in the prepared remarks, ahead of where we expected to be, in a sense creates more headroom to allow us to deploy capital.

Now that capital still needs to be productive from a customer's viewpoint, either improving reliability, or as we just discussed with respect to the solar units, improving the long-term cost-effectiveness of the system.

But assuming it is, then from a investor perspective, we can sort of afford to accommodate it within the terms of the current settlement agreement.

Great.

Two more questions, one on accounting: you mentioned that the accounting treatment for dropdowns would be to amortize those gains starting 12 months after the initial drop and over the life of the -- over what time, again?

I'm sorry.

I don't recall the last piece.

Okay, let me just repeat that.

In the structuring of NEP, because of the presence of IDRs, we have subordinated our LP interest.

Those subordination provisions go away one year after we have sustained the LP distribution corresponding to the high level of the splits.

Until that time, from an accounting perspective, we defer all the accounting gains that are recorded on the transfer of assets from Energy Resources to NEP.

Once we clear that one-year period, then we can start amortizing those gains.

And those gains would be amortized over what period?

Over the life of the assets.

Okay.

And we would expect those to run through NextEra Energy Resources ongoing earnings?

Correct.

Great.

So you get the cash in and the you do the drop, you amortized the gain over, starting the year out over the life of the asset?

Subject to the more technical description that I gave.

Going forward, it would then be the case, but the subsequent projects, you would be getting the cash and starting to realize the gain simultaneously.

Got you, great.

One final question for Armando, we talked a bit last time we saw you about the opportunity for storage as a growth investment in NEER.

California has this RFP going on.

Can you talk about whether or not storage is, in fact, a piece of the growth opportunity at NEER and if so, what's the magnitude and when might we start seeing those investments?

I think it is.

I think I've been pretty consistent in saying that, at least my expectations for storage investments to become a significant part of our CapEx spending at NEER is really towards the later part of the decade.

As you mentioned, there are opportunities in California, opportunities in Hawaii, opportunities in New York and actually there are some smaller opportunities in PJM.

We are looking at and playing in all of those markets, but I would not expect in the near-term, through 2016, even if we're significantly successful, for the Cap Ex to be very meaningful in terms of what it adds to earnings.

Having said that, the team that we have put together, I think, is a good team and I continue to believe that towards the latter part of this decade, we will be able to make some significant investments.

Thank you gentlemen.

We'll take our question from Paul Patterson with Glenrock Associates.

Just to recap a little bit here on the NEP accelerated growth and maintaining the long-term growth outlook as well, is that basically being driven by just a more robust outlook in terms of the opportunities for renewable development?

I just wanted to clarify as to what -- make sure I understand exactly how you're able to accelerate the growth in the near-term and maintain long-term growth.

Is that what's driving it?

Yes, the underpinnings of it, obviously, are our long-term expectations for the evolution of the Energy Resources portfolio because that's the principal source of the projects that create the opportunity set for NextEra Energy Partners.

We're feeling very good about that.

We've had great success this quarter in the relatively short-term and the long-term fundamentals for us to be very encouraging, so that's kind of a fundamental driver.

Then assuming that you can get comfortable with the long-term growth expectation for the opportunity set, then the next question is what's the right sort of shape for the growth profile?

Clearly, we recognize that, other things equal, meaning, as long as you can sustain a long period of good growth, by good I mean 12% to 15%, then it's better to have more earlier rather than later.

Then if you couple that with the recognition that, with this tax equity structure, we may have some assets that previously, we would have thought about as not being available for 10 years, now been eligible earlier.

It makes sense to get those transferred when we can, so there's more opportunity, particularly in the short term and hence an acceleration in the short-term appears to us to make a lot of sense.

Okay, I just wanted to make sure I understood that.

With respect to slide 20 and the new investment, now I realize things have changed, you have changed things a little bit here; you provide a lot more information.

But it does look like the new investment line has dropped a bit.

Obviously, we have NEP on the top part there.

Could you elaborate a little more about what's changed in new investment other than the allocation to NEP in that slide?

It's going to be difficult for me to do that on the call.

A couple caveats, that slide 20 does have some differences from the prior, what I call the gross margin hedged chart.

So it's very difficult to compare those directly.

Among other things, we have, in the new disclosure, we have allocated into the adjusted EBITDA across the various lines, the base G&A that we have supporting the respective elements of the business that we didn't have before.

So all those will tend to be a little bit lower.

One of the things that is on our list to do is now to go back and compare these pieces and understand precisely why some of the line items might look a little bit different.

I would say there's no major change to the 2015 numbers.

Most of the developments that we've seen in the last quarter will tend to affect 2016 and 2017 much more.

Okay, great.

Finally, weather versus normal, I'm sorry if I missed this, what has it been year-to-date, the impact of weather versus normal?

On Energy Resources, year-to-date on the wind side is a little above average, the quarter was a little bit below average.

Solar has been about on.

And the utility?

It's been about an average year overall.

The challenges we've had here in Florida have been associated much more with heavy rainfall and thunderstorms and lightning, but in terms of average cooling degree days, it's not been greatly different.

Now recognize, of course, that all of that gets absorbed by pluses or minuses and simple depreciation and amortization at FPL, so it doesn't have a direct immediate ROE impact.

Right, okay.

Thanks so much.

Okay.

Thank you very much.

This concludes today's conference.

Thank you for your participation.