新世紀能源 (NEE) 2014 Q4 法說會逐字稿

Good day, everyone, and welcome to the earnings conference call for NextEra Energy and NextEra Energy Partners.

Today's conference is being recorded.

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

Please go ahead, ma'am.

(technical difficulty) -- and 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 as Eric Silagy, President and Chief Executive Officer of Florida Power & Light Company.

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

We will be making forward-looking statements during this call based on current 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 incorrect or because of other factors discussed in today's earnings news release and the comments made during this conference call in the Risk Factors section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our websites, nexteraenergy.com and nexteraenergypartners.com.

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

Today's presentation also includes references to adjusted earnings and adjusted EBITDA, which are non-GAAP financial measures.

You should refer to the information contained in the slides accompanying today's 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 to Moray.

Thank you, Amanda, and good morning, everyone.

NextEra Energy delivered strong performance in the fourth quarter, capping off an outstanding year overall.

Fourth-quarter adjusted earnings per share grew 8.4%, while full-year adjusted earnings-per-share growth was 6.6%, even including a negative impact of $0.15 per share associated with the launch of NEP.

Just as important, we made excellent progress on our major capital initiatives, and Energy Resources had one of its best years ever in terms of new project origination, signing contracts for roughly 1400 MW of new renewables projects, as well as partnering with EQT to begin development of the Mountain Valley Pipeline.

As a result, we are very well-positioned for future growth and can reasonably expect to be able to extend our long-term track record of growing adjusted earnings in the 5% to 7% range at least through 2018.

Cash flow from operations grew 7.8%, leading to a slight improvement in our cash flow coverage metrics as expected, and we maintained our strong credit position, which remains an important competitive advantage in a capital intensive industry.

In addition to all these developments, 2014 saw the very successful launch of NEP, the initial assets of which delivered operating and financial performance in line with expectations.

The favorable development of Energy Resources' contracted renewable portfolio, coupled with other factors, led us to conclude that it makes sense to accelerate the growth of the NEP portfolio in 2015, and we now expect to reach the so-called high splits, which implies LP unit distributions at an annualized rate of $1.13 by the end of this year.

Late in December, the growth potential of Energy Resources and by extension NEP was further supported by the federal government's action to extend the Wind PTC program another year, which we expect will mean that we will be able to offer our customers very attractive pricing on wind projects with delivery dates through the end of 2016.

Longer term, we continue to believe the growth potential for renewables will be strong, supported by both improving economics and the EPA's Clean Power Plan.

All-in-all, it was an exceptionally strong year with excellent current financial performance balanced with equally positive developments in terms of future growth potential.

We are very pleased with the progress we have made.

Now let's turn to the results for the quarter and the full year.

For the fourth quarter of 2014, FPL reported net income of $286 million or $0.65 per share, up $0.08 per share year over year.

For the full-year 2014, FPL reported net income of $1.5 billion or $3.45 per share, up $0.29 per share versus 2013.

As a reminder, our 2013 results included a negative impact of approximately $0.07 from transition costs associated with Project Momentum, our enterprise-wide productivity initiative.

The principal drivers of growth for continued investment in the business and increased wholesale volumes are associated with two long-term contracts.

FPL's capital expenditures were approximately $832 million in the quarter, bringing our full-year capital investments to a total of roughly $3.1 billion and driving year-over-year growth in regulatory capital employed of 5.8%.

We achieved significant milestones throughout the year, bringing into service the Riviera Beach Clean Energy Center ahead of schedule and slightly below budget; starting construction on our generation modernization project at Port Everglades; and continuing to invest in our transmission and distribution network to help us improve our already outstanding system reliability.

Our regulatory ROE for the 12 months ended December 2014 will be approximately 11.5%, achieving the 2014 target that we shared with you previously.

As a reminder, there is no longer an embedded negative impact to transition costs associated with Project Momentum.

Under the current rate agreement, you will recall that we record reserve amortization entries to achieve a predetermined regulatory ROE, in this case the 11.5% that I previously mentioned.

During the fourth quarter, we reduced our cumulative utilization of reserve amortization since 2013 from $155 million to $122 million, a reversal of $33 million, leaving us a balance of $278 million, which can be utilized in 2015 and 2016.

Relative to the expectations that we discussed on the last call, the smaller reversal reflects the unfavorable impact of mild weather in the fourth quarter on revenues.

However, the $278 million remaining balance is better than we expected when the rate agreement began, primarily as a result of our productivity initiatives which have been very successful.

Total nonfuel-based O&M costs in 2014 were more than $100 million below where we were in 2012.

Looking ahead, we expect the balance of the reserve amortization, coupled with our weather-normalized sales growth forecast of 1.5% to 2% per year and current CapEx and O&M expectations, will allow us to support a regulatory ROE of approximately 11.5% in 2015 and in the upper half of the allowed band of 9.5% to 11.5% through the end of our current rate agreement.

We are continually working hard to find new ways to strengthen the value proposition that we deliver to our customers, and I would like to provide updates on three recent positive developments.

First, in December, the Florida Public Service Commission approved the Woodford project portion of our gas reserves petition, an important long-term hedging opportunity against potential volatility in the market price for natural gas.

We expect the PSC to decide in March on our proposed guidelines for subsequent investments and natural gas supplies.

Second, 2014 was the second year of FPL's current rate agreement and the second year for the gas and power optimization program that we proposed as part of that agreement, which, of course, was PSC approved.

I am pleased to report that under this innovative gain sharing program, FPL delivered roughly $54 million of incremental value to its customers through optimization activities, and once reviewed and approved by the Commission, we will be able to record roughly $13 million of incremental pretax income in 2015 under the gain sharing provisions.

This is an obvious example of a win-win proposition.

Third, we remain optimistic that there is greater potential for additional utility scale solar projects in Florida.

Our recent focus has been on improving the economics of three roughly 74 MW solar PV projects on which we have already done significant development work and which we expect we will be able to enter service in 2016 and qualify for the 30% ITC.

I am pleased to report that yesterday we issued a press release confirming that we believe we can now move forward with these three projects with overall economic benefits to our customers.

The total capital investment for these three projects is expected to be approximately $400 million to $420 million.

Florida's economy continue to improve in 2014 and again did better than the US average on most major measures.

Florida's seasonally adjusted unemployment rate in December was 5.6%, down 0.7 percentage points from a year earlier and in line with that of the nation.

However, this masks the fact that Florida's labor force participation rate also increased as more people were attracted to a healthier employment market.

Florida added 230,000 jobs over the 12-month period ending December 2014, largely within the private sector.

The corresponding growth rate in jobs of 3% outpaced that of the nation by 0.9 percentage points.

In fact, Florida's rate of job creation outpaced the US in the majority of individual private sectors, reflecting diversified growth.

Florida's population is also growing at a healthy rate.

The US Census Bureau reported recently that Florida's population increased by more than 290,000 people over the 12-month period that ended July 1 of last year, reaching 19.9 million, and moving Florida ahead of New York as America's third-largest state.

In the housing market, the Case-Shiller Index for South Florida shows prices up 9.5% from prior year and building permits that appear to be stabilizing at healthy levels.

The strengthening economy was reflected in improvements in Florida's Consumer Sentiment Index, which by the end of the year had reached its highest level since February 2007.

Fourth-quarter sales volume was down 3.7%, driven by mild weather.

FPL's average number of customers increased by approximately 68,000 or 1.5% compared to the prior year period with a roughly comparable estimated impact to change in sales of 1.4%.

As a reminder, the remote connect and disconnect capability enabled by our smart meters was fully deployed by the fourth quarter of 2013.

Consequently, none of the fourth-quarter 2014 customer growth is attributed to this impact.

Usage per customer declined by 5% compared to the prior year with weather accounting for 5.3% of the decrease, offset by a 0.3% increase in underlying usage growth.

In the fourth quarter, inactive accounts were roughly 15% below the level of the prior year comparable period, and new meter connections continued to show steady improvement by increasing almost 47,000 in 2014, which is over 20% higher than the 2013 additions.

For the full year, customer growth and mix increased by 1.2% compared to 2013.

Year-over-year weather normalized usage per customer increased slightly by 0.1%.

This metric was somewhat volatile in 2014, but our long-term expectation remains at approximately 0.5% per year net of the impact of efficiency and conservation programs through the period of the rate agreement and flat thereafter.

Let me now turn to Energy Resources, which reported fourth-quarter 2014 GAAP earnings of $614 million or $1.39 per share.

Adjusted earnings for the fourth quarter were $178 million or $0.40 per share.

Energy Resources' contribution to adjusted earnings per share in the fourth quarter was flat compared to last year.

Strong positive contributions from new investments, as well as improvements in customer supply and trading, were offset by reductions in gas infrastructure, largely driven by higher depletion rates and by the impact of refueling outages at our Duane Arnold and Point Beach nuclear facilities.

For the full-year 2014, Energy Resources reported GAAP earnings of $985 million or $2.24 per share.

Adjusted earnings were $833 million or $1.89 per share.

As a reminder, adjusted results include the negative impact of $0.15 per share associated with establishing and launching NEP.

This, in turn, includes a $0.10 per share noncash income tax charge, driven by separating our Canadian projects to enable them to fit into the overall NEP structure.

The growth in Energy Resources' contribution to adjusted earnings per share of $0.06 for the full year was driven largely by growth in our contracted renewables portfolio, which added $0.29 per share.

During the year, we installed roughly 1364 MW of new wind and 265 MW of new solar, making 2014 the strongest year ever for new renewable capacity coming into service.

We elected CITCs for roughly 265 MW of solar projects in 2014 compared to approximately 280 MW of projects in 2013.

We expect to elect CITCs on roughly 365 MW of new solar generation in 2015.

Contributions from our existing business were up $0.06 per share year over year.

Wind resource for 2014 was slightly above our long-term expectations, following a slightly lower resource in 2013.

Customer supply and trading overall ended the year up $0.04 per share.

Asset sales added $0.01 per share year over year.

Offsetting these increases was a $0.06 per share decline in gas infrastructure, mainly due to increased depreciation expense, primarily related to higher depletion rates.

Increased interest expense negatively affected the comparison to last year by $0.09 per share due to growth in the business.

Contributions from corporate G&A and other decreased $0.04 per share year over year, primarily driven by share dilution.

As we did last year, we have included a summary in the appendix to the presentation that compares Energy Resources' realized equivalent EBITDA to the ranges we provided in the third quarter of 2013.

In addition, we have updated Energy Resources' projected adjusted EBITDA and cash flow slides and included an additional year forward.

The portfolio of financial information for 2015 and 2016 can be found in the appendix to the presentation.

Please note that the slides now reflect the impact of the anticipated accelerated growth at NEP.

All expectations associated with NEP assume future trading yields roughly comparable to today's levels.

Energy Resources' financial performance in 2014 was stronger than may appear from a simple calculation of adjusted EPS growth, in part because of the impact of the various costs and accounting charges associated with the establishment of NextEra Energy Partners.

Growth in adjusted EBITDA and cash flow were both strong with adjusted EBITDA growing by 12% and operating cash flow by 29%, although the latter number is affected by intercompany tax effects and working capital changes.

The strong growth in Energy Resources' cash flow reflects the impact of new contracted renewable projects coming into service.

As I mentioned earlier, Energy Resources had one of our best ever periods of origination activity for new contracted renewables in 2014.

On the last quarterly call, we discussed a number of strong prospects that the team was pursuing, and I am pleased to report that since that time we have added roughly 500 MW to our backlog of wind and solar projects.

All of these new projects have characteristics that we expect will make them attractive candidates to be made available to NEP over the course of time.

We are now well ahead of the expectations that we shared with you at our March 2013 investor conference with positive implications for earnings and cash flow growth in 2017 and beyond.

Contingent upon IRS guidance, we believe that the extension of the Wind PTC, along with our development activities and efforts to Safe Harbor equipment, should be supported to our US program through 2016.

The accompanying chart shows our current estimate of megawatts that can be delivered in their respective periods.

Over the last two years, we have brought into service approximately 2285 MW of new renewables, and in addition we have signed contracts for another roughly 2115 MW, which we expect to bring into service by the end of 2016.

If our development program goes as expected, we believe Energy Resources and NEP's combined renewables portfolios will reach at least 14,200 MW by the end of 2016 and likely will be significantly higher.

We will provide a more detailed update on our origination and development activities at our March investor conference.

Let me now review the highlights for NEP.

As you know, the launch of NEP came at the end of the second quarter.

Consequently a discussion of full-year results is not meaningful, and we will instead simply focus on the fourth quarter.

As a reminder, NEP consolidates 100% of the assets and operations of NEE Operating LP in which both NextEra Energy and NEP LP unitholders hold an ownership interest.

Accordingly, the financial values for NEP that we discussed in these prepared remarks or in the attached slides are presented on a 100% basis.

At present NextEra Energy owns approximately 80% of the economic interest, and NEP LP unitholders own approximately 20%.

NEP's initial portfolio delivered fourth-quarter adjusted EBITDA and CAFD of $54 million and $32 million respectively.

The assets operated well.

Wind and solar resource were near normal, and financial results were generally aligned with our expectations.

During the quarter, NEP also made its initial distribution payment to unitholders.

Earlier this month NEP completed the acquisition of Palo Duro, the first of two previously announced agreements to expand its portfolio through project acquisitions from NextEra Energy Resources.

Palo Duro is an approximately 250 MW wind project in Texas.

It ended service in December 2014 and sells 100% of its output under a 20-year PPA.

NEP paid approximately $228 million in cash consideration, excluding post-closing working capital and other adjustments, and assumed a differential membership liability of approximately $248 million.

NEP continues to expect a first-quarter 2015 closing of its agreement to acquire Shafter, a 20 megawatt contracted solar project currently under construction in California, for an estimated cash consideration of $64 million.

As discussed on the third-quarter call, these acquisitions are being funded by cash on hand, including the $150 million of primary proceeds retained from the IPO and a draw on NEP's existing revolving credit facility.

We expect to issue equity in order to support longer-term financing needs at some point in 2015.

Turning now to the consolidated results for NextEra Energy.

For the fourth quarter of 2014, GAAP net income attributable to NextEra Energy was $884 million or $2 per share.

NextEra Energy's 2014 fourth-quarter adjusted earnings and adjusted EPS were $458 million and $1.03 respectively.

For the full-year 2014, GAAP net income attributable to NextEra Energy was $2.5 billion or $5.60 per share.

Adjusted earnings were roughly $2.3 billion or $5.30 per share.

For the quarter, the corporate and other segment was flat relative to 2013 on an adjusted EPS basis.

For the full year, the corporate and other segment was down $0.02 per share on an adjusted basis from 2013.

On the development front, 2014 was a successful year for our pipeline projects.

The development of both Sabal Trail Transmission and Florida Southeast Connection continue progress well through their respective processes, as both projects submitted the necessary filings with FERC in 2014 and are on track to receive FERC approval in 2015 in support of a mid-2017 commercial operations date, as scheduled.

The Mountain Valley Pipeline joint venture with EQT Corporation continues to progress through the permitting process with the FERC application targeted for the fourth quarter of 2015.

The project has secured approximately 2 BCF per day of 20-year firm capacity commitments with an expected capital opportunity for NextEra of $1.0 billion to $1.3 billion.

The project is expected to be operational by year-end 2018.

NextEra Energy's operating cash flow growth outpaced EPS growth year over year, and our overall credit metrics improved and are in line with our expectations and consistent with our readings.

In the appendix of today's presentation, we have provided actual performance for 2013 and 2014, as well as our projections for 2015.

Additionally, you will see the corresponding ranges that the rating agencies indicate for those metrics at our ratings.

Approximately $15 billion of financing transactions were executed in 2014 by our treasury team to support the growth of our business.

As usual, we employed conventional debt issuances and continued to make use of project level debt and tax equity partnerships at energy resources.

Consistent with our well-established strategy of recycling capital, proceeds generated through the interrelationships between NextEra Energy and NEP introduce another source of capital integrated into NextEra's ongoing financing program.

In light of the progress made against our execution objectives, we continue to be comfortable with the 2015 adjusted EPS expectations we shared with you last quarter of $5.40 to $5.70 per share.

For 2016 we are updating our expectations to a range of $5.75 to $6.25, and we expect to be able to provide more insight into the drivers of earnings and cash flows for 2016 and beyond at our investor conference in March.

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

Turning now to NEP, our expectations taking into account all the asset acquisitions we are now contemplating are unchanged since the last call.

For the full-year 2015, we continue to expect the NEP portfolio to grow 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 approximately $1.13, which corresponds to the upper tier of the IDR splits by the end of 2015 or possibly slightly earlier.

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

Assuming current trading levels, this implies 2016 adjusted EBITDA of $580 million to $620 million and 2016 CAFD of $170 million to $190 million.

That concludes our prepared remarks, and we will now open the line for questions.

Thank you.

(Operator Instructions) Dan Eggers, Credit Suisse.

Thanks for the update.

I guess question number one, Jim has been pointing to the idea that your 2016 would be a disappointment if it wasn't at $6.

What do you guys, when you saw the guidance increase today, can you just talk about what you saw to give you confidence to move that number higher?

Well, first of all, we have had really since the investor conference the prior range of $5.50 to $6.00.

So that was based on the initiatives that we laid out for you at that time.

Since then, we have been able to push forward and execute successfully on I would say the vast majority of those initiatives, and we indicated as we went along the way that we were feeling better about where we might be within that range.

Separately, Jim very clearly articulated a charge to the organization, a challenge to the organization of being at the $6.00 range, hence the comment about being disappointed we didn't get there.

And then in the third quarter, we simply indicated that we would try and update now once we got past the Florida election and had a chance to roll the numbers up again.

So all of that is a preamble to say that based on the success we have had since laying out those capital initiatives in March of 2013, we now think that centering the range around that $6.00 mark is appropriate, consistent with our normal method of coming up with our expectation.

So, as always, we are telling you what it is we see today.

We could be literally anywhere within that band, but we think that band is appropriate given all the factors that we can see today.

Okay.

And I guess, Moray, just on the wind additions and the warehousing of additional equipment to qualify for the PTC, can you just walk through what you guys are doing to key that up and then how we should think about the ability to sustain beyond what is contracted additional wind growth for 2015 and 2016?

I will ask Armando to comment on the specifics on the development side.

But just for general context, I have said on a number of occasions that with the PTC extension, which Congress now passed, we felt comfortable that that would provide us good opportunities for projects that would deliver through the end of 2016.

I had also said that if there were no further extension of the PTC, we might well see a drop off in new development for you while, but we would expect even without PTC extension to see development pick up again later in the decade as the influence of improving economics and the EPA's Clean Power Plan come into play.

So just with that as general context, Armando, you might want to comment on what we are doing in specific development activities to make sure that we can get them in by the end of 2016.

Right.

So a couple of things.

First, we are on a -- I know we give you these numbers on a quarterly basis, but we are on what I would consider a pretty decent roll with our development activities in the renewables side.

So over the last couple of years, we have signed long-term power purchase agreements for wind and solar that are just above 2900 megawatts.

Of that 2900, Moray pointed out in the slides this morning that some of those were built in 2014, but we've still got 2115 -- I believe the number is -- of megawatts for contracts that we have in hand that will go COD in 2015 and 2016.

That number does not include any potential for wind projects in 2016.

We believe that the IRS is going to provide similar guidance on this PTC as they did last time.

We hope that will be provided before the investor conference in March, and at the time we will share with you what our expectations are on the wind side.

But it clearly would be a giant disappointment if we have 0 MW in 2016.

I just do not think that is going to happen.

On the solar front, really over the last 12 to 18 months, we have done very well in that market.

I think it is still way too early to talk about what is going to happen with tax credits for solar beyond 2016.

And as such, we probably have just a couple of more quarters here where we and others will be able to sign folks up for long-term agreements on the solar side.

But we've got several very promising opportunities on the solar side that I hope will pan out.

To give you an indication, though, of what we have been doing, 2014 was also our highest ever year in terms of bringing renewable energy megawatts to COD.

In 2014 we brought 1630 MW of COD, so we clearly have the capabilities to do that.

And I hope we would do that.

I am certainly not committing to that, but we will have more information for you in March.

That's great.

And just to clarify one thing, that 980 MW of wind that you have on slide 11, that would be all for 2015 delivery because you do not have clarity on the 2016 from the IRS yet, is that correct?

Yes.

Okay.

Very good.

Thank you, guys.

Julien Dumoulin-Smith, UBS.

So I wanted to follow up on the solar announcement in Florida and just explore that a little bit further.

First, can you expand a little bit on the regulatory process involved?

Obviously you have kind of alluded to it and tried it a little bit in the past, but what mechanisms precisely you are looking for, what kind of recovery you are looking for?

And then subsequently just in terms of the timing, can you talk about the ability to scale this up, or what total size do you see ultimately in Florida?

I know you delineated at least the first batch here, but is there an ability to scale this up similarly as you described gas before in the state?

On the first part, the regulatory needs to be recovered through base rate, so we have been working hard to make sure that we can deliver customer value, by which I mean make the addition positive to our total system economics in the current environment.

Not surprisingly, that has meant working very hard on getting the initial costs down because that's where so much of the economics are.

And so we have now reached that point.

So since these projects have positive economics for the customer, we believe it is appropriate to go forward, and in due course we will recover them through base rates.

On the second part of the question, there are some special characteristics of these projects that make them particularly attractive right now, and we can't quite yet see generally scaling that up to a much larger size.

We are going to need some further improvements in the economics.

These are also assisted by the fact that we are going to benefit from the existing 30% ITC.

So there is a question obviously about future projects from that perspective.

So the answer to the second part of your question is, yes, we think there is huge potential longer-term, but we think that we need to get a little bit further still on the economics before we can go much beyond the three projects that we are talking about here.

Great.

Excellent.

And then coming to Hawaii, could you give us a little bit of an update on where you stand?

Just as I imagine you have had conversations with folks in the state, I mean how do you feel about being able to execute that both from a timeline perspective and also just in terms of anything you might have to provide to get it all executed?

Sure.

Jim will have a couple of words.

Julien, obviously it is early days.

The teams are working on the SEC filings, as well as the Hawaii PC filing for revelatory approval, and things are moving apace.

And, as I said, it is early days, and I remain optimistic that we are going to be able to finalize things within a 12-month period here by the end of the year.

Great.

And just a last detail, any updates on the rate base effort in Florida?

Obviously you've got the first gas approval here, but just any issues or any changes in the program as you look towards getting the rest done?

Really no change.

Obviously we are pleased that they approved the specific project.

They will take up the question of the guidelines in March.

Great.

Thank you.

Paul Ridzon, KeyBanc.

If we look at the midpoint of your 2016 guidance, are you just kind of using the forward gas curves as they currently sit?

Yes.

All our expectations are always based on current forward curves, both for commodities and for interest rates.

So every time as part of our preparation for these quarterly calls, we go through an update to that outlook.

We update all the major driving assumptions, of which the commodity curves are one.

So yes, they do incorporate current curves.

Now recognize, of course, that those curves are bouncing around literally every day (multiple speakers).

Right.

On play, you have a $0.50 range, I guess?

Well, that's one of the big factors that causes the need for a range, certainly.

And Moray, over the past couple of years, you have kind of expanded your reach across the energy platform be it pipeline, gas reserves.

Are there anything else on the back burner we need to look at as far as potential opportunities?

Well, we are certainly -- we are always looking to see whether there are logical extensions that flow from the current skill set and current opportunity set.

But I think we have articulated to you and to others pretty clearly the ones that we are active in at the moment.

So obviously our core is the power business.

We have extensive knowledge of the gas business.

We have built that over time.

We are very capable of doing all kinds of large-scale development and construction infrastructure type projects.

Transmission development is definitely a focus.

The other one that I probably should remind everybody is obviously we have a small effort going in storage in a variety of different aspects from early-stage -- following early-stage R&D, early-stage production companies to actual projects that we either have completed or have in process.

So that is kind of the suite of opportunities at the moment.

You are talking electricity storage?

Correct.

Okay.

Thank you very much.

Steve Fleischmann, Wolfe Research.

A couple of quick questions.

First, if you look at this year, I think you came in around $5.30, and if you added back the $0.15 of one timers of the NEP restructuring, you are almost kind of in your range for 2015 just doing that.

Just to kind of round out 2015, is there anything that particularly hits this year -- kind of limits the uptick?

No.

I would say it is the other way around.

So let me just talk a little bit about 2014.

Why were we able to exceed our original expectations even while absorbing $0.15 of incremental and unanticipated at the time charges?

There are a number of reasons.

Most of them, frankly, having to do with the Energy Resources portfolio, most parts of which ended up doing a little better than we originally expected.

First, we had just plain wind and solar resource was better than the long-term averages.

There was probably about $0.08 worth of goodness from that.

Interest rates stayed low, lower than we -- because as I implied in my response with Paul earlier, we marked them to the curve, but that curve didn't manifest itself over the years.

So it was probably corporatewide actually it was probably about $0.04 of goodness from there.

And then the other big one was really performance in the Northeast.

So the NEPOOL portfolio was on the order of $0.10 or so better than we expected, even -- more than compensating for the shortfall that we had in our customer supply business in the first quarter in the Northeast, and that business, in turn, made up that big shortfall over the rest of the course of the year.

So you add up all of those different things and there was probably somewhere on the order of $0.25 to $0.30 of unanticipated goodness.

Now to be fair, there was also some unanticipated badness, some small factors, but that is kind of different.

So, again, when we do the expectations, we just go back to baseline normal expectations, where the commodity curves are right now.

So it is much more -- and that is how we have done 2015.

So it's much more a matter of fact that we've got $0.20 of, in a sense, unanticipated goodness in 2015 -- in 2014 -- that we cannot automatically expect will carry over into 2015.

Certainly hope it will, but we can't count on it.

Okay.

And just on 2016 guidance in terms of the renewable backlog, should we assume what you lay out here that is already contracted gets you maybe to the midpoint, and if you are able to do more, that's how you get toward the higher end?

No.

Absolutely not.

We have covered this actually on a number of occasions.

The stuff that we are doing now in new development is not going to have a significant impact until we reach 2017, 2018 and beyond.

In fact, for the last year, pretty much the development effort is generating projects that are really going to help us in 2017, 2018 and beyond.

So there may be some slight timing impacts on 2016, but that is not really going to be a big driver of where we are in the 2016 range.

Okay.

Great.

And then finally -- (multiple speakers)

Just remember that historically when we build wind, we get most or virtually all of the COD very, very late in the year.

So when you are building and we don't have anything in here for 2016 wind, but we certainly hope to build some.

And I would love to be able to build them in January, February and March.

But traditionally we put those in very, very late in the year.

So there is just very little EBITDA that goes into the year.

And on the solar front, you are getting to the point really at this point where it is going to be very difficult to sign contracts over the next couple of months and expect that you will be -- have a COD at anything other than very, very late in 2016.

So that's why, just go back and look at history, when we go in COD, it is very late in the year, and it really affects the future years' earnings.

Great.

One last question.

Just I think in the beginning of your remarks, you kind of reiterated the 5% to 7% I guess through 2018.

But it does seem like your 2016 kind of got you effectively high-end or above that range.

So just can you just maybe context the 2016 guidance with the 5% to 7%?

Sure.

2016, that is the center of that range, $6, is squarely within the 5% to 7% back from 2012.

Okay.

Thank you.

Michael Lapides, Goldman Sachs.

Congrats on a good 2014.

I wanted to ask a P&L question.

The commentary about staying above the midpoint or towards the higher end of the range in 2016, meeting the authorized ROE band, can you talk a little bit about what headwinds, if any, exist at FPL?

You're highlighting really strong expected but weather normalized demand growth, and you have a lot of the regulatory amorts kind of in your back pocket to use over the next few years.

Just trying to think about things that could offset those.

Yes, there was nothing in particular, but recognize that when we started out with the rate agreement, sort of picture yourself at the beginning of the rate agreement looking forward.

In general, you're going to need to utilize a little more surplus depreciation in the out years to maintain a given level of profitability just given the fundamental growth in the regulatory capital deployed.

So there is nothing special.

We're just again doing the same thing, taking our best view of the range of possibilities for 2016 revenue, including weather variability against that, expectations for 2016 costs, CapEx, etc., and the amount of surplus depreciation remaining.

And all of those give us comfort that in 2016 we can be at least above the midpoint of the formal range, so somewhere between 10.5% and 11.5%.

Got it.

And I know we will see this in the K and probably at the analyst day, but any insight you can give us on 2015 and 2016 CapEx expectations at just FP&L?

I'm going to defer on that one because I don't have the specific data in front of me.

The K will be out pretty soon.

This is Jim.

The other thing I would say is that we are going to lay out in good detail our capital plans at FPL in the March investor conference on both sides of the business, frankly.

Got it.

Thanks, guys.

Much appreciated.

Greg Gordon, Evercore ISI.

Armando, I just want to make sure I heard correctly that practically speaking when I look at slide 11 and I look at the backlog for wind in the United States, you said that that doesn't have anything in 2016, so that 980 MW is really just all delivery in 2015.

Is that right?

Yes, that is correct, and let me just give a clarifying point.

That is correct.

And all of those 980 MW that you see on there, we have committed to with the customer to bring those in before the end of 2015.

If for some reason a customer comes back to us and says, okay, now that we feel comfortable about 2016, can you just slip it into 2016, we will obviously do that.

But what I really meant to say is we have signed no contracts right now; none of the numbers that you see on here are based on a contract that we signed for 2016 COD.

(multiple speakers)

That looks really good because your backlog went up from like 1860 MW to 2254 MW since the third quarter, and you still have good option on 2016 if you get the extension.

Yes.

Just based on looking at those slides from the last quarter until today.

Absolutely.

Yes.

It has been a great period.

Shifting to another question, it has become a smaller and smaller piece of variability in your business, but the Texas market has obviously been under some duress in terms of gas prices coming down but also heat rates contracting in the wake of new supply additions and concern over the economy in Texas with oil prices having come down as much as they have.

I know your guidance on 2015 EBITDA and cash flow has moderated a bit.

Can you talk about market conditions there and maybe what you have done to hedge out that risk?

Armando may want to comment as well, but I would say that in general on the commodity front both oil, gas and power, nothing much good has happened recently, and that definitely includes Texas.

In the short term, because we do hedge extensively, there is a relatively modest impact, but I would certainly tell you that my personal view of the Texas market is less bullish than it was.

Armando?

I'll add just a couple more to that.

When I look at our Texas assets, it's really divided into three sets of assets.

You've got Lamar and Forney at 2800 MW combined cycle.

You've got roughly 1800 MW of what we call hedged wind, and you have a much smaller 400 or 500 MW or so of contracted wind in Texas.

The hedge to wind, really the first time that any significant hedges on the hedged wind start rolling off is 2017, and that is not a very significant portion.

You've got hedges after 2020 that start rolling off.

So I don't worry in the near term that much about either the hedged portfolio, hedged wind portfolio or contracted wind portfolio.

As Moray mentioned, on the combined cycle gas assets, we leveraged those assets last year, and part of what we did was we went out and hedged a good part of the margin for about two and a half years, and we have been legging into additional hedges when we can.

That's a market that does not have a lot of liquidity really past 2016, and even in 2016, it is not like you can just hit the bid that you see on the screen.

So it's not something I am concerned about at all in the near term.

The longer term economics, as Moray said, on the market, I am certainly not as bullish as I was a couple of years ago.

Thank you, gentlemen.

Have a good morning.

Hugh Wynne, Sanford Bernstein.

Moray, you had emphasized in your presentation today the improvement in cash flow from operations and EBITDA, which was stronger even than the growth in earnings.

Was wondering if you could drill down into that a little bit and just give us a feel for the primary drivers there and what were the differences with the growth in earnings?

Sure.

At the Energy Resources level, I think the main observation to make is simply that the strong contributions to cash flow coming from these contracted renewables projects gets masks a little bit, particularly in the early years by some other factors.

So I will describe two things.

First of all, simply in 2014, we had a number of non-cash items that affect earnings, of which the largest was simply the impact of some of the NEP launch costs, which obviously we would not expect to continue.

So that is one source of difference between the picture that you will get if you look at earnings growth and the picture you will get if you look at cash flow growth.

But the more fundamental one is that by the nature of these contracted renewable projects, you have virtually all your investment upfront.

And so in a sense, the faster that you grow that business, the greater the disparity between your earnings profile -- the impact that it has on your earnings profile -- and your underlying cash flow profile.

So that the growth in cash flow that is coming from the projects is kind of masked in the early years by the fact that they are not as accretive in the early years as they will be in subsequent years.

So it's almost like a mathematical thing that goes on.

So we simply wanted to highlight the fact that the cash flow growth at Energy Resources is very strong and just a flag for people that you probably want to look both at its contribution to earnings and its contribution to cash flow.

Okay.

And if I could, just a quick follow-up on the solar initiative at FPL.

If I remember correctly, those were three 75 MW projects, and you are estimating a cost of $400 million to $420 million?

Is that correct?

Correct.

And then you are saying that the economics would need to improve for the growth in utility scale and solar to continue?

Can you amplify on that at all what you think would be sort of an economic cost per watt for utility scale solar?

Well, recognize that those projects are advantaged by a couple of things.

First of all, eligibility for the 30% ITC, and secondly by I will call it good [citing] conditions.

So prior development work that has been done, access to transmission, etc.

So if you just look at the generic, supposing I wanted to add 200 plus MW of solar somewhere in Florida, you have got to start with a clean slate, find a new site, get transmission axis, all of those things.

Look at the full cost of the project.

That would not be economic today at the 10% ITC level.

So in answer to the direct question of how much more do costs have to come down, I would have to look more closely at the economics.

I'm going a little bit off memory, but yes, I would think somewhere on the order of 10% to 15%, and we certainly think that that is likely to occur over the next few years.

So, again, I feel very optimistic about doing more later in the decade.

Hugh, the only other thing I would say is we are very pleased that in this historically low price commodity environment that we have some utility scale solar projects in Florida that are cost effective for customers.

And so that 10% or 15% improvement going forward to offset the loss of the ITC and some of the special advantages that these projects have, one of the ways to do that is to have commodity prices come up a little bit.

And so -- and we are seeing this throughout the country now that solar is becoming increasingly cost effective -- utility scale solar is becoming increasingly cost effective compared to avoided cost at utilities around the country, and I think that is a very, very positive thing for our customers here in Florida and also for Armando's renewable business across the rest of the country.

And just as a reminder to everyone really, the challenge of making solar work here in Florida is actually quite a bit more than might appear because of our low cost structure and hence low rate structure, which is effectively what we are competing against.

Right.

Thank you very much.

I appreciate it.

Thanks, Hugh.

I think we have time for one more question.

Angie Storozynski, Macquarie.

So first on the growth in your wind power installations, we have heard from other wind developers in the US who seem pretty confident that the projects that will start operations before the end of 2017 will still qualify for the PTC given the extension through the end of 2014.

You seem to believe it is only until 2016.

So where is the difference?

Are you simply conservative in your assumptions, or do you think that it is really still unclear given the lack of the IRS interpretation?

Angie, assuming that the IRS provides similar guidance to what they did last year on in construction, we think that that will mean -- these are my words -- such a Safe Harbor for projects that would get COD before January 1 of 2017.

There has always been the question out there that because the IRS or Congress -- the IRS is just interpreting -- did not provide a what I will call a dropdead date on COD, that if you have continuous construction activities through the period of COD, that you could qualify for the production tax credit beyond again what I call my Safe Harbor date.

So if some folks are saying, look, we can build at some point in 2017 because we believe that we will have met continuing guidance and the IRS has provided some examples of what those activities are, I think that is certainly doable.

That is certainly a more aggressive interpretation than we would take.

Now we may have some projects just because of their circumstances that we would feel comfortable building in 2017 to build -- I'm sorry, to meet that IRS guidance.

But I can tell you that we will try to minimize those projects because we think they carry more of a risk than those projects that get done by the end of 2016.

Okay.

And then separately on NEP, so I just wanted to clarify one thing.

So if you are talking about 12% to 15% growth in distributions per share, you are assuming that you will be able to issue equity for each of the forward years assuming that the yield at the time of the issuance will be close to the [2.8%, 2.9%] that we are currently observing using the projections of the distributed cash per share?

Is that correct?

Yes.

It doesn't necessarily have to be exactly that, but that is why we included the comment about assuming at roughly current trading levels, yes.

Okay.

Thank you.

Thank you, everybody.

And at this time, that does conclude today's presentation.

We thank you for your participation.