新世紀能源 (NEE) 2016 Q2 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 Ms. Amanda Finnis.

Please go ahead, ma'am.

Thank you, Claire.

Good morning, everyone, and thank you for joining our second-quarter 2016 combined earnings conference call for NextEra Energy and NextEra Energy Partners.

With me this morning are Jim Robo, Chairman and Chief Executive Officer of NextEra Energy; John Ketchum, Executive Vice President and Chief Financial Officer of NextEra Energy; and Armando Pimentel, President and Chief Executive Officer of NextEra Energy Resources.

Also [are also] officers of NextEra Energy Partners; as well as Eric Silagy, President and Chief Executive Officer of Florida Power & Light Company.

John 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, 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 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 non-GAAP financial measures.

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

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

Thank you, Amanda, and good morning, everyone.

NextEra Energy and NextEra Energy Partners each delivered strong second-quarter financial results and solid operating performance.

NextEra Energy's adjusted earnings per share increased 7% against the prior-year comparable quarter, driven by new investments in energy resources.

For the first six months, NextEra Energy achieved year-over-year growth of 11% in both unadjusted earnings per share and cash flow from operations.

NEP grew per-unit distributions by 40% from a year earlier, and added to what we already considered to be a solid run rate with the acquisition of two high-quality wind facilities just after the end of the quarter.

Both businesses remain on track to achieve the full-year financial expectations that we have previously discussed, subject to our usual caveats.

Florida Power & Light's contribution to second-quarter earnings per share was roughly flat, down $0.01 from 2015.

Strong growth, driven by continued investment in the business, was offset by share dilution and a refund to customers related to the decision by the Florida Supreme Court to disallow investments in long-term natural gas supplies.

Aside from the impact of this decision, we are very pleased with FPL's financial results.

We earned a regulatory ROE of approximately 11.5%.

And average regulatory capital employed grew roughly 8.4% over the same quarter last year, reflecting our continued commitment to invest new capital to deliver low bills, high reliability, and clean energy solutions for the benefit of our customers.

Along these lines, during the quarter we announced a plan to acquire and phase out one of the state's highest greenhouse gas-emitting coal fired plants located in Martin County, which is expected to result in significant customer savings and substantial reductions in carbon emissions.

In addition, we received site certification for the Okeechobee Clean Energy Center that is expected to enter service in mid-2019.

Earlier this month, FPL was honored to receive the J.D. Power award for ranking highest in residential customer satisfaction among large utilities in the South.

We work hard to continue to improve service for our customers, and are proud that FPL's 2016 score is our highest ever in the study's history.

As a reminder, FPL filed its formal request on March 15 for rate relief, beginning in January 2017, following the expiration of our current settlement agreement.

And I will provide an update on the proceedings thus far in just a moment.

Energy Resources continued to benefit from strong contributions from new investments, and this was the principal driver of second-quarter growth.

We remain poised for another big installation year at Energy Resources, and our major activities remain on track to support delivery of approximately 2,500 megawatts of new contracted renewables projects in 2016.

If our development program goes as expected, Energy Resources and NEP's combined renewables portfolio will reach approximately 16,000 megawatts by the end of this year.

During the quarter, the IRS provided start-of-construction guidance for the wind PTC.

The guidance provides for a start of construction Safe Harbor of up to four years, increased from the two-year Safe Harbor formerly put in place for the 2014 PTC.

While there is some uncertainty on the impact of timing of customer demand as a result of this increased tenure, we believe that the longer-term impact further strengthens what we already consider to be one of the best environments for renewables development in our history.

In addition, the IRS also provided guidance for the repowering of wind projects.

And we are pleased to announce that we are currently pursuing repowering opportunities at two of our existing Texas wind projects for roughly 327 megawatts to be completed by the end of 2017.

We continue to believe that the longer-term fundamentals for North American renewables growth have never been stronger; and that the capabilities of our development organization, together with our purchasing power, scale in operations, strong access to capital, and cost of capital advantage, place us in an excellent strategic position to capture even more opportunities going forward.

NextEra Energy Partners' portfolio additions over the last year drove substantial growth in cash available for distribution.

In turn, the NEP Board declared a quarterly distribution of $0.33 per common unit, or $1.32 per common unit on an annualized basis.

NEP's strong performance was underscored by an approximately 285 megawatt acquisition from Energy Resources earlier this month.

Included in the acquisition are the Cedar Bluff and Golden Hills wind energy centers, each commissioned in 2015 with GE technology.

These high-quality wind projects are expected to provide an attractive yield to investors.

At the same time, the utilization of debt and cash on hand to fund the purchase price reflects the Partnership's flexible approach to financing and allows NEP to be opportunistic as to future growth in 2016.

Overall, we are very pleased with the results for the quarter.

We believe that both NextEra Energy and NextEra Energy Partners are well positioned heading into the second half of the year.

Now let's look at the result for FPL.

For the second quarter of 2016, FPL reported net income of $448 million and earnings per share of $0.96, down $0.01 per share year-over-year.

Continued investment in the business contributed $0.08 of growth in earnings per share versus the prior-year comparable quarter, but was offset by the impact of the Woodford Project gas reserve refund and share dilution.

We continue to identify opportunities to invest capital for the benefit of customers, with regulatory capital employed growing by approximately $2.6 billion, or 8.4%, over the same quarter last year.

Similar to the Cedar Bay transaction that closed in the third quarter of last year, we are pursuing a plan to acquire and phase out another coal-fired power plant.

The Indiantown Cogeneration facility is a 330 megawatt power plant located in Indiantown, Florida, which has a contract to supply capacity and energy to FPL through 2025.

FPL proposes to purchase the ownership interest in the Indiantown Cogeneration facility for $451 million, including existing debt.

If approved by the Commission, this transaction is expected to result in a significant reduction in the plant's operations, and enable earlier shutdown of the facility than would otherwise be the case.

This plan is projected to save FPL customers an estimated $129 million, and prevent nearly 657,000 tons of carbon dioxide emissions annually.

The acquisition, if approved, is expected to close early in 2017, and is another example of our commitment to provide low bills and clean energy solutions for the benefit of Florida customers.

Along with Cedar Bay, this transaction, if approved, will result in the early retirement of two of the highest greenhouse gas-emitting power plants in the state, and further FPL's position as a clean energy leader.

During the second quarter, we were disappointed that the Florida Supreme Court reversed the PSC's December 2014 approval of the acquisition of long-term natural gas supplies from the Woodford Project.

We continue to believe the investment presents a long-term opportunity to hedge potential volatility in the market price for natural gas.

And we appreciate the PSC's careful consideration of this innovative approach to managing this risk.

Our second-quarter results include a negative impact of $0.03 per share, reflecting a refund to be provided to customers through future fuel clause proceedings for all revenue requirements accrued to date for this investment, as compared to settled natural gas prices over the same period of time.

Going forward, the Woodford Project investment has been removed from customer recovery, and we expect physical production to be liquidated in the open market.

Our reported ROE for regulatory purposes will be approximately 11.5% for the 12 months ending June 2016.

As a reminder, under the current rate agreement, we record reserve amortization entries to achieve a predetermined regulatory ROE for each trailing 12-month period.

During the second quarter, we utilized $16 million of reserve amortization, which was less than we had planned, leaving us with a balance of $71 million for the remainder of 2016.

We continue to expect that the balance of the reserve amortization, coupled with current CapEx and O&M expectations, will allow us to support a regulatory ROE in the upper half of the allowed band of 9.5% to 11.5% through the end of our current rate agreement in 2016.

As always, our expectations assume normal weather and operating conditions.

Turning now to Florida's economy, the current unemployment rate of 4.7% is the lowest level since 2007; and the number of jobs was up approximately 245,000, or 3%, compared with June of last year.

Florida's private sector continues to drive the state's job growth, and more than 1.1 million private sector jobs have been added since 2010.

The real estate sector continues to show strength, with new building permits remaining at a healthy level, and the Case-Shiller Index for South Florida home prices up 6.3% from the prior year.

In addition, the latest readings of Florida's consumer confidence remain near post-recession highs.

FPL's second-quarter retail sales volume was down 2.5% from last year.

We estimate that weather-related usage per customer had a negative impact on year-over-year retail sales of 5.5%.

On a weather-normalized basis, second-quarter sales increased 3%, comprised of a continued customer growth impact of approximately 1.2% and increased weather-normalized usage per customer of approximately 1.8%.

As a reminder, our estimates of weather-normalized usage per customer are subject to significant short-term volatility.

Looking ahead, we continue to expect year-over-year weather-normalized usage per customer to be between flat and negative 0.5% per year, as we saw last year.

As we have previously stated, on March 15 we submitted testimony and detailed supporting information for FPL's 2016 base rate proceeding.

During the quarter, nine quality of service hearings were conducted across the state, and an overwhelming majority of participants spoke positively about the service they receive from FPL.

Intervenor and staff testimony were filed earlier this month, and we will be submitting rebuttal testimony next week on August 1.

We are focused on technical hearings that are scheduled to take place in late August and early September.

And we expect the staff recommendation and Commission ruling on revenue requirements and rates in the fourth quarter.

The four-year base rate plan has been designed to support continued investments in long-term infrastructure and advanced technology, which improves reliability and helps keep customer bills low.

As always, we are open to the possibility of resolving our rate request through a fair settlement agreement.

And our core focus remains on pursuing a fair and objective review of our case that supports continued execution of our successful strategy for customers.

Let me now turn to Energy Resources, which reported second-quarter 2016 GAAP earnings of $234 million, or $0.50 per share.

Adjusted earnings for the second quarter were $313 million, or $0.67 per share.

Adjusted EPS increased $0.10 or approximately 18% year-over-year.

Energy Resources' core business results were primarily driven by contributions from new investments of $0.19 per share, reflecting continued growth in our contracted renewables program and contributions from our gas pipeline development projects.

These gains were partially offset by a decline in contributions from our existing asset portfolio of $0.04 per share.

A favorable impact from the partial reversal of a 2014 income tax charge that resulted from the separation of our Canadian projects to enable them to fit into the overall NEP structure was more than offset by lower state tax incentives, the ongoing impact of PTC roll-off, and other headwinds versus the prior-year comparable quarter.

Wind resources were roughly 92% of the long-term average, essentially in-line with the second quarter of last year.

Additional details are shown on the accompanying slide, including the impact of unfavorable market conditions on our upstream gas infrastructure activities, and increased interest expense, reflecting continued growth in the business.

As I mentioned earlier, the action taken by Congress in December 2015 to extend the wind PTC over a five-year phase down period was further enhanced during the quarter by IRS guidance on start of construction.

Subject to beginning significant physical work or meeting certain Safe Harbor provisions, the guidance extends the PTC for an additional four-year period.

Therefore, as detailed on the accompanying slide, we now expect that a wind facility that commences construction this year, by complying with the Safe Harbor to procure 5% of the total capital to be invested and achieves commercial operation by the end of 2020, will qualify for 100% of the PTC.

As compared to the two-year Safe Harbor period that was put in place for the 2014 PTC, we expect this increased tenure to help support our US wind development activities further into the next decade, and provide a greater overall opportunity set than would otherwise have been the case.

While this is terrific for our longer-term potential growth, we remain watchful as to whether it may impact near-term customer demand by delaying some opportunities from 2017 and 2018 to later years.

For solar, we continue to expect IRS start of construction guidance to follow later on, given that the commercial operation deadline for the first step of the solar ITC phase-down is not scheduled to occur until January 1, 2020.

Overall, the added planning stability provided by tax incentives are expected to serve as a bridge to further equipment cost declines and efficiency improvements that should enable renewables to compete on a levelized cost of energy basis with gas-fired technology, when tax incentives are ultimately phased down.

In addition to the four-year start of construction Safe Harbor for wind, the IRS also released guidance for repowering wind facilities.

The guidance confirms two key points.

First, it explains that the 5% Safe harbor for starting construction applies to the repowering of wind facilities.

Second, it provides an 80/20 rule, by which a repowered wind turbine may qualify for a new 10-year PTC period if the cost of the new equipment incorporated into the turbine is at least 80% of the turbine's total value.

As I mentioned earlier, we are moving forward with repowering two of our Texas wind assets.

We are also conducting due diligence on the rest of our US wind portfolio, and are beginning to talk to customers in order to assess the potential size of this opportunity.

We hope to be able to give a more comprehensive update on the size of our repowering initiative before the end of the year.

Regardless of the total size, we expect the majority of our repowerings to be in 2018, 2019, and 2020.

As a result, we do not expect this opportunity to change our overall financial expectations for NextEra Energy through 2018.

The team continues to execute on our backlog and pursue additional opportunities for contracted renewables development.

From our total 2015 to 2016 renewables development program of over 4,000 megawatts, roughly 1,500 megawatts were brought into service in 2015, and construction activities remain on track for the remaining project backlog.

If our development program goes as expected, Energy Resources and NEP's combined renewables portfolios will reach approximately 16,000 megawatts by the end of this year.

From this base, the expectations we discussed on the last call to bring into service roughly 2,800 to 5,400 megawatts of new North American renewables projects over the course of the 2017 to 2018 time frame, are unchanged.

Since the last call, the team signed roughly 200 megawatts of US wind projects, bringing the total contracts currently signed for delivery in this time frame to approximately 575 megawatts.

Including 327 megawatt repowering opportunities and currently signed contracts for new wind and solar projects, our 2017 to 2018 renewables backlog is now over 900 megawatts.

Together, we expect to invest approximately $250 million of capital to complete these repowering projects, which should generate returns similar to new build opportunities.

While the team is actively pursuing a number of additional opportunities, we continue to expect that a greater portion of new project demand, and, in turn, a greater portion of our investment opportunities, to be in 2018.

Although we are optimistic about the prospects for new renewables growth, it is important to remember that forecasting 2017 and 2018 origination expectations at this stage in 2016 remains subject to a number of uncertainties.

Turning now to the development activities for our natural gas pipelines, the Florida pipelines remain on track.

FERC approval was received earlier this year, and we continue to expect an in-service date in mid-2017.

NextEra Energy's investments in Sabal Trail transmission and Florida Southeast Connection are expected to be roughly $1.5 billion and $550 million, respectively, and FPL is the anchor-shipper on both pipelines.

The Mountain Valley Pipeline project, in which our expected investment is roughly $1 billion, has continued to progress through the FERC process, and we continue to expect to achieve commercial operations by year-end 2018.

Let me now review the highlights for NEP.

Second-quarter adjusted EBITDA was $156 million.

And cash available for distributions was $65 million, up $54 million and $15 million, respectively, from the prior-year comparable quarter.

Strong contributions from acquisitions were the principal driver of growth.

New projects added $68 million of adjusted EBITDA, and $28 million of cash available for distribution.

After accounting for the results of new project additions, existing projects in the NEP portfolio delivered adjusted EBITDA and CAFD roughly in line with the prior-year comparable quarter.

Second-quarter wind resource for the NEP portfolio was roughly 91% of the long-term average, which was similar to the prior-year comparable period.

As a reminder, these results are net of IDR fees, which we treat as an operating expense.

IDR fees increased $8 million from the second quarter last year.

The impact of other effects, including higher management fees and outside services, are shown on the accompanying slide.

As I mentioned earlier, just after the end of the quarter, NEP completed and approximately 285 megawatt acquisition of the Cedar Bluff and Golden Hills wind energy centers for a total consideration of approximately $312 million, subject to working capital and other adjustments, plus the assumption of approximately $253 million in liabilities related to tax equity financing.

The purchase price for the transaction was funded in part by the issuance of HoldCo debt, with the balance of the purchase price funded with cash on hand and through a draw under a project level revolving credit facility.

The use of HoldCo debt is consistent with our target at NEP for a long-term capital structure utilizing HoldCo leverage of approximately 3.5 times project distributions, after project debt service.

Based on this metric, we expect our current incremental HoldCo debt capacity to be roughly $300 million to $400 million.

Looking ahead, NextEra Energy Partners expects to continue to be flexible and opportunistic as to future growth opportunities and financing activities.

Turning now to the consolidated results for NextEra Energy.

For the second quarter of 2016, GAAP net income attributable to NextEra Energy was $540 million, or $1.16 per share.

NextEra Energy's 2016 second-quarter adjusted earnings, and adjusted EPS, were $777 million and $1.67 per share, respectively.

Adjusted earnings from the corporate and other segment increased $0.02 per share compared to the second quarter of 2015.

For the first six months, NextEra Energy achieved year-over-year growth in adjusted earnings per share and operating cash flow of 11%.

Our year-to-date results now reflect the first-quarter 2016 favorable impact of approximately $17 million, or $0.04 per share, not formerly included in our first-quarter financial statements.

This first-quarter impact, which occurred as a result of an accounting standards change on March 30, 2016, is expected to be largely representative of the full-year impact, subject to NextEra Energy's stock price volatility and stock option exercise activity.

At the corporate level, our base case plan continues to assume no new equity for 2016.

The sale of our Lamar and Forney natural gas generation assets located in ERCOT closed at the beginning of the quarter, generating net cash proceeds of approximately $456 million.

In addition, we continue to expect opportunities to recycle capital through potential additional sale opportunities of merchant and other non-strategic assets in our portfolio.

Capital recycling remains an important part of our financing plan as we continue to execute on our strategy to become more long-term contracted and rate regulated.

We remain on track to deliver our EPS expectations for this year and the longer term.

For 2016, we continue to expect adjusted earnings per share at NextEra Energy to be in the range of $5.85 to $6.35, with more of our growth, for a variety of factors, expected to occur in the first versus the second half of the year.

Based on what we see now, we expect most of our growth in the second half of the year to be in the fourth quarter.

For 2018, we continue to expect adjusted earnings per share at NextEra Energy to be in the range of $6.60 to $7.10, implying a compound annual growth rate off a 2014 base of 6% to 8%.

In addition, we continue to expect to grow our dividends per share 12% to 14% per year, through at least 2018, off a 2015 base of dividends per share of $3.08.

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

Turning now to NEP.

Following the acquisition of the Cedar Bluff and Golden Hills wind energy centers just after the end of the second quarter, we expect the current portfolio to support a CAFD run rate of $230 million to $260 million (sic - see slide 16, "$290 million") as of December 31, 2016.

As a result, we now expect to exceed the low end of our previously stated December 31, 2016, portfolio run rate CAFD expectation of $210 million.

We are also updating the December 31, 2016, run rate for adjusted EBITDA from $640 million to $760 million to $670 million to $760 million, reflecting calendar year 2017 expectations for the forecasted portfolio at year-end 2016.

Our expectations are subject to our normal caveats, and are net of expected IDR fees, as we expect these fees to be treated as an operating expense.

From a base of our fourth-quarter 2015 distribution per common unit at an annualized rate of $1.23, we continue to see 12% to 15% per-year growth in LP distributions as being a reasonable range of expectations through 2020, subject to our usual caveats.

As a result, we expect the annualized rate of the fourth-quarter 2016 distribution to be in a range of $1.38 to $1.41 per common unit, meaning the fourth-quarter distribution that is payable in February 2017.

In summary, we continue to execute against our strategic and growth initiatives across the board at FPL, Energy Resources, and NEP.

We remain very focused on our key objectives for the year, and are off to a strong start through the first two quarters.

Overall, we believe our opportunity set is one of the best in the industry.

And we are well positioned to leverage our businesses to continue to deliver on our growth expectations now and into the future.

That concludes our prepared remarks.

And with that, we will now open the lines for questions.

(Operator Instructions).

Stephen Byrd, Morgan Stanley.

I wanted to discuss the repowering updates you provided on the wind business.

It sounds like you are making some good progress.

Could you give us a sense of what portion of your fleet would either be sufficiently old that it's the run through the PTC, or that elected to CITC.

Is there a rough portion we should be thinking about that could potentially be eligible for repowering?

Stephen, it's Armando.

Obviously a question that everybody wants to know so they can give some size to the program.

I think what I can tell you is that it's a fair amount of our program that would be eligible for repowering.

I'd say that anywhere from maybe 3 to 4 gigawatts are potential repowering candidates.

But what we say internally, and what I want you and others to understand, is each one of these repowering projects that we're looking at is a whole new project.

We've got to look at -- has the permitting changed?

Have the environmental regulations changed?

What do the land leases look like?

What discussions can we have with the customers?

What do the old PPAs look like, if it's a merchant project?

How comfortable are we with revenues and/or hedges that we have to take a look at?

So, we've actually got a very large spreadsheet where we are looking at these projects.

But I can tell you that, in detail at this point, we've only looked at a very small amount of the projects that we feel comfortable with.

And most of what we are seeing -- again, it's still very early, because all these things are just like their own mini-projects -- most of what we're seeing we think would likely go COD in 2019 and 2020.

There's obviously going to be a portion, if they work, that are going to go into 2017 and 2018.

And, unfortunately, it's going to probably be dribs and drabs like you have today, when we announced these 327 megawatts.

But a large portion of these look like, if they are going to make sense, would be in 2019 and 2020.

So a very small piece, and we're very happy to announce it today, because it certainly wasn't something that we were thinking about six months ago.

But you will probably continue to hear from us that, hey, this works; and this doesn't work; and so on.

That's very helpful color, Armando.

Thank you.

And then just shifting over to natural gas infrastructure, you have had good success in growing the business.

From here, when you look out at additional growth opportunities in natural gas infrastructure, are there logical growth opportunities that you really need in the near term?

Or should we be thinking that, while it's a great opportunity, it's going to progress over an extended period of time?

In other words, are there actionable additional options that you see?

And do you also see a real need in the near term?

Or is this just something that's a broader -- it's not quite as near term, in terms of your thinking around growth?

So, I think a couple of points on that.

First, when we acquired the NET portfolio last year in Texas, one of the things that we said was, we were happy to be acquiring an interstate portfolio of pipelines, and we thought it would give us opportunities to expand in that area.

And that we believe that the additional gas requirements coming out of Mexico would present us opportunities down the line; we still think that.

It's what moves or transactions that get negotiated with our friends south of the border, always take a little bit longer than what we would expect, but we still think that there are opportunities.

I wouldn't want you to believe that they are $2 billion type opportunities like we did in NET Mexico.

I think these are growth opportunities in Texas and maybe to the Mexican border, and we're excited about that.

Beyond that, we're doing greenfield work.

It's very difficult for us to be able to participate in what I'll call the acquisition market, which is primarily the MLPs participate in.

So we're doing some greenfield work, along with the small business that we have in the upstream.

And we are certainly hopeful that from now through 2020 that we would have another project, another pipeline project, to be able to announce.

But I wouldn't say that there's anything in the near term that we would be announcing.

Great.

Thank you very much.

Appreciate it.

Jonathan Arnold, Deutsche Bank.

Just a follow-up on the repowering.

I recall, at one point, you had indicated you might need to get some incremental IRS guidance around the 80/20 calculations, and the like.

Do you have that in a form that you feel is financeable currently, or is there still a need to firm up the structure?

Jonathan, it's Armando.

We did get some incremental guidance from the IRS on repowerings a couple of months ago.

The reason that we felt comfortable announcing the 327 megawatts on repowering today is we think that it, at least this project and the calculations, the fair value calculations that we have to do in the project, fit squarely into that guidance.

I will tell you that, as I mentioned before, that each one of these are mini-projects.

It would be helpful, obviously, to get additional guidance from the IRS to make the entire portfolio that I talked about before work.

But there's a good bit of the portfolio that we're comfortable with the guidance that we have received to date.

And that, in and of itself, would not be what holds it up.

And one thing to add to that, Jonathan, we have secured tax equity financing for the two projects that we announced on this morning's call.

Okay, great.

That was going to be my follow-up.

But are you pursuing incremental clarification or not?

We don't need any incremental clarification at this point, Jonathan.

It would be -- we're not the only ones that are thinking about doing something like this, so there are others that are interested, I think, potentially in getting additional clarification.

But for the projects, at least for the initial projects that we're looking at, the guidance that we have received is good enough.

But again, I want to make sure that everybody understands: these things are all mini-projects, in and of themselves.

The IRS piece is just one small bit of what we need in order to make a conclusion that we would move forward.

Okay.

Thank you.

And then on -- just as we look at the slide with the detail on the NextEra Energy Resources EBITDA and cash outlook, it seems there's been a bit of an uptick from first quarter in the financing costs line.

Can you give us a sense of what's driving that?

Is it incremental project financing?

Is it higher costs?

Is it --?

We just had some incremental refinancing activity that was impacting that line, Jon.

Okay.

Great.

That's all I got.

Thank you.

Paul Zimbardo, UBS.

Yet another follow-up on repowering.

Can you provide a little additional color on how you selected those specific 327 megawatts out of the portfolio, and what kind of return profile you are expecting on that investment?

I feel comfortable giving you a little bit more detail on the former, but at this point I think it's too early to talk about the returns.

Although I can at least tell you on the returns that we wouldn't be making investment returns on repowering projects if they weren't at least as good as the returns that we're getting a new projects.

So we took a look at our portfolio; obviously if a project does not have production tax credits -- it is no longer generating production tax credits -- that makes it a pretty good candidate for a repower.

Why?

Well, because if you are going to repower before the production tax credits have expired, you are going to lose some of those older production tax credits in order to gain new production tax credits.

Having said that, projects that still have one or two years of production tax credits that they are generating, they may also work.

I'm not saying that they would work.

But you've got to understand whether giving up two years' old production tax credits and getting another 10 years of production tax credits -- as an example, in 2020, when you can get 100% PTCs for 10 years -- whether that makes sense or not.

Projects that -- what we call the convertible investment tax credit, what other people call the 30% grant from the government -- those never had production tax credits.

Those are actually decent candidates.

There's not a big difference whether a project was or is tax equity financed or is project financed.

So either one of those would work.

There's not a big difference whether a project has already been dropped or sold to NextEra Energy Partners.

Certainly, NextEra Energy Partners could do this.

Projects that are merchant have one less difficulty associated with them; that is, you don't have a PPA counterparty to have a discussion with.

Having said that, we have had discussions with a couple of PPA counterparties and they love the idea of repowering.

I am not suggesting that those are going to get repowered.

But at least the discussions that we've had, those customers love the idea that they can get repowered turbines.

So, that's the things -- probably the most important things that we're looking at, in order to determine if somebody is a candidate.

Yes, but the bottom line, Paul, is that the return thresholds are at least equivalent, if not slightly better than what we currently see in our new build portfolio.

That's why repowerings are so attractive.

Okay.

Thank you.

That's great.

And then one other question at the utility, after the Supreme Court decision for the gas rate basing, do you still think this is an opportunity you are going to explore?

And if so, what are the next steps from a regulatory or legal standpoint?

This is Eric Silagy.

From a reserve standpoint, the Court was clear that the PSC would have to go back and review this.

They feel as if actually to do that they would need the authority, so that would really require legislative action.

And whether or not that occurs or not remains to be seen.

We clearly see a lot of value in the opportunity at the utility to be able to have predictability and some certainty a little more around gas supplies from a pricing standpoint.

And that's what this is; it's a physical hedge.

And so we think there's a lot of value there for customers.

With the Commission thought that unanimously, and the Court made it clear that they weren't really passing a judgment on whether or not it was a good idea; just that they didn't believe that the Commission had the authority under the current legislative construct to be able to make that ruling.

And so, in a way, they were encouraging that to be clarified through the legislative process.

Okay.

Thank you much.

Shahriar Pourreza, Guggenheim Partners.

Really robust spending outlook at Resources, and it doesn't appear that you are putting any strain on your credit metrics in the near term.

But can you touch on if you see any mismatches between the future cash flows and the current development spend, say post 2017, 2018?

And where these potential merchant asset sales that lever to mitigate any potential (technical difficulty) right size?

No, we don't see any mismatches.

We continue to grow cash flow through new investments.

We do a run at a free cash flow deficit, which we finance with -- from third-party sources.

We are careful in terms of how we balance our growth, going forward.

We have very attractive investment opportunities at Florida Power & Light that we continue to execute on, and continue to see good opportunities at Energy Resources.

But as we said in the prepared remarks, we do continue to look at recycling activities as a way to become more long-term contracted and rate-regulated, which is consistent with our strategy.

Got it.

Thanks, that's helpful.

And then just on the reserve amortization balance, any sort of expectations how much we could carry into 2017, if it's extended as part of the negotiation process in the current filing?

Or do you expect to fully recognize it by year end?

Yes, it's a feature of our settlement agreement that we executed back in 2012, so the plan would be to use what we currently have.

Okay, got it.

And then just lastly on the Woodford Shale investments, what do you (technical difficulty) from an asset standpoint?

I'm sorry, Shahriar, could you repeat the question?

Sorry about that.

So just on the Woodford Shale investments, what are you exactly unwinding from an asset standpoint?

Or are these just contracts?

Yes, all we're unwinding is basically the fuel cost that was passed on to customers.

And since natural gas prices have come down just a hair, the differential between what was rolled through in the fuel charge and what the market price for natural gas is, that's really the unwind of the charge.

However, I do want to say that with -- in our current natural gas price environment, this would have been a great time to be [blaring] in to further investments.

So it's unfortunate with the Supreme Court decision.

Exactly.

Thanks so much.

Paul Ridzon, KeyBanc.

Can you give a sense of, as you look at these repowering opportunities, a dollar per megawatt -- kind of put bookends around that?

It is going to depend.

I will give you an assessment, though, on the ones that we announced today.

The CapEx investment is roughly $250 million.

That's not to say that it's going to be the same metric for every project that we could do.

But for this one, it was roughly $250 million.

Is part of the economics that make these at least as good as new development the fact that you don't have to do the siting and permitting?

How big a component is that?

As I mentioned before, these are all mini-projects.

In some cases, you are going to have to re-permit.

In some cases, you are going to have to relicense.

In some cases, you're going to have to have discussions with the county or the state or the -- you're going to have to deal with birds and bats and bees, and all of the things that we generally deal with.

We've got to take a look at these as a brand-new development.

Some states are actually easier to get some things done than others, but that's the case for repowering, the same as for new investments.

Paul, let me just add, because we've had a lot of questions on -- this is Jim -- on repowering this morning.

I just want to reemphasize something that Armando said.

We're not trying to be cagey in terms of how we're answering all these questions on repowering.

The reality is, we have several gigawatts, as Armando said, of opportunities, but each project is a completely new development.

And it's a little bit easier than the old development because you don't have to go get land leases, and you have a transmission interconnect.

But there's still an enormous amount of work that goes to get done for each of these projects.

So, we have a big team on it.

We're running through it.

It is, as Armando said -- if it's up to -- if it's as many as 3 or 4 gigawatts, that's a tremendously big opportunity for us.

And we're, as always, on something that we've been -- the other point I just wanted to make is we've been working on it for about 90 days.

And so, I think we have made tremendous progress, actually, in the last few months on it.

And we're going to have more clarity on each of the calls that we do, as we go forward.

It is becoming clear, though, for sure, that most of the activity is going to be 2018, 2019, and 2020.

And so, really as you think about this for us, it's a terrific driver of growth post-2018, as we think about the longer-term future for the Company.

And is this 327 megawatts a megawatt-per-megawatt displacement, or is this -- are you adding more megawatts with bigger towers?

Now, this is not a megawatt-for-megawatt -- well, let me put it to you this way.

We are taking turbines down that have 327 megawatts of capacity, and we are putting refurbished turbines up that have 327 megawatts of capacity.

Does that answer your question?

Yes.

Yes, it does.

And then you alluded to the fact that the second-half growth is going to come in the fourth quarter.

Are we expecting a down third quarter?

Yes, we're expecting most of the growth to have occurred in the first half of the year versus the second.

And that's really due primarily just to some timing issues around some tax items.

And then Lamar/Forney sale having hit in the second quarter as well.

Those are really the two primary factors.

Okay.

And then in Florida, is there a specific time period carved out for settlement discussions?

No, there's not.

Obviously we're going to be going into hearings starting on August 22.

Those are scheduled to last for two weeks.

And so, we're open to settlement discussions at any time.

But, realistically, timing becomes more challenging as you get closer and closer to getting in the hearings, simply because everybody is gearing up and then going into the hearings.

Okay.

Thank you very much.

Greg Gordon, Evercore ISI.

Thanks.

Actually, that last question was the vast majority of my question.

I was wondering if, at this point, there had been any of these specific filings that talk about the concept of retaining or changing the current return on equity construct.

In the last several rate deals you had, the Commission has been consistent in giving you a target-based ROE with a wide band of opportunity in risk.

Do you expect that you'll have the same framework going forward?

Or is there potential for a change in that framework?

And if so, when will we get a sense of where the different parties are on that issue?

This is Eric.

We filed our case, and we don't expect any change in the long-standing Commission framework of having it at 100 basis points [on the other side of] a midpoint.

That's really designed for -- again, to -- for the Commission to be able to have predictability and stability, and not having people coming in for a rate cases in the short-term basis.

So, there's no indication that that's going to change.

That's something that the Commission has had in place for a while.

And it's effective for all the [IOEs] in Florida.

Great.

And has there been any testimony filed on cost of capital yet?

Well, we had lots of testimony filed, absolutely.

So the Commission has received our direct testimony.

And as John said, we are in the process now of filing -- preparing our rebuttal testimony, and that will go in on August 1.

Great.

And is there -- I know that there's been a lot of -- I doubt you are going to answer this question, but someone has to ask it.

Is there anything that you can say publicly about the Oncor process?

Greg, I know you had to ask it, and I'm not going to comment on it.

Okay.

Thank you, guys.

Steve Fleishman, Wolfe Research.

Just to follow up on the rate case, what's your views on the chances of settling the case?

Is it the same as when you filed earlier this year, or has anything changed in your views on settlement chances?

Steve, this is Eric.

It's always hard to predict.

We've got a number of intervenors.

We've made it very clear that we're always open to having these discussions.

We think settlement is a good thing, just generally, as long as it's fair for all the parties.

But we just finished nine quality of service hearings for the Commission; went around the state throughout our territory.

The response from customers was overwhelmingly very positive.

We filed a very strong case.

I feel really good about where we stand from a perspective of -- we've had the lowest bills in the state for six years in a row, and the highest reliability and the best customer service, and an emissions profile that's the cleanest in the Southeast US.

And I think the Commission recognizes that.

So we're prepared to go into hearings and to finish the case out.

But if we can have a settlement, that's great.

It's just hard to predict, because it's not dealing with one counterparty; it's multiple counterparties.

Okay.

Great.

And then maybe just clarify on a financing plan.

I know you guys have talked about really looking to limit any equity needs for your plan, particularly in the near term.

Do you continue to think you can fund the plan pretty much without additional equity?

Yes, we do for 2016.

With the sale of Lamar/Forney generating about $450 million in net cash proceeds, I think that puts us in a pretty good position for the balance of this year.

We have a few more capital recycling opportunities that we are looking at, as well.

And for 2017, really not going to give any guidance around that until we get through the rate case.

Okay.

Thank you.

Michael Lapides, Goldman Sachs.

I think easy question, and likely for Eric.

Eric, can you talk about the issues surrounding Turkey Point, especially with the lawsuit that's been filed?

And just how you think about the cost of remediation?

How do you think about the timeline for that?

And then obviously some of the complainants are talking about the potential for cooling towers.

What do you think about the likelihood and need for that would be, as well?

Yes, Michael.

Turkey Point, there are a lot of parties obviously who have jumped in on this for a whole variety of reasons.

The reality is that the cooling canals have operated as designed.

There is no impact on the local drinking water wells.

There's no pollution going into Biscayne Bay.

There is a concentration of salt water below the cooling canals that has moved through the limestone.

That was, frankly, anticipated during the original design of the canals.

Everybody knew that was going to occur; it was a question of how far.

We have now identified, because we now have the technology to identify, how far some of that saltwater has migrated.

And we have a plan in place.

We're working very closely with the Florida Department of Environmental Protection, the Miami-Dade authorities, and others to mitigate that plan.

It's fact-based.

It's science-based.

We're going to undertake that.

We're waiting on permits to be able to do some of that.

And the costs associated with that is the cost associated with operating the plant.

And so we fully expect that to be recovered through our environmental cost recovery clause.

Got it.

Thanks, Eric.

Much appreciated.

Thank you very much, everyone.

That will conclude today's conference call.

Thank you very much for your participation, ladies and gentlemen.

You may now disconnect.