新世紀能源 (NEE) 2016 Q3 法說會逐字稿

Good day everyone, and welcome to the NextEra Energy and NextEra Energy Partners 2016 third-quarter release 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, Amelia.

Good morning, everyone, and thank you for joining our third-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; Armando Pimentel, President and Chief Executive Officer of NextEra Energy Resources; and Mark Hickson, Senior Vice President of NextEra Energy; all of whom are also officers of NextEra Energy Partners, as well as Eric Silagy, President and Chief Executive Officer of Florida Power and 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 new 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, www.nexteraenergy.com and www.nexterapartners.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 accompanying today's presentation for definitional information and reconciliations of certain non-GAAP measures to the closest GAAP financial measure. With that, I'll turn the call over to John.

Thank you, Amanda. Good morning, everyone. Before I begin my remarks on our third-quarter results, I would like to say a few words about Hurricane Matthew. As you know, residents of the Caribbean and Southeastern US were recently impacted by the severe effects of this dangerous and deadly storm. Our deepest sympathies are with those who have been impacted by Hurricane Matthew's widespread destruction.

Since 2006, FPL has invested more than $2 billion to build a stronger, smarter, and more storm-resilient energy grid. Earlier this month when Hurricane Matthew affected FPL's service territory along Florida's East Coast, these investments benefited customers by resulting in fewer outages and faster restoration. In response to the Hurricane, FPL deployed more resources pre-storm than ever before, which together with its grid investments, enabled the Company to restore service to 98.7% of the 1.2 million affected customers by the end of the second full day after the storm left our service territory.

At the height of restoration, FPL's workforce numbered 15,000, including our own employees along with workers from contracting companies and our partner utilities across the country. I would like to personally thank each member of this team for their dedicated service during this critical period for our customers.

In addition, earlier today, NextEra Energy announced that it has reached an agreement for an affiliate to merge with Texas Transmission Holdings Corporation, including TTHC's approximately 20% indirect interest in Oncor Electric Delivery, for total cash consideration of approximately $2.4 billion. In addition, we have reached agreement to acquire the remaining 0.22% interest in Oncor that is owned by Oncor Management Investment LLC, for total cash consideration of approximately $27 million. If approved, these transactions, when combined with NextEra Energy's previously announced merger with Energy Future Holdings for its 80% interest in Oncor, would result in NextEra Energy owning 100% of Oncor. I will provide additional details on this announcement after reviewing our financial results.

Turning now to our financial performance, both NextEra Energy and NextEra Energy Partners delivered strong third-quarter results. And building upon solid progress made in the first half of the year, we remain well-positioned to achieve our overall objectives for 2016. NextEra Energy's third-quarter adjusted earnings per share increased 9% from the prior-year comparable period, primarily reflecting contributions from continued investments at both Florida Power & Light and Energy Resources.

Equally as important, both principal businesses executed well on our major initiatives, and it was a period of continued advancement in our opportunity set for new renewables. At FPL, pursuing a balanced outcome in our base rate case to support continued execution of our successful strategy for customers remains a core focus. Since the last call we completed the technical hearing for the case. And after months of negotiation, we are pleased to have reached, with three interveners, what we believe is a fair and constructive long-term settlement agreement that will allow us to continue to focus on operating the business efficiently and reliably for the benefit of customers.

The one-day hearing was held last Thursday to consider the proposed settlement agreement. We expect the Florida Public Service Commission to vote on their agenda conference on November 29. Our major capital initiatives progressed well. And we were pleased to receive Commission approval on our proposal to acquire and phase out the Indiantown Cogeneration facility. I will provide additional details on these updates, as well as FPL's solid financial performance, during the third quarter in just a moment.

At Energy Resources contributions from new investments were the principal driver of growth. And our major activities remain on track to support delivery of roughly 2,500 megawatts of new contracted renewables projects in 2016. We continue to execute on our backlog and pursue additional contracted renewable development opportunities. And it was an excellent period of new project origination.

Since the last call, I am pleased to report that our development organization has added almost 2,000 megawatts of renewables projects for post-2016 delivery to our backlog, including approximately 600 megawatts of new wind projects and roughly 1,300 megawatts of additional repowering opportunities within Energy Resources' existing wind portfolio. We continue to conduct due diligence to identify the full opportunity set. And I will provide our latest thoughts on our expectations for repowering projects later in the call.

Energy Resources' continued ability to expand its pipeline of growth opportunities is expected to benefit NEP. Since the last call, NEP completed its third major acquisition this year from Energy Resources with the addition of an approximately 132-megawatt share of high-quality long-term contracted solar generation. We continue to believe that the scale, financial strength, experience, and track record of its best-in-class sponsor are what set NEP apart from other infrastructure alternatives. This acquisition is also another example of why NEP is important to NextEra Energy, as it highlights the value of the energy resources contractor renewables portfolio, enables the recycling of capital from operating assets back into development projects, and enhances NextEra Energy's tax efficiency.

NEP continued its strong year to date financial performance, delivering third-quarter adjusted EBITDA and cash available for distribution in line with our expectations. The NEP Board declared a quarterly distribution of $0.34125 per common unit, or $1.365 per common unit on an annualized basis, up 26% from a year earlier. Overall, with three strong quarters now behind us, we are well-positioned for the year and are very pleased with the progress we're making at the both NEE and NEP.

Now let's look at the detailed results, beginning with FPL. For the third quarter of 2016 FPL reported net income of $515 million and earnings per share of $1.11, up $0.04 per share year over year. Regulatory capital employed increased by 8.6% over the same quarter last year, and was the principal driver of FPL's net income growth.

Our reported ROE for regulatory purposes will be approximately 11.5% for the 12 months ended September 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. We ended the second quarter of 2016 with a balance of $71 million, and due to higher base revenues driven by weather-related usage and customer growth, we reversed $159 million of reserve amortization in the third quarter.

We believe the remaining reserve amortization balance of $230 million, coupled with our current CapEx and O&M expectations, will allow us to support a year-end regulatory ROE of 11.5%, which is the upper end of the current allowed range. Based on what we see right now we are likely to end the year with a positive reserve amortization balance which, under the terms of the proposed 2016 rate agreement, we will be able to utilize over the next four years.

Earlier this month we were pleased to receive approval from the Florida Public Service Commission on our proposal to acquire and phase out the Indiantown Cogeneration facility, a 330-megawatt coal-fired power plant that has a contract to supply capacity and energy to FPL through 2025. With an expecting -- expect a closing date for the transaction in early 2017, we plan to purchase the ownership interest in the facility for $451 million, including existing debt. Similar to the acquisition of Cedar Bay that we closed in the third quarter of 2015, the transaction is expected to enable early retirement of one of the highest greenhouse gas emitting power plants in the state while also providing estimated customer savings of $129 million.

In addition, construction has continued to progress well on FPL's three 74.5 megawatt utility-scale solar PV projects that we expect to enter service this year. During the quarter we were pleased to announce the completed installation of half of the 1 million new solar panels that will comprise these new solar energy centers. Once complete these projects will roughly triple the solar capacity on FPL's system and add to the overall fuel diversity of our fleet, which is important for FPL and its customers.

Consistent with our commitment to provide low bills and clean energy solutions for the benefit of Florida customers, the proposed 2016 rate agreement, if approved, allows FPL to recover in rates up to an incremental 1,200 megawatts of cost-effective new solar generation approved over the four-year term of 2017 through 2020. This would allow Florida customers to benefit from favorable tax incentives, cost declines, and efficiency improvements in solar technology that, together, make universal solar a cost effective source of energy for our customers.

The Florida economy remains healthy. The state's seasonally adjusted unemployment rate of 4.7% is below the national rate. And Florida's annual job growth rate has exceeded the nation's rate since 2012. The latest readings of Florida's consumer sentiment have remained close to post-recession highs. FPL's third-quarter retail sales increased 4% from the prior-year comparable period. And we estimate that approximately 3.2% of this amount can be attributed to weather-related usage per customer.

On a weather-normalized basis, third quarter sales increased 0.8%. Continued customer growth of approximately 1.4% was partially offset by a decline of 0.6% and weather-normalized usage per customer. Looking ahead we expect year-over-year weather-normalized usage per customer to average between 0% and negative 0.5% per year for the foreseeable future.

FPL was impacted by Hurricane Hermine in September 2016 and Hurricane Matthew in October 2016. Although FPL has not completed the final accounting, our preliminary estimate of storm restoration cost is currently approximately $350 million. Prior to the storms, FPL's storm and property insurance reserve had the capacity to absorb approximately $112 million in additional storm restoration costs. The remaining balance of the storm restoration costs not covered by the reserve will be deferred and recorded as a regulatory asset on FPL's balance sheet.

Under the 2012 rate agreement, beginning 60 days following the filing of a cost recovery petition with the FPSC, FPL is authorized to recover the remaining balance of the storm restoration costs on an interim basis from customers through surcharges, plus an additional $117 million to replenish the reserve to the level authorized by the 2012 rate agreement.

Interim recovery is available for costs that in total for the calendar year do not exceed $4 for every 1,000 kilowatt hours of usage on monthly residential bills based on a 12-month recovery period. FPL intends to file a petition with the FPSC in the fourth quarter of 2016 to seek interim recovery of storm restoration costs under this mechanism.

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. The proceeding has encompassed an extensive evidentiary process. And during the quarter, we completed the technical hearing for the case, and subsequently submitted our post-hearing brief in mid-September.

After months of negotiation, we reached a proposed settlement agreement in early October with three of the interveners in the proceeding: the Office of Public Counsel, the South Florida Hospital and Healthcare Association, and the Florida Retail Federation. The four-year proposed agreement beginning January 2017 and ending December 2020 provides for retail-based revenue adjustments, as shown in the accompanying slide, and an allowed regulatory return on equity of 10.55%, with a range of 9.6% to 11.6%, and no change to our equity ratio from investor sources.

The proposed agreement also includes the flexibility over the four-year term to amortize up to $1 billion of depreciation reserve surplus, plus any reserve amount remaining at the end of this year under FPL's 2012 rate agreement. As I mentioned earlier, the proposed agreement also provides for solar-based rate adjustments, or SoBRA, upon commercial operations of to 300 megawatts annually of new solar generation, subject to a cost cap of $1,750 per kilowatt and a showing of overall cost effectiveness for FPL's customers.

We expect our regulatory capital employed to be consistent with our rate case filing plus any incremental solar investment opportunities we move forward with under the SoBRA if approved by the Commission. Under the proposed agreement, FPL would continue to recover prudently incurred storm costs consistent with the framework in the current settlement agreement.

Future storm restoration costs would be recoverable on an interim basis beginning 60 days from the filing of a cost recovery petition, but capped at an amount that could produce a surcharge of no more than $4 for every 1,000 kilowatt hours of usage on residential bills during the 12 months of cost recovery. Any additional costs would be eligible for recovery in subsequent years. If storm restoration costs were to exceed $800 million in any given calendar year, FPL could request an increase to the $4 surcharge to recover the amount above $400 million.

The proposed agreement also authorizes a continuation, with minor modification, of the incentive mechanism for sharing with customers the gains that we achieve in excess of a threshold amount for our gas and power optimization activities, and introduces a 50-megawatt battery storage pilot program designed to enhance service for customers or operations of solar facilities. FPL has agreed to not seek incremental recovery of the revenue requirements associated with the battery storage pilot program until its next general base rate case. We believe the proposed settlement is fair, balanced, and constructive, and supports our continued ability to provide clean, highly reliable, low-cost service for our customers through the end of the decade.

Let me now turn to Energy Resources which reported third-quarter 2016 GAAP earnings of $307 million, or $0.66 per share. Adjusted earnings for the third quarter were $279 million, or $0.60 per share. Energy Resources' contribution to third-quarter adjusted earnings per share increased $0.11, or approximately 22%, from the prior-year comparable period.

New investments added $0.27 per share, including $0.14 from continued growth in our contracted renewables portfolio. Contributions from new investments in natural gas pipelines were $0.13 per share, including a positive $0.09 impact resulting from a reduction in the contingent earn-out liability that was recorded as part of the Texas pipeline acquisition last year.

The earn-out, which was originally recorded at roughly $200 million, is required to be paid if contracts for growth projects on the NET Mexico pipeline are signed by December 31, 2016 and if those expansion projects meet several precedent conditions. Recently, NET Mexico completed a nonbinding open season. While the results of that open season were encouraging in terms of capacity expansion on the pipeline, we are still in the process of evaluating the responses and are having discussions with potential shippers over preceding agreements.

However, based on the information we have to date, we no longer believe that the full $200 million will be payable. We will have a more detailed update in the fourth quarter earnings call as we move forward to sign agreements with the parties that have expressed an interest in new capacity.

The NET Mexico pipeline remains well-positioned, as it has one of the lowest capacity payments of any pipe serving the growing Mexican market from the US. We remain confident that the Texas pipeline's asset, which is owned by NEP, will deliver on its adjusted EBITDA and CAPD growth expectations that we outlined at the time of the acquisition.

Partially offsetting the positive contribution from natural gas pipelines was a $0.09 per share decline in contributions from our upstream gas infrastructure activities, primarily due to lower commodity prices and increased depreciation expense reflecting higher depletion rates. On an annual basis we would expect the $0.09 to be roughly $0.15 for the full year 2016.

The contribution from existing generation assets declined by $0.02 per share, partly reflecting the sale of Lamar and Forney natural gas generation assets early in the year net of interest expense. Fleetwide wind resource was 100% of the long-term average during the quarter. All other impacts reduced results by $0.05 per share, including the effects of increased interest expense reflecting continued growth from the business and share dilution.

We remain enthusiastic about the fundamentals for North American renewables growth driven by the continued execution of our development organization together with our purchasing power, scale and operations, strong access to capital, and cost of capital advantages. As you may recall, the action taken by Congress in December 2015 to extend the wind PTC over a five-year phase-down period was further enhanced earlier this year by our IRS guidance on start of construction.

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

Following our announcement on the last call that we are pursuing repowering opportunities at two of our existing Texas wind projects, the team has continued to conduct due diligence on our existing portfolio. As I mentioned earlier, today we are announcing plans to pursue additional repowering opportunities for roughly 1,300 megawatts to be completed in the 2017/2018 timeframe. We expect to invest approximately $875 million of capital to complete these repowering projects. Earnings from the projects are excited to be comparable to similar new-build opportunities with significantly less capital investment.

Based on everything we see now, and inclusive of today's announcement and the announcement from our last call, we expect this opportunity set to continue to grow to support a total of at least $2 billion to $2.5 billion of capital deployment opportunities for repowerings over the next four years, with a greater portion of incremental opportunities expected to become actionable beyond 2018.

In addition to our plans to repower certain of our existing wind generation facilities, I am also pleased to report continued strong customer demand for wind. Since the last call we signed contracts for roughly 600 megawatts of new wind projects, including approximately 500 megawatts for post-2018 delivery. The attached chart updates additional details on where our renewables development program now stands.

Together with the repowering opportunities that I just mentioned, we remain comfortable with the overall ranges we have discussed for 2017 and 2018. The development activities for our natural gas pipelines remain on track. The Florida pipelines received FERC notice to proceed in August, and have commenced full construction activities. We continue to expect an in-service date in mid-2017.

As a reminder, NextEra Energy's investments in Sabal Trail transmission and Florida Southeastern 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 has continued to progress through the FERC process. We continue to expect approximately 2 BCF per day at 20-year firm capacity commitments to achieve commercial operations by year-end 2018. NextEra Energy's expected investment is roughly $1 billion.

Let me now review the highlights for NEP. Third-quarter adjusted EBITDA and cash available for distribution were $174 million and $51 million, respectively. And strong contributions from new assets remain the principal driver of growth from the prior-year comparable period. In addition, existing assets benefited from a favorable year-over-year comparison of overall wind and solar resource. As a reminder, these results are net of IDR fees, which we treat as an operating expense. IDR fees increased $10 million from the prior-year comparable quarter.

NEP has executed well against its growth objectives, highlighted by strong access to equity and debt markets. During September, NEP was able to sell to the underwriters at the time of the announcement the full block of limited partnership units to be issued in connection with the acquisition of a partial interest in the Desert Sunlight Solar Energy Center. This issuance, which raised approximately $297 million, was completed at a lower operating discount and lower trade yield than the prior February offering, and demonstrated yet another source of capital for NEP, as we were able to access the retail market for approximately 75% of the issuance.

In late September the underwriters exercised the over-allotment option, which allowed NEP to raise another $45 million. NEP continues to target a long-term capital structure utilizing HoldCo leverage of approximately 3.5 times project distributions after project debt service. And based on this metric, we estimate our current incremental HoldCo debt capacity to be roughly $450 million to $500 million. Looking ahead, together with our at-the-market dribble program, we expect this debt capacity to allow NEP 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 third quarter of 2016 GAAP net income attributable to NextEra Energy was $753 million, or $1.62 per share. NextEra Energy's 2016 third-quarter adjusted earnings and adjusted EPS were $809 million and $1.74 per share, respectively. Adjusted earnings from the corporate and other segment decreased $0.01 per share compared to the third quarter of 2015.

As I mentioned in my opening remarks, earlier today NextEra Energy announced it has reached an agreement for an affiliate to merge with Texas Transmission Holdings Corporation, including TTHC's approximately 20% indirect interest in Oncor Electric Delivery, for merger consideration of approximately $2.4 billion. In addition, we have reached agreement to acquire the remaining 0.22% interest in Oncor that is owned by Oncor Management Investment LLC for total cash consideration of approximately $27 million.

If approved, these transactions, when combined with NextEra Energy's previously announced transaction with Energy Future Holdings for its 80% interest in Oncor, would result in NextEra Energy owning 100% of Oncor. The total transaction consideration implies an enterprise value for Oncor of $18.7 billion.

Under the terms of the TTHC merger agreement, NextEra Energy will pay TTHC 100% of the merger consideration in cash. As a result of the transaction, no debt will reside at TTHC or Texas Transmission Investment upon close of the merger.

We expect to fund the merger consideration through a combination of debt and equity consistent with our commitment to maintaining NextEras Energy's strong balance sheet and credit ratings. We believe the transaction further affirms NextEra Energy's commitment to Oncor, its customers, and the State of Texas.

As a reminder, NextEra Energy previously announced on July 29 a proposed transaction with Energy Future Holdings that would result in NextEra Energy owning approximately 80% of Oncor electric delivery. The definitive agreement is part of an overall plan of reorganization designed to allow Energy Future Holdings to emerge from Chapter 11 bankruptcy.

During the quarter, the United States Bankruptcy Court for the District of Delaware approved EFH's entry into the merger agreement. And we were also pleased to achieve additional credit support for the EFH transaction. Although there is inherent uncertainty involved with the bankruptcy process, we currently expect a creditor vote and confirmation hearing in the fourth quarter in order to be in a position to receive bankruptcy court confirmation of the plan of reorganization by the end of the year.

Separate from the bankruptcy approval process, together with Oncor we look forward to filing by November 1 our joint application with the Public Utility Commission of Texas seeking approval of our proposed acquisition. Based on our current targets for completing key milestones, and subject to required approvals, we expect the transactions to close in the first half of 2017.

If approved, the transactions with EFH, TTHC and OMI, which would result in NextEra Energy owning 100% of Oncor, are expected to be meaningfully accretive to earnings, enabling NextEra Energy to grow at or near the top end of its previously announced 6% to 8% per year adjusted earnings per share growth rate through 2018 off the 2014 base. Through the transactions we see an opportunity to make two already great companies even stronger. In addition, we expect that Oncor's credit rating will be improved postclosing, generating real savings for customers in terms of lower borrowing costs.

NextEra shares Oncor's commitment to providing affordable and reliable electric service and providing high-quality customer service for the benefit of Oncor's customers and the continued economic growth of the state. We believe the transactions are beneficial for all key stakeholders, including the State of Texas and Oncor's customers, the creditors of the EFH bankruptcy estate, and NextEra Energy?s shareholders.

Setting aside the potential for accretion that we see with our proposed Oncor transaction, we continue to expect 2018 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 our 2014 base of 6% to 8%. In addition, we continue to expect to grow our dividends per share 12% to 14% per year for at least 2018 off a 2015 base of dividends per share of $3.08.

For this year, we continue to expect 2016 adjusted earnings per share at NextEra Energy to be in the range of $5.85 to $6.35. Within this range it is worth noting that we believe that we are well positioned to achieve results for 2016 towards the top end of our 6% to 8% per year adjusted earnings per share expectations, again off our 2014 base of $5.30.

We hope to be in a position to provide longer-term expectations at an investor conference this spring following the resolution of the FPL rate proceeding and required milestones in the Oncor approval process. As always, our expectations are subject to the usual caveats, including, but not limited to, normal weather and operating conditions.

Let me now turn to NEP. 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 and 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.

The December 31, 2016 run rate expectation for adjusted EBITDA of $670 million to $760 million and CAFD of $230 million to $290 million are unchanged, reflecting calendar year 2017 expectations for the forecasted portfolio at year-end December 31, 2016. Today we are introducing December 31, 2017 run rate expectations for adjusted EBITDA of $875 million to $975 million and CAFD of $310 million to $340 million, reflecting calendar year 2018 expectations for the forecasted portfolio at year-end December 31, 2017.

The midpoint of this CAFD range reflects roughly 25% growth from the comparable CAFD midpoint, based on our December 31, 2016, run rate expectations. Our expectations are subject to our normal caveats and are net of anticipated IDR fees, as we expect these fees to be treated as an operating expense.

In summary, both NEE and NEP delivered excellent third-quarter results. And we are pleased with the progress we have made on all of our major initiatives. At FPL we continue to focus on operational cost effectiveness, productivity, and making long-term investments to further improve the quality, reliability, and efficiency of everything we do. At Energy Resources we have made terrific progress on our development program, and continue to feel optimistic about our renewables growth prospects and the quality of our renewables pipeline.

For NEP, renewable origination success at Energy Resources continues to expand the pipeline of potential drop-down assets. And NEP has excess debt capacity to enable us to be flexible and opportunistic regarding future growth. Overall, we continue to believe that we have one of the best opportunity sets and execution track records in our industry.

That concludes our prepared remarks. And with that, we will open the line for questions.

Thank you.

(Operator Instructions)

Stephen Byrd, Morgan Stanley.

Hi. Good morning.

Good morning, Stephen.

So wanted to touch on what you, John, had mentioned about re-powering opportunities. Very pleased to see the magnitude of that. I just wanted to make sure I understood your commentary correctly. You were indicating that essentially the capital cost would be lower than the new-build, which certainly makes sense. But the return would be essentially as if it were at new-build investment levels. So therefore, it looks like a relatively attractive return on capital. Did I get that right?

You got that right. So the CapEx is roughly half of a new-build and the return is superior to a new-build transaction.

Okay. Great. And in terms of just the kinds of steps you need to go through to actually get these re-powerings done, how should we think about execution risk, counterparty negotiations? How much is required in terms of counterparty negotiations? What sort of things should we be thinking about in terms of execution risk?

Well, on the execution side, we have to negotiate with our counterparties. Some of those counterparty negotiations will include a blend and extend of the existing agreement. But given that the CapEx is, again, roughly half of the CapEx for a new-build and the returns are a bit higher, there is a little bit of room for those negotiations with counterparties.

That is one of the main execution risks that we have. We also have to study the interconnection agreements to make sure that to the extent we are providing additional capacity that we have the ability to put that additional capacity online. Those are the main execution risks around the re-powering opportunities.

Okay. Understood. And you are laying out $2 billion to $2.5 billion of capital deployment opportunity so we can sort of do the math to look at the total megawatts involved, then, I guess.

That is correct.

Okay. Sorry, and just one last question and I'll get back in queue. We have seen a number of companies announce their interest in becoming big in wind. We saw one company this morning lay that out.

I am just curious if you could, at a high level, speak to competitive trends you are seeing? The kinds of barriers to entry that you see from your perspective, given you have been one of the biggest players in wind for a very long time. I'm interested in your perspective on that.

Sure, Stephen. I'm going to the question over to Jim.

So Stephen, we've had competitors in this business for 15 years. They have come, they've gone. There is no one in this industry that has the greenfield capabilities that we do. Plenty of folks lay out the fact that they want to be in the wind business. And really what they are in is they're in the wind development project acquisition business at COD, which is, frankly, not really being in the wind business.

Being in the wind business, 70% or 80% of the value creation is the organic development, the greenfield development of those projects. And there's no one in the industry that has the pipeline that we do, that has the team that we do, and the year in and the year out track record. I worry about a lot of things, and that is like, very, very low on my list of things that I worry about.

That is great. Thank you very much.

Matt Tucker, KeyBanc Capital Markets.

Good morning. Thank you for taking my questions.

Good morning, Matt.

Wanted to ask a few questions about the HoldCo debt capacity at NEP. I guess, first, just curious, what kind of changed since you provided an estimate -- I think when you announced Desert Sunlight that was about $75 million lower. I appreciate the math illustration you provided in the slides, but still wasn't clear what changed there.

And then just how should we be thinking about how you are going to look to utilize this debt capacity? Is the target something that you'd look to reach over the next 12 to 18 months, or the next few transactions? Or how much cushion would you like to kind of leave there for potential periods where you really do not feel like you can access equity and want to continue to make acquisitions?

Yes. So a few things. On the HoldCo debt capacity, remember that we financed our July drop-down with largely debt. We then went ahead and equitized the September drop. The cash purchase price for Desert Sunlight was $218 million. We raised about $341 million in equity, which allowed us to pay down our revolver. That really was the main contribution to the additional HoldCo debt capacity to get us to $450 million to $550 million.

In terms of the cushion on debt capacity, I really think that puts us in an opportunistic and flexible position as to how we time future drop-down opportunities and as to how we finance those opportunities. So we will see how things progress in terms of the capital markets going forward. But that does give us flexibility.

Also, you've got to remember with wind assets, when we drop the wind assets in, you can think about the leverage from tax equity being right around 45% to 55%. So we're dropping those assets down. They are naturally creating additional HoldCo debt capacity at the NEP level.

Thanks. That is very helpful. And then, lastly, just your thoughts on the current wind outlook. Are we completely past El Nino? Are we seeing La Nina? Just what are you seeing over the next 6 to 12 months, or however far your outlook goes?

It's tough to look out 12 months and really come up with what an accurate forecast might look like. But certainly, we saw a return to normal with our third-quarter results. So we will see how the fourth quarter progresses.

Thanks, guys.

(Operator Instructions)

Jonathan Arnold, Deutsche Bank.

Good morning, guys.

Good morning, Jonathan.

Two quick questions. One, on the new contracted wind that is not re-powerings, I noticed the 100 megawatts in 2017 and 2018 and then 500 is post 2018. Should we anticipate that most of what you do on the backlog is going to be longer dated going forward here? Or is that just sort of the nature of some of these deals you signed this quarter, because I know you talked about being unsure whether tax credit extensions were going to push things a little bit out?

Hey, Jonathan. It's Armando. I would not read too much into that. It is just really the pace and negotiations. What I can say is that there is a lot of activity going on right now for both 2017 and 2018, and 2019 and 2020 in the contracting market. We were -- these two came in kind of at the right time for 2019. But I would not read too much into that, other than just timing.

There are -- you have got irons in the fire still for 2017, 2018, it's fair to say?

Yes, absolutely. We still feel comfortable with the guidance, or the expectations that we have provided to you and we reaffirm today for 2017, 2018.

Great. And then just, we have -- you obviously had a strong third quarter. Last time you spoke publicly, I think you were talking down the second half a little bit versus the first half in terms of growth. And we have you at about [$617 million] trailing [12-month] earnings. And I was curious while the guidance range, you did not take up the low end? Or is this -- are there are some challenges in Q4 that we should be thinking about, or are you -- it feels like you're tracking pretty well on the -- .

Yes, Jonathan. We did have a good third quarter. But with the fourth quarter, we still do expect the growth to drop off a bit compared to what we saw with 2015. And we are targeting again to be at the upper end of our 6% to 8% range, is the way to think about how we will finish the fourth quarter and the full year.

Okay. So you talked about some tax-timing issues in the second half. Is that more a Q4 item, then, or is that still -- ?

There were some tax-timing issues that had benefited the earlier part of the year. That is a part of it. There are some other smaller things as well; not any one thing worth calling out or mentioning.

All right. I think that does it. Thank you.

Colin Rusch, Oppenheimer.

Thanks so much. I've got two questions. Can you just give us a bit more detail on what is in that receivable due from a related party at NEP? And then, secondly, with the wind re-powering opportunity, given the pretty dramatic price declines on battery storage with companies like LG and Tesla offering installations below $400 a kilowatt hour now, how are you seeing that opportunity change? And is there a meaningful avoided cost PPA opportunity that you guys are seeing right now?

Yes. On the due-from-related party for NEP, recall that NextEra Energy provides credit support to NEP. But as part of that credit support arrangement, NextEra Energy has the right to benefit from the cash sweeps by taking cash out of those accounts, which it has an obligation to put back in for the benefit of NEP. So that is what the due-from-related parties is. On the battery question, I will defer to Armando.

We have been talking about batteries now, I think, for a couple of years. And we keep saying that we would expect batteries to be a significant investment opportunity for us sometime earlier in the next decade. And it is tracking based on where we thought our expectations would be.

We have roughly, currently -- boy, I am going to say about 10 projects -- 10 battery projects across the US and Canada. A little bit different technology in each one. But these are fairly small investments that we are making in battery storage. Somewhere in the neighborhood of $6 million to $15 million is a potential average for each one of those investments.

Whether it is Tesla, as you mentioned, or whether it is other estimates that you and us have seen, I mean, battery storage will continue to come down significantly through this decade. And we continue to believe that at some point in the next decade, I do not know whether it will be earlier or whether it will be later, but battery storage will be commercially viable. The cost will come down enough that you will be able to strap it on with renewable technology, whether it is wind or more likely solar, and have a very competitive project in the renewable energy space.

Okay. Great. I will take the rest of it offline. Thanks, guys.

Angie Storozynski, Macquarie.

Thank you. So I have one follow-up on the re-powering. So how does the 50% reduction of CapEx versus new-build reconcile with this IRS requirement that it's an 80% increase in the value of the turbine?

You cannot do that reconciliation, Angie. It is Armando. The way that the 80/20 works is, obviously, for others on the phone, if you were to go out and completely tear down a wind project and start over, you would get PTCs on the new investment.

The IRS guidance allows you to do a whole bunch of work on those wind projects. And 80% of the value that you are putting in, if you meet the 80% test, the entire investment qualifies as new production tax credits. It is based on a fair value method, though, not based on a cost method.

So when John answered the question before that it is a lot less capital for re-powering opportunities and the economic returns are just as good or better, he was talking about the cost that was going into the wind project, not about the 80/20 test.

Angie, this is Jim. Simply said, it's not 80% of the new-build cost. It is 80% of whatever you think the value of the existing asset is, and the existing asset's been typically depreciated by 10 or 11 or 12 years. So it's -- what you're trying to do is apples and oranges.

Okay. And then, all of the projects that are going to be re-powered or are considered re-powering targets have PPAs. So there would be no merchant re-powering?

Actually, Angie, all of the projects that we announced today that we are moving forward on on the re-powering side are all projects that we have long-term hedges on. We have not announced any re-powerings of projects that have power purchase agreements. So when John mentioned that our expectation that this could be a $2 billion to $2.5 billion program, virtually all of the remaining opportunities that we are looking at are under power purchase agreements, and, therefore, we would have to have discussions with the counterparties, as John mentioned earlier, to make sure that we can move forward on those. I feel comfortable that we would move forward on a vast majority of those. And that is why we gave CapEx guidance on the total program today.

Okay. Thank you. And last question on NEP. So I understand that you have the corporate capacity you can use to finance growth. But as you are the only one, really, with active IDRs [along with deal codes]. And those IDRs require simply more and more assets to be dropped down in order to mute this 12% to 15% growth in distributions per share for LP holders. And as such, basically, your funding requirements are growing quite considerably as you move to higher spreads. Would you consider, instead, doing away with the IDRs in case there is no recovery and no liquidity in the YieldCo market on the equity side? Or do you feel like between co-financing by NextEra or private placements you can actually place enough equity to achieve the growth and pay IDRs?

Angie, the way we look at it, I think the first thing to look at when you are dealing with a YieldCo like ours with a strong sponsor is how many projects -- what is the pipeline at the sponsor to be able to drop down projects? Do have a long pipeline of opportunities to be able to drop down into, in this case, NextEra Energy Partners? Because if you have that, the current economics certainly work.

There are -- you talked about HoldCo debt capacity at the beginning of your discussion. I hope it's clear; I think we have made it clear that we will not be reaching at least our preliminary HoldCo debt capacity target in 2017. We are slowly increasing the debt capacity of NextEra Energy Partners. So by the end of 2018, at least preliminarily, we believe that we would get to the HoldCo debt capacity which gives us in this market a tremendous amount of flexibility as to when to be able to raise equity and when to be able to raise additional HoldCo debt capacity.

I think it's just too early in the life of NextEra Energy Partners to really start talking about what we are going to do in the future with IDRs. We feel comfortable with the way NextEra Energy Partners is working right now. It brings a lot of benefits to NextEra Energy. We're certainly not comfortable with where it is trading. I do not think any management team is ever comfortable with where their units are trading.

But we feel confident that we at NextEra Energy will be able to have a sufficient number of projects for a sufficient number of time in order for NextEra Energy Partners to be successful long term.

Great. Thank you.

Stephen Byrd, Morgan Stanley.

Yes. I just had one follow-up. In terms of the market for tax equity and tax appetite, I wondered if you just give a commentary in terms of high-level overall access, your position there, just your take on the state of monetizing tax attributes?

We have seen the tax equity market for our projects continue to hang in there, Stephen. We have seen no issues. One of the things that we try to do going into any one year is estimate the amount of tax equity needs that we will have. And then we allocate those to our tax equity providers going into the year. So really, it has not been an issue for us with regard to our projects.

Thank you.

And with no further questions in the queue, that does conclude today's presentation. Thank you for your participation. You may now disconnect.