新世紀能源 (NEE) 2017 Q3 法說會逐字稿

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

Today's conference is being recorded.

At this time, for opening remarks, I'd like to turn the call over to Mr. Matthew Roskot.

Please go ahead, sir.

Thank you, Laurie.

Good morning, everyone, and thank you for joining our Third Quarter 2017 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, Executive 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 & 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 website, 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 accompanying today's presentation for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure.

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

Thank you, Matt, and good morning, everyone.

Before I begin my remarks on the third quarter results, I would like to say a few words about the 2017 hurricanes.

As you know, residents of the Caribbean and Southern U.S. were recently impacted by the dangerous and deadly effects of hurricanes Harvey, Irma, Maria and Nate.

Our deepest sympathies are with those who have been affected by any of these storms with widespread destruction.

Hurricane Irma was the largest hurricane event Florida Power & Light has ever faced.

The powerful storm impacted all 35 counties and 27,000 square miles of FPL service territory, causing more than 4.4 million customers to lose power.

In preparation for the hurricane, FPL assembled and prepositioned the largest restoration workforce in U.S. history, which grew to approximately 28,000 at its peak.

This preparation and coordinated response, combined with the hardening and automation investments that FPL has made since 2006 to build a stronger, smarter and more storm-resilient energy grid, enabled the company to restore service to over 2 million customers in 1 day and to complete the restoration of all 4.4 million customers in 10 days.

The efforts of our team resulted in the fastest restoration of the largest amount of people by any one utility in U.S. history.

Mutual aid in times of disaster is one of the hallmarks of our industry, and this storm was no exception.

We are deeply grateful for the assistance provided by our industry partners.

I would also like to personally thank each member of the restoration team as well as the contractors, vendors and first responders that supported our efforts for their dedicated assistance during this critical time for our customers.

To put Hurricane Irma in context, it's useful to compare it to Hurricane Wilma from 2005, which, prior to Irma, was the storm that affected the largest number of FPL customers.

Unlike Hurricane Irma, which made landfall in Florida as a Category 4 storm and affected the entire state, Hurricane Wilma was a Category 3 storm, whose primary impacts were to the southern half of the Florida peninsula.

Based upon a methodology developed by the National Center for Atmospheric Research, Hurricane Irma had an approximately 50% higher damage potential than hurricane Wilma and resulted in over 90% of FPL customers losing power compared to 75% for Hurricane Wilma.

Notwithstanding the fact that Hurricane Irma was a much stronger storm impacting a larger portion of FPL service territory, there was an approximately 80% reduction to pole damage and an 80% improvement in the time to energize all substations following the storm when compared to Hurricane Wilma.

After day 1, FPL had 50% of its customers restored, also an 80% improvement compared to the Wilma restoration efforts.

In fact, 95% of customers impacted by Irma were restored in 1 week.

And while the average customer outage from Hurricane Wilma lasted for over 5 days, the average outage for customers affected by Hurricane Irma was roughly 2 days, a 60% improvement.

The total GDP within our service territory averages over $1 billion per day.

By reducing the average customer outage by more than 3 days when compared to Wilma, we believe the avoided economic loss to the state has more than paid for the $3 billion in hardening investments we have made since 2006.

Given the size and scale of this hurricane, the Florida Public Service Commission has opened a docket to solicit customer comments and to take evidence on the statewide utility response to Irma, including an analysis of the impact prior hardening activities had on restoration efforts.

We believe that the improvement in FPL storm restoration efforts shows that our ongoing transmission and distribution investments, together with our preparation and coordinated response, are providing significant value to our customers.

In an effort to mitigate a significant bill impact for our customers related to the cost recovery for Hurricane Irma, we currently expect to propose a surcharge equivalent to $4 on a 1,000 kilowatt-hour residential bill beginning in March of 2018, which equates to a step-up of $0.64 from a surcharge related to Hurricane Matthew that rolls off at that time.

Subject to review and prudent determination of our final storm cost by the Florida Public Service Commission, which are preliminarily estimated to be approximately $1.3 billion, we expect the surcharge to increase by roughly $1.50 to approximately $5.50 per month in 2019 and stay at that level until the storm costs are fully recovered, which is expected by the end of 2020.

Turning now to our financial performance.

NextEra Energy delivered solid third quarter results, and building upon strong progress made in the first half of the year remains well positioned to achieve our overall objectives for 2017.

NextEra Energy's third quarter adjusted earnings per share increased by $0.11 or 6.3% against the prior year quarter, primary reflecting contributions from new investments at both Florida Power & Light and Energy Resources.

Year-to-date, we have grown adjusted earnings per share by 9.2% compared to the prior year comparable period.

We also executed well on major initiatives, including continuing to capitalize on one of the best renewal development periods in our history.

At Florida Power & Light, earnings per share increased $0.08 from the prior year comparable quarter.

Strong growth was driven by continued investment in the business to maintain our best-in-class customer value proposition of clean energy, low bills, high reliability and outstanding customer service.

We earned a regulatory ROE of approximately 11.5%, and average regulatory capital employed grew roughly 9.8% over the same quarter last year.

All of our major capital initiatives remain on track, including the 1,750-megawatt Okeechobee Clean Energy Center and construction of the 874.5-megawatt solar energy centers that are currently being built under the Solar Base Rate Adjustment or SoBRA mechanism of the rate case settlement agreement.

We were also pleased that the Florida Public Service Commission approved a settlement agreement with the Office of Public Counsel for the early phaseout of the St.

Johns River Power Park, helping to further reduce costs for FPL customers and lower emissions for Florida residents.

At Energy Resources, adjusted EPS increased by roughly 3% year-over-year as contributions from new investments more than offset a negative contribution from our existing assets as a result of poor fleet-wide wind resource, which was the lowest on record for the months of July through September over the past 30 years.

Following the success of recent quarters, it was another excellent period of new project origination.

Since the last call, our development organization has added 760 megawatts of long-term contracted projects to our backlog, including the largest announced combined solar plus storage project in the United States.

This continued cost and efficiency improvements in wind and solar technology support compelling renewable economics that remain the primary driver of ongoing customer origination activity.

Energy Resources continue to advance our wind repowering program as well, adding 514 megawatts to our repowering backlog for 2018 delivery.

We also commissioned more than 300 megawatts of repowering projects and closed the first tax equity financing for our wind repowering portfolio.

Finally, we were pleased to receive the FERC certificate for MVP and look forward to advancing construction activities to support a year-end 2018 commercial operation date.

Overall, with 3 strong quarters complete in 2017, we are pleased with the progress we are making at NextEra Energy and are well positioned to achieve the full year financial expectations that we have previously discussed, subject to our usual caveats.

Now let's look at the detailed results beginning with FPL.

For the third quarter of 2017, FPL reported net income of $566 million or $1.19 per share, an increase of $51 million and $0.08 per share, respectively, year-over-year.

Regulatory capital employed increased by approximately 9.8% over the same quarter last year and was a principal driver of FPL's net income growth of 9.9%.

FPL's capital expenditures were approximately $1 billion in the third quarter, and we continue to expect our full year capital investments to total between $5 billion and $5.4 billion.

Our reported ROE for regulatory purposes will be approximately 11.5% for the 12 months ended September 2017.

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 third quarter, we reversed $124 million of reserve amortization after offsetting the impacts of Hurricane Irma, leaving us with a balance of roughly $1.15 billion, which can be utilized over the remainder of our settlement agreement.

We continue to expect the flexibility provided by the utilization of our reserve amortization, coupled with our weather-normalized sales forecast and current CapEx and O&M expectations, to support our target regulatory ROE of 11.5% for the full year 2017, which is at the upper end of the allowed band of 9.6% to 11.6% under our current settlement agreement.

Each of our ongoing capital deployment initiatives continues to progress well as we focus on delivering our best-in-class customer value proposition.

Construction on the approximately 1,750-megawatt Okeechobee Clean Energy Center remains on schedule and under budget.

The 8 solar sites totaling nearly 600 megawatts of combined capacity are currently being built across FPL service territory, and they're all on track and on budget to begin providing cost-effective energy to FPL customers later this year and in early 2018.

We also continue to advance the development of the additional 1,600 megawatts of solar projects that are planned for beyond 2018 and have currently, secured potential sites that could support more than 5 gigawatts of FPL's ongoing solar expansion.

Last month, the Florida Public Service Commission approved the settlement agreement between FPL and the Office of Public Counsel, the consumer advocate in Florida, regarding FPL's proposal for the early shutdown of the St.

Johns River Power Park, an approximately 1,300-megawatt coal-fired plant jointly owned with JEA.

The early retirement of the plant, which is expected in January 2018, is projected to provide total savings to FPL customers of $183 million and prevent nearly 5.6 million tons of carbon dioxide emissions annually, adding to the customer savings and emission reductions of our Cedar Bay and Indiantown transactions.

Earlier this month, we filed a determination of need with the FPSC for the roughly 1,200-megawatt highly efficient, clean-burning natural gas Dania Beach Clean Energy Center.

The project, which has a total expected capital investment of approximately $900 million, is a modernization of our existing Lauderdale plant and is expected to begin operation by mid-2022.

Consistent with our focus on low bills, we estimate that the facility will generate more than $335 million in net cost savings for FPL customers over its operational life.

Finally, we were pleased that earlier in the week, the City of Vero Beach City Council approved FPL's purchase of substantially all of the assets of the municipal electric system for approximately $185 million.

We are continuing to work on the remaining necessary approvals and hope to be in a position to close the transaction in late 2018.

If we are successful, we look forward to Vero Beach's roughly 34,000 customers benefiting from FPL's best-in-class customer value proposition, including rates that are among the lowest in the state.

Despite the effects of Hurricane Irma, the Florida economy remains strong.

Florida's seasonally adjusted unemployment rate was 3.8% in September, down more than 1% from a year earlier and the lowest in over 10 years.

As an indicator of new construction, new building permits remained at healthy levels.

The most recent reading of the Case-Shiller Index for South Florida shows home prices up 5.3% from the prior year, while mortgage delinquency rates continue to decline.

Overall, Florida's economy continues to grow with the latest readings of Florida's consumer confidence near post-recession highs.

FPL's average number of customers in the third quarter increased by roughly 62,000 or 1.3% year-over-year.

For the third quarter, we estimate that warmer weather had a positive year-over-year impact on usage per customer of approximately 1.6% and that Hurricane Irma had a negative impact of approximately 3.5%.

After taking these factors into account, third quarter sales decreased 3% on a weather-normalized basis, which reflects continued customer growth, more than offset by an estimated decline in usage per customer of 1.7%.

With the increased uncertainty and our estimate of weather-normalized usage per customer as a result of Hurricane Irma, we are unable to draw any firm conclusions about long-term trends and underlying usage.

We will continue to closely monitor and analyze underlying usage going forward.

As a reminder, modest changes in usage per customer are not likely to have a material effect on earnings over the course of the settlement agreement as we will adjust the level of reserve amortization utilization to offset any effect, which would allow us to maintain our target regulatory ROE.

Overall, despite the effects of the hurricane, the underlying Florida economy remains strong, supporting ongoing customer growth.

And primarily due to weather, warmer-than-expected temperatures, we have utilized less reserve amortization than expected through the first 3 quarters.

Assuming normal weather and operating conditions, we currently expect to end 2017 with a reserve amortization balance of more than $1.1 billion that can be utilized over the remainder of the settlement agreement.

Our capital initiatives to further enhance our already best-in-class customer value proposition are also progressing well.

These smart capital investments are expected to deliver a regulatory capital employed compound annual growth rate of roughly 8% per year from 2017 through 2020.

We are pleased with FPL's year-to-date execution, and we'll continue to maintain our relentless focus on delivering low bills, high reliability, clean energy and outstanding customer service.

Let me now turn to Energy Resources, which report a third quarter 2017 GAAP and adjusted earnings of $292 million or $0.62 per share.

Energy Resources' contribution to adjusted EPS increased by $0.02 from last year's comparable quarter.

New investments contributed $0.12 per share, primarily reflecting continued growth in our contractor renewables program.

As I previously mentioned, third quarter fleet-wide wind resource was the lowest on record over the past 30 years at 87% of the long-term average versus 101% in the third quarter of last year.

The weaker wind resource in the third quarter was the primary driver of the negative $0.03 contribution from existing generation assets relative to the prior-year comparable quarter.

All other impacts reduced results by $0.07 per share, including the effects of increased interest expense.

Additional details are shown on the accompanying slide.

As I mentioned earlier, we signed contracts for 760 megawatts of new projects since the last call.

In addition to the 566 megawatts of wind for 2018 delivery, we successfully originated 164 megawatts of solar for delivery between 2018 and 2020 and the 30-megawatt battery storage project that will be paired with one of the solar PPAs.

This project is the largest combined solar and storage facility in the United States announced to date.

The strong quarter of origination activity is consistent with recent trends and are reflective of continued strong customer demand, driven largely by wind and solar economics.

The combination of low-cost wind or solar energy, paired with a low-cost battery storage solution, provides a product that can be dispatched with enough certainty to meet customer needs for a firm generation resource.

Today, we are able to offer this firm wind or solar resource for a lower cost than the operating cost of traditional inefficient generation resources.

As we have previously discussed, with continued equipment cost declines and efficiency gains as the tax efficiencies phase down early in the next decade, we expect new firm wind and firm solar without incentives to be cheaper than the operating cost of coal, nuclear and less fuel-efficient oil and gas-fired generation units, creating significant opportunities for renewables' growth going forward.

Our wind repowering efforts also continued to progress.

As I previously mentioned, we added 514 megawatts to our repowering backlog, including approximately 241 megawatts of contracted projects that have new PPA extensions in place.

Our wind repowering backlog now stands at over 2,300 megawatts, all for 2017 and 2018 delivery.

During the quarter, Energy Resources successfully commissioned an additional 308 megawatts of wind repowering projects.

We also closed our first tax equity financing related to a wind repowering, raising roughly $243 million on a portfolio of 327 megawatts of projects.

We continue to expect to invest a total of between $2.5 billion and $3 billion for repowerings through 2020.

The progress we have made this quarter reflects the continued strong outlook for renewables development.

And we believe that by leveraging Energy Resources' competitive advantages, we are well positioned to capture a meaningful share of the wind and solar markets going forward.

The attached chart provides additional details on where our renewables development program now stands.

Beyond renewables, we continue to make good progress on the Mountain Valley Pipeline.

Earlier this month, we received the FERC certificate for MVP.

We are working to complete final development activities and expect to begin -- expect to begin advancing construction efforts to support a December 2018 in-service date.

NextEra Energy's expected investment is approximately $1.1 billion.

Turning now to the consolidated results for NextEra Energy.

For the third quarter of 2017, GAAP net income attributable to NextEra Energy was $847 million or $1.79 per share.

NextEra Energy's 2017 third quarter adjusted earnings and adjusted EPS were $875 million and $1.85 per share, respectively.

Adjusted earnings from the Corporate & Other segment increased $0.01 per share compared to the third quarter of 2016.

Earlier this month, our transmission team was selected by the New York Independent System Operator to develop a 20-mile 345-kV transmission line and accompanying facilities located near Buffalo, New York.

The project is New York ISO's first competitive transmission award under its Public Policy Transmission Planning Process and will help the state to maximize the flow of energy from lower cost renewable generation.

The project is required to be in-service by June 2022, and our investment is expected to total roughly $180 million.

We are very pleased with this recent success and although a very competitive business, look to build on that success with other opportunities going forward.

For 2017, we continue to expect adjusted earnings per share at NextEra Energy to be in the range of $6.35 to $6.85.

We currently expect lower growth in the fourth quarter as we are pursuing several refinancing initiatives to capitalize on favorable market conditions that could drive up to roughly $150 million of MPV savings on a cash basis, but will result in a reduction in net income when they close later this year.

For example, we recently announced the refinancing of $750 million of capital holdings hybrid securities.

While this transaction produces more than $50 million of MPV savings on a cash basis, it will result in a net income reduction of approximately $13 million in the fourth quarter.

Despite this, we continue to believe we are well positioned to achieve full year results at or near the upper end of our previously disclosed 6% to 8% adjusted earnings per share compound annual growth rate expectations off our 2016 base.

For the full year 2017, we expect cash flow from operations to grow above our adjusted EPS growth rate after adjusting for impacts from certain FPL clause recoveries, storm costs and recoveries in the Indiantown acquisition.

Looking further ahead, we continue to expect adjusted earnings per share in the range of $6.80 to $7.30 for 2018 and in the range of $7.85 to $8.45 for 2020, applying a compound annual growth rate off a 2016 base of 6% to 8%.

With the overall strength and diversity of our growth prospects of both FPL and Energy Resources and based on everything we see now, we will be disappointed if we are not able to deliver financial results at or near the top end of our 6% to 8% range through 2020.

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

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

Although it is still premature to draw any firm conclusions, we wanted to provide an update on the potential impacts of the recent tax reform proposal on our long-term adjusted EPS expectations.

We have modeled the scenario, making certain assumptions based on the framework that was released on September 27 by the Trump administration, the House Committee on Ways and Means and the Senate Committee on Finance.

Off our 2020 baseline, we would expect the scenario to be roughly 20% to $0.30 per share accretive.

We continue to be actively engaged in the tax reform discussion, and we'll provide further updates as the ultimate direction of and progress on tax reform becomes clearer.

In summary, NextEra Energy remains on track to meet its 2017 expectations, and we remain as enthusiastic as ever about our future growth prospects.

At FPL, our ongoing focus is on operational cost-effectiveness, productivity and making smart long-term investments to further improve the quality, reliability and efficiency of everything we do.

At Energy Resources, we continue to make terrific progress on our development program and remain optimistic about our renewables' growth prospects as a result of improving equipment cost and efficiencies and ongoing advancements in energy storage.

Overall, we continue to believe that we have one of the best opportunity sets in our industry and that we are well positioned to continue to deliver on our growth expectations going forward.

Let me now turn to NEP.

Yesterday, the NEP board declared a quarterly distribution of $0.3925 per common unit, continuing our track record of growing distributions at the top end of our 12% to 15% per year growth range.

We are pleased to announce that following approval by the Conflicts Committee of the NextEra Energy Partners board, NEP has reached an agreement to acquire 4 additional assets from Energy Resources, adding to what we view as an already best-in-class portfolio with an average 18-year contract life and counterparty credit rating of A3 following the acquisition.

These assets are expected to further enhance the quality and diversity of NEP's existing portfolio and to complete the growth necessary to achieve our previously outlined year-end 2017 adjusted EBITDA and cash available for distribution run rate expectations.

We expect the transaction, which is anticipated to be funded with the issuance of the $550 million of previously announced convertible preferred units and cash on hand, to yield a double-digit return to NEP's unitholders and to be accretive to LP distributions.

I will provide additional details on the transaction in a few minutes.

Building upon the changes we have pursued this year to further improve NEP's investor value proposition, including the governance enhancements, the modified IDR structure, the standalone credit ratings in the mid- to high-BB category and the agreement to issue $550 million of convertible preferred units, NEP demonstrated its ability to access additional low-cost sources of capital this quarter with the issuances of $300 million of 3-year convertible debt and a total of $1.1 billion of 7- and 10-year senior unsecured notes at historically low yields.

Today, we are also announcing that we have upsized and extended NEP's revolving credit facility to further enhance NEP's financial flexibility and strengthen its standalone prospects going forward.

I will provide additional details on each of these financings in just a moment.

Consistent with our long-term growth prospects, today, we are introducing December 31, 2018, run rate expectations, reflecting roughly 22% and 17% growth, respectively, from the comparable year-end 2017 run rate adjusted EBITDA and CAFD midpoints.

Overall, we are pleased with the year-to-date execution at NEP and are well positioned to meet our 2017 and longer-term expectations.

Now let's look at the detailed results for NEP.

Third quarter adjusted EBITDA was $178 million, and cash available for distribution was $47 million, up approximately 2% and down roughly 8% from the prior year comparable quarter, respectively.

Poor wind resource had a meaningful impact on NEP's assets.

Fleet-wide wind resource was 82%, the lowest third quarter on record over the last 30 years, compared to 95% for the third quarter in 2016.

Although still early in the fourth quarter, wind resource has begun to return to more normal levels in October.

On a year-to-date basis, adjusted EBITDA and cash available for distribution have increased by 15% and 10%, respectively.

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

Additional details are shown on the accompanying slide.

As I previously mentioned, and the NEP board declared a quarterly distribution of $0.3925 per common unit or $1.57 per common unit on an annualized basis, an increase of approximately 15% from a year earlier.

NEP completed multiple financing transactions this quarter, further demonstrating its ability to access a variety of capital sources.

In early September, NEP issued $300 million of convertible notes due in 2020 at a 1.5% coupon.

The notes have the potential to convert into equity at a 25% premium to the September 6, 2017 closing price of $42.29.

Consistent with our desire to achieve the top end of NEP's growth expectations, the conversion rate has been structured to allow an approximate 15% annualized growth rate in distributions per unit without an adjustment to the conversion rate.

Concurrently with the debt issuance, NEP purchased a capped call that provides economic and dilution protection up to a 50% premium to the September 6 closing price.

In September, NEP also issued $550 million of both 7- and 10-year senior unsecured notes to refinance approximately $1.1 billion in existing secured holding company debt that had maturities in 2018 and 2019.

We believe the strong demand for the offering, which was more than 5 1/2 times oversubscribed, is indicative of NEP's superior value proposition, supported by diversified cash flows from long-term contracts with strong creditworthy counterparties.

The transaction priced at historical lows, including the lowest spread and coupon for a Ba1/BB U.S. dollar offering on the 7-year tranche and the lowest coupon for a Ba1/BB USD offering on the 10-year tranche.

As I mentioned -- as I just mentioned, today, we are also announcing amendments to our existing revolving credit facility.

In addition to lower borrowing rates, the facility will be upsized from $250 million to $750 million, and the maturity will be extended from July 2019 to October 2022.

We believe that the strong demand from 20 banks to participate in the amended credit facility is reflective of the core strength that separate NEP from other infrastructure alternatives.

We continue to expect a target total holdco leverage to project distributions of 3 to 4x at year-end 2017 and consistent with NEP's credit ratings, total holdco leverage to project distributions of 4 to 5x over the longer term.

We believe these leverage targets are supported by NEP's amortizing project debt and long-term contracted portfolio and are consistent with our experience in financing clean energy assets.

As a result of this financing flexibility, aside from any modest issuances under the aftermarket program or issuances upon the conversion of NEP's convertible securities, we continue to expect that NextEra Energy Partners will not need to sell common equity until 2020 at the earliest.

Beyond the new financings, the previously announced NEP governance enhancements, which will give LP unitholders, among other rights, the ability to elect a majority of the NEP board beginning at the shareholder meeting to be held later this year, we also implemented during the quarter.

As I previously mentioned, we continue to execute on our plan to expand NEP's portfolio with the agreement to acquire 4 additional assets from Energy Resources.

This portfolio is a geographically diverse mix of wind and solar projects, collectively consisting of approximately 691 megawatts, including the acquisition of a 25.9% indirect interest in the Desert Sunlight Solar Energy Center.

The portfolio has a cash available for distribution weighted remaining contract life of 22 years.

The transaction is expected to close by year-end, subject to customary closing conditions and the receipt of certain regulatory approvals and represents another step toward growing LP unit distributions in a manner consistent with our previously stated expectations of 12% to 15% per year through at least 2022.

NEP expects to acquire the portfolio for total consideration of approximately $812 million, subject to working capital and other adjustments plus the assumption of approximately $459 million in liabilities related to tax equity financing and considers approximately $268 million of existing nonrecourse project debt related to the Desert Sunlight project.

The acquisition is expected to contribute adjusted EBITDA of approximately $185 million to $205 million and cash available for distribution of approximately $79 million to $89 million, each on a 5-year average annual run rate basis beginning December 31, 2017.

The purchase price for the transaction is expected to be funded through the issuance of $550 million of previously announced convertible preferred units with the balance funded with cash on hand as a result of NEP's recent convertible debt financing.

Additional details are shown in the accompanying slide.

Following the acquisition of this portfolio from Energy Resources, we expect the NEP assets to support the previously announced December 31, 2017 run rate expectations, reflecting calendar year 2018 expectations for the forecasted portfolio at year-end 2017 for adjusted EBITDA of $875 million to $975 million and CAFD of $310 million to $340 million.

Since we currently expect today's announced acquisition to close later in the fourth quarter, we do not expect the portfolio to provide a meaningful contribution to fourth quarter 2017 adjusted EBITDA or cash available for distribution.

As I mentioned earlier, consistent with our previously announced long-term growth prospects, today, we're introducing December 31, 2018 run rate expectations for adjusted EBITDA of $1.05 billion to $1.2 billion and CAFD of $360 million to $400 million, reflecting calendar year 2019 expectations for the forecasted portfolio at year-end 2018.

Our expectations are subject to our normal caveats and are net of anticipated IDR fees as we treat these as an operating expense.

From a base of our fourth quarter 2016 distribution per common unit at an annualized rate of $1.41, we continue to see 12% to 15% per year growth in LP distributions as being a reasonable range of expectations through at least 2022.

With the acquisitions announced today, we expect the annualized rate of the fourth quarter 2017 distribution, meaning the fourth quarter distribution that is payable on February 2018, to be at the top end of our previously disclosed range of $1.58 to $1.62 per common unit.

While we cannot draw any firm conclusions about the impacts of tax reform on NEP, we expect that on most reasonable scenarios, NEP's U.S. federal income tax shield, which is currently greater than 15 years, and NEP's earnings of profits balance, which is currently expected to remain negative for at least the next 8 years, will not be materially affected.

We are pleased with the progress NEP has made over 2017, and we are well positioned to achieve our full year financial expectations.

Upon the closing of the announced acquisition from Energy Resources, we have successfully executed on our growth strategy for the year.

We believe NEP continues to provide a best-in-class investor value proposition.

As we have previously outlined, NEP has the flexibility to grow in 3 ways, acquiring assets from Energy Resources organically or acquiring assets from other third parties.

NEP also has a cost of capital and access to capital advantage with substantial flexibility to finance its long-term growth as was further demonstrated by the transactions completed this quarter.

These advantages, together with the stability of NEP's cash flows backed by the portfolio's long-term average contract life and strong counterparty credit profile, amortizing debt, tax position, enhanced governance rights and long-term growth expectations through at least 2022, all support NEP's favorable position relative to other yieldcos and MLPs.

NextEra Energy Partners continues to make excellent progress against its strategic and growth initiatives, and we remain as enthusiastic as ever about NEP's long-term prospects.

That concludes our prepared remarks.

And with that, we will open the line for questions.

(Operator Instructions) We'll go to Stephen Byrd, Morgan Stanley.

I wanted to check in on your excess balance sheet capacity and just generally, your balance sheet strength.

You've been putting up additional wins in the renewables business, and it looks like there's also upside at the utility.

When we think about using that excess balance sheet capacity, do you see significant organic opportunities at the different business units?

Or do you think you're likely to still have excess balance sheet capacity through the end of the decade?

Okay.

So first of all, the excess balance sheet capacity is about $3 billion to $5 billion through 2020.

And when you look at the financial plan that we have laid out through 2020 at the investor conference, the CapEx that we already have planned for the FPL business and the Energy Resources business does not take into account that $3 billion to $5 billion of excess balance sheet capacity.

So what do we do with it?

We have a few options.

I think our preferred option would be to find incremental capital investment opportunities that drive long-term value for shareholders and that also help to create growth post 2020, which we view as being strong, given all the potential growth platform opportunities that we have in the next decade, given where we see renewables and also given all the opportunities that FPL has on Eric's side of the business.

Understood.

And just shifting gears to storage.

You made some interesting remarks about storage.

And I guess, we're hearing that storage solicitations are now a regular part of a lot of renewable procurements.

I was just curious, your opinion as to whether we're currently in the right ZIP code that you think many customers will opt for storage linked with renewables or do you think that's a few years down the road?

What's your sense of the likely customer appetite over the next couple of years for storage linked with renewables and PPAs?

Yes.

Storage is very real now.

And I think -- and as evidenced by the project we announced today with the 30 megawatts tied to an existing solar project, making it the largest combined solar plus storage project in the U.S. But when you look at where storage economics are, storage costs continue to come down significantly, efficiency continues to improve at a rate where we can now combine storage with solar and really beat the pricing, the existing variable costs just to operate a nuclear or coal plant, and be pretty darn competitive even with combined cycle gas facilities.

And what's the result of that?

Because of that, on almost every solar procurement that we are bidding on today, counterparties are asking us not only for solar bid, but also for a combined solar plus storage bid.

They clearly understand the benefits that are created by the firm dispatchability of the combined products.

So the short answer is, we're already here and things should only continue to improve as we go forward and as tax incentives phase down in the next decade, and you can combine storage, which will be even lower cost, even more efficient, with an even lower cost and more efficient solar panel and balance of system cost, we see that as a very viable product going forward, and we also are continuing to look for opportunities to combine solar with wind or storage with wind.

And with that, I don't know if Armando has anything that he would like to add.

Steven, real quick, recall that at the investor conference, what we laid out was the roughly $700 million of CapEx opportunities in the storage market through 2020.

We continue to think that's a good number.

That doesn't mean that customers aren't significantly interested in what's going on and proactively asking for bids.

And even as the cost estimate comes down, we continue to believe that this is going to be a significant opportunity early part of the next decade.

We'll go next to Steve Fleishman, Wolfe Research.

Just one question on the NEP financing for the new drops.

Could you just repeat kind of the financing plan that you laid out for the new drops announced today?

Yes, absolutely, Steve.

So for the new drops, remember, right around the time of the investor conference, we completed the $550 million convertible preferred offering at a 4.5% coupon, lowest coupon ever for a convertible offering.

That will comprise the lion's share of the $812 million equity price for that acquisition.

The balance will come from cash on hand.

Now cash on hand is really coming from the convertible debt offering that we closed on in September at a 1.5% coupon, with the up 25% and then the cap [capped] call on top of that given a second [arm of] consideration of up 50%.

We'll go next to Greg Gordon, Evercore Partners.

The first is you've reclassified a significant chunk of your wind assets from merchant to contracted, and there's a footnote that describes why.

But can you go into some more detail as to what the underlying assumptions are that -- with regard to profitability of those assets and why they've shifted.

Yes.

It's really pretty simple.

So those are repowering assets that were formerly ERCOT merchant assets.

And the way the economics works is that roughly 90% of the gross margin comes from the production tax credits.

So you can think of the PTC as essentially being a contractual hedge.

So every megawatt-hour that we're generating, we're getting paid $24 on that megawatt-hour for 90% of the gross margin.

And so given that, and also the fact that some of those projects will carry financial hedges going forward, the more appropriate classification over the next 10 years during the PTC period is as a contracted asset.

Well that makes a pretty underlying strong statement about the incremental IRR you're getting on the repowerings if the vast majority of your return at the hurdle rate is coming just from getting the PTCs without worrying about a substantial energy margin.

Is that the right way to think about it?

Well, yes, I mean, remember too -- I mean, it's about half the CapEx and because of -- it's half the CapEx, you're getting the driver from the PTCs and then energy is the upside.

That's why we've said the unlevered IRRs are a few ticks up from what we would get on a newbuild wind project.

Fantastic.

My second question is, if you would humor us, can you delineate what the basic assumptions you were assuming are on your baseline tax case?

Yes.

I mean, it's really what came out on September 27.

So you can think of it as a 20% corporate tax rate, 100% immediate expensing, and then we've made an assumption on what the interest limitation is that I'm probably not going to share on this call.

Fair enough.

But the industry EI has been lobbying on behalf of the industry to try and achieve an offramp or an exemption on interest deductibility and bonus depreciation, correct?

It -- well, I'll let Jim take it.

So Greg, listen, I just think on tax reform, it's very fluid right now.

Obviously, the industry has been weighing in, I've been spending a lot of time on it, and we don't even have a bill out of House Ways and Means yet.

So I think it's too early, really, to say anything about where any of this stands other than you can rest assured, I'm highly engaged on this.

We'll go to Michael Lapides, Goldman Sachs.

Guys, couple of questions.

One, probably for Armando, which is, can you talk about, when you think about your renewable pipeline, how much of that is the counterparty of -- traditional regulated utility versus how much of it is a corporate entity, whether a big tech company or someone else?

So Michael, right now, for us, I'd say, 90% of what we're doing is probably the more traditional customers, and those could be the rate-regulated utilities or the munis and co-ops.

And I'd say, 5% to 10% are the latter, which you asked about for the corporate entities, what we call C&I companies.

We continue to see more C&I companies out there.

And actually, we are engaging in that business more proactively today than we have in the past.

So I would expect, for us, that 5% to 10% to go up.

Got it.

And then, guys, how are you thinking about the Section 201 case and some of the recent developments and what that could do if any to solar-related demand?

Really, for 2018 solar demands, but even for the next few years?

So Michael, this is Jim.

Obviously, this is something we're watching very closely.

I think I spoke on this issue in September.

We're fine in '17 and '18 because we prebought our panels when we saw this going on.

'19 is probably the year we're most concerned about.

That's probably where there is potentially a pinch point, depending on where the ITC comes out and where the administration comes out on this.

Post '19, I think there's going to be -- the market's going to -- the market will have time to react to whatever happens, and I think we'll get back to normal business in 2020 and beyond.

But '19 is our focus, and we're working quite hard in a number of fronts.

And it's something that we're watching closely, and we're highly engaged on it and the whole team is highly engaged on it across the board.

We'll go next to Julien Dumoulin-Smith, Bank of America Merrill Lynch.

Let me start real quickly on the 201 issue there if I can.

What are you expecting when you talk about 2019 and really beyond that in terms of market reaction?

I mean, what's your kind of playbook as far as you see this playing out right now?

And then secondly, what is your expectation in terms of the positioning of parties and thinking about how this could actually play out over the next few months?

Is a settlement possible, et cetera, to make this a little bit more palatable?

So Julien, it's Jim again.

I just think it's too early to tell what's going to happen here.

And I think, honestly, there's a pretty broad range of potential outcomes on this, and I wouldn't care to speculate on what's going to happen.

I think we'll see.

We're -- and what we're doing is frankly scenario planning across a variety of different outcomes and making sure that we're going to be prepared in case of any potential outcome.

Excellent.

Well -- and looking beyond the current 2020 period, you guys have done a fantastic job in the repowering side thus far.

I'm curious, how are you thinking about repowering opportunities under kind of a sub-100% PTC, call it, 80%, 60%?

I mean, you've been pretty forward looking before across the industry, and this seems like an opportunity to pivot.

Are you engaging with parties on that front?

I mean, do you have an expectation for an ability to use those PTCs that are expired 2000 -- say, '12, '13 and '14 vintage projects as they come off in the early part of the next decade and repower those?

Armando...

So I'm just thinking in the longer term.

Yes.

Look, most of what -- not most, just about everything of what we're doing today is to make sure that we can grab the -- as many of these repowering opportunities through 2020, having safe harbored a good part of that equipment in order to get the 100% Production Tax Credits.

There's already been one entity out there, which I'm sure you've seen, that has announced the project where they would be getting 80% Production Tax Credits and that the economics work for them under that scenario.

Our expectation is that when the Production Tax Credit goes down to 80%, that there are actually going to be some repowering opportunities that are going to work, maybe not necessarily for the reasons that some might believe.

When we're looking at repowering opportunities, one of the things that we're looking at is, how close is the old asset, if you will, to the end of its PTC life, right?

And if it's 9 or 10 years into its life, 100 -- taking the asset down and repowering it and putting it up and getting 100% PTCs for 10 years might work.

But if it's at the end of 2020, if it's only gone through 7 years, let's say, you wouldn't necessarily want to repower the asset at that point and lose 3 years of the old PTCs.

But if you wait another year, now you're 8 years or 9 years, it may actually make sense to give up 1 year of the old PTCs and get 10 years of the 80% PTCs.

So that scenario planning is something that we are spending a little bit of time right now.

We certainly have a lot of assets that would be subject to that.

But I do believe that there are going to be repowering opportunities that work with 80% PTCs.

We'll go next to Paul Ridzon, KeyBanc.

John, I think on the second quarter call, you said look for most of the second half growth to hit the fourth quarter.

I'm just trying to calibrate.

We saw a 6.5% growth in the third quarter here.

Did some of that growth shift quarters?

And then just how do I think about the sub-par wind resource you had in the quarter?

How does that figure into the numbers?

Yes.

So by the time of the second quarter call, we were pretty well into July, which was, well, not a terrific wind resource month.

Things -- we were concerned about the trend for the rest of the quarter.

For August and September, August ended up kind of following suit with July, and we're a little bit surprised because September rebounded a little bit more than we had expected.

I think that September ended up being about 95% of normal.

And now we've seen October has truly rebounded so far this month.

That was part of it.

We had a little bit better performance out of other miscellaneous parts of the business, none worth pointing out individually that, when added up, put us in a little bit better position than what we were expecting for the quarter, including some origination activity that we had on the business.

Should we think about that incremental positive as essentially being offset in the fourth quarter by the refinancings that you talked about?

Yes.

And so the fourth quarter -- that's why I think I made the comment that growth will be down a little bit in the fourth quarter.

We have really been focused on liability management.

When you look at our portfolio -- one of the things I made a comment on at the investor conference is, if you look at our financing portfolio, we have one of the longest average tenors combined with one of the lowest average interest rates of any of our peers.

And that's because we constantly look at the portfolio for refinancing activity opportunities.

And that -- those are the opportunities we're looking to execute on in the fourth quarter.

The remarks were that the MPV could be as high as $150 million.

Obviously, those come with some prepayment penalties that do have some book impacts associated with them, but we're just trying to continue our trend of being very mindful that we're in an attractive low interest rate environment and looking at the balance sheet as we always do, to be opportunistic, and that's what you can expect would be reflected in the fourth quarter results.

And you don't treat those kind of onetime -- make holes or anything as unusual items?

No.

We flow them through.

We'll go next to Shar Pourreza, Guggenheim Partners.

Just a quick follow up on the battery storage comments, John.

Did Dania filings that you filed for show that the asset was materially more economical than battery storage and solar, even in the 2022 time frame?

So I'm curious on sort of how that fits in with your viewpoint that batteries plus solar could be economical with the CCGT?

And then just a follow-up on Dania, is -- looking at FP&L's gas assets, there are other plants that fit the similar economics as sort of the plant that you're converting.

So I'm kind of curious if the Dania plant's a one-off.

And do you see any opportunities thus far?

Yes.

I think we'll just tackle the Dania piece first.

The Dania piece first is, one, you got to consider its location.

I mean, it's in South Florida, it has a transmission advantage given its location.

If you look at the economics on the reduced O&M on improving the fuel efficiency of that facility, given its location, that's why that one works.

We continue to look for other opportunities.

We have the 50-megawatt battery storage pilot program in Florida where we will look to do a lot of the same things we've done on the Energy Resources side, including the project we announced today where we can actually combine our storage capability with newbuild solar in Florida.

And that -- those opportunities will come about not only through the 8 facilities we're currently building within the 1,600 post 2018.

Where exactly that will end up will depend on where they're located in the overall economics of those facilities.

But it's a terrific opportunity for Florida to take advantage of the same opportunities that our regulated customer base outside of Florida are looking for.

And Shar, this is Jim.

I just -- one other thing on storage and renewable competitiveness is we see storage and renewables being -- really competing very well against inefficient, old operating nuclear and coal plants where you look at those -- you look at the economics of those sites, they're anywhere from $0.04 to $0.05 on a cash, cash cost per kilowatt basis to operate.

These new CCGTs, particularly in a constrained place like Dania Beach, are very, very cost-effective and super fuel-efficient.

And typically, you wouldn't see renewables and storage competing with that just yet.

We'll go next to Chris Turnure, JPMorgan.

Given -- you guys probably have maybe 6 or so months to go to kind of finish out the '17 to '18 bucket of renewable backlog, could you just give us an update on how you might fall out within that 4-gigawatt range?

Are you coming up on the bottom now?

Will any of it kind of spill into 2019?

In terms of your maybe original expectations, has anything changed in the last 3 to 6 months?

Yes.

So first, we're already there on solar.

Not only there on solar for '17 and '18.

We're pretty darn close to a range for '19 and '20.

And we'll look to continue to add to that obviously going forward.

And then on the wind side, given the 760-megawatt total portfolio today, the wind additions that were part of that, we're within striking distance on wind.

And I'll let Armando fill in the details with kind of his viewpoint.

So for wind, and this has been the case for a long time, right, the -- when folks are looking for wind, they're looking out much shorter -- at a much shorter time period.

One of the things that I'm honestly most happy about so far in the cycle is we have almost 900 megawatts of wind signed up all ready for 2019 and '20.

But when you're focused on '17 and '18 and particularly, on wind, there's the current -- there's the -- just the recent history that we announced today of signing 560 megawatts of 2018 wind.

And I can tell you that we are working on a pretty decent backlog for additional 2018 wind right now.

Whether that happens or not, it depends.

Customers understand that if they wait a little longer, that the prices could be a little cheaper.

And so you're always fighting that.

But I was very pleasantly surprised with the 566 megawatts we signed for 2018 this past quarter.

And my expectation is that, that number in 2018 will continue to go up just as it has in the past, just because wind has a shorter time frame.

Is it fair to say that just kind of the higher half or the upper half of the range is still achievable for '17 to '18?

It's -- I think honesty, all of the numbers in that range are achievable.

And if all I wanted to do was to meet the higher end of the range on wind for '17 and '18, I'm -- we could probably do that.

But that's not necessarily always the right thing to do, right?

I mean, you may be talking customers into building something in 2019 and 2020 because it's better economics for us honestly than it could be for 2018.

So every situation is different.

Again, I'm happy at this point that we've signed almost 900 megawatts for '19 and '20 and that we still have a pretty decent backlog of '18 opportunities that we have been shortlisted on.

Okay, that's helpful color.

And then maybe, John or Jim, given the stock performance has been a strong as it has year-to-date, just kind of maybe going back to an earlier question on cash return versus dividend or incremental investment opportunities versus buybacks, does the stock performance kind of lower the hurdle to deploy capital into other investments or to return cash to shareholders through a bigger dividend increase maybe than previously expected?

So Chris, this is Jim.

Listen, we remain very disciplined in how we evaluate all our incremental opportunities.

We're looking hard at a lot of different things to continue to deploy that excess balance sheet capacity very profitably for us going forward and that's going to be our focus.

But as always, we're not going to do dumb stuff either.

We're going to be very disciplined about it.

And we'll -- on the dividend, we'll be -- we just had a discussion with the board about the dividend in October.

We'll have another one in December, and we'll be coming out with our post-2018 dividend policy in February once we -- once the board finalizes where they're going to come out on that.

So more to come on the dividend.

Ladies and gentlemen, that will conclude today's question-and-answer session.

Thank you for your participation.

You may disconnect at this time.