新世紀能源 (NEE) 2017 Q4 法說會逐字稿

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

Today's conference is being recorded.

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

Please go ahead, sir.

Thank you, April.

Good morning, everyone, and thank you for joining our fourth quarter and full year 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.

Jim will provide some opening remarks and will then turn the call over to John for a review of our fourth quarter and full year results.

Our executive team will then be available to answer your questions.

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

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

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

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

You should refer to the information contained in the slides 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 Jim.

Thanks, Matt, and good morning, everyone.

As John will describe in more detail later in the call, 2017 was a terrific year for both NextEra Energy and NextEra Energy Partners.

Moreover, 2017 was a year in which we successfully positioned both businesses for strong growth well into the next decade.

For NextEra Energy Partners, we started 2017 by structurally modifying the IDR fee, which allowed NEP to extend its distribution growth expectations through at least 2022, avoid the need to sell common equity until 2020 at the earliest other than modest sales under the ATM program and increase levered returns for unitholders to the low double digits on future acquisitions.

This change, combined with other steps we took to improve NEP's investor value proposition over the past year, including governance enhancements, stand-alone credit ratings in the mid- to high-BB category and NEP's utilization of additional sources of low-cost financing, helped separate NEP from its peers.

We were able to grow the NEP LP distribution by 15% year-over-year and deliver a total unitholder return of over 75%.

NEP outperformed other yieldcos by more than 55% on average, and its total shareholder return was almost 90% higher than the Alerian MLP Index.

With the flexibility to grow in 3 ways, acquiring assets from Energy Resources organically or acquiring assets from other third parties, NEP has clear visibility to support its growth going forward.

As we said before, Energy Resources' portfolio as of the end of 2016 provides one potential path to support NEP's 12% to 15% growth per year through 2022.

And with one of the lowest costs of capital among all yieldcos and MLPs, NEP has the currency to be competitive in acquiring long-term contracted assets from other third parties going forward.

With tax reform and a record renewable origination year by Energy Resources in what promises to be one of the best renewables development environments in our history over the next several years, we look forward to further improving NEP's already best-in-class distribution growth visibility.

I continue to believe that when NEP's growth potential is combined with its substantial financing flexibility and the strength of its underlying portfolio, with an 18-year average contract life and strong counterparty credit profile, NEP offers unitholders an investor value proposition that is second to none.

For these reasons, NEP is as well positioned as it's ever been, and I look forward to strong performance in 2018 and beyond.

Turning now to NextEra Energy.

2017 was an outstanding year of execution across the board.

Financially, we were able to grow 2017 adjusted EPS by 8.2% and extend our long-term track record of delivering results for shareholders.

Dating back to 2005, we've delivered compound annual growth in adjusted EPS of over 8%, which is the highest among all top 10 U.S. power companies who've achieved on the average compound annual growth of 2.9% over the same period.

In 2017, we delivered a total shareholder return of over 34%, outperforming the S&P 500 by roughly 15% and the S&P Utilities Index by more than 25%.

Over the last 10 years, we've outperformed 79% of the S&P 500 Utilities Index and 63% of the S&P 500.

We were once again honored to be named, for the 11th time in 12 years, #1 in the electric and gas utilities industry on Fortune's 2018 list of World's Most Admired Companies.

The strength of our 2017 execution has set the foundation for several announcements that I'm going to make on this morning's call.

First, as we announced last week, tax reform provides an unprecedented opportunity to benefit FPL customers.

Rather than seek recovery from customers of the approximately $1.3 billion in Hurricane Irma storm restoration costs, FPL plans to recover these costs through federal tax savings, generated during its current settlement agreement.

During the fourth quarter, FPL expensed the approximately $1.3 billion that was recorded as a regulatory asset related to Irma cost recovery and utilized the available reserve amortization to offset nearly all of this expense, ending the year with a 0 reserve amortization balance.

FPL expects to partially restore the reserve amortization utilized in the fourth quarter through tax savings and to end 2020 with a sufficient amount of surplus to potentially avoid a base rate increase for up to 2 additional years in 2021 and 2022.

As a reminder, FPL is currently allowed to earn within a permitted ROE band of 9.6% to 11.6%.

The settlement agreement also allows FPL to access and utilize the accumulated reserve amortization available at the end of 2020 by deferring the initiation of a new base rate case.

Based on what we see at this time and assuming normal weather and operating conditions, our goal is for FPL to continue operating under its current base rate settlement agreement for up to 2 additional years.

The flexibility afforded under the settlement agreement provides FPL with the ability to return tax savings to customers in the fastest way possible.

By foregoing the surcharge, FPL customers are expected to save approximately $250 on average through 2020, with a typical residential bill nearly 30% below the national average, following a $3.35 per month decrease that will take effect March 1 with the completion of cost recovery for Hurricane Matthew.

Moreover, by potentially operating under the settlement agreement for up to 2 additional years, customers save by avoiding a base rate increase in 2021 and 2022.

Second, I'm pleased to announce that we're increasing our financial expectations to take into account the favorable impact of tax reform at Energy Resources.

The reduction in the corporate federal income tax rate from 35% to 21% at Energy Resources is significantly accretive to earnings.

Due primarily to this favorable impact, tax reform is expected to increase NextEra Energy's adjusted EPS by roughly $0.45 in 2018.

For 2018, our goal is to achieve our new $7.70 per share midpoint, which assumes we grow our 2017 adjusted EPS of $6.70 per share by 8% and add approximately $0.45 for the benefit of tax reform.

Third, with the certainty provided by the new tax reform legislation and the anticipated continued strength of the investment opportunities at both FPL and Energy Resources, I'm also pleased to announce that we're extending NextEra Energy's financial expectations by 1 year, from 2020 to 2021.

With this announcement, we now expect to be able to sustain the 6% to 8% per year growth in adjusted EPS off our revised 2018 midpoint of $7.70 per share through 2021, subject to our usual caveats.

Details of our new financial expectations are included in the accompanying slide.

Tax reform is generally expected to result in lower operating cash flows for NextEra Energy as FPL uses tax savings to recover the Irma storm surcharges.

Despite this, everything we see now suggests that our operating cash flow will continue to grow in line with our adjusted EPS growth range from 2018 through 2021.

Overall, the tax reform outcome is positive and will immediately benefit FPL customers while being accretive to NextEra Energy shareholders.

Fourth, we're advancing our renewable product offerings as we prepare for the next phase of renewable development.

As a result, our prospects for new renewables growth have never been stronger.

As expected, Congress did not make any retroactive changes to the PTC or ITC, which were each extended under a 5-year phasedown at the end of 2015.

With incentives, wind is the cheapest form of energy at $0.012 to $0.018 per kilowatt hour at high wind sites, while solar continues to be priced at a discount to other forms of generation at $0.025 to $0.035 per kilowatt hour.

Taken together, we continue to be in the best renewables environment in our history, as evidenced by our 2017 results.

The ongoing cost declines in renewables are leading to increased economic demand from customers.

Wind turbine technology continues to improve through a combination of taller towers and wider rotor diameters.

Today, we're installing 127-meter rotor diameter turbines.

By 2021, we expect manufacturers to be selling approximately 150-meter rotor diameter turbines in the U.S. market, further increasing net capacity factors and helping reduce installed wind costs on a dollar per kilowatt basis.

Over the past year, we've seen an approximate 30% reduction in turbine costs.

Through the end of the decade, we expect another 10% decline per year on average.

As a result, we continue to expect that without incentives, early in the next decade, wind is going to be a $0.02 to $0.025 per kilowatt hour product.

For solar, we continue to see rapid price declines and efficiency improvements.

And we're well positioned to mitigate any impacts of the recently announced tariffs from the ITC 201 proceeding.

As we previously discussed, before any tariffs were put in place, we purchased modules for our 2017 and 2018 build.

We recently completed an additional order that covers our module needs for 2019 and a significant portion of our 2020 build.

Ultimately, we expect that by 2020, as the tariff steps down, the market will have adjusted to these new dynamics.

By early in the next decade, as further cost declines are realized and module efficiencies continue to improve, we expect that without incentives, solar will be $0.03 to $0.04 per kilowatt hour product, below the variable costs required to operate an existing coal or nuclear generating facility of $0.035 to $0.05 per kilowatt hour.

As the world's current leader in wind, solar and storage development, we are uniquely positioned for the next phase of renewables deployment that pairs low-cost wind and solar energy with a low-cost battery storage solution, to provide a product that can be dispatched with enough certainty to meet customer needs for a firm generation resource.

We believe no other company has our expertise in all 3 products: wind, solar and battery storage, to leverage the combined technologies at the low cost we can achieve.

In fact, we recently submitted a bid at a very competitive price for a combined wind, solar and battery storage product that is able to provide an around-the-clock, new firm, shaped product specifically designed to meet the customers' needs.

By leveraging Energy Resources' competitive advantages, including our development skills; purchasing power; best-in-class construction expertise; resource assessment capabilities; strong access to and cost of capital advantages; and the ability to combine wind, solar and battery storage solutions together, we remain well positioned to capture a meaningful and growing share of the renewables market going forward.

Finally, in addition to increasing and extending our financial expectations and having what I believe to be the best opportunity set in our industry, we continue to maintain one of the strongest balance sheets in our sector.

Through the sale of noncore assets over the last 2 years, including FiberNet and our Forney, Lamar and Marcus Hook gas generation assets, we've recycled almost $4 billion of capital while advancing our strategy to become more long-term contracted and rate regulated.

Based on the strength of our balance sheet and enhanced business risk profile, S&P and Moody's recently announced favorable adjustments to our credit metric thresholds.

While S&P has already reduced our FFO-to-debt rating trigger to 23% from 26%, yesterday, Moody's announced its plan to reduce NextEra Energy's CFO preworking capital-to-debt rating threshold from 20% to 18% if the regulated contribution to our business mix continues to improve to approximately 70% over time.

Based on this level of regulated contribution, we would also expect a further reduction to our FFO-to-debt rating trigger from S&P.

At our current thresholds of 23% and 20% at S&P and Moody's, respectively, we currently expect to have $5 billion to $7 billion of excess balance sheet capacity that can be utilized through 2021 to either buy back shares or opportunistically execute on profitable incremental capital investments or profitable acquisition opportunities if it makes sense to do so.

Our excess balance sheet capacity serves as a cushion as its utilization is not currently assumed in our financial expectations.

Today's announcements set the foundation for growth over the next 4 years.

While there certainly will be challenges that we'll have to manage due to the overall strength and diversity of our opportunity set, I will be disappointed if we're not able to continue to deliver financial results at or near the top end of our 6% to 8% compound annual growth rate range while, at the same time, maintaining our strong credit ratings.

I remain as enthusiastic as ever about our future prospects, and today's announcements for NextEra Energy are a reflection of that enthusiasm.

I'll now turn the call over to John to provide the detailed results.

Thank you, Jim, and good morning, everyone.

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

We achieved full year adjusted earnings per share of $6.70, up 8.2% from 2016, while continuing to make excellent progress on our major growth initiatives.

FPL grew regulatory capital employed approximately 10.3% year-over-year as we continued investing in new and modernized generation as well as a stronger and smarter grid to further improve the already outstanding efficiency and reliability of our system.

All of our major capital initiatives, including one of the largest solar expansions ever in the Eastern U.S., remain on track.

In 2017, FPL continued executing on its outstanding customer value proposition, delivering its best-ever service reliability performance while maintaining a typical customer bill that is more than 25% below the national average and the lowest among the top 10 investor-owned utilities by market cap.

As Jim mentioned earlier, 2017 was the best period for new wind and solar origination in our history.

The Energy Resources team added more than 2,700 megawatts of new renewables projects to our backlog, including the largest combined solar and storage facility in the United States announced to date and roughly 700 megawatts of additional wind repowering to our backlog.

Over the course of the year, we commissioned roughly 2,150 megawatts of wind and solar projects in the U.S., including the first approximately 1,600 megawatts of our repowering program.

All in all, 2017 was a terrific year of execution at FPL and Energy Resources.

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

For the fourth quarter of 2017, FPL reported GAAP net income of $344 million or $0.73 per share.

FPL's adjusted earnings for the fourth quarter, which excludes a tax reform-related item that I will discuss in a moment, were $394 million or $0.84 per share, an increase of $23 million and $0.05 per share, respectively, year-over-year.

For the full year 2017, FPL reported GAAP earnings of $1.88 billion or $3.98 per share.

Adjusted earnings were $1.93 billion or $4.09 per share.

Before moving on, let me take a moment to discuss the specific tax reform impacts to FPL.

For the fourth quarter, FPL is excluding from adjusted earnings the $50 million after-tax net impact that results primarily from the shortfall of available reserve amortization to offset the Irma cost recovery expense.

This tax reform-related item reduced our reported ROE for regulatory purposes to approximately 11.1% for the 12 months ended December 2017.

For the full year 2018, we expect tax savings to begin restoring our reserve amortization balance.

And coupled with our weather-normalized sales forecast and current CapEx and O&M expectations, we expect to target a regulatory ROE of 11.6%.

Based upon our historic pattern of underlying revenues and expenses, we do not expect that the tax savings will fully offset our typical reserve amortization requirements for the first half of 2018, causing FPL to initially earn below our 11.6% target regulatory ROE.

We expect FPL to earn a regulatory ROE towards the middle of a range of roughly 10.4% to 10.8% in the first quarter and roughly 10.7% to 11.1% in the second quarter before returning to more normal levels in the third and fourth quarter, all on a trailing 12-month basis and subject to our normal caveats.

So while this will result in some lumpiness in our quarterly expectations, we do not expect it to impact our full year results.

During the fourth quarter, FPL was required to revalue its deferred income tax liabilities to the new 21% corporate income tax rate.

The majority of the reduction in income tax liability, totaling approximately $4.5 billion, has been reclassified to a regulatory liability that we expect will be amortized over the underlying assets' remaining useful lives.

Regulatory capital employed increased by approximately 10.3% for 2017 and was the principal driver of FPL's adjusted EPS growth of 10.2% for the full year.

FPL built upon key successes from 2016, again being recognized as the most reliable electric utility in the Southeast.

At the same time, FPL's typical customer bill has remained well below both state and national averages.

FPL's capital expenditures were approximately $1.5 billion in the fourth quarter, bringing its full year capital investments to a total of roughly $5.3 billion.

Each of our ongoing capital deployment initiatives continues to progress well.

We were pleased to complete construction of the first 4 74.5-megawatt solar energy centers, governed by the Solar Base Rate Adjustment or SoBRA mechanism of the rate case settlement agreement, on schedule and under budget.

An additional 4 solar sites, totaling nearly 300 megawatts, are currently on track to begin providing cost-effective energy to FPL customers later this quarter.

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

This month, we completed the early retirement of the St.

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

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

Additionally, progress on the Dania Beach Clean Energy Center continues to advance through the regulatory approval process.

Continued smart investments such as these will allow FPL to deliver on its outstanding customer value proposition of low bills, high reliability and superior customer service, and are expected to support a compound annual growth rate in regulatory capital employed of approximately 8% from the start of the settlement agreement in January 2017 through at least December 2021.

The economy in Florida remains healthy.

The current unemployment rate of 3.7% remains below the national average and near the lowest levels in a decade.

Florida's consumer confidence level remains near 10-year highs.

The real estate sector also continues to show strength, with new building permits remaining at healthy levels and the Case-Shiller Index for South Florida home prices up 4.4% from the prior year.

FPL's fourth quarter retail sales increased 0.5% from the prior year comparable period.

We estimate that weather-related usage per customer contributed approximately 1.2% to this amount.

On a weather-normalized basis, fourth quarter sales declined 0.7% as ongoing customer growth was more than offset by a decline in weather-normalized usage per customer.

For 2017, we estimate that FPL's retail sales benefited from a positive year-over-year impact of 1.7% from weather, which is partially offset by a decline of 0.9% as a result of the net effects of Hurricanes Matthew and Irma.

After accounting for these factors and the 2016 leap year impact, FPL's 2017 retail sales on a weather-normalized basis declined by 1.6%, which was primarily driven by a reduction in underlying usage per customer, partially offset by customer growth.

While the recent trend in underlying usage is below our long-term expectations, we have not yet drawn any firm conclusions.

We will continue to closely monitor and analyze underlying usage and will update you on future calls.

Modest changes in usage per customer are not likely to have a material effect on earnings while we operate under the current settlement agreement as we will adjust the level of reserve amortization utilization to offset any effect, which is expected to allow FPL to maintain its target regulatory ROE.

Let me now turn to Energy Resources, which reported full year 2017 GAAP earnings of $2.963 billion or $6.27 per share.

Adjusted earnings were $1.23 billion or $2.61 per share, reflecting roughly 12% year-over-year growth.

For the fourth quarter, Energy Resources reported GAAP earnings of $1.894 billion or $4 per share and adjusted earnings of $230 million or $0.49 per share.

This quarter's adjusted results excluded 2 items: a gain related to revaluing deferred income tax liabilities that I will discuss in a moment, and a charge associated with our Duane Arnold Energy Center.

For Duane Arnold, in the latter part of 2017, we concluded that it is unlikely that the facility's primary customer will extend the current contract after it expires in 2025.

Without a contract extension, we will likely close the facility at the end of 2025 despite being licensed to operate until 2034.

As a result, during the fourth quarter, Duane Arnold's book value and asset retirement obligation were reviewed, and an after-tax impairment of $258 million was recorded that reflects our belief it is unlikely the project will operate after 2025.

That being said, we will continue to pursue a contract extension that would enable Duane Arnold to continue operations.

Duane Arnold's contribution to Energy Resources net income has been and is expected to be negligible over the next several years.

As a result of tax reform, Energy Resources was required to revalue its deferred income tax liability to the new 21% corporate income tax rate.

This $1.925 billion reduction in income tax liability provided an income tax benefit during the fourth quarter, which has been excluded from adjusted earnings.

Based upon our strong banking relationships and our position as the #1 renewables developer, we remain confident that our access to tax equity will remain robust.

As an example, following the signing of the tax reform legislation, we were able to close our 4 remaining 2017 tax equity financings, totaling more than $1 billion in proceeds at economics substantially similar to what was expected before tax reform.

Energy Resources' contribution to adjusted earnings per share in the fourth quarter increased by $0.08 versus the prior year comparable period.

This primarily reflects contributions from new investments and increased contributions from our existing generation assets as a result of repowering, partially offset by lower contributions from our gas infrastructure business due to the absence of the Texas pipelines' earnout adjustment that was recorded in the fourth quarter of 2016.

Energy Resources full year adjusted earnings per share contribution increased $0.28 or approximately 12% year-over-year.

Growth was driven by continued new additions to our renewables portfolio, including the roughly 2,500 megawatts of new wind and solar projects that we commissioned in 2016, which are included in new investments during the first 12 months of their operation.

In total, new renewables investments added $0.67 per share.

Contributions from new natural gas pipeline investments added $0.10 per share.

Partially offsetting new investment growth was a decline of $0.11 per share in contributions from our existing generation assets, the majority of which is attributable to the sale of the Lamar, Forney and Marcus Hook natural gas-fired generating assets in 2016.

Contributions from our gas infrastructure business declined by $0.19 per share, $0.16 of which is attributable to the absence of the earnout adjustment that was recognized for the Texas pipelines in 2016.

All of the other effects had a negative impact of $0.19 per share, mostly driven by a year-over-year increase in interest expense.

Additional details are shown on the accompanying slide.

In 2017, Energy Resources advanced its position as the leading developer and operator of wind, solar and battery storage projects.

Since the last call, we have signed contracts for 736 megawatts of new renewables projects, including 512 megawatts of wind and 224 megawatts of solar.

With today's announced contracts, our 2017 and 2018 wind backlog is now nearly 2,000 megawatts.

With visibility to several hundred megawatts of additional projects for 2018, we continue to believe that we can achieve the range of expectations that we have previously provided for 2017 and 2018.

For 2019 and 2020, we are already just below the range of expectations that we have provided for solar.

And for U.S. wind, our current backlog is already almost half of the low end of our expected range.

Additionally, our total current backlog of almost 7,000 megawatts, including repowering for 2017 through 2020, is the largest for a 4-year period in Energy Resources' history.

The accompanying slide provides additional detail on where our renewables development program now stands.

Beyond renewables, 2017 was an excellent year for Energy Resources' natural gas pipeline activities.

During the year, both the Sabal Trail Transmission and Florida Southeast Connection natural gas pipeline projects successfully achieved commercial operation on budget and on schedule.

The Mountain Valley Pipeline also made excellent progress over the year, receiving its first limited notice to proceed from FERC earlier this week, and we remain on track to achieve a year-end 2018 commercial operations date.

Turning now to the consolidated results for NextEra Energy.

For the fourth quarter of 2017, GAAP net income attributable to NextEra Energy was $2.155 billion or $4.55 per share.

NextEra Energy's 2017 fourth quarter adjusted earnings and adjusted EPS were $590 million or $1.25 per share, respectively.

For the full year 2017, GAAP net income attributable to NextEra Energy was $5.378 billion or $11.38 per share.

Adjusted earnings were $3 -- $3.165 billion or $6.70 per share.

NextEra Energy's operating cash flow, adjusted for the impacts of certain FPL clause recoveries, storm costs and recoveries in the Indiantown acquisition, increased by almost 15% year-over-year.

During the fourth quarter, we were able to capitalize on the ongoing favorable market conditions and completed all of the refinancing initiatives we were considering as of the third quarter call.

These combined financings, which have roughly $165 million of after-tax NPV savings on a cash basis, resulted in net income reduction of approximately $33 million when they closed in the fourth quarter.

For the Corporate and Other segment, adjusted earnings for the full year decreased $0.15 per share compared to 2016, primary reflecting the impact of these refinancing costs.

Turning now to our financial expectations for NextEra Energy.

As Jim discussed, we are increasing the range of our adjusted EPS expectations and increase -- and extending our long-term growth outlook.

We now expect NextEra Energy's adjusted EPS compound annual growth rate to be in the range of 6% to 8% through 2021, off a revised base of the midpoint of our new 2018 range, or $7.70 per share.

Additional details of our revised expectations are shown in the accompanying slide.

For 2018, while we target the new $7.70 midpoint of our range, we expect that the majority of the growth will come in the second half of the year.

As I mentioned earlier, in the first half of the year, FPL is expected to earn below its regulatory ROE of 11.6% as we do not expect that the tax savings will immediately offset our typical reserve amortization requirements.

This will present a headwind to adjusted EPS growth during the first quarter, with stronger growth expected for the balance of the year as the regulatory ROE on a trailing 12-month basis increases towards our target 11.6% level by the second half of the year.

During the period of our financial expectations, we expect the interest on all NextEra Energy's debt to continue to be fully tax-deductible at the 21% federal corporate income tax rate despite the limit on interest deductibility in the tax reform legislation.

As a reminder, due to the NEP governance changes that we implemented in 2017, NextEra Energy is required to deconsolidate NEP from its financial statements beginning January 1, 2018.

These changes will be reflected in our first quarter financial results.

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

We expect the board of NextEra Energy to determine the dividend policy for beyond 2018 at our next regularly scheduled board meeting in February, and we will make an announcement about the outcome of that -- of their decision at that time.

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.

Yesterday, the NEP board declared a quarterly distribution of $0.405 per common unit or $1.62 per common unit on an annualized basis, up 15% from the comparable quarterly distribution a year earlier and at the top end of the range we discussed going into 2017.

Fourth quarter adjusted EBITDA and CAFD increased approximately 18% and 12% year-over-year, respectively.

For the full year 2017, adjusted EBITDA increased 16% while CAFD was up 11% from 2016.

In regards to the impacts of tax reform for NextEra Energy Partners, NEP recorded a $101 million charge related to revaluating its deferred income taxes to the new 21% corporate income tax rate in the fourth quarter.

The duration of NEP's income tax shield, which we have previously said is greater than 15 years, will remain better than 15 years following tax reform.

Additionally, the expectation that NEP runs a negative earnings and profit or E&P balance for at least the next 8 years also remains unchanged.

With no adverse impacts to NEP's tax shields or the ongoing strength of the renewables development environment, NEP remains well positioned to continue delivering on its unitholder value proposition.

NEP's fourth quarter 2017 adjusted EBITDA of approximately $199 million increased $31 million from a year earlier.

Fourth quarter CAFD was approximately $76 million, an increase of $8 million year-over-year, which was driven primarily by NEP's strong portfolio growth, with a relatively modest offset from higher fees.

Wind resource returned to normal after a weak third quarter as overall wind resource was 102% of the long-term average during the fourth quarter.

The appendix of today's presentation includes a slide with additional details regarding 2017 wind resource for the NEP portfolio.

For full year 2017, adjusted EBITDA and CAFD were $743 million and $246 million, up 16% and 11%, respectively, driven primarily by growth of the underlying portfolio.

Additional details are shown on the accompanying slide.

The NEP portfolio as of year-end 2017 supports adjusted EBITDA and CAFD run rates in line with the expectations we have shared previously for December 31, 2017.

Since the federal income tax rate declined from 35% to 21%, the resulting pretax value of NEP's tax credits, which are calculated by dividing 1 minus the tax rate, changes as well.

While tax reform impacts the calculation of NEP's adjusted EBITDA, it has no effect on cash available for distribution.

Our previous December 31, 2017, run rate expectations for adjusted EBITDA of $875 million to $975 million are now $830 million to $930 million as a result of this change.

The December 31, 2017, run rate range for CAFD of $310 million to $340 million remains unchanged.

Our previously announced December 31, 2018, run rate expectations, reflecting calendar year 2019 expectations for the forecasted portfolio at year-end 2018 for adjusted EBITDA of $1.05 billion to $1.2 billion are now $1 billion to $1.15 billion as a result of tax reform.

The December 31, 2018, run rate range for CAFD of $360 million to $400 million is unchanged.

As a reminder, our expectations are subject to our normal caveats and are net of anticipated IDR fees as we treat these as an ongoing operating expense.

From an updated base of our fourth quarter 2017 distribution per common unit at an annualized rate of $1.62, we continue to see 12% to 15% per year growth in LP distributions as being a reasonable range of expectations through at least 2022.

We expect the annualized rate of the fourth quarter 2018 distribution that is payable in February 2019 to be in a range of $1.81 to $1.86 per common unit.

Tax reform has highlighted several optimization opportunities within NEP's international portfolio, which we continue to evaluate.

One such opportunity that we are exploring is the potential sale of the Canadian portfolio, which could enable the partnership to recycle capital back into U.S. assets, which benefit from a longer federal income tax shield, allowing NEP to retain more CAFD in the future for every dollar invested.

We would only execute on such a transaction if it were accretive to NEP's long-term growth runway to do so, potentially positioning the partnership to extend its financial expectations and need for common equity.

If we decide to move forward, we will update you on the progress of our efforts over the coming months.

With the IDR restructuring, governance enhancements, financing flexibility, competitive cost of capital and visible prospects for future growth in place, we are pleased with NEP's execution during 2017.

Heading into 2018 and beyond, NEP is as well positioned as it's ever been to deliver its long-term financial expectations and best-in-class investor value proposition.

That concludes our prepared remarks.

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

(Operator Instructions) We'll take our first question from Stephen Byrd with Morgan Stanley.

I wanted to maybe hit first on the last thing, John, that you talked about on NextEra Energy Partners in terms of the -- a potential for sale of the Canadian portfolio.

I'm sorry, I didn't quite follow sort of the potential benefit of that and how to think about that, what would the rationale be in terms of tax reform?

Yes.

We are looking at -- as a result of tax reform, Stephen, we are looking at some optimization opportunities around our international portfolio.

There is a difference between the federal income tax shield in the U.S. and in Canada after the results of tax reform have come through.

So this has pinpointed a potential capital recycling opportunity, where we may be able to sell the assets in the Canadian portfolio and then use those proceeds to reinvest either in third-party M&A opportunities or acquisitions from Energy Resources or to support our organic growth program.

And by reinvesting those proceeds in the U.S., what that does is it has the effect of actually creating more CAFD for every dollar invested.

And because of that, it puts us in a position where we could extend our runway, our financial expectations and extend the need for common equity.

So it's kind of a very interesting opportunity that we continue to evaluate here internally.

Okay, understood.

That makes a lot of sense.

At the beginning, you all mentioned some of the changes at the rating agencies in terms of targeted ratios.

I just want to make sure I understood that properly.

Given the most recent change from Moody's that you mentioned, moving from 20% to 18%, so long as the -- if there was a mix of the regulated assets in the 70% range, if -- am I to understand that if you have that kind of business mix, that, that would result in additional leverage capacity over the $5 billion to $7 billion?

Did I get that right?

Yes.

So let's walk through it.

So right now, here's the state of play.

We are at 23% FFO to debt with S&P.

We're currently at 20% CFO to debt with Moody's.

Moody's has said that we have an opportunity to move down from 18% to 20% if we -- or I'm sorry, from 20% to 18% if we're able to further improve our regulated business mix up to 70%.

S&P, though, is still the gating metric.

So S&P, we feel like if we could improve our regulated mix to right around the same range that Moody's is targeting, that would also result in a reduction to the S&P credit threshold.

So yes, that would create additional balance sheet capacity.

But right now, the $5 billion to $7 billion of balance sheet capacity we described, that's tethered to where we stand today, which is 23% at S&P and 20% at Moody's, with the opportunity to further improve upon that $5 billion to $7 billion of excess balance sheet capacity if we're able to make a slight improvement in our regulated business mix for both agencies.

That's very clear.

And then maybe just lastly on the utility business.

In terms of tax reform, I just wanted to check whether that has any impacts on your net rate base growth.

I was wondering whether it might increase your rate base growth or if you think your overall sort of rate base position over time is similar to sort of where it's been in the past pretax reform.

Yes, no.

It does impact our rate base.

Again, one of the main impacts of tax reform is for rate-regulated utilities, customers and shareholders benefit because we were able to preserve in the final outcome of tax reform the ability to fully deduct interest at the utility level, but that was made as a compromise in exchange for no longer being able to take immediate expensing at the utility.

So if you can't take immediate expensing at the utility, it has the impact of lowering our deferred tax liability, which is actually 0 cost equity in our capital structure.

So if that goes down, it's just more equity that we're able to put into the business, which has the effect of increasing the rate base growth over time.

And we'll take our next question from Steve Fleishman from Wolfe Research.

So just a couple of questions.

On the excess capital, the $5 billion to $7 billion, so just to clarify, in your plan on growth rate, you're just effectively keeping that as cash on the balance sheet for now, it's not being put into buybacks or any investment, it's just extra available cash?

Yes.

Exactly, Steve.

We think of it as excess debt capacity that we have on the balance sheet.

It is not utilizing that excess balance sheet capacity.

It's not in our current financial expectations.

It's really a cushion and upside.

So if later on, we wanted to explore 1 of 3 options, which one of which could be a buyback; another could be something in the regulated M&A space; or third, incremental capital investment opportunities around the 2 main businesses, those are opportunities to utilize that excess balance sheet capacity.

Okay.

Second question, just a quick detail.

So in your 2018 guidance, it's up about $0.65 from prior midpoint.

So $0.45 of that is tax.

Is there any particular item that represents the other $0.20?

Yes.

It's pretty simple.

What we did is we took the $6.70, and we just said, "Look, we're going to assume we're going to grow $6.70 at 8% and then add on $0.45." So really, that extra $0.20 is roughly that additional 8% off the $6.70.

Okay.

And that's just all the business?

Okay.

Yes.

And targeting the midpoint, Steve, of the $7.70 in '18.

Great.

And then can you give us a sense against these S&P, Moody's metrics, kind of where are you with tax reform?

Because we have your metrics as of now, but it doesn't include with the tax reform changes in terms of FFO to debt.

Yes, no.

Yes, we do not expect tax reform to have an impact on where the metrics currently stand.

So what I just told you takes into account tax reform.

Okay.

And then just lastly, on NEP.

So in terms of the communication here, the Canadian transaction might be an upside to runway and growth runway, and then you're still just assuming the NEE portfolio as a drop-down as of year-end '16.

So anything you've done '17 and plan to do through 2020 would be additional potential growth for NEP?

Exactly.

I mean, Steve, NEP has terrific visibility into future growth because of that, because if you locked our portfolio down as of the end of '16, consistent with what we said at the investor conference, that locked-down portfolio as of the end of '16 was enough to support NEP's growth, 12% to 15% through 2022.

And so what we've been able to add since then is incremental to that.

And on the Canadian portfolio, we would only do that -- to be very clear, we will only do that transaction if it is incrementally accretive to our long-term growth runway and puts us in a position to extend our financial expectations and potentially our need for common equity.

We'll take our next question from Michael Lapides from Goldman Sachs.

Two questions.

One, with the onetime -- and Jim, just curious, how you're thinking about this and how you and the management team will present to the board because it's obviously a board decision.

With the onetime step-up in earnings guidance for 2018, how are you thinking about the dividend and whether there's a similar kind of onetime step-up in the dividend and then continued growth from there?

So Michael, as you said, it's a board decision.

We have been talking about some various options over the last couple of months.

When we -- in 2015, when we set the 12% to 14% growth rate through at least 2018, the "at least" was not a -- that was not a mistake in 2 words that we put in front of that.

And so we're going to be reviewing a variety of different options.

Obviously, earnings are stepping up with the midpoint at $7.70, something like 15%.

So we will have some room from a payout ratio standpoint.

And we have a lower payout ratio than the rest of the industry does, and so we have some room there as well.

So I'm a big believer in returning cash to shareholders.

And so we'll be making a recommendation here in a few weeks, and we'll have an announcement sometime in February once we make the decision in our board meeting.

Got it.

And one quick follow-up, more strategic.

Post-tax reform, how does NextEra and how do you look at the M&A market in utilities?

Meaning, does tax reform make M&A more difficult for utilities?

Does it make it less difficult for utilities?

We've had a number of years where there's been just kind of an accelerated level of transactions.

Just want to kind of get your high-level views.

Yes.

Yes.

I think 2 things, Michael.

One is that it obviously takes a pretty important uncertainty off the table, right?

So you know at least what the rules of the world -- road are for how you finance any potential acquisition going forward and what the benefits are.

And then I would just say, secondly, I think you've seen the rating agencies put a variety of our peers on negative watch over the last couple of weeks because tax reform, all else being equal, if you're 100% regulated, puts stress on your FFO-to-debt ratios.

We've been very methodically moving our business mix to create balance sheet capacity and to improve our business mix over time.

And I think we're in kind of a unique position relative to the rest of our peers vis-à-vis our capacity.

And so that's obviously a positive for us.

That said, we're going to continue to be super disciplined about what we look at, and it will have to be accretive and will have to make strategic sense for us.

And that's -- as you've seen over the years, we've been very disciplined, and we haven't chased things for the sake of just getting them to close.

And so we'll -- that will continue to be how we approach M&A.

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

So just a follow-up question and then a new question.

On the -- your earnings were up 9%, the $0.65 that Steve Fleishman articulated, with $0.45 from tax.

If I'm just thinking about the components of the other $0.20, is part of that the increased earnings power from not having bonus depreciation in '18 and beyond and the resultant increase in earnings power at the utility?

And then if I do that math, clearly, the delta would come from better outcomes at Energy Resources ex tax reform.

And if so, what are you seeing that's ahead of the prior plan in Energy Resources that caused you to, whatever that component is, increase it by that amount?

Yes.

Really, what we were doing, again, is just rebasing ops.

So if you took $6.70 and you said what's the right midpoint for 2018, we've been telling investors we'd be disappointed not to be able to grow '18 at 8% off of '17, right?

And that's really your missing 20% or your missing $0.20 to get you to the $7.70 midpoint.

Then you add on $0.45 for tax reform, and tax reform primarily reflects the reduced corporate tax rate from 35% to 21% in Energy Resources.

A couple other things in there, a little bit of a deferred tax benefit at FPL as well, but that's all in the $0.45.

That's really how you get to $7.70 as the midpoint.

The midpoint for '18 is what we're targeting, and it's what we are then going to base our future growth expectations off of at 6% to 8%, off that 2018 $7.70 baseline going forward.

Great.

Second question is with regard to the explanation of what you're doing with regard to helping FPL customers on Slide 7. Would you mind just walking through the steps of what happened this year, how you utilized the reserve amortization to offset the Hurricane Irma costs and then how the reserve amortization will be replenished and then how that positions you to then avoid having to ask customers for more money for another 2 years?

Can you just -- apologize for asking, but if you could just take us discretely through those steps to understand this impact.

Yes, absolutely.

Really simply, we had a $1.3 billion regulatory asset on our books, and that asset was there because we anticipated having to charge customers $4 in '18, maybe $5.50 or so in '19 and '20.

And so that established a regulatory asset on our books for about $1.3 billion.

We then said, "Well, tax reform has occurred.

Here's an opportunity to immediately return tax savings to customers by utilizing surplus in the right way." I mean, the average savings to the customer is going to be about $250, that you can see an immediate rate reduction of $3.38 where Matthew rolls off on March 1 and potentially the ability to avoid a base rate increase up through 2022 -- I'll get to that in a minute.

But -- so how did we do it?

We wrote down the $1.3 billion.

We had sufficient surplus to offset the majority of that $1.3 billion, and it's a permitted use of surplus under our settlement agreement to do that.

That left roughly $50 million after tax that could not be recovered from surplus.

We are taking that against -- excluding that from adjusted earnings as a tax reform-related item.

And then as you go forward, on the second part of your question, since we start with a 0 reserve amortization balance, we're able to replenish that over time through the tax savings that we get through the -- from the reduction in the federal income tax rate of 35% to 21%.

And instead of immediately returning or flowing that savings to customers over a much longer time, as you amortize that benefit out, this is a way to get the savings into customers' pockets immediately.

So that's how that works.

We would expect to end 2020 with a reserve amortization balance that would be sufficient to potentially allow us to stay out of a rate case for up to 2 years.

We'll take our next question from Julien Dumoulin-Smith from Bank of America.

So I wanted to ask real quickly, can you comment real quickly on the payout ratios here?

And just related thinking on that, I heard your earlier commentary about evaluating kind of the pace of EPS growth, but can you give us a little bit of a sense or a way to think about eventual payout ratios under the new forecast?

Has it moved at all?

I suppose that could give us a little bit of a sense on how you're thinking about this, if it's changed.

So Julien, I think what I said is probably all I'm prepared to say.

As we said, it's a board decision.

Our current payout ratio is -- the industry average payout ratio is around 65%.

Our current payout ratio is below that and is -- now, with the new rebasing that we've done in 2018, will be quite below that.

And when we -- and as I said earlier, I'm a big believer in returning cash to shareholders.

We are discussing options with the board right now, and we'll have an announcement on it in a few weeks.

Got it.

All right, excellent.

And then also a cash flow question real quickly if you can.

As you think about sort of the financing benefits from 100% expensing with tax reform as well as, I imagine, some benefits in terms of equipment costs, how does that change your financing plan on the near side?

If you could just talk about that a little bit and maybe discretely break it out.

And then at the same time, on the equipment side, how has that changed your outlook for '21 and even '22 at this point in terms of the near business trajectory?

Yes.

I mean, 2 things I'll say about that.

First of all, we're not limited in terms of our interest deductibility, so it really doesn't change a whole lot the way we would approach financing those businesses.

We will continue to expect tax equity dollars to be available.

Again, we have always had a first call on the tax equity market.

So we intend to finance the Energy Resources renewables build in much of the same way as we have in the past.

In terms of tax savings and its impact on the renewables business, a lot of those tax savings from manufacturers in particular, I mean, we would expect to hopefully see some benefit and reduced prices on the equipment side as a result of the lower taxes that they will be paying.

Armando, I don't know if you have anything you want to add to that.

No.

I think I'll -- I mean, I think you said this in a couple of times today.

Things are going well at Energy Resources, and there's nothing really that happened in tax reform that upsets our plans going forward.

I mean, we feel really good about Energy Resources in that.

But perhaps to clarify, in terms of wind equipment pricing itself, how much is that -- how much are you realizing the benefits that I suppose others are talking about?

And how has that changed your own views on '21 to '22?

Clearly, you extended the outlook by 1.

Yes.

I mean, I think what we have said is and what is in Jim's remarks, we saw a 30% reduction last year, as much as 10% going forward.

Tax reform could have some incremental benefits probably on top of that.

As you get out there, we will certainly, as always, try to squeeze our supply chain to pass those benefits onto us.

I mean, this is a competitive space.

In order to be competitive, if you're on the equipment side, and deliver the lowest price possible while retaining your profit margin, you're probably going to be expected to relay most of those tax benefits onto your customer if you want to be competitive.

And Julien, just one other thing.

When we talked about 30% and 10%, that's cost per kilowatt hour or cost per megawatt hour.

And we would expect that -- we'd expect the -- that's the way we think about it, and that's how we -- it's not just turbine price, it's wind capture, it's balanced plant reduction and costs, it's all of those things.

And this concludes today's presentation.

We thank you for your participation.

You may now disconnect.