新世紀能源 (NEE) 2018 Q1 法說會逐字稿

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Thank you, Bryan.

Good morning, everyone, and thank you for joining our first quarter 2018 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 and the comments made during this conference call, in the Risk Factors section of the accompanying presentation on our latest reports and filings with the Securities and Exchange Commission, each of which can be found in 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 John.

Thank you, Matt, and good morning, everyone.

NextEra Energy delivered strong first quarter results, and is off to a solid start towards meeting its objectives for the year.

Adjusted earnings per share increased almost 11% against the prior year comparable quarter, reflecting successful performance at both Florida Power & Light and Energy Resources.

FPL increased earnings per share $0.07 from the prior year comparable period.

Regulatory capital employed grew approximately 12.9% year-over-year, and all of our major capital initiatives remain on track.

During the quarter, FPL successfully commissioned nearly 600 megawatts of cost-effective solar projects under the Solar Base Rate Adjustment, or SoBRA, mechanism of our settlement agreement as well as the largest combined solar-plus-storage project in operation in the United States.

Additionally, the Florida Public Service Commission unanimously approved FPL's petition for determination of need for the Dania Beach Clean Energy Center, further advancing the roughly 1,200-megawatt project through the regulatory approval process.

FPL continued to deliver on its best-in-class customer value proposition of low bills, high reliability and outstanding customer service.

As announced on our last call, FPL was able to pass the benefits of tax reform back to customers immediately by foregoing recovery of the $1.3 billion in surcharges related to Hurricane Irma.

And as a result, the average of 1,000 kilowatt hour residential bill was reduced by $3.35 per month beginning March 1, as the surcharge related to Hurricane Matthew rolled off.

FPL's typical residential bill is now nearly 30% below the national average, and the lowest among all of the Florida IOUs.

Our ongoing efforts to invest in a stronger and smarter grid to further improve the already outstanding efficiency and reliability of our system resulted in FPL delivering its best ever service reliability in 2017, ranking it among the top of all major utility companies in Florida.

At Energy Resources, the lower federal income tax rate and increased contributions from our repowered wind projects helped drive growth for the quarter.

Consistent with what we have previously characterized as the best renewables development period in Energy Resources' history, we had one of our most successful quarters of new wind and solar generation origination, adding more than 1,000 megawatts of projects to our backlog.

We were also pleased with the progress of our natural gas pipeline development efforts, with MVP commencing construction and announcing its first expansion opportunity off the mainline pipe, which I will discuss in more detail in a moment.

At this early point in the year, we are very pleased with our progress at both FPL and Energy Resources.

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

For the first quarter of 2018, FPL reported net income of $484 million or $1.02 per share.

Earnings per share increased $0.07 or approximately 7% year-over-year.

As a reminder, 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 of 2017, FPL utilized its remaining available reserve amortization to offset nearly all of the expense associated with the write off of the regulatory asset related to Irma cost recovery, ending the year with a $0 reserve amortization balance.

Consistent with our expectations, the tax savings generated during the first quarter did not fully offset the reserve amortization required to achieve our target regulatory ROE of 11.6%.

As a result, our reported ROE for regulatory purposes will be approximately 11.2% for the 12 months ended March 2018.

This is above the ROE expectations we shared on our fourth quarter earnings conference call and is due to warmer-than-normal weather and reduced O&M expenses driven by our continued focus on cost management.

After a strong quarter, we now expect FPL to achieve its target regulatory ROE of 11.6% either late in the second or early in the third quarter on a trailing 12-month basis and subject to the usual caveats.

Based upon our weather-normalized sales forecast and current CapEx and O&M expectations, we expect to begin partially restoring the reserve amortization balance through tax savings later this year and continue to expect that FPL will end 2020 with a sufficient amount of surplus to potentially avoid a base rate increase for up to 2 additional years.

Operating under the current base rate settlement agreement would create further customer benefits by potentially avoiding a base rate increase in 2021 and 2022.

The Florida Public Service Commission has opened separate dockets to address tax reform for each of the Florida investor-owned utilities, including FPL.

We expect hearings to occur in August of this year, and look forward to working with the FPSC and other interested parties to further explain how FPL's prompt actions within the terms of the settlement agreement benefit customers.

Regulatory capital employed grew approximately 12.9% year-over-year, and all of our major capital initiatives remain on track.

As a reminder, due to tax reform, FPL will no longer take bonus depreciation of future investments, which is expected to result in an increase to investor sources of capital as the contribution from accumulated deferred income taxes decreases over time.

Therefore, beginning this quarter, our presentation of FPL's regulatory capital employed is net of accumulated deferred income taxes, which is treated as 0 cost equity in our capital structure, as this more appropriately reflects the growth in FPL's earnings.

In the appendix of today's presentation, we have provided a reconciliation of our historical numbers to our revised methodology.

Turning to our development efforts, all of our major capital projects at FPL are progressing well.

FPL's capital expenditures were approximately $1.2 billion in the quarter, and we expect our full year capital investments to be between $4.9 billion and $5.3 billion.

Adding to the nearly 300 megawatts of solar projects that were placed in service in January, during the quarter, we were pleased to complete construction on schedule and under budget of the next 4 74.5-megawatt solar energy centers developed under the SoBRA mechanism of the rate case settlement agreement.

The 8 solar plants that entered service in 2018 are projected to generate more than $100 million in total savings for FPL customers during their operating lifetime.

FPL's 10-year site plan that was filed with the public service commission earlier this month included plans for more than 3,200 megawatts of additional solar projects across Florida over the coming years, including the approximately 600 megawatts that remain under the SoBRA mechanism of our settlement agreement.

To support what continues to be one of the largest-ever solar expansions in the U.S., FPL has already secured almost 6 gigawatts of potential sites.

During the quarter, we also deployed the first 2 projects under FPL's 50-megawatt battery storage pilot program, pairing battery systems with existing solar projects.

The 4-megawatt battery system with 16-megawatt hours of storage capacity was deployed at the Citrus Solar Energy Center, representing the first large-scale application of DC-coupled batteries at a solar plant in the U.S. and enabling the facility to deliver more energy to FPL's grid.

Additionally, FPL installed a 10-megawatt battery project with 40-megawatt hours of storage capacity at the Babcock Ranch Solar Energy Center, creating the country's largest combined solar-plus-storage project currently in operation and highlighting FPL's innovative approach to further enhance the diversity of its clean energy solutions for customers.

FPL will install additional battery storage projects to further enhance the reliability and efficiency of its system and to position FPL for future deployments as battery costs continue to decline over the coming years.

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

As I previously mentioned, in March, the Florida Public Service Commission granted the determination of need for the Dania Beach Clean Energy Center.

The approximately $900 million project is expected to begin operation in 2022 and generate nearly $350 million in net cost savings for FPL customers, while reducing air emissions by roughly 70% compared to the existing power plant.

We continue to make significant progress with FPL's purchase of substantially all of the assets of the City of Vero Beach's municipal electric system, receiving approval for the transaction from the Orlando Utilities Commission and all 19 member cities on the FMPA Board.

The transaction is now undergoing FPSC review.

Pending commission approval, this transaction would represent what we believe is the first privatization of a vertically integrated electric municipal utility in the United States in more than 25 years and is reflective of FPL's collaborative efforts with the city, local and regional leaders as well as other state authorities to benefit Vero Beach's more than 34,000 customers with FPL's best-in-class value proposition.

FPL's continued smart investment opportunities are expected to support the compound annual growth rate and regulatory capital employed of approximately 9% from the start of the settlement agreement in January 2017 through at least December 2021, while further benefiting our customers.

This compound annual growth rate is higher than we have previously discussed as it now is net of declining contribution from accumulated deferred income taxes, for the reasons I mentioned earlier, which more appropriately reflects the growth in FPL's earnings.

The Florida economy continues to show healthy results and is among the strongest in the nation.

The current unemployment rate of 3.9% is near the lowest levels in a decade and remains below the national average.

The real estate sector continues to grow with average building permits in the Case-Shiller Index for South Florida up 7.4% and 3.8% respectively, versus the prior year.

Florida's consumer confidence level also remains near a 10-year high.

FPL's first quarter retail sales increased 2.9% from the prior year comparable period, and we estimate that approximately 1.3% of this amount can be attributed to weather-related usage per customer.

On a weather-normalized basis, first quarter sales increased 1.6% with continued customer growth and an estimated 0.7% increase in weather-normalized usage per customer both contributing favorably.

While the growth in underlying usage is a reversal from the trend in recent quarters, as we have often discussed, this measure can be volatile on a quarterly basis.

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

Let me now turn to Energy Resources, which reported first quarter 2018 GAAP earnings of $3.926 billion or $8.26 per share and adjusted earnings of $386 million or $0.81 per share.

This quarter's GAAP results reflect certain impacts that I would like to take a moment to summarize.

As we have previously discussed, due to the increased governance rights that were granted to NEP's LP unitholders, NEP was deconsolidated from NextEra Energy's financial statements beginning in January 2018.

NextEra Energy now accounts for its investment in NEP on the equity method of accounting, and as a result of this change, recognized an approximately $3 billion after-tax gain or $6.32 per share during the first quarter of 2018 from recording its investment in NEP at fair value.

The projects owned by NEP will continue to provide value to NextEra Energy over their operating lives through NextEra Energy's continued investment in NEP.

Accordingly, NextEra Energy will exclude this initial gain from adjusted earnings and realize that as related projects provide an economic benefit to Energy Resources, which offsets the higher depreciation and amortization resulting from recording the investment in NEP at fair value.

Beyond deconsolidation, in the first quarter of 2018, Energy Resources remeasured its tax equity arrangements or differential membership interests, resulting in a net after-tax gain of $484 million to reflect the impact of the newly enacted tax rates.

Since this remeasurement is not expected to have an economic impact on our underlying tax equity transactions, we are excluding these tax reform-related impacts from adjusted earnings and reflecting the benefit over the original term, which we believe better reflects the economic substance of the transactions.

Additional detail on these and other changes are included in the appendix of today's presentation.

The Energy Resources contribution to adjusted earnings per share increased by $0.05 or roughly 7% from last year's comparable quarter.

With approximately 1,600 megawatts of repowered wind projects being commissioned in 2017, contributions from existing generation assets increased by $0.06 per share primarily as a result of increased PTC volume from these repowered projects.

Contributions from new investments declined by $0.17 per share as the prior comparable quarter benefited from the timing of tax incentives on certain projects.

For the full year, we expect contributions from new investments to be slightly positive.

Contributions from our gas infrastructure business, including existing pipelines, increased by $0.06 year-over-year.

As expected, the reduction in the corporate federal income tax rate was accretive to Energy Resources, increasing adjusted EPS by $0.12 compared to 2017.

All other items decreased results by $0.02 per share.

Additional details are shown on the accompanying slide.

As I mentioned earlier, the Energy Resources development team continues to capitalize on what we believe is the best renewables development environment in our history, adding 667 megawatts of new wind projects and 334 megawatts of new solar projects to our backlog since the last call.

All of these 1,001 megawatts added to backlog, 34 megawatts of the solar projects and 247 megawatts of the wind projects, are for delivery this year.

The accompanying chart updates information we provided on last quarter's call, but our overall expectations have not changed.

For 2019 and 2020, we are now within the range of expectations that we have provided for solar.

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

We continue to track well against the total development forecast for 2017 through 2020 that we shared at our investor conference last year.

And with returns on energy resources renewables projects consistent with what we have previously shared, our backlog continues to track against the assumptions supporting our previously announced financial expectations.

One of the best quarters of new renewables origination in our history is a reflection of the increasingly strong economic demand for wind and solar, which will continue to benefit from additional retirements of coal, nuclear and less fuel-efficient oil and gas-fired generation units, creating significant opportunities for renewables growth going forward.

Combined with our competitive advantages in renewables development, we expect this will help drive well into the next decade, building on the nearly 300 megawatts of renewables projects we have already signed for beyond 2020.

In addition to the progress we made with battery storage projects at FPL, yesterday, Energy Resources commissioned its first solar-plus-storage project.

These projects represent the beginning of 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 nearly firm generation resource, all at a lower cost than that required to operate traditional inefficient generation resources.

Beyond renewables, we were pleased to begin construction on the Mountain Valley Pipeline during the first quarter, and we continue to expect a December 2018 in-service date.

Earlier this month, with project partner, EQT Corporation, we also announced the MVP Southgate project, a proposed expansion pipeline that will receive gas from the MVP mainline in Virginia and extend south to new delivery points in central North Carolina.

The project, which is anchored by a firm capacity commitment from PSNC Energy, commenced a binding open season in order to provide additional market participants an opportunity to subscribe to the project.

As currently designed, the project has a targeted in-service date of the fourth quarter 2020, subject to FERC and other regulatory approvals.

We look forward to providing additional details following evaluation of the open season results.

Turning now to the consolidated results for NextEra Energy.

For the first quarter of 2018, GAAP net income attributable to NextEra Energy was $4.428 billion or $9.32 per share.

NextEra Energy's 2018 first quarter adjusted earnings and adjusted EPS were $919 million and $1.94 per share, respectively.

Adjusted earnings from the corporate and other segment increased $0.07 per share compared to the first quarter of 2017 primarily due to certain favorable tax items and lower interest expense.

Based on our first quarter performance at NextEra Energy, we remain comfortable with the expectations we have previously discussed for the full year, and we'll continue to target the $7.70 midpoint of our adjusted EPS range.

Longer term, we continue to expect NextEra Energy's adjusted EPS compound annual growth rate to be in a range of 6% to 8% through 2021 off our 2018 expectation of $7.70 per share, all subject to our usual caveats.

We continue to believe that we have one of the best growth opportunity sets in our industry, and 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 2021.

Operating cash flow is expected to grow roughly in line with our adjusted EPS compound annual growth rate range from 2018 through 2021.

As we announced in February, the board of NextEra Energy approved the 2-year extension of the existing dividend policy of targeting 12% to 14% annual growth in dividends per share.

This extension is expected to result in a growth rate in dividends per share of 12% to 14% per year through at least 2020 off a 2017 base of $3.93 per share.

The board's extension of this policy reflects the continued strength of adjusted earnings and operating cash flow growth at NextEra Energy.

With a payout ratio of only 59% at the end of 2017, below the peer average of roughly 65%, and one of the strongest balance sheets in our sector, we remain well positioned to support the dividend policy going forward.

Similar to the recent recognition of NextEra Energy's enhanced business risk profile by S&P and Moody's, earlier this month, Fitch announced that it was widening its sustained FFO adjusted leverage thresholds from 3.5x to 3.75x to 4x to 4.25x.

At our current rating agency thresholds, we expect to have $5 billion to $7 billion of excess balance sheet capacity through 2021.

We continue to expect that if the regulated contribution to our business mix improves to roughly 70%, that we would receive a further reduction to our current rating agencies thresholds from S&P and Moody's, creating additional balance sheet capacity.

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

In summary, after a strong start to the year, we continue to remain as enthusiastic as ever about NextEra Energy's future prospects.

At FPL, we continue to focus on delivering our best-in-class customer value proposition through operational cost-effectiveness, productivity and making smart long-term investments to further improve the quality, reliability and efficiency of everything we do.

Energy Resources maintains significant competitive advantages to capitalize on the expanding market for renewables development and continues to make strong progress on its natural gas pipeline development and construction efforts.

With the strength of our credit ratings and significant balance sheet capacity, NextEra Energy is uniquely positioned to drive long-term shareholder value.

We remain intensely focused on execution and on extending our long-term track record of delivering value to shareholders.

Let me now turn to NEP.

NextEra Energy Partners is also off to a strong start to 2018, with significant year-over-year growth in both adjusted EBITDA and cash available for distribution, reflecting new asset additions during 2017 and outstanding underlying performance of the portfolio.

Yesterday, the NEP board declared a quarterly distribution of $0.42 per common unit or $1.68 per common unit on an annualized basis, up 15% from a year earlier.

Earlier this month, NEP announced the sale of its Canadian portfolio of wind and solar projects to Canada Pension Plan Investment Board.

The transaction, which was completed at an attractive 10-year average CAFD yield of 6.6%, including the net present value of the O&M origination fee, highlights the significant underlying value of NEP's portfolio and is expected to be accretive to long-term growth, as I will discuss more in a moment.

We continue to expect that NEP will have no need to sell common equity until 2020 at the earliest, other than modest issuances under the ATM program, and have taken further steps to enhance our financing flexibility by opportunistically hedging our exposure to future interest rate volatility.

Overall, we are pleased with the strong start to 2018 and remain focused on continuing the success going forward.

As I just mentioned, at the end of March, NEP entered into a definitive agreement with CPPIB for the sale of its 396-megawatt Canada wind and solar portfolio.

Total consideration for the portfolio is approximately USD 582 million, including the net present value of the O&M origination fee, subject to customary working capital and other adjustments, plus the assumption by the purchaser of approximately USD 689 million in existing debt.

The foreign currency exchange rate has been hedged for the transaction, which is expected to close in the second quarter of this year, subject to receipt of regulatory approvals and satisfaction of customary closing conditions.

When the agreement was executed in the first quarter, it accelerated payment by Energy Resources to NEP of an approximately USD 30 million note receivable, which was acquired by NEP with the Jericho wind project.

This note receivable is not included in the sale to CPPIB.

The sale price of the portfolio represents an attractive 10-year average CAFD yield of 6.6%, inclusive of the net present value of the O&M origination fee, highlighting the underlying value of NEP's renewable assets.

We expect to be able to accretively redeploy the proceeds into higher-yielding U.S. acquisitions from Energy Resources or third parties to support NEP's long-term growth.

With a lower effective corporate tax rate and a longer tax shield in the U.S. versus Canada, NEP can retain more cash available for distribution in the future for every $1 invested into U.S. assets, which in turn is expected to provide a longer runway for FPL -- for limited partner distribution growth.

As a result, today, we are pleased to announce that we are extending our financial expectations for NEP another year as we see 12% to 15% per year growth and per-unit distributions as a reasonable range of expectations through at least 2023.

Let me now review the detailed results for NEP, which reflect the outstanding operational and financial performance for the quarter.

Including the benefit from the acceleration of the Jericho note receivable that I just described, first quarter adjusted EBITDA was $258 million, and cash available for distribution was $95 million, up roughly 52% and 138%, respectively, against the prior year comparable quarter.

Excluding the impact of this payment, growth remains very strong, with adjusted EBITDA and cash available for distribution increasing approximately 34% and 63%, respectively, year-over-year.

Contributions from portfolio acquisitions were the principal driver of growth.

New projects added $49 million of adjusted EBITDA and $32 million of cash available for distribution.

Existing projects also contributed favorably primarily as a result of contracting activity at one of the Texas pipelines.

For the NEP portfolio, wind resource was also favorable at 105% of the long-term average versus 99% in the first quarter of 2017.

Cash available for distribution reflects $17 million of higher debt service due to the timing of payments related to the senior unsecured notes that were issued in the third quarter of last year.

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

Additional details are shown on the accompanying slide.

NEP's portfolio of long-dated amortizing project-level debt helps to limit interest rate exposure.

During the quarter, we were pleased to further mitigate potential interest rate volatility and enhance NEP's significant financing flexibility with a $5 billion interest rate hedge agreement.

Under the agreement, at any date until March 26, 2028, NEP has the flexibility to effectively enter into a 10-year interest rate swap at a fixed rate of 3.192% in any amount up to the $5 billion total.

Any unutilized balance as of March 26, 2028, will be cash settled, hedging rates at that time through 2038.

The swap, which is reflective of the long-term approach we continue to take with NEP, together with amortizing project-level debt, will help limit interest rate exposure going forward and is expected to help maintain NEP's relative cost of capital advantage compared to MLPs and other yieldcos.

NextEra Energy Partners continues to expect a December 31, 2018, run rate for adjusted EBITDA of $1 billion to $1.15 billion and CAFD of $360 million to $400 million, reflecting calendar year 2019 expectations for the forecasted portfolio at year-end 2018.

As I just mentioned, from a base of our fourth quarter 2017 distribution per common unit, at an annualized rate of $1.62, we now see 12% to 15% per year growth in LP distributions as being a reasonable range of expectations through at least 2023, subject to our usual caveats.

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

We are pleased with NEP's strong start to 2018.

We believe NEP continues to provide a best-in-class investor value proposition with the flexibility to grow in 3 ways: acquiring assets from Energy Resources, organically or acquiring assets from other third parties.

NEP's cost of capital and access to capital advantages, which have even further improved relative to other yieldcos and MLPs, position NEP well to support its growth going forward.

These advantages, combined with the stability of NEP's long-term contracted cash flows, backed by strong counterparty credits, favorable tax position and enhanced governance rights, leave NEP well positioned to meet its long-term financial expectations and enhance unitholder value.

That concludes our prepared remarks.

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

(Operator Instructions) Our first question today comes from Julien Dumoulin-Smith with Bank of America.

So I just wanted to follow up a little bit.

Clearly, there's been a lot of discussion out in the marketplace of late.

I'd just be curious, first, with respect to your balance sheet, can you elaborate a little bit more and perhaps define more precisely the additional balance sheet latitude that you alluded to from the rating agencies?

And then perhaps to the extent to which you can elaborate on acquisitions, how do you think about utilizing that additional latitude?

Do you think about maintaining a buffer, even kind of pro forma, any kind of acquisition?

Effectively, how much is this new dry powder or the cumulative dry powder that you have?

Yes.

So essentially the $5 billion to $7 billion results as a -- from taking our downgrade threshold metric with S&P to 23%.

And what we have said is that we have more latitude if we are further able to improve our regulated business mix.

So depending on the size of a potential opportunity, if we add more regulated business mix, that gets us close to 70% regulated.

That gives us an opportunity to move from 23% down to a lower amount with S&P, and to also further improve on our current downgrade threshold metric with Moody's, which is currently at 20%.

I'm not right now going to frame how much excess balance sheet capacity that actually creates for us.

But needless to say, it would provide more than an ample buffer going forward.

Julien, this is Jim.

The only thing I'd add to that is I think you asked how close to the thresholds would we ever run the business given an acquisition.

And I think 2 things about that: One is, is that we would never do anything that isn't accretive and doesn't make sense.

And we've been very disciplined about this, and we will continue to be disciplined.

And then secondly, we value a strong balance sheet and a -- and our strong credit ratings.

And we're not going to do anything that puts that at risk, which would include, I think, and I think you're seeing some of the implications of that in -- playing out in the sector this year with -- as a result of kind of unexpected cash flow impacts.

As a result of tax reform, folks have had a -- there's been some equity pressure and some balance sheet pressure on a lot of our peers.

And our thinking about how we manage our businesses is not to manage it on a razor's edge from a balance sheet capacity and credit strengthening standpoint either.

So it has to be accretive, and we're going to continue to have a very strong credit as a very important part of our strategy going forward.

Excellent.

Let me just pick up on that last point quickly.

Obviously, there's been a lot of movement in the midstream side of the sector as well.

You all have been very specific about looking at regulated opportunities given the additional balance sheet latitude afforded out of that.

But is midstream something that you all are kind of evaluating anew?

Or are the credit concerns there so pervasive that again, that largely remains off the radar screen in terms of what you are evaluating?

Yes.

I mean I think on the midstream side, midstream creates 2 potential opportunities.

But it has to be a midstream opportunity that fits within our profile.

Number one, we're very focused on greenfield.

We've seen a lot of success on the greenfield opportunities.

We mentioned the mainline -- main pipeline expansion opportunity that we have off of MVP, so we're very happy with the greenfield success that we're seeing there.

And given some of the struggles that we see in the MLP sector, I do expect us to continue to maintain a cost-of-capital advantage, whether it's on greenfield opportunities or on third-party M&A.

If we're looking at third-party M&A, we're always going to be picky at NextEra Energy based on what we look at.

We're going to want to see longer average term contract life.

We're also going to want to see higher credit quality.

You look at the pipes that we've developed, they are very high-quality pipes.

We would not want to dilute the portfolio that we currently maintain.

But as you look forward, certainly with pipeline opportunities, that does present chances for us perhaps at NEE and at NEP as well.

Don't forget that NEP enjoys a very favorable yield, particularly what's happened to the MLP as a result of the FERC decision that was handed down 3 or 4 weeks ago, and then also the higher yields that we see many of the yieldcos trade out.

So for us, we have terrific opportunities to grow NEP in 3 ways.

As I mentioned, one is buying assets from Energy Resources; two is organically.

But it's also encouraging to see the cost of capital advantage that I think we really maintain in both the MLP and the yieldco space.

And you can expect us to be opportunistic and disciplined as to how we evaluate those opportunities going forward.

Got it.

So for instance, using some of the latitude created from the Canadian sales, it wouldn't be crazy to think about that going towards a midstream opportunity at the NEP level.

Well, I mean, at the NEP level, we have a number of opportunities, right?

On -- from a Canadian standpoint, we have third-party opportunities that we can look at.

I wouldn't isolate those to MLP opportunities.

We have a lot of renewable opportunities.

We have other asset opportunities that we continue to look at as well.

And then, obviously, always have the opportunity to buy assets directly from NextEra Energy Resources.

Julien, let me just add to that, and then we're going to have to move on to the next question.

I think it would be highly unlikely that you would see NEP enter into a transaction in the midstream space, right?

I mean, we like what we have, but I think it would be highly unlikely that you would see us increase our exposure through an acquisition at NEP.

Our next question comes from Steve Fleishman with Wolfe Research.

So just on the NEP extension of the dividend growth, another year at least.

If you had to point to one driver of that, what would that be?

Yes, I mean, a couple of things: One is Canada, being able to execute the Canadian transaction at 6.6% yield, to be able to reinvest those proceeds in the U.S. under a more attractive tax regime at a higher yield, that's one opportunity.

And then also all the continued success that you continue to see at Energy Resources.

We are clearly in one of the best renewables environments that we've ever been in.

I think that's evidenced by the fact we had one of the best quarters of origination in our history, posting over 1,000 megawatts.

Okay.

And then just in terms of the -- maybe just to talk on the overall renewables market, I mean, there's just so many kind of high-level factors: the solar tariffs, the steel tariffs, things like that, just the core thesis of better economics and the like.

Is that -- is your whole kind of thesis still in place in terms of hitting the targets and then economics beyond 2020?

Yes.

No, it absolutely is.

I mean, first of all, we managed around the solar tariff impact.

We already bought forward our panel needs for '18 and '19, and now secured a good part of '20.

We announced the JinkoSolar opportunity, where we'll be an anchor tenant on that opportunity, buying about 2.7 gigawatts of panels from Jinko at attractive prices.

Because again, we are the anchor tenant on that facility.

So I feel very good about the mitigation steps that we've taken on solar panels.

I don't see that as being an impediment to growth for our portfolio going forward based on what we've been able to secure.

When you look at steel and the wind turbine, wind turbine doesn't really use that much steel.

I mean, the steel is in the tower.

The tower is all manufactured domestically.

And if you look at the blades themselves, there's just not a whole lot of steel there.

So not really much of a meaningful impact to wind.

And then when you look at solar, the solar panel itself doesn't contain aluminum or steel, just some in the racking.

That's a very small impact overall.

Then when you look at the economics of the renewable market today, we truly enjoy a competitive advantage that has not changed: the buying power that we have on the O&M side; the continued productivity that we see on reduced O&M cost, which is only benefits from having the largest renewables operation in North America, which is very scalable; the cost of capital advantage that we maintain.

We don't have to pursue expensive construction financing.

We can balance sheet finance our wind and solar build and then term it out with access to the tax equity market or project financing.

We have not seen anything on the tax equity side to suggest any compression that would affect our build.

Again, we have first call on that market.

If anything, we see tax equity prices fall, which has been a nice benefit.

And then the last piece is just you benefit by having a large portfolio because you get much higher (inaudible) correlated information as to new sites that you can build upon, which really helps with top line growth going forward.

And when you throw into the mix the expertise that we've developed on the battery side, I feel very good about the competitive advantages that we have on renewables.

Steve, just a second.

The only thing that John didn't cover was volume, really.

I mean, he covered all the points that we're seeing as really driving costs down, which are, obviously, helpful to the economics.

But the volume piece, I mean, there is a lot of volume, right, in the industry right now.

I mean, we are pricing some very large renewable projects at this point.

I don't think we've -- I'm sure we've never seen the volume out in the market that we're seeing.

And so it makes us pretty happy about the future.

Just, Armando, when you say volume, you mean large scale, like RFPs, so to speak.

Or...

Yes, there's just a lot of RFPs out in the market, both of the traditional utilities and C&I companies.

And we're pricing -- we continue to price projects in 2018, but we are going out as far as 2022 at this point in pricing projects.

Yes, and that's a good point that Armando brought up on volume, because the other point that I want to make is around capital deployment.

We are deploying as much capital as we have ever deployed in this business.

You guys have seen the numbers from our Analyst Day, $10 billion to $11 billion a year between both businesses.

And renewables, obviously, makes up a big piece of that.

We have not seen a change in the returns that we have previously communicated to investors.

I mean, we see unlevered IRRs in wind kind of high-single digits, unlevered in the high teens, low 20s; solar, a couple hundred bps below on the unlevered IRR and mid-teens on the ROEs.

And those are numbers we've been communicating to investors for a long time.

And because of all the competitive advantages that we have in the sector, notwithstanding tax reform, we've been able to make up for some of the impacts on bonus depreciation and preserving those returns.

Our next question comes from Greg Gordon with Evercore.

Can you just talk about the cadence of the earnings at NextEra and Energy Resources over the course of the year?

It is somewhat unusual for you guys to have a $0.17 drag in the first quarter from new developments.

I looked back at the last couple of years' worth of Q1 releases, just to sort of scan it, and it does look like an outlier.

So is there a unique sort of circumstances this year that's driving the shape of the earnings contribution this year?

Yes.

You got to -- one thing, I'll take you back just to January -- or the first quarter back in 2017.

We had a large solar project, our Blythe solar project, that was originally on CITCs.

For various reasons, we converted that over to ITCs for tax reasons.

That was captured all in the first quarter.

Typically, we would spread the ITCs on a project over a year.

But because that project's already been placed into operation, it all showed up in the first quarter.

But certainly in '17, nothing unusual.

Our ITC and PTC makeup was very similar to what you've seen for a number of years from Energy Resources.

But that ITC recognition event in the first quarter of 2017 just set up a bad comparison for new investment activity.

One other thing I should say, Greg, is the whole year is fine now.

I mean, when you look at the new investment activity for the year, it's fine.

Okay, I appreciate that.

Second question, one of the things you guys have not done is just have your focus expand to looking at or bidding on, at least you haven't publicly disclosed, any bids on offshore wind.

Nor have you expanded the breadth of your focus geographically outside of North America.

Can you comment as to why there isn't an opportunity on a risk-adjusted basis, either on offshore wind or outside North America that is attractive to you?

Yes, I'm going to turn that question over to Jim.

So Greg, just on offshore winds, we looked very hard at offshore winds 15 years ago and worked on a project off of Long Island, got very close on it.

I personally spent, when I was running NextEra Energy Resources at the time, personally spent a lot of time on the development on that project.

And fundamentally, development time lines are 5 to 10 years.

Permitting is uncertain.

It is a moon shot in terms of building, in terms of finding people who actually know what they're doing from a construction standpoint.

It's terrible energy policy, and then it's really expensive.

I mean, even in New England, for example, in the last RFP, Massachusetts turned down several projects that we bid at $0.05 for -- in solar.

And you can do -- let me tell you, offshore wind RFP in Massachusetts is not going to come in at $0.05.

It is just -- it's bad energy policy, and it's bad business.

And so we don't tend to do either of those things.

And so that's why we're not going to be doing offshore wind.

In terms of international, this industry has, honestly, a pretty lousy track record in international.

And we have plenty of things to keep us busy here in North America.

And we're going to continue to be focused in primarily in U.S. going forward, and we'll be able to continue to grow well just with that focus.

I think our investors are not really too excited about us doing anything outside of the U.S.

Next question comes from Michael Lapides with Goldman Sachs.

Just on FPL, can you rehash a little bit?

I may have lost you during the prepared remarks.

Are you effectively kind of raising your earnings expectations for FP&L and maybe the earnings growth rate off of 2017 actuals?

Well, let's back up just a minute.

So on FPL, because we had taken all the surplus against Irma, we expected depreciation expense to be higher, right, in the first quarter and the second quarter as well.

But we are replenishing our surplus balance at the same time through continued tax savings.

Now we were able to offset that higher depreciation expense at FPL through higher base revenues and reduced O&M expenses in the first quarter.

And so what that has allowed us to do is probably move up the timing of when we could perhaps achieve an 11.6% ROE on that business.

We had originally communicated in last call, that may not be until third quarter.

It looks more likely it could be late in the second quarter or early in the third quarter.

So things at FPL continue to progress a bit better than expected because of the improvements that we've seen in weather and in O&M.

And so should we assume kind of in your going-forward guidance, meaning not just 2018, beyond, that you stay in that 11.5%, 11.6% range in terms of earned ROEs?

And then, should we also assume that kind of, because there's no bonus depreciation, whatever your old rate base growth guidance pretax reform is, now it's actually a higher number?

Yes.

So a couple of things there.

I mean, first of all, the 11.6% is included in our financial expectations for 2018, the $7.70.

Nothing's changed with regard to the $7.70 target or with the financial expectations that we have communicated, growing 6% to 8%.

Disappointed not to be at the higher end off that -- off of that $7.70 target.

All that's really happened with -- you saw a little bit of an increase in the regulatory capital employed growth for the first quarter at the 12.9%, and we expect regulatory capital employed growth to be around 9% between 2017 and 2021.

That's really a factor of just backing deferred -- accumulated deferred taxes out of our rate base calculation.

And the reason that we've done that is deferred tax liabilities, which are 0 cost to equity, are actually going to decrease over time.

Because as you recall, with tax reform, FPL, and all rate-regulated utilities, are allowed to take full interest deductibility without being subject to the German thin cap rule of 30% of EBITDA and then 30% of EBIT after 5 years.

But in exchange for that, regulated utilities can no longer take immediate expensing.

Because FPL can no longer take immediate expensing, its book cash difference on taxes decreases, and so its deferred tax liability goes down, which means it's 0 cost to equity comes down.

So we just went ahead and pulled the accumulated deferred tax impact line out of our rate base since its 0 cost to equity.

That resulted in a slight uptick in the regulatory capital employed growth that you can expect for FPL at the 12.9%.

We have a walk on that in the Appendix.

Next question comes from Jonathan Arnold with Deutsche Bank.

Could I just ask on the market in the -- I know you don't identify individual counterparties.

But could you give us a sense of the breakdown in the new origination by customer type at all, whether utilities, munis, corporates, just some flavor there?

It's probably pretty close to 1/3, 1/3, 1/3.

I mean it's not going to be exactly there.

But I mean we had a -- we're being -- we're having more success in the C&I sector, I'd say, over the last 6 to 8 months then we had in the past.

We talked about that before, that while that was never going to be a really big sector for us, we needed to bring our market share up a little bit, and we've done that.

We're still very competitive on what I would call the IOUs.

That's a market that I think we do -- not I think, we do the best in, in terms of market share compared to the other markets.

But we're also seeing munis and co-ops that are buying.

And interestingly, in the comment I made before, it's the muni, co-op and large IOUs that are really reaching out further in the curve than the C&I sector, right?

When you're pricing the C&I sector, you're really pricing projects for this year or next year primarily.

And when you're pricing projects for the larger companies, we're now seeing -- we're pricing projects in 2022.

So it's -- I'm happy with all of the sectors and how we're doing.

And I'm really happy that we're seeing a lot of activity beyond 2020.

Of the 1,000 megawatts out of this quarter, is it roughly an equal breakdown?

It's definitely not equal, but I'd say it's probably 1/3, 1/3, 1/3, some -- it's not going to be 90 and 10.

Yes.

So that's what I was looking for, Armando.

And then, just want to -- I wanted to thank you for putting the portfolio slide back in on the projected numbers.

I'm just curious.

I noticed on the contracted renewables line for new investment, you're now mentioning in the footnote that, that includes net proceeds from selling development projects.

So was curious how much of the number is that -- is it a material amount?

And is that just things you already you announced?

Or are you anticipating further activity on that front?

Yes.

Jonathan, if you remember, I think it was last year, we announced the -- a transaction with a larger customer, which I think most of you folks know who that is.

It was around 1,500 megawatts.

And out of that 1,500 megawatts, 500 of it was going to be PPAs.

And then about 1,000 megawatts of it was going to be, what I would call, build-own-transfer projects.

Some of them were early-stage development rights projects, where we were going to flip the project prior to even ordering the turbines or doing any of the construction that was going to be done by the buyer.

And then also some build, own, transfer.

We'd actually build the project and then flip it.

We see that business in certain circumstances as a very good business for us and a continuing business for us.

Because what it could do is it can allow us to get more long-term contracted PPAs.

But if you have an opportunity to sell development rights on a project -- remember, we have a very large land bank, which we talked about in the past, close to 20 gigawatts, where we go out, we heat map the entire country, we secure land rights.

We have interconnection of key positions.

And we can take those pieces of property, which are actually good development sites, and sell them and earn roughly 20% of the NPV that we could earn on, projects that we built completely and that we own for its remaining useful life.

And on the build, own, transfer, you can build the project and not have to take any of the operational risk and sell it for an NPV at roughly 40% to 45% of what we could achieve if we held the asset through end of life.

So those are opportunities, typically with larger investor-owned utilities, that we will continue to evaluate and look at because they are good return, good NPV-producing opportunities for the overall business.

But let's not forget, the size of the renewable pie is as big as it's ever been.

And it's as big as it's ever been because coal and nuclear are very expensive.

We have a significant cost advantage over both coal and nuclear.

And also, an efficiency and cost advantage over lower-efficient oil-fire generation and gas-fire generation projects.

And so as we go forward, the bulk of our activity is always going to be signing PPAs and holding the asset through life.

But there can be some opportunities also around the build-own-transfer side, which will be very attractive as well.

We won't ignore those opportunities as they come forward.

John, I get why you're doing it, but I was curious if there's -- if you can calibrate how much of the 200 to 400 relates to that kind of thing for 2018.

And whether that's the deal that you signed last year or a new one?

Yes.

The reason I was giving the context, Jonathan, is that it's going to move around, right?

I mean because it's something that we will look at on an opportunistic basis, sometimes it'll be like what we had announced on a larger transaction last year where we were able to do the build, own, transfer in exchange for getting over 500 megawatts of long-term contracts out of that deal.

But when you look at our addressable market, it's -- I've always said, it's munis, co-ops, small- to medium-sized investor-owned utilities and larger investor-owned utilities that look to do a little bit of rate basing.

This provides a nice build-own-transfer opportunity for us as well, and then everything that we see on the C&I space.

So terrific growth opportunities we continue to see on the long-term contracted side of the business.

But sometimes, we are going to be opportunistic as part of our continuing business operation looking at build, own, transfers.

But it's going to -- I can't give you a flat number of, oh, expect this amount in any one year.

It's just going to change over time.

Was the deal you referenced from last year, was that booked last year?

Or was that sort of booked when the regulatory approval comes over this year perhaps?

This year.

So that's part of this year's number, but you're not going to -- you can't give us a sense of how much.

Yes, it's -- we'll make further announcements of it going forward.

But it's not going to be a material part of our earnings for the year.

The other thing, Jonathan, is we've sold projects every year for the last 15 years.

It's not going to be any bigger or less than it's ever been in the last 15 years as part of NextEra Energy Resources' net income.

It's going to move around, as John said, but it's not a big deal.

It's us making sure that we capitalize on the market.

And its terrific return on invested capital, and it's really good for shareholders.

Perfect.

So it's a modest thing and not changing that much.

This will conclude the question-and-answer session as well as today's conference.

Thank you for attending today's presentation.

You may now disconnect.