NextEra Energy, Inc.

Good morning and welcome to the NextEra Energy, Inc. and NextEra Energy Partners LPQ1 2019 earnings call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Matt Roscott, Director of Investor Relations. Please go ahead, sir.

Thank you, Jory. Good morning, everyone, and thank you for joining our first quarter 2019 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, Rebecca Chiava, Executive Vice President and Chief Financial Officer of NextEra Energy, John Ketchum, 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 Szilagyi, President and Chief Executive Officer of Florida Power & Light Company. Rebecca will provide an overview of our results, and our executive team will then be available to answer your questions. We'll 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 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 Rebecca.

Thank you, Matt, and good morning, everyone. Nexter Energy delivered strong first quarter results and is well positioned to meet its overall objectives for the year. Adjusted earnings per share increased approximately 12% year-over-year, reflecting successful performance across all of our businesses. SPL increased earnings per share 20 cents from the prior year comparable period. which was driven by continued investments in the business for the benefit of our customers. The roughly 1,750-megawatt Okeechobee Clean Energy Center, which is among the cleanest and most fuel-efficient power plants of its kind in the world, entered service at the end of the first quarter on budget and ahead of schedule. During the quarter, FPL also successfully completed the construction on schedule and on budget of nearly 300 megawatts of cost-effective solar projects built under the Solar Base Rate Adjustment or SOBR mechanism of our settlement agreement. By executing on smart capital investments such as these, FPL is able to maintain our best-in-class customer value proposition of clean energy, low bills, high reliability, and outstanding customer service. FPL's typical residential bill remains nearly 30% below the national average and below the level it was in 2006, while our service reliability has never been higher. The integration of Gulf Power, which we closed on at the start of the first quarter, continues to progress smoothly. We are now focused on ensuring we successfully execute on key systems and capital initiatives. We have already begun to see significant benefits from our focus on operational cost effectiveness, with base retail O&M costs down nearly 5% year over year. Consistent with our focus at FPL, we are also identifying smart capital investments that to further reduce costs and improve overall customer value proposition. By executing on this strategy, we expect the acquisition to benefit customers, shareholders, and the Florida economy. At Energy Resources, adjusted EPS increased by 10 cents per share year-over-year, primarily reflecting contributions from new investments. It was another strong quarter of renewables origination, with our backlog increasing by nearly 1,000 megawatts since the last call. Included in these backlog additions is our first co-located combined wind, solar, and storage project as we further advance the next phase of renewable 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. At this early point in the year, we are pleased with our progress at FPL, Gulf Power, and Energy Resources. Now let's look at the detailed results, beginning first with FPL. For the first quarter of 2019, FPL reported net income of $588 million, or $1.22 per share. Earnings per share increased 20 cents year over year. Regulatory capital employed growth of 8.3% was a significant driver of FPL's EPS growth versus the prior year comparable quarter. FPL's capital expenditures were approximately $1.1 billion for the quarter, and we expect our full-year capital investments to be between $5.7 billion and $6.1 billion. A reported ROE for regulatory purposes will be approximately 11.6% for the 12 months ending March 2019, compared to 11.2% for the 12 months ending March 2018. During the quarter, we utilized $156 million of reserve amortization to achieve our target regulatory ROE, leaving FPL with a balance of $385 million. As we previously discussed, FPL historically utilizes more reserve amortization in the first half of the year, given the pattern of its underlying revenues and expenses, and we expect this year to be no different. We continue to expect that FPL will end 2020 with a sufficient amount of surplus to continue operating under the current base rate settlement agreement for up to two additional years, creating further customer benefits by avoiding a base rate increase during this time. Turning to our development efforts, we continue to identify smart capital investments to further enhance our already best-in-class customer value proposition. Consistent with the 30 by 30 plan we announced earlier this year, FPL's 10-year site plan that was filed with the Florida Public Service Commission earlier this month included plans for roughly 7,000 megawatts of additional cost-effective solar projects across Florida over the coming years. This includes the approximately 300 megawatts that remain under the SOBR mechanism of our settlement agreement, as well as the nearly 1,500 megawatts of Solar Together community solar projects that we expect to construct over the next two years, subject to approval by the Florida Public Service Commission. Through Solar Together, which would be the nation's largest community solar program, participating customers will subscribe to a portion of new solar power capacity and, in return, they will receive credits that are expected to reduce their monthly bills over time. During the initial preregistration period, customer demand for the voluntary program was substantial. with approximately 200 of FPL's largest energy users, indicating more than 1,100 megawatts of intended participation. The 20 new universal solar sites that are currently planned for this program are projected to cost approximately $1.8 billion and generate an estimated $139 million in net lifetime savings, with non-participating customers expected to receive 20% of this total. To support what is one of the largest ever solar expansions, FPL has already secured approximately 7 gigawatts of potential sites. During the quarter, FPL also announced its modernization plan to replace two existing natural gas steam units, totaling approximately 1,650 megawatts, with clean and renewable energy, including the world's largest solar-powered battery system. The 409 megawatt, 900 megawatt hour Manatee Energy Storage Center is expected to increase the predictability of the existing co-located solar project, enabling FPL to more efficiently dispatch other power plants. The project is expected to be in service in 2021 and save customers more than $100 million while eliminating more than 1 million tons of carbon dioxide emissions. We will provide additional detail on these announcements and other capital initiatives at our June investor conference. Let me now turn to Gulf Power, which reported first quarter 2019 net income of $37 million, or $0.08 per share. During the first 12 months following the closing of the Gulf Power acquisition, we intend to exclude one-time acquisition integration costs, including those related to enhanced early retirement programs, severance, and system costs. We do not intend to exclude any integration costs beyond this year. Interest expense to finance the acquisition is reflected in the corporate and other segment and largely offsets the first quarter Gulf Power net income contribution. Gulf Power's reported ROE for regulatory purposes will be approximately 10.0% for the 12 months ending March 2019. For full year 2019, we are targeting a regulatory ROE in the upper half of the allowed band of 9.25% to 11.25%. We expect to achieve the regulatory ROE expansion through operating efficiencies while making significant capital investments to improve the value proposition for our GulfPower customers. During the quarter, GulfPower's capital expenditures were roughly $100 million, and we expect our full-year capital investments to be approximately $700 million. We will provide additional details on Gulf Power's operating plan and capital investment opportunities in June. During the quarter, Gulf Power filed a cost recovery petition for the approximately $350 million in Hurricane Michael restoration costs. Subject to a review and prudence determination of the final storm costs by the Florida Public Service Commission, Gulf is proposing a surcharge equivalent to $8 per month on a 1,000 kilowatt hour residential bill until the storm costs are fully recovered, which is expected to occur after approximately 60 months. Gulf Power believes that the proposed surcharge strikes an appropriate balance between ensuring timely cost recovery and mitigating customer bill impacts. The Florida economy continues to show healthy results and is among the strongest in the nation. The current unemployment rate of 3.5% 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 and the Case-Shiller Index for South Florida up 11.6% and 4.8% respectively versus the prior year. Florida's consumer confidence level also remains near a 10-year high. During the quarter, FPL's average number of customers increased by approximately 100,000 from the comparable prior year quarter, driven by continued solid underlying growth, as well as the addition of Vero Beach's roughly 35,000 customers late last year. FPL's first quarter retail sales increased 0.5% year over year. Partially offsetting customer growth was a decline in overall usage per customer of 0.5%, driven by unfavorable weather and an estimated 0.1% decrease in weather normalized usage per customer. A slight decline in underlying usage is a reversal from the trend over the past 12 months, but as we have often discussed, this measure can be volatile over time. We will continue to monitor closely and analyze the underlying usage and will update you on future calls. For Gulf Power, the average number of customers was roughly flat to the comparable prior year quarter. We estimate that Hurricane Michael resulted in a decrease of approximately 7,000 customers, roughly offsetting the strong growth experienced during the earlier months of 2018. Over time, we expect that 60 to 80 percent of these customers will return as they are able to rebuild and otherwise recover from this devastating storm. Gulf Power's first quarter retail sales decreased 7.5% year-over-year, primarily due to milder-than-normal weather in 2019 relative to the extreme cold experienced in January of 2018. As a reminder, unlike FPL, Gulf Power does not have a reserve amortization mechanism under its settlement agreement to offset fluctuations in revenue or costs. Now let me turn to Energy Resources, which reported first quarter 2019 GAAP earnings of $301 million, or 63 cents per share, and adjusted earnings of $448 million, or 93 cents per share. This is an increase in adjusted earnings per share of 10 cents, or approximately 12%, from last year's comparable quarter results. Last year's first quarter results have been restated higher by $9 million, or 2 cents per share, to reflect the adoption of new lease accounting standards during the fourth quarter of 2018. New investments added 8 cents per share, primarily reflecting the roughly 1,700 megawatts of new contracted wind and solar projects that were commissioned during 2018. Weaker wind resource during the first quarter was responsible for roughly the entire 10-cent decline in contributions from existing generation assets. First quarter fleet-wide wind resource was one of the worst over the past 30 years at 91% of the long-term average versus 102% during the first quarter of 2018. We continue to have confidence in the accuracy of our long-term wind resource assumptions and expect to continue to experience both positive and negative quarterly variability. The appendix of today's presentation includes a slide with additional details of long-term resource variability for the current energy resources wind portfolio. Beyond renewables, our other existing generation assets continue to perform well. We were pleased to receive the 20-year license extension for the Seabrook Nuclear Facility, allowing the profitable plant to continue to offer the New England State's attractively priced, carbon-free energy until at least 2050. Our gas infrastructure business, including pipelines, and the customer supply and trading businesses both contributed favorably to the first quarter results. All other impacts, including small, favorable year-over-year tax items and low corporate G&A due to the timing of development activity, increased results by 3 cents versus 2018. As I mentioned earlier, the Energy Resources Development Team had another strong quarter of origination. We added 223 megawatts of wind projects to our backlog, including a 100-megawatt build-own transfer project with a 30-year O&M agreement that will allow the customer to leverage energy resources' best-in-class operating skills while providing ongoing revenue through the contract term. We also added 485 megawatts of solar projects and 50 megawatts of four-hour battery storage projects to our backlog and 110-megawatt solar plus storage build-own transfer agreement during the quarter which is not included in our backlog additions. Our wind repowering program also continued to progress during the quarter as we added 195 megawatts to our backlog and commissioned an additional 55 megawatts of repowered projects. Although we expect to continue to sign projects that will go into service before the end of 2020 in the coming months, we are pleased that we already have nearly 2,700 megawatts in backlog for 2021 and beyond. Beyond renewables, while we continue to advance MVP towards ultimate completion and we expect to ramp up construction activities in the coming months, the Fourth Circuit's decision not to pursue an en banc review on the Atlantic Coast Pipeline's Appalachian Trail crossing authorization presents a challenge to both timing and cost. Since the original court decision, we have been working with our project partners on several alternatives to address the issue, and we continue to vigorously pursue these paths. At this point, our previously announced fourth quarter 2019 target and service date appears unlikely. We are continuing to work through options with our partners and will provide a further update in the near future. As a reminder, we do not expect any material adjusted earnings impacts, nor any change to NextEra Energy's financial expectations, regardless of the outcome of the ongoing challenges related to MVP. Turning now to the consolidated results for NextEra Energy. For the first quarter of 2019, GAAP net income attributable to NextEra Energy was $680 million, or $1.41 per share. NextEra Energy's 2019 first quarter adjusted earnings and adjusted EPS were $1.06 billion and $2.20 per share, respectively. Adjusted earnings from the corporate and other segment decreased $0.14 per share compared to the first quarter of 2018, primarily due to higher interest expense as a result of the financing related to the Gulf Power acquisition. Since the last call, we have completed approximately $5.2 billion in longer-term financing transactions to replace the bridge loans that were executed prior to Gulf Power closing. These financing are both fixed and floating rate and are for a variety of maturities between one and a half and 60 years, with a weighted average tenor of roughly 12 years and a weighted average interest rate of 4.4%, including the effect of the interest rate swaps we entered into at the time of the acquisition announcement. After closing these transactions, we repaid the bridge loans and settled the interest rate hedges. During the quarter, NextEra Energy Transmission received FERC approval to acquire Transbay Cable, a 53-mile, rate-regulated, high-voltage direct current underwater transmission cable system, which provides approximately 40% of San Francisco's daily electrical power needs. We continue to expect to close the acquisition later this year, assuming we receive the required approval from the California Public Utilities Commission, which is the last material condition outstanding. Based on our first quarter performance at Nexster Energy, we remain comfortable with the expectations we have previously discussed for the full year. For 2019, we continue to expect adjusted earnings per share to be at or near the top end of our previously disclosed 6% to 8% growth rate off a 2018 base of $7.70 per share. Our longer-term expectations through 2021 remain unchanged, and we will be disappointed if we are not able to deliver growth at or near the top end of our 6% to 8% compound annual growth rate range off of our $7.70 base realized in 2018, plus the expected deal accretion from the Florida transactions. From 2018 to 2021, we expect that operating cash flow will grow roughly in line with our adjusted EPS compound annual growth rate range. As always, our financial expectations assume normal weather and operating conditions. In summary, after a strong start to the year, we 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. The Gulf Power integration continues to advance well, and everything we see today leaves us even more confident. about our ability to deliver the financial expectations we have previously outlined for Gulf while improving the customer value proposition. Energy Resources maintains significant competitive advantages and continues to capitalize on the best renewables development period in our history. Combined with the strength of our balance sheet and credit ratings, NextEra Energy is uniquely positioned to drive long-term shareholder value, and we remain intensely focused on executing on these opportunities. Let me now turn to NextEra Energy Partners. The NEP portfolio performed well and delivered financial results in line with our expectations after accounting for below normal wind resource. Yesterday, the NEP Board declared a quarterly distribution of 48.25 cents per common unit, or $1.93 per common unit on an annualized basis, up 15% from a year earlier. Inclusive of this increase, NEP has grown its distribution per unit by nearly 160% since IPO. During the quarter, NextEra Energy Partners announced an agreement to acquire a geographically diverse portfolio of six wind and solar projects from NextEra Energy Resources. The approximately 600 megawatts of projects, which have a weighted average contract life of 15 years and a counterparty credit rating of A2 at Moody's and A at S&P, further diversify NEP's existing portfolio. Upon completion, the acquisition, combined with an associated recapitalization of existing NEP assets, is expected to enable NEP to complete the growth necessary to achieve our previously outlined year-end 2019 run rate expectations, even after excluding the PG&E-related projects' cash flows. These transactions are expected to be financed with a $900 million convertible equity portfolio financing, which I will discuss in more detail in a moment, as well as existing NEP debt capacity. Let me now review the detailed results for NEP. First quarter adjusted EBITDA of $225 million and cash available for distribution of $47 million were generally in line with our expectations after accounting for the weak wind resource. The first quarter of 2018 presents a particularly challenging comparable quarter as both adjusted EBITDA and CAFTI benefited from the $30 million acceleration of the note receivable related to the sale of our Jericho asset. In addition, the adjusted EBITDA and cash available for distribution contribution from existing assets was reduced by approximately $23 million and $22 million, respectively, as a result of the weak wind resource. which was 89% of the long-term average versus 105% in the first quarter of 2018. As noted during our discussion around energy resources results, we have confidence in our long-term resource assumptions and expect to continue to experience both positive and negative quarterly variability. For the balance of 19, based on the shape of the contributions from the recently divested and acquired assets, we expect most of NEP's growth in adjusted EBITDA and CAFTI to be in the second half of the year. At the end of the first quarter, approximately $38 million of cash distributions for PG&E-related projects, including Desert Sunlight 250, which is contracted with Southern California Edison, were restricted as a result of events of defaults under the financing that arose due to PG&E's bankruptcy filing. PG&E continues to make payments under all of our contracts for post-petition energy deliveries, and we continue to pursue all options to protect our interests, including vigorously defending our contracts and working with key stakeholders of each financing. Additional details of our first quarter results are shown on the accompanying slide. As I previously mentioned, we continue to execute on our plan to expand NEP's portfolio with the acquisition from Nextdoor Energy Resources that we announced during the quarter. NEP expects to acquire the unlevered portfolio for total consideration of $1.02 billion, subject to working capital and other adjustments. The acquisition is expected to close later this quarter. and contribute adjusted EBITDA of approximately $100 million to $115 million, and cash available for distribution of approximately $97 million to $107 million, each on an annual run rate basis as of December 31st, 2019. Following the acquisition, these assets will be combined with 581 megawatts of existing NEP wind assets into a new portfolio. The $220 million of existing project debt on the current NEP assets is expected to be immediately paid down, creating significant benefits for NEP, including being net present value, distribution per unit, and credit accretive, as well as generating roughly $25 million in incremental CAFTI. To finance the new acquisition and debt recapitalization of the existing assets, NEP will utilize the proceeds from a $900 million convertible equity portfolio financing with KKR as well as existing debt capacity. The KKR financing will have an initial effective annual coupon of less than 1% and provide NEP with the flexibility to periodically buy out KKR's equity interest at a fixed 8.3% pre-tax return, inclusive of all prior distributions, between the three and a half and six-year anniversaries of the agreement. NEP will have the right to pay a minimum of 70 percent of the buyout price in NEP common units issued at no discount to the then current market price. This transaction further demonstrates NEP's continued ability to access attractive sources of capital to finance its growth while providing third-party confirmation of NEP's long-term outlook and high-quality portfolio. Relative to the initial convertible equity portfolio financing transaction that we executed with BlackRock in 2018, this financing will have several features that further enhance the value for NEP unit holders. With a lower initial coupon, more cash will be available to LP unit holders, allowing NEP to acquire fewer assets to achieve the same level of future distribution growth. If NEP acquires fewer assets, it will have lower future financing needs. As a result, following the transaction, we believe NEP will be well positioned to meet its long-term financial expectations without the need to sell common equity until 2021 at the earliest, other than modest sales under the at-the-market program. In addition to reduced future equity needs, NEP will retain the flexibility to convert the pending KKR portfolio financing into common units at no discount over a longer period of time. This should be accretive to NEP unit holders who retain all of the unit price upside as NEP executes on its expected distribution growth objectives. Additionally, NEP will maintain significant option value on the underlying portfolio of assets while also preserving debt capacity and balance sheet flexibility. Upon successfully executing the transaction that we announced last quarter, NextEra Energy Partners expects to achieve its 2019 growth objectives, assuming no cash is available from the PG&E-related projects. Excluding all contributions from these projects, NextEra Energy Partners continues to expect a year-end 2019 run rate for CAFTI in the range of $410 million to $480 million, reflecting the calendar year 2020 expectations for the forecasted portfolio at the end of 2019. If PG&E-related cash distributions were included, year-end 2019 CAFTE expectations would be in the range of $485 million to $555 million. Year-end 2019 run rate adjusted EBITDA expectations, which assume full contributions from projects related to PG&E as revenue is expected to continue to be recognized remain unchanged at $1.2 billion to $1.375 billion. From a base of our fourth quarter 2018 distribution per common unit at an annualized rate of $1.86 per common unit, we 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. Additionally, following the transaction announced earlier this quarter, NEP announced its intention to grow its 2019 distribution at 15%, resulting in an annualized rate of the fourth quarter 2019 distribution that is payable in February 2020 to be at least $2.14 per common unit. Our ability to continue to grow distributions at the top end of our expectations range for 2019, despite the PG&E related headwind, is reflective of NEP's market-leading position and our continued focus on delivering value for LP unit holders. NEP continues to maintain flexibility to grow in three ways, through organic growth, third-party acquisitions, or through acquisitions from NextEra Energy Resources, providing clear visibility into its future growth prospects. Energy Resources currently has nearly 21 gigawatts of projects it could sell to NEP, including its existing operating renewable assets and its backlog of projects it intends to build over the coming years. Additionally, despite the recent challenges related to PG&E, during the quarter, NEP demonstrated its ability to access extremely low-cost financing to support its growth. With continued financing flexibility, a strong base of underlying assets, a favorable tax position, and enhanced governance rights, NEP is well positioned to meet its growth expectations. We remain focused on continuing to execute and creating value for LP unit holders going forward. In summary, both Nexter Energy and Nexter Energy Partners are benefiting from our history of strong execution that has positioned us well to capitalize on the terrific growth opportunities available to us across our businesses. We look forward to sharing more detail with you at our investor conference on June 20th. That concludes our prepared remarks, and with that, we will open up the line for questions.

We will now begin the question and answer session. To ask a question, you may press star then 1 on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then 2. At this time, we'll pause momentarily to assemble our roster. And we will take our first question from Steven Byard at Morgan Stanley. Please go ahead.

Hi, good morning.

Good morning, Steven.

I wanted to talk about resources. You continue to put up impressive growth numbers there. I noticed BOT, build, own, transfer, continues to show up. Would you mind just talking at a high level in terms of trends with respect to BOT? Do you see a trend in that direction? Is this more just what you expected? It's going to be a part of the mix but not a growing trend. What are you seeing in terms of the BOT side of the market?

So, Stephen, as you know, we've seen a tremendous growth in our renewables opportunities across the board, and we've historically benefited from sales to IOU customers, munis and co-ops, as well as a growing demand from CNI customers. Two of those groups, the munis and co-ops, as well as the CNI customers, generally are not that interested in build-own transfers or owning the renewable assets. They're very happy to take advantage of all of the advantages that we bring to the table, including of our cost of capital, our scale, our ability to construct and deliver these projects and ultimately operate them over the long term at a low price. Our IOU customers are increasingly building renewables and wanting to procure and incorporate more into their portfolios. So as the pie has gotten bigger, there's probably a nominal number of megawatts that are increasing in terms of build-on transfers. And our team has been able to successfully offer to our customers a multitude of benefits to them, of bringing all of the advantages that we bring to them and sell part of it as build-on transfer and typically part of it as a PPA to them, bringing a total package that is very valuable to our customers. So it's increasing, but, you know, a very positive addition to our portfolio. John might add some more.

Yeah, Stephen, this is John. What I would add to that is the way I look at BOT is it enables more contracts. So the BOT that you saw this quarter was the Portland General transaction where we had, you know, a trifecta of wind and solar with battery storage. And the BOT – was part of the wind facility that we actually ended up building, but we got a contract back for the other piece of it. And that's typically the type of BOT transaction that you'll see us enter into. But it is a part of the business, and it's an enablement for more contracted origination around the renewable portfolio.

Understood. So it's a tool in the toolkit. You earn good returns on it, and it's part of the solution you offer to some customers. So understood. I wanted to shift over to solar together. This is a really interesting model. Rebecca, you mentioned briefly the savings to customers. Would you mind just speaking a little bit to this? It does seem like a nice model to offer solar to your customers. I just want to make sure I understood what you had mentioned, I think, on the $1.8 billion model. I think you mentioned $139 million of savings. Could you just talk through that a little bit more in terms of the benefits to customers from solar together?

Yep. So as you might expect, we've long been excited about deploying more solar in Florida. It is the sunshine state, and as solar has gotten to be more cost-effective, we're very excited about bringing it across our entire portfolio. And there's a certain amount of interest from our CNI customers who don't necessarily want to take on the ownership and construction responsibility, particularly when it's not at scale and not as cost competitive as what we can build. And so when we went out and offered up this idea of a community solo program, we got a significant amount of interest from our large CNI customers, which is primarily the group that we went out to talk to. And that was the 1,100 megawatts of initial demand for this pre-registration period that we offered up. And so then we sized our program to be around 1,500 megawatts. So in the layout of the program, customers that sign up for this, the voluntary participation, will pay a certain amount on their bill in the near term, and over the long term will receive credits against their bill. But about 25 percent, 20-25 percent of the savings the net savings to the overall system are actually going to be retained by the non-participating customers. So FPL's existing customers will get a benefit from this program as well.

That's helpful. Thanks so much.

And we'll take our next question from Steve Fleshman at Wolf Research. Please go ahead.

Yeah, hi, good morning. Hopefully you can hear me okay.

We can hear you fine.

Okay, great. So just could you maybe give a little more color on the MVP comments with respect to just more color and also what would be driving an update soon as opposed to like now or the analyst day?

So as I mentioned in the prepared remarks, We, along with everybody else, were certainly disappointed by the Circuit Court not taking up the en banc review. And as soon as the initial adverse decision was made, we started working closely with our partners on a variety of different options, whether it's legislative, administrative, et cetera, to resolve the issue so that we can continue to build and ultimately bring online MVP. And we remain confident that one of those many options will ultimately come together so that we can put MVP into service, which at this point we think will be even more valuable than what we originally thought just because of the challenges that building pipelines in this area has proven to be. But, you know, at this point, looking at what we previously targeted for our in-service date of year-end 2019, that's challenging. So we're still working on what exactly the path forward is and the timing for COD. We are going to resume construction, as you know. We temporarily, you know, pause construction during or kind of tone down construction during the winter period just for the overall conditions. As we're starting to get to the spring thaw, we'll resume construction where we can and And then as we firm up plans and it's clear which of these options will come to fruition, we'll give you more specifications in terms of timing and ultimate cost.

Steve, this is Jim. We'll certainly have both a date and a cost for you at the annulistic.

Okay. And then also, could you talk a little bit more about the undergrounding legislation and just what the investment opportunity and customer benefit is there?

Sure. I'll start, and then I'll probably hand it over to Eric to add some more details. As everyone is well aware, after the devastating impacts in our service territory from Irma and then broader in Florida from Michael and other hurricanes, It became clear to a lot of critical stakeholders about how important it is to have continuous service for our customers. As you probably know, Florida is now a trillion-dollar annual economy. I think it's something like the 16th largest economy in the world if we were our own economy. So every day that we're offline is a significant harm to our state. And so there's an appreciation from critical stakeholders in the legislature and other communities about the value of resiliency in our grid. And one of the ways that we can improve the resiliency is through some undergrounding. So there's some legislation going through the current session in Florida for the possibility of setting up a separate clause that ultimately we could recover investments and earn a return on for undergrounding in our service territory through a clause mechanism.

Hi, Steve. This is Eric Szilagyi. I guess the only thing I'd add on this is that the legislation has progressed through both the Senate and the House pretty well. It's gone through six different committees, three in the House, three in the Senate. It's passed out of all those committees unanimously. So to date, there hasn't been a single no vote against it in either body. There are some slight differences in the version, so those have to be reconciled. It's not really substantive. It's more of verbiage. But we expect it to be taken up by the full House, the full Senate, in the coming next week or so, two weeks at the most because that's the end of session. And if it passes, then indications are that the governor will be supportive as well. I mean, there is a huge focus on resiliency in the state, as Rebecca talked about. And, frankly, we've worked very hard. over the past couple of years with a couple of pilot programs to look at how do we get costs out of underground. And we've gotten it now to the point where, particularly under a programmatic approach, we'd be able to get the cost to be equal, if not even a little better, than some of the hardening efforts that we do above ground. So it's a real win for customers, both financially as well as, obviously, resiliency.

Thank you.

And as a reminder, that is star one on your telephone keypad if you would like to ask a question. We'll take our next question from Shar Perez at Guggenheim Partners. Please go ahead.

Hey, good morning, guys.

Good morning.

So just let me just ask a quick question, a couple here, but around Santee Cooper. There's obviously a lot of mixed data points we're seeing with lawmakers. The town hall meetings seem to be a little bit noisy, and we kind of still have two competing bills here. And then on the other hand, the process seems to be much more competitive than we all thought. So maybe a quick status update regarding the process. Are we still expecting some sort of a closure in the decision by the June timeframe?

So maybe I'll start off with the typical caveats that I think are appropriate responses to the question. And if maybe Jim wants to add something specific, I'll toss it to him. But as you know, we typically don't comment on M&A activity other than very general comments that we look for opportunities where there's a constructive regulatory environment. It's accretive, and ultimately there's a good fit from our business perspective, including the opportunity to deploy the Florida playbook and being able to improve customer value proposition for our customers. I don't know, Jim, if you want to add some specific comments.

So, you know, obviously we've confirmed that we put a bid in for Santee, and again, You know, there's a process going on. I would expect it to come to conclusion here, you know, by June. And, you know, we will see how it plays out. I think the state realizes that they, you know, that Santee has, you know, upwards of $4 to $5 billion of debt for, you know, on an asset. You know, the... the nuclear plant that is never going to generate any income. And so it's an issue for the state that they need to address, and I think the vast majority of folks in the state understand that they need to address it. And, you know, the key stakeholders are, I think, working hard to come to a conclusion about how, you know, how the process is going to move forward. So, you know, we're cautiously optimistic that they bring – you know, that the legislature passes something to lay out what the process will be. And then we'll see. As I said, we did confirm on the last call that we put a bid in. And, you know, you can imagine that we'll continue to play in the process. And it's someplace where we think we can add a lot of value and bring value to customers and bring value to economic development in the state. Got it.

Got it. And just a quick update on Gulf Power. You know, you're sort of five months into it. It seems like you're still kind of reiterating the $0.15 to $0.20 of accretion, despite golf already contributing $0.08 in the quarter. Are you starting to see some incremental near-term opportunities to your prior stated accretion guide, or is this something that maybe you'll update at the analyst day?

Well, a couple of comments on golf. First, at a high level, maybe taking more of the second part of your question first. We obviously closed at the very beginning of this year, and we are as enthusiastic as ever about the opportunities with golf as we were prior to closing the acquisition. I personally spent time up there. I know many of the other folks on the senior team, and obviously we have a terrific team at golf now executing, and that's both taking costs out of the business as well as identifying those smart capital investments. which will ultimately deliver on the value proposition that we've been targeting with FPL, which is low bills, high reliability, terrific customer services, and clean energy. So very optimistic and excited about it. More specifically to the numbers, yes, you're correct on the $0.08, but as you know, we're going to highlight the Gulf contributions as its own entity, and then for the financing costs to close the acquisition are showing up at C&O. So you might want to think about those two together. We do have opportunities to further improve the cost position through the balance of the year. We'll also start to ramp up the capital investments. As I talked about, we're planning to deploy a total of $700 million for the full year at Gulf. And then obviously there's some ROE improvement that I talked about in the prepared remarks as well. Our guidance expectations remain from the overall company perspective, as we talked about, of our six to 8% growth from our 2018 adjusted EPS of $7.70 in 2019. And then we expect to have the incremental accretion on top of that growth rate of 15 cents in 2020 and 20 cents in 2021. Got it.

And then lastly, Rebecca, just you mentioned administrative options with MVP. Can you confirm if you're working with the ACP owners around this option? Obviously, they're completely different projects, but how much collaborating are you doing with ACP owners like Dominion?

I don't want to talk through really the details of that. As I talked about a couple of minutes ago, we've worked very closely with our partners to develop different options, and we do believe there are various options in order to complete it. But we don't really think that it's to our advantage to get through a lot of the details of that out publicly. So we're working on it very hard, remain confident in our ability to ultimately construct and bring it into service.

Great. Thanks, guys.

Thank you. Thank you.

And we will take our next question from Julian Dumoulin-Smith with Bank of America Merrill Lynch. Please go ahead, sir.

Hey, good morning. Can you hear me?

Good morning, Julian. We can hear you fine.

Excellent. All righty, so at this point, I think perhaps a couple clarifications, perhaps starting with the last question. On golf, just to go back to what you were saying about your expectations on earned ROEs already pretty healthy, how do you think about the timeline to go back in for a formal rate case and then also perhaps the prospect of getting an amortization-type mechanism eventually? I mean, certainly that would be one of the multiple priorities I would imagine in contemplating any kind of rate recovery, but at the same time, given the ability to earn within the band clearly at the upper end already, how do you think about timeline?

So we're still at the early stages, Julian. We closed it a couple of months ago, and right now the team's head is very much into identifying the cost savings opportunities, putting the dots, the I's, and crossing the T's on the capital initiatives that we can make, and we're putting those plans together. For now, I'd like to limit it to the comments that we made in the script and the prepared remarks that we expect to be at the upper half of the ROE band, and we expect to target the capital investment opportunities of a total of $700 million in 2019. And to the extent that we can put more detail around that, particularly around the capital initiatives, we'll highlight more of those at the June investor conference.

Totally appreciate it. And then secondly, if you can – Just coming back to where you started the Q&A on the backlog here, it seems like another shift in backlog seems to be longer dated beyond the 2020 period. If you look at what was added, it seems like the bulk of it for this quarter was added, and the bulk of it at that was solar. Can you comment a little bit about the economics of solar in the backlog as you move through time in 19 and 20 versus the 20 onwards type projects? And then perhaps any other nuances you might see in terms of safe harboring or otherwise in the 20 onwards type timeframe?

I think there are a couple of comments in there, Julian, so you'll have to correct me if I don't hit all of them. But in terms of the timing of the backlog, as you know, we set out expectations at our last investor conference for the full 2017 through 2020 timeframe. We're now healthily in those ranges, which sets us up very well to deliver on the expectations that we've long talked to you all about. And as we highlighted in the script today, we now have the 2,700 megawatts of projects that are beyond 2020. And that's actually building up over time, and there's actually one or two projects that moved from the before 2021 timeframe into 2021. We're starting to see customers shift their focus to beyond 2020. I wouldn't say that the team has stopped the efforts to sign contracts for a 2020 COD. In fact, I'm sure John will tell you that he's pushing his team hard, and no doubt customers continue to be interested in signing up wind projects before the end of 2020. But, of course, with solar still having the full benefit of tax incentives into the early 20s, customers are certainly focusing on that as well. To answer the return question, our returns, as we've long talked about, have have generally remained consistent on a levered basis over time, and that hasn't changed materially in recent weeks or months.

Right. All right, excellent. Well, we can leave it there. Thank you very much.

Hey, Julian, this is Jim. The only other thing I'd add is you can imagine we are safe harboring for 21 and beyond, so we're not taking advantage of that opportunity.

Right. You should assume everything's safe harbored. Correct. Exactly. All right, excellent.

And once again, that is star one if you would like to ask a question. And we'll take our next question from Jonathan Arnold at Deutsche Bank. Please go ahead.

Good morning, guys. Thank you. Good morning. Could I just ask on the subject of BOT and the backlog, and you've had situations where you are adding BOT to the backlog and then others where you, including last quarter, where you didn't. What's the trigger to determine whether BOT is shown in backlog or not?

Typically, if there's some sort of operating agreement where there's ongoing economic value to us, then we've decided to include it in our backlog, where the transaction is really focused more on a build and then truly sale and then the operations and all ongoing economics or to the customer's benefit, we've excluded it.

Okay. This is John. So the contract that's BOT this quarter, you know, again, is related to Portland General. It's a 300 megawatt wind facility, 100 megawatts BOT, 200 megawatt is – is the balance that we'll loan under a contract. And so that facility is going to be, the whole 300 megawatts is going to be operated by us. I'm sorry, I got that backwards. 200 megawatts is the piece that's the BOT and the 100 megawatts is the piece that we take back.

Okay. So that makes sense. But then, for example, say the 200 BOT project that you announced on the fourth quarter call, Was that something different, and is that we shouldn't anticipate that would end up in backlog, or should we?

No, no, that would not be in backlog. And just to clarify, we've got 100 megawatts of BOT, right, with Portland General, 200 megawatts under contract.

Yeah, I said this is all at Wheat Ridge, correct? I see that in there.

That's all Wheat Ridge.

And then there's the solar piece as well.

There's the solar piece as well and the battery storage.

Okay, I get it. Thank you for that. And then just on another topic, as we're thinking about what to anticipate at the analyst day, I know we talked about at some point you might sort of start talking more around profitability metrics on backlog as opposed to just megawatts. Is that something – that you think might be part of the update or is still a work in progress?

Jonathan, it is very much a work in progress. I think the general outline should be somewhat consistent with what we've talked about in the past, which is overviews of our – basically putting meat to the bone, helping you understand what the growth opportunities are for each of our businesses. Obviously, for the first time at Gulf Power, it will be detailed plans on how we're looking at the business and what the opportunities are. At Energy Resources, we certainly, it's likely, will put together an overview of the renewables market as we see it today to help you see some of the details of why our team continues to be excited about renewable economics and ultimately the demand from our customers that will enable us to continue to grow our business.

Okay, great. Thank you.

And we will take our final question from Michael Lapidus at Goldman Sachs. Please go ahead.

Hey, guys. Thank you for taking my questions. Just curious, a lot going on in Florida these days, and this may be one for Eric. How are you guys thinking about a handful of items? One is the outstanding petition or complaint regarding tax reform implementation in the last FP&L kind of rate review. The other is I think there's still some litigation outstanding or a challenge regarding implementation of the SOBRA mechanism. And then finally, just curious, is there anything that has to happen or anything that could happen that could derail the two-year extension of the existing rate agreement you have?

Yeah. Hey, Michael. It's Eric. So let me start with the tax reform document. We've had – We recently had hearings over it and filed testimony. There's going to be additional hearings that take place in mid-May. You know, look, we feel very good about our position and how it fits within our rate agreement. Our arguments are solid and sound. You know, it's a proceeding. We'll go through it. But I feel very good about where we stand overall from the tax reform position. Other areas, obviously, as you know, we've got the Irma docket that's still out there, too. That's going to be in mid-June. Again, feel very good about that. That was a storm that we actually restored more people faster than anybody in history, and we paid for it using our tax savings, the reserve amortization. I feel very good about our positions in front of the Public Service Commission. I can't predict who's going to oppose what and when they're going to file for hearings, but right now the arguments have been strong and the hearings have gone well so far.

Got it. Thanks, Eric. To Eric's comments, is your reference to going in for a rate case, As we talked about both in this script and obviously in prior comments, tax reform enabled us to potentially have a two-year extension of our settlement agreement, and that obviously the benefit of delaying any amount of time is further delaying the time where we'd need a base rate increase from our customers, so hopefully saving the customers some money. But it's up to two years, and we'll have to go through the thought process again as we typically do, about when's the best time to go in and looking at all of our costs and our forecasts about when do we need some incremental revenues.

Got it. But there's nothing mandating you to come in at any point in time. It's kind of an FT&L or a next-year decision on when to come in.

Well, as you know, under the settlement agreement, we need to notify the commission in March of 2020. if we intend to come in within the next year, a time frame after that.

Right. So, Michael, the settlement takes us through 2020, through the end of 2020. We have to notify if we choose to extend, but it is our choice. It's a unilateral decision, and we'll do that by March of 2020. And as Rebecca said, it could be up to two years is what we've been saying.

Got it. Thank you, Eric and Rebecca. Much appreciated.

This will conclude today's conference call. Thank you for your participation. You may now disconnect.