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Good morning, ladies and gentlemen, and welcome to Emera's Q1 2018 Earnings Conference Call and Webcast. [Operator Instructions] Please note this conference will be recorded May 11, 2018, at 9 a.m. Eastern Time. I would now like to turn the call over to your host for today's call, Ken McOnie, Vice President, Investor Relations and Treasurer for Emera. Please go ahead, Mr. McOnie.
Thank you, Denise, and thank you all for joining us this morning for Emera's First Quarter 2018 Conference Call and Live Webcast. Emera's first quarter earnings release was distributed yesterday after market closed via newswire and the financial statements, management's discussion and analysis and the presentation being referenced on this call are all available on our website at emera.com. Speaking on the call today is Scott Balfour, Emera's President and Chief Executive Officer; and Greg Blunden, Chief Financial Officer. Scott, Greg and other members of Emera's management team will respond to your questions following their prepared remarks. This morning, Scott will begin with an update on our business and strategic initiatives. Greg will then follow with an overview of the financial results. We expect the presentation segment to last about 15 minutes, after which we will be happy to take questions from analysts. I will take a moment to advise you that this conference call will contain forward-looking information and statements with respect to Emera. Forward-looking statements involve significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements. Generally, these factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations. Such risk factors or assumptions include, but are not limited to, regulation, operations and maintenance, energy prices, general economic conditions, weather, derivatives and hedging, capital resources, loss of service area, licenses and permits, environment, insurance, labor relations, human resources and liquidity risk. A number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking statements. And now I will turn things over to Scott.
Thank you, Ken, and good morning, everyone. First of all, let me say that I am truly delighted to be hosting my first analyst call as Emera's Chief Executive Officer. The past couple of months have been a whirlwind of activity, but I'm enjoying every minute of it and I'm more excited than ever about the opportunities ahead for our business. And happily, I am able to report that Emera delivered very strong first quarter financial results, reporting adjusted earnings per share of $0.87 and operating cash flow before working capital of $444 million. This represents a 21% increase in our adjusted EPS and a 28% increase in our cash flow quarter-over-quarter. These results demonstrate the earnings opportunity that exists in our business now that includes TECO, along with the benefits of our diversified portfolio and were delivered, despite the challenges of a stronger Canadian dollar and the impacts of U.S. tax reform. All to say, a solid start to the year. In addition to delivering strong financial results, we've had a productive first quarter on a number of key initiatives. As we highlighted in February, the Maritime Link was placed into service on January 15, 2018. This transformative project was delivered on time and under budget and is currently providing benefits to customers in both Nova Scotia and Newfoundland. This new air tie enables the sale of electricity between the 2 provinces and is also improving regional system reliability. In Florida, on March 1, we had a positive regulatory decision from the Florida Public Service Commission, which approved our plan to retain the 2018 benefits of U.S. tax reform in the business to fund the recovery of storm restoration costs. Greg will speak to the details of the settlement agreement and its impact on our U.S. tax reform mitigation efforts in a few moments. I have to say, I have the good fortune of taking the reins of Emera during a period of relative regulatory stability. With our 2 largest utilities, Tampa Electric and Nova Scotia Power, both underrate stability agreements for the next couple of years and with both today earning well within their allowed return on equity bands. In New Mexico, we recently filed a general rate application for rates to be effective in early 2019, which is the first request for a rate increase by New Mexico Gas since 2012. If approved, it would result in a modest 1.4% rate increase for the average residential customer. But importantly, would allow for changes to rate design that would improve the stability of the utilities earnings in periods of unseasonable weather. We're also in the midst of a distribution rate case in Maine. It was filed in October of 2017 and where a decision will be received and is expected in mid-June with rates to be effective by July 1. Turning to our project initiatives, we're pleased with the progress so far that we've made to-date on our solar investments in Florida. So far, we've invested USD 140 million of the forecasted total capital spend of USD 850 million and are on track to bring 145 megawatts online by the end of the third quarter of this year, with the plan for an additional 250 megawatts to follow in the first quarter of 2019. Pursuant to this solar-base rate adjustment mechanism, or SoBRA, announced in September of 2017, as each tranche of solar is brought online, there was an immediate cash recovery in customer rates. SoBRA Tranche 1, which was specifically approved by the FPSC earlier this week, will add $8 million of incremental revenue in 2019 -- 2018. And Tranche 1 and 2 combined, will add USD 70 million of revenue in 2019. We believe that there is further capacity in the Florida grid for solar and we're actively looking to install an additional 600 megawatts post 2020. Projects like this SoBRA-enabled solar build in Tampa form part of our rate-base growth forecast true to 2020. This growth is supported by our $6 billion capital program over the same period or about $2 billion per year, which is focused on investments in renewable and clean energy, modernization of aging infrastructure and customer focused technologies. The rate-based profile presented reflects a conservative estimate of our growth plans and only includes projects that we are highly confident will proceed. We will continue to fill in our forecast as projects are approved. Opportunities to further enhance our rate-base growth beyond that reflected here, include further solar investments in Florida and the modernization of our Big Bend Facility, which we are presently advancing. As part of our regular planning cycle, we will be refreshing our long-term capital plan during the third quarter and providing an updated forecast in the fall. Overall, we see tremendous opportunity at Tampa Electric to displace coal-fired generation with lower emission natural gas fire generation. Our Big Bend generating station is currently a 4 unit, 1,658 megawatt dual fuel facility. We are advancing an opportunity to retire 1 unit and repower another with 2 natural gas combustion turbines and 2 heat recovery steam generators that will generate steam for a refurbished steam turbine. This modernization would significantly reduce the carbon intensity of the energy produced by the facility and generate significant savings for customers. Modernization of the unit is estimated to cost approximately USD 800 million and generate approximately USD 750 million in savings for customers. Construction could begin as early as 2019 with an in-service date of late 2022 or early 2023. The initial capital spend on this project is expected to be funded with internally generated cash flow from Tampa Electric. Overall, I'm really pleased with the results of the quarter and the progress we've made advancing our regulatory agenda and capital program. And with that, I'll turn it over to Greg for the detailed financial results.
Thank you, Scott, and thank you all for joining us this morning. We released our earnings and filed our quarterly financial statements in MD&A for the first quarter of 2018 yesterday afternoon after market closed. In Q1 2018, Emera reported net income of $271 million and earnings per share of $1.17 compared with net income of $312 million and $1.48 per share in Q1 of 2017. Our first quarter adjusted net income and earnings per share, which excludes mark-to-market adjustments, were $202 million and $0.87 per share in 2018 compared with $152 million and $0.72 per share in the prior year. We also reported an increase in operating cash flow before changes in net working capital of $96 million or 28% to $444 million. Operating cash flow is a key metric for our business because it is a basis upon which our credit metrics are calculated. The increase was in line with our forecast and we expect the growth trend to be maintained for the rest of the year. Weather is always a factor in the energy business and favorable conditions in Florida, the Northeast U.S. and New Mexico contribute to both earnings and cash flow growth. And now for some details. The market provided opportunity for Emera Energy in Q1 2018 and the business was able to capitalize on it. Very cold conditions in January resulted in average gas prices in the $25 range, peaking at $140. That compared to a $5 range in January 2017 and a $9 peak. That January experience moved the forward prices up, so Emera Energy was able to hedge some of its transport portfolio through February and March at attractive values, which proved astute as actual market conditions moderated later in the quarter. As a result, Q1 trading margins were $69 million, a $43 million increase over Q1 of 2017. Moving into the summer gas season, things will be quieter for a while, but the strong start to the year leads us to forecast that Emera Energy will deliver at the high-end of its normal $15 million to $30 million U.S. earnings guidance in 2018. The generation side of the business performed as expected in Q1 2018, including the realization of higher capacity revenues. As we have previously noted, 2018 will see an approximate USD 40 million increase in capacity revenues, the after-tax impact of which we expect to flow substantially to the bottom line, resulting in increased earnings over 2017 amounts. Energy margins also improved over Q1 2017 with an increase in spark spreads and in volumes generated. While the results at Emera Energy increased significantly on a quarter-over-quarter basis, they are in line with our Q1 performance from 2016 and 2015, where net earnings were $48 million and $76 million, respectively. Emera Florida and New Mexico also benefited from favorable weather in their service territories. In Tampa, January was quite cool, while February brought record setting heat. New Mexico experienced more seasonally cold weather during the quarter than in the prior year. The cold weather drove higher gas consumption at gas utilities, while both temperature extremes increased electric load. Tampa Electric also benefited from higher base rates related to the Polk Power Station expansion, which came into service on January 15, 2017, partially offset by higher depreciation costs. And the gas utilities also benefited from lower income tax expense. Nova Scotia Power, Emera Maine and Emera Caribbean performed as expected during the quarter. Both Nova Scotia Power and Emera Maine service territories were hit with a number of late-seasonal Easters, which increased storm cost for both utilities and delayed capital spending in Maine. Relatively lower Q1 earnings in both utilities are expected to reverse during the balance of the year. Earnings from Emera Caribbean continue to be impacted by Hurricane Maria. In Dominica, while power has been restored to all those who are able to receive it, there is still significant restoration work to be completed on the island. I am pleased not only with the growth that we are seeing in our earnings and cash flow, but with the improvement in the quality of these earnings. As Scott highlighted in his remarks, the Maritime Link was placed into service during the quarter. As a result, this asset is now generating cash earnings. We also saw quarter-over-quarter increase in capacity payments in New England. These payments are a predictable part of our earnings and provide a steady stream of earnings and cash flow. In addition, we continue to see strong load and customer growth in the State of Florida, underpinning the sustainable regulated earnings growth from our Florida utilities. The addition of TECO to our portfolio has meaningfully improved the quality of Emera's earnings and cash flow in increased proportion driven by a regulated operations. On a trailing 12 month basis, Emera's operating earnings are approximately 92% regulated, an increase of approximately 16% since 2016. Since our last conference call in February, we have materially reduced our estimate of the negative impacts of U.S. tax reform on our business. We now expect the impact in 2018 to be about $125 million at the high-end of our forecast, 40% lower than initial estimates. At the low end, it's $75 million and in 2019 and beyond, we expect the impact will be largely mitigated. That improvement was made possible by effective and productive regulatory work and our ability to realize the benefits of tax reform in our unregulated operations. For example, on the regulatory front, as Scott noted earlier, in Florida, the Florida Public Service Commission approved our settlement agreement allowing Tampa Electric to offset the 2018 impacts of tax reform against the storm restoration costs incurred for Hurricane Irma and other name storms. This settlement agreement is in the best interest of customers who will not see any change to their 2018 rate as a result of U.S. tax reform or storm restoration costs. The settlement agreement allows us to effectively collect all of our approximately USD 100 million of storm costs in 2018. Without the settlement agreement, collection of approximately $45 million of cost would have been delayed until 2019. In the PGS, the Florida Public Service Commission ordered the effective date of U.S. tax reform to be February 6, allowing PGS to keep the benefits of U.S. tax reform for the first 5 weeks of the year. As PGS is a winter peaking utility, these first 5 weeks are among the highest earning of the year. In New Mexico, the revenue requirement of our general rate application filed in February incorporates the benefit of U.S. tax reform. In Maine, we expect the benefits will be addressed as part of the deliberations on our current distribution rate case entering the FERC's annual adjustment of transmission rates. In other words, in both jurisdictions, we are expecting the tax reform will be handled as part of the regular rate making process. And beginning in 2019, we are expecting to begin to be refunded our alternative minimum tax or AMT credit balance of USD 214 million. We are expecting approximately USD 100 million next year with 50% of the remaining balance owing to us each year thereafter. We also see substantial opportunity to grow the investor owned capital in our utilities with the elimination of bonus depreciation and a resulting decrease in deferred tax liabilities, there will be a need to rebalance the regulatory capital structure in our U.S. utilities, which will provide an investment opportunity and create additional earnings capacity of approximately USD 30 million by 2022. So all in all, a more positive outlook. And as I noted earlier, even with the impacts of tax reform, we are expecting operating cash flow to increase year-over-year at a comparable rate to the first quarter. Speaking of cash, over the past 12 months, we have made significant progress in strengthening our balance sheet. Since Q1 2017, we have raised approximately $875 million of equity through the combination of a public issuance and our DRIP program. We have been focused on deleveraging at the whole co level and we've decreased our consolidated leverage by almost 2%. We are on track to meet our targeted capital structure of 55% debt, 35% equity and 10% hybrid capital by 2020. We continue to evaluate our funding requirements relative to our capital investment plan, targeted capital structure and targeted credit metrics. When we look at our funding requirements for 2018, we expect capital spending to be approximately $2 billion and the cash dividend requirements after the DRIP to range between $325 million and $350 million. The vast majority of the funding for these activities will be provided from cash flow from operations that we expect to continue to show strong year-over-year improvement in 2018. And from operating company debt, in line with approved capital structures at the utilities, which are driving this rate-based growth. Any incremental funding requirements could be addressed through hybrid securities and/or preferred shares, for which we currently have room within our targeted capital structure. Overall, we are off to a great start in 2018. The fundamentals of the business have never been stronger and we've made excellent progress in our plans to manage the short-term challenges of tax reform. I am confident that the highly regulated diversified portfolio is well positioned to capitalize on the investment opportunities we see in front of us and to continue to provide above average long-term investor returns. With that, I'll now turn the presentation back over to Ken.
Thank you, Greg. This concludes the presentation. Denise, we would now like to open up the call and take questions from analysts.
[Operator Instructions] Your first question comes from the line of Linda Ezergailis with TD.
I wonder if you can help us understand a little bit about the next major milestones of the Big Bend coal-to-gas opportunity that would lead to a positive FID and the cadence of timing of that?
Sure. Nancy Tower is actually on the line. Nancy, do you want to respond to that?
Hi Linda, it's Nancy. We are working our way through our internal approval. So at the same time, we've -- we're continuing to move the project forward. For example, in April, we filed for environmental approval. And so we expect to make a final announcement in the next several weeks once we finish all our internal approvals. So that's where we are.
And are there any sticking points or anything? Or are you optimistic that there's -- it should come?
Yes, we're very optimistic. We're going to reduce -- we're converting 2 units that would primarily burn coal today to highly efficient natural gas. So from an environmental perspective, we're reducing the environmental impact at Big Bend, so we don't see any issues with environmental approval on that.
Okay, that's helpful. And maybe just, while we're talking about Florida, can you comment on the installation of another 600 megawatts of solar post 2020? What might be the milestone to kind of get to a decision on that? Is it just a matter of timing? And would the cost be similar to what's already approved under SoBRA, realizing that there's inflation, but the costs currently coming down for solar, can you give us a sense of how that might unfold?
So I'll start and Scott can jump in, but one of the things to enable us to put another 600 megawatts of solar to actually get the fast -- more fast-acting generation on our system. So the conversion repowering of Big Bend will help us in terms of getting that additional solar, if you will. So it's a little bit of changing the generation mix on our system to enable us to do that. So we are looking at it at this point. We are buying land when we see it. But safe to say that we haven't approached the regulator at this time, but it's something that we've got in the back of our minds and sort of -- and trying to set up our system such that it can take another 600 megawatts. When we get the first -- when we finish the first tranche or the first 600 megawatts in 2022, we will have 7% on our system going from, essentially, a standing start of 0 to 7% of our generation. So we need to understand a little bit better, how that works on our system. And again, I think the fast-acting generation at Big Bend will be helpful to that.
Yes, Linda, I think Nancy covered it well. I'd say, on the second wave of solar is still very early days, of course, and we're very focused on executing the first 600 megawatts. But the notion is that we're really coming from a standing start in Florida and recognizing the solar regime that is there in the state. We just see the opportunity for taking the 600 megawatts to -- within the existing system of Tampa Electric, further enabled by the addition of more gas-fired generation. We see the opportunity for that system to handle another 600 megawatts. And as it relates to the Big Bend modernization, I mean, really the key in this is that reference to the significant customer value that can be attributed by progressing that project, which is really reinforcing Nancy's statement that we're quite optimistic about the ability to advance that project. We're not at a final decision date yet, of course, as Nancy referenced. But with the project driving those kinds of benefits for customers, certainly leads us to that optimism.
Your next question comes from Rob Hope with Scotiabank.
We appreciate all the color on the increasing cash flow profile as a result of some of the mitigation factors that you're seeing in terms of U.S. tax reform. Just a couple more questions on that though. When you look at your credit metrics, have you given any thought to potential partial monetization of some long-duration assets or rare rate sales that would allow you to strengthen your credit metrics further?
Yes, Rob, it's Scott. So I'd say, we're always looking at and thinking about our portfolio of assets and making sure that we've got capital allocated in the right place. Obviously, we're not talking about a sale of any assets today. And obviously, there's a clear message in that. But I would say, as part of a regular strategic review process, we're constantly looking for both the financial and strategic fit of those assets that we own and similarly, potential investment opportunities in front of us and balancing all of that against our path and plan to continue to strengthen our balance sheet. So all of those things fold into the mix for us. And if at some point in time we have something to announce, of course, we will do that. In the meantime, we just continue to do our work and focus on maintaining the commitment to our plan.
All right. That is -- appreciate the color there. And then just moving over to the dividend. In the MD&A, you reiterated the 8% growth commitment there. We do see -- and we appreciate the color in terms of when you expect to reach your credit metrics. What about the dividend payout ratio? When would you expect to get back into your targeted range there?
Robert, it's Greg. I mean, nothing has changed from what we think is the long-term target where we'd like to be. Obviously, as a result primarily of U.S. tax reform, it's unlikely that we'll get there in 2018 and 2019. But we certainly see making meaningful progress, both this year and next year, towards that path and targeting to get there by the end of the decade.
Your next question comes from David Quezada with Raymond James.
My first question, just on the Florida solar, the $70 million revenues in 2019. Just to confirm, is that a run rate you expect to reach? Or is that just a calendar year 2019 impact?
It's Greg. What'll happen, you get the $70 million, will get incorporated into 2019. There'll be another additional revenue bump in 2020, when the last tranche comes in and then that effectively is baked into rates, basically until the next general rate application. So it's not a onetime thing. It'll be in perpetuity until there's a general rate application.
Right. Okay, perfect. And then just, I guess, more broadly, thinking about your capital plan. A lot of moving parts. Seems like there's some good upside to it. I'm wondering when you would consider releasing a revised capital plan, if at all?
Yes, we're kind of -- our normal planning process, we're kind of in the middle right now where we're refreshing all of our capital plans and long-term business forecasts. And so our traditional schedule would be to kind of come out in the fall with any material or updated capital forecast.
Your next question comes from Robert Catellier with CIBC Capital Markets.
I just wanted to follow-up on Big Bend briefly here. I'm wondering if the strategy is to get a regulatory settlement -- some form of settlement on rates before you move forward with the project?
It's Nancy. Because we are not increasing the steam capacity at Big Bend, we don't actually need regulatory approval for the project. So once we have environmental approval, we'll be able to proceed fully with the project. So it's a repowering retirement, no increase in steam capacity. So it's a modernization, really, of an existing unit.
I think, Robert, it's -- sorry, go ahead Nancy.
And I was just saying, with the $750 million of customer benefit on that, it will get approved and we will look forward to get it approved in the next general rate application. But certainly, we believe that it's something that customers and regulator will like.
Okay, Robert, I was just going to add. I mean, obviously, with any large capital programs, to the extent that you can get a regulatory settlement from a revenue recovery perspective like the SoBRA, is helpful. But if it looks like -- and something -- maybe it's unusual, but something that we always strive to achieve. If we find that, to Nancy's point, that the cost recovery will be through a general rate application, we'll manage the capital spending so that we're not straining capital in the interim period.
Okay, got it. Just I appreciate the new disclosures on the U.S. tax reform. One item I wanted to clarify is that some of the other companies in the sector have been a little bit more convincing on the deductibility of interest on that particular issue. So I just wondered if you could clarify your disclosures in terms of the majority of U.S.-based financed -- interest can be properly allocated to the utilities? And exactly how much is the majority, I guess, is what I'm after and what -- is there any risk to that?
Robert, it's -- we're following the same path, I think, that all of our peers both north of the border and south of the border were assuming that the majority of our whole co interest expense, primarily related to our TECO bond financing, is going to be allocatable to the utility business, and therefore, deductible. And so what you're seeing flow through our results consistent with what we communicated last call is really just the change in effective rate on that tax. Everything that we've seen from financial advisers, from the Edison Electric Institute who is doing lobbying, we fully expect that, that is, in fact, going to happen. We think there's a very low probability that, that will be the place we find ourselves in later this year.
Okay, and then finally, none of you have had a little bit of -- a little bit of time in the elite chair. Scott, I was wondering if there's been any tweaks to your thinking on strategy.
So yes, I mean, tweaks would be the right word for it, I think, Robert, in the sense that -- look, I mean, the strategy that's in place today and you've heard me talk about it in recent shareholder meetings with you and with others, has been in place for a decade. And that strategy of delivering cleaner, affordable, reliable energy to customers continues to be relevant today and we think durable for the near future that certainly that we see. But I think, you've also seen us emphasize the word reliable more recently than we might have before. You also hear us talking more about investing in technology to improve the customer experience. And so those kinds of themes are -- I think you use the right word, tweaks, as it relates to the fundamental strategy and the execution of that, which is delivering cleaner, affordable and reliable energy to customers.
Your next question comes from the line of Ben Pham with BMO.
I wanted to follow-up on the payout ratio question and comments around the payout ratio reduction towards this -- towards the end of this decade. And I'm wondering, you got a lot of visibility on the rate base growth in Tampa and whatnot. And I'm just -- I'm curious, how does the capacity payments play in that outlook that you're providing on the payout? Is that more of a gradual decline that it's significant in that overall analysis or it's just really something you guys can really -- can manage well going forward?
Yes, I think, Ben -- I mean, a large challenge that we have, I think, of getting there faster was the result of U.S. tax reform and the after-tax cost of our debt. And so we view a world where we grow into it naturally. We're expecting, both in '18 and '19 on average, to probably have double-digit EPS growth and that by itself will allow us to bring that number down. Obviously, the capacity payments on our New England gas generating plants are part of that. The growth in Florida is also part of that. So collectively, when we look at the core business, we see a natural growth and no need to do anything materially different from what we've been doing.
Okay. And can you give a high-level sense of how that high FFO to debt ratio moves around, looking at you -- assumptions you're highlighting today, this year and maybe next year, if you can?
Yes, I think in general, about $150 million of debt is about 10 basis points on our cash flow credit metrics and about $15 million of FFO would have the same kind of directional effect.
Are you guys at 12% right now or?
We wrapped up both, I think, I don't know if they published it. Both the rating agencies have this just north of 10 at the end of last year and we are targeting 12 by the end of the year.
Your next question comes from Andrew Kuske with Crédit Suisse.
I guess, question might be for Greg and it's just on Emera Energy. Given the quarter that you've just had and we've seen some of these quarters in the past, how do you think about, effectively, the book and the positioning for the remainder of the year, is clearly, you've outperformed in the quarter. Do you effectively derisk and lock things down as much as you can and really preserve that and then use those excess cash flows just for deleveraging a capital investment? Like how do you think about the positioning of the business? And then financially, on how you use those proceeds?
Yes, Andrew, good question. I mean, we don't maintain open positions. So as opportunities come up to hedge, that I alluded to in the first quarter, we've done that. I think on an annualized basis, obviously, what we've experienced in Q1, is baked. It's not something that we're putting at risk over the balance of the year. If you look on an annualized basis, we talked about the $40 million plus U.S. of capacity payments, tax -- FX adjusted tax effect, it's effectively kind of in that $40 million plus in earnings. We would see us going from last year where we were at the low end of the $15 million to $30 million guidance for our trading group towards the high-end and we're seeing a little bit of benefit from increased spark spreads and generation at the plant. So I think when you collectively add that up, you should probably think of us going from what was probably the low 20s last year net income, up to $80 million-plus this year.
Okay, that's very helpful. And I know you talked a little bit about this in your prepared comments just on your capital structure, how much headroom do you have on prefs and hybrids? And where would be the situs? Would you look to push press down on some of the underlying subs to grid like an SPI, for example, or can you do more on a hybrid function at the top of the house at Emera at the whole co?
I mean, Andrew, we've got quite a bit of headroom on the prefs. I don't know the exact number, but I would say that our headroom is probably greater than what the market capacity might be right now. But from a mathematical perspective, it's probably high hundreds of millions of dollars, probably close to $1 billion of capacity on our capital structure.
[Operator Instructions] Your next question comes from Robert Kwan with RBC Capital Markets.
I was just coming back to the Big Bend modernization. There was some talk about trying to recover it within a general rate case, is that something based on your forecasting that you would have to do? Or do you think you've got some room in the revenue line with loading customer growth and anything you can do on the cost line?
Robert, it's Nancy. We would, of course, run AFUDC on the way through, but we -- our expectation is that we would have to go in for a general rate application, eventually, for that $800 million, $850 million investment.
Okay. Just coming back, I guess, to the tax form impact and the cash flow side of things and, Greg, you provided a bit of bridge, kind of, by pieces and some of the dollar impact on how you're mitigating or bringing the 2018 down from, I guess, it was that kind of the $200 million worst-case scenario, ended up $75 million to $125 million range. Just wondering, is there something similar then, kind of starting at that $200 million number for 2019 and beyond? You gave the AMT amount of $100 million, I'm just wondering, how does that kind of walk back to something closer to 0?
Yes, and so I think when you look at what is likely to transpire in 2019 versus 2018, what we will see is a reduction in base rates at Tampa Electric. So for tax reform, we still have to go through a regulatory process. Obviously, there's a lot of moving pieces to calculate that. We expect that number to be less than $100 million on a rate reduction. That will be offset in 2019 by the refund of our AMT credits, which will start when we file our 2018 tax returns and we'll get that refund. And so all being said, that sounds like it's a bit of a positive for us. But then we'll have, obviously, some adjustments through rate cases in New Mexico and Maine as well, as well as Peoples Gas that is already taking effect. So when we add all of that up and we look at '19, we think '19 is going to be relatively neutral to 2018.
Understood. I guess, maybe then to go back to, where did the original $200 million number come from, like what was in that number originally that you don't think is going to play out?
Yes, so the -- I think the way we try to characterize it on last quarter's call, was that was the book end that if we had a most likely a negative regulatory decision in virtually every one of our jurisdictions. So think of Peoples Gas, New Mexico Gas, Emera Maine, that we had to refund effective January 1 per customers, regardless of where we would have been in ROE band. Tampa Electric would've kept us on the same schedule of storm restoration cost, the collection of those costs and retroactive adjustments as well. And so was going through the steps to say what is the worst-case scenario on each and every one of those. And obviously we've done a lot of work over the last few months to mitigate that.
There are no further questions queued up at this time. I'll turn the call back over to Mr. McOnie.
Well, thank you, everybody, for participating. We appreciate your interest in Emera and please reach out to us if you have any questions.
This concludes today's conference call. You may now disconnect.