Fortis Inc. (FTS) Q3 2017 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. My name is Ruth and I will be your conference operator today. Welcome to the Fortis Q3 2017 Conference Call and Webcast. During the call, all participants will be in a listen-only mode. There will be a question-and-answer session following the presentation [Operator Instructions]. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Thanks, Ruth, and good morning, everyone, and welcome to Fortis’ 2017 third quarter results conference call. I’m joined by Barry Perry, President and CEO; and Karl Smith, Executive VP and CFO, other members of the senior management team as well as executives from certain subsidiaries, including Eddington Powell with FortisTCI. Before we begin today’s call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our 2017 third quarter MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to Barry.

Thanks, Stephanie, and good morning, everyone. Strong third quarter results reflect the execution of our top priorities for 2017, with the first priority focused on integrating ITC and the second priority centered on reaching a constructive rate case settlement in Arizona. Successful execution of both these priorities had positioned Fortis for a strong 2017. Some would say, we are firing on all cylinders. Last month, we announced our new capital expenditure program of $14.5 billion for the period 2018 through 2022. This reflects an increase of $1.5 billion from the prior year’s plan. The capital program is predicated on a diversified mix of highly executable low-risk projects and supports our average annual dividend growth target of approximately 6% through 2022. We had a strong quarter notwithstanding a number of challenges. In August, government-owned BC hydro exercised its right of first offer, resulting in the terminations of our agreement with Teck Resources to acquire Teck’s two-thirds ownership interest in the Waneta Dam hydroelectric facility. While we were disappointed with the outcome, Fortis realized a $24 million after-tax break fee from Teck.. And in early September, our utility in the Turks and Caicos Island suffered significant damage to its transmission and distribution network, following Hurricane Irma’s path of destruction. We’re so thankful to report, all of our employees were safe and no fatalities occurred on the islands. Further, our generation assets withstood minimal losses and no employee injuries were reported during the restoration efforts. To-date, FortisTCI, as we stored electricity to approximately 99% of all of its customers that have the capability to be reconnected. To restore the islands electric system in a timely manner, Fortis deployed nearly 250 power lines technicians, planners and other support staff, including those from our operating utilities across North America and contract personnel to support the restoration efforts. In fact, Fortis was the first responder with boots on the ground within 48 hours of the passing of Hurricane Irma. Restoration costs, largely capital in nature are estimated at U.S. $25 million to $30 million. We anticipate requesting recovery of these costs as part of the FortisTCI’s annual regulatory filing. All in all, Hurricane Irma challenged our operations, and in doing so, brought our entire company closer together. Employees from America, from Canada and from the Caribbean are contributing to help FortisTCI. A great example of our substantially autonomous business model coming together to serve our customers to restore life essential electricity, while concurrently carrying on operations at all our other utilities. As a reminder, FortisTCI’s assets represent less than 1% of Fortis’ total consolidated assets. In October, we announced a quarterly dividend increase of 6.25% for the December 1 dividend payment This marks 44 consecutive years of annual common share dividend increases, continuing one of the longest records in Canada. In addition to the dividend increase, we extended the targeted of average annual dividend growth guidance of approximately 6% through 2022. Now for some information on our recently announced five-year capital program. As highlighted at our Investor Day a few weeks ago, our new five-year capital program of $14.5 billion consists of a diverse mix of highly executable low-risk projects. The program is driven by projects that improve the transmission grid, address natural gas system capacity and gas line network integrity, increased cyber protection and allow the grid to deliver cleaner energy. As a result, our consolidated rate base is expected to exceed $25 billion this year and climb to approximate $32 billion by 2022. This yields a three-year rate base CAGR of 5.2% through 2020, and a five-year CAGR of 4.5% through 2022. Our average annual capital spending over the next five years is projected to be $2.9 billion, up from $2.6 billion in our previous plan. This is due in part to the efforts of our improved business planning process to identify proven investment opportunities across our utilities for all five years of our capital program. Fortis BC and UNS are the primary contributors to the $1.5 billion increase in our five-year capital program. At FortisBC, the forecast now includes the Eagle Mountain Woodfibre Gas Pipeline project estimated at $350 million. The pipeline expansion project will support the proposed LNG site in Squamish, British Columbia. Given that the project has received the number of approvals over the past year, we’ve included in our new plan. The project remains contingent on Woodfibre, LNG proceeding with its facility. Additionally, the multi-year pipeline integrity management program at FortisBC estimated at $300 million has been added. The program is focused on improving pipeline safety and integrity of the high pressure transmission system, including pipeline modifications and looping. At UNS, the new capital program includes the expected addition of 200 megawatts of flexible generation resources and the 550 megawatts Gila River Generating Unit 2 facility. The addition of flexible generation resources consists of 10 natural gas fired reciprocating engines and is estimated at $230 million with expected in-service dates between 2019 and 2020. The engines will provide ramping and peaking capabilities, replace aging, less efficient steam turbines and will facilitate the addition of renewable generating resources to the grid. Further, the addition of the 550 megawatt natural fired gas – natural gas-fired Gila River Generating Unit 2, estimated approximately $210 million, will assist with the replacement of retiring coal-fired generation facilities. This project will include an initial tolling agreement with a purchase option expected to be exercised in late 2019. Beyond the base capital program, our near-term development projects continue to progress. In fact, just last week, the newly released Ontario long-term energy plant highlighted both the Wataynikaneyap Power project and the Lake Erie Connector project. We view this acknowledgement by the Ontario government as a positive development in advancing these projects forward. During the quarter, progress was made on the Wataynikaneyap Power project, when the Federal government announced up to $60 million in funding to connect the Pikangikum First Nation to Ontario’s power grid. This First Nation is the closest of the 22 First Nation communities to the grid and this funding decision gives momentum to a larger project. Remaining milestones include finalizing a cost-sharing agreement between the federal and provincial governments, filing for a leave to construct, as well as environmental approvals and permitting. At ITC, the Lake Erie Connector project received its final major permit approval from the U.S. Army Corps of Engineers on October 16. The project is now fully permitted in both the United States and Canada. ITC previously received a Presidential Permit from the U.S. Department of Energy, as well as a major permits from Canadian – Canada’s National Energy Board and the Pennsylvania Department of Environmental Protection. The remaining milestones include completing cost refinements and securing favorable transmission service agreements. As the only contracted transmission project included in Ontario’s 2017 long-term energy plan, this two-way line will provide the first direct power connection between Ontario and the PJM energy market, which is comprised of 13 states in the Eastern – in the East United States. The Lake Erie Connector will open a door to electricity trading between these two markets that will improve the security and reliability of both energy grids. I’ll now turn the call back over to Karl for an update on our third quarter results.

Thanks, Barry. Good morning, everyone. As Barry highlighted, our third quarter 2017 financial results were quite good. Adjusted earnings for the quarter were $254 million, compared to $153 million for the same quarter last year. Adjusted earnings per share of $0.61 for the quarter were higher by $0.07, or 13%. On a year-to-date basis, adjusted earnings of $794 million were higher by $322 million, and adjusted earnings per share were higher by 16%, or $0.26, reaching $1.92. Cash flow from operations of $2 billion for year-to-date September 2017 increased more than 40% over the same period in 2016. The increase was driven by contributions from ITC and higher earnings from UNS. As noted on the previous slide, adjusted earnings per share increased $0.07 compared to the third quarter of 2016. ITC contributed $0.03 to adjusted earnings per share after considering finance charges and increased equity associated with the acquisition. A $0.03 increase in adjusted earnings per share was driven by Aitken Creek and relates to mark-to-market of natural gas hedges and improvement of the underlying business. During the third quarter, there were $3 million of unrealized gains recognized, compared to an unrealized loss of $1 million for the same period in 2016. UNS delivered another strong quarter, improving our adjusted earnings per share quarter-over-quarter by $0.02. New rates effective February 2017 at Tucson Electric Power was the main driver. FortisAlberta improved by $0.02 per share compared to the third quarter last year. This was driven by higher capital tracker revenue. On a year-to-date basis, FortisAlberta continues to be largely in line with 2016 earnings performance. Tempering earnings, foreign exchange impacts resulted in a $0.01 decrease in the third quarter earnings per share over the same period in 2016. The average U.S. dollar to Canadian dollar foreign exchange rate was $1.25 this quarter, down from $1.31 in the third quarter last year. As a reminder, earnings are not significantly affected by U.S. dollar to Canadian dollar foreign exchange fluctuations. As stated in the past, that for every $0.05 change in the Canadian to U.S. dollar exchange rate, there was a corresponding $0.07 impact to annual earnings per share. We recently implemented a hedging program, utilizing forward sales contracts for a portion of our U.S. dollar cash flows. This program will reduce our earnings per share exposure to approximately $0.06 for every corresponding $0.05 change and foreign exchange. Increased common equity resulting from a dividend reinvestment plan lowered adjusted earnings per share by $0.02 compared to the same period in 2016. For the nine months ended September 30, 2017, adjusted earnings per share increased $0.26 compared to the same period in 2016. Year-to-date, UNS had very good performance, improving our adjusted earnings per share by $0.15. The revenue impacts resulting from the recent rate order and higher electricity sales due to hot weather in the second quarter were the major drivers. In addition, timing of operating expenses and more favorably priced wholesale electricity contracts contributed to higher earnings. Aitken Creek contributed an $0.08 improvement in adjusted earnings per share year-to-date. Unrealized gains on the mark-to-market and natural gas hedges contributed approximately $0.05 of this increase. The remainder largely reflects a full nine months of ownership of the facility, which we acquired in April 2016. ITC contributed $0.07 to adjusted earnings per share for year-to-date 2017, after considering finance charges and increased equity associated with financing the acquisition. Partially offsetting these increases were lower earnings from our Caribbean utilities, given the impacts of Hurricane Irma and a higher weighted average number of common shares outstanding as a result of our dividend reinvestment plan. Our strong business risk profile is supported by the stable, predictable cash flows generated from our regulated utility operations, maintaining financial flexibility and preserving our investment grade credit ratings. From a liquidity perspective, our consolidated credit facilities totaled approximately $5.3 billion. At the end of September 2017, there was $4 billion of unused capacity, including approximately $1 billion of unused capacity under our committed corporate credit facility. Our capital program is fully funded through debt raised at the utilities, cash from operations and common equity contributions from our dividend reinvestment plan. As we pursue incremental and near-term development projects beyond our base capital plan, we will remain financially disciplined ensuring that the opportunities are appropriately accretive to earnings per share and support of our existing credit ratings. We continue to enjoy relative regulatory stability and we remain focused on two significant regulatory decisions. As you may recall, at ITC, we await a decision from FERC on the Second MISO ROE Complaint, which is anticipated next year. At Central Hudson, our request to increase the electric and natural gas rates with the New York Public Service Commission was filed in July. The rate filing seeks to increase the allowed ROE to 9.5% from 9%, and the equity component of the capital structure to 50% from 48%, and order is expected in mid-2018. In addition, we are working on two legacy proceedings at UNS and FortisAlberta. At Tucson Electric Power, the second phase of the rate case related to net metering and the rate design for new distributed generation customers is expected to be completed in the first quarter of 2018. At FortisAlberta, we anticipate a decision in the first quarter of 2018 on the rebasing application to establish the revenue requirement for the second PBR term and 2018 distribution rates. Further, as a decision on the generic cost of capital to determine an ROE and capital structure for the period 2018 through 2020 is expected in the third quarter of next year. Before wrapping up, I’d like to comment briefly on the preliminary U.S. tax reform house bill that was released yesterday. While it is early in the process, the impacts are not material at a consolidated level and do not change our operating approach or strategy. In addition, the impact is minimal at the U.S. operating subsidiaries and presents opportunities to advance investments in energy infrastructure. On balance, there’s a slight negative impact to earnings in the early years, assuming we do not factor in improved economic conditions or any other mitigating factors. In fact, the impact is well within the range of outcomes that we would generally see in our planning process. I’ll now turn the call back to Barry.

Thank you, Karl. To close, our strategy is straightforward. We’re leveraging our low-risk business model, operating expertise and diverse footprint of our regulated utilities to drive growth opportunities for the business. After a very strategic and successful expansion into the United States, we are now focused on sustainable investment in our existing utilities. The opportunities that we are pursuing will enhance our ability to serve customers safely and reliably, grow our rate base and support our 6% average annual dividend growth target through 2022. Before closing, I want to congratulate and thank Eddington Powell and his team at FortisTCI, along with the restoration crews from other subsidiaries for their safe and rapid response to restore electricity for our customers on the Turks and Caicos Islands. Now I’ll turn the call back over to Stephanie.

Thank you, Barry. This concludes the presentation. At this time, we would like to open the call to address questions from the investment community.

Ladies and gentlemen, we will conduct a question-and-answer period. [Operator Instructions] Your first question comes from the line of Rob Hope with ScotiaBank. Please go ahead.

Good morning, everyone.

Good morning, Rob.

Question is for Karl, hoping you could add a little bit more color just in terms of the GOP tax proposal, it’s early days and this is just a starting point. But what are the key drivers that are kind of informing that initial slight negative view on that? Would that just be some of the double leverage related to that U.S. operating subsidiaries?

There’s really got nothing to do with the double leverage, Rob. And on balance, it’s probably a positive compared to some of the proposals that have been slowed over the last year. The slightly negative, it comes from the reduced tax shelter at the holding company level. So the tax rate decreases from 35% down to 20% and obviously less of that interest is back sheltered. The good news, at least, on the surface and again, this is really early days, Rob. So we’ve got to spend some more time taking through this. But the good news is that the bonus depreciation – it looks like bonus depreciation will come to an end. That’s a slight positive in terms of the operating subsidiaries, because the rate base doesn’t decline at such a rapid rate. So that’s one thing. Interested operability was a scary item over the last mine months, but it looks like with this 30% shelter or a limit of up to 30% EBITDA that we would be fine there. So really the negative impact of any would come from the reduced tax shelter on the interest expense that we have at our holding company in the U.S.

All right. That’s good color. Thank you. And then switching gears just in terms of Woodfibre, you added it to your project list with the Investor Day a couple of weeks ago. It looks like the construction schedule has been pushed off a little bit. Just want to make sure you’re still confident on that project and want to continue it in the secured bucket?

Yes. We are, Rob, based on our assessment of all the work that’s going on with the proponent there, our assessment is the project still going to go. Clearly, we continue to work with them and monitor it. And if our view changes, we will update that in our quarterly information, but we’re pretty confident this point is going to go forward.

All right. Great, thanks. Congrats on a good quarter.

Thank you.

Your next question comes from Robert Kwan with RBC Capital Markets. Please go ahead.

Good morning. Just looking at the two transmission projects in the Ontario, long-term energy plan, especially on the Lake Erie. Have you seen a big change in the last, call it, quarter two in terms of potential discussions in securing Ontario power to back the line?

Well, we haven’t obviously disclosed, Rob, who we are and we dealing with, but we are continuing to have dialogue. So, I really can’t add much more color than that. We’re progressing. The project obviously with the permitting now complete. So our big focus right now is on the transmission service agreement and we continue to work that.

Okay. And I guess just related to the Waneta project and that BD costs you incurred in the quarter. How should we think about that going forward?

Well, they were sort of long ago incurred costs and we did get sort of a order from the OEB that sort of allowed us to start deferring costs. And there were certain conditions of that order that these costs didn’t qualify for, so we just clean that up, Rob. So we’re not expecting at this point that we would have further write-offs of costs related to that – of that project. We would obviously accumulate the costs under the OEB order. And if the project did not go forward, we would seek to recover those in our rates in Ontario. But that project is really giving momentum at this point, and there’s a real focus in trying to move it forward this fall here, so.

Got it. And if I can just finish on Aitken Creek, just in terms your hedging, is – are the derivatives really just the gas season kind of a summer/winter play, or do you have longer-term hedges that are driving the mark-to-market, such as, I don’t know if you’re actually hedging the underlying cushion gas?

The hedges aren’t long in nature, Rob, they would be like summer in the summer or winter in the winter type of factors.

Okay.

And these are the accounting rules, of course, in all. And it’s really one-half of what you see there, because we only hedge the gas as we acquire it and put it storage. So we don’t adjust the inventory value of that gas, obviously. So hard to predict what the volatility would be like on a go-forward basis. But the underlying economic reality is that, there’s really limited exposure of any to the gas that we have in the ground there.

Understood. Thank you very much.

Thanks, Rob.

Your next question comes from Andrew Kuske with Credit Suisse. Please go ahead.

Thank you. Good morning. I think, the question is probably for Karl just on the FX hedges you layered in, in a quarter. And just maybe walk us through a little bit of the logic on the FX hedges now, and why now in the market, and how you think about the FX hedges, are you really thinking about the dividends you’re paying in the future and having a greater probability and certainty around the cash flows to fund those?

It’s all about reducing the risk associated with our underlying our business plan. Obviously, we’re not going to go into a lot of detail about business plan assumptions. But we’re not trying to take a stand here, or try to predict where the exchange rates are going to go or going to be. So when we get to a position, where we’re locking in sort of what our planning assumptions are then we’ll take advantage of that. So just recently that opportunity presented itself. It is tied into the underlying cash flows from our U.S. operations that we repatriate and those funds support our dividend payments obviously. And so, we’ll just – it will be a program type of activity, where we’ll just – let them roll off, put them back again. In the intervening period, we do see an opportunity to sort of roll off one early then we’ll do that depending on where the exchange rates are at any particular point in time. But as you can see, I mean, it does mute the volatility, but the sensitivity is not that large, I mean, even given the hedges that we did recently, it uses only about $0.01 per share. So the other sort of that point is that, there’s not much volatility in our earnings period.

As evidenced in the quarter. Maybe just one different kind of question here. And maybe this is for Barry and it’s just about what you’re seeing in Alberta at this stage in time. Economy coming back a little bit, maybe some stutter stepping. But are you seeing any greater competition for labor in that market? And what’s really happening at the local utility levels? What kind of interesting data points are coming out?

Andrew, we remain very positive about Alberta. But maybe I’ll let Karl Bomhof, our CEO out there just say a few words about local conditions on labor and the economy. Karl, are you there?

Yes, I’m. Thanks, Barry. Yes, I mean, certainly over 2017, we’ve seen a little uptick in labor tightening. There has been slightly more activity in the oil and gas sector. We’ve seen some increases or return to customer connections there. Overall, I think that we’ve seen the bottom over the last couple of years, so there will be an uptick even on some wage growth across Alberta that there wasn’t in the past couple of years. We certainly don’t see a return to the pre-recession days, where the labor market was very tight, the recovery, particularly in country [ph] when it comes to the job market, it’s been very muted and slow. So we’re not anticipating that to be a risk to our organization at all.

Andrew, I will point out that we are really seeing some uptick in new customer growth in British Columbia on the gas side with these very prolonged – but very prolonged period of low gas prices, we are adding a fair number of customers in British Columbia right now. And also, Arizona, the economy picking up in Tucson. We’re starting – really start to feel the benefits of that, so that underlies obviously our optimism to our planning period, so.

That’s very helpful. Thank you.

[Operator Instructions] Your next question comes from Robert Catellier with CIBC. Please go ahead.

Hi, good morning. First, I’d like to offer my congratulations on the recovery at TCI, following Irma, I know that’s probably a lot harder to do and you made it sound on the call here.

It was damn hard Rob. So I’m so proud of the team. We – obviously, there’s still lots of folks in Turks and Caicos that are suffering from the impacts of Irma, but we’ve done our job well down there. We got the power back on. And the economy is going to start coming back quickly, and so we’re not going to miss the tourism season, that’s for sure. So that’s pretty, pretty damn good for the islands.

Fantastic. I was going to – you’ve actually touched on most of my questions. I just wanted to follow-up on the two Ontario projects that are currently in your capital plan specifically Lake Erie, I mean, it looks like a great product and that’s why it is included in old type, but just one thing to be included in that plan and another to get through the politics I guess. So, how would you characterize politics in terms of a gating factor, it’s a more – a question of just securing the customers and then the politics would take care of themselves if you think you have to wait till after the election before the customers are going to want to contract?

I would say because it’s in the plan, Rob, we have strong political support for the project, so I don’t think that’s the issue really. We’re just working through with an off taker to sign a contract really that would take the lion’s share of the use of the line. So, this is – it would be a longer-term contract, it is complex and we continue to work through that with the party. So, I think politically we’re – we got the support we need for both the Watay Project and Erie Connector. It’s always good for projects to have really a good common sense logic to them and both these projects have a great underlying story about why they should be moving forward, so we’re very optimistic that these will progress maybe Watay gets finalized before Erie, but ultimately I firmly believe that Erie Connector is a project that gets done.

Yes, I agree with you. Just a clarification from Karl on the tax reform, understanding it’s early days, but my first look at it, I mean when you say it’s a slight negative, that would only be from the status quo because and in my opinion the changes that were announced or proposed yesterday are actually slightly better than you originally discussed.

I agree with you totally Rob, but I mean all they can do is compare, at least at this stage anyway compare it to that status quo.

Right.

But as I mentioned, like some of the changes that have been suggested over the last nine months looked would have been more negative than what we saw yesterday. So our first read is that we’re pleased and the balance looks positive.

Yes, okay that’s what I thought, thank you.

Your next question comes from Linda Ezergailis with TD Securities. Please go ahead.

Thank you. I just had a follow-up question with respect to your Wataynikaneyap Project. I’m wondering how your discussions with the government are progressing in terms of how they view the considerations and pros and cons of ongoing subsidies versus an initial capitalization infusion and kind of what the bookings of possibilities are and when that will get resolved?

Linda, really we’re still in the midst of those discussions. I would tell you there is strong support from the federal government and the promise to sort of finalize the sort of funding structure I’ll call it, and so we’re having current discussions on those matters right now. Clearly this has to be from our perspective a business opportunity and a fully funded federal government project is not something that we’re interacted in frankly and neither are the First Nations for that matter. So there has to be equity investment in this project and so those discussions we’re having really revolve around that mix of contributions versus equity and we’re making progress there and – so everyone at the table really support this project going forward and see it as one of those frankly signature kind of projects for the relationship between First Nations business and government frankly. So I’m optimistic, but you’ve hit the nail on the head, we are focused on that funding structure right now.

Great, thank you.

Your next question comes from Jeremy Rosenfield with Industrial Alliance. Please go ahead.

Yes, thanks. Just a couple: one cleanup and one bigger one. Just on the recovery costs at TCI, was the thought that this would be recovered by adding the cost into – back into rate base and then you’re recovering that over time within rates, was that the idea?

I think, Jeremy, generally, asset remains to be seen exactly how it happens. We’ll be having dialogue with the government, with the regulator there as we progress this. Clearly, we’re open to very many different scenarios. But we’ve done our job in Turks and Caicos well before the storm, frankly, of making sure that that utility was operating at a very good standard. And also we did our job putting the power back on. And so we’ll have that dialogue with the regulator, and we do fully expect that our costs would be covered. Clearly, they would have to be, I think, come back to overall, probably for a long period of time. These are the normal way that you do these things. And so, we’ll be getting into those discussions now in the next few months here or so.

Okay. And just maybe on the same theme now for a second, when you think about the potential for hurricanes impacting the business, those are obviously thought of as one-time costs. But the question is, when you – as you move forward, do those costs accelerate? And then does the risk profile of the business change, our insurance costs going up like, have you done anymore sort of higher-level thinking as to the impact from hurricanes just generally on the investments in the Caribbean?

I would say, our thinking has not changed at all. We – there have been hurricanes in the Caribbean forever. And I’m not going to sign on to the thought at this point, at least, that they’re increasing or anything like that. So, the risk of being in the Caribbean, as you’re going to from time-to-time get a storm, and that’s why frankly, equity thickness and ROEs return on equity in the Caribbean should be higher and they are higher. So I think, that continues. That sort of compact continues to be there. And the key about our business is there. We’ve got to make sure that the assets are at the right standard and that can withstand like a – most of these storms. Clearly, it’s going to be hard to build stuff to Cat five standards. But we’ve done a pretty good job of strengthening our system down there. And especially when we – when you think about generation, we had no impact on our generation, which is very important that as soon as you’re ready to bring customers back on having that generation available was the godsend, frankly. So, we don’t look at it really any differently. Clearly, we would like to progress maybe on some of the regulatory mechanisms over time to make sort of recovery a little more seamless, I would say, as you go through these things. But we’ll make progress on those as we go forward here.

Okay.

Eddinton Powell, Eddinton is on the line. Anything you want to add Eddinton?I know, you’ve been there 60 days of putting the power backyard down there. So, jump in if I’m sure you have few things to say?

Well, I mean, Barry, you covered it quite well, and it’s not just that we’re thinking about business continuity and survivability of the system. But the government is also thinking about how we strengthened the entire infrastructure of the country. So the country survives and recovers some of the kinds of not sort of that sort of hurricane. But the Caribbean is no different than the Pacific to that Typhoon and those kinds of things.

I would say, Jeremy, on the insurance, clearly, we do put business interruption insurance in place for the Caribbean. And when there are busy storms seasons, you do see some knock-on impacts for future insurance, renewals that’s not uncommon and probably to be expected. We just frankly came through a period, where insurance premiums were going down for the Caribbean. So we were enjoying some better costs there. And I expect now that with the amount of storms we’ve gone through and the impact, we’ll start to see some creep going forward in the – in those costs, but that’s just a normal cycle to go through.

Okay, good. I appreciate the color. Just ask one more question around opportunities in DC. There have been rumblings recently around the site seeing, and I’m sure you saw the BCC report that came out. And I’m just wondering if you think that there are future attractive opportunities to participate more in sort of upstream power generation side in BC, obviously, within context of either contracted infrastructure, or regulated investment within FortisBC, how long what you were trying to do with one-year? But what’s the outlook there? Do you think that there is a bigger market opportunity potentially in the future?

I think, we’re really pursuing the right stop in British Columbia. There’s some natural gas for transportation. Renewable natural gas, harvesting from landfill, those kind of things are really in the wheelhouse of the current government, Community Solar, for example at the – on our electric utility. These are areas we’re looking at. So I’m really optimistic that we’ll continue to progress our business in British Columbia. We, as I mentioned earlier, we’re adding more customers now on the gas side, especially this prolonged period of low gas prices are really shining a light on how attractive it is to be a gas customer, frankly. So we are optimistic there, and we’ll continue to work those areas. And many of them are aligned with the strategy of the current government and the prior government for that matter so.

So that was a no for the power generation, or?

I’m probably reluctant to get into gas-fired generation, that kind of thing. We probably would look at some wind, some solar, but unless it’s in our regulated business, probably we’re reluctant to look at standalone facilities like that. So our focus is really on the cleaner energy area. And clearly, we’ll look at things when they come up. But generally, that’s where we see a lot of opportunity at this point so.

Okay. Thanks. That’s it.

Thank you very much.

As there are no further questions, I’d like to turn the call back to Ms. Amaimo for any closing remarks.

Thank you, Ruth. We have nothing further at this time. Thank you for participating in our third quarter 2017 results call. Please don’t hesitate to contact Investor Relations should you need anything further. Thank you for your time, and have a great day.

Thanks, everyone. Bye-bye.

Thank you for participating, ladies and gentlemen. This concludes today’s conference. You may disconnect.