Fortis Inc. (FTS) Q2 2019 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by. My name is Sharron and I will be your conference operator today. Welcome to the Fortis Q2 2019 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, Sharron, and good morning, everyone. And welcome to Fortis' second quarter results conference call. I'm joined by Barry Perry, President and CEO; and Jocelyn Perry, Executive VP and CFO; other members of the senior management team, as well as CEOs from certain subsidiaries. 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 2019 second 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.

Thank you, Stephanie, and good morning, everyone. Let me start by saying that our team made great progress in the quarter to advance our growth strategy. Most notably, we announced that we’re increasing our 2019 capital outlook by $600 million to $4.3 billion, representing a 16% increase. As part of funding our incremental capital, we raised $142 million from the aftermarket equity program or ATM to fund the equity component of our increased capital expenditures. Looking beyond 2019, we remain committed to the $17.3 billion 5-year capital plan. We are currently updating the plan to reflect the 2020 to 2024 5-year period and expect to update the market on September 10 at our Investor Day. In mid April, we successfully closed the sale of the Waneta Expansion for proxies of approximately $1 billion and booked a $484 million gain related to this transaction. Net proceeds were used to pay down corporate short-term borrowings as well as repurchase a portion of the corporation's outstanding debt. We are pleased with this outcome. In July, we issued our 2019 sustainability update, the report updated the performance of our utilities and expanded our reporting on indicators related to employees, natural gas operations and water use. Additionally, we included information on our efforts to advance United Nations sustainable development goals. Our focus on energy delivery limits our impact on the environment. That said, we strive to do better by delivering cleaner energy and being a strong energy partner in our communities. With our focus on the delivery of cleaner energy, TEP announced they’re partnering with key community stakeholders and climate change experts at the university of Arizona to develop new carbon emission reduction goals to prepare for the future energy needs of the customers. We are focused on reducing our environmental footprint and look forward to working with these stakeholders to create measures focused on emission reduction and increase renewable energy to customers. In British Columbia, we recently announced that FortisBC entered into a 2-year supply agreement to export 53,000 tons of LNG per year to China, equivalent to heating 30,000 homes per year in BC. This is the first Canadian agreement to have LNG regularly shipped to China. The LNG supply is contracted through the recently expanded Tilbury facility. This development is an encouraging step for Canada's LNG export industry and for FortisBC as we think about further LNG expansion at the Tilbury site. Turning now to Slide 5, a walk through the drivers of the 2019 $600 million capital increase. This increase is evidence of our focused effort to grow the regulated businesses by identifying and executing on opportunities within our existing footprint. Capital spending for 2019 is expected to increase to $4.3 billion, up from $3.7 billion previously announced. This increase is driven by regulated investments in renewable energy, transmission infrastructure and grid modernization. UNS is the main driver of the increase and is forecasting to spend $1.4 billion in capital investments this year, up $300 million from the $1.1 billion we previously disclosed. In March, TEP announced the construction of the US$370 million Oso Grande Wind project. Construction of the 247 megawatt wind farm is expected to commence later this year and be online by the end of next year. We previously included this project in the plan as a 150 megawatt project and the increased capacity resulted in more than $200 million of additional capital spending in 2019. Once completed, it will become TEP's largest renewable energy resource and generate enough power to supply nearly 100,000 homes per year. This project is expected to increase TEP's renewable energy to approximately 28% of its total production by 2021. ITC is focused on making needed grid investments in and around its existing operating territories. As a result, ITC identified additional grid solutions as well as several small transmission asset acquisitions within the existing footprint. These investments result in approximately $100 million increase in capital spending for 2019. The remaining incremental capital spend is a result of investment needed to maintain and upgrade our existing infrastructure at our other regulated utilities and higher foreign-exchange. Our major capital projects for 2019 are progressing well and are on track. ITC recently announced completion of multi-value projects four and seven. These new high-voltage transmission lines are part of 17 multi-value projects approved within the Midwest to provide access to low-cost electricity generation, improve reliability and efficiency and expand access to renewable energy resources. At UNS, the majority of the capital will be executed in the second half of the year. In addition to the Oso Grande Wind project, significant project spending for the balance of the year includes the expected purchase of the Gila River Generating Station Unit 2. In addition, UNS expects to begin investing in the 250 megawatt Southline transmission project, a transmission line across Southern New Mexico and Southern Arizona. A significant milestone was recently achieved in the Wataynikaneyap Power Project when the environmental assessment notice of approval was received for the final two phases of the project. The project is targeted to be completed in 2023 and will reduce greenhouse gas emissions associated with the diesel generation currently used by the remote communities. We're confident in our ability to deliver on our $4.3 billion capital plan for 2019. Virtually all of our planned capital investments for the year are in our regulated businesses. As mentioned earlier, we expect to update our new 5-year capital plan on September 10 at our Investor Day. For 45 consecutive years, we have increased our dividend. This consistent track record makes us a leader in dividend growth in Canada. Our strong growth profile coupled with our low-risk highly regulated and geographically diversified energy deliver utility business gives us confidence that we will be able to continue this track record for the foreseeable future. I will now turn the call over to Jocelyn for an update on our second quarter 2019 results.

Thank you, Barry, and good morning, everyone. Reported earnings for the quarter of $720 million or $1.66 per common share is significantly higher than last year. Earnings for the quarter reflect the $484 million gain on the sale of our 51% interest in the Waneta expansion. On a year-to-date basis, reported earnings of approximately $1 billion or $2.39 per common share also reflect the gain on the Waneta sale when compared to the previous year. Adjusted EPS of $0.54 for the quarter was $0.05 lower compared to the second quarter in 2018. This decrease was primarily due to weather. Cooler temperatures at UNS and decreased production at the Belize Hydro generating facilities, driven by lower rainfall, reduced EPS by $0.06 in the quarter. On a year-to-date basis, adjusted EPS was $0.02 lower than the first six months of 2018. Rate base growth driven by our regulated businesses as they continue to execute on their capital plans was offset by unfavorable weather impacts, reduced earnings and Aitken Creek and regulatory lag in Arizona. Weather alone impacted EPS by $0.06 in the first half of 2019 when compared to 2018. Before getting into the specific drivers of the quarterly in year-to-date earnings results, I want to spend some time this morning on the weather impacts during the quarter. Earnings for the second quarter in our Arizona business was down $21 million from the prior year. The decrease was driven by an approximate 10% reduction in retail sales due to cooler temperatures, which reduced air-conditioning load in the region. In recent years, Tucson has recorded some of its hottest temperatures with the second quarter of 2018 being the second hottest quarter on record. In comparison, this year the region experience its mildest second quarter in the last 20 years. The month of May was particularly cooler in the Tucson region. This resulted in 32% lower cooling degree days than normal during the quarter. Earnings for the quarter and year-to-date were also impacted by the weather in Belize as they are experiencing drought conditions. With the lower rainfall, production in the second quarter was 15 gigawatt hours compared to 57 gigawatt hours in the previous year. For the first six months of 2019, production was 39 gigawatt hours compared to 120 gigawatt hours in 2018. So again, in total, weather driven impacts on earnings per common share was $0.06 for the second quarter. And now turning to Slide 11, let's take a look at the other EPS drivers in the quarter. First and foremost we saws growth at the majority of our regulated utility businesses. This growth was led by ITC, which contributed to an increase in EPS of $0.03 and $0.01 was driven by our Western Canadian Electric and Gas businesses. Next, higher U.S dollar to Canadian dollar foreign exchange rate favorably impacted results this quarter. The average rate was a $1.34 compared to a $1.29 in the second quarter last year. Furthermore, there was a $0.01 EPS increase during the quarter due to lower corporate costs, partially offset by a higher number of weighted average common shares as a result of the shares issued under a dividend reinvestment plan and the ATM. The earnings loss from no longer having the Waneta plant was offset by reduced corporate finance charges and again on the US$400 million tender offer. As previously mentioned, lower earnings at UNS mainly driven by cooler temperatures reduced EPS by $0.06. At our non-regulated energy infrastructure businesses, EPS decreased by $0.03 for the quarter. This was driven by lower realized margins that Aitken Creek and lower rainfall decreasing production in Belize. And lastly, earnings at Central Hudson and in our other electric segment reduced EPS by $0.02, reflecting timing of insurance proceeds received in 2018 related to the hurricane Irma and timing differences associated with Central Hudson's rate order. Turning to Slide 12, adjusted year-to-date earnings per share decreased $0.02 compared to the same period in 2018. Similar to the quarter, a higher U.S dollar to Canadian dollar foreign exchange rate for the first half of 2019 resulted in a $0.04 EPS increase. Additionally, rate base growth at ITC improved EPS by $0.03 and our Western Canadian utilities improved EPS by $0.02 for the first half of 2019. At Central Hudson, EPS increased $0.01 driven by higher delivery rates and lower storm restoration costs. UNS contributed to a $0.05 decrease in EPS for the first half of 2019. Again, this was largely driven by cooler temperatures in Arizona as well as higher costs associated with rate base growth that are not yet included in rates due to the historical test year. The non [technical difficulty] infrastructure businesses results were negatively impacted by weather as a result of lower rainfall in Belize and lower realized margins at Aitken Creek also impacted EPS year-to-date. And lastly, EPS was lower by $0.01 reflecting a higher number of weighted average common shares, partially offset by lower corporate costs. Turning now to our 2019 regulatory outlook. At ITC, we await a final decision from FERC and the MISO-based ROE. You will recall that FERC also issued two notices of inquiry in March. The first comment on its policies for determining the ROE used in setting rates. And the second on how to improve its transmission incentive policy to ensure appropriately encourage the development of needed infrastructure to the benefit of our customers. Comments were due to FERC at the end of June and upon review, ITC view the submissions is generally in line with expectations. Reply comments on the based ROE were provided to FERC last week and reply comments on the incentive NOIs will be provided later this month. And at this time it is still uncertain weather and wind [technical difficulty] further on these matters. As you are aware, FERC ordered last October that ITC was no longer fully independent and reduced the incentive adder to 25 basis points, down from the approximate 50 basis points that ITC was earning in rates. ITC appealed this decision, but in July FERC denied ITC's request for rehearing. ITC is now considering its options, including potentially appealing to the U.S Court of Appeals. As discussed during the last quarter, FortisBC filed its multiyear rate plan earlier this year as the current term expires at the end of 2019. The proposed plan seeks approval for rate setting framework for 2020 through to 2024, and we anticipate a decision next year. Tucson Electric Power filed its rate case April 1. Current rates at TEP are based on a mid-2015 test year and our requested rates include approximately US$700 million of additional rate based investments. Additional request in the rate filing include an ROE increase of 60 basis points to 10.35% and increased equity thickness to 53%. The rate case hearings are scheduled for early 2020 and a decision is anticipated next year. Lastly, TEP also filed a proposal with FERC in May, requesting its current state of transmission rates and revenue requirement be replaced with forward-looking formula rates to allow for more timely recovery of transmission related costs. Just this week FERC issued an order accepting TEP's proposed rate revisions effective August 1, subject to hearing and settlement procedures. This concludes my remarks. And I will now turn the call back to Barry.

Thanks, Jocelyn. The Fortis business keeps getting stronger. Our portfolio of well run highly regulated utilities are focused on delivering energy to customers each and every day. Given our diversification, coupled with the low-risk nature of our assets, we're able to focus on the local needs to customers, which in turn yield opportunities to grow the business for the foreseeable future. As we look ahead to the remainder of 2019 and beyond, our growth profile is strong and supports our 6% dividend guidance. We look forward to rolling out our 2020 to 2024 plans to you at Investor Day in Michigan. Lastly, Fortis is a leader in the ESG area. Sustainable practices remain front and center as we serve our communities in North America. We are committed to doing even more in this area in the future. I will now turn the call back to Stephanie.

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

Thank you. [Operator Instructions] And our first question comes from Robert Kwan with RBC Capital Markets. Please go ahead with your question.

Thanks. If I can just come back to the sort of the ATM and managing the uptick in the 2019 capital, I’m just wondering was that kind of you just proactively looking at the funding resources in your credit metrics, or did you have anything specific from the rating agencies ultimately as well just, what’s the expected use on the ATM for the remainder of the year?

Robert, really it's consistent on what we’ve been saying. If we said, if our capital goes beyond the levels that we disclosed, we would start using the ATM. There is nothing from the agencies or anything like that. It's just you're seeing -- we're seeing obviously increased growth here and we’re just tapping into that market. It is a very low cost efficient way of raising the equity component of that growth.

Okay. And I guess just with some of the lead times of converting some of that to cash, should we think about ATM usage being close to the full uptick in capital though?

I would say, we are going to obviously report our ATM usage on a quarterly basis and we're going to discuss our full funding plan in September, Robert. So I would just say stay tuned for that. It's a month away. We are putting the final touches on our 5-year capital plan and funding strategy. So we well have a deep dive in September on that.

Sounds good. I guess, just kind of turning to weather, looking forward here, how is Belize actually shaping up for, call the second half, and then for Arizona following kind of the weaker weather quarter. Weather looked really good in July. So did you -- have you seen that uptick in usage for TEP?

So, David -- I think we talked about this yesterday. I think we’re about normal for July, David, is that correct, in Arizona?

Yes, we ended up being actually pretty hot for July. We ended up being the third hottest that we had on record for July compared to last year, lower than 9th hottest. So there's a little bit of a positive delta, but we haven't even closed the books yet, Robert, but we expect it to be at least slightly positive.

That’s great. Okay.

And believe, Robert, sort of drought conditions continue, although this is typically around when the rainy season starts and what remind everyone, in Belize we -- one tropical storm can fill the reservoir at times. So it's -- it doesn't take much. So I think they change pretty quickly, but right now we are still experiencing very dry conditions there.

Okay. And just to finish in Arizona, have you spend anything yet to connect or support the Rosemont mine? And if so, are there any recovery provisions which is -- that just get rolled in if that continues to get sideways for now?

David, do you want to take that one?

Sure. The answer to the -- quick answer to that, Robert, is no and we won't be spending any. Rosemont funds the entire transmission line and then turns it over to us. So we don't have any capital at risk or regulatory recovery risk associated with that project or its delay.

That’s great. Thank you.

Thanks, Robert.

Next question comes from Ben Pham with BMO. Please proceed with your question.

Thanks. Good morning. I just want to stay with UNS and then some of [indiscernible] volatilities you’ve seen this quarter last year. And I’m just wondering, as you think about the earnings of this utility going forward, is there any impetus to look at revenue decoupling at UNS at all?

Yes, in a perfect world, yes, Ben. But I always thought it was going to be extremely hot in Arizona. So, I guess, I’m betting on the heat. So, yes, we’ve one quarter that was a little cool there. David, maybe you can comment on historically the utilities in Arizona really focus at all on the sort of decoupling issue. I know, obviously, we had a historical test year in Arizona as well. The business is growing well over the years. So the utility there haven't really, I guess, taken this on recently. So maybe you can share some history, David.

Yes. We do -- Ben, we do have a partial decoupling mechanism that takes into account both energy efficiency and distributed generation reductions. We’ve a utility here at Southwest Gas. It does have a full decoupling mechanism that does include weather. Neither us or any other utility that I’m aware of in Arizona has a full decoupling mechanism. It has been something that has been discussed kind of in fits and starts over the past probably decade, since we implemented the energy efficiency rules. But it's -- we don't have that request in our current rate case, but longer term that might be something that we look at, but nothing really on the radar screen at this point.

All right. Great. And maybe just switch to some of the commentary on FERC transmission ROEs. Looking through the commentaries that have been followed in, it sounds like everything is in line with your expectations. Can you expand on that a little bit like as you go through a filing. Is this -- is it more -- you’re not seeing anything in that that as quite challenging in terms of folks really looking for lower ROEs, or are you just saying in line that you don’t expect there's really any material outcome from this -- these reviews analyzed?

Ben, the comments were more really reflective of our review of all the submissions and sort of coming up with a conclusion that there's been nothing really new in the submissions that from what -- what's been filed before at FERC. And remember this is like in some cases 6, 7 years of process now that we’ve been going through and FERC did open up the ROEs process for further submissions few months back and those submissions really didn't create any new sort of ideas in our view. And so that's -- that was the nature of that comment. Linda, maybe you can add some more flavor than that, but that's sort of my understanding.

Yes, Barry, I mean I would sort of categorize it as when we say that the comments were as expected, I would say sort of industry, the transmission owners, the utilities EEI groups like wires, obviously supported -- obviously the continuation of incentives as well as it relates to the ROE NOI very supportive of them, the new methodology that FERC has established in the New England proceedings. On the other side of the coin, state commission, consumer advocates, customer groups were as expected, opposed to sort of additional incentives for investment in transmission. And then I would say there was a third category of sort of the renewable energy industry that supported and advocated for incentives to incent transmission to interconnect renewables. So I think when we say as expected, I think that’s sort of the genesis of the comment. I think it's still too early to say or suggest what FERC might do with these NOI proceedings. I think obviously, FERC is going to have to wade through all the comments and ultimately make some policy decisions in terms of what direction they want to go in terms of the NOI proceedings.

All right. That’s great. That’s very helpful. Thank you.

Thanks, Ben.

Your next question comes from Julien Dumoulin-Smith with Bank of America. Please proceed with your question.

Hey, good morning.

Good morning, Julien.

Hey. So just wanted to follow a little bit up on that last question on transmission, if you can. Can you elaborate a little bit on some of the latest on the 2019 transmission expansion plan? Since the headline is about where that that’s shaping out in the MISO region specifically and how that reconciles against your own current budgets? Just sort of curios. Then even to the extent to which [indiscernible] preempting September's draft release of the '20 MTEP. Any sense of where this is all heading versus where you projected last go around, and I recall last year's update itself was pretty material already. So, little bit of preemption of next month or September's updates, that I’m very curios.

So, Julien, I’m not going to seal [ph] all my good material for September. So -- but I would tell you that we still see good growth at ITC and very, very, strong on the business there. So, Linda, maybe you can offer some specific comments regarding the MISO stuff for Julien.

Yes, Julien, I would just say, look, if history is any indication of the future, I mean I would not focus on in terms of what is -- what submitted in terms of the specific projects versus what might to recommend. History always demonstrate that what comes out of the MISO process is less than we submit. And I would just say our forecast, our capital forecast in our 5-year plan is solid and we do not anticipate any outcome of the MISO preliminary recommendations or ultimately the MTEP decision having any effect or impact on our capital forecast.

Okay. Fair enough. And then, Hickory -- just while we're on the subject of transmission, any updates in confidence, be able to get the thing done?

Linda, keep going.

Yes. Sorry, your question was on the Hickory -- Cardinal-Hickory Creek MVP 5 line?

Yes.

Yes, that’s obviously proceeding. We've gone through the hearings process in Wisconsin, and we now await a decision from the Wisconsin commission. I would say we feel very confident on the outcome of that decision, primarily based on, obviously, the need for the project. Obviously, it's been a pretty, I would say, contentious case just in terms of sort of the environmental interests that have come out and opposed the project, but we remain confident that we will get approval for the project, given the need for the project.

Got it. And then last quick one, maybe a high-level, with respect to Arizona and everything going on in that state with some of your peers, confidence still in the rate case process and the integrity of the progress altogether? I would just be curious if you’ve anything to add without getting too specific, if there's anything you want to throw out there.

Well, Julien, from my perspective, I'm going to let David weigh in here. But just from my perspective, we still have positive relations with the commission and I'm still very positive overall on Arizona. Our business there has done extremely well since we purchased it and the economy is strong. Yes, there's some noise with the regulator and some of the issues, I would think more specifically with APS, but obviously we get dragged into that from time-to-time. So, David, maybe you can provide some more color since you're on the ground there.

Yes, I don't think that we see anything that's going to necessarily affect or impact our pending rate case. We do have a lot of policy topics under discussion at the commission, and I think we will as our state generally does. We will do a very orderly and thoughtful process in evaluating energy policy and everything else that’s on the dockets here. So, we’ve a lot under discussion, and again, if we do it in that orderly fashion, I think we can meet both the requirements and desires of our customers and our regulators. So, nothing that we are super worried about at this point.

Your next question comes from Mark Jarvi with CIBC Capital Markets. Please proceed with your question.

Good morning.

Good morning.

Just wanted to go back to UNS and just think about some of the timelines here for capital deployment in the back half, or maybe into 2020. With Oso Grande and the bill transfer agreement, can you just remind us how you actually see capital deployed at TEP as that has progressed and eventually completed?

David, do you want to take that?

Yes, I don't have the schedule right in front of me, but that US$370 million, I think it's about two thirds of it that goes in this year, in essence, in writing checks just based on the funding agreement that we’ve with the constructor there. So, it is fairly heavy loaded here toward the tail end of this year, and then the rest of that capital will be dribbling in over the entire 2020 time period up until that year end. So that’s why we had that little bit of a difference in uptick in the 2019 capital budget. When we upsize that project from 150 to that roughly 250 megawatt number, we also finalized the payments in that schedule and that's what kind of pulled a little extra into 2019.

Okay. That's helpful. And then on some of the other bigger ticket items like Southline and Gila Unit 2, just wondering confidence if that happens in 2019, or chance that kind of gets pushed out a bit?

We are still very confident with Gila. That is just, in essence, triggering a option to buy that plant and writing the check to Salt River Project for it. So that capital, I think, is pretty well on schedule. As far as the Southline Project, we don't have much in this -- in the 2019 year, but we do still expect to spend that here, and then the vast majority of that is over the next couple years.

Okay. And then, maybe just turning around the corner to the Investor Day in a month's time, but -- so the incremental $100 million spend at some of the utilities, maybe just kind of comment on where you're finding those opportunities and whether or not it's just this year, or you see that carrying forward into future years?

I think you're going to have to stay tuned, Mark, for the Investor Day. Obviously, that $100 million is spread a bunch -- over a bunch of businesses. Some of it's renewables, those kind of things, but I think that we will have much more to say about that in September.

Fair enough. And then maybe just last question here on ITC on some of these small tuck-ins and add-on assets, like how much more of that do you guys see in the footprint and the pace of those types of small additions?

All of our businesses are looking for this kind of stuff, things that -- that's in their footprint, that may be owned by industrial firms or whatever that we can actually get in and run a little better because it's our business. So, it's always a little bit of that, but I don't see it as being material in any way to the -- to long-term growth, but we will get one of them every now and then. I sort of put, for example, like the REAs in Alberta in the same category, maybe small munies in Ontario, these are things that occasionally, we will be able to successfully get one of them over the line, but they're really now in the $30 million, $40 million, $50 million range and they're good stuff, but again, not material.

Okay, thanks.

Your next question comes from Rob Hope with Scotia Capital. Please go ahead with your question.

Good morning, everyone.

Good morning, Ron.

First question, back on Arizona, just wanted to know if you have any comments on the commission's hearing about looking at retail competition once again in the state?

My only comment is I think it's the third time this has been looked at in Arizona, and obviously, we're going to work with the commission if there's a process regarding that and we are involved in those discussions. So, I will say that, generally, Fortis has always been focused on poles and wires. So that's a core business and we're comfortable there. And clearly, Arizona is the place that we’ve generation, and it's in rates right now. I always look at competition -- as long as you're treated fairly when it's deregulated in terms of your investments in that generation, then you should be Okay. But, David, do you want to offer some more comments?

Yes, I would just echo what you just said, Barry. If we go through a nice, detailed, thoughtful review and process on this, I think you're going to come out with one of two options. One is, I think, that folks will see that there's a lot of unintended consequences in a competitive market, and that there's really no problem here that we're trying to fix. And I think at the end of the day, with that sort of review, you would probably say it's not worth it. But if, at the end, you do and the commission decides that we need to go to a competitive generation market, remember, this is generation only, it just depends on how you set the rules and how you do that. It's very difficult, extremely complicated to get all of that stuff right, and if -- but if you do get all of that right, it can be beneficial. So at the end of the day, it's not something that we are extremely worried about. But we do want to make sure that this takes into account the opinions of all the stakeholders, and there's quite a few folks lining up against competition as they have in other states recently. But it takes away some of the policy decision-making capability of our commission if you go to a competitive wholesale market, we think the state loses a lot of its ability to drive energy policy in a competitive market. So a lot of discussion still to be had around this, a lot of workshops, and still -- hopefully, a lot of input from all the stakeholders.

All right. And then switching over to the west side of the continent, I just saw that you secured some additional contracts on the LNG, but on a longer-term basis, how are you thinking about increased LNG volumes out of B.C. versus the need to kind of reinforce and increase the reliability of the system?

We are -- I continue to become more and more excited about our prospects for our gas business in British Columbia. I keep reminding folks that we’ve a large gas LBC there serving over a million customers, and we currently own the lion share of gas infrastructure in the province. So -- and we are right now in the midst of conversations regarding further investment in that gas infrastructure related to resiliency of the pipeline network to get more redundancy into the lower mainland, whether it would be also tank storage to be able to ride through any problems on the system and LNG export from our Tilbury site. So, none of this is really in our plans at this point in time, but I'm really optimistic that Fortis will be able to find some ways to deploy capital to make the business better in British Columbia and we are really excited about that, and hopefully we can talk a little more about that over the next little while.

Good stuff. Looking forward to the Investor Day. Thank you.

Your next question comes from Patrick Kenny with National Bank Financial. Please proceed with your question.

Yes, good morning and thanks for the sustainability update. Obviously, TEP is well on pace to reach that 30% renewables target on the generation front. Just wondering if you can comment longer term around potential opportunities to accelerate coal to gas or ramp up new renewables. And again, what this might mean for potential rate base upsides, say, over the next five years plus?

Patrick, thanks for the question on this, because I am so proud of my team in Arizona. David, really agreeing to work with the University of Arizona and community stakeholders to really work together to develop the right plan for that community. And I think that’s -- that hasn't been done in all cases in different regions around North America and I am proud of the team for taking that on. So I do believe that this will allow more investments to occur in that region in renewables over time and I'm going to let David talk a little bit about those prospects.

Yes, Patrick, we are going through that integrated resource planning process right now. And obviously, when people see that we're hitting our 2030 goal really in just a couple of years, we are going to likely see the desire and our own desire to increase that a little bit more. Now, we are going to shift to hopefully greenhouse gas reduction targets because I think that’s really what we should be focusing on from integrated resource planning and from a climate perspective. But during that process, I'm sure we will have stakeholders kind of all over the map on how far and how fast we want to go related to renewables. It will provide, I think, significant upside in our business to invest in some of these renewables, and of course the renewable supporting technology. I mean -- I think going forward, when we are already at 30%, any time you say, additional renewables, you have to add storage in that next breath. And so we are going to be looking at that stuff really hard over this next year and developing a plan for what that looks like for the next 15 years is what our IRP is, but we're going to be looking out even further than that.

Patrick, I should mention that one thing we haven't talked about really is renewable natural gas that much. We continue to increase the amount of renewable natural gas that we have in British Columbia and I see that as, again, another area that potentially will grow our business in over the next decade. So we're pretty excited about sort of the I will call, the ESG component of that gas business in British Columbia as well.

That's interesting as well. I was also just going to follow-up and ask if there was any update on Big Chino at this point?

So, Big Chino, big project, the right kind of project for the region in Arizona. ITC obviously was spearheading this very large pump storage facility. It would take about 8 to 10 years probably to do it, maybe in the same kind of range of probably $6 million to $8 billion. So we really took a step back in this project in the last few months here and really are now looking at how do we move forward. So we've slowed down the spending a little bit, because it's -- it really was too large of a project for the company. So we're looking at engaging with some other partners to see if we can move it forward from here. So, it's -- I would say, slowed a little bit here at this point.

Okay. I appreciate those comments.

[Operator Instructions] We have a question from Chris Turner with JP Morgan. Please proceed with your question.

Good morning, everyone. I just wanted to maybe get some help understanding the decision to raise the CapEx guidance today. Obviously, you have discrete projects, but I think maybe you could have pushed back some CapEx in other areas or wait until the Analyst Day. So maybe some help around that decision on the messaging there. And I wanted to just confirm that it's still your message that the base CapEx plan ex this does not require external equity, just the DRIP.

So, Chris, I guess it's just August 1, and we were seeing significant increase in '19, so we just felt that for the year we couldn't wait until September, given that we were issuing our second quarter results here to be transparent. But for the 5-year plan, we sort of felt that we could wait. It's not yet been finalized that we can wait until September 10. That was sort of the logic we, I suppose we could have easily just added $600 million to the 5-year and been done with it, but I guess we wanted to update the full five years at once rather than dripping it in over time kind of thing. So, in terms of the equity, we do -- when you look at how we identify the funding last year for the $17.3 billion, we talked about the equity we get from our DRIP plan, dividend reinvestment, we talked about asset sales, the Waneta sale, so we've been executing on that. So Nothing has really changed on that. We did as well say if CapEx was going up, we would start using the ATM, which is what’s happened now in this quarter. So I think everything we’ve done has been consistent with what we’ve been talking about for the last year.

Okay. And then, my second question is on EPS growth. I think in 2018, your growth was negative 1%. It's down 2% year-to-date, but consensus still has you guys growing 4% year-over-year. Any color on how kind of how to think of the back half or any drivers that might help growth at that time?

We don't comment on EPS guidance, Chris, other than I will just say we're feeling really good about the business, we're investing a lot of capital in our regulated businesses, they're high-quality businesses and that capital will increase the earnings of those businesses over time and will be reflected in Fortis's growth over the period. When you think about it, we are basically a big wires business in North America that's growing its rate base in the 7% range right now. So that's pretty strong growth and that’s going to end up being reflected in EPS growth over time.

All right. Thank you, Barry.

Thank you.

[Operator Instructions] As there are no further questions at this time, I will turn the call over to Ms. Amaimo for any closing remarks.

Thank you, Sharron. We have nothing further at this time. Thank you everyone for participating in our second quarter 2019 results call. Please contact Investor Relations should you need anything further. Thank you for your time and have a great day.

Thank you for participating. Ladies and gentlemen, this concludes today's conference. You may disconnect.