Ladies and gentlemen, thank you for standing by. My name is Sharon 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. At that time, those with questions should press star followed by one on their telephone. If at any time during the conference you need to reach an operator, please press star zero. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.
Thanks, Sharon, and good morning everyone, and welcome to Fortis's second quarter results conference call. I am 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 slideshow. 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.
Thanks, 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 are increasing our 2019 capital outlook by CAD 600 million to CAD 4.3 billion, representing a 16% increase. As part of funding our incremental capital, we raised CAD 142 million from the at-the-market equity program, or ATM, to fund the equity component of our increased capital expenditures. Looking beyond 2019, we remain committed to the CAD 17.3 billion five-year capital plan. We are currently updating the plan to reflect the 2020 to 2024 five-year period and expect to update the market on September 10th at our Investor Day. In mid-April, we successfully closed the sale of the Waneta expansion for proceeds of approximately CAD 1 billion and booked a CAD 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 the United Nations Sustainable Development Goals. Our focus on energy delivery limits our impact on the environment. 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 are 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 increased renewable energy to customers. In British Columbia, we recently announced that FortisBC entered into a two-year supply agreement to export 53,000 tons of LNG per year to China, equivalent to heating 30,000 homes for a 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 five, I'll walk through the drivers of the 2019 CAD 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 CAD 4.3 billion, up from CAD 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 CAD 1.4 billion in capital investments this year, up CAD 300 million from the CAD 1.1 billion we previously disclosed. In March, TEP announced the construction of the $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 CAD 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. ITC identified additional grid solutions as well as several small transmission asset acquisitions within its existing footprint. These investments result in an approximate CAD 100 million increase in capital spending for 2019. The remaining incremental capital spend is the 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 MW 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 2 phases of the project.
The project is targeted to be completed in 2023 and will reduce greenhouse gas emissions associated with the diesel generations currently used by the remote communities. We are confident in our ability to deliver on our CAD 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 five-year capital plan on September 10th 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 delivery utility business, gives us confidence that we will be able to continue this track record for the foreseeable future. I now turn the call over to Jocelyn for an update on our second quarter 2019 results.
Thank you, Barry. Good morning, everyone. Reported earnings for the quarter of CAD 720 million, or CAD 1.66 per common share, is significantly higher than last year. Earnings for the quarter reflect the CAD 484 million gain on the sale of our 51% interest in the Waneta Expansion. On a year-to-date basis, reported earnings of approximately CAD 1 billion or CAD 2.39 per common share also reflect the gain on the Waneta sale when compared to the previous year. Adjusted EPS of CAD 0.54 for the quarter was CAD 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 CAD 0.06 in the quarter. On a year-to-date basis, adjusted EPS was CAD 0.02 lower than the first six months of 2018.
Rate-based growth, driven by our regulated businesses as they continue to execute on their capital plans, was offset by unfavorable weather impacts, reduced earnings at Aitken Creek, and regulatory lag in Arizona. Weather alone impacted EPS by CAD 0.06 in the first half of 2019 when compared to 2018. Before getting into the specific drivers of the quarterly and 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 CAD 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 experienced 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. Again, in total, weather-driven impacts on earnings per common share was CAD 0.06 for the second quarter. Now turning to slide 11. Let's take a look at the other EPS drivers in the quarter.
First and foremost, we saw growth at the majority of our regulated utility businesses. This growth was led by ITC, which contributed to an increase in EPS of CAD 0.03, and CAD 0.01 was driven by our Western Canadian electric and gas businesses. Next, a higher U.S. dollar to Canadian dollar foreign exchange rate favorably impacted results this quarter. The average rate was 1.34 compared to 1.29 in the second quarter last year. Furthermore, there was a CAD 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 our dividend reinvestment plan and the ATM.
The earnings lost from no longer having the Waneta plant was offset by reduced corporate finance charges and a gain on the US $400 million tender offer. As previously mentioned, lower earnings at UNS, mainly driven by cooler temperatures, reduced EPS by CAD 0.06. At our non-regulated energy infrastructure businesses, EPS decreased by CAD 0.03 for the quarter. This was driven by lower realized margins at Aitken Creek and lower rainfall, decreasing production in Belize. Lastly, earnings at Central Hudson and in our other electric segment reduced EPS by CAD 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 CAD 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 CAD 0.04 EPS increase. Additionally, rate-based growth at ITC improved EPS by CAD 0.03, and our western Canadian utilities improved EPS by CAD 0.02 for the first half of 2019. At Central Hudson, EPS increased CAD 0.01, driven by higher delivery rates and lower storm restoration costs. UNS contributed to a CAD 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-based growth that are not yet included in rates due to the historical test year. The non-infrastructure businesses was also 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.
Lastly, EPS was lower by CAD 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 on the MISO base ROE. You will recall that FERC also issued two notices of inquiry in March. The first sought 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 it appropriately encourages 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 viewed the submissions as generally aligned with expectations. Reply comments on the base ROE were provided to FERC last week, and reply comments on the incentive NOI will be provided later this month.
At this time, it is still uncertain whether and when FERC 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 last quarter, FortisBC filed its multi-year 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 1st.
Current rates at TEP are based on a mid-2015 test year, and our requested rates include approximately $700 million of additional rate-based investments. Additional requests in the rate filing include an ROE increase of 60 basis points to 10.35% and increase 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 1st, subject to hearing and settlement procedures. This concludes my remarks, and I'll 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 are able to focus on the local needs of 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 have remained 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'll 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. Ladies and gentlemen, we will now conduct the question and answer period. If you would like to register a question, please press the star followed by the one on your telephone. If your question has been answered and you would like to withdraw your registration, please press the pound sign. If you're using a speakerphone, please lift your handset before entering your request. One moment please, for the first question. 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 usage of the ATM and managing the uptick in the 2019 capital, I'm just wondering, was that you just proactively looking at the funding sources 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 in what we've been saying. We've said if our capital goes beyond the levels that we've disclosed, that we would start using the ATM. There's nothing from the agencies or anything like that. It's just 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. I guess just with those, 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're going to obviously report our ATM usage on a quarterly basis, and we're going to discuss our full funding plan in September, Robert. I would just say stay tuned for that. It's a month away. We're putting the final touches on our five-year capital plan and funding strategy. We'll have a deep dive in September on that.
Sounds good. I guess just turning to weather. Looking forward here, how is Belize actually shaping up for, call it the second half? Then for Arizona, following the weaker weather quarter, weather looked really good in July. Have you seen that uptick in usage, for TEP?
David, I think we talked about this yesterday. I think we're about normal for July, David, is that correct, in Arizona?
Yeah, 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, where we were the ninth hottest. There was a little bit of a positive delta, but we haven't even closed the books yet, Robert. We expect it to be at least slightly positive.
Okay. That's great.
In Belize, Robert, the drought conditions continue, although this is typically around when the rainy season starts, and I'll remind everyone, in Belize, one tropical storm can fill the reservoir at times. It doesn't take much. Things could change pretty quickly, but right now we're still experiencing very dry conditions there.
Just to finish in Arizona, have you spent anything yet to connect or support the Rosemont Mine? If so, are there any recovery provisions or would that just get rolled in if that continues to go sideways for them?
David, do you want to take that one?
Sure. The quick answer to that, Robert, is no, and we won't be spending any capital. Rosemont funds the entire transmission line and then turns it over to us. We don't have any capital at risk or regulatory recovery risk associated with that project.
Moran, I want to stay with UNS and some of the water volatility 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?
In a perfect world, yes, Ben. I always thought it was going to be extremely hot in Arizona, I guess I'm betting on the heat. We had one quarter that was cool there. David, maybe you can comment on historically, have the utilities in Arizona really focused at all on the sort of decoupling issue? I know obviously we had the historical test year in Arizona as well. The business has grown well over the years. The utilities there haven't really, I guess, taken this on recently, maybe you can share some history, David.
Yeah. We do, Ben. We do have a partial decoupling mechanism that takes into account both energy efficiency and distributed generation reductions. We have a utility here, Southwest Gas 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 in fits and starts over the past, probably decade, since we implemented the energy efficiency rules. We don't have that request in our current rate case. Longer term, that might be something that we look at. Nothing really on the radar screen at this point.
All right. Great. Maybe to switch to some of the commentary on FERC transmission ROEs. You look through the commentaries that have been filed, and it sounds like everything's in line with your expectations. Can you expand on that a little bit? As you go through the filings, you're not seeing anything that is quite challenging in terms of folks really looking for lower ROEs? Are you just saying in line, and that you don't expect there's really any material outcome from these reviews analyzed?
Ben, the comments were more really reflective of our review of all the submissions, sort of coming up with a conclusion that there's been nothing really new in the submissions from what's been filed before at FERC. Remember, this is like, in some cases, six, seven years of process now that we've been going through, FERC did open up the ROE process for further submissions a few months back, those submissions really didn't create any new ideas, in our view. That was the nature of that comment. Linda, maybe you can add some more flavor than that's sort of my understanding.
Yeah, Barry, 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 the continuation of incentives as well as it relates to the ROE NOI, very supportive of the new methodology that FERC has established in the New England proceeding. On the other side of the coin, state commissions, consumer advocates, customer groups were, as expected, opposed to sort of additional incentives for investment in transmission. 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. I think when we say as expected, I think that's sort of the genesis of the comments.
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 proceeding.
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. 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? There's been some headlines about where that's shaping out and in the MISO region specifically and how that reconciles against your own current budget. Just sort of curious. Even to the extent that we said, I suppose preempting September's draft release of the 20 MTEP, any sense of where this is all heading versus where you projected last go around? I recall last year's update itself was pretty material already. A little bit of a preemption of next month or September's release, but I'm super curious.
Julien, I'm not going to steal all my good material for September. I will tell you that we still see good growth at ITC and very strong on the business there. Linda, maybe you can offer some specific comments regarding the MISO stuff, for Julien.
Yeah, Julien, I would just say, look, if history is any indication of the future, I would not focus on in terms of what's submitted in terms of the specific projects versus what MISO recommends. History always demonstrates that what comes out of the MISO process is less than we submit. I would just say, our capital forecast and our five-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.
Oh, okay. Fair enough. Hickory, just while we're on the subject of transmission, any updates and confidence in being able to get this thing done?
Linda, keep going.
Yeah. Sorry, your question was on the Hickory Cardinal Creek MVP5 line?
Yeah.
Yes. That is obviously proceeding. We've gone through the hearing 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. We remain confident that we will get approval for the project, given the need for the project.
Got it. 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 process altogether. I'd just be curious if you have anything to add without getting too specific, just 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. Obviously we get dragged into that from time to time. David, maybe you can provide some more color since you're on the ground there.
Yeah, 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. I think we'll do as our state generally does. We'll do a very orderly and thoughtful process in evaluating energy policy and everything else that's on the dockets here. We have 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. Nothing that we're 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.
I just want to go back to you and ask 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 build transfer agreement, can you just remind us how you actually see capital deployed out of TEP as that is progressed and eventually completed?
David, do you want to take that? Yeah. I don't have the schedule right in front of me, but that $370 million US, 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 have with the constructor there. It is fairly heavy loaded here towards 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. That's why we had that little bit of a difference in uptick in the 2019 capital budget. When we upsized that project from 150 to that roughly 250-megawatt number, we also finalized the payments and that schedule, and that's what kind of pulled a little extra into 2019.
Okay. That's helpful. On some of the other bigger-ticket items like Southline and Gila unit 2, just wondering, confidence that that happens in 2019 or chances of that kind of gets pushed out a bit?
We're still very confident with Gila. That is just, in essence, triggering an option to buy that plant and writing a check to Salt River Project for it. That capital, I think, is pretty well on schedule. As far as the Southline project, we don't have much in the 2019 year, but we do still expect to spend that year and then the vast majority of that's over the next couple of years.
Okay. Maybe just turning around the corner to the Investor Day in a month's time, the incremental CAD 100 million spend on some of the utilities, maybe you 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 CAD 100 million is spread over a bunch of businesses. Some of it's renewables, those kind of things. I think that we'll have much more to say about that in September.
Fair enough. Maybe just the last question here on ITC on some of these small tuck-ins and add-on assets. How much more of that do you 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'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. There's always a little bit of that, but I don't see it as being material in any way to long-term growth. We'll 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 munis in Ontario. These are things that occasionally we'll be able to successfully get one of them over the line, but they're really now in the CAD 30 million, CAD 40 million, CAD 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.
Morning, everyone.
Morning, Rob.
First question back on Arizona. Just want 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. 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. Clearly, Arizona is a place that we have 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 investment in that generation, then you should be okay. David, you want to offer some more comments? Yeah. I'd 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. I think at the end of the day with that sort of review, you'd probably say it's not worth it. 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. But if you do get all of that right, it can be beneficial. At the end of the day, it's not something that we're extremely worried about, but we do want to make sure that this takes into account the opinions of all the stakeholders.
There's quite a few folks lining up against competition as they have in other states recently. 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. A lot of discussions still to be had around this, a lot of workshops, and still hopefully a lot of input from all the stakeholders.
All right. Switching over to the west side of the continent. 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 BC versus the need to reinforce and increase the reliability of the system?
I continue to become more and more excited about our prospects for our gas business in British Columbia. I keep reminding folks that we have a large gas LDC there, serving over a million customers, and we currently own the lion's share of gas infrastructure in the province. 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 be also tank storage to be able to ride through any problems on the system, and LNG export from our Tilbury site. 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.
We're 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.
Yeah, good morning, and thanks for the sustainability update. Obviously, TEP is well on pace to reach that 30% renewable 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. What this might mean for potential rate base upside, 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. I think that hasn't been done in all cases in different regions around North America, and I'm proud of the team for taking that on. I do believe that this will allow more investments to occur in that region in renewables over time. I'm going to let David talk a little bit about those prospects.
Yeah, Patrick, we're going through that integrated resource planning process right now. Obviously when people see that we're hitting our 2030 goal really in just a couple of years, we're going to likely see the desire and our own desire to increase that a little bit more. Now we're going to shift to hopefully greenhouse gas reduction targets, because I think that's really what we should be focusing on from an integrated resource planning and from a climate perspective. During that process, I'm sure we'll 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 think going forward, when we're already at 30%, anytime you say additional renewables, you have to add storage in that next breath. We're 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. 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'll call it the ESG component of that gas business in British Columbia as well.
Yeah, that is interesting as well. Was also just going to follow up and ask if there was any update on Big Chino at this point.
Big Chino, big project, the right kind of project for the region in Arizona. ITC obviously was spearheading this very large pumped storage facility. Would take about 8 to 10 years probably to do it. Maybe in the same kind of range of probably CAD 6 billion-CAD 8 billion. We really took a step back on this project in the last few months here and really are now looking at how do we move forward. We've slowed down the spending a little bit and
It really was too large of a project for the company. We're looking at engaging with some other partners to see if we can move it forward from here. It's, I would say, slowed a little bit here at this point.
Okay. Appreciate those comments.
Once again, if you'd like to ask a question, please press star one on your telephone keypad. We have a question from Chris Turnure with JPMorgan. 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 waited to the Analyst Day. Maybe some help around that decision on the messaging there. 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.
Chris, I guess it's just August 1st, and we were seeing significant increase in 2019, so we just felt that for the year we couldn't sort of wait till September, given that we were issuing our second quarter results here to be transparent. For the five-year plan, we sort of felt that we could wait. It's not yet been finalized, that we could wait till September 10th. That was sort of the logic. I suppose we could've easily just added CAD 600 million to the five-year and been done with it. I guess we wanted to update the full five years at once rather than dripping it in over time kind of thing.
In terms of the equity, when you look at how we identified the funding last year for the CAD 17.3 billion, we talked about the equity we get from our DRIP plan, dividend reinvestment. We talked about asset sales, the Waneta sale. We've been executing on that, so nothing's 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. I think everything we've done has been consistent with what we've been talking about for the last year.
Okay, my second question is on EPS growth. I think in 2018, your growth was negative 1%. It's down 2% year-to-date. Consensus still has you guys growing 4% year-over-year. Any color on 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'll 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're basically a big wires business in North America that is growing its rate base in the 7% range right now. That's pretty strong growth, and that's going to end up being reflected in EPS growth over time.
All right. Thank you very much.