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Hydro One Ltd
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Good morning, ladies and gentlemen, and welcome to the Hydro One Limited's Second Quarter 2021 Analyst Teleconference. [Operator Instructions] As a reminder the call is being recorded. I would now like to introduce your host for today's conference, Mr. Omar Javed, Vice President, Investor Relations at Hydro One. Please go ahead.
Good morning, everyone, and thank you for joining us in Hydro One's earnings call. Joining us today are our President and CEO, Mark Poweska; our Chief Financial Officer, Chris Lopez; and our Chief Regulatory Officer, Frank D'Andrea. In the call today, we will go over our recently filed joint rate application, our sustainability goals and the quarterly results. We will then spend the majority of the call answering as many of your questions as time permits. There are also several slides that illustrate some of the points we'll address in a moment. They should be up on the webcast now or if you dialed into the call, you can find them on Hydro One's website in the events -- in the Investor Relations section under Events and Presentations. Today's discussions will likely touch on estimates and other forward-looking information. You should review the cautionary language in today's earnings release and/or MD&A, which we filed this morning regarding the various factors, assumptions and risks that could cause our actual results to differ as they all apply to this call. With that, I'll turn the call over to our President and CEO, Mark Poweska.
Thank you, Omar. Before we begin, I'm sorry to share that in mid-June, one of our employees lost his life after being struck by a motor vehicle while working in the [ Catas casing ] region. Our thoughts and prayers are with his family, friends and coworkers. Along with all our employees, executives and directors, I'm devastated that we have experienced this tragic loss. Safety remains our top priority, and we must eliminate serious injuries in our company. The investigation on what led to this incident is ongoing. And together with the authorities, we are looking to understand the details and the cause of the accident. We are yet again reminded of the hazards our employees face and the extremely tough conditions in which they work to deliver reliable electricity and fulfill our customers' needs. To operate a safe and resilient grid, our assets need investment, and our customers are supportive of reinvesting in an electricity system that will provide them with reliable power. On August 5, we filed our comprehensive 5-year investment plan for both the transmission and distribution segments of our business with the Ontario Energy Board. Informed by extensive customer engagement, this is our first-ever joint rate application. It is a strategic plan to significantly improve reliability for our distribution customers, manage risks, prepare for the impacts of climate change, support communities and contribute to economic development. It balances the needs of customers with the impact on bills through our hard work, innovation and continuous improvement.In 2019 and 2020, Hydro One conducted customer engagement surveys to reflect customer needs and preferences for the transmission and distribution system investment plan. The engagement was the most comprehensive in Hydro One's history, with nearly 50,000 customers participating. For the first time, investment planning and customer engagement processes were integrated over 2 phases and customer feedback was provided as an input into the overall plan. In addition to hardening the system to withstand the impacts of climate change and to make it more reliable for future generations, we learned just how important it is, not only to Hydro One, but also to our customers that we one, proactively replace aging infrastructure to avoid more costly repair, maintenance and emergency work; two, make investments to improve reliability; and three, make the system more resilient. We also conducted a systemic review of our asset investment needs, driven by asset condition and system requirements. What we found was a significant portion of transmission, distribution and common assets have deteriorated to the point where they pose a risk to achieving business and customer objectives around safety, reliability and the environment. This needs to be fixed, and we are confident that our 5-year plan is the right plan for all Ontarians. We have a critical need to modernize our grid, to prepare for future integrated distributed energy resources, to prepare the system for severe weather and the impacts of climate change, to prepare for the greater electrification of the economy and enhanced cybersecurity, to ultimately develop a modern, flexible grid of the future. We have seen that Ontario has continued to prosper and there is continued economic growth that requires access to safe and reliable power. Whether it's the agriculture sector in Southwest Ontario or mining in the north, electricity is the backbone of the economy, and we are committed to connecting new customers and facilitating economic prosperity. As a result of our robust asset management approach and this significant customer outreach, we are proposing capital expenditures of approximately $12.5 billion over the 2023 to 2027 period. Of this amount, approximately 67% is geared towards system renewal. The remainder represents a combination of: one, nondiscretionary spend driven by our obligation to connect; and two, investments to ensure that we are meeting operational objectives and addressing future customer requirements. Some examples of the work that is contemplated under the extensive investment plan are as follows. For the transmission segment, we will invest approximately $3.5 billion to address station assets, including those which link major generation resources to major load centers, and those that serve local distribution companies and large industrial facilities. We've allocated approximately $1.9 billion to address lines assets which serve smaller towns, First Nations communities and businesses, pipeline compressor stations and large load facilities such as mines and paper mills. For the distribution business, we will modernize the infrastructure, to detect, repair and restore power more quickly, thereby improving resiliency and reducing the impact of power outages on our customers by up to 25% over the application period. We will install approximately 1,200 remote operable switches and reclosers, approximately 5,000 fault indicators. We will replace 51,000 wood poles in poor condition and refurbish another 14,000 poles. We will also add 120 distribution station transformers and facilitate new load connections. And these are just some examples of the extensive work required. Combined, these transmission and distribution capital investments will result in a rate base growth of approximately 6% per annum for the 5-year period, '23 to '27. This is an increase of approximately 1% from our previous rate base growth guidance till 2022, reflecting the needs of the system and our customers. We will do this work while becoming even more efficient and more productive. The savings, as a result of our combined hard work, our efficiency and our productivity to date, are already flowing to our customers. Since the IPO to the end of 2020, we generated over $738 million in productivity savings. These and future improvements allow us to reduce the rate impact for our customers. And I'm pleased to say that based on these numbers, in the first year of the new investment period, customer bills will decrease for the distribution segment by 1.8% and decrease for transmission segment by 0.3%. Over the 5-year period of the application, distribution and transmission customers will see an average increase that is less than expected inflation. Distribution and transmission bills will have an average annual increase of 0.8% and 0.3%, respectively, over 5 years. To put that into context, our typical residential customers' bill will increase by an average of $1.68 each year for the 5-year period. Again, our work to drive efficiencies and continually improve productivity has helped us to keep our costs as low as possible for our customers. And as we consider the needs of the grid, we are also taking the initiative to be mindful of the environment in which we operate. I am proud to report that we have received a number of accolades on the sustainability front. We received the Environmental Excellence Award from the Electricity Distributors Association for our pollinator program. We're recognized again by Corporate Knights as the best 50 corporate citizen in Canada, and we were designated a Sustainable Electricity Company yet again by the CEA -- So today, we are also excited to share our annual sustainability report. It highlights the important progress we have taken over the last year and sets out our new sustainability priorities centered on people, planet and community. We have further increased our transparency by aligning with GRI and SASB standards and are on our way to alignment with the TCFD standard. For planet, we are including climate change considerations into decisions and plans to ensure grid resiliency through our adaptation strategies. We're also making commitments to do our part in mitigating climate change and establishing new targets. While we only account for 0.2% of Ontario's emissions, we plan to achieve a 30% reduction of greenhouse gas emissions by 2030. Furthermore, Hydro One is committed to achieving net zero GHG emissions by 2050. This means that along with many other initiatives, we are planning on converting 100% of our fleet of sedans and SUVs to electric vehicles or hybrids by 2030. For people, we are setting targets and working to identify, eliminate and prevent systemic barriers in the workplace. As signatories to the Catalyst Accord, we are committed to achieving in our workplace at least 30% of female executives while our Board is already at 50%. We also signed the BlackNorth Initiative Pledge, under which we are committed to having 3.5% black executives and Board of Directors as well as hiring 5% black students in our workforce by 2025. These steps will renew our promise to identify, eliminate and prevent systemic barriers in the workplace and build a diverse, equitable and inclusive workforce at Hydro One. And finally, for communities. We realized that Hydro One has a critical role to play in helping Ontario emerge stronger from the COVID-19 pandemic. We are continuing to support the Ontario economy by investing in our communities, hiring locally, paying taxes and buying goods and services from local suppliers, including indigenous suppliers. In 2020, we purchased $1.4 billion of goods and services from Ontario suppliers. Our shared success depends on our ability to build trust as a reliable partner and good neighbor for communities and the people of Ontario. We also recommend that we serve approximately 100 First Nations communities across Ontario and we are committed to building long-term relationships with these communities. While we spent $42 million with indigenous communities in 2020, we're excited to announce that we will increase spending to 5% of the company's purchases of materials and services on indigenous procurement by 2026. In addition, as part of our community investment program, we will ensure that 20% of our corporate donations and sponsorships support indigenous communities. As I've referenced on previous calls, I'm pleased to say our unions share our overall partnership mind. Recently, the members of the Society of United Professionals voted in favor of renewing the collective agreement. This collective agreement covers approximately 1,800 employees in frontline supervisory, engineering and professional roles across the company's operations. The agreement reflects our shared commitment to working together. Notably, for the first time, wage increases included an equity component. The agreement also allows for increased productivity, enhanced flexibility and a renewed emphasis on diverse and inclusive practices. We are now in a period of labor stability with this agreement in place for the next couple of years. And with that, I'll turn it over to Chris to discuss our positive financial results for this quarter. Over to you, Chris.
Thank you, Mark. Good morning, everyone, and thank you for joining us today. I hope you and your families are safe and doing well. I'll take this moment to express my sincerest of condolences to the family, friends and coworkers affected by this tragic motor vehicle accident. My thoughts and prayers are with you all. With respect to the business, we are excited about the recent filing of the joint rate application that includes the investment plan for both our transmission and distribution businesses for 2023 through to 2027. Equally, I am energized by the recent release of our sustainability targets and happy to share our sustainability report, which outlines the progress we have made and the impact we have had on people, the planet and the communities we serve. In terms of our financial results for the quarter, we saw a decline in earnings per share to $0.40 from $1.84. Although this seem dramatic, the decline was primarily due to the deferred tax asset, or DTA, decision by the Ontario Divisional Court that was rendered in Q2 of 2020, which led to an $867 million income tax recovery last year. On an adjusted basis, this quarter, we saw an increase in earnings per share to $0.40 compared to $0.39 in the same period last year. The main drivers of higher adjusted earnings this quarter were Ontario Energy Board, or OEB, approved rates for the transmission and distribution segments, higher demand and lower COVID-19 related expenses. These were partially offset by onetime revenues for the transmission segment in the second quarter of 2020, higher operation and maintenance administration costs and higher depreciation and asset removal costs. Our second quarter revenue, net of purchased power, was higher year-over-year by 2.6%. This was comprised of OEB approved rates for 2021 as well as stronger demand in both the transmission and distribution segments. Transmission revenues were lower by 2.4%, while distribution revenues net of purchased power were higher by 8.1%. For the transmission segment, the revenue reflects OEB-approved rates resulting from the transmission rate filing received in the second quarter of last year as well as strong peak demand this quarter. However, the year-over-year revenue increase was offset by the onetime impact of the OEB decision last year, which included the catch-up revenue for the first quarter of 2020 and the recognition of conservation and demand management revenues, both of which drove last year's revenues higher. Year-over-year peak demand for the quarter was higher by 1.8%, driven by strong demand in April and June, partially offset by lower demand in May. For the Distribution segment, in addition to the OEB approved rates, electricity distributed to Hydro One customers was higher by 8.6%. That said, nearly 48% of the increase was attributed to the inclusion of demand from the acquired electric local distribution companies, or LDCs, Peterborough and Orillia, which had closed in the third quarter of 2020, and as such, were not included last year. While these 2 LDCs contributed towards higher distribution revenues, the impact to net income was not material. On the cost front, operating maintenance and administration expenses were higher by 7% year-over-year. The year-over-year comparability is challenging as last year, we incurred higher COVID-19-related costs due to the temporary stand-down of our workforce in the face of the pandemic. At the time, these COVID-19 costs were largely offset by lower work program costs as programs were deferred. This year, the relationship of COVID-19 costs and work program costs has reversed. We incurred minimal COVID-19 costs but higher work program costs. The higher work program costs are driven by timing of vegetation management work, our emergency restoration efforts and customer programs in the distribution segment. As referenced earlier, our OM&A was also higher due to the acquisition of Peterborough and Orillia. Consistent with previous quarters, the financial impact of the measures taken by Hydro One to support our customers, including the Pandemic Relief Fund, financial assistance and increased payment flexibility, extending the Winter Relief Program and the small business pandemic relief program launched in January 2021 were not material. Depreciation expense was higher year-over-year due to the increase in capital assets which is consistent with our stated capital investment program as well as higher asset removal costs and environmental spend. On financing, we saw a decrease in interest expense in the quarter due primarily to the recognition of carrying charges associated with the recovery of the DTA amount previously shared with ratepayers. The carrying charges will be minimal going forward. Financing costs also declined due to higher capitalized interest as compared to last year due to a higher average balance of assets under construction in the second quarter of this year. Income tax expense was $26 million for the quarter compared to an income tax recovery of $849 million in the same quarter last year. The increase in income tax expense was primarily due to $867 million income tax recovery recognized last year following the Ontario Divisional Court decision on the deferred tax asset. When adjusted for this onetime item, the adjusted income tax expense for the second quarter last year was $18 million. The $8 million increase in adjusted income taxes was due to lower net deductible timing differences and higher pretax earnings. The effective rate this quarter was 9.8% versus 6.9% last year, and consistent with our previous guidance of 6% to 13% for periods prior to the implementation of the deferred tax asset decision. With the implementation of the DTA decision on July 1, 2021, and as communicated last quarter, the effective tax rate guidance will now change to 14% to 22% over the next 5 years, with the most significant impact over the '21 to 2023 DTA recovery period. As a reminder, the change in effective tax rate will be net income neutral. On June 17, 2021, the OEB issued their final guidance on the rules and operation of the deferral accounts established for utilities, to track the impacts arising from COVID-19. The OEB determined that eligibility for recovery of most balances will be subject to a means test based on the utility's achieved regulatory ROE. Given this guidance, we've not recognized any amounts related to COVID-19 costs as regulatory assets. As a reminder, we had reversed the recognition of regulatory assets associated with bad debt in the fourth quarter of 2020 and had recognized the expense in the same period. As a result, there is no net income impact from this guidance. Moving to investing activities. Capital investment for the second quarter was $553 million, which is a 28.9% increase from the second quarter of 2020. The increase was mainly due to a higher volume of refurbishments and replacements for stations, lines and wood poles along with higher investments in multiyear development projects for the transmission business, higher volume of work on customer connections in both the transmission and distribution businesses and the construction of a new Ontario grid control center in Orillia.We placed $300 million of assets in service in the second quarter, an 81.8% increase compared to the prior year. This was largely a result of the lumpy nature of placing assets into service. The year-over-year increase related primarily to transmission segment, which had substantial completions and higher spend on lines and component replacements in 2021. In the distribution segment, we saw a year-over-year increase of 40.2% due mainly to a higher volume of work on customer connections and assets placed into service for system capability reinforcement projects. On guidance, we continue to be committed to and affirm our target of 4% to 7% earnings per share growth through 2022. We expect to provide guidance post 2022 after the approval of the joint rate application. As promised, we have updated the future capital investment tables for the period 2021 through to 2027 for all segments. We have also provided the annual expected rate base numbers and corresponding revenue requirements for the amounts included in the joint rating application. Between the filing of the joint rate application and reaffirmation of our guidance, Hydro One has and continues to demonstrate a resilient business strategy and stable fundamentals. Together, they allow us to support our customers and communities while delivering positive financial results. I'll stop there, and we'd be pleased to take your questions.
Thank you, Mark and Chris. We ask the operator to explain how they'd like to organize the Q&A polling process. In case we aren't able to address your questions today, my team and I are always available to respond to follow-up questions. Please go ahead.
[Operator Instructions] Our first question comes from Mark Jarvi with CIBC Capital Markets.
The first one, just if I look at the updated CapEx, putting aside the joint rate application. looks like for 2021 and 2022 spend has gone a little higher. Can you just talk about the drivers? And I think also in the joint rate application that winds how you're allowed to be above a little bit the forecast for rate base, just maybe you can give us some context in terms of where you think you'll end up at the end of '22 in terms of how much -- and how much you're allowed to be off of the original forecast in terms of rate base growth?
Yes. Chris, do you mind taking that?
Sure. Thanks, Mark. Thanks for the question, Mark Jarvi. Yes, so we did increase '21. I think it went up by $140 million approximately. And really what's driving that Mark is increased demand work, so customer connections and growth in the distribution business. But on the transmission side, as you know, our long-term projects are lumpy in nature. So what we're doing there is just moving CapEx between years. It doesn't have a material impact on rate base.
And then on the distribution side, does it have a sort of a small favorable impact of where you'll trend to in rate base for the next couple of years?
It will do. As I said, it was $40 million of additional spend on distribution. And the nature of distribution is changing a little bit. Now is a combination of -- it's still mostly sort of in year when you spend the CapEx that's in service within 12 months, but there are some longer-term projects now helping connect up stations and so on, that don't fall in the transmission side of the business. So it has a little bit of lumpiness to it, but the majority of that $40 million will translate into increased rate base. And as a reminder, we can be within that dead band of plus or minus 2%.
Got it. And then when you go through some of your materials, there's some talk of like on the joint rate application impact of climate change on physical infrastructure, are you guys seeing anything in terms of increased aging or a bit more wear and tear in terms of strain on reliability? And now how does that sort of play into like the sort of the incremental investments you see needed over the next sort of 5-year window?
Yes. It's Mark here. We did build in the impact of climate change into our investment plan, particularly into one dealing with our poor condition poles, but also our vegetation management and in a big way, investing in technology to help us with reliability in our assets. So I talked about reclosers and fault finders and things like that. And so we have built in a fairly significant investments to reduce or improve our reliability by about 25% on the distribution side, and a lot of those are reflected in adapting to climate change.
And just a follow-up on that, Mark. In that technology improvements, is that sort of a little bit of an OpEx to CapEx switch where you can put back what you'd normally do on maintenance spending more into some capital investments. And that helps, I guess, just keep both fairly stable here? Is that part of the thesis here on...
Yes, that's a great point. We're investing in technology, which will reduce things like truck roles and things like that in the event of outages because we'll be able to restore the system using our central control center in a more efficient way.
Our next question comes from Maurice Choy with RBC Capital Markets.
My first question, I wanted to just pick up on, it might be a little bit too early to ask, but you filed your application Friday, have you received any early feedback from your stakeholders, including those in government as well as other political parties? As well, you mentioned, obviously, you've done a few rounds of feedback with other stakeholders in preparation for this application. How significantly different is this application from those rounds of feedback?
I would say our approach to consulting with stakeholders in this round is wide and significant. We also did a technical briefing for media. So the media understands what we're asking for in our application. The feedback we've received is very similar to what we received from our customers. People understand our need to invest in the system. They understand what the drivers are. And the approach we're taking is to be open and transparent right upfront on what we're asking for and why, and that's why we did a proactive technical briefing with media, the day after we filed the application. And our customer engagement really showed a robust support from our customers, which helps with stakeholders such as government and others that we did that work so that we can demonstrate that our customers are supportive of what this investment plan is.
And just a follow-up on that, have you had any engagement with them since Friday?
With customers or -- no.
No, specifically those with the government as well as other political parties.
No, not since Friday, we haven't. We did do the media technical briefing on Friday, like I talked about. We did brief stakeholders, some of them the night before, like government and they're supportive of our investment and understand why we need to do it.
Great. And just to finish off my second question. The company has always had this simple and easy to understand 555 strategy in this regulatory period. As you look at the JRAP, is there anything in there that would cause you to believe that your EPS and dividend growth wouldn't also march in line with your rate base CAGR?
So we've given guidance out to the end of '22, and we will update that guidance after the approval of JRAP. I think it's too premature for us to speculate on that. We need to go through the process with the OEB and finalize our rate order and then we will update that guidance going forward.
At least on the funding plan, I suppose that -- would you be reconfirming that no equity issuance would be required?
That's correct. With the plan that we put forward, we will not need equity to support the investment plan.
Our next question comes from Rob Hope with Scotiabank.
Two kind of longer-term conceptual questions. The JRAP's got a placeholder ROE of 8.34%. How are you thinking about kind of that ROE relative to your cost of capital as well as could you -- would you be open to the OEB revising how it's looking at cost of capital? And would you try to spur that?
Yes. So Rob, I'll start and maybe I'll ask Chris or Frank to weigh in because we do have Frank, our Chief Regulatory Officer online. But the 8.34% is what the ROE would be based on the interest rates if we were to set it today. We will be updating that in Q4 '22 based on the actual formulaic approach for our ROE based on the interest rates at that time. So as I said, the 8.34% is essentially a placeholder for today, and that will get updated to reflect the differences. Frank, do you have anything you want to weigh in on about?
No, you've got that correct, Mark. It is a placeholder for now and we will look at it when we file our final draft rate order from the OEB, so that will be determined in the fourth quarter of 2022.
Rob, it's Chris here. Just remember, that is a formulaic process. So it's based on the movement in the Canadian loan bonds. The number you see there at 8.34% was the number that was set by the OEB in Q4 of last year. So just as a matter of process, we use the rate that they've got out there in the public. They'll update that again this year. And they'll update it -- the one that we'll apply to this application will be in Q4 of 2022. So it will depend on your view of interest rates at that point in time. If you were to update it today, it would be 8.7% or approximately around that number. But if you look forward to what you think it might be in 2022, that's what we get factored into the ROE.
Okay. And then just to confirm, you're happy with the formulaic ROE calculation, you wouldn't look to kind of spur a revision of the cost of capital parameters?
No. At this time, Rob, we're very happy with the -- we think it balances risk and opportunity together. Now again, if you would have said at a certain point in time, say the economy was in a very unusual place like right at the beginning of COVID. That might be something we'd look at it to say, look, how do we rebalance or adjust that given it's a 5-year application, but we think there's sufficient time for that to play through by the end of 2022.
Right. And then kind of another longer-term question. Just going through the load forecast in the JRAP, looking for kind of just a little bit of load here. But as we're seeing the potential electrification of the economy, how does that kind of play into your thinking about potential upside to the demand forecast? And I guess then the offset would be increased embedded generation. So how are you thinking about kind of the puts and takes and benefits of additional demand?
Yes. We -- our load forecast is based on historical load and then the forward-looking consensus forecast on things like economic drivers of electricity consumption, which includes GDP, housing starts, population and those types of things. It also includes views on EV take-up. And as far as overall electrification, we are seeing already a transition to electrification which is built into our historic load -- historic loads which will carry through to the forecast. So example would be the agriculture sector has already been transitioning over to electricity. And as far as that trend continues, it is built into our forecast.
Your next question comes from Andrew Kuske with Credit Suisse.
I guess it's a question for Mark, and it's a bit of a philosophical question on how you thought about the JRAP from a positioning standpoint. And what effectively are you trying to solve for? Is it a capital deployed amount that can raise a certain amount of rate growth? Or is it from a benchmarking standpoint on where you really want to stand from transmission reliability, distribution reliability with avoiding rate shock in between those 2 concepts?
Yes, it really is balancing the need for investment in our assets based on condition of our assets with rates and impact on customers. And that's really why we did such an extensive outreach with customers. And we did assess with them different investment levels and what it would mean to their bills and asked them what they would support. We did it both for the transmission customers and the distribution customers. And overall, we had support from our customers on our level of investment, with about half of them actually saying that we should be investing more and half saying we should be at where we are or lower. So we think it's good support for our investment plan because it does balance the customers' needs and views with bill impacts. And in that one of the big areas that customers were concerned about is reliability, particularly our rural customers. And this investment plan does improve reliability for them by about 25%. So I think we found that balance, Andrew, in this investment plan, and that's what we'll be putting forward as our evidence to the OEB.
That's helpful. And then just to go back to the 2/3 of the capital is really system renewal oriented. But clearly, renewing a system that has facility age that can be 40 or 50 years plus in some cases, you get a lot of productivity benefits in capital deployment. Can you give some [Audio Gap] so that you expect, is there ways to quantify that from a financial standpoint, whether it's [ M&A ] declines, future maintenance capital, is there something you can give us on that front?
Well, maybe I'll talk about the condition and Chris can weigh in on the economics and the impacts on that. So we've often talked about 1/3 of our assets are end of life. We don't replace assets just because of age, we replace them because of conditions. So the end-of-life assessment gives us some general assessment. But then we've done a condition asset assessments. And what we found is about 10% of our transmission assets are in poor condition today. And that means about 27% of our transformers, 11% of our breakers, 14% of our conductors. And in this investment plan, we're not even dealing with all of those that are in poor condition. We're dealing with a lot of them, but we don't even deal with all of those. So I believe that there is good evidence as to why we need to be investing in those, and that's 67% of our overall investment plan. Chris, do you want to take the second part of Andrew's question?
Sure Andrew, I think it's the same program we had from 2015 to 2020. So through that period in Mark's comments this morning, he talked about achieving approximately $738 million of productivity savings over those 5 years. And that's really the benefit or the target of offsetting inflation every year. So that's translated into about $50 million per year. That will continue, and it gets roughly split over the longer term between our capital and operating programs. So up to this point, capital has been more like 65%, 70% of our program and OpEx has been the remainder. So I would see that continuing over the longer term. I'll just remind you, Andrew, that's been a big benefit to rate payers. Where they see that is they see it when we -- if we over-earn, we share 50% of that benefit with rate payers. And part of that first year rebasing that the rate payers have seen, that 1.8% reduction in bills or $3.20 per bill across the year, a chunk of that is due to the benefits of productivity. So that's us being rebased at the end of this rate period to those productivity benefits. So I see that continuing, Andrew, it will be roughly the same as what you saw in the past.
Our next question comes from Ben Pham, BMO.
I wanted to go back on the financing funding outlook for the JRAP. You mentioned no need for equity. I'm wondering -- I mean, it's a pretty big step up in CapEx per year. Your comments on no equity need. Is that just taking your cash flow from operations less the dividend and then you're financing OpCo debt at 60%? Is that what's driving that conclusion?
Chris, do you want to respond?
Sure. Thanks for the question, Ben. There's 2 things. At this point in time, we are slight -- we have some balance sheet flexibility that will take us up to our 60-40 debt equity, maybe slightly higher than that over this rate period. But we also have the large deferred tax assets on our balance sheet in which you might consider and that sits around $2 billion. So we're monetizing that as well. So as we do that, we don't need any additional borrowing to do that. And through the deferred tax asset decision, you saw the return of over $250 million of that amount in the next 2 to 3 years. And then after that, it's about $50 million per year. So that's part of it. And then the uplift in earnings, we will hold our payout ratio constant so we retain part of that to fund our growth. So we don't see a need for equity when we move from 5% to 6% through to 2027.
Okay. And would you say that given your source of their capital, this new CapEx program, does it restrict you to some extent on smaller LDC acquisitions? I know it's a small, but does this be at a point where you're a bit more restricted in what you can do outside of your base plan?
No, Ben. From our point of view, we understood the asset condition for longer than just this rate application. So we had been seeing this need for a while. It's now absolutely supported through customer consultation and so on. But that just allowed us to plan. I know some of the questions from analysts in the past have been with the decision of the DTA, would you look at returning capital to investors. We said we would if we didn't see a need for it. But this is where the need comes. So we do not see it impacting one, our ability to finance the applications you have in front of you or LDCs. And in the past, what I've said is the LDC consolidation should continue at approximately $100 million to $200 million per year. Now if we did something larger, Ben, beyond that, then yes, we would look at how we would finance that. But $100 million to $200 million per year through this rate period, we would see no need for additional equity.
Okay. Great. And then on the JRAP, any sense of timing on the station, you have a likely time before 2022 and we anticipate it's similar in the past and not the conversations you have so far you have a couple of months beyond just because it's a joint application. Got any thoughts, initial thoughts on a decision?
Yes. We expect a decision in the fourth quarter of 2022. The OEB process for an application of this size bigger than $500 million is 355 days from the date of an [indiscernible] application, which we expect will be around August 9, next year, if you go on that 355 days, but we really are expecting it by Q4 of 2022.
Our next question comes from Linda Ezergailis with TD Securities.
I'm wondering if I can get a sense of some of the aspects of your union agreement that was just reached. Are those already reflected in your JRAP? And also, how might we think of the expiry of your IT Capgemini agreement the end of 2024? Is it reasonable to assume a renewal similar to what's in place currently? Any sort of context on those 2 agreements would be helpful.
Sure, Linda. Maybe I'll take the society agreement first, which is one that we recently signed, and it will take us out to 2023. So it was a successful bargaining with the society and it resulted in a number of enhancements aligned to our strategic goals. And namely, it created a path to ensuring labor costs are better aligned to the market for society-represented roles. And the agreement also helps us move towards our corporate D&I and sustainability goals, as well as, as I said in my opening comments, a portion of the increase is in the society agreement, our equity base, which ties more of our employees to the performance of the company, which we think is a positive outcome. It also maintains our existing contracting out flexibility. So as we see our capital plan growing, that gives us some flexibility there as well to contract out some of that work. So we think it was a good agreement for both our employees and for the company overall. And then the IT Capgemini, which is the second part of that. We have in-sourced a lot of the -- from Energex -- or sorry, Energy to Hydro One a bunch of the IT and then we have the outsource agreement with Capgemini for the remainder of those services that used to be provided by Energy. We do see that, that is giving us an overall cost benefit by -- that new arrangement with Capgemini directly. I can't speculate on whether we will extend that contract at this point. But we are seeing that we are getting benefits out of that in the new arrangements with -- directly with Capgenimi instead of through Energy and by in-sourcing the critical things that we wanted to have within the company.
Okay. And as a follow-up, just better trying to understand what's embedded in your JRAP. How can we think of the inflation assumptions in your capital expenditures? And you have a capital factor as well. Just trying to get an understanding of whether any sort of productivity factor is embedded in your capital factor in your formula as well?
Yes. Maybe I'll ask Frank to speak to how we've embedded the productivity into the capital factor. So Frank, can you maybe explain that to Linda?
Sure. Thank you, Mark. Linda, the last time we did our application for transmission and distribution, we had put a bottom line reduction into our application. And that seemed to cause confusion at the hearing. So what we've done now is we've built it into the formula, and it's just the standard formula from the OEB. So there is, of course, a stretch factor. But in the capital factor, there's assumed additional stretch there as well. And so that productivity factor is now captured through the formula. In terms of the inflation, it is the standard inflation assumptions that follow the Ontario CPI, so in or around 2%.
Our next question comes from David Quezada with Raymond James.
My first question, just in light of the contemplated increase in CapEx, which is pretty meaningful in the JRAP. I'm curious how you'll go about what your requirements will be in terms of adding staff and I guess, how you think about the availability of third-party contractors as you look to increase the base CapEx?
Yes, David, it's Mark here. So as I talked about in the society agreement, we do have the ability to contract out and society covers a lot of our engineering project management, that type of support. We also do have the ability on new stations in greenfield to contract that out into a transmission to outside contractors and construction companies. So we have been building a plan within our execution group to ramp up our ability to deliver on this increased capital without actually increasing a lot of headcount increases within Hydro One. So we have been negotiated to our agreement that flexibility, knowing that we are looking at ramping up our capital, and I think we're in good shape to do that.
Okay. Great. And then maybe just one more for me. Among the parts of your business that are not covered by the JRAP. I appreciate that you will be putting out an updated capital plan next year. But are you able to comment on just the pace of CapEx and rate base growth that you expect for those other parts of the business, do you think it's going to be roughly consistent with what's outlined in the JRAP?
Yes. A large part of our spend is within the JRAP. There are some projects which are outside of JRAP, and they are in other filings that we will be having. So as part of JRAP, we're proposing 2 regulatory accounts with the OEB to allow us to execute on new externally driven work without materially impacting the JRAP CapEx. And so some examples of that are the development work for Waasigan, Chatham, the Lakeshore and Lambton. The -- we do expect these new transmission projects to be in-licensed partnerships like we did for B2M and NRLP and they'll be subject to their own rate applications outside of JRAP. So some of our new lines are outside of this investment plan which we're showing you today.
[Operator Instructions] Our next question comes from Dariusz Lozny with Bank of America.
Just wanted to come back to the proposed spending in the JRAP, specifically the division between distribution and transmission. It looks like the step-up in distribution is a little bit more of a step change than in transmission. And you've touched on it a little bit, but can you just talk about what drove that particular step up? Is it more just a factor of distribution rates being a little bit more out of date than transmission comparably or just a greater need to refurbish aging equipment or any other factors?
I would say the biggest difference between TX and DX, why it is more of a step up is because in TX our reliability of TX is first quartile, where the reliability on the DX side is its third or fourth quartile. And in order to improve the reliability, which is one of the things the customers commented on as our customer outreach, we need to step up the spending there. And part of that is on things like poor condition poles, but it's also the technology investments I talked about before, which is the reclosers and fault finders and things like that on the system to help us improve the reliability. So the drivers are different with transmission and with distribution, and we do see that we need to improve the reliability on the distribution side more so than on transmission.
Okay. Excellent. One more, if I can. In terms of your 4% to 7% EPS guidance range through '22, now that we're -- presumably, there's some visibility into 2022. Have you given any consideration to potentially narrowing that range?
Dariusz, it's Chris. I can take this one. We will leave that guidance in place. And I think I said in the past that, look, we have more confidence of being at the upper end of that range that was provided previously. So it will stay consistent. When the joint rate application is approved, we will update our guidance beyond 2022.
Our next question comes from Patrick Kenny with National Bank Financial.
Just back to your sustainability targets. I know your carbon footprint is already quite modest relative to other utilities in North America. But just curious on your target to reduce GHG emissions by 30% by 2030. Curious if you have any opportunities to move that reduction target more in line with the federal government's new target of 40% to 45%? And if you did accelerate that goal, what that might mean for the 5-year capital plan?
Yes. We're -- we just released our goal of 30% by '30, and we think it's the right goal for us irrespective of the fact that the government has accelerated it. And to your point, we're -- our carbon footprint is relatively small. And we think our role actually is to help decarbonize the economy through connecting the 96% decarbonized electricity in Ontario to customers. So -- and the other thing is our target includes Scope 1 and Scope 2. So the Scope 2 is tied to the -- to how green the grid is in Ontario, which we don't directly control. And so we wanted to make sure that we set a target which was achievable by the actions we can take, and we will also work with the suppliers in the ISO and the OEB on looking at the mix of carbon versus non-carbon-generating electricity in Ontario. So we're comfortable with that. And our JRAP includes investments to get there, and they're not incremental to what we were looking for. And so the primary areas around converting our fleet building automation into our buildings to reduce our carbon footprint of our buildings, reducing the diesels in our remote communities. That's probably our biggest single footprint is our remote communities and some of those will be coming off of diesel as they're connected to the grid, and we'll look at renewable opportunities for others. So we're comfortable with the targets we've set, and that they're achievable.
And as a follow-on, maybe for Chris, too, but just perhaps you can confirm what amounts, if any, within the capital plan are earmarked for innovation and some of your green tech JVs. I know you've -- your basically accelerating some of the charging station initiatives quite rapidly. So just curious if there's any upside to the capital plan related to some of those joint ventures?
Thanks, Pat. Yes. So there will be -- at this point in time what you're referring to there is our joint venture, Ivy, the charging network. It's in its very early stages. So that has not sort of -- there is upside to capital investment in there that's not included in this plan. So what we've really updated for today is really the joint rate application. So to the extent that EV penetration happens quicker or even more broader, that would be reflected in the next update. And we do those updates, Pat, normally around our business plan, so sort of the end of the year going into the new year. So there's definitely upside there. And that the EV charging stations is -- would be outside the joint rate application in any case, it's not regulated. But we do see upside there, and we will update that normally once a year as part of our business planning process.
And our last question comes from Matthew Weekes with Industrial Alliance.
I was just noticing that when you look at the CapEx and the way that it's trending, it seems like a greater amount is generally directed towards sustaining CapEx, so over the years. Is it too early to tell? Or would you say that this trend would continue or level off? If it does level off over the long term, would you see a leveling off at around maybe 75% or something like that, sustaining CapEx as a percentage of total CapEx?
Yes, it's Mark here. So it is based on condition. The sustaining investments are primarily based on condition. And as I said before, we do condition assessments of our assets. And even at the investment that you're seeing today, we don't deal with all our poor condition assets by the end of the '27 period. And so if you assume, which is -- which we need to, that the existing assets will continue to age, we're not dealing with all the poor condition assets in this investment plan. Others will get into that poor condition zone by the end of the investment period. That we'll continually update and look at those conditions going forward as we develop our application beyond '27. So short answer is there is a long-term kind of need to invest in our aging assets in Ontario.
And that does conclude our Q&A session for today. I'd like to turn the call back over to Omar Javed for any further remarks.
Thank you, Chen. The management team at Hydro One thanks everyone for their time with us this morning during what is a busy period. We appreciate your interest and your ownership. If you have any questions that weren't addressed on the call, please feel free to reach out and we'll get them answered for you. Thank you again, and enjoy the rest of your day and continue to be safe.
Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program, and you may all disconnect. Everyone, have a great day.