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Fortis Inc
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Ladies and gentlemen, thank you for standing by. My name is Laura, and I will be your conference operator today. Welcome to the Fortis 2022 Annual Earnings 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, Laura, and good morning, everyone, and welcome to Fortis' fourth quarter and annual 2022 results conference call. I'm joined by David Hutchens, President and CEO; 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. Actual results can differ materially from the forecast projections included in the forward-looking information presented today.
All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our annual 2022 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars.
With that, I will turn the call over to David.
Thank you and good morning, everyone. 2022 was a great year for Fortis. Our utilities invested $4 billion of capital for system resiliency and modernization and to interconnect cleaner energy to our systems. These investments translated into strong earnings and rate base growth, demonstrating the value of our organic growth strategy and supporting our roughly 6% dividend increase in 2022.
On the sustainability front, we reduced our 2022 annual greenhouse gas emissions by 28% since 2019, keeping us on track to reach our carbon reduction targets. As part of their annual Board Games report, The Globe and Mail ranked Fortis number one among 226 companies in the S&P/TSX Composite Index for good governance, reflecting our board's commitment to best-in-class practices.
And most importantly, we remain focused on delivering safe and reliable service to our electric and gas customers across our North American utilities. These are the core tenets of our value proposition. And at Fortis, as we keep this at the forefront as we mitigate and respond to the impacts of climate change. And while our reliability metrics continue to outperform industry averages in 2022, our utilities remain committed to investing in their energy systems to better withstand the increasing frequency of severe weather events.
And with the backdrop of inflation reaching 40 year highs, our teams have successfully managed average annual increases in controllable operating cost per customer to approximately 2% over the past five years by finding efficiencies through innovation, and process improvements. And while we have limited ability to control energy commodity costs that are passed through directly to our customers in some jurisdictions, we are helping our customers manage their bills by extending recovery periods and through energy efficiency and payment assistance programs.
Over a 20 year timeframe, Fortis has delivered average annual total shareholder returns of approximately 11% or 751% in total, well above the benchmark indices shown on the slide. While our one year total shareholder return for 2022 was below our historical average returns, we expect to continue to deliver stable and compelling returns over the long run.
At Tucson Electric Power, the closure of our last unit at the San Juan Generating Station, removed another 170 megawatts of coal-fired generation from our portfolio and contributed to our 28% reduction in Scope 1 emissions compared to 2019 levels. With this progress, we are more than halfway to achieving our target to reduce greenhouse gas emissions 50% by 2030 and are on track to meet our 2035 target of 75% reduction. Upon achieving that target, we expect our assets will be primarily focused on energy delivery and renewable carbon free generation.
Last year, we also established a 2050 net zero Scope 1 greenhouse gas emissions target, reinforcing our long-term commitment to decarbonize while ensuring we preserve customer reliability and affordability. In the fourth quarter, we rolled out our new $22.3 billion five-year capital plan, our largest to-date. The plan consists of virtually all regulated investments and a diverse mix of highly executable projects supporting rate base growth across our portfolio of utilities. It also includes $5.9 billion for investments that directly support cleaner energy.
Over the next five years, we expect rate base to increase by $12 billion from approximately $34 billion in 2022 and to over $46 billion in 2027, supporting average annual rate base growth of 6.2%. From a growth perspective, our teams continue to pursue opportunities beyond the base plan. Key areas of focus include incremental investments, supported by the Inflation Reduction Act in the U.S., Climate Adaptation & Grid Resiliency, as well as LNG and renewable fuels.
Progress also continues on MISO's long range transmission plan. As we previously discussed, ITC anticipates transmission investments in the range of US$1.4 billion to US$1.8 billion through 2030 for Tranche 1. ITC currently has US$700 million of this estimate included in their five year capital plan. Tranche 2 is well underway with the initial concepts identified by MISO in late 2022. The second tranche will look at a new future, DOV2A, which calls for more renewable penetration and higher electricity demand. And while it is still early in the planning process, MISO Board approval of Tranche 2 projects is targeted for the first half of 2024.
The Inflation Reduction Act is expected to support TEP's clean energy transition by reducing the cost of new renewables and providing funding to aid the communities impacted by the exit from fossil fuels. The TEP team continues to work through its all source request for proposals, which seeks to secure renewables and energy storage to support their transition away from coal. In total, we estimate incremental investments of approximately US$2 billion to US$4 billion through 2035 will be required to implement TEP's current integrated resource plan. TEP expects to file an updated plan later this year.
Next turning to Slide 10, we increased our dividends paid per common share to $2.17 in 2022, up approximately 6% from 2021, marking 49 consecutive years of dividend increases. Looking ahead, we remain committed to building on our track record through the execution of our organic growth strategy that supports our 4% to 6% (ph) dividend growth guidance through 2027.
Now I will turn the call over to Jocelyn for an update on our fourth quarter and annual financial results.
Thank you, David, and good morning, everyone. Before I get into the annual results, I want to briefly touch on our fourth quarter performance. Reported earnings were $370 million or $0.77 per common share, $0.08 higher than the fourth quarter of 2021. Adjusted earnings were $347 million or $0.72 per common share, $0.09 higher than the fourth quarter of 2021.
The key drivers of growth include strong regulated rate base growth across our utilities as well as higher sales and transmission revenue in Arizona, higher hydroelectric production in Belize, which was up significantly from historically low levels in the fourth quarter of 2021 and higher gas margins at Aitken Creek also contributed to earnings growth. And finally, foreign exchange favorably impacted the translation of our U.S. denominated earnings during the quarter. Corporate cost for the quarter reflect higher finance costs and taxes.
On an annual basis, reported earnings were $1.3 billion or $2.78 per common share, $0.17 higher than 2021. Adjusted earnings for 2022 were also $1.3 billion or $2.78 per common share. As the adjustments to reported earnings offset one another in 2022. Adjusted earnings per common share of $2.78 represents 7% growth or approximately 6% absent foreign exchange impacts.
The waterfall chart on Slide 14 provides the annual EPS drivers by segment. And while there were several market factors impacting our 2022 results, underlying growth from our regulated utilities was the primary driver of year-over-year growth. Our largest utility ITC increased EPS by $0.07, again reflective of strong rate base growth.
Lower stock-based compensation costs at ITC in 2022 were substantially offset by losses on investments that support retirement benefits, higher non-recoverable finance costs and gains recognized on interest rate swaps in 2021. The $0.07 EPS increase for Western and Canadian utilities was driven by rate base growth. The increase in EPS of $0.06 for our U.S. electric and gas utilities was mainly driven by UNS.
In Arizona, higher sales and transmission revenue more than offset higher costs associated with rate base growth, not yet included in customer rates, higher operating expenses, and losses on investments, including certain retirement benefits. Our Energy Infrastructure segment contributed to a $0.05 EPS increase, mainly driven by higher gas margins at Aitken Creek. Rate base growth and higher electricity sales in Eastern Canada and the Caribbean contributed a $0.03 increase in EPS compared to 2021.
Foreign exchange favorably impacted the translation of our U.S. denominated earnings, which increased annual EPS by approximately $0.06. The EPS change in corporate of $0.11 was mainly driven by mark-to-market losses on both total return swaps and foreign exchange contracts, as well as higher finance costs. The remaining decrease was largely related to increased corporate costs and taxes.
And as a note, the mark-to-market losses in the corporate segment was more than offset by the favorable foreign exchange impact just discussed and lower stock-based compensation recognized across the utilities in 2022. And lastly, with our dividend reinvestment program, EPS decreased $0.04 due to higher weighted average shares outstanding.
As you can see on Slide 15, we were active in the capital markets again in 2022, issuing over $3 billion in long term debt. Debt issued at Fortis, Inc. and ITC Holdings, mainly refinance maturing debt, while our regulated utilities issued debt in support of their capital programs. Debt maturing at Fortis and ITC Holdings averages approximately US$400 million, annually through 2025.
With our recent debt issuances coupled with almost $4 billion available on our credit facilities, we continue to maintain a strong liquidity position supporting our $22.3 billion capital plan as David mentioned earlier. And despite several macro headwinds, in 2022, we saw an improvement in our credit metrics and achieved a cash flow to debt ratio of 11.7%. And when we consider the import of foreign exchange, the ratio is actually 12%. Our credit metrics coupled with Fortis' low business risk profile continue to support our investment grade credit ratings.
Turning to some of our ongoing regulatory proceedings since we last updated the market. At ITC, FERC issued an order in November denying the complaint filed by the Iowa Coalition for Affordable Transmission, which sought to lower ITC Midwest equity ratio. We also await next steps from FERC on the MISO based ROE and supplemental NOPR on transmission incentives. The timing and outcome of both proceedings remain unknown.
In Arizona, TEP's rate case is ongoing. In its application, TEP requested rate base of US3.6 billion and allowed ROE of 10.25% and equity layer of 54%. Arizona Corporation Commission staff have recommended a 9.6 allowed ROE with rate base and equity layer largely consistent with TEP's request. Rebuttal (ph) testimony is expected to be filed over the next month with hearings scheduled to commence in late March.
Last month, Central Hudson filed a response to the New York Public Service Commission Show Cause order regarding the deployment of the utilities new customer information system. Central Hudson has devoted significant resources to rectify matters with the system and are making strong progress in resolving any remaining billing issues. The timing and outcome of this proceeding remains unknown.
At Fortis DC (ph), the generic cost of capital proceeding remains ongoing with the decision expected in the second quarter. And lastly, the Alberta Utilities Commission issued a final decision in December approving Fortis Alberta's 2023 revenue requirement reflecting a 5% increase in distribution rates. The decision is expected to form the basis for going in rates for the third PBR term starting in 2024.
With that, I will now turn the call back to David.
Thank you, Jocelyn. To recap, in 2022, we invested $4 billion in capital delivered strong EPS and rate base growth, further reduced our carbon emissions, managed operating costs, and were recognized as a leader in Canada for our governance practices. These accomplishments wouldn't be possible without the continued commitment of our 9,200 people.
Moving forward, we are focused on executing our $22.3 billion capital plan, which will drive rate base growth of 6% and support our dividend growth guidance of 4% to 6% through 2027.
That concludes my remarks. I will now turn the call back over to Stephanie.
Thank you, David. 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 begin the question-and-answer session. [Operator Instructions] Your first question comes from the line of Maurice Choy from RBC Capital Markets. Please go ahead.
Thank you, and good morning. My first question, Dave, you mentioned in your prepared remarks that there is an incremental spending of $2 billion to $4 billion through 2035 to implement the current TEP IRP, although, there is a new plan due late this year. How would you characterize impact of the IRA on this spending? Is that a case where the amount is likely not change or go up, or is it a case where mixes or projects will change? And also on timing, is there a way that you can accelerate the decarbonization projects?
Yeah. Thanks, Maurice for that question. Actually, it might be a little of everything and that's what we're doing in the Integrated Resource Plan, update now is to figure out exactly what that means from a timing perspective, investment opportunity perspective as well as cost associated with the renewable energy investments that we have to make to keep on that transition path that we have there.
I'll have to say that probably one of the biggest benefits of the Inflation Reduction Act is that those tax credits, not just that there are those tax credits, but that those tax credits are transferable. I think that really levels the playing field between utility investments and PPAs. So you don't have to find some fancy way of and in the tax equity et cetera. So all things being equal, I think that's another notch in the column for doing more utility owned and utility constructed renewals.
And maybe just to follow on to that, you obviously have a new chairperson within the commission there. Any thoughts about changes in how the commission or chair looks at things in terms of affordability, in terms of decarbonization?
Not right out of the gate. I'll maybe turn that over to Susan to see if she has any opinions after her initial conversations with the new commissioners there at Arizona Corporation Commission. It is obviously after the election, we've got two new commissioners and we're looking forward to getting our cases adjudicated before them. But I'll turn it over to Susan to answer that in a little more detail.
Okay. Thanks, Dave, and thanks, Maurice for the question. Yeah. I do think it's early to tell how our new composite of commissioners will affect policy this year, but we do have a new Chair, Commissioner O'Connor. We do have two new commissioners. We've actually met with the new commissioners. They came down to Tucson last month, which I think is a really good sign that they're interested in understanding our operations. They wanted to see our generation fleet.
They wanted to see our control room where we participate in the energy and balance market. I think there is a greater understanding of our business. We’ll always lead to better outcomes. We really pride ourselves in having strong relationships with our commission and that trend is continuing with these new commissioners. But I do think in terms of policy, it's pretty early to tell how the new chair and the new commissioners will impact policy.
Great. Thanks for that. And maybe I'll just finish off with FERC matters. There are obviously a number of regulatory items that remain outstanding. How do you see these skinning resolve with the four member FERC makeup being what is it right now? And maybe as a quick follow-up thoughts on the MISO base ROE? What are you booking in right now? And then if there's a possibility of proactively requesting and justifying for a higher rate?
Yes. Thanks, Maurice. I think we've talked about this in the past. It's really tough to see where some of these policy decisions are going to land and how it's going to be executed with the two commission, two Republican and two Democrats. And seeing how that -- how the commission functions under the new Interim Chair, Chair Phillip’s.
We do think that based on Chair Phillip’s comments that he's really going to be pushing down the same path to get some of these policy issues that are in the NOPR’s, the transmission planning and cost allocation, NOPR’s, as well as the interconnection in queue NOPR, it seems like he's really going to continue to progress those. Has a big strong focus on reliability as you might imagine from his history working for NERC, but also on making sure that there's energy equity and energy justice involved in some of these decisions as well. So we're looking forward to seeing him move forward on those dockets.
On the ROE, I'm actually going to turn that over to Linda Apsey, our CEO of ITC because she can explain exactly her thoughts on that.
Great. Yes. Thanks, Dave. Thank you, Maurice, for the question. Yeah. We continue to book basically and assume that 10.77% all in ROE. It's obviously it's premature, it's speculative to know or understand what FERC might do as a result of the court remand of the base ROE case. So we are continuing forward with the current ROE projections.
With regards to possibility for, sort of a new tool by filing to file for a new ROE, that's certainly something that we continue to track and monitor, as we continue to track sort of the mark-to-market rates. Obviously, we are providing FERC with the appropriate sort of time, if you will, to respond to the court remands, but we are continually in discussions and assessing our options with respect to whether we would move forward with a new updated 205 filing. At this time that decision has not been made by MISO transmission owners.
Thanks, Linda. I'd just add to that directionally obviously with the data that would be updated and any new ROE filing, the current data and higher interest rate would be supportive of a higher ROE than the data that was used to set these prior ROEs back that data is six, seven, eight years old.
That makes sense. Thanks for the color.
Thanks, Maurice.
Thank you. Your next question comes from the line of Rob Hope from Scotiabank. Please go ahead.
Good morning, everyone. I appreciate the thoughts on the Tucson rate filing, but I was hoping you could maybe dive a little bit deeper when you take a look at the staff testimony for the staff recommendation, aside from the ROE, is there anything that gives you a pause for concern and how have conversations gone with other stakeholders? And so that may be a little bit early just given when the evidence is due?
Yes. I'm going to kick that over to Susan Gray, who I didn't properly introduced. I just introduced her as Susan. But you all likely know Susan Gray is the CEO of UNS Energy. So I'll kick it over to her to give you some insight on where we see that rate case going.
Sure. Yeah. Thank you for the question, Rob. So I think your question was, do we have any concerns based on what staff filed? And I think that, we think that with a file was largely in line with our initial filing. And so we think that there's pretty small gap between their testimony and ours. We're still in the rebuttal phase, so the rebuttal testimony is due next week. And we're optimistic that we can reach some stipulations through this process and go into the hearings, which start March 29 in a pretty good position in terms of agreements with staff and other major interveners.
We have not had significant conversations with the other interveners at this time. So I think there was a precedent set with the stipulations that were agreed to by staff and Southwest Gas, in the Southwest Gas rate case that recently was settled. So we're hopeful that we can also work with staff to get to some stipulations prior to the hearing.
All right. Appreciate the color. Moving north, can you give us some updated thoughts on the build out of LNG at Tilbury, you were able to get some First Nations agreements there recently. However, the regulatory framework is still, slow and ongoing?
Yeah, Rob. That's great. I'm going to -- actually, I'm going to kick this right over to Roger Dall’Antonia. He's been working on some of these agreements as recent as last week, so he's got the most recent updates. Roger?
Thanks, Dave. Good morning, Rob. So on Tilbury, there's two primary regulatory processes. One is the environmental assessment on the jetty, which is the infrastructure to allow for filling a bunkering barges to fuel marine vessels. The second is the environmental assessment for the build out of the Tilbury site, including a storage tank and additional liquefaction.
In both instances, the environmental assessment office, there's obviously significant focus on indigenous support for those projects. The deals that we've been announcing recently primarily focus on the jetty process. That's currently now with both the provincial and federal environmental assessment offices for referral. We're hoping to see a decision on the jetty sometime in the next few months.
And the environmental assessment process for the Tilbury build out tank and the further liquefaction is in the stage of preparing the detailed application, working with environmental assessment process in scoping out the application as well as considering how to engage indigenous communities to have indigenous environmental estimates as part of the process.
Appreciate it.
Thanks. Thank you.
Thank you. Your next question comes from the line of Linda Ezergailis from TD Securities. Please go ahead.
Thank you. I'm wondering, if you could give us a sense of how you view the relative attractiveness of different financing options with the filing of your short-form based shelf prospectus, wondering where prep (ph) shares sit in terms of your levers to finance either your current capital plan or if you choose to maybe accelerate some of the decarbonization initiatives and add to the current plan? Can you talk about also your capacity to add new projects to the current plan before considering other levers like discrete common equity?
Thank you, Linda. This is Jocelyn. Yeah. So with press, yeah, it's certainly a part of our toolkit today. And so we're always watching that market. When we laid out the five year capital plan in the fall, right? It was a pretty simple funding plan that we had for that $22.3 billion capital, no discrete equity, just a DRIP. And most of the debt is at the regulated entity at Fortis Inc. press (ph) certainly will be a part of the equation and we're looking at all sources, right, of funding. But very, very simple and we expect to keep our balance sheet where it is from a capacity perspective.
I actually, clearly, it depends on DRIP participation, which remains quite healthy, thus far. It really going to depend on the timing of any additional capital, right? I mean, if for some chance that we advanced more of the LRTP projects. I'm just using those as an example or the investments in Arizona. It's possible that we'll go back to the drawing board. But I actually feel there's certainly a bit of capacity in our plan today. So it's not no immediately that if we see some variances from our annual plan right now that we'll be able to handle it.
But if in fact we see a material change, then as I always say, I guess we go right back to the drawing table and everything goes back on the table. But we do have a bit of capacity in our funding plan today. And I think a more green [indiscernible] Linda, I do expect more green financings coming out of our subsidiaries. We're seeing more and more green financings because we're getting more and more involved in cleaner energy investments. So I do expect to see that trend to continue as well.
Thank you. Appreciate the context. And maybe just on the flip side of the equation, recognizing that affordability is at the forefront in many jurisdictions. What are the thoughts on potentially deferring other discretionary capital to the extent that Fortis and its subsidiaries choose to accelerate green initiatives. And what sort of forbearance is there at the rating agencies to continue to kind of defer recovery of those expenses as kind of the customer bill pressures, one of the levers as well to consider.
So I'll start that answer, Linda. I think on deferring capital, we don't see that as necessary on a going forward basis. You have to remember that not all capital immediately either contributes to rate increases or even shows up in rate increase. We always like to prioritize our capital based on doing that capital first that saves our customers money, the old OpEx for OpEx (ph) kind of trade.
Even the resource transition that we're doing down in Arizona as we shut down a coal plant and remove the fuel and O&M and replace it with investments in infrastructure. It's a good story for customers, investors and the planet. So those are the things that we're really focused on and we can't slow down the necessary investments that we need to make in reliability and resiliency. And in fact, those are ones that we probably need to step up more on a going forward basis to make sure that our systems are ready to handle more severe weather events going forward. So that's kind of on the capital side.
On cost control side, that's something that we're always focused on. So we know that every dollar that goes in there, we want to figure how much that -- how much of that we can offset with other costs and that's really things that we can do across the board. So we start with obviously managing our capital, managing our expenses, looking at innovation and efficiencies as best we can.
We look at the entirety of the bill, what our customers use, focus on energy efficiency conservation programs, we focus on, in our vertically integrated utilities on how we dispatch that energy to maximize the benefits of being in the market for our customers. And at the end of the day, as you alluded to, we have to find a couple of things for assistance for our customers. One [indiscernible] assistance to help them pay their bills if they're struggling, which is something that we always do and obviously step up even more so in hard economics times like we're focused or like we're in today.
But we also look at ways that we can -- in essence use our balance sheet when we need to use our balance sheet to spread out some of these cost recoveries and smooth the bill impacts for our customers. And those are things that we have done in the past and will likely do going forward just to help manage that affordability and impacts on our customers.
And just to clarify the debt rating agencies have they communicated kind of any sort of notional limit to how the balance sheet can be used to smooth out bill impacts or is that de minimis in the grander scheme of things with them?
Linda, this is Jocelyn. No, they have not, specified them to the – to that detail. We have conversations with them, of course, about how we plan to fund the capital program and how we see recovery. And affordability is clearly proud of that discussion, but they've not defined any boundaries by which, we can execute and fund the capital program.
Thank you. I'll jump back in the queue.
Thanks, Linda.
Thank you. Your next question comes from the line of Mark Jarvi from CIBC Capital Markets. Please go ahead.
Thanks. Good morning, everyone. I just wanted to talk about sort of longer term or interim growth prospects at ITC. Right now in the five year plan, you're looking around 6% rate base growth. As you look into sort of long term planning prospects there 2A talked about David, expectations around maybe seeing a higher growth in the back half of the decade. We've seen some other transmission companies in MISO growing north of 8%, is that something you guys think you can achieve as you move through these planning processes?
Mark, that's a great question and its early days for that right now. I think, as we put out our five year capital plan. I just want to press last fall, right? So we immediately then start on the next one. And we try to see how far out we can look on these investment opportunities. And the long range transmission planning process is a long process and it's obviously early days in Tranche 2. We like what we see in the early days, but we have no idea where that's all going to land and we won't for a bit longer.
We don't expect those final projects to really be approved by the MISO Board until the middle of next year. But we'll have more information in each quarter as we go along and as that process proceeds. But it's really hard to see how much and where those will fill in the out years, even in the Tranche 1 that we have, we have less than half of our estimate in the next four years with the remaining part really in the following three years. So we can kind of see how that's stacking up.
But beyond that, it's just this layering effect of additional transmission projects where they go in, how they can be supported, the timing for permitting and sighting, et cetera. So it's too early to really give you anything other than directionally we think that there's going to be a fair bit more transmission. Well, I'll say not just in MISO. Directionally in the United States and I will say in North America, we will see a much more robust investment thesis on transmission. We see the Inflation Reduction Act and how that is driving the ends of this conversation, the generation transits and the renewable energy, clean energy of any kind.
And then of course, on the demand side looking at electrification, manufacturing, et cetera. We have to make sure that we're focused on the middle part, which is transmission and distribution that's between those two. And that's the investment that we think is really going to be taken off here going forward. We just can't put numbers on it, but we do know directionally it should be up.
Okay. And then, maybe coming out from a bit of a different direction. Are there any elements of ITC's footprint, age of the assets, capacity availability right now that were constrained. I guess, the upside case relative to other transmission operators in the region or whether it's more challenging permitting or citing in terms of where you operate right now?
No, there's, I don't see any reason that ITC would be challenged any more than anyone else's to build transmission. In fact, I might say at that team on the back say that they're probably the best transmission plan and development team out there. So if there's ways to do it, and they've got a great footprint, too, right? I mean they're in MISO and MISO is basically wind alley, and even solar alley to some extent. So the ability -- the number of projects, particularly as you look at the planning process that's going on in MISO and our expertise in my view, should put us ahead of the curve.
Okay. That's good to hear. And then just turning to Central Hudson in terms of the customer information system. Are you guys able to, at all give any color in terms of potential range of outcomes? And if it's just sort of one-time penalties you might be faced or if there's other sort of more, I guess, recurring pressure in terms of earnings profile at Central Hudson may come out of these proceedings?
No, it's hard to say what's going to come out of the proceeding. We're obviously -- we answered the Show Cause order there, and now we'll have conversations with our regulators and try to figure out where this is going. Most of the O&M impacts that we have seen in '21 and '22 were to get the system to where it needs to be, and we continue to make the additional changes in investments and tweaks to that system as we go to make sure that it's -- we got to get to the point where it's ultimately operating as design, which we think we're getting close on. But we won't see the ongoing O&M drag that we saw the last couple of years. But as far as penalties, that's hard to figure out now. I think we have got a good response to that Show Cause order and we just need to explain the situation and get ahead of it.
Got it. Thanks for the time.
Thank you. Your next question comes from the line of Ben Pham from BMO. Please go ahead.
Hi. Thanks. Can you hear me, okay?
Yeah. Ben, we can hear you.
Okay. Great. I was wondering on your electric versus gas mix, how do you think that mix changes or will it change over the next five years? And then, do you have an internal target of where you want to be in what the CapEx program is to this current CapEx program is complete?
Yeah. No, we don't have like an ongoing mix other than what you can see clearly in our five year capital plan and the level of investments that we see there. In fact, FortisBC is still a very growing utility. And I think for all the right reasons, there's not just the natural gas service territory that they have there, but some of the LNG investments they're making to help produce greenhouse gases and other people's neighborhood. So that's a great asset for us to have and still has very strong growth. We don't have any designs of changing on purposely changing that mix on a going forward basis.
Okay. Great. And then can you share for 2022 on the realized returns, was there any utilities that's earning below the allowed [indiscernible]?
Yeah, I don't know. I don't have that at my fingertips. And -- but yeah, I don't need -- that handy. Obviously, when you look at regulatory lag cycles, just I'll just philosophically, what you would see like in Arizona is that you probably wouldn't be quite earning your return right as you're getting into the volume rate case because after a few years of lag, you'd see a dip. But I actually don't have those numbers in my fingertips.
Okay. And maybe lastly on your -- you have -- your maturity schedule on the debt and you break up between non-reg and regulated, that's quite useful. Do you expect to recover the interest rate change in the -- sorry, in the regulated maturing debt in the rates?
Yes, Ben. It will be a part of our [indiscernible] proceedings or oil utilities. Some of our utilities have mechanisms that track it, but it's will be part of the rate case, and we've not had any issue in front of the regular recovery these types of costs. So we're not anticipating any problems going forward.
Okay. Perfect. Thank you.
Thanks, Ben.
Thank you. [Operator Instructions] Your next question comes from the line of Richard Sunderland from JPMorgan. Please go ahead.
Hi. Good morning and thank you for the time today. I wanted to circle back to MISO in this future 2A. Can you speak a little bit to what this refreshed scenario considers versus the old future to and how that's translating to the early stages of the Tranche 2 process versus, I guess, what you were witnessing at this point in time for Tranche 1?
Yeah. I don't mind the exact tweaks between what they did to Future 2 to make it Future 2A. So they -- just to be clear though, I mean, the first tranche, Tranche 1 was based off of future 1, which was the kind of lowest level of electrification and probably lowest level of resource transit and renewable integration. So Future 2, which was in the middle, obviously, Future 3 was the one that was the fastest on both of those.
And if you remember, historically, and this is data that was -- is now a couple of years old, they put kind of price tags on those different futures of $30 billion for Future 1 and up to $80 billion for Future 2. Future 2 in the middle, I never had a number on exactly what that future investment portfolio would look like. But I don't know, if it's quite halfway there or not, but I don't know if it's the exact adjustments that were made.
Maybe Linda has a little bit additional color on what 2A includes that you she could share?
Yeah, Dave. They have not yet released specifically their updated assumptions in 2A. However, we do know directionally, it's being updated to assume a greater level of renewables penetration to update for utilities carbon reduction goals, as well as increased load projections based on electrification. So I would say, from a directional perspective, it's all pointing in the direction of a more probably ultimately a more realistic scenario of what the future looks like, which ultimately, I think from a transmission perspective, I think, would directionally result in the need for more transmission to interconnect more renewable generation resources.
Got it. That's very helpful color. And just one follow-up on the MISO front. Again around the Tranche 2 process, you hearing anything from MISO on how they might tackle kind of the greenfield versus brownfield split or how they're baking that into their analysis. Obviously, spent a lot of attention over the past few years on that some of the headwinds on greenfield transmission development. So just curious if you hearing anything from MISO on this front for the latest tranche.
Go ahead, Linda.
Dave, yeah, thanks. I wouldn't say in any great specificity. I think there is recognition that, yes, I mean certainly, as we drive to build out more and more transmission investment, the siting becomes certainly more challenging to get the necessary land. So I would say, at a high level, directionally, certainly, there's a lot of encouragement to the extent that you can kind of upgrade existing infrastructure or upgrade the infrastructure on existing rights, ways that can certainly help to facilitate the realization of those projects.
But in terms of MISO being sort of, I would say, directive or assuming those things in their planning process, it does not really emerge. I think they leave that more to the specific transmission owners to identify and determine kind of the specific routing, citing and ultimately, the necessary siting requirements. But I would say, just thematically, just given the transmission is getting more difficult to build and land is getting more difficult to acquire yeah. I mean I think solutions that would look at utilizing existing rights-of-way structures, towers would be certainly beneficial in realizing the investment.
Great. Thank you for taking my questions.
Absolutely.
Thanks, Rich.
Thank you. Your next question comes from the line of Patrick Kenny from National Bank Financial. Please go ahead.
Thank you. Good morning, everyone. Just back to BC on the wood fiber gas pipeline. I know it's relatively small in the grand scheme of things, but just with respect to the 20% increase and the total cost up to $420 million, I believe. Is the expectation that you'll be able to earn on the full final price tag whatever that ends up being by 2027 or it just the original $350 million and then you have to absorb any excess costs above that on the balance sheet?
No, we wouldn't absorb any excess costs. There's a bit of a complicated formula in the course and contribution in native construction that the wood fiber would pay for and the remaining part, all of our investment would go into rates.
Okay. Perfect. Thanks for that. And then in Alberta, just given how high power prices have been here, I know you've received approval for a 5% increase in distribution rates for 2023. But just wanted to check in on how you're thinking about managing or perhaps smoothing out future rate increases? And for getting any pushback from the regulator on the pace of rate base growth, at least until power prices settle back down?
Yeah. That's a great question. It's the same thing that we're seeing in every one of our jurisdictions. And in Alberta, we're just the distribution system operator there. So our rates are varies, kind of slow and steady increasing part of the bill. It's not a very volatile, it's not volatile at all. So this is the rate increase that we got going this year, pales in comparison to the increases that they're seeing in the actual power part of their bill, the energy part. So we're obviously watching that. We are investing as we need to invest in the system and the needed reliability upgrades that we need to do to connect new customers.
Obviously, the Alberta economy is a bit cyclical. So we see the boom and bust on growth, and we're seeing good growth there now and hopefully, for a long period of time. So we're cognizant of that cost focus, but it's really not our part of the build that's causing the angst. We do know though that it's a total bill perspective that the regulators look at, in that province, but we're doing what we can to control the costs that we can control. But we still have to make those investments we need to make in the system.
Appreciate the color. Thanks, David.
Thank you. There are no further questions on the phone line at this time. Ms. Stephanie Amaimo, please continue for any closing remarks.
Thank you, Laura. We have nothing further at this time. Thank you, everyone, for participating in our fourth quarter and annual 2022 results conference call. Please contact Investor Relations should you need anything further. Thank you for your time and have a great day.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.