Q3 2023 Fortis Inc Earnings Call

Operator: Those with questions, should press star followed by the number 1 on their telephone. If at any time during the conference you need to reach an operator, please press star zero. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

At this time I would like to turn the conference over to Stephanie of Magnus. Please go ahead Mr. Mimo.

Stephanie Amaimo - Head of IR, Fortis Inc.: Thank you, Ludy and good morning everyone and welcome to Fortis' third quarter 2023 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. Today Jocelyn will speak to the prepared remarks on behalf of Dave as he is recovering from laryngitis, while Dave and Jocelyn will address questions at the end.

Recovering from laryngitis, well, Dave and Jonathan will address questions at the end.

Before we begin today's call, also 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 US GAAP financial measures in our 3rd quarter 2023 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to Jocelyn.

GAAP financial measures in our third quarter 2023, MD&A also unless otherwise specified all financial information referenced is in Canadian dollars with that I will turn the call over to Jacqueline.

Jocelyn Perry - CFO, Fortis Inc.: Thank you and good morning everyone. The third quarter proved to be a busy and positive quarter for Fortis. We received a number of key regulatory decisions in Arizona and Western Canada, which I will speak to shortly. Together, rate base growth and the recent regulatory outcomes in British Columbia and Arizona, supported strong earnings growth in the quarter and year-to-date. And for those that attended in person or tuned in virtually, you know we held our Investor Day in September, outlining our new $25 billion capital plan for 2024 to 2028. This capital plan supports 6.3% average annual rate base growth and 4% to 6% annual dividend growth guidance through 2028. Lastly, the pending sale of Aitken Creek is progressing as expected with the British Columbia Utilities Commission or BCUC approving the sale last week. With all regulatory requirements satisfied, we expect the transaction will close in the fourth quarter.

<unk> rate base growth and the recent regulatory outcomes in British Columbia in Arizona supported strong earnings growth in the quarter and year to date.

And for those that attended in person or tuned in virtually you know we held our Investor day in September outlining our new 25 billion capital plan for 'twenty to 'twenty four to 'twenty or 'twenty eight this capital plan to support six 3% average annual rate base growth and 4% to 6% annual dividend growth guidance.

Through 2028.

Lastly, the pending sale of Aitken Creek is progressing as expected with the British Columbia Utilities Commission or BCUC approving the sale last week. With all regulatory requirements satisfied, we expect the transaction will close in the fourth quarter.

With decisions in the TEP rate case and the generic cost of capital or GCOC proceedings in Alberta and BC, we have completed a number of large regulatory applications. In August, the Arizona Corporation Commission issued its decision in TEP's general rate application, approving an increase in non-fuel revenue of $100 million US dollars and 9.55% allowed ROE and a 54% equity layer. New customer rates became effective on September 1st. Also last month, the BCUC issued a decision on the GCOC proceeding. The decision resulted in an allowed ROE of 9.65% for both Fortis utilities, reflecting a 90 basis point increase for FortisBC Energy and 50 basis point increase for FortisBC Electric. The equity thickness levels also increased from 38.5% to 45% for FortisBC Energy and from 40% to 41% for FortisBC Electric. The new cost of capital parameters are retroactive to January 1st, I'll speak later to the related financial impacts.

Over 100 million U S dollars and $9 five 5% allowed ROE and a 54% equity layer through customer rates became effective on September one.

Also last month, the BC UC issued a decision on the juice, you'll see preceding the decision resulted in an allowed ROE of 965% for both Fortis utilities, reflecting a 90 basis point increase for Fortis BC energy and 50 basis point increase for Ford is D C electric.

The equity thickness levels also increased from 38, 5% to 45% for Fortis BC energy and from 40% to 41% for Fortis BC electric the new cost of capital parameters are retroactive to January 1st I'll speak later to the related financial impacts.

In October, the Alberta Utilities Commission or AUC issued a decision on FortisAlberta's third performance-based rate setting mechanisms as well as the 2024 GCOC [inaudible]. Overall, the PBR decision was generally in line with management's expectations. FortisAlberta continues to evaluate the annual capital provisions included in the PBR decision, which were premised on 2018 to 2022 historical levels. In the GCOC decision, the AUC adopted a formulaic approach in determining the allowed ROE, which will be calculated annually. Although the 2024 allowed ROE calculation won't be finalized until later this year, using today's inputs, we expect the allowed ROE for 2024 to be modestly higher than the notional ROE of 9%. All in all, we received balanced regulatory outcomes for our customers and stakeholders in Arizona and Western Canada.

Overall, the PBR decision was generally in line with management's expectations for this Alberta continues to evaluate the annual capital provisions included in the PBR decision, which were premised on 2018 to 2020 to historical levels.

In the G. C O C decision the AUC adopted a formulaic approach in determining the allowed ROE, which will be calculated annually, although the 'twenty 'twenty four allowed ROE calculation won't be finalized until later this year using todays inputs. We expect the allowed ROE for 'twenty 'twenty four to be modestly higher than the note.

<unk> ROE of 9% all in all we received balanced regulatory outcomes for our customers and stakeholders in Arizona in Western Canada.

With $3 billion invested in our systems through September, our $4.3 billion dollar annual capital plan remains on track. Major capital projects continue to advance in line with our plan. In August, FortisBC Energy commenced construction on the Eagle Mountain-Woodfibre gas line project and just a few weeks ago TEP announced it will build the Roadrunner Reserve project, a 200 megawatt battery energy storage system. This system is expected to be operational in the summer of 2025, capable of serving approximately 40,000 homes for 4 hours when deployed at full capacity. This project support system reliability as TEP exits from coal and expands its renewable resources. TEP expects to file its next integrated resource plan on November 1st.

Major capital projects continue to advance in line with our plan in August Fortis BC RG commence construction on the Eagle Mountain Wood fiber gasoline project and just a few weeks ago T. P announced it will build the road runner Reserve project, a 200 megawatt battery energy storage system. This system is expected to be operation.

In the summer of 2025 capable of serving approximately 40000 homes before ours when deployed at full capacity. This project support system reliability as T. P exits from coal and expands its renewable resources.

TEP expects to file its next integrate integrated resource plan on November 1st.

The preferred portfolio is expected to align with Fortis' Scope 1 greenhouse gas emissions reduction targets of 50% by 2030, 75% by 2035 and net zero by 2050. A five-year $25 billion capital plan is comprised of virtually all regulated investments and a diverse mix of highly executable low-risk projects. This new plan is $2.7 billion higher than the previous five-year plan. The increase is driven by regional transmission projects at ITC associated with Tranche 1 of the MISO Long Range Transmission Plan as well as investments in Arizona to support TEP's exit from coal. Investments supporting system adaptation resiliency and economic development are also driving capital growth for the benefit of our customers.

50% by 2030, 75% by 2035 and net zero by 2050.

A five year $25 billion capital plan is comprised of virtually all regulated investments and a diverse mix of highly executable low risk projects. This new plan is $2 7 billion higher than the previous five year plan. The increase was driven by regional transmission projects at ITC associated with tranche.

One of the MISO long range transmission plan as well as investments in Arizona to support T piece exit from coal in.

Investments supporting system adaptation resiliency and economic development are also driving capital growth for the benefit of our customers.

We expect rate base will increase by $12.6 billion to over $49 billion in 2028, supporting average annual rate base growth of 6.3%. In the third quarter, our board of directors declared a fourth quarter dividend increase of 4.4%, marking 50 years of consecutive increases in dividends paid. Fortis is proud to be one of only two companies listed on the Toronto Stock Exchange to achieve this significant milestone. In September, we also announced the extension of our 46% annual dividend growth guidance through 2028 supported by our sustainable growth outlook.

In the third quarter, our board of directors declared a fourth quarter dividend increase of four 4% marketing 50 years of consecutive increases in dividends paid.

Board is proud to be one of only two companies listed on the Toronto stock exchange to achieve this significant milestone.

In September we also announced the extension of our 4% to 6% annual dividend growth guidance through 2028 supported by our sustainable growth outlook.

Slide eight provides a summary of our third quarter and year-to-date reported and adjusted earnings per share. Reported earnings include timing differences related to mark to market accounting of natural gas derivatives at Aitken Creek and the revaluation of deferred income tax assets related to a change in the corporate tax rate in the state of Iowa. Adjusted EPS was $0.84 cents, $0.13 cents higher than the third quarter of 2022. On a year-to-date basis, adjusted EPS was $2.37, $0.31 cents higher than the same period last year. Key earnings drivers center around continued investments in our regulated rate base, the recent regulatory orders in BC and Arizona as well as warmer weather in Arizona. I'll get into the details of each of the next couple of slides.

Our reported earnings include timing differences related to mark to market accounting of natural gas derivatives at Aitken Creek and the revaluation of deferred income tax assets related to a change in the corporate tax rate in the state of Iowa.

Adjusted EPS was <unk> 84 cents 13 cents higher than the third quarter of 2022 on a year to date basis, adjusted EPS was $2 37.

31 cents higher than the same period last year.

Key earnings drivers center around continued investments in our regulated rate base. The recent regulatory orders in D. C in Arizona as well as warmer weather in Arizona I'll get into the details of each of the next couple of slides.

The waterfall chart on slide nine highlights the EPS drivers for the third quarter by segment. Our western Canadian utilities contributed a $0.09 cent EPS increase reflecting the new cost of capital parameters approved by the BCUC in September 2023, totaling approximately $0.08 cents, including $0.05 cents per common share associated with the retroactive impact to January 1st. Rate base growth also contributed to the increase which was partially offset by the timing of operating costs at FortisAlberta. EPS was higher by $0.01 cent below US electric and gas utilities, with UNS increasing $0.02 cents in Central Hudson down one.

Our western Canadian utilities contributed a nine cent EPS increase reflecting the new cost of capital parameters approved by the BC you see in September 'twenty two 'twenty three.

Totaling approximately eight including five cents per common share associated with the retroactive impact to January 1st rate base growth also contributed to the increase which was partially offset by the timing of operating costs at Ford as Alberta.

EPS was higher by one simple our U S electric and gas utilities with Unf's, increasing two cents in central Hudson down one.

In Arizona, the quarterly results were mainly driven by new rates at TEP, effective September 1st and higher retail sales due to warmer weather. New rates increased EPS by approximately $0.02 cents, while weather in the quarter favorably impacted EPS by $0.04 cents with July being the hottest month on record in Tucson. Lower wholesale and transmission revenues, higher operating costs and lower production tax credits for Oso Grande tempered the results at UNS for the quarter. Central Hudson's results reflect higher operating costs as expected due to the timing of costs in the first half of the year, partially offset by rate base growth. At our other electric segment, EPS increased $0.01 cent driven by rate base growth and higher sales. Our energy infrastructure segment contributed a $0.02 cent EPS increase for the quarter. This includes higher earnings at Aitken Creek, reflecting market conditions, net of lower hydroelectric production in Belize.

Weights increased EPS by approximately two cents, while weather in the quarter favorably impacted EPS by four cents with July being the hottest month on record in Tucson.

Lower wholesale transmission revenues higher operating costs and lower production tax credits for also Grande tempered the results at U S for the quarter.

Central Hudson's results reflect higher operating costs as expected due to the timing of costs in the first half of the year, partially offset by rate base growth.

At our other electric segment EPS increased one cent driven by rate base growth and higher sales.

Energy infrastructure segment contributed a two cent EPS increase for the quarter. This includes higher earnings at Aitken Creek, reflecting market conditions net of lower hydroelectric production in Belize.

Elevated finance costs at corporate and higher weighted average shares outstanding, issued under our dividend reinvestment plan, were offset by the favorable impact of a higher average US to Canadian dollar foreign exchange rate. And although not shown on the slide, ITC's rate base growth for the quarter was largely offset by higher non-recoverable finance and stock-based compensation cost. Year-to-date EPS was impacted by many of the same factors discussed for the quarter. On a year-to-date basis, an increase in the market value of certain investments that support retirement benefits and lower depreciation associated with the retirement of the San Juan generating station in 2022, also favorably impacted results.

Finance and stock based compensation cost.

Year to date EPS was impacted by many of the same factors discussed for the quarter on a year to date basis, an increase in the market value of certain investments that support retirement benefits and lower depreciation associated with the retirement of the San Juan generating station. In 2022 also also favorably impacted breeze.

Salt.

Before I move on from earnings, I would like to take a moment to explain where we are with respect to the pending sale of Aitken Creek. As I mentioned, we expect to close the transaction in the fourth quarter. Until close, we continue to recognize earnings associated with Aitken Creek in accordance with US GAAP. Upon close of the transaction, adjusted earnings will exclude the gain expected to be recorded on the sale as well as the earnings recognized since the March 31st effective date. For the third quarter, we recorded adjusted earnings at Aitken Creek of $13 million or $0.03 cents per common share and $24 million or $0.05 cents per common share for the six months period since March 31st. Through September, we have raised over $2 billion of debt, primarily to refinance maturing debt and to fund our capital program.

As I mentioned, we expect to close the transaction in the fourth quarter until close we continue to recognize earnings associated with Aitken Creek in accordance with U S. GAAP.

Upon close of the transaction.

Adjusted earnings will exclude the gain expected to be recorded on the sale as well as the earnings recognized since the March 31 effective date for the third quarter. We recorded adjusted earnings of eight at Aitken Creek of $13 million or three cents per common share and 24 million or five cents per common share for the six months.

Period since March 31st.

Through September we have raised over 2 billion of debt primarily to refinance maturing debt and to fund our capital program.

With regards to upcoming maturities, we currently have about $1.7 billion due through the end of 2025, including almost $200 million US dollars in non-regulated debt at Fortis Inc. Our primary exposure to elevated interest rates pertains to holding company debt as our regulated utilities ultimately recover changes in interest rates through regulatory mechanisms and the periodic rebasing of customer rates. We'll continue to monitor the debt capital markets and consider interest rate hedges or pre-funding opportunities. With proceeds from our debt issuances and the expected sale of Aitken Creek, as well as over $4 billion available in our credit facilities, we remain in a strong liquidity position and are comfortably positioned within our investment grade credit ratings as we execute our $25 billion capital plan.

Our primary exposure to elevated interest rates pertains to holding company debt as a regulated utilities ultimately recover changes in interest rates through regulatory mechanisms and the periodic re basing of customer rates will continue to monitor the debt capital markets and consider interest rate hedges or pre funding opportunities.

With proceeds from our debt issuances and the expected sale of Aitken Creek as well as over 4 billion available on our credit facilities. We remain in a strong liquidity position and are comfortably positioned within our investment grade credit ratings as we execute our $25 billion capital plan.

To summarize, we have made significant progress in 2023 to advance our growth strategy. We have executed our capital plan as expected, concluded key regulatory proceedings and delivered strong earnings growth through the third quarter. And with our recently announced five-year capital plan, we are continuing to deliver regulated growth to support a more reliable and cleaner energy future. When combined with a regulated and geographic diversity, strong ESG story and good governance model, we are well-positioned for the future. That concludes my remarks, I'll now turn the call over to Stephanie.

And with our recently announced five year capital plan, we are continuing to deliver regulated growth to support a more reliable and cleaner energy future when combined with the regulator with a regulated and geographic diversity strong ESG story and good governance model, we are well positioned for the future.

That concludes my remarks, I'll now turn the call over to Stephanie <unk>.

Stephanie Amaimo - Head of IR, Fortis Inc.: Thank you, Jocelyn. This concludes the presentation at this time, we'd like to open the call to address questions from the investment community.

Operator: Thank you. We will now conduct a question and answer period. If you'd like to register a question, please press the star followed by the number 1 on your telephone. If your question has been answered and you would like to withdraw your registration, please press the pound sign. If you're using a speakerphone, please keep your handset before entering your request. And we kindly request that you speak loudly and slowly to ensure all participants can hear your question. One moment please for the first question.

Your class and he kindly request you to speak loudly in slowly to ensure all bank expense you can hear your questions. One moment. Please for the first question.

Your first question comes from the line of Maurice Choy from RBC Capital. Your line is open.

Maurice Choy - Director, Canadian Energy Infrastructure, RBC Capital Markets: Thank you and good morning. I just want to start with ITC. I assume you would have seen the US Solicitor General's comments early this week to the Supreme Court regarding Texas rule ROFR--admittedly this feels consistent with the past commentaries, but any thoughts on that submission? Do you think FERC will do anything on the backs of that and, you know, what does the US Supreme Court position may mean for your existing ROFRs?

I assume you would have seen.

U S solicitor General's comments really to speak to the Supreme Court.

Regarding Texas rule for admittedly this feels consistent with the past countries, but any thoughts on that submission.

Think FERC will do anything.

And you know what to say.

He was Supreme Court position May mean for your existing workforce.

David Hutchens - CEO, Fortis Inc.: Yeah. Thanks for the question, Maurice. I'm going to kick that over to Linda Apsey, our CEO of ITC to give you a little bit of color on that. But yeah, we did see that and she can explain some of those differences between what we have in Iowa and what Texas sees.

Linda H. Apsey - CEO, ITC Holdings Corp.: Great. Thanks, Dave and good morning Maurice. Yes, we too saw that Solicitor General opinion on the Texas ROFR and I think it, you know, I think standing back from it was sort of a mixed bag. I think in terms of some of the reflections of the Solicitor General, I think most importantly is that it's strong--it sort of. Versus for example, the Minnesota a role for which had also been challenged and was upheld. By the district court in in that covers the Minnesota area. Essentially, the Solicitor General indicated that they did not feel as though the issue was ripe for the Supreme Court to take up the issue. And that there was still sort of opportunity you know for this issue to continue to play out so I would say by and large it was a you know sort of a mixed opinion I'm not clear what the Supreme Court will do if anything I certainly as I said it was the solicitor General's recommendation. That the court not take up the issue and I think from our perspective. It is it does I think demonstrate that the ROFRs--whether it'd be in Minnesota, Michigan or what had been proposed in Iowa--is distinctly different from what the Texas ROFR was.

Yes, we too saw that solicitor general our opinion on the Texas Rover and I think it you know I think standing back from it it was sort of a mixed bag I think in terms of some of the reflections of the solicitor General I think most importantly is that it's strong it's sort of.

Calls out a distinction between the Texas, a role for which in essence does not provide any opportunity for any non incumbent utility to participate in investment in transmission in the state.

Versus for example, the Minnesota a role for which had also been challenged and was upheld.

By the district court in in that covers the Minnesota area.

Essentially the the solicitor general sort of.

Indicated that you know they did not feel as though the issue was ripe for the Supreme Court to take up the issue.

And that there was still sort of opportunity you know for this issue to continue to play out so I would say by and large it was a you know sort of a mixed opinion I'm not clear what the Supreme Court will do if anything I certainly as I said it was the solicitor General's recommendation.

That the court not take up the issue and I think from our perspective. It is it does I think demonstrate.

That the ropers, whether it'd be in Minnesota, Michigan, or what had been proposed in Iowa.

<unk> is distinctly different from what the Texas role for was.

Maurice Choy - Director, Canadian Energy Infrastructure, RBC Capital Markets: Great, thanks.

David Hutchens - CEO, Fortis Inc.: Linda, just a little additional color on that, as well. I thought one of the interesting parts about that argument, that it's not ripe, was the fact that FERC is obviously looking at things like re-instating federal ROFRs for some projects and that's part of the planning and cost allocation offer that they have out there so that's an interesting, I think, deference to FERC as well.

That's an interesting I think difference to FERC as well.

Linda H. Apsey - CEO, ITC Holdings Corp.: Yes. Thank you, David. Absolutely.

Maurice Choy - Director, Canadian Energy Infrastructure, RBC Capital Markets: Maybe like, any thoughts on timing of that potential for a clean statement?

Linda H. Apsey - CEO, ITC Holdings Corp.: David, I don't know if you want to take that or me?

David Hutchens - CEO, Fortis Inc.: What was the question, Maurice?

Maurice Choy - Director, Canadian Energy Infrastructure, RBC Capital Markets: You referenced the reinstatement of the federal offer by FERC. Any thoughts on timing? Do we need a full slate of commission it first? Any thoughts on that?

Any thoughts on timing do we need a full slate of commission it Spurs.

Any thoughts on that.

David Hutchens - CEO, Fortis Inc.: Yes, I think it probably will be a bit of time there because that's part of the planning and cost allocation NOPR and I think that they're really probably waiting to move that forward to whatever a fuller complement of FERC commissioners.

Maurice Choy - Director, Canadian Energy Infrastructure, RBC Capital Markets: Great. And maybe just finishing off on FX. Clearly, FX is higher today than the $1.30 you've seen in your five-year plan. I know you provided sensitivities on slide 22 for EPS and CapEx, but could you remind us of your cash flow or earnings hedges for the upcoming years and assuming these FX rates hold, clearly helpful to earnings, but how would you approach funding the additional CapEx?

Privy ethics is higher today than the $1 30, you'll see them in your five year plan.

I know you provided a sensitivity on slide 22 for EPS and Capex.

But could you remind us of your cash flow or earnings hedges for the upcoming years and assuming these FX rates hold clearly helpful to earnings, but how would you approach funding additional capex.

Jocelyn Perry - CFO, Fortis Inc.: Maurice, this is Jocelyn. Yeah, we do hedge cash flows. We actually go out two years about in 100% of our cash flows but you're right, with the rates where they are today, where we're always watching that and we hedge a little more sometimes and we hedge a little less sometimes. And it does impact our earnings, but particularly we watch it around cash flows. So we used to do it actually one year out, but we moved to two years a few years ago and we continue to watch it and we continue to change as the rates change.

100% of our cash flows and but you're right with the rates, where they are today, where we're always watching that and we hedge a little more sometimes and we hedge a little less sometimes.

And it does impact our earnings, but particularly we watch it around cash flows. So we like we used to do it actually one year out, but we moved to two years, a few years ago and we continue to watch it and we continue to change as rates change.

Maurice Choy - Director, Canadian Energy Infrastructure, RBC Capital Markets: And can I ask what rate do you hedge those two years of cash flows?

Jocelyn Perry - CFO, Fortis Inc.: Well, I'd have to get that average rate. It's actually a good rate today because we've been we've been in the market recently, but I'd have to get the specific rate for that; we got a lot of little hedges that we put in place.

Maurice Choy - Director, Canadian Energy Infrastructure, RBC Capital Markets: Great. Thank you very much and get well soon Dave. You do sound good, I will say.

David Hutchens - CEO, Fortis Inc.: Thank you. I'm okay in the lower register [laughter].

Operator: Thank you. Your next question comes from the line of Rob Hope from Scotiabank. Your line is open.

Rob Hope - Director, Equity Research, Scotiabank: Good morning, everyone. I was hoping you could give us some additional color on the Tucson IRP which will be filed in the coming days. Maybe can you just talk about how it has changed with the IRP and whether we could see some upside or downside in your CapEx plan, depending on kind of the the eventual outcome of the transition there?

Maybe can you just talk about how it has changed with your I R. P and whether we could see some upside or downside in your Capex plan, depending on kind of the the eventual outcome of the transition there.

David Hutchens - CEO, Fortis Inc.: So Rob, I'd love to give you a bunch of details on that but we're just around the corner from releasing that publicly and we really don't want to front run our commissioners in the process. So that filing and all the details and comments that we'll make around that arejust around the corner so I'd ask for your patience and call us back and we'll give you as much information as you'd like on that.

Or just around the corner so I'd I'd.

I'd ask for your patience and then call us back and we'll we'll give you as much information as you'd like on that.

Rob Hope - Director, Equity Research, Scotiabank: Sounds good. And then maybe a follow up there. How are you dealing with some of the supply chain issues that we're seeing there? Are you seeing them improve or are there still some headwinds and how are you managing kind of the supplier issues right now?

And then maybe a follow up there.

How are you dealing with some of the supply chain issues that we're seeing there are you seeing them improve or card or are there still some headwinds and how are you managing kind of the supplier issues right now.

David Hutchens - CEO, Fortis Inc.: Yeah. So, so far we haven't really seen that impact because we're kind of doing--I mean, we're not doing a whole ton of any one thing. So we're not dependent on some huge amount of panels or wind or batteries, et cetera. It's a very balanced portfolio approach that we're doing so we have not, to date, as we sit here today, I feel like we have any issues there now. Obviously, those change as we go forward and we'll be watching that but I think we're gonna be just fine.

On some huge amount of panels or wind or.

Batteries et cetera, it's a very balanced.

The portfolio approach that we're that we're doing so we have not to date.

As we sit here today I feel like we have any issues. There now obviously those are those change as we go forward and we'll be watching that but.

I think I think I think we're gonna be done just fine.

Rob Hope - Director, Equity Research, Scotiabank: Thank you.

David Hutchens - CEO, Fortis Inc.: Thanks, Rob.

Operator: And your next question comes from the line of Mark Jarvi from CIBC Capital Markets. Please proceed with your question.

Mark Jarvi - Equity Research Analyst, CIBC Capital Markets: Yeah, thanks. Good morning, everyone. So just wanted to come back to the comments around higher interest rates and Jocelyn, you mentioned that the holding company debt, just--at the operating subsidiaries, where are you feeling the most pressure from any regulatory lag or I guess there'll be [inaudible] interest rates versus deemed debt and wherever we see a carryover of that impact in the 2024, if at all.

So just wanted to come back to the comments around higher interest rates and it's also you mentioned that the holding company.

At the operating subsidiaries, where are you feeling the most pressure from a regulatory lag or I guess there'll be catone interest rates versus zynga and wherever we see a carryover of that impact in the 'twenty 'twenty four.

At all.

Thanks, Mark. Yeah I--so most of our utilities actually have mechanisms to capture the interest rate changes from year to year, like ITC in Alberta and BC. But the one, I think you've already hit it, the one that there is a lag is that UNS. So until they go in for their next rate case more than they used to any new debt issuances that they have done, so I would say in large part, most of our utilities actually have those mechanisms; but that's probably the one area where its--and its small, right. It would be a small impact relative to Fortis. Any way you can kind of put some metrics around that or quantify it to some level?

Jocelyn Perry - CFO, Fortis Inc.: Thanks, Mark. Yeah I--so most of our utilities actually have mechanisms to capture the interest rate changes from year to year, like ITC in Alberta and BC. But the one, I think you've already hit it, the one that there is a lag is that UNS. So until they go in for their next rate case more than they used to any new debt issuances that they have done, so I would say in large part, most of our utilities actually have those mechanisms; but that's probably the one area where its--and its small, right. It would be a small impact relative to Fortis.

So most of our utilities actually have mechanisms to capture the interest rate changes from year to year like ITC in Alberta, and B C. But the one I think you've already hit it. The one that there is a lag as that U N S. So until they go in for their next rate case more than they used to.

Any new debt issuances that they have done so I would say in large part most of our utilities actually have those mechanisms, but that's probably the one area, where its and its small right. It would be a small impact relative to afford us.

Mark Jarvi - Equity Research Analyst, CIBC Capital Markets: Any way you can kind of put some metrics around that or quantify it to some level?

Any way you can kind of put some metrics around that or quantify it.

<unk>.

Jocelyn Perry - CFO, Fortis Inc.: Well, I can't believe it to be material because I'm thinking about--really what you're talking about is the delta on any new debt issuances over the next couple of years--and I don't know if Susan has that number in front, but you know, it's probably a couple of hundred million in, I mean not that over the next two years and so it's the delta between probably their current rate and about 2% delta on that. So, again, not big for Fortis and as you know with UNS, with the way that their rates are set, some things are positive, some things are negative so it's not necessarily a drag on earnings and so you have to look at the full picture as well.

I can't believe it to be material, because I'm thinking about really what you're talking about is the delta on any new debt issuances over the next couple of years and I don't know if Susan has that number in front, but you know, it's probably a couple of hundred million in.

I mean not that over the next two years and so it's the delta between probably their current rate and about 2% Delta on on that so again not big for Ford Us and as you know with you on this with with the way that their rates are set some things are positive some things are negative so it's not necessarily.

A drag on earnings and so you have to look at the full picture as well.

Mark Jarvi - Equity Research Analyst, CIBC Capital Markets: Got it. And then just given where you think rates are today and you think about the maturities in 2024 even, any idea in terms of when you look to address that? Is that something you'd be patient with it? It is something just want to kind of address and clear off earlier than later? Any sort of updated views in terms of how you deal with those maturities in the next 12 months.

And then later any sort of updated views in terms of how you deal with those maturities in next 12 months.

Jocelyn Perry - CFO, Fortis Inc.: Well, we watch it daily and so we make these decisions quite frequently but what I will say is I tend to get that risk behind us. So in the past, we've actually had a lot of debt forward and we continue to do that so it is a strategy that we've deployed before and I suspect, will deploy again. We'll keep watching the market, I mean, it's still very volatile but it's something that you really have to reset your thinking on week to week.

Uh huh.

Get that risk behind us right. So so in the past, we've actually hard to them a lot of that forward and we continue to do that so so it is a strategy that we've deployed before and I suspect, we will deploy again, but well keep watching the market I mean, it's still it is still very volatile but.

It's something that you really have two two to reset your thinking on week to week.

Mark Jarvi - Equity Research Analyst, CIBC Capital Markets: Okay. Thanks, everyone.

Operator: And your next question comes from the line of Ben Pham from BMO Capital Markets. Please proceed with your question.

Ben Pham - Managing Director, Pipelines and Utilities Analyst, BMO Capital Markets: Hi, thanks. Good morning. Maybe to continue that last question on refinancings, I'm wondering is there any meaningful differences between when you said, what the Canadian and US market and refinancing upcoming debt such as the '24-'26. When you think about just where interest rates are going between the two countries, your FX exposure, where you want that to be and cost of hedges.

I'm wondering is there any.

Meaningful differences between when you said, what the Canadian and U S market and.

Refinancing upcoming debt such as the 24 26, when you think about it. Just where interest rates are going between the two countries traffics exposure and where you want that to be in and cost of hedges.

Just where interest rates are going between the two countries traffics exposure and where you want that to be in and cost of hedges.

Jocelyn Perry - CFO, Fortis Inc.: Ben, that's what we do all day long. So every time, in both markets, we're looking at where we're issuing, what we're issuing, the tender, the currency. I mean, we've done some FX currency swaps on Canadian debt, like--we're active in that market but as I said on the previous question, it is something that you sort of have to reset your mind every week because it is changing but all of those things are considered every time we go to market.

But we do all day long.

So every time you know in both markets, we're looking at where we're we're issuing what we're issuing the tender of the you know.

The currency I mean, we've we've done some.

Effects currency swaps on Canadian debt like we we will.

We're active in that market and but as I said on the previous question. It is something that you sort of have to reset your mind every week because it is changing but all of those things are considered every time, we go to market.

Ben Pham - Managing Director, Pipelines and Utilities Analyst, BMO Capital Markets: And would you say on your FX matching them and--what I'm getting at is--you have a US dollar maturity coming up, you can issue in Canada to 1% benefit, but yet on your FX exposure comes off a bit like a U. Right now your FX exposure mostly is in line with where you want to be?

Your FX matching them and kind of what I'm, what I'm getting at is do you have a U S dollar maturity.

Coming up you can issue in Canada to one per cent benefit, but yet on your FX exposure comes off a bit like a U.

Right now you your FX exposure, mostly is in line with where you want to be.

Jocelyn Perry - CFO, Fortis Inc.: Yeah, I think we're comfortable where we are today, but again--yeah, no I would leave it at that. We're comfortable where we are today but we're always watching it.

Yeah, No I I would I'd leave it at that we're comfortable where we are today, but we're always we're always watching it.

Ben Pham - Managing Director, Pipelines and Utilities Analyst, BMO Capital Markets: Okay. And I know the cost of capital decisions post-Investor Day provided details in EPS sensitivities, that's very useful. How do you think [inaudible] flow through that impact on credit metrics and if there's an impact on your equity needs?

Bachelor Day provided the details in EPS sensitivities Thats very useful how're you.

How do you think really flow through that impact on credit metrics and if there's an impact on your your equity needs.

Jocelyn Perry - CFO, Fortis Inc.: So Ben, so that question is--what impact is the GCOC having on our cash metrics. Okay. Yeah, I think it's about 20 BPS, but again, that's going to depend on how that's recovered in rates and I know that the folks in western Canada are still looking at how--well, we don't have the order, I should say, on how that's actually going to flow through customer rates--but I think in the, when it all settles, when it all gets into customer rates is probably about 20 BPS in BC. And with respect to [inaudible], we have actually followed our compliance filing with the BCUC. We are expecting that they will require about $300 million, not quite sure yet when we have to fund that but it will likely be late this year or early into next year.

G C O C. Having on our cash metrics. Okay. Yeah, I think it's about 20, bips, but again, that's going to depend on how that's recovered in rates and I know that the folks in western Canada, We're still looking at how are.

We don't have the order I should say on how that's actually going to flow through customer rates, but I think in the you know when it all settles in it all gets into customer rates is probably about 20 bps in D C.

And with respect to.

We we have actually followed our compliance filing with the B C. You see we are expecting that they will require about 300 million not quite sure yet when we have to to fund that but it will likely be like lately this year or early into next year.

Ben Pham - Managing Director, Pipelines and Utilities Analyst, BMO Capital Markets: Okay, got it. Thank you.

Operator: And your next question comes from the line of David Quezada from Raymond James. Your line is open.

David Quezada - VP, Equity Research Analyst, Raymond James: Thanks morning, everyone. Maybe a question just from a regulatory perspective. You've had a few big decisions recently, I'm just wondering where you'll be turning your focus to going forward and any updated thoughts around when we could see some development on the outstanding items at ITC?

Thanks morning, everyone. Maybe a question just just from a regulatory perspective.

You've had a few big decisions recently, I'm, just wondering where where you'll be turning your focus too going forward and.

Any updated thoughts around when we could see some development on the outstanding items at ITC.

David Hutchens - CEO: Yeah, I'll turn it over to Linda to comment on the ITC for timing because, you know, some of that stuff is still up in the air but we have always got something in the hopper related to regulatory filings. We still got a very small UNS electric case going down in Arizona, we're getting ready to file another multi-year rate plan at FortisBC. So a couple in, a couple out, we're always in this process for sure. But no real big regulatory decisions that we're waiting on yet today other than those ones from FERC.

Some of that stuff is still up in the air but we have always got something in the hopper are related to regulatory filings.

We still got a a very small U S electric case going down in Arizona, we're getting ready to file another multi.

Your rate plan.

At Fortis BC. So a couple in a couple out we're always in this process for sure.

But no real.

Big.

Regulatory decisions that were waiting on yet.

Other than those ones from FERC.

And Linda if you want to opine on, your opinion on those like the base ROE and the, some of those other ones that are hanging out there.

Some of those other ones that are hanging out there.

Linda H. Apsey - CEO, ITC Holdings Corp.: Sure, of course. Yeah, certainly we don't have any clarity around when FERC might act. I think as we have discussed and spoken about before on these calls, certainly the composition of the FERC Commission is somewhat kind of, I think, standing in the way of some progress on decisions around many of the pending matters before FERC. Certainly as a transmission owner group at MISO, we continue to be engaged around the base ROE matter and certainly with MISO TOs as well as the industry, continue to be engaged and discuss the other pending NOPRs, incentive NOPRs as well as other issues. But I would say, particularly on the base ROE issue, I think we're gonna have to wait until we have a full composition of commissioners until we see any progress or traction on that issue and then on the incentive NOPR issue, it is our view and it's our read that is not a priority issue amongst the commissioners at this point in time and so we just continue to track and monitor and be engaged to the extent that we can on those issues.

Certainly the the composition I think of the FERC Commission is somewhat you know kind of I think standing in the way of some progress on decisions around many of the pending matters before <unk>.

Certainly as a transmission owner group at MISO, we continue to be engaged around the base ROE matter and certainly with my son T OS as well as the industry. You know continue to be engaged and discuss the other pending no Percy incentive nowhere as well as other issues, but you know I would say.

<unk> I'm on the the base our O E issue I think we're gonna have to wait and wait until we have a full composition of commissioners until we see any progress or traction on that issue and then on the incentive no per issue. It is our view and it's our read.

That is not a priority issue amongst the commissioners at this point in time and so we just continue to track and monitor and be engaged to the extent that we can on those issues.

Yeah.

David Hutchens - CEO, Fortis Inc.: Thanks, Linda. I totally forgot I do the round the horn in my head there at all the different utilities and what's coming up, but Central Hudson obviously has a a rate case that's currently filed and pending as well.

I totally forgot I do the round the horn in my head there at all the different utilities, and what's coming up but central Hudson, Obviously has a a rate case, that's currently filed and pending as well.

David Quezada - VP, Equity Research Analyst, Raymond James: Excellent. Thanks for that and then maybe just one more for me. Thinking about the MISO Long Range Transmission Plan, I'm wondering if you have any thoughts around, you know, some of the things the IMM has put out there about fleet assumptions and you see that having any material effect on how things could play out there?

Thinking about the might go a long way in transmission plan I'm wondering if any thoughts around you know some of the things. The I M. M has put out there about fleet assumptions and you see that having any.

No material effect on how things could play out there.

David Hutchens - CEO, Fortis Inc.: Linda?

Linda H. Apsey - CEO, ITC Holdings Corp.: Yeah, of course. Look, I mean, we have great confidence in MISO's expertise, experience and abilities around putting these future scenarios together. I think the futures reflect all of their member utilities, carbon reduction goals, obviously assumptions around electrification and other, how that impacts load demands. As well as FERC has the insight and perspective around the generator interconnection queue and so we remain very confident and comfortable in MISO's scenarios. There are assumptions and we think that MISO is best prepared and equipped to respond to the IMM's issues and concerns and we have comfort and confidence that MISO will continue forward with the futures that they've developed and ultimately continue to work towards the transmission projects. That will comprise the Tranche 2 and we obviously will continue to be optimistic in terms of MISO's ability to continue to push forward.

We have great confidence in MISO has expertise experience and abilities around you know putting these future scenarios together I think the futures reflect you know all of their member utilities, our carbon reduction goals, obviously assumptions around electrification.

<unk> and other how that impacts our low demands.

As well as you know first has the insight and perspective around the generator interconnection queue and so we remain very confident and comfortable M. In MISO is scenarios. There are assumptions and I'm. You know, we think that MISO is best prepare.

Third and equipped.

To respond to the I M EMS issues and concerns and we have comfort and confidence that MISO will continue forward with the you know the futures that they've developed and ultimately continue to work towards the transmission projects.

That will comprise the tranche two and we you know obviously or you will continue to be optimistic in terms of you know my ability to continue to push forward.

David Quezada - VP, Equity Research Analyst, Raymond James: Excellent. Appreciate the color. Thank you, Linda.

Linda H. Apsey - CEO, ITC Holdings Corp.: Yep.

Operator: And your next question comes from the line of Linda Ezergailis from TD Securities. Your line is open.

Linda Ezergailis - Managing Director, Institutional Equities Research, TD Securities: Thank you. Recognizing it's not as impactful to afford us overall at the ITC, but I am curious to hear your views on Alberta and your expectations around your utilities' ability to kind of outperform and overearn under PBR 3.0. And what sort of efficiencies might be further squeezed out realizing you've already likely done a lot on that front?

Curious to hear your views on Alberta, and your expectations around your utilities ability to kind of perform and over earn under P. B R. A 3.0.

And what sort of efficiencies might be further squeezed out realizing you've already likely done a lot on that front.

David Hutchens - CEO, Fortis Inc.: Yeah. That's a great question Linda, thanks. And I'm going to turn that over to Janine Sullivan, our CEO of FortisAlberta to provide some color on the PBR and any other questions you have related to Alberta.

Good morning Linda and thanks for that question. As you know, we've been working through that process to come to this conclusion on PBR 3.0 for some time. And many of the issues that we were contemplating in the process, we were prepared for and filed evidence on so we've been planning for and thinking about how we would adjust or accommodate some of the findings in this decision for some time. And the findings were in keeping with where we kind of expected things to go. I will say that we are kind of reconsidering the capital portion of the decision, where they are premising future funding on historical additions. It really doesn't consider what was approved for 2023, when we will be based under cost of service. And it does include years of course that were impacted by the pandemic. So looking forward, we see a need for additional capital now there are provisions in that plan that allow us to go forward and ask for that capital. So that's that's helpful. But we are thinking about that particular element.

Janine Sullivan - CEO, FortisAlberta: Good morning Linda and thanks for that question. As you know, we've been working through that process to come to this conclusion on PBR 3.0 for some time. And many of the issues that we were contemplating in the process, we were prepared for and filed evidence on so we've been planning for and thinking about how we would adjust or accommodate some of the findings in this decision for some time. And the findings were in keeping with where we kind of expected things to go. I will say that we are kind of reconsidering the capital portion of the decision, where they are premising future funding on historical additions. It really doesn't consider what was approved for 2023, when we will be based under cost of service. And it does include years, of course, that were impacted by the pandemic.

Planning for and thinking about how we would adjust or accommodate some of the findings in this decision for some time.

And they the findings were in keeping with where are we kind of expected things to go I will say that we are kind of considering the capital portion of the decision on where they are promising a future funding on the historical additions.

It really doesn't consider what was approved for 'twenty to 'twenty three we will be based under cost of service.

And it does include years of course that were impacted by the pandemic. So looking forward, we see a need for additional capital now there are provisions in that plan that allow us to go forward and ask for that capital. So that's that's helpful. But we are thinking about that particular element.

So looking forward, we see a need for additional capital. Now there are provisions in that plan that allow us to go forward and ask for that capital. So that's helpful, but we are thinking about that particular element.

With respect to the efficiencies, in particular, there has been a lot of conversation because of the affordability narrative in Alberta about the need for identifying efficiencies for our customers and we're very committed to that. And we continue to evaluate any and all opportunities to deliver those for customers in our day-to-day operations and we'll actually have to report on them to the commission in future periods as part of the PBR plan. So yes, being a third term, it obviously requires us to look deeper into our organization for efficiencies, but that's what we do and we were prepare for that expectation. As I said, given the narrative around affordability and given the discussion in the PBR proceedings.

And our day to day operations and will actually have to report on them to the commission in future periods as part of the PBR plan. So yes, there you know being a third term you know it obviously require us requires us to look deeper into our organization for efficiencies, but that's what we do and we weren't.

Prepare for that expectation as I said, given the narrative around affordability and given the discussion in the PBR proceedings.

Linda Ezergailis - Managing Director, Institutional Equities Research, TD Securities: Thank you. And just as a follow up, bigger picture, you know, the Alberta government's focus on customer affordability--where do you see the levers being most likely in order to achieve that? Like, do you think there's anything really material that can be done on the distribution wire side or transmission wire? Do you see that more coming from other parts of the bill like generation or other components?

Customer affordability, where do you see the leavers being most likely in order to achieve that like do you think there's anything really material that can be done on the like distribution wire side or transmission y or do you see that more coming from other parts of the bill like a generation or other.

Components.

Janine Sullivan - CEO, FortisAlbert: I will share with you that in Alberta right now there is a very detailed process going on, led at the provincial government level around all issues related to bills and they are taking a very fulsome approach to understanding exactly what's driving the affordability concerns. And I will say that, all things are on the table with the government right now. With respect to our distribution in particular, we work with them on opportunities to assist customers in managing the affordability concerns. So things like DSM--demand side management--energy efficiency, programming, which hasn't been clearly defined in Alberta. We believe that as the front-facing customer utility service, we should be the one delivering those types of programs. So we are working with them to advance that type of programming and the role utility plays in that and that's one space in particular, where we think we can assist customers.

<unk>.

And I will say that all things are on the table with the government right now with respect to our distribution in particular are we work with them on.

Opportunities too.

His customers in managing the affordability concerns so things like a D. S M demand side management energy efficiency programming, which hasn't been clearly defined in Alberta, we believe that as the front facing customer utility survey, we should be the one delivering those types of programs. So we are working with them.

To advance that type of programming and the world utility plays in that and that's one space in particular, where we think we can assist customers.

Thank you. Linda I'd I'd add my own I suppose personal opinion I guess is that of all the components of the bills in Alberta. The distribution. One is the last one to focus on from the from the position of cost reduction and efficiencies because that's not the part of the bill that's growing. Or as volatile as the other a couple of parts of the Bill. So that's I think where we're not in the in the Bull's eye on this conversation. Although it is they are casting a wide net to mix a couple of metaphors there for you.

Linda Ezergailis - Managing Director, Institutional Equities Research, TD Securities: Thank you.

Linda, I'd add my own, I suppose, personal opinion I guess--is that of all the components of the bills in Alberta, the distribution one is the last one to focus on from the position of cost reduction and efficiencies because that's not the part of the bill that's growing or as volatile as the other couple of parts of the bill. So, that's I think, where we're not in the in the bull's eye on this conversation. Although it is--they are casting a wide net, to mix a couple of metaphors there for you.

Or as volatile as the other a couple of parts of the Bill. So that's I think where we're not in the in the Bull's eye on this conversation. Although it is they are casting a wide net to mix a couple of metaphors there for you.

Linda Ezergailis - Managing Director, Institutional Equities Research, TD Securities: Thank you.

Yeah.

Operator: Thank you. And once again, if you would like to register a question, please press the star followed by the number 1 on your telephone. Your next question comes from the line of Dariusz Lozny from Bank of America. Your line is open.

Your next question comes from the line of Dar use Logmein from Bank of America. Your line is open.

Yeah.

Dariusz Lozny - Securities Analyst, Bank of America: Hey, good morning. Thanks for taking my question. Just wanted to ask one on Arizona, obviously without wanting to front run the IRP announcement that's coming next week. I just wanted to ask about the prospects for getting concurrent recovery in some form, obviously there was a robust stakeholder process this time around. Certainly some interest there, but it didn't seem like--it seems like there's some opposition there. So curious what learnings you can talk about or maybe perhaps adjusting your strategy on a go-forward basis as you pursue that concurrent recovery. And a related topic, perhaps just how that manifests in your planning for owned generation on a go-forward basis versus PPAs. Thank you.

Certainly some interest there, but it didn't seem like Oh, it seems like there's some opposition there. So curious what learnings you can you can talk about or maybe perhaps.

Adjusting your strategy on a go forward basis as you pursue that concurrent recovery and a related topic, perhaps just how that manifest in.

You're planning for owned generation on a go forward basis versus Ppas. Thank you.

Yeah. Thanks, Dariusz. And there's a couple of data points. The first one is TEP rate case, where we asked for the resource transition mechanism, which is what we called it and got morphed into something called the system reliability benefits adjuster--which is meant to recover some of these investments between rate cases and get a more concurrent recovery and obviously reduce regulatory lag. We did not get that in the TEP case; now we're in the process and ask for the exact same thing and the same name now, in the UNS Electric, a smaller electric utility that we have down in Arizona. And so far, we have got support from staff and others for that. Now that just came  out of the hearing process and we're waiting on a recommended opinion and order that we would expect towards the end of this year, with rates maybe in Q1 of next year. So that will be kind of that next indication of whether or not there's some way for us to look at getting this. If we don't, then there's always the opportunity of looking at a more generic docket to have these conversations and try again in the next rate case. It isn't nearly as urgent for TEP, obviously with the investment tax credits and production tax credits that provide some benefits between rate cases as well and do serve to reduce some of that regulatory lag, that helps for sure. And of course, we can always ask in the next rate case and see how--take the temperature of the commission and other utilities are asking for these same kind of mechanisms as well. And sooner or later, I think we'll get something like this. It's just defining those parameters and seein how that will work going forward.

David Hutchens - CEO, Fortis Inc.: Yeah. Thanks, Dariusz. And there's a couple of data points. The first one is TEP rate case, where we asked for the resource transition mechanism, which is what we called it and got morphed into something called the system reliability benefits adjuster--which is meant to recover some of these investments between rate cases and get a more concurrent recovery and obviously reduce regulatory lag. We did not get that in the TEP case; now we're in the process and ask for the exact same thing and the same name now, in the UNS Electric, a smaller electric utility that we have down in Arizona. And so far, we have got support from staff and others for that. Now that just came out of the hearing process and we're waiting on a recommended opinion and order that we would expect towards the end of this year, with rates maybe in Q1 of next year.

And obviously reduce regulatory lag we did not get that in the T. P case now we're in the process and ask for the exact same thing and the same name, though and the U S electric a smaller electric utility that we have down in Arizona and so far we have got support from from staff and others for that now that just K.

Out of the hearing process and we're waiting on a recommended opinion and order that we would expect towards the end of this year with rates maybe in Q1 of next year. So that will be kind of that next indication of whether or not there's some way for us to look at getting this if if if if we don't then there's always the opportunity of looking at a a more.

So that will be kind of that next indication of whether or not there's some way for us to look at getting this. If we don't, then there's always the opportunity of looking at a more generic docket to have these conversations and try again in the next rate case. It isn't nearly as urgent for TEP, obviously with the investment tax credits and production tax credits that provide some benefits between rate cases as well and do serve to reduce some of that regulatory lag, that helps for sure. And of course, we can always ask in the next rate case and see how--take the temperature of the commission and other utilities are asking for these same kind of mechanisms as well. And sooner or later, I think we'll get something like this. It's just defining those parameters and seein how that will work going forward.

Generic <unk>.

Docket to have these conversations and try again in the next rate case, it isn't nearly as urgent for TEP, obviously with the investment tax credits and production tax credits that provide some benefits between rate cases, as well and do serve to reduce some of that regulatory lag that that that helps for sure.

And of course, we can always ask in the next rate case in C O.

Yeah, I'll take the temperature of the commission and other utilities are asking for these same kind of mechanisms as well and sooner or later I think we'll get something like this it's just defining those parameters and see.

And how that will work going forward.

Dariusz Lozny - Securities Analyst, Bank of America: Okay, great. Thank you very much, appreciate it.

Operator: Thank you. And there are no further questions at this time. I would like to turn it back to Ms. Amaimo.

Stephanie Amaimo - Head of IR, Fortis Inc.: Thank you, Ludy. We have nothing further at this time. Thank you everyone for participating in our third quarter 2023 results conference call. Please contact Investor Relations should you need anything further. Thank you for your time and have a great day.

Please contact Investor Relations should you need anything further thank you for your time and have a great day.

Operator: Thank you Ms. Amaimo. And this concludes today's conference call. Thank you for participating, you may now disconnect.

Okay.