Q4 2023 Fortis Inc Earnings Call

Good morning, everyone. Thank you for standing by my name is Laura and I will be your conference operator today welcome to Ford F Q4, 'twenty 'twenty 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.

Operator: Good morning, everyone. Thank you for standing by. My name is Layla, and I will be your conference operator today. Welcome to Fortis's Q4 2023 earnings conference call and webcast. During the call, all participants will be in a listen-only mode.

Operator: There will be a question-and-answer session following the presentation. At that time, those with questions should press a star followed by one on their telethons. 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 Amaymo. Please go ahead, Ms. Amaymo.

The presentation at that time that was the question should press star followed by one on the 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 a mine mouth. Please go ahead, Mr. My mouth.

Stephanie Amaymo: Thanks, Laura, and good morning, everyone. Welcome to Fortis' fourth quarter and annual 2023 results conference call. I am joined by David Hutchins, 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 slideshow. Actual results can differ materially from the forecast projections included in the forward-looking information presented today.

Thanks, Laura and good morning, everyone welcome to afford us this fourth quarter and annual 23 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 are non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U S. GAAP.

Stephanie Amaymo: All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our annual 2023 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.

Natural measures and our annual 2023 M. DNA 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.

David Hutchins: Today, we are pleased to report strong 2023 operational and financial results. During the year, we provided reliable service to our customers, invested $4.3 billion of capital in our energy systems, concluded key regulatory applications, sold the non-regulated Aitken Creek natural gas storage facility, and further reduced our carbon emissions. Adjusted EPS grew approximately 9 percent, excluding foreign exchange impacts, with interest rate growth and the regulatory outcomes in British Columbia and Arizona serving as key drivers.

Today, we are pleased to report strong 2023 operational and financial results. During the year, we provided reliable service to our customers invested $4 3 billion of capital and our energy systems concluded key regulatory applications sold the Nonregulated Aitken Creek natural gas storage facility.

And further reduced our carbon emissions.

Adjusted EPS grew approximately 9%, excluding foreign exchange impacts with rate growth and the regulatory outcomes in British Columbia, and Arizona, serving as key drivers.

David Hutchins: And with our track record of executing a regulated growth strategy, we increased our fourth-quarter dividend by 4.4%, marking 50 consecutive years of increases in dividends paid, a milestone of which we are very proud. Our utilities operate electric and natural gas transmission and distribution systems across North America, and we know that the safety and reliability of the service we provide is imperative to our customers and employees and is embedded in everything we do. In 2023, our metrics were in the top quartile for safety and reliability relative to our North American peer benchmark.

And with our track record of executing our regulated growth strategy, we increased our fourth quarter dividend by 4.4%, marking 50 consecutive years of increases in dividends paid.

Stone of which we are very proud of.

Our utilities operate electric and natural gas transmission and distribution systems across North America, and we know that the safety and reliability of the service. We provide is imperative to our customers and employees and is embedded in everything we do.

In 2023, our metrics were top quartile for safety and reliability relative to our North American peer benchmarks.

As we make the necessary investments in our utilities, we remain focused on managing customer bill impacts, while we have limited control of energy commodity costs and higher interest rates, both of which are pass through to our customers. We continue to manage operating costs through efficiencies innovation and process improvements.

David Hutchins: As we make the necessary investments in our utilities, we remain focused on managing customer bill impacts. While we have limited control of energy commodity costs and higher interest rates, both of which are passed through to our customers, we continue to manage operating costs through efficiency, innovation, and process improvement. We also work with our customers to help them manage their bills through our Energy Efficiency and Demand-Side Management, or DSM, program.

We also work with our customers to help them manage their bills through our energy efficiency and demand side management or D. S M programs.

David Hutchins: Just last week, the British Columbia Utilities Commission awarded Fortis Inc.'s $600 million DSM plan for 2024 through 2027. The plan continues cost-effective initiatives for customers to save on energy use while incorporating new programs to further align with the Clean DC Roadmap to 2030. Customer affordability is critical as we execute our clean energy goals and invest in the resiliency of our energy system. We continue our track record of dependable shareholder returns despite a challenging year for the utility sector. In 2023, we delivered an annual total shareholder return that ranked in the top quartile of our utility peer group. Additionally, over a 20-year period, we have had an average annual return of approximately 11%, significantly higher than the returns generated by the benchmark index. Through 2023, we achieved a 33% reduction in scope on emissions compared to 2019 levels. The closure of the coal-fired Sandstone Generating Station in June 2022, as well as the start of seasonal operations of the Springerville units in 2023, contributed to the emissions reduction.

Just last week, the British Columbia Utilities Commission.

Florida, B C 600 million DSM plan for 'twenty 'twenty four through 2027.

And continuous cost effective initiatives for customers to save on energy use while incorporating new programs to further align with the clean B C roadmap to 2030.

Customer affordability is critical as we execute our clean energy goals and invest in the resiliency of our energy systems.

Okay.

We continued our track record of dependable shareholder returns despite a challenging year for the utility sector. In 2023, we delivered an annual total shareholder return that ranked in the top quartile of our utility peer group.

Over a 20 year period, we have had an average annual return of approximately 11% significantly higher than the returns generated by the benchmark indices.

Through 2023, we achieved a 33% reduction in scope, one emissions compared to 2019 levels the.

The closure of the coal fired San Juan generating station in June 2022, as well as the start of seasonal operations of the springerville units in 2020 three contributed to the emissions reductions.

David Hutchins: With this continued progress, we are on track to achieve our target to reduce Scope 1 greenhouse gas emissions 50% by 2030, 75% by 2035, and net zero by 2050. While all of our utilities play a part in reducing carbon emissions, the bulk of the reductions will be achieved through the execution of TEP's integrated resource plan. In November, both TEP and UNS Electric filed their 2023 IRPs with the Arizona Corporation Commission. TEP's IRP calls for the addition of over 2,200 megawatts of renewable generation, over 1,300 megawatts of energy storage, and 400 megawatts of natural gas peaking units through 2038 and supports the closure of TEP's remaining 900 megawatts of coal-fired generation by 2032. This balanced portfolio supports the delivery of cleaner, reliable, and affordable energy for our customers.

With this continued progress we are on track to achieve our targets to reduce scope one greenhouse gas emissions, 50% by 'twenty 30, 75% by 2035 and net zero by 2050.

Well all of our utilities play a part in reducing carbon emissions. The bulk of the reductions will be achieved through the execution of Tep's integrated resource plan and new.

November bolt T P and U S electric filed their 2023 IR piece with the Arizona Corporation Commission G. P's AARP calls for the addition of over 2200 megawatts of renewable generation over 3500 megawatts of energy storage and four megawatts of natural gas, peaking units.

Through 2038 and supports the closure of TPS remaining 900 megawatts of coal fired generation by 2032.

This balanced portfolio supports the delivery of cleaner reliable and affordable energy for our customers the new natural gas capacity will accelerate renewable energy additions and will support TEP using less coal generation through 2032 further reducing cumulative scope one emissions.

David Hutchins: The new natural gas capacity will accelerate renewable energy additions and will support TEP using less coal generation through 2032, further reducing cumulative Scope 1 emissions. In December, T&P and UNS Electric issued a joint all-source request for proposals seeking new resources in support of the IRP. The RFP calls for over 600 megawatts of renewable energy and energy efficiency resources and over 800 megawatts of firm capacity.

In December TEP, and <unk> electric issued a joint all source request for proposals seeking new source new resources in support of the IR piece.

The RFP calls for over 600 megawatts of renewables and energy efficiency resources and over 800 megawatts of firm capacity.

As for the next steps on the IR piece, we expect a decision from the N C C in the fall.

David Hutchins: As for the next steps on the IRPs, we expect a decision from the NCC in the fall. Looking ahead, we expect to release our climate report during the first quarter of 2024, showcasing the climate scenario work completed by our utilities over the past two years to ensure we are building climate resiliency into our operations. In the third quarter, we announced our highly executable, low-risk, $25 billion five-year capital plan, our largest to date. In the fourth quarter, as part of the Iowa Right of First Refusal proceeding, a district court placed an injunction on MISO's long-range transmission project in Iowa.

Looking ahead, we expect to release our climate report during the first quarter of 'twenty 'twenty four showcasing the climate scenario work completed by our utilities over the past two years to ensure we are building climate resiliency into our operations.

In the third quarter, we announced our highly executable low risk $25 billion five year capital plan, our largest to date.

In the fourth quarter as part of the aisle right of first refusal proceeding a district court placed an injunction on MISO is long range transmission projects in Iowa.

As a result, Itc's tranche one projects located in Iowa are currently on hold Jocelyn will speak to this in more detail on the regulatory update.

In late December the BC UC denied Florida species application for the OCA noggin capacity upgrade our smallest major capital project estimated at approximately $200 million.

David Hutchins: As a result, ITC's TRONS1 project located in Iowa is currently on hold. Jocelyn will speak to this in more detail in the regulatory update. In late December, the BCUC denied FortisBC's application for the Okanagan Capacity Upgrades, our smallest major capital project, estimated at approximately $200 million. While the BCUC agreed with the need to address pipeline capacity shortfalls in the Okanagan region, they instructed FortisBC to investigate other options to meet capacity needs and submit a plan by the end of July. FortisBC's investment in the Eagle Mountain Wood Fiber Gas Line project is now forecasted at $750 million through 2027, compared to $420 million previously estimated. The increase was a result of amendments made to agreements with Wood Fiber, LNG, and other partners that became effective following the completion of certain conditions, including the BCUC approval of an amended transportation rate schedule. This allows for an increase in our rate base without increasing customer rates. Our five-year capital plan of $25 billion remains on track, supporting average annual rate-based growth of approximately 6 percent.

While the BCC agreed with the need to address by pipeline capacity shortfalls in Okinawa in region. They instructed Florida SBC to investigate other options to meet capacity needs and submit a plan by the end of July.

Florida species investment and the Eagle Mountain Wood fiber gas line project is now forecasted at $750 million through 2027.

Compared to 420 million previously estimated the increase was a result of amendments made to agreements with wood fiber LNG and other partners that became effective following the completion of certain conditions, including the BCC approval of an amended transportation rates schedule. This allows for an increase in our rate base without.

Increasing customer rates.

Our five year capital plan of 25 billion remains on track supporting average annual rate base growth of approximately 6%.

Our next five year plan is in progress and we expect to release it in the fall.

The plan, we continue to pursue additional opportunities ITC continues to work with MISO on tranche two of the long range transmission plan and we expect MISO board approval in the second half of this year.

And Nicholson, we estimate between two and a half and $5 billion of incremental investments through 2010, yet at TEP and <unk> electric to support their <unk>.

David Hutchins: Our next five-year plan is in progress, and we expect to release it in the fall. In conjunction with that plan, ITC continues to work with MISO on tranche two of the long-range transmission plan, and we expect MISO board approval in the second half of this year.

We also anticipate growth opportunities associated with renewable natural gas solutions and the LNG infrastructure in British Columbia.

Across all of our utilities, we expect additional growth opportunities to support climate adaptation.

Good resiliency in the clean energy transition.

As mentioned earlier, we increased our common share dividend in the fourth quarter by four 4%, marking 50 consecutive years of increases in dividends paid in 2023, we also extended our 4% to 6% annual dividend growth guidance through 2028 supported by our low risk regulated growth profile.

David Hutchins: In addition, we estimate between $2.5 and $5 billion U.S. dollars of incremental investment through 2020 at TC and UNF elections to support their IOPs. We also anticipate growth opportunities associated with renewable natural gas solutions and LNG infrastructure in British Columbia. Across all of the utilities, we expect additional growth opportunities to support climate adaptation. Grid Resiliency and the Clean Energy Trend

Now I will turn the call over to Johnson for an update on our fourth quarter and annual financial results.

Thank you David and good morning, everyone before I get into the results I want to point out that we are now reporting the former energy infrastructure segment, which included Aitken Creek and Florida's Billy's within the corporate and other segment with the sale of Aitken Creek in the fourth quarter. We will report Fortis believes in this segment going forward.

Reported earnings per common share for the fourth quarter of 'twenty to 'twenty, three where 78 cents once that's higher than reported in the fourth quarter of the prior year <unk>.

Jocelyn Perry: As mentioned earlier, we increased our common share dividend in the fourth quarter by 4.4%, marking 50 consecutive years of increases in dividends paid. In 2023, we also extended our 4 to 6% annual dividend growth guidance through 2028, supported by our low-risk regulated growth profile. Now, I will turn the call over to Joplin for an update on our fourth quarter and annual financial results. Thank you, David, and good morning, everyone.

Adjusted EPS for the fourth quarter of 2023 was 72.

Consistent with the fourth quarter of 2022.

Results for the quarter were in line with expectations and reflect the timing of adjustments related to Aitken Creek as we stated on the last earnings call Aitken Creek had an effective sale date of March 31, and with the transaction now closed as of November 1st we have excluded adjusted earnings of 24.

Or approximately <unk> <unk> per common share initially recorded in the second and third quarters of 2023.

Jocelyn Perry: Before I get into the results, I want to point out that we are now reporting the former energy infrastructure segment, which included Aspen Creek and Fortis Belize within the corporate and others segment. With the sale of Aspen Creek in the fourth quarter, we will report Fortis Belize in this segment going forward. Reported earnings per common share for the fourth quarter of 2023 were $0.78, one cent higher than reported in the fourth quarter of the prior year.

The remaining EPS decrease for the corporate and other segment reflects lower earnings at Aitken Creek, driven by the timing of the disposition and higher margins recognized in the fourth quarter of 2022.

At our regulated utilities, the nine cent increase in EPS quarter over quarter was driven by rate base growth higher retail revenue in Arizona associated with new customer rates at TEP and the new cost of capital parameters at Fortis BC.

Jocelyn Perry: Adjusted EPS for the fourth quarter of 2023 was $0.72, consistent with the fourth quarter of 2022. Results for the quarter were in line with expectations and reflect the timing of adjustments related to Aitkin Creek. As we stated on the last earnings call, Aitkin Creek had an effective sale date of March 31st, and with the transaction now closed as of November 1st, we have excluded adjusted earnings of 24 million, or approximately 5 cents per common share, initially recorded in the second and third quarters of 2023. The remaining EPS decrease for the corporate and other segment reflects lower earnings at Aitkin Creek, driven by the timing of the disposition, and higher margin At our regulated utilities, the $0.09 increase in EPS quarter over quarter was driven by rate-based growth, higher retail revenue in Arizona associated with new customer rates at TEP, and the new cost of capital parameters at Fortis BC. As David mentioned, we delivered strong EPS growth in 2023. The reported EPS was $3.10, 32 cents higher than 2022.

As David mentioned, we delivered strong EPS growth in 2023.

Ported EPS was $3 10, 32 cents higher than 2022.

Adjusted EPS was $3.09, reflecting 9% growth over 2022.

Our western Canadian utilities contributed an 18% EPS increase 10 cents of which related to the new cost of capital parameters approved by the BC UC in September 2023 rate base growth also contributed to the increase.

For our regulated U S and electric and gas utilities, almost half of the 12% EPS increase was driven by new rates at T. P effective September 1st.

Higher retail sales associated with warmer weather and customer growth and 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.

Our largest utility ITC increased EPS by six cents, reflecting 6% year over year earnings growth strong rate base growth and an increase in the market value of investments that support retirement benefits was tempered by higher non recoverable finance costs.

At our other electric segment rate base growth higher sales and equity income from the watch any kidney at project contributed to that increase in EPS for.

Jocelyn Perry: Adjusted EPS was $3.09, reflecting 9% growth over 2020. Our Western Canadian utilities contributed an 18-cent EPS increase, 10 cents of which related to the new CASA capital parameter approved by the DCUC in September 2023. Rate-based growth also contributed to the increase.

For the corporate and other segment. This decrease mainly reflects higher holding company finance costs as well as three cents related to lower hydroelectric generation in believes and lower earnings at Aitken Creek.

For 2024, we do expect the sale of Aitken Creek to be neutral to EPS.

And lastly, the favorable impact of a higher average U S to Canadian dollar foreign exchange rate was partially offset by higher weighted shares outstanding issued under our dividend reinvestment plan.

Jocelyn Perry: For our regulated U.S. and electric and gas utilities, almost half of the 12% EPS increase was driven by new rates at TEP effective September 1st. Higher retail sales associated with warmer weather and customer growth, 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. Our largest utility, IPC, increased EPS by 6 cents, reflecting 6% year-over-year earnings growth.

All in all a very strong growth year across our portfolio of regulated utilities.

Looking back Fortis has delivered rate base growth of six 5% and adjusted EPS growth of approximately 6% on average annually over the past three years.

In 2023, we issued approximately 3 billion of debt to refinance maturing debt and to fund our capital program our.

Our primary earnings exposure to elevated interest rates pertains to holding company debt as a regulated utility is ultimately recover changes in interest rates through regulatory mechanisms and periodic re basing of customer rates.

Jocelyn Perry: Strong rate-based growth and an increase in the market value of investments that support retirement benefits were tempered by higher non-recoverable finance. At a rather electric segment rate-based growth, higher sales and equity income from the Watanakiniyaq project contributed a two-cent increase in EPS. For the corporate and others segment, this decrease mainly reflects higher holding company finance costs as well as 3 cents related to lower hydroelectric generation in Belize and lower earnings at a concrete plant.

In the upcoming year, we have approximately 600 million U S dollars of nonregulated debt coming due with the maturity at ITC holdings, largely pre funded in 2023.

We also have $250 million of preference shares with dividend rate resets in early 'twenty 'twenty, four and $600 million in December 2024, well continue to monitor the debt capital markets and consider interest rate hedges and additional pre funding opportunities.

With proceeds from our debt issuances and the sale of Aitken Creek as well as well as over 4 billion available on our credit facilities, we remain in a strong liquidity position to execute our $25 billion capital plan.

Jocelyn Perry: For 2024, we do expect the sale of Aitkin Creek to be neutral to ECF. And lastly, the favorable impact of a higher average U.S. to Canadian dollar foreign exchange rate was partially offset by higher-weighted shares outstanding issued under our Dividend Reinvestment Plan. All in all, a very strong growth year across our portfolio of regulated utilities. Looking back, Fortis has delivered rate-based growth of 6.5% and adjusted EPS growth of approximately 6% on average annually over the past three years. In 2023, we issued approximately $3 billion of debt to refinance maturing debt and to fund our capital program.

As we outlined at Investor day, the majority of our capital plan is expected to be funded from cash from operations and debt issued at our regulated utilities equity funding is expected from our drip program with a $500 million ATM program available for additional funding flexibility if required to date we have.

Not raised any equity under the ATM program.

We achieved a moody's cash flow to debt ratio of 11, 6% and then S&P <unk> to debt ratio of 11, 4% in 2023, both coming in stronger than our forecast outline at Investor day.

Our S&P metric was below our new threshold of 12%, which S&P raised from 10, 5% in November.

Jocelyn Perry: Our primary earnings exposure to elevated interest rates pertains to holding company debt as our regulated utilities ultimately recover changes in interest rates through regulatory mechanisms and periodic rebasing of customer rates. In the upcoming year, we have approximately $600 million of non-regulated debt coming due, with the maturity at ITC holdings largely pre-funded in 2025. We also have $250 million of preference shares with dividend rate resets in early 2024 and $600 million in December 2024. We'll continue to monitor the debt capital markets and consider interest rate hedges and additional pre-funding opportunities. With proceeds from our debt issuances and the sale of Aitkin Creek, as well as over $4 billion available on our credit facilities, we remain in a strong liquidity position to execute our $25 billion capital plan.

<unk> also revised its outlook on our issuer rating to negative, citing rising physical risks due to climate change including wildfires.

We were surprised by S&P's report, we have a strong track record of managing climate risks, including wildfires and other climate events and they have not had a significant impact on our operations and financial results to date.

<unk> also benefits from constructive regulatory jurisdictions and legal environments over.

Over the next year, we will continue to engage with S&P on this matter.

We do not expect to also our funding plan, which remains on track to achieve average annual cash flow to debt metrics of approximately 12% over the next five years.

As David mentioned earlier in December the Iowa District Court ruled that the Iowa role for legislation was unconstitutional and procedural grounds. The district Court also granted a broad injunction on the road for legislation preventing additional actions on the tranche one projects in Iowa that were previously awarded.

To ITC Midwest by MISO in July 2022.

Jocelyn Perry: As we outlined at InVEST today, the majority of our capital plan is expected to be funded from cash from operations and debt issued at our regulated utilities. Equity funding is expected from our GRIT program, with a $500 million ATM program available for additional funding flexibility, if required. To date, we have not raised any equity under the ATM program.

ITC has filed a motion for reconsideration with the district Court.

While the timing and outcome of the proceeding remains unknown ITC will continue to aggressively pursue the new ROE for Bill in Iowa.

It's important to highlight that the district court ruled on the manner in which the Iowa broker was passed and not on the merits of the broker.

Further and importantly, MISO is the only entity charged with determining what projects are to be competitively bid pursuant to its tariffs.

Jocelyn Perry: We achieved a Moody's cash flow-to-debt ratio of 11.6% and an S&P FFO-to-debt ratio of 11.4% in 2023, both coming in stronger than our forecast outlined at InvestorDay. However, our S&P metric was below our new threshold of 12%, which S&P raised from 10.5% in November. S&P also revised its outlook on our issuer rating to negative, citing rising physical risks due to climate change, including wildfires. We were surprised by S&P's report.

Also approximately 70% of the tranche tranche one projects are upgrades to ITC Midwest facilities, along existing rights of way, which under MISO tariff grants ITC Midwest the option to construct the upgrades regardless of the outcome of the road for legislation.

And Furthermore.

For any portion of the first tranche of the MISO LRT pre projects to be competitively bid. We believe it would require a federal decision that significantly departs from existing rules under the MISO tariff.

Last month, the ACC issued its decision on Unf's Electric's general rate application approving among other things a 9.75% allowed return on equity and a 54% common equity layer the new rates became effective on February one.

Jocelyn Perry: We have a strong track record of managing climate risk, including wildfires and other climate events, and they have not had a significant impact on our operations and financial results to date. Fortis also benefits from constructive regulatory jurisdictions and legal environments. Over the next year, we will continue to engage with S&P on this matter. However, we do not expect to alter our funding plan, which remains on track to achieve average annual cash flow-to-debt metrics of approximately 12 percent over the next five years. As David mentioned earlier, in December, the Iowa District Court ruled that the Iowa role for legislation was unconstitutional on procedural grounds.

The ACC also approved a system reliability benefit or SRP mechanism. ESRB allows you want us electric to recover generation investments between rate cases subject to an annual cap and earnings test. The SRV is expected to reduce volatility in customer rates and the frequency of future rate cases.

With regards to our regulatory calendar for 2020 form the general rate application at Central Hudson remains ongoing as.

As the current three year plan ends on June 30th.

The New York Service Commission staff and Intervenor testimony was filed in November with staff recommending a one year rate increase including a nine 2% allowed ROE and 48% equity thickness. This litigated proceeding remains on track.

Jocelyn Perry: The District Court also granted a broad injunction on the role of legislation, preventing additional actions on the Trots 1 project in Iowa that were previously awarded to ITC Midwest by MISO in July 2022. IPC has filed a motion for reconsideration with the district court. While the timing and outcome of the proceeding remains unknown, IPC will continue to aggressively pursue the new Rolls-Royce bill in Iowa. It's important to highlight that the district court ruled on the manner in which the Iowa ROFA was passed and not on the merits of the ROFA. Furthermore, and importantly, MISU is the only entity charged with determining what projects are to be competitively bid pursuant to its tariffs.

At Fortis, we see the current multi year rate plan concludes at the end of 2024 and an application for the next plan is expected to be filed with the BC you see in the first half of 2024.

In Alberta, the formulaic allowed ROE was set at 9.28% for 2024 and will be reset annually in the fourth quarter.

Lastly, there are no new updates to report on the outstanding for MISO base, Roe or notebooks and transmission incentives at ITC.

Overall, we expect a lighter regulatory year as compared to 2023.

And with that I'll now turn the call back to David.

Jocelyn Perry: Also, approximately 70% of the Trans1 projects are upgrades to ITC Midwest facilities along existing rightways, which under Michael's tariff grants ITC Midwest the option to construct the upgrades regardless of the outcome of the ROPA legislation. Furthermore, for any portion of the first tranche of the MISO LRT3 project to be competitively bid, we believe it would require a federal decision that significantly departs from existing rules under the MISO tariff. Last month, the ACC issued a decision on U.N.S. Electric's general rate application, approving, among other things, a 9.75% allowed return on equity and a 54% common equity layer. The new rates became effective on February 1st.

We are pleased with our accomplishments in 2023 and we appreciate the contributions of every employee who helped to make last year. A success. We recognize that it's no small task to keep each other safe deliver reliable service to the customers invest over $4 billion of capital obtained key regulatory outcomes.

And deliver solid financial results for 2024 and beyond we are focused on executing our regulated growth strategy to ensure we continue our operational and financial track record for the benefit of our customers and shareholders that concludes my remarks, I will now turn the call back over to Stephanie.

Thank you David This concludes the presentation at this time I would like to open the call to address questions from the investment community.

Thank you.

We will now conduct a question and answer period.

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Jocelyn Perry: The ACC also approved the System Reliability Benefit, or SRB, mechanism. The SRB allows UNS Electric to recover generation investments between rate cases subject to an annual cap and earnings test. The SRB is expected to reduce volatility in customer rates and the frequency of future rate cases. With regard to our regulatory calendar for 2024, the general rate application at Central Hudson remains ongoing as the current three-year plan ends on June 30th. The New York Service Commission staff and intervener's testimony was filed in November, with staff recommending a one-year rate increase, including a 9.2% allowed ROE and 48% equity fix. This litigated proceeding remains on track.

Kindly request you speak loudly I'm slowly to ensure all participants can hear your questions. One moment. Please for your first question.

Our first question comes from the line of movies Choi from RBC capital markets. Please go ahead.

Thank you and good morning, everyone I wanted to follow up on your comments on the funding plan.

Richard do you mentioned that you do not expect to alter back at the Investor Day.

Getting to 12% would've meant you had about 100 to 150 basis points of cushion versus your downgrade thresholds.

That cushion, that's obviously effectively wiped out S&P when it moved the goalposts are what are some of the push it takes on keeping the 12%.

Jocelyn Perry: At FortisBC, the current multi-year rate plan concludes at the end of 2024, and an application for the next plan is expected to be filed with the BCUC in the first half of 2024. In Alberta, the formulaic allowed ROE was set at 9.28% for 2024 and will be reset annually in the fourth quarter. Lastly, there are no new updates to report on the outstanding mycobase ROE or NOFRS on transmission incentives at I

Target and.

Any proactive actions, you're considering to restore to cushion if the.

It is important to you.

Hi, Maurice this is jocelyn yeah, that's a good question.

Clearly that was a big jump in the threshold to go from 10 five to 12, so you're right. We've made we've eliminated the cushion, but we do have a plan.

That saves us get getting to on average 12% over the five years and obviously getting above that 12, we're gonna be laser focus on this of course and as we go through the year I mean, we're always looking at our cash flows and then we're also getting you know confirmations around certain tax rules and we thought first.

Stephanie Amaymo: Overall, we expect a lighter regulatory year as compared to 2023. And with that, I'll now turn the call back to David. We are pleased with our accomplishments in 2023, and we appreciate the contributions of every employee who helped to make last year a success. We recognize that it's no small task to keep each other safe, deliver reliable services to customers, invest over $4 billion in capital, obtain key regulatory outcomes, and deliver solid financial results. For 2024 and beyond, we are focused on executing our regulated growth strategy to ensure we continue our operational and financial track record for the benefit of our customers and shareholders. That concludes my remarks. I will now turn the call back over to Stephanie.

The minimum tax was going to impact US now it's not so that that gives us a little bit of a room.

To push our metrics forward, but yeah, well continue to push forward with our cash flows refine them as we go out through the year, we do have the ATM available to us even though right now I don't have any firm plans to use that ATM.

Great. Thanks, and just a follow up on that as you look out through 'twenty three and four are there any.

Events are items that we should look out for that might motivate you to want to restore the Christian.

I think Maurice I mean, we're going to continue to have conversations with the S&P. Clearly you know we want to set ourselves up to rebuild that cushion, but again. This was a surprise we will continue to have further conversations with S&P about the nature of their concerns.

Round wildfire risk and climate risk and just understand the goalpost a little better but the aim is to certainly meet the threshold and and just start building back that question, but I don't see.

Operator: 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. We will now conduct the question and answer period. If you would like to submit a question, please press the star followed by the number on your telephone. If your question has been answered and you would like to advise your registration, please press the pound sign. If you are using a speakerphone, please lift your hands up before entering your request.

Any other event that although then speaking with S&P throughout the year, just trying to fully understand the nature of the negative outlook.

Got it. Thank you and my follow up question is on Arizona in terms of fee.

Potential repeal of the state's renewable energy standard in tariff.

<unk>, obviously does have a new RFP that was filed.

What does the repealing the R. S. T mean in terms of TPS decarbonization growth plans.

Yeah, Yeah I'm already so this is Dave thanks for that question. It doesn't mean anything because we've already exceeded the renewable portfolio standard it was only 15.

Maurice Choi: And we kindly request you speak loudly and slowly to ensure all participants can hear your question. One moment, please, for your first question. Our first question comes from Maurice Choi from RBC Capital Markets. Please go ahead. Thank you, and good morning everyone.

15% requirement, which we have surpassed already.

Obviously the cost recovery of.

Maurice Choi: I wanted to follow up on your comments on the funding plan, which you do mention that you do not expect to alter. That's to be investigated. Getting to 12% would have meant you had about 100 to 150 basis points of cushion versus your downgrade threshold.

Historical items from that will continue to be able to continue to make sure that we get those through the normal regulatory processes.

But overall the goal isn't it doesn't really have any impact on us if youll remember a couple of years ago. There was quite a lengthy debate as to whether or not the Arizona was going to adopt some more aggressive goals, even all the way to net zero goals, but that never did happens that the.

Jocelyn Perry: That cushion is obviously effectively wiped out at S&P when it moved to the goalposts. What are some of the push-and-takes on sweeping the 12% target? Any proactive actions you're considering to restore the Christian faith, if the Christian faith is important to you? Hi, Maurice. This is Jocelyn.

The renewable portfolio standard is is a bit out of date I think there isn't probably any utility at least any of the big ones that are having already met the 20.

Jocelyn Perry: Yeah, that's a good question. Clearly, that was a big jump in the threshold to go from 10.5 to 12. So you're right, we've eliminated the cushion. But we do have a plan that sees us getting to an average of 12% over the five years and, obviously, getting above that 12. We're going to be laser focused on this, of course. And as we go through the year, I mean, we're always, you know, looking at our cash flows.

The 2025 requirements.

Perfect. Thank you.

Our next question comes from the line of Rob Hope from Scotiabank. Please go ahead.

Good morning, everyone.

I wanted to circle back on the Oakland Ogden decision. So maybe looking forward how do you work with the regulator, whether it's in D C or other jurisdictions, especially on the natural gas side such that.

Your views of demand growth.

Lineup with how the regulator is seeing the world so that.

Jocelyn Perry: And we're also getting, you know, confirmations around certain tax rules. And at first, we thought that the minimum tax was going to impact us. Now it's not.

For example, do you think you need to get this pipeline to serve demand if they think that demand maybe not necessarily show up there. So how do you how do you bridge that gap moving forward.

So that's a that's a great question Robin we've got a couple of different jurisdictions that we see this end and in Arizona, We actually don't have this conversation really hasn't been a pushback on.

Jocelyn Perry: So that gives us a little bit of room to push our metrics forward. But we'll continue to push forward with our cash flows, and refine them as we go out through the year. We do have the ATM available to us, even though right now, I don't have any firm plans to use that ATM.

On the natural gas infrastructure or demand.

Going forward basis, I'm going to kick it over to.

Jocelyn Perry: Thanks, and just to follow up on that, if you look out through 2024, are there any events or items that we should look out for that might motivate you to want to restore the fission? I think, Maurice, I mean, we're going to continue to have conversations with S&P. Clearly, you know, we want to set ourselves up to rebuild that cushion, but again, this was a surprise.

To to Roger down until any other seal for SBC to talk a little bit about D. C. And then you can spring back and I can talk a little bit about New York as well.

Thanks, David Thanks, Rob, maybe I'll start a little bit with the OCC decision itself.

Disappointed of course that it was denied we'd put quite a bit of work into that that application I think there's three things that come out of the decision that are that's important to understand the first is the commission does see the need for capacity upgrades, so they're not denying.

Jocelyn Perry: We'll continue to have further conversations with S&P about the nature of their concerns around wildfire risk and climate risk and just understand the goalposts a little better. But, you know, the aim is certainly to meet the threshold and start building back that cushion. But I don't see any other event other than speaking with S&P throughout the year, just trying to fully understand, you know, the nature of the negative outlook. All right.

Are the basis for it the second is they've why they've denied that they have directed us to come back with the mitigation plans. So they are expecting us to provide some solution, which we will do.

The third issue and really the heart of your question is what's changed that they're not accepting our load forecast and I think when you look at their reasoning, it's really not so much that they don't think we have a role from a point of view of a commission regulated natural gas it's more of that.

Jocelyn Perry: Thank you. And my final question is on Arizona in terms of the potential repeal of the state's Renewable Energy Standard and Tariff. TEP obviously does have a new IRP that was filed. What does the repeal of the REST mean in terms of TEP's decarbonization growth plan? Yeah, Maurice. This is Dave.

With the policy direction that D. C is going with clean D C.

Significant uncertainty right now on.

How it is D C need some.

Really aggressive emissions targets, what does that mean for solutions out or 56 years life like the Ocu pipeline upgrade relative to what the long term forecast is versus the near term.

David Hutchins: Thanks for that question. It doesn't mean anything because we've already exceeded the Renewable Portfolio Standard. It was only a 15% requirement, which we have exceeded already. Obviously, the cost recovery of historical items from that will continue to make sure that we get those through the normal regulatory processes. But overall, the goal doesn't really have any impact on us.

Passey shortfall.

So it's for US it's really a.

I can comment that we demonstrate.

A variety of scenarios, where we think the capacity.

Issue may not be resolved over the long term how do you do that I think what we've always done in the past is looked at load growth.

David Hutchins: If you'll remember, a couple of years ago, there was quite a lengthy debate as to whether or not Arizona was going to adopt some more aggressive goals, even all the way to net zero goals, but that never did happen. The Renewable Portfolio Standard is a bit out of date. I think there isn't probably any utility, at least any of the big ones, that haven't already met the 2025 requirement.

With the contingency factor looking at.

On the upside making sure that you are never short I think what commissions are looking at when Theres policy uncertainty is really give you more around.

A variety of scenarios.

And what is the ability to scale up in your your asset mix. So you're not building the largest program the largest facility, but is there a way to mitigate with near term solutions, but also expand if load growth.

Proves to be higher than they were expecting so I think it's going to be a change in how we approach.

Robert Hope: Thank you. Our next question comes from the line of Rob Hope from Scotiabank. Please go ahead. Good morning, everyone.

The load forecasting over the next number of applications.

How do we get some certainty around how clean.

Clean D C. In our instance goes from policy into specific regulations, so more to come on that for sure.

Robert Hope: I want to circle back on the Okanagan decision. So, maybe looking forward, you know, how do you work with a regulator, whether it's in D.C. or other jurisdictions, especially on the natural gas side, such that your views of demand growth line up with how the regulator is seeing the world? So, for example, you think you need to get this pipeline to trip demand, but I think that demand may not necessarily show up there. So, how do you bridge that gap moving forward? That's a great question, Rob.

Thanks, Roger and Robert as you know, it's it's important I think as we look out in the future that we.

Are really looking at more incremental and in many steps in the in our longer term planning process, which may be an outcome of what the fortis BC looks at what their regulator.

Maybe a stack of shorter in middle and longer term investment opportunities instead of starting at the long term, which can be more expensive. Obviously as you you know if you're building.

Incrementally and have that flexibility it will cost you that optionality always cost you a little bit of money.

David Hutchins: And we've got a couple different jurisdictions that we see this in. In Arizona, we actually don't have this conversation with those people, and there hasn't been a pushback on natural gas infrastructure or demand on a going forward basis. I'm going to hand the microphone over to Roger D'Alentonio, the CEO of FortisBC, to talk a little bit about British Columbia. And then you can spring back, and I can talk a little bit about New York as well.

But at the end it might provide a bit more flexibility for us to see the future a little bit clearer in the shorter term periods at a time.

Alright, thanks for that.

Back on the on the New York piece. So there there is a.

New York legislation, that's called the affordable gas transition act that that we can.

You know it limits the amount of free footage or actually zeroes out the the free footage it's allowed for for new gas customers So would incur.

Roger D'Alentonio: Thank you, David. Thanks, Rob. Maybe I'll start a little bit with the OCE decision itself, disappointed, of course, that it was denied.

Increase the amount of.

Contribution needed to get gas service.

Roger D'Alentonio: We've put quite a bit of work into that application. I think there are three things that come out of the decision that are important to understand. The first is that the Commission does see the need for a capacity upgrade, so they're not denying the basis for it. The second is why they deny that they've directed us to come back with an mitigation plan, so they are expecting us to provide some solution, which we will do. I think the third issue and really the heart of your question is what changed so they're not accepting our load forecast, and I think when you look at their reasoning, it's really not so much that they don't think we have a role from the point of view of a Commission regulating natural gas.

Increase upfront cost or you know homes et cetera.

There's some other growth limitations in there as well, obviously, where we're looking at that.

Don't necessarily agree with that policy as well, but at the at the end of the day. When you look at our service territory. One our gas service territory is pretty small it's a small part of our overall business.

From a Florida perspective, but also the gas and electricity customers are basically almost completely overlap and in central Hudson's serviced or so it's a it's it's actually a great way to look at it similar to how Roger looked at the Corona.

Roger D'Alentonio: It's more that with the policy direction that BC is going with CleanBC, and significant uncertainty right now on how BC will meet some fairly aggressive emissions targets, and what that means for solutions that are 56 years old, like the OCE pipeline upgrade, relative to what the long-term forecast is versus the near-term capacity shortfall. So, for us, it's really incumbent on us to demonstrate a variety of scenarios where we think the capacity issue may not be resolved over the long term. How do you do that?

The Corona situation, where we serve electricity and natural gas.

It's a great way for us to apply the right.

The amount of electrification of natural gas and.

In energy solutions to our customers when you can provide both sides of it so.

One one could be a growth opportunity, but the most important thing is to be managing the customer affordability on the pace of these transitions.

Okay, I appreciate that and that actually leads to kind of the the second of my questions on the electric side, we've seen another number of system operators increased demand expectations.

Roger D'Alentonio: I think what we've always done in the past is looked at load growth with the contingency factor looking on the upside, making sure that you're never short. I think what commissions are looking at when there's policy uncertainty is really more around a variety of scenarios and the ability to scale up in your asset mix, so you're not building the largest program or the largest facility, but is there a way to mitigate with near-term solutions but also expand if load growth proves to be higher than they're expecting. So, I think it's going to be a change in how we approach load forecasting over the next number of applications until we get some certainty around how Clean BC, in our instance, goes from policy to specific regulations. So, more to come on that for sure. Thanks, Roger.

Across the continent for variety of reasons when we take a look at your service territories, where do you think you could see the greatest upward revision audited demand forecast moving forward and why.

Yeah, I think there's there's probably a little a little of that in almost every service territory I'll say, the big ones are likely Arizona.

You'll see in the economic growth that's happening there, whether it's a battery factories data centers.

My conductor chip manufacturing.

That's statewide but some of that's in our service territory and some of it will be coming to our service territory in the near future. So that's on the back of additional.

David Hutchins: And, Rob, it is, you know, it's important, I think, as we look out in the future, that we are really looking at more incremental and many steps in the longer-term planning process, which may be, you know, an outcome of what FortisBC looks at with their regulator. It may be a stack of shorter, middle, and longer-term investment opportunities instead of starting at the long-term, which can be more expensive, obviously, as you, you know, if you're building, you know, incrementally and have that flexibility, it will cost you. That optionality always costs you a little bit of money. But in the end, it might provide a bit more flexibility for us to see the future a little bit clearer in the shorter-term. Thank you. Thank you. We'll talk back on the New York piece. So there is New York legislation that's called the Affordable Gas Transition Act that limits the amount of free footage or actually zeroes out the free footage that's allowed for new gas customers.

The conversations on manufacturing increasing.

In the area and of course, Arizona is always a.

Our net migration state as well, where we end up with good strong population growth.

Typically decade after decade.

Other one is in the Midwest I think that the manufacturing.

Boom that I think we will see.

And are seeing.

And our main jurisdiction there like Michigan.

I will definitely lead to additional.

Additional infrastructure needs additional transmission needs for us.

It's it's it's manufacturing, which obviously drives jobs, which drives how much you know drives the economy in general and some of the inflation reduction Act and.

Incentives for domestic content are really driving.

Some of these are manufacturing facilities. So it's good to be in that service territory and that's that's really setting aside even the latest Michigan clean energy legislation that is increasing the pace at which they have to get to a 100% clean energy, which is by 2040 now.

David Hutchins: So it would increase the amount of contribution needed to get gas service, which would increase upfront costs for homes, et cetera. We have some other growth limitations in there as well. Obviously, we're looking at that, and I don't necessarily agree with that policy as well, but it is. At the end of the day, when you look at our service territory, one, our gas service territory is pretty small. It's a small part of the overall business from a Fortis perspective, but also, gas and electricity customers are basically almost completely overlapped in Central Hudson's service.

That legislation, which I think is missing in and a fair number of forecast on us that's not under demand side. That's that's on the supply side, but of course that that drives renewables transmission and the rest of the things that are that we are really fond of.

I appreciate that thank you.

Our next question comes from the line of Linda as a guideline from TD Cowen. Please go ahead.

David Hutchins: So, it's actually a great way to look at it, similar to how Roger looked at the Kelowna situation, where we serve electricity and natural gas. It's a great way for us to apply the right amounts of electrification and natural gas and energy solutions to our customers when you can provide both sides of it. So, one could be a growth opportunity, but the most important thing is to manage customer affordability on the face of these transactions. I appreciate that. And that actually leads to kind of the second of my questions.

Thank you.

Just wondering if you can help us understand just a further two more races question given the lack of wiggle room in your in your financing and your debt metrics.

Mike that tilt you towards kind of pre funding to kind of.

Give you a little bit.

More not no wiggle room, but that too.

<unk> maybe some.

Surprises and.

Maybe might you'd be more inclined to opportunistically consider divestitures and how might that manifest itself. I'm also wondering how youre approaching opportunistic acquisitions.

David Hutchins: On the electric side, we've seen a number of system operators increase demand expectations across the continent for a variety of reasons. When we take a look at your service territories, where do you think you could see the greatest upward motivation on a demand forecast moving forward and why? Yeah, I think there's probably a little of that in almost every service territory. I'll say the big ones are likely Arizona, just seeing the economic growth that's happening there, whether it's battery factories, data centers, or semiconductor chip manufacturing.

Would you need to high grade that or might that pumped using the ATM.

Given some of the other moving parts.

Okay.

Linda This is Jocelyn I'll take the first part of that question.

Yeah, I mean, we're always looking at you know.

Pre funding opportunities if the market should open and timing of when we actually go into the market, but with respect to this particular room rating.

I wouldn't expect it to materially in hot are costing a if we had to.

David Hutchins: That's statewide, but some of that's in our service territory, and some of it will be coming through our service territory in the near future. That's on the back of additional conversations on manufacturing increasing in the area. Of course, Arizona's always a net migration state as well, where we end up with good, strong population growth, typically decade after decade.

Go to market them, even with this negative outlook, they're so but you're right. I mean, we do look for opportunities to to go to market. So I would say that's always are on the docket for us and with respect to the a T M.

The ATM is there and that's exactly why we put the ATM in place it was to give us some financial flexibility for events, particularly around growth that you know he's either unforeseen or a timing of cash flows from our subs or whatever it may be.

David Hutchins: The other one is in the Midwest. I think the manufacturing boom that we'll see and are seeing in our main jurisdictions there, like Michigan, will definitely lead to additional infrastructure needs, and additional transmission needs for us. It's manufacturing, which obviously drives jobs, which drives housing, which drives the economy in general. Some of the Inflation Reduction Act incentives for domestic content are really driving some of these manufacturing facilities, so it's good to be in that service territory. That's really setting aside even the latest Michigan clean energy legislation that is increasing the pace at which they have to get to 100 percent clean energy, which is by 2040 now, due to that legislation, which I think is missing in a fair number of forecasts.

We go through the year.

That's why I say, we're not firm on and you know any plans to use the ATM, but the ATM is there and so well continue to monitor it as we go through the year and.

Well, we'll firm up those plans as the year unfolds I'll pass the asset divestiture a question over to David.

Yeah.

Obviously, the focus that we have.

From a from a strategy perspective is executing that $25 billion capital plan now of course as fiduciary is we're always looking for opportunities to add value for our shareholders. So.

David Hutchins: That's not on the demand side, that's on the supply side, but of course, that drives renewables, transmission, and the rest of the things that we are really fond of. I appreciate that. Our next question comes from the line of Linda Ezergailis from TD Talon. Please go ahead. Thank you. I'm just wondering if you can help us understand a further, more racist question, given the lack of wiggle room in your financing and your debt metrics.

We all know it's it's it's on us to make sure that we're looking at all opportunities, but as Joseph mentioned, that's we're not dependent on anything other than the funding plan that we've laid out pretty clearly in the in the Investor day back in the fall.

Thank you and maybe just as a follow up at a higher level question.

The Chevron doctrine, that's been in place for 40 years.

Linda Ezergailis: Might that tilt you towards kind of pre-funding to kind of give you a little bit more, not wiggle room, but to anticipate maybe some surprises, and maybe you might be more inclined to opportunistically consider divestitures, and how might that manifest itself? I'm also wondering how you're approaching opportunistic acquisitions. Would you need to high-grade that, or might that prompt you to use the ATM, given some of the other moving parts? Linda, this is Jocelyn.

Approximately.

And addresses.

And an ability for an agent a U S federal agencies reasonable interpretation of any sort of ambiguous statute is being challenged.

What sort of impact with the discarding of removal of the Chevron doctoring potentially have on your business and also beyond that.

<unk>, we do have a U S election coming this fall. So just wondering how youre thinking generally about FERC and any sort of other potential shifts in.

Jocelyn Perry: I'll take the first part of that question. Yeah, I mean, we're always looking at, you know, pre-funding opportunities if the market should open and timing of when we actually go into the market, but with respect to this particular rating, I wouldn't expect it to materially impact our costing if we had to go to market, even with this negative outlook there, so, but you're right, I mean, we do look for opportunities to go to market, so I would say that's always on the docket for us, and with respect to the ATM, you know, the ATM is there, and that's exactly why we put the ATM in place, it was to give us some financial flexibility for events, particularly around growth that, you know, is either 114 or timing of cash flows from our subs or whatever it may be, so, you know, as we go through the year, that's why I say we're not firm on, you know, any plans to use the ATM, but the ATM is there, and so we'll continue to monitor it as we go through the year, and, you know, we'll firm up those plans as the year unfolds. I'll pass the asset divestiture question over to David. Yeah, obviously the focus that we have from a strategy perspective is executing that $25 billion capital plan. Now, of course, as fiduciaries, we're always looking for opportunities to add value for our shareholders. So, you know, it's on us to make sure that we're looking at opportunities.

How are your regulated businesses in the U S. A.

Has to adjust to any sort of new macro environment.

That's a that's a great question, Linda and it's it's a.

It's interesting because the Chevron doctrine has held precedence for.

Deference to regulatory bodies for years and years and years and it is an orphan.

Sided a precedent that are obviously has been used by regulators too.

All I'll say colored.

Color around those gray areas, where legislation hasn't really determined.

Who has the responsibility to be able to make those calls.

This has probably been a cod, while it's obviously been a conversation that's been going on for decades.

But it is.

It is interesting to hear the conversation I don't think in the long run.

It changes anything from our perspective is.

I think what the main purpose of this conversation is to understand or to determine whether or not regulatory agencies are overstepping.

But the the.

I'll say the bounds that are put on by legislation that isn't clear.

So and frankly it recently because it is so hard to get legislation done in the U S. It is left up to.

The regulatory bodies to kind of reach and then there is that there's a fine line between regulation and policy.

David Hutchins: But, as Jocelyn mentioned, we're not dependent on anything other than the funding that we laid out pretty clearly at the investor day back in the fall. Thank you. And maybe this is a follow-up, a higher level question. I don't know if this is for Linda or maybe someone more honed in on the regulatory situation. The Chevron Doctrine that's been in place for 40 years and addresses an ability for a U.S. federal agency, for example, to use any sort of ambiguous statute is being challenged.

So I don't see it having it it's an interesting conversation I don't see it really having any impact on what we see today I just think it may make it maybe a little more difficult to legislate bye bye regulation on a going forward basis. If it is challenged.

Okay.

Thank you and any other comment beyond them. This particular Supreme Court challenge to any sort of shifts maybe in kind of regulatory like what's going on at FERC, and where their priorities might be or any other commentary would be appreciated.

Linda Ezergailis: What sort of impact would the discarding or removal of the Chevron Doctrine potentially have on your business? And also, beyond that decision, we do have a U.S. election coming this fall. So, just wondering how you're thinking generally about FERC and any sort of other potential shifts in how your regulated businesses in the U.S. might have to adjust to any sort of new macro environment. That's a great question, Linda, and it's interesting because the Chevron doctrine has held precedent for deference to regulatory bodies for years and years and years, and is an often-cited precedent that has obviously been used by regulators to, I'll say, color in around those gray areas where legislation hasn't really determined who has the responsibility to be able to make those calls.

Yeah, I think FERC.

Down to three commissioners is focused on a couple of things clearly I think the planning and cost allocation <unk> has been discussed in depth as being sort of frontline. It was great to see the interconnection queue.

Anil rule come out and this is sort of the next thing in the Q from a bigger broader transmission policy perspective, due to the benefits to us having that closer to the front of the queue is that part of that.

Part of that <unk> is asking the question about whether or not to reinstate the federal right of first refusal for certain projects, which order 1000 took away many years ago. So that that's part of that conversation as well so we'd like to see that.

David Hutchins: This has probably been – well, it's obviously been a conversation that's been going on for decades, but it is interesting to hear the conversation. I don't think in the long run this changes anything from our perspective if – I think the main purpose of this conversation is to understand or determine whether or not regulatory agencies are overstepping what the – I'll say the bounds that are put on by legislation that aren't clear, and frankly, recently, because it is so hard to get legislation done in the U.S., it is left up to the regulatory bodies to kind of reach in, and So I don't see it having; it's an interesting conversation. I don't see it really having any impact on what we see today.

Moving and we hope it stays.

At the front of mind from a FERC perspective.

Thank you.

Thanks Linda.

We have our next question comes from the line of Mike Harvey from CIBC. Please go ahead.

Thanks, Good morning, maybe Jonathan if you could clarify the comments around the reconsideration of refreshing, Iowa did you say that there'll be a parallel process to push through legislation and maybe just kind of.

Just update on where you think.

That effort is right now in terms of right now there's legislation in Iowa.

But he asked you Josh.

So.

Yeah. Thanks for the question it is a bit as a parallel path reconsideration was filed in December and obviously in a parallel path that we're trying to get new ROE for legislation through Iowa.

David Hutchins: I just think it may make it maybe a little more difficult to legislate by regulation on a going forward basis, as it is challenging. Thank you. Thank you, and any other comments beyond this particular Supreme Court challenge to any sort of shifts maybe in kind of regulatory, like what's going on at FERC and where their priorities might be, or any other commentary would be appreciated. Yeah, I think the PERC, obviously down to three commissioners, is focused on a couple things clearly.

And David any sort of rough timelines on when you think that could be tabled and try to go to a vote.

Not.

Don't really have a good timeline for that where we're obviously shooting for this legislative session, which is still newish.

And so we're trying to get at as quick as we can and to get it to get it done and approved during this legislative session, which I think goes through April ish time frame.

David Hutchins: I think the planning and cost allocation NOPR has been discussed in depth as being sort of a front line. It was great to see the interconnection queue final rule come out, and this is sort of the next thing in the queue from a bigger, broader transmission policy perspective, of having that closer to the front of the queue. Part of that NOPR is asking the question about whether or not to reinstate the federal right of first refusal for certain projects, which Order 1000 took away many years ago, so that's part of that conversation as well. We'd like to see that, you know, moving, and we hope it stays at the forefront of mind from a first perspective.

And all centers at this point are that there is a political will to push that through and drive that forward at this point.

Yes, so so far we're seeing good reception and hoping to getting that pushed through.

Okay, and then coming back to D C.

With yearend now done just clarification on the equity injection with the.

Equity, taking a step up it has that been determined and what is that amount that actually go into 2024.

Yeah, Mark that's that's been determined it was $300 million.

So that's a little bit less than you would have thought a couple months ago is that right.

Yeah. It was it was about what we thought it may have been a little bit lower.

Okay, and then just as you think broadly around that question around the Okanagan pipeline gas.

David Hutchins: Thank you. We have our next question coming from the line of Mark Harvey from CIDC; please go ahead. Thanks, Turmuril.

This transition around electrification, but obviously be starting with forest fires wildfires drought conditions, which has hampered their wholesale so the generation market. There. So what conversation goes on around sort of reliability and cost stability to the gas assets offer versus some of the pressures that the electric network metaphase for Alaska.

Mark Harvey: Maybe, Jocelyn, if you could clarify the comments around the reconsideration of Roe v. Fish in Iowa. Did you say that it would be a parallel process to push through legislation? Maybe just kind of get an update on where you think that effort is right now in terms of rewriting legislation in Iowa. But, yeah, he asked you, Jonathan, so, yeah, thanks for the question. It is a parallel path.

Three years.

Well that depends on the jurisdiction.

Obviously in Arizona, we have natural gas now in our newest our integrated resource plan for bolt at Tucson Electric power in a U S electric our two electric utilities there.

There's you know, Alberta has a whole different conversation as well recognizing the need and just looking and seeing a lot of additions of natural gas capacity from a generation standpoint coming on this year and obviously a lot of conversations in that jurisdiction.

Jocelyn Perry: Reconsideration was filed in December, and, obviously, on a parallel path that we're trying to get new ROPA legislation through Iowa. And, David, any sort of rough timelines on when you think that could be tabled and try to go to a vote? I don't really have a good timeline for that.

Is it distribution on the company.

Or sort of a bit on the sidelines on that but in British Columbia, you don't hear a whole lot of conversation around natural gas generation because they're they have so much hydro. So a lot of most of the conversation is like site expansion and around hydro and renewables at this point.

David Hutchins: We're obviously shooting for this legislative session, which is still new-ish, and so we're trying to get it as quick as we can and to get it done and approved during this legislative session, which I think goes through the April-ish timeframe. And all the signs at this point are that there is a political will to push that through, and we can drive that forward at this point. Yeah, so far we're seeing good reception and hoping to get in on that.

It is incumbent on.

US as folks who operate in every one of our jurisdictions to make sure that we're getting out and having those conversations of getting that balanced portfolio that allows us to get to that cleaner energy future as fast as we can but with the big asterisk around affordability and reliability and and I think we're having a lot more constructive.

Jocelyn Perry: Okay. And then coming back to BC, so what's the year-end now done? Just clarification on the equity injection with the equity thickness step-up. Has that been determined?

Discussions with.

The government and regulators.

And I think overall, we will see more I think positive and balanced discussions and outcomes are due to due to that conversation.

Mark Harvey: What is that coming out of the fiscal year 2024? Yeah, Mark, that's been determined. It was 300 million. That's a little bit less than you would have thought a couple months ago, is that right? It was about what we thought, but it may have been a little bit lower.

Okay. Thanks very much.

Thanks, Mike.

Our next question comes from the line of Ben Pham from BMO. Please go ahead.

Hi, Thanks, good morning.

I was wondering.

If you can maybe add a bit more.

Color on Europe.

Mark Harvey: Okay, and then just if you think broadly around that question around the open armory pipeline for gas in the, And, you know, this transition around electrification but the constant struggle of forest fires, wildfires, drought conditions, which has hampered the whole purpose of the generation market there. So, what conversation goes on around, you know, the sort of reliability and profitability that gas assets offer versus some of the, you know, pressures that the electric network might face over the last couple of years? Well, that depends on the jurisdiction.

Comments on asset rationalization what.

What conditions are factors.

It is a core asset to move into a noncore.

Asset.

So that's it.

I understand the question right is what.

What are what do we consider noncore assets I mean that all of our assets that I would say.

That we define as core as.

But our business is all about and that's regulated utility assets.

Why Aitken Creek was an unregulated asset in.

That that made sense to monetize for a variety of reasons, but one has to take that almost $500 million proceeds and use it to invest in the main thing, which is our regulated utility businesses. So from that perspective nine.

David Hutchins: Obviously, in Arizona, we have natural gas now in our newest integrated resource plan for both Tucson Electric Power and UNS Electric, our two electric utilities there. There's, you know, Alberta's a whole different conversation as well, recognizing the need and looking and seeing a lot of additions of natural gas capacity from a generation standpoint coming this year. And obviously, a lot of conversations in that jurisdiction, not that we're, as a distribution-only company, we're sort of a bit on the sidelines on that. But in British Columbia, you don't hear a whole lot of conversation around natural gas generation because they have so much hydro, so most of the conversation is, you know, about the expansion around hydro and renewables at this point.

<unk> 99, and change I mean, it almost round to a 100% regulated assets. So.

So we are so we we don't have we don't kind of define the things as noncore per se.

Is there a non Reg is that the only thing I really like is that the.

Police hydro assets.

Yeah, Yeah, yeah, the Belize hydro assets are the only.

Nonregulated assets that we have.

Okay got it thank you.

We have our next question comes from the line of David <unk> from Raymond James. Please go ahead.

Yeah. Thanks, Good morning, everyone. Just one for me I'm just curious.

Going back to the Iowa real for issue I Wonder if that proceeding or some of the decisions they're effect.

David Hutchins: I think it is incumbent on us as folks who operate in every one of our jurisdictions to make sure that we're getting out and having those conversations about getting that balanced portfolio that allows us to get to that cleaner energy future as fast as we can, but with the big asterisk around affordability and reliability. And I think we're having a lot more constructive discussions with government regulators. And I think overall we will see more, I think, positive and balanced discussions and outcomes due to that conversation. Okay. Thanks, everyone. Thanks, Mark. Our next question comes from the line of Ben Pham from BMO. Please go ahead.

Do you think it might affect or prompt the challenges to the broker you have in other states.

Just any commentary around how you see that potentially playing out in the other states.

Yeah I mean, there's this there has had some challenges in other states.

Some that we operate in something that we have real version and in other states as well.

To make sure that you define these rover so that they they beat those challenges like the one that we have in Minnesota has met that challenge. So that's obviously part of the you know the conversation would go to look at a new Rover and I was making sure that it.

From a constitutionality perspective.

Ben Pham: Hi, thanks for the morning. I was wondering if you could maybe add a bit more color to your comments on asset rationalization. What conditions are factors?

And you know from the principles of that that it ends up being a good solid.

For that we can do we know that if challenge will still survive, but yeah. Those that's already happened its happened in Texas and other places as well, but we think and we strongly believe.

David Hutchins: There's a core ask that's moving to an encore. So, if I understand the question right, what do we consider non-core assets? I mean, all of our assets that I would say that we define as core are what our business is all about, and that's regulated utility assets. That's why Aiken Creek was an unregulated asset, and that made sense to monetize for a variety of reasons, but one is to take that almost $500 million proceeds and use it to invest in the main thing, which is our regulated utility businesses. So, from that perspective, we're 99 and change. I mean, it almost rounds to 100% regulated assets. So, we don't kind of define things as non-core, per se. If you're not, Greg, is that the only thing really left? Is that just the leaked Hydra assets?

These rovers out of the absolute right way for us to develop transmission on a going forward basis for a variety of reasons, but you know that.

The big ones are affordability reliability and getting clean energy on the grid as fast as we can.

And making sure that we don't we don't sacrifice any one of those three things and I'll say the sad part about having the injunction sitting there is negative to all three of those things. These are projects that improve affordability by interconnecting cheaper resources delivering cleaner energy and.

And or are there for reliability and having those delayed is a negative to the three absolute tenants of our utility sector. So we want to make sure that we have the ability to get those projects done and get them done fast and and affordably for our customers.

David Hutchins: Yeah, the Belize hydro assets are the only non-regulated assets that we have. Thank you. We have our next question come from the line of David Quezada from Raymond James. Please go ahead. Thanks.

Excellent. Thank you appreciate it.

We have our next question coming from the line of Patrick Kenny from National Bank Financial. Please go ahead.

David Quezada: I'm just curious, going back to the Iowa roper issue, I wonder if that proceeding or some of the decisions there affect, or if you think it might affect or prompt challenges to the roper you have in other states, any commentary around how you see that potentially playing out in the other states. There have been challenges in other states, some that we operate in, some that we have ROFERs in, and other states as well. You have to make sure that you define these ROFERs so that they meet those challenges, like the one that we have in Minnesota has met that challenge. So that's obviously part of the conversation when you go to look at a new ROFER in Iowa is making sure that it, from a constitutionality perspective, and from the principles of that, that it ends up being a good, solid roofer that we can trust that if challenged, we'll still survive. But yeah, those things, that's already happened. It happened in Texas and other places as well.

Thank you good morning, everybody I'm just on the wood fiber project I know, it's still a relatively small investment, but just wondering if you could provide a bit more color on the key drivers of the increase in costs there.

And then you know it looks like you're fully protected through regulatory approval for now but.

Just given the three year construction window.

How should we be thinking about.

Being protected from any further potential escalations in our construction costs between now and then.

Yes sure. These aren't these aren't escalations. These are really due to the ability of us to do more as a more of a rate based investment and for the wood fiber parties.

To have less of a contribution in aid of construction. So it shouldnt be a read through that this was a project.

Increased cost and or scope.

It's just that we now have a bigger piece of that overall pipeline.

Pi now Roger happened to have been up there at the wood fiber side, just the last couple of days so.

David Hutchins: But we think and we strongly believe that these roofers are the absolute right way for us to develop transmission on a going forward basis for, you know, a variety of reasons. But, you know, the big ones are affordability, reliability, and getting clean energy on the grid as fast as we can. And making sure that we don't sacrifice any one of those three things.

He can opine on that as well Roger.

Yes, Thanks, David Good morning, Patrick David has it right.

We have a long term transportation service agreement with a specific rate schedule dedicated to wood fiber and.

There's a the ability to manage the contribution either construction.

Then change the total structure over the 40 years. So this was by design.

David Hutchins: And I'll say the sad part about having the injunction sitting there is it's negative to all three of those things. These are projects that improve affordability by interconnecting, you know, cheaper resources, delivering cleaner energy, or are there for reliability. And having those delayed is a negative to the three absolute tenants of our, you know, utility sector. So we want to make sure that we have the ability to get those projects done and get them done fast and affordably for our customers. Excellent. Thank you. Appreciate it. We have our next question coming from the line of Padre Penny from National Bank Financial. Please go ahead. Thank you. Good morning, everybody.

As the project went into construction, we started construction on our pipeline.

Late last year Wood fiber site I was there.

On Wednesday, there into a site prep and construction so as we finalize the transportation service schedule agreement.

With updated costs had a construction we ended up adjusting the contribution either construction, which now has us investing $750 million directly back.

In the project recovered by the Transportation service agreement over the life of the project.

Patrick Penny: Just on the Wood Fiber Project, and it was... Still a relatively small investment, but I was just wondering if you could provide a bit more color on the key drivers of the increase in cost there. And then, you know, it looks like you're fully protected through regulatory approval for now, but given the three-year construction window, how should we be thinking about being protected from any further potential escalations in construction costs between now and then? Yeah, sure. These aren't escalations.

Patrick.

I have to note that.

It might be the first time I've heard is a $750 million not being that big of a threat.

[laughter] good point good point David.

And then just back to S&P's report I know you'll be.

Further discussions with them throughout the year, but.

Any sense as to what our incremental risk mitigation measures you might be needing.

Needing to put in place here over and above what Youre already doing just in order to relieve some of their concerns.

David Hutchins: These are really due to the ability of us to do more of a rate-based investment and for the wood fiber parties to have less of a contribution in aid of construction. It shouldn't be a reworking of this project, increasing cost and or scope. It's just that we now have a bigger piece of that overall pipeline pie. Now, Roger happened to have been up there at the wood fiber site just the last couple of days. He can opine on that as well, Roger. Thanks, David. Morning, Patrick. Yeah, Dave has it right.

And then I guess.

Just given the relatively low precipitation out west. This winter if you can comment on any proactive activities you might be.

Undertaking ahead of the next wildfire season.

Yeah. So we we have been involved and engaged in trying to.

Finding the best ways to mitigate.

The climate impacts in general, but wildfires in particular, and we've been doing that not only amongst our own utilities to our Florida operating group and sharing the best practices and trying to understand additional technologies practices procedures recovery waste, we can coordinate with Oh.

Roger D'Alentonio: We have a long-term transportation service agreement with a specific rate schedule dedicated to wood fiber, and there's the ability to manage the contribution to construction, which will then change the total structure over the 40 years. So, this was by design. As the project went into construction, we started construction on our pipeline late last year with the fiber site. I was there on Wednesday.

Arjun <unk> services when there is a fire all of those things and we also do that externally.

The broader north American utility sector, there's a lot of.

Good ideas or there's just a laundry list of things that you can do to mitigate wildfire impacts those may or may not apply every every single utility has a different jurisdiction of different fire threat et cetera, but.

Roger D'Alentonio: They're into site preparation and construction. So, as we finalized the transportation service schedule agreement with updated costs ahead of construction, we ended up adjusting the contribution ahead of construction, which now has us investing $750 million directly back into the project recovered by the transportation service agreement over the life of the project. Patrick, I'll have to note this. That might be the first time I've heard of $750 million not being that big of a project.

It's it's incumbent on us to make sure that we're doing all the things necessary.

Our jurisdictions to mitigate it now we think we are now based on what we know today as we as we learn and Nomura and as a sector grows their knowledge in this and learns and knows what works and what doesn't work. We will look at implementing those and we just have to match up knowledge that we're getting and we're gaining across the.

David Hutchins: And then, just back to S&P's report. I know you'll be having further discussions with them throughout the year. Any sense as to what incremental risk mitigation measures you might be needing to put in place here over and above what you're already doing just in order to relieve some of their concerns? And then, I guess, given the relatively low precipitation out west this winter, if you can comment on any co-active activities you might..., you know, undertaking ahead of the next wildfire season.

Sector with the with the expectations of rating agencies to make sure that we've got this covered in that we're all talking on the same terms and have the same level of expectations of what that what that means.

So.

Yep.

Okay. That's great. Thank you.

We have our next question comes from the line of Michael Sullivan from Wolfe Research. Please go ahead.

Hey, everyone. Good morning.

Hey, Michael.

It is just just a quick one back to the MISO.

Patrick Penny: Yeah, so we have been involved and engaged in trying to find the best ways to mitigate climate impacts in general, but wildfires in particular, and we've been doing that not only amongst our own utilities through our Fortis operating group and sharing the best practices and trying to understand additional technologies, practices, procedures, you know, recovery, ways that we can coordinate with emergency services when there is a fire, all of those things. And we also do that externally, using the broader North American utility factor. There are a lot of good ideas. There is a laundry list of things that you can do to mitigate wildfire impacts.

Am I sort of tranche two process I think you mentioned.

Approvals in the second half of the year any sense of when we might see like a first look at initial project awards.

Yeah. So the way that the process goes is is I think that batch doesn't come out probably.

Because right now they are still doing all the modeling to figure out which are the are the right projects I don't think we will get a good view onto that into those that level of project detail.

Probably until summer sometime.

Okay, Great and then just coming out of that.

<unk> rate case, and now that you've got the SRP. There just how you think about how that translates over to TEP and the regulatory.

David Hutchins: Those may or may not apply. Every single utility has a different jurisdiction, a different fire threat, et cetera, but it's incumbent on us to make sure that we're doing all the things necessary in our jurisdictions to mitigate them. Now, we think we are now based on what we know today, as we learn and know more, and as the sector grows its knowledge of this, and usually knows what works and what doesn't work. We'll look at implementing those, and we just have to match up the knowledge that we're gaining across the entire sector with the expectations of rating agencies to make sure that we've got this covered and that we're all talking on the same terms and So, I'll leave it at that. Okay, that's great. Thank you. We have our next question coming from the line of Michael Sullivan from Wolf Research. Please go ahead. Hey, everyone. Good morning. Hey Michael.

In renewables build out strategy there.

Yeah. That's a great question. So obviously, we didn't get the SRV and Tep's rate case in U S. Electric did in there you obviously every rate cases different than.

And the size of these investments for the smaller U S. Electric is is a bit different than.

So then the larger Tucson electric power.

Portfolio, but we do see this as definitely as a positive.

We don't necessarily need it now.

Because we have a lot of.

Our renewable and storage investments are towards the tail end of our of our five year plan.

But it is something that we now see as a.

As a framework to be able to use for T. P. When it files. Its next rate case, so nothing urgent to try to figure out something between now and that next rate case and of course, we don't have a you know a.

<unk>, a very rigid or.

Michael P. Sullivan: It is. Now, just a quick one back to the Mysotron 2 process. I think you mentioned approvals in the second half of the year. Any sense of when we might see, like, a first look at initial project awards? Yeah, so the way that the process goes is, I think that batch won't come out, probably, because right now they're still doing all the modeling to figure out which are the right projects. I don't think we'll get a good view of that level of project detail, you know, probably until summer sometime.

Defined rate case schedule, but we think we can manage obviously with the investment tax credits and production tax credits.

To help them to fill in that regulatory lag that we can we can manage effectively and not have any changes in our in our plan or our integrated resource plan.

Based on what we know today.

Great. Thanks, so much.

Just a reminder, if you would like to register a question. Please press the star followed by the one on your telephone keypad.

Our next question comes from the line of Panic James from Bank of America. Please go ahead.

David Hutchins: Okay, great. And then, just coming out of the UNS rate case and now that you've got the SRB there, just how do you think about how that translates over to TEP and the regulatory and renewables build-out strategy there? Yeah, that's a great question.

Hi, Good morning, Thank you for taking my questions.

Following on Michael's first question, how are or how could the Iowa transmission ROE for our proceedings affect your strategy regarding MISO tranche two projects and further planning in the region and then in the event tranche one projects could be affected or are there opportunities.

David Hutchins: So obviously, we didn't get the SRB in TEP's rate case, and UNS Electric did. And obviously, every rate case is different, and the size of these investments for the smaller UNS Electric is a bit different than the larger Tucson Electric Power portfolio.

<unk> for contingent standouts were either at ITC or across the organization.

So what was the last part.

David Hutchins: But we do see this definitely as a positive. We don't necessarily need it now because a lot of our renewable and storage investments are towards the tail end of our five-year plan. But it is something that we now see as a framework to be able to use for TEP when it files its next rate case. So there is nothing urgent to try to figure out between now and that next rate case. And, of course, we don't have a very rigid or defined rate case schedule.

Contingent what.

Okay.

Okay.

Sure.

Yes, yes, okay, you didn't spend elsewhere.

Okay, yes, so it.

Obviously, the whole our whole a multi pronged approach here is to get the injunction removed from those tranche one projects. So that we can continue.

And those projects developed the parallel piece that I mentioned theres actually two parallel pieces here one is to get the role for a new I will roll for past, which if we can do that that would hopefully be in place before the tranche two projects are allocated and the third one that I mentioned.

David Hutchins: But we think we can manage, obviously, with the investment tax credits and production tax credits, helping to fill in that regulatory lag that we can manage effectively and not have any changes in our plan or integrated resource plan based on what we know today. Great, thanks so much. Just a reminder, if you would like to register a question, please press the star followed by the 1 on your telephone keypad. We have our next question coming from the line Tanner James from Bank of America. Please go ahead. Hi, good morning.

Earlier too is.

The focus on looking to get something into the world of federal role for it.

And the planning and cost inflation number. So those are those are the kind of the three things that we're looking at.

Contingent spend wise, we're always looking for additional investments whether it's in it remember the the the MISO long range transmission plan is a big piece of the planning process, but there's also.

Tanner James: Thank you for taking my question. Following on Michael's first question, how are or how could the Iowa Transmission and ROFA proceedings affect your strategy regarding MITESO TRANCH 2 projects and further planning in the region? And then, in the event TRANCH 1 projects could be affected, are there opportunities for contingent spend elsewhere, either at ITC or across the organization? So, what was this last part about contingent spend? I'm going to miss you too a lot of batteries. He didn't spend them elsewhere.

The annual M type projects that are they get brought in there as well so and then there's additional things like the joint targeted interconnection queue investments that could provide an opportunity which are investments that go across some of the different.

<unk> connect are different our T OS et cetera, So all of those things, where we're always looking for contingent spend for sure.

Alright, great. Thank you very much.

Thank you.

David Hutchins: Yeah, so our whole multi-pronged approach here is to get the injunction removed from those tranche one projects so that we can continue getting those projects developed. The parallel piece that I mentioned; there are actually two parallel pieces here. One is to get a new Iowa roper passed, which if we can do that, that would hopefully be in place before the tranche two projects are allocated, and the third one that I mentioned earlier too is the focus on looking to get some level of federal roper funding in the plan and cost of each in NOPR. So those are kind of the three things that we're looking at. Contingent spend-wise, we're always looking for additional investments, whether, and remember the MISO long-range transmission plan is a big piece of the planning process, but there's also the annual MTEF projects that get brought in there as well, and then there's additional things like the Joint Targeted Interconnection Q investments that could provide an opportunity, which are investments that go across some of the different, connect the different RTOs, e So all of those things; we're always looking for contingent spend, for sure.

There are no further questions I would like to turn the call back to Ms. Elena.

Thank you Laura we have nothing further at this time. Thank you everyone for participate participating in our fourth quarter and annual 2023 results Conference call. Please contact Investor Relations should you need anything further thank you for your time and have a great day.

Thank you ma'am. Thank you for participating this concludes today's conference call you may now disconnect.

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Tanner James: All right. Great. Thank you. As there are no further questions, I would like to call back to Ms. Amano. Thank you, Laura. We have nothing further at this time. Thank you, everyone, for participating in our fourth quarter and annual 2023 results conference call. Please contact Investor Relations should you need anything further.

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Stephanie Amaymo: Thank you for your time, and have a great day. Thank you. Thank you, ma'am. Thank you for participating. This concludes today's conference call. You may disconnect. The Bulletproof Executive, 2013

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