Q4 2023 Fortis Inc Earnings Call

Operator: Good morning, everyone. Thank you for standing by. My name is Lara, 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.

Good morning, everyone. Thank you for standing by my name is Laura and I will be your conference operator today.

Laura: I'll come to Florida, as Q4, 'twenty 'twenty fee earnings conference call and webcast. During the call all participants will be in a listen only mode. There will be a question and answer session. Following the presentation at that time that was the question should press star followed by one on the telephone line if at any time during the call.

Operator: There will be a question-and-answer session following the presentation. At that time, those with questions should press star followed by 1 on their telephone. If at any time during the conference you need to reach an operator, please press star 0. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Speaker Change: Friends, who you need to reach an operator, please press star zero.

Stephanie: At this time I would like to turn the conference over to Stephanie Yeah. My mouth. Please go ahead, Mr. My mouth.

Stephanie Amaimo: Thanks, Laura, and good morning, everyone. Welcome to Fortis' fourth quarter and annual 2023 results conference call. I'm 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.

Stephanie Yeah: 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 Wonder if.

Stephanie Yeah: Remind you that the discussion will include forward looking information, which is subject to the cautionary statement contained in the supporting slide show actual results can differ materially from the forecast projections included in the forward looking information presented today, all non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U S.

Stephanie Amaimo: 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.

Stephanie Yeah: GAAP financial measures in 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.

David Hutchens: And good morning, everyone. Today, we are pleased to report strong 2023 operational and financial results.

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 Aiken 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 Hutchens: 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.

David Hutchens: Adjusted EPS grew approximately 9%, excluding foreign exchange impacts with rate growth in 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 percent, 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.

David Hutchens: 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.

David Hutchens: Millstone of which we are very proud.

David Hutchens: 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' unemployed and is embedded in everything we do.

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

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 increased innovation and process improvements. We also work with our customers to help them manage their bills through our Energy Efficiency and Demand-Side Management, or DSM, programs.

David Hutchens: 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 these innovation and process improvements.

David Hutchens: We also worked 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 appointed FortisBC's $600 million DSM plan for 2024-2027. The plan continues cost-effective initiatives for customers to save on energy use while incorporating new programs to further align with the CleanBC 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 to deliver a 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 1 emissions compared to 2019 levels. The closure of the coal-fired sand dune generating station in June 2022, as well as the start of seasonal operations of the Springerville units in 2023, contributed to the emissions reduction.

David Hutchens: Just last week, the British Columbia Utilities Commission.

David Hutchens: Florida, B C 600 million DSM plan for 2024 through 'twenty 'twenty seven.

David Hutchens: Continuous cost effective initiatives for customers to save on energy as well.

David Hutchens: A new programs to further align with the clean B C roadmap to 2030.

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

David Hutchens: 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.

David Hutchens: 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.

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

David Hutchens: The closure of the coal fired San Juan generating station in June 2022, as well as the startup 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 targets 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.

David Hutchens: 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 'twenty 35, and net zero by 2050.

David Hutchens: While all of our utilities play a part in reducing carbon emissions. The bulk of the reductions will be achieved through the execution of TPS integrated resource plan.

November both T. P. M D U N S electric filed their 2023 IR piece with the Arizona Corporation Commission G.

David Hutchens: <unk> calls for the addition of over 2200 megawatts of renewable generation over 1300 megawatts of energy storage and four megawatts of natural gas, peaking units through 2038 and supports the closure of Tep's remaining 900 megawatts of coal fired generation by 2000.

David Hutchens: 32.

David Hutchens: 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 'twenty 32, 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, TEP and UNS Electric issued a joint all-source request for proposals, seeking new resources in support of the IRPs. The RFP calls for over 600 megawatts of renewable energy and energy efficiency resources and over 800 megawatts of firm capacity.

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

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

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 projects in Iowa.

David Hutchens: The next steps on the IR piece, we expect a decision from the MCC in the fall.

David Hutchens: Looking ahead, we expect to release our climate report during the first quarter of 2020 for showcasing the climate scenario work completed by our utilities over the past two years to ensure we are building climate resiliency into our operations.

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

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

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

David Hutchens: 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 Tronch One projects located in Iowa are 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 Upgrade, 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%.

David Hutchens: 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 gasoline 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 followed.

David Hutchens: 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 are.

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

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

David Hutchens: 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.

David Hutchens: And at <unk>, we estimate between two and a half and $5 billion of incremental investments through 'twenty.

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.

David Hutchens: At TEP and <unk> electric to support their <unk>.

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

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

David Hutchins: In addition, we estimate between $2.5 and $5 billion U.S. dollars of incremental investments through 2028 at TEP and UNS Electric to support their IOPs. We also anticipate growth opportunities associated with renewable natural gas solutions and LNG infrastructure in British Columbia. Across all of our utilities, we expect additional growth opportunities to support climate adaptation, Grid Resiliency, and the Clean Energy Transition.

David Hutchens: Good resiliency in the clean energy transition.

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

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 4-6% annual dividend growth guidance through 2028, supported by our low-risk regulated growth profile. Well, we'll turn the call over to Jocelyn for an update on our fourth quarter and annual financial results. Thank you, David, and good morning, everyone.

Johnson: 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 Fortis Billy's within the corporate and other segment with the sale of Aitken Creek in the fourth quarter. We will report <unk> believes in this segment going forward.

Johnson: Reported earnings per common share for the fourth quarter of 2023 were 78 cents once that's higher than reported in the fourth quarter of the prior year <unk>.

Johnson: Adjusted EPS for the fourth quarter of 2023 was 72.

Johnson: Consistent with the fourth quarter of 2022.

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 Aitken Creek and Fortis Belize within the corporate and others segment. With the sale of Aitken 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, $0.01 higher than reported in the fourth quarter of the prior year. Adjusted EPS for the fourth quarter of 2023 was $0.72, consistent with the fourth quarter of 2022.

Johnson: 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.

Johnson: 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.

Johnson: 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: Results for the quarter were in line with expectations and reflect the timing of adjustments related to Aiken Creek. As we stated on the last earnings call, Aiken 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 others segment reflects lower earnings at Aitkin Creek, driven by the timing of the disposition and higher margins recognized in the fourth quarter of 2022. 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 FortisBC. As David mentioned, we delivered strong EPS growth in 2023. Reported EPS was $3.10, 32 cents higher than 2022.

Johnson: As David mentioned, we delivered strong EPS growth in 2023 reported EPS was $3 10, 32 cents higher than 2022.

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

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

Johnson: 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 one.

Johnson: 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.

Johnson: 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.

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 cost of capital parameters approved by the BCUC in September 2023. Rate-based growth also contributed to the increase.

Johnson: At our other electric segment rate base growth higher sales and equity income from the watch any kidney at project contributed a two cent increase in EPS.

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

Jocelyn Perry: For our regulated U.S. and electric and gas utilities, almost half of the 12-cent 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, ITC, increased EPS by 6 cents, reflecting 6% year-over-year earnings growth.

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

Johnson: 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.

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

Johnson: 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.

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

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 finances. In our other 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 three cents related to lower hydroelectric generation in Belize and lower earnings at a concrete plant.

Johnson: 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.

Johnson: 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.

Johnson: 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.

Jocelyn Perry: For 2024, we do expect the sale of Aitkin 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. 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.

Johnson: 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.

Johnson: 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.

Johnson: Have not raised any equity under the ATM program.

Johnson: 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.

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 2022. 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.

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

Johnson: S&P also revised its outlook on our issuer rating to negative, citing rising physical risks due to climate change including wildfires.

Johnson: 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.

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

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

Johnson: 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 ROE 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.

Johnson: To ITC Midwest by MISO in July 2022.

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

Jocelyn Perry: 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.

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

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

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

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

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 Investor Day. 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.

Johnson: And Furthermore.

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

Johnson: Last month, the ACC issued its decision on Unf's Electric's general rate application approving among other things a 975% allowed return on equity and a 54% common equity layer the new rates became effective in February 1st.

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% 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.

Johnson: The ACC also approved the 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.

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

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

Johnson: 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 week 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 Tranche 1 projects in Iowa that were previously awarded to ITC Midwest by MISO in July 2022. 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 Roll-for-Bill in Iowa. It's important to highlight that the district court ruled on the manner in which the Iowa roofer was passed and not on the merits of the roofer. Furthermore, and importantly, MISO is the only entity charged with determining what projects are to be competitively bid pursuant to its tariff.

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

Johnson: In Alberta, the formulaic allowed ROE was set at 928% for 2024 and will be reset annually in the fourth quarter.

Johnson: Lastly, there are no new updates to report on the outstanding for MISO base ROE or no person on transmission incentives at ITC.

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

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

David Hutchens: 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.

Jocelyn Perry: Also, approximately 70% of the Trans1 projects are upgrades to ITC Midwest facilities along existing rights-ways, which under MISO's tariff grants ITC Midwest the option to construct the upgrades regardless of the outcome of the ballot for legislation. And furthermore, for any portion of the first tranche of the MISO LRTP 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 UNS 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.

David Hutchens: 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.

Stephanie Yeah: Thank you David This concludes the presentation at this time I'd like to open the call to address questions from the investment community.

Stephanie Yeah: Thank you we will now conduct a question and answer period. If you would like to register a question. Please press the star followed by the one on your telephone.

Speaker Change: My question has been answered and you would like me to via registration. Please basket pound sign if you're using a speaker phone. Please lift your handset before entering your request.

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 30. The New York Service Commission staff and intervenor testimony was filed in November, with staff recommending a one-year rate increase, including a 9.2% allowed ROE and 48% equity fix. This litigative proceeding remains on track.

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

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

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

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

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

Movies Choi: 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 FERC-MISO-based ROE or NOPERS on transmission incentives at ITC.

Movies Choi: Target and.

Movies Choi: Any proactive actions, you're considering to restore to cushion.

Movies Choi: It is important to you.

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

Jocelyn Perry: 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.

Jocelyn Perry: 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.

David Hutchins: 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 service 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 Stefan.

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

Jocelyn Perry: 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.

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

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

Speaker Change: 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.

Speaker Change: 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 cushion, 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 ask a question, please press the star followed by the 1 on your telephone. If your question has been answered and you would like to withdraw your registration, please press the pound sign. If you are using a speakerphone, please lift your handset before entering your request.

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

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

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

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

Speaker Change: What does the repeal of the R. S. T mean in terms of TPS decarbonization growth plans.

Speaker Change: What does the repeal of the R. S. T mean in terms of TPS decarbonization growth plans.

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.

Speaker Change: 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 a 15% requirement, which we have surpass already.

Speaker Change: 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. Back to Ambassador A. Getting to 12% would have meant you had about 100 to 150 basis points of cushion versus your downgrade thresholds.

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

Dave: 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 debt.

Maurice Choi: 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 keeping the 12% target? Any proactive actions you're considering to restore the cushion if the cushion is important to you? Hi Maurice, this is Jocelyn.

Dave: 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, it'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, on average, 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. And we're also getting, you know, confirmations around certain tax rules. And we thought at first that the minimum tax was going to impact us; now it's not.

Dave: The 2025 requirements.

Speaker Change: Perfect. Thank you.

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

Robert Hope: Good morning, everyone.

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

Robert Hope: Your views of demand growth.

Robert Hope: Lineup with how the regulator is seeing the world so that.

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

Jocelyn Perry: So that gives us a little bit of room to push our metrics forward. But, you know, we'll 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.

Robert Hope: 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.

Robert Hope: On the natural gas infrastructure or demand.

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

Jocelyn Perry: Great, thanks. And just to follow up on that, as 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 cushion? 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.

Robert Hope: 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.

Roger: 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.

Roger: 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.

Roger: 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.

David Hutchins: Thank you. And my final question is on Arizona in terms of the potential repealing 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, yeah, Maurice. This is Dave.

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

Roger: Significant uncertainty right now on.

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 surpassed already. Obviously, the cost recovery of historical items from that will continue to be, and we will continue to make sure that we get those through the normal regulatory processes. But overall, the goal isn't, doesn't really have any impact on us. 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.

Roger: How it is D C meet some fairly aggressive emissions targets, what does that mean for our solutions out or 56 years life like the Ocu pipeline upgrade relative to what the long term forecast is versus the near term.

Roger: Passey shortfall.

Roger: So it's for US it's really.

Roger: Comment that we demonstrate.

Roger: A variety of scenarios, where we think the capacity.

Roger: 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.

Roger: With the contingency factor looking at.

Robert Hope: 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 hasn't already met the 2025 requirements. Perfect, thank you. Our next question comes from Rob Hope from Scotiabank. Please go ahead. Good morning, everyone.

Roger: On the upside making sure that you are never short I think what commissions are looking at when Theres policy uncertainties really give me more around a variety of scenarios.

Roger: And what is the ability to scale up in your 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.

Robert Hope: I want to circle back on the Okanagan decision. So maybe looking forward, you know, how do you work with the regulator, whether it's in BC 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 that, you know, for example, you think you need to get this pipeline to serve demand, but I think that demand may not necessarily show up there. So how do you bridge that gap moving forward?

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

Roger: The load forecasting over the next number of applications.

Roger: Until we get some certainty around how.

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

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

Speaker Change: 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.

David Hutchins: That's a great question, Rob, and we've got a couple of different jurisdictions that we see this in. In Arizona, we actually don't have this conversation, and there hasn't been a pushback on natural gas infrastructure or demand on a going forward basis. So I'm gonna kick it 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. Thanks, David. Thanks, Rob. Maybe I'll start with a little bit on the OCE decision itself. I was disappointed, of course, that it was denied.

Speaker Change: 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.

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

Speaker Change: 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.

Speaker Change: Alright, thanks for that.

Speaker Change: No.

Speaker Change: Back on the on the New York piece. So there there is a.

Speaker Change: New York legislation, that's called the affordable gas transition act that that we can it limits the amount of free footage or actually zeroes out the the free footage it's allowed for for new gas customers. So you know.

Roger D'Alentonio: We 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, the Commission does see the need for a capacity upgrade, so they're not denying the basis for it. The second is, while they've denied it, 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's changed so that they're not accepting our load forecast.

<unk> increased the amount of.

Speaker Change: Contribution needed to get gas service, which would increase upfront cost or you know homes et cetera.

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

Speaker Change: 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.

Speaker Change: 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: 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. It's more that with the policy direction that BC is going with CleanBC, there's significant uncertainty right now on how BC will meet some fairly aggressive emissions targets. What does that mean for solutions that have 56 years of life, like the OCDU pipeline upgrade, relative to what the long-term forecast is versus the near-term capacity shortfall? For us, it's really incumbent 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?

Speaker Change: On the Corona situation, where we serve electricity and natural gas.

It is a great way for us to apply the right.

Speaker Change: Amount of electrification of natural gas.

Speaker Change: And 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.

Speaker Change: Okay 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 going to be more around a variety of scenarios and what is the ability to scale up in your asset mix so you're not building 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? I think it's going to be a change in how we approach load forecasting over the next number of applications and how we get some certainty around how CleanBC, in our instance, goes from policy to specific regulations, so more to come on that for sure. Thanks, Roger.

Speaker Change: 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.

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

Speaker Change: Just seeing the economic growth that's happening there, whether it's a battery factories data centers.

Speaker Change: Semiconductor chip manufacturing.

Speaker Change: 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 you know.

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 a 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. All right. Thanks for that!

Speaker Change: The conversations on manufacturing increasing.

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

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

Speaker Change: Typically decade after decade.

Speaker Change: The other one is in the Midwest I think that the manufacturing.

Speaker Change: Boom that I think we will see in our.

Speaker Change: Seeing and in our main jurisdiction there like Michigan.

Speaker Change: I will definitely lead to you know.

Speaker Change: Additional infrastructure needs additional transmission needs for us.

Speaker Change: 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 incentives for domestic content are really driving some.

Speaker Change: 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 a increase in the pace at which they have to get to a 100% clean energy, which is by 2040 now.

David Hutchins: We'll talk back on the New York piece. So there is a New York law that's called the Affordable Gas Transition Act that can, you know, limits the amount of free footage or actually zeroes out the free footage that's allowed for new gas customers. So it would, you know, increase the amount of contribution needed to get gas service, which would increase upfront costs for, you know, homes, et cetera. There are some other growth limitations in there as well.

Speaker Change: To 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.

David Hutchins: Obviously, we're looking at that and, you know, don't necessarily agree with that policy as well. 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 Fortis perspective. But also, gas and electricity customers are basically almost completely overlapped in Central Hudson's service.

Speaker Change: I appreciate that thank you.

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

Linda: Thank you.

Linda: 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 are.

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 amount of electrification and natural gas and energy solutions to our customers when we can provide both sides of it. So one could be a growth opportunity, but the most important thing is to manage customer affordability at the pace of these transitions. I appreciate that. And that actually leads to kind of the second of my questions.

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

Linda: Give you a little bit.

Linda: More not no wiggle room, but that too.

Linda: <unk> maybe some.

Linda: Surprises and.

Linda: 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.

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

David Hutchins: On the electric side, we've seen another number of system operators increase demand expectations across the continent for a variety of reasons. When we take a look at your service territories, you know, where do you think you could see the greatest upward revision 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.

Linda: Given some of the other moving parts.

Linda: Okay.

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

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

Jocelyn Perry: 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.

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

Jocelyn Perry: 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 so you know as we.

David Hutchins: 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. That's on the back of additional conversations on manufacturing increasing in the area, and of course, Arizona's always a net migration state as well, where we end up with good, strong population growth, typically decade after decade. The other one is in the Midwest.

Jocelyn Perry: We go through the year.

Jocelyn Perry: 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 we'll continue to monitor it as we go through the year and.

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

David Hutchins: I think the manufacturing boom that I think we'll see and are seeing in our main jurisdictions there, like Michigan, will ultimately lead to additional infrastructure needs, and additional transmission needs for us. It's manufacturing, which obviously drives jobs, 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. That's not on the supply side.

Jocelyn Perry: Yeah.

David Hutchens: Obviously, the focus that we have.

David Hutchens: 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 Hutchens: 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.

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

Speaker Change: I don't know if this is for Linda or maybe someone more honed in on the regulatory situation.

David Hutchins: 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. Appreciate that. Thank you. Our next question comes from the line of Linda Ezergailis from TD Cowen. Please go ahead.

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

Speaker Change: Approximately.

Speaker Change: And addresses.

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

Linda Ezergailis: Thank you. I'm just wondering if you can help us understand, just further to Maurice's question, given the lack of wiggle room in your financing and your debt metrics, 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 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.

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

How are your regulated businesses in the U S might have.

Speaker Change: You have to adjust to any sort of new macro environment.

Speaker Change: That's a that's a great question Linda and it it's.

Speaker Change: It's interesting because the Chevron doctrine is held precedents for deference to regulatory bodies for years and years and years and his is an often cited.

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 the 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. But you're right.

Speaker Change: Precedent that are obviously has been used by regulators to I'll say.

Speaker Change: Colored in the around those gray areas, where the legislation hasn't really determined.

Speaker Change: Who has the responsibility to be able to make those calls.

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

Jocelyn Perry: 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.

Speaker Change: But it is.

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

Speaker Change: It changes anything from our perspective is.

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

David Hutchins: It was to give us some financial flexibility for events, particularly around growth that is, you know, either unforeseen 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 it's on us to make sure that we're looking for opportunities. But, as Jocelyn mentioned, we're not dependent on anything other than the funding plan that we laid out pretty clearly at the investor day back in the fall. Thank you.

Speaker Change: But the the.

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

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

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

Speaker Change: 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.

Speaker Change: Yeah.

Speaker Change: 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.

Speaker Change: Yeah, I think FERC.

Speaker Change: 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.

David Hutchins: And maybe just as 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, but the Chevron doctrine that's been in place for 40 years, approximately, and addresses an ability for a U.S. federal agency's reasonable interpretation of any sort of ambiguous statute as being challenged.

Speaker Change: 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.

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 up 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 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.

Speaker Change: 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.

Speaker Change: Moving and we hope it stays.

Speaker Change: At the front of mind from a FERC perspective.

Speaker Change: Thank you.

Speaker Change: Thanks Linda.

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

Michael P. Sullivan: Thanks, Good morning.

Michael P. Sullivan: Maybe Jonathan if you could clarify the comments around the reconsideration of refreshing, Iowa did you say that it would be a parallel process to push through legislation and maybe just kind of.

Speaker Change: Just update on where you think.

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 it 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 isn't clear. So 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 there is a fine line between regulation and policy. 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.

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

Speaker Change: But he asked you Josh Yeah [laughter].

Speaker Change: So.

Josh: 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.

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

Josh: Not.

David Hutchens: Don't really have a good timeline for that where we're obviously shooting for this legislative.

<unk>, which is still newish.

David Hutchens: 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 just think it may make it maybe a little more difficult to legislate by regulation on a going-forward basis if it is challenging. 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 FERC, obviously down to three commissioners, is focused on a couple things clearly. I think the planning and cost allocation, NOPR, has been discussed in depth as being sort of on the front line. It was great to see the interconnection queue final rule come out.

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

David Hutchens: Yeah. So so far we're seeing good reception and hoping to getting that pushed through okay.

Okay, and then coming back to D C.

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

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

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

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

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

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

Mark: This transition around electrification, but obviously BC, 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.

David Hutchins: And this is sort of the next thing in the queue from a bigger, broader transmission policy perspective. One of the benefits, too, of having that closer to the front of the queue is that 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, so we like to see that moving, and we hope it stays at the forefront of mind from a FERC perspective. Thank you. Lynch, Linda

Mark: Three years.

Speaker Change: Well that depends on the jurisdiction.

Speaker Change: 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.

Speaker Change: 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.

Mark Harvey: We have our next question come from the line of Mark Harvey from CIBC. Please go ahead. Thanks, everyone. Maybe, Jocelyn, if you could clarify the comments around the reconsideration of the roe-for-ish in Iowa. Did you say that it would be a parallel process to push through legislation? Maybe just kind of give us an update on where you think that effort is right now in terms of rewriting the legislation in Iowa. He asked you, Jocelyn. So yeah, thanks for the question. It is a parallel path.

Speaker Change: Is it distribution on the company.

Speaker Change: 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 there. They have so much hydro so a lot of most of the conversation as you know like site expansion and around hydro and renewables at this point.

Jocelyn Perry: Reconsideration was filed in December and, obviously, on a parallel path that we're trying to get new ROFA legislation through Iowa. 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.

Speaker Change: It is incumbent on.

Speaker Change: 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.

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 April-ish time frame. In all senses, at this point, it seems that there is a political will to push that through and drive that forward at this point. Yeah, so far, we're seeing good reception and hoping to get that.

Speaker Change: Discussions with.

Speaker Change: 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: Okay. And then coming back to BC, with the year-end now done, just clarification on the equity injection with the equity thickness step-up. Has that been determined?

Speaker Change: Okay. Thanks very much.

Speaker Change: Thanks Mark.

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

Ben Pham: Hi, Thanks, good morning.

Mark Harvey: And what is that amount that has to go in in 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, it may have been a little bit lower.

I was wondering.

Ben Pham: If you can maybe add a bit more.

Ben Pham: Color on Europe.

Ben Pham: Comments on asset rationalization what.

Ben Pham: What conditions are factors.

Ben Pham: It does have a core asset to move into a noncore.

Ben Pham: Asset.

Speaker Change: So that's it.

Speaker Change: I understand the question right is what what are what do we consider noncore assets.

David Hutchins: Okay. And then just if you think broadly around that question around the Okanagan pipeline and gas needs, and you know, this transition around electrification, but obviously, BC struggled with forest fires, wildfires, drought conditions, which has hampered their whole subsurface generation market there. So what conversation goes on around, you know, the sort of reliability and cost stability that gas assets offer versus some of the, you know, pressures that the electric network might have faced for the last couple of years? Well, that depends on the jurisdiction.

Speaker Change: All of our assets that I would say.

Speaker Change: That we define as core as.

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

Speaker Change: Why Aitken Creek was an unregulated asset.

Speaker Change: That that made sense to monetize for a variety of reasons, but one has to take that you know almost $500 million proceeds and use it to invest in the main thing, which is our regulated utility businesses. So with it so from that from that perspective, where 99 and <unk>.

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, 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.

Speaker Change: Change I mean, it almost round to a 100% regulated assets.

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

Speaker Change: Is your non Reg is that the only thing I really like is that.

Speaker Change: Police hydro assets.

Speaker Change: Yeah, Yeah, yeah, the Belize hydro assets are the only.

Speaker Change: Nonregulated assets that we have.

Speaker Change: Okay got it thank you.

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

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

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

David Hutchins: So, most of the conversation is, you know, like site C expansion and around hydro and renewables at this point. 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. Hi, thanks. Good morning. I was wondering if you could maybe add a bit more color to your comments on asset rationalization. What conditions or factors are involved?

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

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

David Hutchens: Yeah I mean, there's this there has had some challenges.

David Hutchens: Other states.

David Hutchens: Some that we operate in something that we have real version and in other states as well you have 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.

David Hutchens: So that's obviously part of the you know the conversation would go to look at a new role for and I was making sure that you know from a from a constitutionality perspective.

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

David Hutchens: 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 in other places as well, but we think and we strongly believe that.

Ben Pham: Does a core asset move into a non-core? 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 in 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. Is your non-reg, is that the only thing really left?

David Hutchens: 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.

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

David Hutchens: 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.

David Hutchens: 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: Is that just the lease hydro assets? Yeah, the Belize hydro assets are the only non-regulated assets that we have. I got it. Thank you. We have our next question come from the line of David Quezada from Raymond James. Please go ahead. Yeah, thanks. Morning, everyone. Just one question for me. I'm just curious.

Speaker Change: Excellent. Thank you appreciate it.

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

Patrick Kenny: Thank you good morning, everybody 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.

David Quezada: Going back to the Iowa roofer 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 roofer you have in other states? Just any commentary around how you see that potentially playing out in the other states?

Patrick Kenny: And then you know it looks like you're fully protected through.

Patrick Kenny: Regulatory approval for now but just.

Patrick Kenny: Just given the three year construction window, how should we be thinking about.

David Hutchins: Yeah, I mean, there have been challenges in other states, some that we operate in, some that we have rover programs in, and other states as well. You have to make sure that you define these rover programs 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 roofer in Iowa is making sure that it, you know, from a constitutionality perspective, and, you know, from the principles of that, that it ends up being a good solid roofer that we can, we know that if challenged, we'll still survive. But yeah, that's already happened. It happened in Texas and other places as well.

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

Speaker Change: Yeah 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 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 increases.

Speaker Change: Increased cost and or scope.

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

Speaker Change: Now Roger.

Speaker Change: They've 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 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. 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. Thank you. I appreciate it. We have our next question coming from the line of Patrick Kenny from National Bank Financial. Please go ahead. Thank you, and good morning everybody.

Speaker Change: He can opine on that as well Roger.

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

Roger: 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.

Roger: 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.

Roger: Late last year Wood fiber site I was there.

Roger: Air on Wednesday, there into a site prep and construction so as we finalize the translation service schedule agreement.

Roger: With updated cost had a construction we ended up adjusting the contribution either construction.

<unk> now has us investing $750 million directly back.

Patrick Kenny: Just on the wood fiber project, I know it's still a relatively small investment, but I was wondering if you could provide a bit more color on the key drivers of the increasing 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 many further potential escalations in construction costs between now and then? Thanks. Yeah, sure. These aren't escalations.

Roger: And the project recovered by the Transportation service agreement over the life of the project.

Roger: Patrick.

Patrick Kenny: I have to note that.

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

Speaker Change: [laughter] good point good point there.

Speaker Change: So and then just back to S&P's report I know you'll be.

Speaker Change: Having further discussions with them throughout the year, but.

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

Speaker Change: 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. So, it shouldn't be a read through that this was a project increase in 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. So, he can apply it to that as well. Roger.

Speaker Change: And then I guess.

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

Speaker Change: Undertaking ahead of the next wildfire season.

Speaker Change: Yeah, So we have been involved and.

Speaker Change: <unk> engaged in trying to find.

Speaker Change: Finding the best ways to mitigate.

Speaker Change: Climate 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.

Roger D'Alentonio: Thanks, David. Morning, Patrick. Dave has it right.

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, and I was there on Wednesday.

Speaker Change: We can coordinate with our emergency services when there is a fire all of those things and we also do that externally.

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

Speaker Change: 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 prep and construction now. So, as we finalized the transportation Service Scheduler agreement with updated costs ahead of construction, we ended up adjusting the contribution aid to construction, which now has us investing 750M directly in the project recovered by the transportation service agreement over the life of the project. Patrick, I'll have to note that that might be the first time I've heard of $750 million not being that big of a project. Good point, good point, David.

Speaker Change: It's it's incumbent on us to.

Speaker Change: Make sure that we're doing all the things necessary.

Speaker Change: Our jurisdictions to mitigate it now we think we are now.

Speaker Change: Just on what we know today as we as we learn and Nomura as a sector grows there.

Speaker Change: And 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 at where.

David Hutchins: So, 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 proactive activities you might..., you know, undertaking ahead of the next wildfire season.

Speaker Change: Gaining across the entire 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.

Speaker Change: Yep.

Speaker Change: Okay. That's great. Thank you.

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

David Hutchins: Yeah, so we have been involved and engaged in trying to find the best ways to mitigate, well, 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 across the broader North American utility sector. There are a lot of good ideas. There is a laundry list of things that you can do to mitigate wildfire impacts.

Michael P. Sullivan: Hey, everyone. Good morning.

Michael P. Sullivan: Hey, Michael.

Michael P. Sullivan: It is just just a quick one back to the MISO.

Michael P. Sullivan: Am I sort of tranche two process I think you mentioned.

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

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

Michael P. Sullivan: 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.

Michael P. Sullivan: Probably until summer sometime.

Michael P. Sullivan: Okay, Great and then just coming out of the U S 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 it. Now, we think we are now based on what we know today, and as we learn and know more, and as the sector grows its knowledge of this and learns and 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 getting and that we're gaining across the entire sector with the expectations of the rating agencies to make sure that we've got this covered and that we're all talking on the same terms and have the same level of expectations of what that means. So I'll probably. Okay, that's great. Thank you. We have our next question coming from the line of Michael Sullivan from Wolfe Research. Please go ahead. Hey, everyone. Good morning, and Michael.

Michael P. Sullivan: In renewables build out strategy there.

Michael P. Sullivan: 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.

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

Michael P. Sullivan: So then the larger Tucson electric power.

Michael P. Sullivan: Portfolio, but we do see this as definitely as a positive.

Michael P. Sullivan: We don't necessarily need it now.

Michael P. Sullivan: Because we have a lot of.

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

Michael P. Sullivan: But it is something that we now see as a.

Michael P. Sullivan: 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 a very rigid or.

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

Michael P. Sullivan: It is. Just a quick one back to the MISO-TRANCH2 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?

Michael P. Sullivan: 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.

David Hutchins: 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 would get a good view of that, into that level of project detail, you know, probably until summer sometime. Okay, great. And then just coming out of the UNS rate case, and now that you've got the SRB there, 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. 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 from the larger Tucson Electric Power portfolio.

Michael P. Sullivan: Based on what we know today.

Speaker Change: Great. Thanks, so much.

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

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

Panic James: Hi, Good morning, Thank you for taking my questions.

Panic James: 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 for contingent staff elsewhere either.

Panic James: ITC or across the organization.

Speaker Change: So what was the last part of contingent what.

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.

Speaker Change: Okay.

Speaker Change: Okay.

Speaker Change: Yes.

Speaker Change: Elsewhere.

Okay, Yeah. So.

Speaker Change: The whole our whole a multi pronged approach here is to get the injunction removed for from those tranche one projects. So that we can continue getting those projects developed.

Speaker Change: The parallel piece that I mentioned theres actually two parallel pieces here one is to get the I will roll for a new I would 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 earlier too is the phone.

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 our integrated resource plan based on what we know today. 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 of Tanner James from Bank of America. Please go ahead. Hi, good morning.

Speaker Change: On looking to get some level of.

Speaker Change: Of Federal Rover.

Speaker Change: And the and the planning and cost allocation <unk>. So those are those are the kind of the three things that we're looking at contingent.

Speaker Change: 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 ROFR proceedings affect your strategy regarding MISO-TRANCH2 projects and further planning in the region? And then, in the event TRANCH1 projects could be affected, are there opportunities for contingent spend elsewhere either at ITC or across the organization? So what was the last part of contingent spend? I missed the last part here, but yeah, I'll continue to spend money elsewhere. Yeah, so obviously, 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.

Speaker Change: 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.

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

Speaker Change: Alright, great. Thank you very much.

Speaker Change: Thank you.

Speaker Change: There are no further questions I would like to turn the call back to Ms <unk>.

Speaker Change: 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.

Speaker Change: Yeah.

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

David Hutchins: One is to get the Iowa ROFR, a new Iowa ROFR, 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 ROFR in the planning and cost allocation 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 or not, and remember the MISO Long-Range Transmission Plan is a big piece of the planning process, but there are also the annual MTEP 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, et cetera. So all of those things, we're always looking for contingent spend, for sure.

Speaker Change: Cool.

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Tanner James: All right, great. Thank you very much. Thank you. If there are no further questions, I would like to turn the call back to Ms. Amayma. 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.

Speaker Change:

Speaker Change: Yes.

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Speaker Change: [music].

Stephanie Amaimo: 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.

Speaker Change: Hum.

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