Fortis Inc. Aktie

Good morning, everyone, and welcome to the 2026 Annual General Meeting of Shareholders of Fortis Inc. I am Stephanie Amaimo, Vice President of Investor Relations, and I'm pleased to support the facilitation of our meeting today.

Before we get started, we would like to acknowledge land on which we gather today as the ancestral homelands of diverse indigenous groups, including the Beothuk, Mi’kmaq, Innu, and Inuit. If you are joining us online, please take a moment to acknowledge the first peoples of the lands in which you call home. This is a hybrid meeting, allowing both in-person and online attendees to fully participate. If you've already voted by proxy, you do not need to vote again. If you have not already voted, registered shareholders and duly appointed proxy holders are eligible to vote during the meeting, either in person or via the online Lumi platform.

Only registered shareholders and duly appointed proxy holders may ask questions during the formal conduct of business. And if you're in person today, please proceed to the nearest microphone. If you're online, please submit your questions via the messaging tab. Motion-specific question will be addressed as each item of business is considered. General questions will follow management's remarks, and we have reserved 20 minutes at the end for Q&A.

With that, I will now invite the Chair of our Board, Jo Mark Zurel, to call this meeting to order.

Thank you, Stephanie. All right. Well, thank you. I'm pleased to call the 2026 Annual General Meeting of Shareholders of Fortis Inc. to order. On behalf of my Board colleagues, I would like to welcome you to the Fortis Energy Center. We would also like to welcome everyone attending online. Before we begin the formal part of the agenda, I would like to briefly comment on a few key Board highlights from 2025.

First of all, we are enormously proud of our strong governance practices, which enable our Board to have optimal strategic oversight, ensure effective risk management and protect shareholder interests. In 2025, the Globe and Mail ranked Fortis first among 206 public companies in Canada for our strong corporate governance practices. I would also like to highlight Fortis' strong commitment to delivering long-term value to our shareholders. The Board was once again pleased to increase Fortis' common share dividend for the 52nd consecutive year.

You'll hear more about our performance and our plans for the future during management's presentation. This year, we are asking you to elect 12 directors to the Fortis Board, 11 current directors and 1 new nominee. Tracey Ball is retiring from the Fortis Board after 12 years of exceptional service as a director, including 4 years as Chair of the Audit Committee. Throughout her tenure, Tracy provided deep financial expertise and guided Fortis through a successful pivot to an organic growth strategy. We extend our sincere gratitude to Tracy for her dedication and meaningful contributions. We are pleased to welcome [ Mary Hemington ] as a first-time nominee. She brings extensive experience across the energy, infrastructure and financial sectors that will add to the Board's strength. We also want to recognize and thank our continuing directors for their strong oversight and steadfast commitment to Fortis. The nominees offer a strong mix of skills, experience and perspectives that will support our continued collective success.

As we reflect on our progress over the past year and the opportunities ahead, your Board remains committed to ensuring a successful and sustainable Fortis for years to come. On behalf of the Board, I also want to give recognition and thanks to all Fortis employees for their dedication and excellence, which have resulted in another successful year. With me at the podium this morning are David Hutchens, your President and CEO; Jocelyn Perry, Executive VP and Chief Financial Officer; and Jim Reid, Executive Vice President, Sustainability and Chief Legal Officer. Members of our Board of Directors and management team are present with us in person today.

The meeting will follow the notice of meeting in the proxy circular. The main items of business are: number one, to receive the financial statements for the year ended December 31, 2025; two, to elect our directors; three, appoint the auditors and authorize the directors to fix their remuneration; and four, an advisory vote on executive compensation.

Following the conclusion of the formal portion of this meeting, we will hear from David and Jocelyn for management's presentation. Computershare Trust Company of Canada is our transfer agent and registrar of our common shares. And with your consent, I appoint Colleen Nielsen and [ Augustin Nara ] of Computershare to act as scrutineers for this meeting. I further appoint Jim Reid as Secretary of the meeting.

I have been advised that all documents required to be delivered to shareholders were mailed on or before March 31, 2026, to the shareholders of record as of March 20, 2026. The scrutineers have confirmed that there is a quorum present. As notice has been properly given and a quorum is present, I can confirm that this meeting is validly constituted for the transaction of business. We will now present the consolidated financial statements for the year ended December 31, 2025. The audited annual financial statements and MD&A were filed with securities regulators and posted on our website on February 12, 2026.

Please hold questions on the financial statements until after the remarks from management. Before we move to the resolutions, I'll explain -- I'll take a moment to explain our voting practice. Most shares were voted by proxy in advance and tabulated up to the proxy cutoff time of 10:30 a.m. Newfoundland Daylight Time on Tuesday, May 5, 2026. We will also tabulate votes cast in person and online during the meeting. For those of you in the room receiving ballots to complete your voting, we ask that you pass your ballots to the scrutineers or raise your hand so that your ballots may be collected.

Online voting will open after the first motion is read and close after the final motion is read. The first resolution is the election of directors. We are proud to put forward 12 highly qualified candidates for election to the Board this year. The resolution is set out on Page 11 of the circular, and I'll call on William Greene to place the motion before us.

I hereby move that Pierre Blouin, Lawrence Borgard, Maura Clark, Margarita Dilley, Julie Dobson, Lisa Durocher, [ Mary Hemington ], David Hutchens, Gregory Knight, Gianna Manes, Donald Merchand and Jo Mark Zurel be elected as directors of Fortis to hold office until the close of the next annual meeting or until their successors are elected or appointed.

Thank you. I'll ask Grace Chafeto second the motion.

I second the motion.

Thank you. We'll now proceed to a vote.

[Voting]

For registered shareholders or appointed proxy holders who have not yet voted, you may do so now either online or by returning your ballot to a scrutineer in the room. Based on the proxy vote tabulation, each of the nominees received more votes in favor than votes withheld and that no nominee received less than a 96% favorable vote. I declare all director nominees elected. The next resolution is to appoint the auditors and authorize the directors to fix their remuneration as discussed on Page 11 of the circular.

I invite Stephanie Daley to make a motion.

I hereby move that Deloitte LLP be appointed auditors of Fortis until the close of the next annual meeting or until their successors are appointed and that the directors be and are hereby authorized to fix the remuneration of the auditors at such an amount as they may, in their discretion, determine.

Thanks, Stephanie. I will ask [ Mary Beth Evans ] to second this motion.

I second the motion.

Thank you. Is there any discussion? We will now proceed to a vote.

[Voting]

Based on the proxy vote tabulation, over 99% of the proxy votes were cast in favor of the appointment of Deloitte LLP as auditors. I therefore declare the resolution carried. The next item of business is the advisory vote on Fortis' approach to executive compensation as described on Page 12 of the circular. I ask Andreas Murphy to propose the resolution in this regard.

I hereby move on an advisory basis and not to diminish the role and responsibilities of the Board of Directors of Fortis, the shareholders of Fortis accept the approach to executive compensation as described in the Compensation Discussion and Analysis section of the Management Information Circular of Fortis dated March 20, 2026.

Thanks, Andreas. I will ask Austin Duff to second the motion.

I second the motion.

Thanks, Austin. Is there any discussion relating to this item of business? We'll now proceed to a vote.

[Voting]

The proxy results indicate that over 95% of the shares voted by proxy accept the company's approach to executive compensation, and I therefore declare the advisory resolution carried. All resolutions have been moved and seconded. We will now close online voting and ask the scrutineers to calculate the final results. While this is taking place, I would like to thank our shareholders who voted this year, whether you voted today or in advance of the meeting. We appreciate your continued participation.

Final voting results will be published this afternoon in a media release available on the Fortis website and filed on SEDAR+ and EDGAR. I will now ask our scrutineers to confirm the voting results. Based on votes received by proxy prior to the proxy cutoff time and votes received online and in person today, I'm pleased to announce that all motions have been carried. This concludes the formal business of the meeting.

Before I pass things over to David and Jocelyn for management's presentation, I will ask Melissa Hardy for a motion to terminate.

I hereby move that the meeting be terminated.

Thanks, Melissa. Will Gordon Payne second that motion?

I second the motion.

Thanks, Gord. I declare the 39th Annual General Meeting of Fortis closed. We'll now move to management's presentation followed by Q&A.

Thank you, Jo Mark. As a reminder, if you're in the room today and would like to proceed to ask a question, please come to the nearest microphone at the end of management's presentation. For those online, select the messaging icon to the left of your screen and type your question.

Please note that David and Jocelyn's statements may include forward-looking information. Details regarding forward-looking information are displayed on the screen and can also be found in our 2025 MD&A. And as updated in our first quarter report to shareholders, actual results can differ materially from the forecast projections included in the forward-looking information presented today. Unless otherwise indicated, all financial information referenced is in Canadian dollars.

I will now pass things over to David and Jocelyn for management's presentation.

Good morning, and welcome to Fortis Place. Once a year at our AGM, we have the opportunity to see some familiar faces, and we are pleased to have you back. For those online, thank you for being with us. Before we get into our results, I'd like to introduce members of our senior leadership team.

Please stand as I call your name. Previously introduced by our Chair, we have Jocelyn Perry, Executive Vice President and Chief Financial Officer; Jim Reid, Executive Vice President, Sustainability and Chief Legal Officer. We also have Stuart Lochray, Executive Vice President, Strategy and Business Development. And I'd also like to take a moment to acknowledge a member of our executive team who will be retiring later this month, Mr. Gary Smith. Gary has had an incredible 42-year career with Fortis, serving in leadership roles across our utilities and boards. He's been an integral part of Fortis' growth and success, and we're incredibly grateful for his many contributions.

Today, we're pleased to be joined in person by Gary Murray, President and CEO of Newfoundland Power, along with the CEOs of our other utilities and members of their Boards who are joining us virtually. Fortis' success is built on a strong local operating model with each utility led by a local executive team and a majority independent Board. This structure keeps decision-making close to our customers, communities and supports constructive relationships with our regulators and continues to drive strong operational performance across our footprint.

As we look at Fortis today, we operate across Canada, the United States and the Cayman Islands. We serve 3.5 million electricity and natural gas customers, and we are 100% regulated with 95% of our assets focused on energy delivery. Our poles, wires and gas lines are long-lived assets with an outsized role. The delivery of reliable, affordable energy requires skill, discipline and deep local expertise. Our utilities provide the stability that customers, businesses and investors depend on every day. Supported by geographic and regulatory diversity and strong local relationships, our approach has served us well over time and continues to support long-term value for our shareholders.

Turning now to 2025. It was a year defined by focus and momentum, helping us deliver energy that goes further for our customers and communities. Across Fortis, we delivered safe, reliable service, kept affordability front and center and continued to strengthen the infrastructure our communities rely on every day. This focus translated into strong operational performance, solid financial results and continued rate base and earnings growth. Strong results matter, but how we deliver them matters just as much.

For Fortis, that means operating with a customer-first approach in every decision. We understand the economic pressures our customers are facing. Through operational efficiency, disciplined capital planning and innovation, we're finding smarter, more cost-effective ways to keep energy as affordable as possible. This includes making pragmatic investment decisions, such as Tucson Electric Power's conversion of 2 generating units to natural gas at the Springerville Generating Station. This approach costs far less than building comparable new resources. It extends the life of existing infrastructure and reduces emissions by 40%.

We also support customers directly through energy efficiency and bill assistance programs, such as Central Hudson's new enhanced energy affordability program. In 2025, Fortis invested $320 million in energy efficiency initiatives to help families and businesses reduce energy use and lower costs. Affordability will continue to be an important part of how we plan, invest and operate. Safety is at the heart of everything we do at Fortis. Protecting our employees, the contractors we work with and the communities we serve is core to our culture and how we operate.

In 2025, we achieved our best safety performance on record, reflecting a strong, consistent focus on safety at every level of the company. We're proud of this milestone, but our work on safety is never done. In 2025, we invested a record $5.6 billion to expand and maintain our energy networks. These investments allowed us to achieve one of our strongest reliability performances, delivering energy to our customers over 99.9% of the time.

Our teams are advancing vital energy projects. At FortisBC, the Tilbury LNG storage expansion project will enhance British Columbia's energy resilience by supporting peak demand and providing a dependable backup supply during extreme weather events or other emergencies. This work is being advanced in close collaboration with our indigenous partners. By modernizing our transmission and distribution grids, deploying new technologies and connecting new energy sources, we're meeting rising demand and delivering lasting value for customers and local economies.

At ITC, our 5-year capital plan includes transmission projects across the Midwestern United States to enhance capacity and integrate new resources. It also includes critical interconnections such as the Big Cedar Load Expansion project, which will power 2 data centers in Iowa. As a result of the substantial data center load associated with this project, network transmission rates for ITC Midwest customers are expected to be reduced by 20% by the end of the decade. This outcome reflects how large new customers can reduce rates while maintaining long-term grid reliability.

We are also designing and operating systems to withstand today's extreme weather events and the climate conditions we expect in the decades ahead. Our 2026 climate resiliency report outlines how our utilities are deepening their understanding of the climate risks and using data-driven insights to strengthen our energy networks. Innovation continues to play an important role in how we serve customers and operate our business. Through the Fortis innovation network and partnerships with industry and start-ups, we are leveraging AI and new technologies to enhance customer experience, advance safety and increase operational efficiency.

For those Newfoundland Power customers who are with us today, you may already know Alex, Newfoundland Power's virtual assistant. Alex is just one example of using AI to improve the customer experience by providing 24/7 support for customer inquiries. And this kind of innovation is happening across Fortis. We continue to make steady progress in decarbonizing and delivering cleaner energy for our customers. Fortis remains committed to a coal-free generation mix by 2032 and advancing toward net zero emissions by 2050.

In Arizona, Tucson Electric Power has significantly expanded its renewable energy portfolio and storage. In 2025, TEP brought one of Arizona's largest battery storage facilities into service, the 200-megawatt Roadrunner Reserve system, which stores hours of low-cost energy for use during peak periods. A second 200-megawatt unit is expected to be completed this year. TEP also has added its largest solar resource to date, the 160-megawatt Babacomari solar facility and recently placed into service another 100-megawatt solar and storage system at the Wilmot Energy Center.

Together, these resources are strengthening the grid reliability and supporting clean energy.

Now I will turn things over to Jocelyn for an update on our financial performance.

Thank you, David, and good morning to everyone. I'll begin my presentation with a look back at our 2025 results. Our regulated growth strategy continues to deliver strong financial results. As David mentioned, in 2025, we invested a record $5.6 billion in capital to strengthen our systems, supporting 7% rate base growth. We reported annual net earnings of $1.7 billion or $3.40 per common share for 2025. Adjusted earnings per common share or EPS was $3.53, representing a 5% growth for the year, excluding the impact of foreign exchange.

This performance was driven by rate base growth and the advancement of major capital projects right across our utilities. We released our first quarter results yesterday with net earnings of $501 million or $0.99 per common share. During the quarter, we invested $1.4 billion of capital in our systems and our annual $5.6 billion capital plan continues to progress as planned.

Looking ahead, our $28.8 billion 5-year capital plan remains on track and reflects $2.8 billion higher from the previous plan. This 100% regulated plan is low risk with only 21% related to major capital projects. Over the next 5 years, we expect rate base to increase by approximately $16 billion through 2030, supporting average annual rate base growth of 7%. We ended the year in a strong liquidity position with nearly $4 billion available on our credit facilities. We issued $2.7 billion of long-term debt, including our first hybrid issuance.

As we look forward, our capital plan is expected to be funded largely with cash from our operations and utility debt and equity from our dividend reinvestment plan. Fortis is well positioned to invest beyond our 5-year capital plan to support low growth that facilitates the interconnection of new energy resources. This includes significant transmission investments and the addition of new large customers in manufacturing, data centers and the mining sector.

Dividends paid per common share increased to $2.49 in 2025, 4% higher than 2024. As noted earlier, Fortis extended its record to 52 consecutive year of dividend increases and continues to target an annual dividend growth of 4% to 6% through 2030. Our history of strong returns continued in 2025 with a 1-year total shareholder return of nearly 24%. Over a 20-year period, Fortis has delivered average annual total shareholder return of approximately 10%, exceeding benchmark indices. And we continue to expect to deliver stable, compelling returns over the long run.

I'll now turn things back to David. Thank you.

Thank you, Jocelyn. Before we conclude, I want to recognize the people and partnerships that underpin Fortis' success. First, our people. Our achievements are driven by the talent and dedication of our teams. We remain committed to empowering employees and creating a workplace where they feel respected, motivated and engaged. Together with our employees, Fortis Companies remain active members of our communities. And in 2025, we contributed approximately $14 million and thousands of volunteer hours to support those communities. This included being a proud major sponsor of the 2025 Canada Summer Games held right here in Newfoundland and Labrador.

Next, our partnerships. Collaboration continues to drive progress at Fortis. We work closely with our communities, regulators, indigenous partners and industry to create value for our customers. In 2025, Fortis was honored to receive the International Edison Award from the Edison Electric Institute for the Wataynikaneyap Transmission Power Project, Canada's largest indigenous-led electricity project built in partnership with 24 First Nations.

Finally, governance and integrity, a foundation that supports everything we do at Fortis. Strong governance has long been a cornerstone of our company. We're fortunate to have a highly qualified, experienced Board of Directors, providing rigorous oversight and strategic guidance, a strength that was again recognized in 2025 when the Globe and Mail ranked Fortis first for corporate governance.

Looking ahead, Fortis is strong, focused and well positioned for the future. Our low-risk, fully regulated utility business, supported by experienced local leadership teams and more than 140 years of service provides a proven platform for growth. As the energy landscape evolves, we will continue to deliver the safe, reliable and affordable energy that our customers expect and sustainable long-term value for our shareholders. On behalf of the entire leadership team and Board of Directors, thank you for your confidence and support. We are excited about the opportunities ahead for Fortis.

I'll now turn the meeting over to Stephanie to begin the question-and-answer period. Thank you.

Thank you, David and Jocelyn. We will now move to our question-and-answer period. First, we received 3 questions that were sent in advance. So with that, these came in from Mr. Derrick Hutchens. The first question reads, the Board's incentive plan for senior executives is very lucrative when corporate performance is strong and targets are met.

Mr. Chairman, can you tell us what checks and balances are in place when decisions are made by present or past senior executives that results in $63 million of shareholders' money being written off in our Belize and Turks and Caicos holdings? And if there is any means to recoup incentive money paid to these senior executives when such money losing investment decisions have been made.

Thank you for the question. The Board takes capital allocation discipline, executive accountability and stewardship of shareholder capital very seriously. With respect to the $63 million loss on the sale of FortisTCI and Belize assets, roughly half of that related to income tax expense associated with repatriating capital back to Canada. These taxes would have been incurred at some point regardless of whether Fortis sold the assets or not.

The decision to sell these assets was a Board endorsed strategic choice to redeploy capital into higher growth, low-risk regulated jurisdictions. This redeployment supports Fortis' long-term rate base growth strategy and is expected to enhance earnings stability and shareholder value over time. Fortis maintains an executive compensation and clawback policy aligned with the SEC, New York Stock Exchange and Sarbanes–Oxley requirements, which permits recoupment of incentive compensation in cases of accounting restatement due to material noncompliance or instances of fraud gross negligence or intentional misconduct. The losses on the asset dispositions do not meet these criteria.

Thank you. The next question reads, Mr. Chairman, one of the responsibilities of the Audit Committee is overseeing the rotation of the audit partner and the independent auditor as necessary. Deloitte has been our auditor since 2017. Can you tell us if the lead audit partner and engagement reviewer have been rotated out in the last 7 years? And if not, why not?

Yes. Deloitte was appointed as the new auditor for Fortis Inc. in 2017 following an extensive request for proposal and evaluation process. As Fortis is an SEC issuer, Deloitte is required to rotate the lead audit engagement partner every 5 years, and I can confirm that the rotation did occur for the 2022 audit and will happen once again in 2027. The Audit Committee is heavily involved in the selection of the lead audit partner to ensure appropriate balance between audit and industry expertise, business familiarity and independence.

Similarly, the engagement quality reviewer has also been rotated every 5 years in accordance with requirements. The Audit Committee will continue to evaluate Deloitte's performance and independence to ensure Fortis shareholders can rely on the external audit process.

Moving to the last question here from online. Mr. Chairman, given the high level of honesty and integrity within the Board, can you inform us what parties and what individuals were in receipt of political donations in excess of $5,000 in 2025?

Yes. Fortis believes in supporting the democratic process and contributes to political parties, candidates and other political entities as permitted by law and in alignment with our values and ethical standards. We manage advocacy and political engagement consistent with our Fortis business model. Laws and local political environments vary across the many jurisdictions that we operate within. Therefore, our utilities directly oversee lobbying and political contributions. Fortis Inc. only makes political contributions here in Newfoundland and Labrador.

We are committed to transparency of this support, whether we participate directly or through trade associations or other organizations that involve -- that engage in political activities. Fortis has annually disclosed all political contributions of CAD 500 or more made by Fortis Inc. and its subsidiaries since 2020. A summary of our 2025 political donations is not yet available, but is scheduled to be posted to our website this summer.

Great. Thank you. Now I'll open it up to the room to see if there's any questions here. Having received no further questions, this concludes our Q&A session.

I would like to turn it over to Jo Mark for final comments.

Thank you, Stephanie. On behalf of our Board of Directors, we would like to thank the entire Fortis team, including those in our operating companies for our strong continued performance in 2025. Finally, I would like to thank our shareholders and other stakeholders who participated both in person and online today.

With that, I will declare the meeting adjourned. Thank you.

Thank you for standing by. This is Betsy, the conference operator. Welcome to the Fortis Inc. First Quarter 2026 Results Conference Call. [Operator Instructions]

The conference is being recorded.

[Operator Instructions]

I would now like to turn the conference over to Stephanie Amaimo, Vice President, Investor Relations. Please go ahead, Ms. Amaimo.

Thanks, Betsy, and good morning, everyone. Welcome to Fortis' First Quarter 2026 Results Conference Call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries.

Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today.

Non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our first quarter 2026 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. Before getting into the results, I'd like to take a moment to acknowledge Gary Smith, Executive Vice President of Operations and Technology, who is retiring at the end of this month. Gary has had an incredible 42-year career with Fortis, serving in leadership roles and boards across our utilities. He has been integral to Fortis' growth and success, and we're incredibly grateful for his many contributions. We truly wish Gary all the best in retirement.

We are pleased with our start in 2026, building on the momentum from last year. During the first quarter, we delivered safe and reliable service while advancing our long-term growth strategy. We invested $1.4 billion of capital into our utility systems and reported earnings per share of $0.99.

We also successfully concluded the UNS Gas rate case, reaching a constructive regulatory outcome for our customers and stakeholders. With 25% of our capital plan invested in the first quarter, we remain well positioned to execute our $5.6 billion of planned investments in 2026. Major capital projects continue to progress. A significant milestone was achieved at the Big Cedar Industrial Center, where ITC completed the substation that will support 300 megawatts of load growth for the first data center.

Transmission upgrade work for the Big Cedar load expansion project is also underway at this location to serve another 1,600 megawatts of new data center load expected to be completed by 2028. At UNS, the ACC approved an amendment to the Springerville Generating Stations certificate of environmental compatibility to allow the conversion from coal to natural gas generation. This approval advances TEP's plan to extend the operational life of the facility and supports long-term customer affordability and system reliability.

As we have discussed in the past, our utilities continue to prioritize capital investments focused on operational need and customer bill impacts. At ITC, with a substantial data center load anticipated to come online in Iowa, ITC Midwest network transmission rates are expected to be reduced by approximately 20% by the end of the decade. At TEP, the coal to natural gas conversion at Springerville Generating Station will be approximately 10% of the capital cost of new gas generation. This is an economical solution benefiting our customers and the communities we serve.

Also at TEP, the 300 megawatts of load growth for the data center associated with the approved energy supply agreement is expected to save a typical residential customer approximately USD 13 per month once at full production, thanks to this additional revenue. Overall, affordability continues to be an integral part of how we plan, invest and operate across our group of companies to ensure cost-effective service for our customers.

Turning now to Slide 7. With our 2026 and 5-year capital plans on track, we continue to expect average annual rate base growth of 7% through 2030. Above and beyond the plan, our teams continue to drive forward a strong slate of incremental growth opportunities.

First, at ITC, the MISO LRTP portfolio of projects is advancing. For Tranche 2.1, ITC expects USD 3.3 billion to USD 3.8 billion of investment beyond 2030 for projects that have been awarded and are not subject to competitive bidding. For projects that are subject to a competitive process, ITC is actively evaluating opportunities and preparing bids as appropriate.

As it relates to competitively bid projects, ITC, alongside its grid acceleration coalition partners, filed a joint complaint at FERC in April against the competitive bidding processes in MISO and SPP. The complaint urges the commission to either direct MISO and SPP to exempt transmission projects from the solicitation process when those projects facilitate new generation or large load interconnection or suspend the solicitation process entirely for the next 5 years.

The complaint emphasizes that competition delays much needed infrastructure development, slowing down AI implementation through regulatory red tape and increasing cost to customers. While complaints at FERC are not subject to a fixed time line, the coalition has asked the commission to issue a ruling by July 16.

Shifting now to load growth opportunities in Arizona. In April, key contractual contingencies tied to the approved ESA for 300 megawatts advanced at TEP with credit support now in place. As you may recall, this initial phase will leverage existing and planned capacity with a ramp-up expected in 2027 and continuing through 2029.

Beyond this ESA, negotiations continue for an incremental 300 megawatts of capacity to support a potential build-out of 600 megawatts at this site. TEP is also in active negotiations for additional capacity at a second site in the range of 500 to 700 megawatts. If agreements are finalized for these subsequent phases, we estimate new generation investment in the range of USD 1.5 billion to USD 2 billion would be required.

Our track record of long-term sustainable growth reflects the strength of our regulated businesses and supports our commitment to deliver 4% to 6% annual dividend growth through 2030.

Now I will turn the call over to Jocelyn for an update on our first quarter financial results.

Thank you, David, and good morning, everyone. For the quarter, we reported net earnings of $501 million or $0.99 per common share. As shown on the slide, we have identified the EPS drivers for the quarter by segment. Our Western Canadian utilities contributed a $0.04 increase in EPS, largely driven by capital investments and timing of operating costs. At ITC, EPS increased by $0.02, largely due to continued capital investment and related rate base growth.

For our U.S. electric and gas utilities, EPS decreased by $0.02. Lower earnings at UNS Energy were driven by wholesale market conditions, timing of planned generation maintenance costs, milder weather as well as regulatory lag for rate base not yet included in rates. Moderating this was higher earnings at Central Hudson due to a shift in quarterly revenue, timing of operating expenses as well as rate base growth.

The Corporate and Other segment reflects higher finance costs and unrealized losses on foreign exchange contracts. While not shown on the slide, earnings at our Other Electric segment were largely offset by the disposition of FortisTCI in 2025. In total, the dispositions had a $0.02 dilutive impact on the first quarter results, and we expect a $0.05 dilutive impact for the full year.

Continuing on, foreign exchange had an unfavorable $0.03 impact for the quarter and higher weighted average shares issued under our dividend reinvestment plan impacted EPS by $0.01. On the financing activities for the quarter, our utilities issued $800 million of long-term debt. Additionally, in April, ITC Holdings issued USD 900 million of unsecured notes with proceeds expected to repay maturing debt and short-term borrowings.

Our capital plan is expected to be funded largely from cash from operations, utility debt and our dividend reinvestment plan. Our $500 million ATM program has not been utilized to date and remains available for funding flexibility as required. On the rating agency front, Morningstar DBRS recently confirmed our A low issuer and unsecured debt credit ratings and stable outlook.

Overall, our liquidity position and our funding plan support our strong investment-grade credit ratings. Several regulatory filings advanced in Arizona during the quarter. In February, the ACC issued an order in the UNS Gas general rate application, authorizing an allowed ROE of 9.61% and a 56% equity ratio.

The order also approved a formula subject to a range of plus or minus 50 basis points around the allowed ROE and inclusive of post-test year adjustments. The first rate adjustment under the formula is expected to occur in April 2027. New rates went into effect on March 1. With respect to TEP's general rate application, the ACC staff filed testimony during the quarter, recommending a 9.75% ROE and a 55% equity ratio.

Staff also filed rate design testimony recommending a formula rate framework that closely mirrors the recently approved approach for UNS Gas. Hearings commenced last month and based on the procedural schedule, we continue to expect an order in the fall. That concludes my remarks.

I'll now turn the call back to David.

Thank you, Jocelyn. To wrap up, we are off to a solid start in 2026 with first quarter results aligned with our expectations. Our utilities are executing their capital plans focused on reliability and customer affordability. Looking ahead, we will continue to drive meaningful shareholder value through execution of our 5-year capital plan and delivery of our 4% to 6% annual dividend growth guidance through 2030. That concludes my remarks.

I will now turn the call back over to Stephanie.

Thank you, David. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.

[Operator Instructions]

The first question today comes from Maurice Choy with RBC Capital Markets.

If I could just start, in your prepared remarks, you mentioned that affordability has been an integral part of how you plan, invest and operate across your companies. And you've also shared how TEP and ITC Midwest customers will benefit from your data center initiatives. So with that, given the heightened nimbyism, how would you characterize how data center sentiment among your local stakeholders have evolved since the Q4 call?

Yes. Thanks, Maurice, and thanks for that question. It's obviously a big topic. And if folks understand how you can do data center development correctly, if you make sure that you have the protections in place for the rest of the retail customers, then you definitely can have a positive impact from an affordability standpoint. It's just, in essence, fairly straightforward math when you add some assets that someone else is going to pay for and then you actually have some kilowatt hours that they use that spread the rest of the fixed costs among a larger pie, then it definitely does help.

It is really hard. I'm not going to lie. It's hard to get folks to understand that messaging, but you have to prove it. And that's hopefully what we're going to be doing here as we go forward as we add this contract that TEP has in place for that first data center and with no additional resources needed to supply it, they're paying for the transmission interconnection. And so now it's really just the end result of them using a lot of kilowatt hours and paying for a lot of the system that the rest of the customers would have. So it's an ongoing conversation and ongoing information flow that we have to have out there. But if you are doing it right, you should be making that loud and clear.

Understood. And if I could finish with a question on ITC. Recognizing that the grid Acceleration Coalition complaint was only filed a few weeks ago. I wonder if you had any early feedback from FERC about whether they're moved by your arguments and how you think this will all play out in the coming months towards your mid-July deadline request?

Yes. Let me turn that directly over to Krista Tanner, CEO of ITC, and she's the one who's been at the front of this. Krista?

Yes. Thank you for the question. So obviously, we haven't talked to the FERC since we filed because that would be a ex parte, but we had several meetings beforehand, and we continue to have meetings with other key stakeholders. And I think it's fair to say that everyone understands that there's a problem here.

Now what they will do, whether they will take our options or come up with their own, I think, remains to be seen. But when you have data centers wanting to connect in 24 months or less, and that's precisely how long the competitive solicitation process takes. That's just an untenable situation. And we provided a lot of good data about we will not win the AI race in this country if we don't move faster. So I think those arguments are compelling. I think everyone understands them. So we are optimistic that something will be done, but obviously, we'll have to wait to see the final order before we see what that solution is.

If I could have a quick follow-up. Have you seen a counter complaint being filed with FERC on this?

Haven't seen a countercomplaint. The only thing that proponents of so-called competition have submitted are studies that Gary pick a handful of projects that were competitive that came in, but nothing, I think, really compelling. Again, if you look at the data and the testimony that we filed with our complaint, I think it's really clear that so-called competition has not lowered cost for customers. In fact, it's increased cost in some cases and the cost associated with delay is far greater than any savings you might see.

So really, all that so-called competition has accomplished is delay. And I mean, there's just no evidence to contradict that. Furthermore, we've had a real-world situation where someone won a bid in Wisconsin and then 3 of those substations had to go to variance analysis because they couldn't be completed in time for a data center. So yes, of course, there are other arguments out there. I would not characterize them as compelling, and they have not filed anything.

That's good to know. And my congratulations to Gary on his retirement and all the best.

The next question comes from Robert Hope with Scotiabank.

So it would seem like you've been making some regulatory and contractual progress at TEP regarding the initial 300 megawatts. This would include the $40 million termination fee. Can you speak to what the next steps are for this project to get across the line and what milestones we should be watching?

Yes. I'll turn that over to Susan Gray, CEO of UNS, so that she only says the things that are public.

Yes. Thanks, Dave, and thanks for the question, Rob. We just hit some really major milestones in terms of having that $40 million letter of credit established and payments for the construction agreement to build out the substation and the transmission interconnection. So the site has been prepared and they're starting to build at this point. So Phase 1 is off and running. The next steps are really around expanding the capability at that first site up to a possible 600 megawatts. So the first 300 is underway, now looking at doubling that capacity.

And then the second site that's in Marana, just north of Tucson, we're also negotiating an agreement, a service agreement for that site. And so then it's about -- once we have all of the terms established, we will have to build new generation to serve those additional agreements. And I think the terms of the contracts will help us -- help guide us in terms of what we need to build and when. So those are really the next steps, but really pleased to see that Phase 1 is underway and moving forward.

All right. I appreciate that. And then my follow-up question relates to Phase 2. So when you're thinking about planning for incremental generation requirements to serve the next phase of load there, how are you incorporating increasing delivery time lines for electrical equipment such as generators? Could you potentially look to lock these up a little bit earlier if you are able to get line of sight to an agreement or we'll call it, backstopping from the counterparty?

Yes. I think we would really need to have certainty from the customer that they're going to move forward and have those customer protections in place. In order to -- and I think that's the incentive to get the agreement locked up here so that we can start moving forward with procurement and potentially partnering with a builder to start actually getting those sites going.

The next question comes from Mark Jarvi with CIBC.

Last quarter, you guys said that you thought maybe FERC would start to tie up some loose ends. We saw the decision on transmission operators in New England. Are you expecting more to come? Is there any expectation that they'll address the adders this year?

Yes. Thanks, Mark. We haven't seen any indication. We're hopeful that, that stale docket finally kind of gets pushed aside. And if they do want to address incentive adders that they do it in the fulsome approach that they started that way back when in 2020, which was looking at all the different incentive adders that you could add based on not just the RTO adder, that was in a bucket of several adders, including additions for using new technology, reducing costs, increasing reliability. So if they do set that aside and want to address it, we hope that they would start with a fresh view of those incentives and what's needed on a going-forward basis.

Okay. And then in the last week, there's been some media reports about a potential executive order around some things like dynamic line rating, reconducting for transmission from the White House. Is that something you guys feel like will come through? And what could that mean for ITC, if anything?

I can't say it. That's the first I heard of that. So Krista, is this something that you've heard? So obviously, the things like dynamic line rating and other conductor -- reconductoring for higher capacity is something that we always look at from an affordability perspective, but I had no idea there was an executive order chatter on it. Krista?

Yes. I think there was just something that came out yesterday, Dave, so you're now behind. And yes, there's always discussion about the proper use and are we using dynamic line ratings and other technology enough I think for ITC, we use it, we have used it when appropriate. And when we don't -- when it's not appropriate, we don't.

So I think we're hopeful through the conversations we've had that it wouldn't be an across-the-board mandate or to use it when it doesn't make sense. I think if there is an executive order issue that it would just be for FERC to look at it and consider it, which frankly, they do when utilities do anyway. So I don't see this as significantly moving the needle rather than just advancing the conversation that's already happening.

Understood. And just last question for me. Just some other media reports about DC LNG, Woodfibre expansion. Can you remind us again where the pipe is size right now, if there's the potential to do incremental investments there in DC?

Roger, do you want to take that one?

Yes. Thanks, Dave. There is an opportunity to expand pipe. It would require a debottlenecking further upstream from the current expansion of our pipeline. We haven't entered into discussions yet with Woodfibre, but it's something that we will be looking at, I'm sure, in the near future here.

The next question comes from Benjamin Pham with BMO.

I want to stay at BC. You mentioned the environmental assessment update on the Tilbury storage site. Was that in response to the Middle East situation that's occurring? And maybe just add incremental context on future expansion if that potentially could be accelerated?

Yes. So far, everything that we have been doing has been based on projects that we've had in the queue for quite a while. So nothing that's incremental or increased due to the Middle East. Obviously, there's a lot of attention on LNG. It's having quite the moment now. And that's probably the genesis of that prior question on looking at whether or not you can increase capacity at Woodfibre for additional LNG. But that EA was just the there's a couple of different EAs going on. One is related to the Tilbury tank, the larger size one that we got approved last year.

And the other is for any ultimate additional LNG liquefaction capacity that we can put at the Tilbury site, which is we refer to as Tilbury 2 in that EA process. So nothing that is directly, I'll say, impacted or pushed by the current situation.

Okay. Got it. And maybe switch to the stats that you -- your expectation, the customer impacts from the data center volume integration and particularly the pronounced impacts you're seeing in the U.S. Midwest throughout the decade. Is that something you think is more book to the Fortis especially magnitude? Or is that -- do you think that's more of a broader industry trend that you're anticipating? And maybe just related to that, is there any expectation that this is more of a lot more room for rate base acceleration?

Yes, it is a broader sector. I'll say it's broader depending on how you're doing it. If you're making sure that the data centers are paying for the incremental or marginal generation that's being installed and I'll say, infrastructure in general, that's being installed to supply them and you're recovering that from that data center with all of, of course, the appropriate credit enhancements, et cetera.

And then you are also getting a bit of contribution back to paying for the rest of the infrastructure that's needed to support that. You don't just pop it on the grid and not need to have the ancillary services and all the rest of the support that you get from the overall grid. Then it will have a positive impact for customers. Obviously, ITC is the transmission rate, you're putting a ton of KWH on that system and you're basically doing a few interconnections to get there. So it's got some really good economics as that percentage decrease reflects.

And then in Arizona, same thing. If you're not building even on the next phases, we would make sure that whatever those next phases are that those data centers are paying for that marginal cost of energy and then some so that there is a positive customer contribution. So it is -- if you're doing it right, especially if you're in a region where you're controlling those portions of the cost, whether it's ITC is a transmission-only company or a vertically integrated utility, we have the ability to see quite clearly how that will benefit customers.

And do you think this is maybe a KW to rate base conversion similar to that recent historical trend of OpEx base?

Yes. So there's -- yes, it's all going -- you always have to look at things on a bill basis on what our customers pay. So it does -- anything that puts downward pressure on bills is a good thing. And that's really what we're focused on, not necessarily saying, well, downward pressures allow for additional incremental investments. We're only making the investments that we need to, to provide value to our customers.

So the more offsets we have for those needed investments that don't necessarily pay for themselves. We have a lot of CapEx or OpEx kinds of conversations, steel for fuel, whatever you want to call it, where you are replacing some of the operating costs with capital and still maintaining or even decreasing customers' bills in that sense. But there are things around resiliency and other investments that we have to make that would normally just increase costs. So it is good to have this other side of the ledger helping to keep customers' rates balanced.

[Operator Instructions]

The next question comes from John Mould with TD Cowen.

Maybe just starting with the Tucson Electric rate case and appreciating it's a live rate case. Just wondering if you could provide some initial thoughts on how the parameters in the rate ask have been received and any points of debate so far that may have varied versus what you saw in the UNS gas rate case process that concluded in February and I'm thinking both about the formulaic rate ask and just also the broader points of the rate case.

Yes, John, it's obviously an ongoing rate case. The testimony started a couple of weeks ago, meaning the in-person testimony, of course, most of this is actually done trade and paper testimony, which frankly hasn't -- we haven't seen anything come up in the hearings that would surprise us from a perspective of not already seeing or hearing the conversation or arguments in the written testimony.

So we were really pleased with the UNS Gas outcome. We were the first utility in Arizona. The UNS Gas was to get that formula rate. We see that we're basically having those same types of conversations in the TEP rate case. So I think it bodes well from that perspective, but it's still in the middle of the process. So we'll kind of couch it at that.

Okay. No, that's fair. And then maybe just stepping back one of the broader opportunities above and beyond the existing capital plans. I'd be curious to know just which are you the most optimistic about in terms of -- turning some of those more aspirational opportunities into firm secured investment and whether it's some of the near-term opportunities or items that extend beyond your current capital planning horizon right now?

Yes. We've got a really good slide in our deck that kind of breaks this conversation up into the 2 different time frames. One is what's possible in the -- kind of in the current 5-year capital plan and then what's possible post 5-year capital plan. And obviously, we're generally like most folks focused on getting those near-term opportunities while still working to get those longer-term opportunities that fill in the growth opportunities later on.

But we have a lot of that just in things that are already happening like the rest of the Tranche 1, Tranche 2.1 and wherever MTEP-26 goes, there's a lot of transmission opportunities that are longer term but really, the short-term ones are some additional data center connections that could happen in manufacturers general interconnections, generation and load in ITC's footprint.

And then, of course, the data center developments that we have in Arizona, those can be -- well, they'd love them to be even shorter term, at least from a data center perspective and as quick as possible, but timing and availability of equipment, et cetera, can delay that a little bit.

So we are looking at those opportunities. And we still have a huge additional one that we really aren't talking about yet because we're in the process of developing the integrated resource plans in Arizona, but that's going to spit out some longer-term investment opportunities for us as well. So a very target-rich environment as it were.

The next question comes from Patrick Kenny with National Bank.

Just a quick question on FortisAlberta with, I guess, the number of components here looking for data center projects. And I know I've seen FortisAlberta partner up with a couple of projects. Just wondering if you could walk us through some of those partnerships and help us distill the overall upside potential if and when the Phase 2 allocation does take off in the province.

Yes. Thanks, Patrick. I'm going to kick that over to Janine Sullivan, CEO of FortisAlberta.

Thanks for the question. There certainly is a lot of data center activity, certainly a lot of discussion first happening in the province. And with the ISO having introduced its 1,200-megawatt cap, it certainly is leading to discussions at the distribution level as to how we can interconnect some of the smaller loads that they want more imminently interconnected. So lots of conversations going on between ourselves, the transmission facility owner and operator and the ISO right now as to how we can facilitate the more timely interconnection of some of this data center opportunity for the province sooner than later.

This concludes our question-and-answer session. I would like to turn the call back over to Ms. Amaimo for any closing remarks.

Thank you, Betsy. We have nothing further at this time. Thank you, everyone, for participating in our first quarter conference call. Please contact Investor Relations should you need anything further, and have a great day.

This brings to a close today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.

Thank you for standing by. This is Betsy, the conference operator. Welcome to the Fortis Inc. 2025 Annual Results Conference Call.

[Operator Instructions]

The conference is being recorded. I would now like to turn the conference over to Stephanie Amaimo, Vice President, Investor Relations. Please go ahead, Ms. Amaimo.

Thank you, Betsy, and good morning, everyone. Welcome to Fortis' Fourth Quarter and Annual 2025 Results Conference Call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries.

Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. Non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our 2025 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. Before we get started, I'd like to take a moment to express our gratitude to Linda Apsey, CEO of ITC for her exceptional leadership ahead of her retirement next month. Throughout her tenure as CEO, she has guided ITC with clarity, integrity and a deep commitment to the people and communities that ITC serves. Her steady leadership has strengthened ITC's foundation and helped position the company for continued success long into the future. We wish her all the best in retirement.

And as we look to the future, we are excited to have a long-time executive at ITC, Krista Tanner, succeed Linda in the role of President and CEO, and she is on the call with us today. Her experience and insight will be vital as ITC continues to meet the changing demands of the energy landscape.

Turning to our business highlights slide. 2025 marked another strong chapter in the Fortis story, During the year, we continued to deliver safe and reliable service to the millions of people who depend on us each day. Our utilities invested $5.6 billion in capital, which strengthened our systems, enhanced our resilience and supported the long-term needs of our customers and communities. These investments translated into strong rate base and earnings growth and supported our track record of increases in dividends paid to 52 consecutive years demonstrating the value of our regulated growth strategy.

Fortis was also recognized by the Globe and Mail's Annual Board Games Report with the #1 ranking in governance out of 206 companies in the S&P/TSX Composite Index, reflecting our Board's commitment to best-in-class practices. And today, we released our 2026 climate resiliency report, which outlines how our utilities are responding to climate risks and utilizing data-driven insights to strengthen our energy network.

A strong culture of reliability and safety continues to be the foundation of our utility operations. In fact, 2025 was one of our best years on record for both safety and reliability and reflects continuous improvement relative to our Canadian and U.S. industry averages. A core tenet of our strategy is to operate cost effectively for the benefit of our customers. While we have experienced cost and supply chain pressures over the past few years, we have been successful in keeping controllable operating costs at or below inflation.

Innovative practices like deploying grid-enhancing technology and using AI for targeted vegetation management and equipment inspections are reducing costs while improving reliability for our customers. Our utilities continue to prioritize capital investments based on operational needs and with consideration of the customer bill impact. We also have energy efficiency programs that help customers directly lower their bills and several of our utilities provide low-income discounts and customer bill assistance programs to help those in need.

Our long history of achieving strong shareholder returns continued in 2025 with a 1-year total shareholder return of nearly 24%. Looking back over a 20-year time frame, Fortis has delivered average annual total shareholder returns of approximately 10%, exceeding the returns generated by the benchmark indices. In the fourth quarter, we rolled out our new $28.8 billion 5-year capital plan, our largest to date. The plan consists of a diverse mix of regulated investments across our utilities, primarily focused on transmission and distribution assets.

The plan is highly executable and low-risk with only 21% relating to major capital projects. Over the next 5 years, we expect rate base to increase by $16 billion, supporting average annual rate base growth of 7%. Above and beyond the plan, we are focused on incremental growth opportunities in both the near and long term. At ITC, we are working on pursuing additional customer connections and MISO LRTP projects. As you might recall, ITC expects additional Tranche 2.1 investments between USD 3.3 billion and USD 3.8 billion for projects awarded through the rights of first refusal in Michigan and Minnesota and system upgrade projects in Iowa that are not subject to competitive bidding.

Most of these investments are expected post 2030. ITC continues to evaluate competitive bidding opportunities and any project awarded would be incremental to this estimate. As it relates to retail load growth in Arizona, in December, the Arizona Corporation Commission approved the energy supply agreement for approximately 300 megawatts to support a planned data center in Tucson Electric Power service territory. The project will use existing and planned capacity with the ramp-up beginning in 2027 and continuing through 2029.

The customer will take service under TEP's commission-approved large power service tariff at full tariff rates with no discount. The 10-year contract includes a 75% minimum billing requirement, providing revenue stability regardless of actual energy use and also includes strong credit and security provisions. The energy supply agreement remains subject to contractual contingencies and continues to progress with the developer closing its land lease with Pima County in December 2025, keeping the project on track.

Beyond this initial phase, negotiations continue for an incremental 300 megawatts of capacity to support a full build-out of 600 megawatts at the site. TEP is also in active negotiations for additional capacity at a second site in the range of 500 to 700 megawatts. Just last month, more than 600 acres of land in Morana was approved for rezoning for the second site. If agreements are finalized for these subsequent phases, we continue to estimate new generation in the range of USD 1.5 billion to USD 2 billion through 2030 would be required.

At FortisBC, the BCUC's approval of the Tilbury LNG storage expansion project late last year provides up to $300 million of potential incremental capital subject to the timing of environmental assessment approvals. In 2025, we increased our dividends paid per common share by 4% compared to 2024, marking 52 consecutive years of increases in dividends paid.

Looking ahead, we remain committed to building on this record through the execution of our growth strategy, supporting our 4% to 6% annual dividend growth guidance through 2030.

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

Thank you, David, and good morning, everyone. Before I get into the annual results, I want to briefly touch on our fourth quarter. Reported earnings per common share for the quarter were $0.83, $0.04 higher than the fourth quarter last year. Reported earnings for the fourth quarter were impacted by losses associated with the disposition of our investments in Belize and reported earnings for the fourth quarter of 2024 reflects a refund liability at ITC associated with the MISO-based ROE decision.

Excluding these items, adjusted EPS was $0.07 higher than the fourth quarter of 2024. Strong rate base growth across our utilities was a key driver for the quarter. Unrealized gains on derivative contracts and a favorable impact of foreign exchange also contributed to the increase quarter-over-quarter. The increase was moderated by lower earnings at UNS driven by regulatory lag and milder weather. Higher holding company finance costs as well as lower earnings contributions from FortisTCI and Belize also impacted the quarterly results.

As David mentioned, we delivered strong EPS growth in 2025. Reported EPS was $3.40, $0.16 higher than in 2024. Reported EPS for 2025 reflect losses associated with the disposition of Turks and Caicos and Belize, totaling $0.13 per share, approximately half of which relate to income taxes. Adjusted EPS was $3.53, $0.25 higher than 2024.

On Slide 12, you'll see the adjusted EPS drivers for the year by segment. Our Western Canadian utilities contributed a $0.10 increase in EPS, largely driven by rate base growth including earnings associated with FortisBC's investment in the Eagle Mountain Pipeline project. This growth was partially offset by the expiration of the PBR efficiency mechanisms and a lower allowed ROE effective January 1, 2025, at FortisAlberta.

Our U.S. electric and gas utilities delivered an $0.08 increase in EPS. The increase in earnings at Central Hudson was due to rate base growth and the rebasing of costs effective July 2024. Earnings were also impacted by a change in the recognition of a regulatory deferral for uncollectible accounts effective July 1, 2025, and a contribution to a customer benefit fund associated with the settlement of an enforcement proceeding.

Lower earnings at UNS Energy was due to regulatory lag associated with over USD 700 million of rate base, not yet included in rates as well as lower retail sales due to milder weather and lower margin on wholesale sales. This was partially offset by higher transmission revenues and AFUDC for major capital projects.

Moving to ITC. Continued capital investments and related rate base growth increased EPS by $0.04. The increase was moderated by higher stock-based compensation and higher finance costs. For the Corporate and Other segment, the $0.01 increase reflected unrealized gains on foreign exchange contracts tempered by higher finance costs as well as lower earnings contribution from Fortis Belize. A favorable impact of foreign exchange contributed an $0.08 increase for the year and higher weighted average shares reduced EPS by $0.06, driven by shares issued under our dividend reinvestment plan.

And lastly, while not shown on the slide, other electric earnings for the year were impacted by rate base growth, offset by the disposition of FortisTCI. Looking back over the past 3 years, Fortis has delivered average annual rate base and EPS growth of approximately 6.5%, continuing our solid growth track record. During this time, we have also successfully reduced our adjusted dividend payout ratio to approximately 70%, highlighting our ability to grow responsibly.

We are in a strong liquidity position with $2.7 billion of long-term debt issued in 2025 and nearly $4 billion available on our credit facilities at the end of the year. With the hybrid debt issuance and asset dispositions in 2025, the growth in our capital plan is still expected to be funded largely from cash from operations, utility debt and our dividend reinvestment plan. Our $500 million ATM program has not been utilized to date and remains available for funding flexibility as required.

On the rating agency front, we are happy to report that in November, S&P confirmed our A- issuer and BBB+ senior unsecured debt ratings confirmed and revised the outlook from negative to stable due to improving financial measures as well as developments at our utilities to mitigate physical risks, namely wildfires. Additionally, it's worth noting that last month, Moody's withdrew its ratings for Fortis Inc. at our request. Our decision was made after evaluating the cost and benefits of that rating and does not impact the stand-alone rating of our utilities rated by Moody's.

Overall, our key credit strengths coupled with our funding plan support our strong investment-grade credit ratings with S&P, Fitch and Morningstar DBRS. In Arizona, both the UNS and TEP general rate applications continue to progress. Last month, the ACC administrative law judge issued a recommended opinion and order with respect to the UNS Gas general rate application, recommending an allowed ROE of 9.57% and a 56% common equity component of capital structure. While the order also recommended a formula, it reflected certain revisions to the formula, including post-test year adjustments.

UNS Gas filed its response on Monday, including its objection to the revisions to the formula. The rate application remains subject to ACC approval, which is expected in the first quarter. The order proposes implementation of new rates by March 1, 2026. At TEP, staff filed its testimony earlier in the week, recommending a 9.75% ROE and 55% common equity component of capital structure. Staff's rate design testimony, including the formula will be filed in late February and hearings are expected to commence in April. Based on the latest procedural schedule, we expect an order in the fall.

That concludes my remarks. I'll now turn the call back to David.

Thank you, Jocelyn. To summarize, 2025 was another great year. We invested more than $5.6 billion in capital and delivered solid EPS and rate base growth. We had strong safety and reliability results, and we delivered compelling returns for our shareholders. These accomplishments wouldn't be possible without the continued commitment of our people.

Going forward, we are focused on executing our $28.8 billion capital plan, which will drive rate base growth of 7% and support our dividend growth guidance of 4% to 6% through 2030.

That concludes my remarks. I will now turn the call back over to Stephanie.

Thank you, David. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.

[Operator Instructions] The first question today comes from Maurice Choy with RBC Capital Markets.

Starting with a question on Arizona and data centers. You mentioned in your prepared remarks that the commission approved the full tariff rates with no discounts, 75% minimum billing requirements, strong credit and security provisions. Recognizing that affordability is a big theme this year, I wonder if you could just speak holistically as to why you think this arrangement works in Arizona and perhaps why other power markets across North America continue to have issues with tariff design or cost allocation?

Yes. Thanks for that question, Maurice. Obviously, affordability is at the tip of everybody's tongue these days talking about how we're going to grow and make sure that we do that in an affordable and responsible manner from a customer perspective. And this is actually one of the prime examples of how it should be done. This energy supply agreement, as we look at our current portfolio at TEP, that's roughly 300 megawatts is supplied out of existing capacity and energy that we -- so we do not have to build anything additional for them. And a little bit of investment that we have to make from interconnection, et cetera, is going to be paid by this customer.

So when you look at the difference between what TEP's rates and customer base would look like with and without this data center, you'll see that there's a lot of new KWH without additional dollars and investments that we would be making on their behalf that will go in to provide a lot of additional fixed cost recovery from all those KWH. And actually, I'm saying KWH, but as I mentioned, the 75% minimum billing demand is there as well. So it actually doesn't necessarily even revolve around how much energy they use.

So this is, I think, the poster child example of how it should be done. And then, of course, as we look forward and building additional capacity for the next phases of those data centers, we will do it in the same manner where we make sure that those data centers cover all of the costs and basically investments that we need to make on their behalf and then some, right? Because when you look at their -- again, their energy usage and how they'll be leaning on the rest of the grid, those kilowatt hour charges that they'll be paying will be spreading out the cost that we have in our system over a much bigger pie. So if you do it right, this is a fantastic customer affordability story, and we're going to make sure that we do it right.

And maybe as a quick follow-up, what gating items are there for the remaining 300 megawatts in this initial site? Is it just waiting for the first 300 megawatts to be built first and then we get to the next 300? Or are there other things to consider?

Yes, there's -- I mean, the second 300 megawatts will need additional capacity that will need to be added. And so of course, how we do that, the timing for that and the negotiations of all the contractual details that covers all of those things that I mentioned to make sure that we are protecting ourselves, the company, et cetera, as well as the customers, that all still has to be finalized.

Understood. And just finishing off with ITC. Have you seen any updates from FERC, particularly now that it has a new chair on moving on with any of the ongoing FERC matters?

So we haven't. I know there's been some chatter out there that there could be some -- but we haven't heard anything. And I'm going to turn that over to Krista because she's recently been wandering the FERC calls and she may have some additional information. Krista?

Yes. Thanks, Dave. That's absolutely right. There has been a lot of chatter, but we haven't heard anything specifically about ROEs or incentives. What I will say, however, is that I think this chair and this commission is laser-focused on running the commission well. And to that end, the Chair has been very vocal that she wants to clean up things that have just been hanging out there for a while. So we are optimistic that things have been hanging out there and are kind of the questions that we get from all of you every time we see you about what's going to happen. We are optimistic that there will be some movement on there.

I think the other thing we're seeing from this FERC is that as part of running the agency well, they're very focused on making sure that their decisions have staying power. This back and forth between administrations is not helpful. And so this Chair has been very intentional about making sure they follow the record, follow the law and get bipartisan support. So while we don't have any insight on what they'll be taking up, I think we're really optimistic that they will be kind of cleaning out the cobwebs and closing some of these old dockets and doing it in a very thoughtful way that will give us some regulatory certainty going forward.

Perfect. Congratulations to Linda and Krista.

The next question comes from Rob Hope with Scotiabank.

I'll extent my congratulations as well. Maybe keeping in Arizona, the ALJ decision on the formula mechanisms moving forward, there was some commentary in the release there about kind of things that were put forward and things that weren't put forward. Can you maybe just kind of speak to your view of what the ALJ's decision is and kind of what you would -- what you like about it and what you don't like about it?

Yes, I'll kick that over to Susan to address. I will just say, as a lead in here, obviously, we've got a couple of different rate cases going on, both UNS Gas and TEP. And I would just want to say on upfront, that these are definitely 2 different companies, 2 different dockets, 2 different mechanisms that were proposed, 2 different ALJs. So it's hard to get -- because it might be your follow-up question, Rob, so sorry if I jumped to it, which is that it's hard to get readthrough from one of these cases to another, but I'll let Susan opine on the UNS Gas case here.

Yes. Thanks, Dave, and thanks for the question, Rob. So it's a lengthy process as we go through the rate case and multiple rounds of testimony working with ACC staff on a design that is acceptable to them. And we came to a pretty good place where other than the dead band, we were in agreement with staff. And the recommended opinion and order was a little different than what we had submitted. I'd say you asked what did we like that's in the, I'll call it, the [indiscernible]. The judge recommended calling it a pilot program, which we think is good because this is the first round of formula rates in Arizona. And so we want the opportunity to continue to adjust the design as we are able to experience it and see how it goes for our customers and for the company.

There's a couple of other kind of minor things that we agree with in terms of the judge's recommendation. I'd say the things that were really hopeful to get changed back to the way that we had proposed and staff had agreed with the design for the formula rate because of the extension of the approval period, we submitted a request to get 6 months of post test year plant recovery. And I think that's really important as the recovery period gets extended to cover those costs and to reduce regulatory lag, which is really the intent of having a formula rate.

We're okay with the larger dead band as long as we can get that post-test year plant. I think the other thing that we feel like the 9.77% ROE is justified and that should not be reduced because of a formula rate. And then the efficiency credit, I think, is just maybe a misunderstanding of -- we had proposed an efficiency credit with the system improvement benefit. And that's pretty typical for a system improvement benefit, but doesn't really relate to a formula rate or this ARAM that we recommended. And so I think that 5% efficiency credit needs to be reconsidered.

So I think we have a good track record with this commission. We filed an amendment on Monday, proposing to go back to basically what staff had recommended, including their deadline range of plus or minus 40 bps. And I think there's a good opportunity here for discussion with the commission as we kind of play out the consequences of the way that the recommended order was written that we can get back to what was recommended by staff.

All right. Appreciate that. And yes, my second question was going to be the readthrough. But instead, I'll go to BC. LNG and increasing energy exports and LNG, we'll call expansion seems to be a focus for the government. Any movement on the next wave of projects at Tilbury with the government and the approvals there?

Yes. So as we sit here today, we don't -- other than that update that I gave in the prepared remarks, related to the LNG tank that we received the approval for late last year. So other than that, obviously, there's some additional projects that we're looking at there, but we don't have anything else to announce right now. There is obviously, I think, a good emphasis in British Columbia on looking for some of the large projects. We hope that bubbles up to some additional investment opportunities for us in that area.

The next question comes from Mark Jarvi with CIBC Capital Markets.

I just wanted to go back to the data center opportunity in Arizona. Commission has been supportive, but more recently, the Attorney General came out with some comments. Any risk that creates a delay or puts a jeopardy some of the planned expansions?

At this point, the pushback from the AG, I think we don't see that as necessarily a big issue or threat to this first contract that we have negotiated. We feel that the comments perhaps that were made on this wasn't quite fully understood exactly how the contract was formed that this was absolutely a 100% Arizona Corporation Commission approved tariff. There weren't any discounts. It was -- so I think some of the arguments -- well, I would say all the arguments that we saw against the energy supply agreement, we feel we have the right answers for. So I think with the clarity of daylight on all of those terms, I don't think we will have an issue.

So Dave, since the comments were made by the AG, have you been able to have some dialogue with them, share some evidence, communicate your position to help clarify some of the maybe misperceptions on that?

So we have spent a bit of time with publicly putting out that same message and both letters to the editor and the paper and things like that. I don't know, Susan, if we've sat down with the AG on this topic or not, but you can opine if you have.

Yes. I think that's right, Dave. We have not sat down with the AG, but we have publicly been sharing the details of the agreement that we're able to. I think you're right.

Okay. And then just in terms of some of those upside drivers you've outlined, I think it's on Slide 8, just in terms of some of the items that could be upside to the plan. If you think about since last quarter when you gave your 5-year plan, progress since then, like if you had to rank those, is it the data center opportunity in Arizona that's the best? Is it load and ITC? Just sort of how you would say that opportunities are shaping up in terms of incremental upside to the plan?

Yes. I guess ranking them, I suppose, there's obviously additional opportunities in ITC related to the -- what was formerly known as the Tranche 2.2 now known as MTEP 26. I think those are obviously a great opportunity for us if and when we want to participate, and we're still evaluating the competitive bidding process in Iowa. Those are things that are pretty close in as well. The data centers in Arizona, for sure, that feels like it's -- I mean, we're having those conversations now.

If we can get that story out, explain very well how these things can benefit the rest of our customers, I think -- which I think we're as an industry on the verge of getting that information out there and getting that explanation so that hopefully, we turn that corner and folks see that some of these big load growth opportunities are actually a way to get more affordable rates. Once that dam breaks, I think we'll get a lot of positive support for those types of projects.

And then like the question before on BC, there are some good opportunities there in that jurisdiction for additional LNG investments. And given, again, the focus there of the government on big projects and some good opportunities to provide economic benefits to that province, that and the -- there's quite a bit of investment opportunities that we see in the Okanagan and our small electric company there as well that we hope to see come to fruition. So it's a pretty big laundry list, but we're happy how full it is.

The next question comes from Benjamin Pham with BMO.

On the annual formula mechanism for both UNS Gas and TEP, do you think that the commission can rule on that mechanism when you have a pending Court of Appeals case outstanding?

Yes, we think they can. So that Court of Appeals is more from a procedural perspective. It was really looking at whether or not they view the policy statement as being required to go through a rule-making process, which just takes a little bit longer time and a little bit more detailed process. The beauty of this is I think we have the record in our favor in that there have been mechanisms like this past, whether it's the system improvement benefit charge or other trackers that we've had. We had a decoupling statement years ago, policy statement. But the most important part is the policy statement was just that. It didn't -- it was the ability for utilities to file in a fully litigated rate case, formula rates, which were then, of course, fully litigated in that rate case.

So it wasn't a rule-making that had any shells in it. It was that a utility may apply for a formula rate based on a handful of principles. So we don't see that as being an issue in us going through a rate case and getting that. And in fact, there's no reason that we needed to even have a policy statement before asking for these types of mechanisms in a rate case. As long as it's a fully litigated rate case, it's within the bounds of the Arizona statutes, then you can ask and the commission can grant anything within those bounds.

Okay. Understood. And on the second question on customer affordability, you've had a pretty good list there on how you plan to manage that going forward. I'm curious, are you sensing from customers or feedback in certain states or provinces where this is a bit more heightened when you look at across your franchises across North America?

Yes. I think it's probably different state by state, province by province, depending on the focus of -- a lot of times, politicians and governments and pushing the affordability question, which everyone should be doing. We just have to make sure that we fully understand the impacts and drivers of affordability, and we're trying to get out there within our own companies and the sector even from a wider perspective and explaining what we're doing in order to address that.

Okay. It seems like a broad conversation, but not something that's being more pointed in that particular area for Fortis.

No, I think we -- as a company and with all our utilities, it's got to be -- this is an extremely important topic. And I would say probably the #1 question that we get asked by you all from an analyst perspective, which is a great -- I think a great result that we're all focused on the same thing, making sure that at the end of the day, we're doing the best job we can to provide our customers the level of service they need and do that as affordably as possible. So we're all on the same page. We just have to make sure that we're looking at it consistently across our Fortis footprint. So we don't say, oh, this jurisdiction hasn't been a big issue or it hasn't come up, let's not pay attention. This is something we're focused on 24/7 in every jurisdiction.

The next question comes from John Mould with TD Cowen.

Just going back to the UNS Gas rate case, and I appreciate you don't want to get ahead of your regulator, how should we think about what could come out of the upcoming ACC open meeting? Could that provide some clarity on finalized details of the formulaic rate structure in terms of an order? Or is that just too short a time line given the exceptions by both you and others? Any insight on that?

So I could pontificate, but I think it's better to just wait a week. So it just got put on next -- a week from today is the 19th open meeting. There's a special open meeting for the UNS Gas case. So instead of getting front run in that, it's just right around the corner. So we'll leave it at that.

No, fair enough. Appreciate that. And then maybe just moving to Ontario. You're on a list of potential participants in competitive transmission procurements and there is one being launched. There's also potential for changes to the LDC landscape in the province with this government pulse expert panel that's in progress. How are you thinking about the potential for more investments in Ontario by Fortis?

Yes. It's a province that we've been in for 30 years. And we've done -- we've got our utilities there as well as our background in building the Wataynikaneyap project. And so we love Ontario. We'd like to invest more there. And so we're trying to see if we can. So it's a good opportunity. And if it works out, great. I mean that's something that we would love to participate in bringing some of our capital into the province and help them build out. They've got a really great energy plan, and we'd love to be a part of it even just on the edges.

[Operator Instructions] The next question comes from Elias Jossen with JPMorgan.

I appreciate the color on the regulatory developments across the Arizona rate cases. So as you move through the process throughout this year, how do we think about increased clarity shaping the potential to issue earnings guidance at some point in the future?

Yes. The increased clarity, good regulatory mechanisms that allow us to forecast a little bit better, taking the peaks and valleys out of the Arizona utilities does provide a little bit better clarity for us from an earnings perspective. And I would say is not the only thing. It's obviously something that would go on the side of the ledger that would allow us to give earnings guidance. But at the end of the day, that's -- there's a lot of other considerations around that as well. So it's sort of one less thing but doesn't necessarily mean that it drives us straight to earnings guidance.

And then recognize you guys have already talked a lot about the large load outlook in Arizona. But can you frame your involvement on the ongoing IRP workshops? I know there's a lot of stakeholders at the table there, but just to get your perspective on those IRP workshops. And can you remind us when we might expect an update there?

Yes. So we're in early days in the integrated resource plan. We've had a couple of public meetings. We put together this big stakeholder group that goes through the entire process. And you can follow -- actually, there's a spot on our website at TEP that you can follow along on the developments there, including once we start putting load forecasts and those kind of estimates there.

I'm glad you brought that up because that was one of the big pieces I meant to mention this a little bit longer term, but an additional above and beyond the capital plan opportunity as we see that and start building out that integrated resource plan, we'll be able to then see how much additional generation and transmission investments we'll need to serve the growing load in Arizona. So it is still early days, but we -- I think we filed that in August of this year. So it will be getting pretty active here over the next few months.

This concludes the question-and-answer session. I would like to turn the conference back over to Ms. Amaimo for any closing remarks.

Thank you, Betsy. We have nothing further at this time. Thank you, everyone, for participating in our fourth quarter and annual results conference call. Please contact Investor Relations should you need anything further, and have a great day.

This brings to a close today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.

Thank you for standing by. This is Betsy, the conference operator. Welcome to the Fortis Inc. Third Quarter 2025 Earnings and New 5-year Capital Outlook Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions]

I would now like to turn the conference over to Stephanie Amaimo, Vice President, Investor Relations. Please go ahead.

Thanks, Betsy, and good morning, everyone. Welcome to Fortis' Third Quarter 2025 Results and New 5-year Capital Outlook Conference Call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries.

Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. Non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our third quarter 2025 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. Today, we are proud to announce another solid quarter marked by strong execution and momentum from our regulated growth strategy. Operationally, we continue to deliver safe and reliable service to our customers. And through September, our utilities invested $4.2 billion in our systems. For the full year, we expect to invest approximately $5.6 billion. Financially, we delivered adjusted earnings per share for the third quarter of $0.87.

In September, we completed the sale of FortisTCI. The sale strengthens our balance sheet and reduces our risk profile. More recently, we entered into an agreement to sell our investments in Belize, including the non-regulated hydro generation facilities to the government of Belize. I am happy to announce that the transition closed last Friday and that Fortis is now comprised of 100% regulated assets. We recognized these were long-held assets in the Fortis family, and we wish our best to the teams in Turks and Caicos and Belize as they continue to serve their customers and communities.

And today, we are pleased to unveil our 5-year capital plan and announced that our Board of Directors has declared a fourth quarter dividend increase of approximately 4%.

Our new $28.8 billion 5-year capital plan is up $2.8 billion compared to the prior plan. This supports rate base growth of 7% and annual dividend growth guidance of 4% to 6% through 2030. This new plan was developed with a strong emphasis on maintaining customer affordability. We prioritize capital investments that provide cost savings that flow through to our customers. This includes the coal to natural gas conversion at the Springerville Generating Station in Arizona, which is more economical compared to the new energy resources included in the prior plan. Our utilities are also continuing to manage operating costs by finding efficiencies through innovation and process improvements.

As you can see on the slide, the growth in our 5-year plan is largely driven by higher transmission investments. At ITC, the $2 billion increase was primarily driven by new interconnections, including the Big Cedar Load Expansion project as well as the MISO long-range transmission plan and baseline reliability projects. At UNS, transmission and distribution investments increased $1 billion with FERC-regulated transmission making up $700 million of the increase. This was largely attributed to a new transmission line at TEP. Generation investments at UNS were reduced by $900 million driven primarily by the planned conversion of the Springerville Generating Station to natural gas, which I spoke to previously. The remaining increase is driven by growth at our other regulated utilities and a higher assumed foreign exchange rate.

The new plan is highly executable with approximately 77% directed towards transmission and distribution investments and critical infrastructure that drives stable, predictable returns. The capital program is low risk and anchored in 100% regulated projects and includes only 11 major capital projects representing 21% of the plan. Consolidated rate base is expected to increase by $16 billion from approximately $42 billion in 2025 to $58 billion in 2030, supporting average annual rate base growth of 7%. This is up 50 basis points from the 6.5% in the prior plan.

Now I'll take a few minutes to dig a little deeper into our larger utility capital plans. ITC's capital plan of $9.8 billion is the largest in the company's history and support strong rate base growth of 8%, up 100 basis points compared to the prior plan. Key elements of ITC's plan includes investments for base infrastructure, MISO's long-range transmission plan, customer connections and grid security. Significant opportunities above and beyond the base plan exists at ITC, including approximately USD 3.3 billion to USD 3.8 billion post 2030 for tranche 2.1 projects assigned through rights of first refusal.

Work is also underway at ITC to evaluate projects within the tranche 2.1 portfolio that are subject to the competitive bidding process. If any of these projects are awarded to ITC would be incremental to ITC's plan. Other avenues of growth at ITC include customer connections associated with over 8,000 megawatts of load growth for proposed data centers and economic development projects in various stages of development across their footprint. This is up 3,000 megawatts just since last quarter. ITC may also realize future opportunities associated with the ongoing MISO LRTP process. All in all, it's a very exciting time at ITC with a significant transmission build-out.

Let's now turn to UNS Energy. Their capital plan of $5.6 billion supports average annual rate base growth of approximately 7%. As a vertically integrated utility, investments are spread across the value chain. Notably, 1/3 of the capital plan is concentrated in transmission with the balance consisting of generation and distribution investments. Regulated generation includes the coal to natural gas conversion of 800 megawatts at the Springerville Generating Station, which is aligned with TEP's exit from coal by 2032 as well as the Black Mountain generation project at UNS Electric.

While there is no new generation reflected in the plan associated with data centers or other large load growth, a new era of demand is approaching with a significant interconnection queue. As we discussed last quarter, TEP reached an energy supply agreement to serve a demand of approximately 300 megawatts that starts to ramp up in 2027 and will use existing and planned capacity. The agreement awaits ACC approval as well as other contractual contingencies. Negotiations are actively ongoing for an incremental 300 megawatts of capacity to support a full build-out of 600 megawatts at this initial site.

TEP is also in active negotiations for additional capacity to second site in the range of 500 to 700 megawatts. If agreements are finalized for these subsequent phases, we estimate new generation in the range of approximately USD 1.5 billion to USD 2 billion through 2030 would be required as well as new transmission. We expect the supply will include a mix of renewable energy, natural gas generation and energy storage. All agreements will be structured to maintain reliability and provide financial protections for our customers and the company.

Other opportunities beyond the plan include new energy resource investments required at TEP and UNS Electric as part of their next integrated resource plans expected to be filed in 2026.

In British Columbia, our natural gas infrastructure is in focus. FortisBC's capital plan of $4.9 billion supports projects that ensure system reliability and integrity as well as major capital projects for LNG and advanced metering infrastructure. Beyond the base plan, we have several opportunities. Just last week, the BCUC approved the Tilbury LNG Storage Expansion project. Given our capital plan assumes a smaller storage tank, we now have potential upside of approximately $300 million. This project is contingent on an environmental assessment, which we anticipate next year.

Other opportunities include LNG expansion at Tilbury for marine bunkering as well as customer and load growth in the Okanagan electric service territory. Some of these opportunities have the potential to fall within the plan period. This is a dynamic and promising time to be an energy delivery utility in North America. As we execute our base 5-year capital plan, we are concurrently focused on unlocking growth opportunities above and beyond the plan across all our jurisdictions.

Turning now to our favorite slide. Today, we announced the declaration by our Board of Directors of a fourth quarter dividend of $0.64 and representing a 4.1% increase. This brings us to 52 consecutive years of increases in dividends paid, a track record that speaks for itself. With our strong dividend history and regulated growth strategy, we are extending our 4% to 6% annual dividend growth guidance through 2030.

Now I will turn the call over to Jocelyn for an update on our third quarter financial results.

Thank you, David, and good morning, everyone. For the quarter, reported earnings were $409 million or $0.81 per common share, and on a year-to-date basis, reported earnings were $1.3 billion or $2.57 per common share. As you can see on this slide, reported earnings include income taxes and closing costs of approximately $0.06 per share associated with the disposition of FortisTCI. Excluding this impact, adjusted EPS for the quarter was $0.87 per common share, up $0.02 compared to the third quarter of last year. And year-to-date September adjusted EPS was $2.63, up $0.18 per common share compared to the same period last year. Adjusted EPS growth to date in 2025 reflects strong performance across all our regulated utilities.

On Slide 14, you will see the adjusted EPS drivers for the quarter by segment. Our U.S. Electric and Gas utilities delivered a $0.03 increase in EPS, higher earnings at UNS reflected an increase in transmission revenue and higher AFUDC associated with ongoing major capital projects. As we discussed last quarter, earnings at UNS are tempered by regulatory lag, driven largely by over USD 700 million of rate base, not reflected in rates.

The increase in earnings at Central Hudson was due to rate base growth as well as a change in the recognition of a regulatory deferral for uncollectible accounts effective July 1, 2025. Growth was moderated by a contribution to a customer benefit fund associated with the joint settlement agreement, which concluded an ongoing enforcement proceeding. Together, these regulatory items impacted adjusted EPS by $0.01.

Moving to ITC, continued capital investments and related rate base growth increased EPS by $0.02, the increase was partially offset by higher stock-based compensation and holding company finance costs.

For our Western Canadian utilities, EPS increased $0.01, largely driven by rate base growth, including earnings associated with FortisBC Energy's investment in the Eagle Mountain Pipeline Project. The expiration of a PBR efficiency mechanism and a lower allowed ROE effective January 1, 2025, at FortisAlberta tempered earnings for this segment.

And while not shown on the slide, at our Other Electric segment, EPS was largely consistent with the third quarter of 2024. Rate base growth was offset by the September 2 disposition of FortisTCI. For the full year, we expect the sale of FortisTCI to have a $0.02 impact on adjusted EPS. A higher U.S. dollar to Canadian exchange rate also contributed a $0.01 EPS increase for the quarter.

For the Corporate and Other segment, the $0.03 decrease reflects higher holding company finance costs, unrealized losses on foreign exchange contracts and lower unrealized gains on total return swaps. And as David mentioned, we sold our assets in Belize in October and do not expect the transaction to have a material impact to adjusted earnings going forward. And finally, higher weighted average shares impacted EPS by $0.02, driven by shares issued under our dividend reinvestment plan.

While most of the factors discussed for the quarter are the same for the year-to-date period, the increase in earnings for the 9-month period also reflects growth at Central Hudson due to the rebasing of costs and a higher allowed ROE effective July 1, 2024, as well as the timing of operating costs in 2025. Earnings year-to-date also reflect lower margins on wholesale sales at UNS Energy and the timing of operating costs at FortisAlberta.

Through September, we raised over $2 billion of debt, including an inaugural corporate hybrid issuance of $750 million at 5.1%. Proceeds from both the hybrid issuance and the sale of FortisTCI during the quarter were used to repay our corporate credit facilities, including the non-revolving term loan providing funding flexibility as we focus on executing our capital program.

As I just mentioned, with the recent hybrid issuance and asset dispositions, the growth in our capital plan is expected to be funded largely from cash from operations, utility debt and our dividend reinvestment plan. Our $500 million ATM program has not been utilized to date and remains available for funding flexibility as required. Overall, our funding plan remains largely consistent with the previous plan and supports average cash flow to debt metrics up over 12% through the period with ample cushion in the latter part of the plan. This balanced approach to funding supports both our growth objectives and strong credit profile.

Turning now to recent regulatory activity with one item of note. In August, the New York State Public Service Commission approved Central Hudson's 3-year rate plan with retroactive application to July 1, 2025, including the continuation of an allowed ROE of 9.5% and a common equity ratio of 48%.

That concludes my remarks. I'll now turn the call back to David.

Thank you, Jocelyn. At our core, we are a utility built on strong fundamentals and a clear, disciplined regulated growth strategy with a long CapEx runway supported by FERC-regulated transmission and retail load growth opportunities in Arizona. For our customers, we remain committed to prioritizing safety, reliability, affordability and the delivery of cleaner energy. For our shareholders, we offer a compelling low-risk return profile reinforced by our capital investment plan and dividend growth guidance through 2030.

That concludes my remarks. I will now turn the call back over to Stephanie.

Thank you, David. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.

[Operator Instructions] The first question today comes from Maurice Choy with RBC Capital Markets.

Just first question is on the timing and likelihood of some of the opportunities over and above the base plan. But within this 5-year period plan, specifically, you mentioned earlier that there is about USD 1.5 billion to USD 2 billion of incremental generation opportunities at TEP that may be required through 2030, and also another $300 million for the LNG Tilbury storage expansion upside. If my math is right, that's about $2.5 billion to $3 billion of incremental investments or another 100 basis points addition to your rate base CAGR. Any reason why you think that these two items may not come through in the coming months, such that we probably could potentially put this as part of our base estimates?

I like your optimism, Maurice, but there's a lot of wood to chop between here and there, right? So we have to get the agreements done with these counterparties. We obviously have to have the ability to build the infrastructure that's needed in the time line that they want. So all those things are definitely possibilities, but still getting generation cited, getting things in the queue, all of those pieces and most importantly, getting these customers to sign up for all the protections that we want for us from a credit perspective and for our customers from a rate perspective. And then going through the regulatory process. There's just a lot of steps between here and there, specifically around the data centers.

And then also for the storage tank in BC, still have to go through the EA process there. So we obviously are very excited and bullish and after these projects as much as we can be. But as you know, we don't drop those things into our capital plan until we have signatures on the dotted line. And we'll keep you posted as those negotiations go and once we reach agreements with some of those third parties.

Understood. If I could finish off with the question on the funding plan on Slide 17, where there was a mention about the balance of equity funding to be satisfied from, among others, asset sales. Obviously, you've sold a number of things here, Turks and Caicos as well as Fortis Belize and Belize Electricity and also Aitken Creek gas storage in the past. So you're 100% regulated right now, as you mentioned, thoughts on what else might be worth trimming, optimizing? Or do you feel like this is no longer an avenue that's worth exploring?

Yes. So we're focused mostly on executing that 5-year capital plan and that laundry list of additional opportunities above and beyond the plan that we just went through. So there is no read-through from the transactions that we just completed. Our portfolio is a great portfolio. And we do have 100% of our assets being regulated now. So there's -- that's not -- when you read that sentence that was looking back not forward.

So that's we look at funding our capital plan is clearly laid out by that funding plan on the slide. And I'd reiterate that the DRIP is the only source. We don't have any discrete equity in there. So the DRIP is the only source of equity. We have the ATM and hot standby, but that's not needed in the current capital plan process.

The next question comes from Rob Hope with Scotiabank.

Good to see the update on the capital plan. Maybe to follow up on the USD 1.5 billion to USD 2 billion of new generation in Arizona. Can you maybe help us understand kind of the timing of when this capital could be secured, just understanding that a lot of these items have relatively long lead times and when they could be in service?

Yes. So if you ask the customers who are asking for this, it's pretty much tomorrow is when they want it. But obviously, it takes time to build data centers. It takes time for us to get the siting and permitting, and of course, building additional generation, you're going to have to get in the Q4 combustion turbines or combined cycles whatever the resource portfolio requires. But it's also kind of not fully defined at this point where you can look at things that are available, as I mentioned in my prepared remarks, we expect this to be a mix of different energy resources, including battery storage, which can happen pretty quick. Renewables, of course, which can supply a good chunk of energy.

And then you look at what the best capacity resource, whether that's a combustion turbine or combined cycle depending on the load features. So that I still think that when you look at longer term, like the current time line that we have with the project in Arizona for the first 300 megawatts as they're looking to be online in '27 and ramping up over the next year or so after that. So I would expect other time lines to be similar to that. But when we look at our plan that goes all the way to 2030, depending on availability of, say, combustion turbines, which would probably be the critical lead item on that. We still think that, that's doable to get that done in that next 5-year time period.

All right. Great. And then maybe taking a look at ITC. So you mentioned that there's 8 gigawatts of potential loan growth associated with data centers and you have Big Cedar in hand. Can you maybe add a little bit of color on how many opportunities you're looking at for that 8 gigs as well as could we see some sanctioning in the next 12 months?

Yes. I'll turn that over to Linda to give some details, but I will remind folks on the call that our three largest customers are DTE, CMS and Alliance. So I'm sure you've seen some of the conversations in those earnings calls as it relates to some of this development as well. So Linda, I'll turn it over to you.

Great. Thank you, Dave, and thanks for the question, Rob. Yes, certainly, the 8 gigawatts that certainly, we are -- we have sort of insight into in terms of those conversations with customers, ongoing planning studies to accommodate them. Certainly, we remain hopeful. I would say there's a lot of activity. We're working closely, as Dave mentioned, with our customers. We're really not in a position to really say or identify just sort of from a time line perspective. I think what we can say is that we continue to see that queue of those prospective data center or other economic development projects continue to grow. So we remain hopeful and optimistic that we will continue to see further announcements. But really, at this point in time, it's premature for us to speculate on which projects were or exactly when. But I would say the queue continues to get larger, and we remain optimistic.

The next question comes from Ben Pham with BMO.

Could you update us on your thoughts with respect to an EPS CAGR initiation, if there's any?

Yes, we still continue whether or not we want to take that next step and give earnings guidance, but we have been pretty happy with all the details that we -- and we hope our investors and analysts are happy with the details that we give on rate base growth and seeing how clear our capital plan and funding plan tied together. We give the dividend guidance as well.

And we always evaluated, I think probably the last time I've had conversations with you all kind of the one thing that we're waiting for because there's a lot of variability in earnings in Arizona to see the outcome of the Tucson Electric Power rate case. Formula rates will provide a much steadier earnings outlook for us, which would allow us to give a little bit more visibility and detail for you all, whether or not we -- I'm not saying that if we get formula rates, we're going to give earnings guidance. But that's one thing that's keeping us from giving it now.

Okay. Understood. And then maybe next on the asset sale side of things. Maybe not to talk specifically on Caribbean valuations. But can you share just the trends you've seen with buyer appetite for those assets? And it seems like you're willing to more do deals with neutral to maybe slightly dilutive perhaps. And just how do you think about CUC in the overall for this portfolio mix today?

Yes. I'd say the interest like in any market, waxes and wanes. I mean, we've seen that over many years as folks had approached us about the Caribbean assets, et cetera. But it's -- there's no like kind of consistency necessarily there. And of course, the buyer universe changes almost on a year-to-year basis. So -- but again, just as far as CUC goes, this isn't a read-through that we're exiting the Caribbean. This is -- those are two distinct and discrete transactions that we did and it doesn't mean we're looking to do anything else.

The next question comes from Mark Jarvi with CIBC.

Just wanted to come back to sort of like friction points on potentially higher spend. As far as I can tell, it doesn't seem like customer affordability is one or balance sheet. So really, is it just equipment availability and permitting, Dave?

Yes. So I'm glad you brought up affordability because when you think about these new large load customers that actually can and well, should be, if you design it rightly, if you correctly, you would get the new customers, the large data center to pay for the growth that is needed in your infrastructure is the kind of growth pays for growth argument. So we definitely want to structure them that way so that in the end, we have a positive impact on customer affordability. They either get improved reliability and don't pay any extra or you end up with the great reliability that we always provide and actually seeing some downward rate impact because of all the energy and infrastructure that those larger customers are now paying part of basically paying a bigger part of the pie.

So now that is a very difficult conversation, not necessarily to say, but for folks to hear and understand that because there's a lot of mixed messages out there that are telling people in different markets that data centers can drive your cost up. Well, when you have the control over the full value chain like you do in a vertically integrated utility, you can make sure that doesn't happen. And your regulators will make sure that doesn't happen. So that's the tack that we're taking in Arizona.

And so when it comes down to it, I mean there's always additional things like making sure that your -- the community is supportive that you -- if you have, whether it's water cooled or air cooled that you understand what that means from a resource perspective, which is one of the reasons that in Arizona, they are all shift into air cooled -- air cooling for the data centers instead of water cooling to kind of take that out of the argument. So it is all of those things permitting, siting. They're great for economic development and jobs in the area, tax base. I mean, it's a great story to tell. But sometimes, it's a bit of a hard story to make sure everybody hears it all.

You brought up the shift to air cooling. Just on that 300 megawatts, the initial site, is that all moved ahead? Is there anything else that need approval for that 300 megawatts? And then in terms of other municipal support or other approvals, what's required then to get to the sort of investment decision on the next 300 megawatts of data center load?

Yes, I'm going to turn that over to Susan. We do have the -- as I mentioned, the energy supply agreement has been filed with the Corporation Commission, which is the first thing we have to get through, but I'll turn it to Susan to talk about any of the other pieces that might need to happen.

All right. Thanks, Mark, for the question. So yes, as Dave mentioned, on our side, the biggest approval that we need is that Corporation Commission approval, which we expect to get by the end of this year. But on the data center side, I think the main approval that they need as a permit to dig a well, which is a state permit. This is on county land and the state would actually approve the water. And that's water just for regular building use like kitchens and bathrooms kind of things.

So that's for the first 300 megawatts. I would say anything beyond that, we're still negotiating contracts. And so not really sure what the types of approvals we would need, but certainly, anything beyond this first contract, we would need to build something new in terms of a generation resource. So that's going to be a more extended period of time. As Dave talked about earlier, it all depends on the resource mix and certainly, some of the generation resources can be built a lot more quickly than others.

So the customer would like to push the time lines, but you need to do your own sort of analysis on generation mix to come back to them with a solution, is that right?

I would say we need to do the analysis on the overall grid impact and make sure that we have all the infrastructure in place to serve the new customers as well as our existing customers as reliably and affordably as possible. I think in terms of what we would build, the customer will have a huge influence on that, right? So if the customer wants to go primarily renewable, that would be their decision and based on what they're willing to pay in terms of resource mix. So we're willing to build whatever they need, whatever they prefer as long as the customer is willing to pay for that incremental cost of maybe increasing the amount of renewable resources.

Understood. And then, Jocelyn, a question for you. Just in terms of the funding plan for the next 5 years, does it contemplate further hybrid issuances? And if yes, can you kind of outline roughly the quantum?

Yes. Thanks, Mark. Yes. No, we don't have any further hybrid included, but we do have capacity. So with that growth that we're talking about here today that is not in the plan, should it come in the plan, then it's possible that we will explore the hybrid market when we look at that growth. And we may also look at it regardless, depending on the market and how the hybrids are pricing relative to other instruments. So yes, definitely an area that we're exploring.

The next question comes from John Mould with TD Cowen.

I'd like to take another stab on the large load front in a couple of places. Maybe just starting with ITC. And I'm not asking for a view on in-service dates, but I'm just wondering if you can provide a little more detail on how the timing of the connection requests are paced. And this 3 gigawatts of growth that you've seen since last quarter, in particular, the pacing of at least what customers are looking for.

So are you asking like how soon they come in before they need it, or just...

Yes, how soon they're seeking to get connected, like just if I was trying to map out the timing of all those requests, is there a particular time period to which it's weighted?

Yes. Let me -- I don't have any visibility to that. Linda, do you have a view on kind of the detailed queue, I guess, CODs that they're looking for?

Look, I mean, I think I would be sort of generalizing, but I think back to Dave, I think on an earlier comment you made is that look, they all want to be connected as soon as possible. Certainly, there's practical realities just in terms of where they are looking to locate their facilities? Are they co-located with existing transmission infrastructure? If not, what is the infrastructure that's necessary, the MISO approval process to get that infrastructure through the MISO queue.

So it's a difficult question. I guess I would generalize and say for the majority, I would say, of the conversations that we are involved with prospective customers, I would say that many of their requests as well as what is reasonably doable, we're looking at the outer years of that existing 5-year plan. Obviously, there's different ramp perspectives around those because some of them want to move more aggressively faster. Some of them are willing to be able to take what they can get as quickly as possible. So I think it's a really difficult question to give any specificity on, but I would say at least for the existing conversations that we are engaged with, I would say, the majority of those requests are looking at the latter part of our existing 5-year plan, so out into the '28, '29, '30 time frame. So hopefully, that provides some context.

Yes. That's very helpful color. And then just on Arizona and the new IRPs that you're planning to file in 2026. By what time would you need on the large load side to have something more definitive in place so that, that's reflected in the broader IRP and also allows you to potentially demonstrate the rate benefits that could potentially come from that in the various IRP portfolios. Just wondering what the timing looks like there.

Yes. So the IRP is going through its process. They've had a couple of workshops and we'll continue more for -- through 2026 with a target of filing those integrated resource plans, I think, in August of next year. But there will be a bunch of different resource portfolios based on different load growth scenarios with and without data centers. And I think even if we file an integrated resource plan and it doesn't include something that we need later, we just we just update that, right? I mean it's just -- that's basically putting a stake in the ground for sort of the bread and butter resources that we need to serve our load growth. But any of these additional investments that we would see and need and require for additional data center growth. I kind of think of it as almost like its own little mini IRP and rate base that would have its own revenue requirement that would be served by, or that would be met by these customers.

So it's a bit of a different model. You wouldn't necessarily need to put them all together. And it's not like we filed this thing in August and say, okay, we got to close up shop any more data centers that come in and ask us for energy, we can figure this out. I mean, this is basically what we've been doing for the past a couple of years while we've had the 2023 integrated resource plan in effect is we still have these conversations, look at how we can meet the load and then adjust accordingly.

The next question comes from Patrick Kenny with National Bank Capital Markets.

Just looking at the rate base CAGRs by utility and seeing Alberta and BC continuing to lag the 7% portfolio average. You touched on some upside in the Okanagan, but I'm just wondering if there might be any other macro or political tailwinds that you're watching out for that might help these two utilities close the gap relative to the group average growth profile, say, over the next 3 to 5 years?

Yes, for sure. So the Okanagan one is -- actually, it's a smaller part of the BC utility portfolio. But I think, has some good substantial growth opportunities there. So I know we don't usually talk too much about the electric business in BC because of the gas business is so big, but that does definitely have some additional opportunities there.

And then on the LNG front, I mean, this is all about not just the extra upsized, I'll call it, storage tank that just got approved by the BCUC, that's one piece of additional investment. But also the additional LNG liquefaction capacity that we could put there for increased bunkering -- mostly for increased bunkering at that Tilbury site. And there are some political tailwinds, I know there's been a lot of conversations about some major projects and across Canada, related to trying to get the economy jump started. I think maybe some of the more of those details might come out later today when the budget is released, but there is some good emphasis on LNG investments in BC. We hope some of that bleeds down and has some good impact on looking at additional LNG investments for bunkering for BC. So there are some investments there.

And I should note, I'll come to BC's defense here a little bit as well. These things are cyclical, right? So the load growth when you complete a bunch of big projects, and then do a new 5-year plan, it might not look as robust as the last one. But believe me, there's a lot of stuff in there. They've executed well on the past and look to add to that on a going-forward basis.

Okay. That's great. And then maybe for Jocelyn, just back on the funding plan, looking at that 5-year average cash flow to debt ratio of, call it, 12.4%. Is that 40 basis points above S&P's threshold anyway. Is that where you'd like to see it on a sustained basis? Or would you still like to see a little bit more cushion built over time? I guess maybe a different way to look at it, like how much dry powder might you have based on your debt metrics to flex the capital program or to handle any further weakness in the Canadian dollar?

Yes. Thanks, Patrick. Yes, you're right. The average for the S&P metric over the 5 years is 12.4%. But as you get to the latter part of the plan, we're actually pushing more like 100 basis points. And you've probably heard me say before that, that's sort of where we have been targeting our cushion. It gives us a lot of dry powder to have the flexibility to finance the projects that are not in our capital plan that we're talking here today. So yes, so this is a plan that sets us up nicely to actually get to that adequate ample cushion in the latter part of the plan.

I'll actually say 100 basis points is actually a lot of cushion. So I feel comfortable really having like 75 to 100 bps above the threshold of 12%, and we're getting there. And so it's -- this plan has actually improved over the prior year plan, which is a good thing. And in large part, it came from the fact that we've done some asset dispositions and we've continued our DRIP. So yes, the cushion is certainly met on average of 12.4%, but we do get to the, I'm going to call it the ideal cushion by the latter part of the plan.

This concludes our question-and-answer session. I would like to turn the conference back over to Ms. Amaimo for any closing remarks.

Thank you, Betsy. We have nothing further at this time. Thank you, everyone, for participating in our third quarter results and new 5-year capital outlook conference call. Please contact IR should you need anything further and have a great day.

This brings to a close today's conference call. You may disconnect your lines. Thank you for participating, and have a pleasant day.

Thank you for standing by. My name is Chuck, and I'll be your conference operator. Welcome to the Fortis Inc. Second Quarter 2025 Earnings Conference Call and Webcast. [Operator Instructions]

I would now like to turn the conference over to Ms. Stephanie Amaimo, Vice President, Investor Relations. Please go ahead, Ms. Amaimo.

Thanks, Chuck, and good morning, everyone. Welcome to Fortis' Second Quarter 2025 Results Conference Call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries. Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show.

Actual results can differ materially from the forecast projections included in the forward-looking information presented today. Non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our second quarter 2025 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. Today, we are pleased to report another great quarter. With capital expenditures of almost $3 billion during the first half of the year, we are executing on our core objective of delivering safe and reliable energy to our customers. Financially, we delivered second quarter earnings per share of $0.76 a $0.09 increase over the same period last year. During the quarter, we also made progress on the regulatory front.

Notably, Tucson Electric Power filed its general rate application, and Central Hudson reached a multiyear rate settlement agreement on its general rate application. Jocelyn will speak to these regulatory developments in more detail shortly.

In Arizona, TEP's retail load growth opportunity advanced with an important milestone reach for a planned data center development. And today, we released our 2025 sustainability update report, highlighting our consistent progress to deliver cleaner energy to our customers. Through 2024, we have achieved a 34% reduction in Scope 1 greenhouse gas emissions when compared to 2019 levels.

In July, the first phase of the Roadrunner Reserve Battery Storage Project was placed in service at TEP. The 200-megawatt energy storage system will facilitate the integration of renewable energy onto the electric grid with the capability to store 800-megawatt hours of energy.

This project was part of the $2.9 billion that we invested in the first half of the year. Given this progress, both our annual and 5-year capital plans are on track. We are well positioned to deliver on our growth strategy with rate base expected to increase by approximately $14 billion to $53 billion in 2029. This supports average annual rate base growth of 6.5%. In Arizona, TEP announced that it plans to convert approximately 800 megawatts of coal-fired generation at a Springerville generating station to natural gas by 2030.

This will allow us to be coal-free by our 2032 target. The conversion supports customer affordability, local communities and reliability as well as our transition to cleaner energy. This, along with many other factors will impact our resource planning at our Arizona utilities. As a result, we will reassess our 2030 and 2035 interim greenhouse gas targets and share the results once complete. We will provide the project details with the release of our 2026 to 2030 capital plan later this year.

New retail load growth opportunities in Arizona continue to advance. TEP just reached an agreement with a data center customer to serve a demand of approximately 300 megawatts that starts to ramp up in 2027 and we'll use existing and planned capacity. This agreement was structured to benefit existing customers, maintain reliability and ensure the power is supplied consistently with -- consistent with 2023 integrated resource plan, including solar and storage projects currently in development.

This agreement is subject to HCC approval as well as other contractual contingencies. Further negotiations are ongoing for additional capacity to support a full build-out at that initial site of 600 megawatts in total. The project's developer also shared that additional capacity may be required at a second site in the range of 500 to 700 megawatts. If negotiations are finalized for these subsequent phases, new generation and transmission investments would be required.

Beyond these opportunities in Arizona, our utilities continue to pursue various opportunities to support load growth, improve grid resilience and facilitate the interconnection of cleaner energy. Work is underway at ITC to prepare to bid on projects within the MISO LRTP tranche 2.1 portfolio subject to a competitive bidding process. These projects, if awarded to ITC, would be incremental to ITC's estimate of USD 3.7 billion to USD 4.2 billion of capital expenditures for the tranche 2.1 projects.

With a long track record of increasing dividends and our sustainable growth runway, we remain committed to our annual dividend growth guidance of 4% to 6% through 2029.

Now I will turn the call over to Jocelyn for an update on our second quarter financial results.

Thank you, David, and good morning, everyone. For the quarter, we reported net earnings of $384 million or $0.76 per common share $0.09 higher than the second quarter of 2024. Through year-to-date June, EPS was $1.76, reflecting a $0.16 increase over the same period last year. EPS growth was mainly driven by rate-based investments across our utilities and higher earnings at Central Hudson and FortisBC, which I'll discuss on the next slide.

On Slide 11, you will see the highlighted EPS drivers for the quarter by segment. Within our U.S. electric and gas utilities, Central Hudson contributed a $0.04 increase in EPS. This increase largely reflects rate base growth as well as the rebasing of costs and a higher allowed ROE effective July 1, 2024.

The impact of a contribution to a customer benefit fund in the second quarter of 2024 and the timing of operating costs also supported the increase quarter-over-quarter. At UNS Energy, the EPS contribution was unchanged from the second quarter of last year, an increase in transmission revenue was offset by regulatory lag.

For our Western Canadian utilities, EPS increased $0.03 largely driven by rate base growth, including earnings associated with the Eagle Mountain Pipeline project.

At FortisAlberta, timing of operating costs, the expiration of a PBR efficiency mechanism and a lower allowed ROE of 8.9%, 7% effective July -- January 1, 2025, tempered growth quarter-over-quarter.

At our Other Electric segment, EPS increased $0.02 due to rate base growth, higher electricity sales as well as the timing of quarterly earnings at Newfoundland Power related to regulatory approvals. And while not shown on the slide, financial results at ITC were largely consistent with the second quarter of 2024 as rate base growth was offset by higher stock-based compensation and higher holding company finance costs.

Foreign exchange gains associated with the revaluation of U.S. dollar-denominated liabilities contributed a $0.02 EPS increase for the quarter. For the Corporate and Other segment, the decrease reflects the timing of income tax recoveries and higher finance costs, partially offset by mark-to-market gains on foreign exchange contracts. And finally, higher weighted average shares lowered EPS by $0.01, driven by shares issued under our dividend reinvestment plan.

While most of the factors discussed for the quarter are the same for the year-to-date period, lower margin on wholesale sales due to market conditions tempered earnings at UNS on a year-to-date basis. All in all, a very strong first half of 2025.

Through June, we raised over $1 billion of debt to repay borrowings and to fund our capital program. As we discussed last quarter, our 5-year capital funding plan remains intact. With a healthy participation from our dividend reinvestment plan, our $500 million ATM program has not been utilized to date and remains available for funding flexibility as required.

During the quarter, Fitch has signed Fortis a first-time BBB+ credit rating. This new rating underscores Fortis' strong overall credit profile and will support cost-effective capital market funding options. With S&P, we remain focused on highlighting our key initiatives around addressing physical and climate risk. In July, we implemented a public safety power shut up or PSPS plan at FortisBC for high-risk areas within its service territory. This builds on the PSPS plans already implemented earlier this year in Alberta and Arizona as well as the wildfire legislation passed in Arizona.

Turning now to recent regulatory activity. In June, TEP filed its general rate application with the ACC seeking new retail rates effective September 1, 2026. The application includes rate base of USD 4.3 billion, representing an increase of approximately USD 750 million since the last rate case. The increase is largely driven by investments in grid upgrades and new energy resources to maintain reliability, improve resilience and serve expanding energy needs.

The application proposes to phase out or eliminate certain adjustor mechanisms and request an annual formula rate adjustment consistent with the ACC's formula rate policy statement issued in 2024. If approved by the ACC, the formula rate plan is expected to improve rate stability for our customers, reduce regulatory and administrative burden as well as simplify the number of adjuster mechanisms. The formula is also expected to allow for timely recovery of prudent investments and costs within plus or minus 20 basis points of TEP's allowed return.

And while not shown on the slide, UNS Gas rate case continues to progress. In July, the ACC staff filed testimony recommending an allowed ROE of 9.75% and use of an annual formula rate adjustment with an ROE dead band within plus or minus 50 basis points.

Lastly, in June, Central Hudson filed a constructive joint proposal with the New York Public Service Commission in relation to its general rate application. The joint proposal provides for a 3-year rate plan with retroactive application to July 1, 2025, an allowed ROE of 9.5% and a common equity ratio of 48%. An order is expected in the second half of 2025.

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

Thank you, Jocelyn. In conclusion, strong results for the first half of the year progress on the regulatory front and advancements of our growth opportunities beyond the plan positions us nicely for the remainder of 2025 and beyond. As we finalize our next 5-year capital plan to be released later this year, we remain focused on continuing to deliver reliable and affordable service to our customers and compelling long-term returns to our shareholders.

That concludes my remarks. I will now turn the call back over to Stephanie.

Thank you, David. This concludes the presentation. At this time, I'd like to open the call to address questions from the investment community.

[Operator Instructions] And our first question will come from Rob Hope with Scotiabank.

Regarding the Arizona data center opportunity. When we look at the incremental 300 megawatts at the first site and the 500 to 700 megawatts at the other site, how quickly could you develop generation to support these assets? And is this a key gating factor at this point?

Yes. That's a great question, Rob. I've got Susan sitting here next to me to provide a little color. But as you know that first 300 megawatts is using existing and planned capacity. So that's always great to be able to serve them as quick as we can. And hopefully, they're on the same time line as we have disclosed on the 2027 time period. So we have that first 300 sort of under our belt to get them situated there.

And then, Susan, if you want to provide a little color on what we're thinking time line-wise for adding the generation and the transmission interconnections we need for the next 300 at that initial site.

Sure. Thanks for the question. Yes. So as Dave said, the first 300 megawatts of capacity that we're already building and then the second 300 will be -- we'll go through our all-source RFP process. We also announced that we're looking at a green tariff with [indiscernible]. And so it will depend on what kind of generation we move forward with, but the goal is to be in service with that second 300 megawatts in that 2030 to 2031 time frame.

All right. That's great. And then I guess more broadly, when you take a look at your entire system and relative to the existing capital plan, would it be fair to assume that we're seeing the greatest upside potential in Arizona and ITC. And then as we take a look at kind of the '26 plan later this year, are there other key areas we should be looking at where we're seeing probably some outperformance?

Yes. I think you hit the nail right on the head there. We do see some -- and you'll see that in sort of our beyond the plan list. There's a lot at ITC quite a bit at Arizona as well. But we continue to look across the entire footprint. We've got some additional opportunities in BC related to LNG, et cetera. So -- and then across the rest of our footprint, we're looking at opportunities as well. So those are the 2 big ones, but we've got, I think, irons in the fire across the entire portfolio. Thanks, Rob.

The next question will come from Maurice Choy with RBC Capital Markets.

Just wanted to touch on the Springerville position. In your slides, you mentioned that it may take Fortis a longer time to achieve its entrant GHG targets. Alongside the conversion of Springerville, you're not expecting a material impact to your 5-year plan. From these statements, is it fair to assume that the cost of conversion, which I assume has elevated over the past few months, roughly matches some form of renewables for storage in your current IRP?

Yes. There's a bunch of puts and takes that are going to be going on here, and that's kind of why we're getting ready to do our next integrated resource plan in Arizona next year. But on our 5-year capital plan, we'll lay out kind of all those puts and takes that we have in the capital plan.

Obviously, this is a great affordability story for our customers to be able to use existing steel in the ground. Also, that's steel in the ground that's already there, so you don't have to get in line to buy it from somebody else and also has the transmission assets to bring it in, so you don't need additional interconnections. And of course, probably one of the best benefits that we see around that is that overall affordability to our customers and just having those additional jobs in a community that's been so important TEP over these several decades.

Maybe just a quick follow-up to that. Is there any potential for Four Corners to also be converted to gas just as Springerville is going to?

Yes. Yes, that's not -- I don't think we've looked at that, but there's always, I guess, potentials. This is a time I think where a lot of folks are looking at repowering existing coal plants. And the reason that we were able to do this at Springerville is we had one of our partners, both -- who was a partner in Springerville, but also has a cold generating station down the road from Springerville Coronado that Salt River project is being able to partner with someone to make it economic to build a gas pipeline that gets down there. But once it gets down there, hopefully, other folks are using it as well.

Understood. And if I could just finish off with a quick question on my favorite province in Canada, which is BC. I wonder if I could have your latest thoughts on the landscape and outlook for gas infrastructure in the province, particularly given the push for energy infrastructure in the country and seemingly an alignment on gas amongst federal, provincial and indigenous theaters? And what this all means for FortisBC?

Perfect. So I'll turn that over to Roger. But before I do just for full disclosure, Maurice, we are -- actually the teams here in Vancouver. So we now recognize how early it is for you to get up for these calls. Go ahead, Roger.

Thanks for the question. I would say much like Canada, B.C. is a bit of a pivot where they're embracing gas, in particular, the LNG opportunity. As you know, we're pursuing expansion of our LNG bunkering opportunity, and we have our LNG storage tank regulatory process ongoing. So directionally, we see that as positive.

As far as gas connections at our domestic infrastructure, CleanBC, which is the signature policy that is dictating issues like client standards, building code standards, which is the policy that is municipalities are using to constrained new gas connections in new buildings, that's in the midst of a review, and that will come out later this year. So I think that will be the first key signpost to understand how the focus on export of LNG translates into a domestic gas agenda. So more to come on that.

The next question will come from Ben Pham with BMO.

Maybe going back to the Arizona data center update and maybe more broadly on the industry overall, this additional second site that you flagged, did this materialize with you potentially just during the last couple of months is always in the cards we had discussions. And then maybe on a broader level, can you comment your pace of discussions with the data center companies have their power needs expanded recently? Has it gone to maybe more jurisdictions than you had anticipated? And how do you think about the pace of announcements going forward?

Yes, sure. I'll turn that over to Susan to answer.

So the data center that we've been reporting on is we were just lumping it all into total number for capacity. And now there's -- as we bring forth more detail on the project, we're just representing that it will be broken into separate sites. So first building out the first 300 that we signed the contract for in July and then up to 600 megawatts at that first site. And then the second side is another 500 to 700 megawatts. So it's all the same project that we've been talking about for a while.

And then what was the second half of your question there, Ben? What's it?

Yes. And maybe you could expect that a broader thought process and the pace of discussions, the customer needs, have they changed materially over the last 3 months?

Yes. So we do have a long queue of projects in Arizona that are behind this initial project. But when we only have so much capacity, you sort of got to give it to the first folks in line. So that sort of, I would say, puts the rest of the negotiations on ice until you can figure out how you can develop things -- additional resources after the first one takes this 300 megawatts.

But to Susan's point, I mean, there's a lot of details and a lot of conversations that we have with folks in the queue and particularly the one here at the top of the queue. It's just that we're basically allowed now because it's getting public information on how those different megawatts are broken out by sites, et cetera.

Prior to that, of course, and we still are under an NDA for any details that they're not allowing us to release or that they haven't released. So it's just filling in the gaps as we get on the road a little bit further, but also as they're finalizing their plans as well.

Okay. That's great. And my second one on the OBBBA legislation, how that you had a bit more visibility on how things are shaking out. Can you comment impact on Fortis? I'm thinking more renewables and in rate base, ITC that impact? And then anything else that you may have done in the legislation?

Yes. So overall, there was -- there's not a lot of impact from One Big Beautiful Bill Act that was passed. Corporate tax obviously didn't change. We have -- obviously, a few weeks ago, we were talking a lot about that 899 Section, which luckily didn't make it in. Obviously, the renewable energy credit reductions and phase out there, that doesn't really have much of a near impact -- a near-term impact for UNS given where they're at in their cycle of projects.

However, on a going-forward basis, it just changes the calculus of RFPs and options as you go forward. It just creates obviously different economic outcomes when those credits aren't in there for renewables and storage. So we -- I think we'll see a longer-term impact related to that. It's just there's nothing really that we can quantify. Obviously, this -- the tax credits don't necessarily -- they make them -- they make those projects more cost effective for our customers because of the credit. So that's something we'll have to consider.

ITC really isn't impacted again in the short term, either, remember those LRTP tranche 2.1 projects that were allocated to ITC. I mean they're done. I mean, done dusted and given to ITC to build. So there's not any impact there. I would say longer term when you think about the implications of reduced renewable energy and storage development, it might change the mix of generation. Will it be less renewables, obviously, fossil generation is a bit in vogue, again, particularly natural gas to build to fill all the data center needs and growth opportunities.

But that's just different generation that ITC would be interconnecting, right? So take gas or renewables. We still have to build the transmission to serve all this additional load that's being talked about, whether it's data centers, manufacturing or the continuation on the clean energy transition that so many utilities have started. So longer term, we'll see how it plays out. But in the short run, it's a very, very limited impact. Thanks.

Our next question will come from Richard Sunderland with JPMorgan.

There's been discussion of new interstate pipeline capacity into Arizona. I'm curious if UNS is involved in discussions here and if you have a need as you begin building gas plants?

Well, for the Springerville repowering one, that's the -- yes, we have had those conversations and all that additional public information about -- obviously, we got to get gas to Springerville and that's -- that was the big kind of nut to crack to figure out how to do that economically. And as I mentioned earlier, it's great to have a partner like Salt River Project and being an offtaker for that as well. That's the one that we've got in the queue now -- or not in the queue, the discussions to get it in the queue now.

Understood. And then, I guess, just again, same topic, but looking into the 2030s, do you see a growing need there. It seems like the state is probably in an okay position for the next 3 or 4 years, but the next decade is probably a little different.

Yes, that's the calculus we have to look at, right? When we look at our integrated resource plan, next year down in Arizona, I mean this is not static. Remember that 3 years ago is when we did the last integrated resource plan. So as we look going forward, it's going to be a very different load curve that we have to serve. And so that's what we look at and then stack up the resources that we need. I'm sure natural gas will be a part of it. Obviously, renewables and storage will be a part of it. So all of those things kind of go into that mix from a long-term perspective.

So it's all a bit TBD at this point. But at the end of the day, infrastructure is going to be needed across our sector and frankly, everyone that serves our sector, right? So if there's additional gas needs, for generation, there's going to be likely additional pipeline needs as well. But that all goes into that long-term planning process.

I appreciate the commentary. I'll leave it there.

This concludes the question-and-answer session. I would like to turn the conference back over to Ms. Amaimo for any closing remarks. Please go ahead.

Thank you, Chuck. We have nothing further at this time. Thank you, everyone, for participating in our second quarter results conference call. Please contact IR should you need anything further and have a great day.

This brings today's conference call to a close. You may disconnect your lines. Thank you for participating, and have a pleasant day.