David Keith Arcaro: I was wondering if you could maybe just give more of a sense of how the conversations are going with data centers and constraints on the system that you are seeing. So I guess I am curious, are you able to keep up with the transmission capacity needs for data centers to handle all of this load growth? You know, it is the wait time, you know, to connect that you are having to discuss with these customers? And is it fair to characterize a lot of this transmission CapEx that you are adding to the plan here? Is that opening up additional capacity to bring in these new customers? Wondering how that all kind of balances right now.
William J. Fehrman: Yes. Thanks for that question. Really excited about where we sit in this regard. As we have noted in here, the increased incremental load growth projected through 2030 is the 28 gigawatts up from the 24 that we talked about before. And that demand growth is roughly 80% tied to data centers in the commercial class and about 20% tied to the industrials. Breaking that up a little more, about 75% is related to transmission and distribution, while 25% is tied to the vertically integrated utilities. And so as I look out across the RTOs, roughly half ends up in ERCOT, 40% in PJM, and about 10% in the SPP.
And so as we look at where we sit to connect these customers, clearly we are working with them to site where we have available transmission today to help them with their ramp-ups in the manner in which they want to run their side of the business. And then in other cases, we are working with them to put in place behind-the-meter solutions. Obviously, 190 gigawatts. But in the meantime, as Trevor noted, we are very focused on reporting what we have signed. We are going to under-promise and over-deliver in this area, but I could not be more excited with where we sit across our service territory.
We are in, I would say, the catbird seat with regards to connecting data center load. The 765 kV transmission network that we have provides us with an extreme competitive advantage for where these folks are trying to site. And so I just see an amazing future ahead of us in this area.

We continue to have conversations with state leaders regarding fair financial returns that they desire to attract more capital and make West Virginia an energy hub.

... we are fully engaged in West Virginia. We are working with all the stakeholders there, and that continues to be a major focus of mine. I am spending a significant amount of time in West Virginia to try and support a better outcome there.

Mon Power and Potomac Edison, subsidiaries of FirstEnergy Corp. (NYSE: FE), have submitted an Integrated Resource Plan (IRP) to the Public Service Commission of West Virginia that outlines how the companies will continue to deliver reliable, cost-effective power to West Virginia homes and businesses over the next decade.
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West Virginia's energy landscape is changing as industries grow, and the need for dependable, cost-effective power is critical. The IRP lays out a roadmap to meet the need, guided by local priorities and a commitment to keeping power accessible and resilient.

The proposed gas and solar investments are aligned with Governor Morrissey’s 50 by 50 initiative, which aims to boost West Virginia’s energy capacity to 50 gigawatts by 2050. We are pleased to pursue generation projects in a state with strong executive, legislative, and regulatory support.

This is an exciting opportunity for FirstEnergy...

Question:  I was just wondering, this morning, on the West Virginia generation, if you kind of talked about build-own-transfer versus self-build, can you maybe kind of talk about how you’d recover the capital in either scenario and how we should kind of think about the impact to earnings 2028 through 2031? If you’re just kind of thinking about a build-own-transfer for 2031, is there really no earnings attribution until then, or could there be milestone payments? Maybe you can kind of expand on that.Answer:  The build-own-transfer, I think, is fairly straightforward. On the we build it side, we, of course, would file for CWIP during construction. We’d expect at least the recovery of that, if not the earnings component, during the pendency of construction. The real significant earnings component for that will come after the asset’s online.

... we think of it as firming up the ability for us to be in that 6% to 8% earnings per share range over the planning period. You know, people don’t traditionally think of utilities as growth investments, but as we look at the opportunity to invest in our system, increasing CapEx over the period, it gives us real confidence that we’ll solidly be in that 6% to 8% earnings per share growth range.

Question:  You touched on in your comments, I guess, the bill increases and the impact generation has had on that. I was just wondering if you could expand a bit more there on the appetite to build new generation elsewhere across PJM if there’s the proper underpinnings to it. How do conversations look on that, and anything new to report there?
Answer:  Yeah. Nothing new to report there, Jeremy. The place where we have a clear window, a supportive Governor, commission, and legislature is in West Virginia. That’s how we’re able to move forward so quickly with those plans. The idea that we’d be building in any of the other states on a long-term basis would really just be speculative at this point.

The impact of this demand will be tremendous. Based on data center customers who are contracted or in our pipeline, we expect FirstEnergy’s system peak load to increase 15 gigawatts, or nearly 50% from 33.5 gigawatts this year to 48.5 gigawatts in 2035. Across PJM, peak load projections are forecasted to increase by nearly 48 gigawatts by 2035, or 30% of the current peak load of 162 gigawatts. FirstEnergy is uniquely situated to support this growing demand through customer-focused investments, specifically in our transmission system.

This system is located in the heart of PJM, interconnecting with a broad number of neighboring utilities and encompassing strategic high-voltage corridors that are a vital part of the transmission grid.

We are also participating in regional network upgrades, which are the investments awarded through PJM’s RTEP open window process.
This includes required system upgrades and improvements to address reliability, security, and load demands of the bulk electric system. Over the last few years, we have been awarded $4 billion of capital investments through the PJM open window process. We recently submitted proposals of capital investments through the 2025 open window to support increasing demand in Ohio, Pennsylvania, and Virginia. These proposed investments include several new and upgraded substations and high voltage lines needed to support the increasing customer demand. The PJM board is expected to award transmission projects in this open window by the first quarter of 2026.  Any projects awarded to FirstEnergy in this open window will be included in our new five-year plan. We now expect transmission investments included in the 2026 to 2030 capital plan to increase by 30% versus our current five-year plan.

​This includes increases from reliability enhancements and regulatory required investments to improve the overall health and performance of our most critical assets on the system and to address growing demand and changes in generation in the region. Our company-wide transmission assets are a terrific growth engine. Our investments are expected to result in a compound transmission rate-based growth of up to 18% per year through 2030. This means total transmission rate base would more than double through the planning period.

Question:  I guess looking at the data center pipeline, I was wondering if you could refresh us on just, you know, the activity seems to continue to be very strong. As you see more gigawatts maybe come in and firm up, is there a way to give any rule of thumb for how much increased transmission CapEx you could see going forward, like on a per-gigawatt basis? I think you’ve given that rule of thumb in the past, but the CapEx that you’re adding to the plan here seems to be, you know, quite a bit stronger. Just wondering your current thoughts on as more and more data center activity continues to come to your service territory, what that could mean going forward.

Answer:  In total right now, as we look at what’s contracted and just our transmission CapEx program in total, I think you could say there’s probably easily $1 billion of CapEx associated with transmission interconnection requests, whether that be direct connection projects or network upgrades to support large loads. That’s what we see now based on the contracted and active large load customers that we have. I think that will vary as we move into the future. We’ve seen a wide range of capital deployment based on interconnection requests depending on the location and the size.

Most of this growth will come from high-quality transmission investments backed by forward-looking rates with constructive ROEs. We’re also excited about new opportunities to invest in generation in a state that is supportive of these efforts.

In closing, the team is extremely focused on the value proposition that we offer to shareholders. We are focused on delivering enhanced customer experience through strong customer-focused investments, which in turn will allow us to provide solid risk-adjusted returns to our investors. The future is bright for FirstEnergy.

​Whether it be industry-leading transmission investment opportunities, significant reliability investments in the distribution system, or the build-out of regulated generation in a supportive state like West Virginia, we have a strong business plan and the right team to execute. We are committed to continuing our positive momentum and delivering value for our shareholders.

Grain Belt Express Issue A: Ameren shall model and share the results of generation that can be delivered through Grain Belt Express to Ameren’s service territory. For this modeling, Ameren shall use data for generic Kansas resources, including wind, solar, battery and natural gas generation, as distinct from data for generic Missouri and Midcontinent Independent System Operator (“MISO”) resources. For this modeling, Ameren shall also use an ownership and delivery cost based on discussions between Ameren and Grain Belt Express. If a firm delivery cost cannot be provided by Grain Belt, Ameren shall use a range of delivery costs to account for uncertainties in what the actual ownership and delivery costs may be.

Grain Belt Express Issue B: Ameren shall weigh the reliability, resiliency, and operational benefits of HVDC transmission facilities. In particular, Ameren shall weigh resource diversity values, cost-effective black-start capabilities, active and reactive power control, voltage and frequency control, dynamic voltage support, emergency power control and power modulation, and damping of electro-mechanical oscillations.

Grain Belt Express Issue C: Ameren shall also assess the potential resource adequacy value provided by Grain Belt Express’s ability to access available generation in neighboring regions. This value is separate from the capacity value of contracted resources with firm transmission on Grain Belt Express. Ameren shall conduct probabilistic analysis using a methodology equivalent to that used by PowerGEM (formerly, Astrape) to evaluate the resource adequacy value of the North Plains Connector.

​This issue goes beyond the bounds of IRP requirements to evaluate "generic" resources and contemplates analysis that is outside the resource adequacy considerations of Ameren Missouri; therefore, it should not be considered a special contemporary issue. Regardless, Ameren Missouri has already evaluated the broader market benefits of two-way flow on the GBX line as part of its analysis pursuant to the aforementioned stipulation and agreement and included in the Company's 2025 IRP Annual Update.

Invenergy also requests that the Commission use its authority under section 309 of the FPA37 to grant remedial relief with regard to LRTP decisions that MISO has made to date to ensure that Tranche 1 and Tranche 2 assessments will result in just and reasonable rates. 

Invenergy asserts that, despite the fact that it now has an effective TCA, MISO’s Tranche 2 draft portfolio still did not consider the impact of advanced-stage merchant transmission and therefore proposed a new 765 kV transmission line in Missouri that is redundant to the GBX Line.

In this case, Invenergy has not shown that MISO’s approach is unreasonable in how it is treating the external nature and unidirectional flow of the GBX Line, and the contention that the GBX Line can be operated bidirectionally misses the mark. The record is clear that Invenergy has not requested the ability to withdraw energy from MISO but only to inject energy onto MISO’s system. Even though the GBX Line could allow bidirectional flow, the GBX Line does not have the agreements and studies in place to effectuate bidirectional flow. This same logic also applies to the GBX Line as an external facility, as it is not intended to solve transmission issues on MISO’s transmission system.

Positive Impacts for Americans: Upgrading the grid is worth it if it creates good-paying jobs for American workers, boosts economic development in communities, and uses American-made materials – even if it costs a little more – because it keeps our country strong.

American Energy: Upgrading our electricity transmission grid will allow us to produce more energy here in our own state, reducing dependence on foreign countries. It is a key step toward future energy independence.

Lower Costs: A modern electricity transmission grid helps open the door for more competition and innovation in energy, giving consumers more options with lower prices and better service.

Prevent Blackouts: A stronger, smarter electricity transmission grid protects us from blackouts, cyberattacks, and natural disasters – keeping the lights on when it matters most.

...the commission may approve the application if it finds that the proposed transmission line:
(1) Will economically, adequately and reliably contribute to meeting the present and anticipated requirements for electric power of the customers served by the applicant or is necessary and desirable for present and anticipated reliability of service for electric power for its service area or region;
(2) Will be in the best interest of West Virginia customers and its citizens; and
(3) Will result in an acceptable balance between reasonable power needs and reasonable environmental factors.