Good morning, everyone. My name is Roy Arthur, Vice President, Investor Relations and Investment Partnerships.

Thank you for joining us today to review Capital Power's fourth-quarter and year-end 2025 results, which we published earlier today. Our integrated annual report and presentation for this conference call are available on our website.

During today's call, our President and CEO, Avik Dey, will provide an update on our business. Following that, Scott Manson, our Interim CFO, will present a review of the quarter and our year-end financials for the company.

Avik will then conclude the formal part of the presentation before we open the floor to questions from analysts in our interactive Q&A. In the spirit of reconciliation, Capital Power respectfully acknowledges that we operate within the ancestral homelands, traditional, and treaty territories of the Indigenous peoples of Turtle Island, or North America.

We acknowledge the diverse Indigenous communities located in these areas and whose presence continues to enrich the community. Before we start, I would like to remind everyone that certain statements about future events made on the call are forward-looking in nature and are based on certain assumptions and analysis made by the company.

Actual results could differ materially from the company's expectations due to various risks and uncertainties associated with our business. Please refer to the cautionary statement on forward-looking information or our regulatory filings on SEDAR+.

In today's discussion, we will be referring to various non-GAAP financial measures and ratios, also noted on the same slide. These measures are not defined financial measures according to GAAP and do not have standardized meanings prescribed by GAAP, and therefore are unlikely to be comparable to other similar measures used in other enterprises.

These measures are provided to complement the GAAP measures that are included in the analysis of the company's results from management's perspective. The reconciliations of these non-GAAP measures to their nearest GAAP measures can be found in our integrated annual report.

With that, I will hand it over to Avik.

Thank you, Roy. Good morning, everyone, and thank you for joining us.

Relentless execution is core to who we are. It's what sets the Capital Power team apart and underpins our ability to deliver on our strategic priorities with excellence, as we did in 2025 and sets us up for continued success in 2026 and beyond.

With precision and passion, our team has executed on our strategic priorities. We have acquired 2.2 GW of generation capacity through our PJM acquisition.

We've optimized contracts across 2 GW of contracted capacity, upgraded and expanded 385 MW across our fleet, extending asset life and maximizing value, and advanced or completed 300 MW of new capacity, growing our renewable power portfolio. Acquire, optimize, develop: these are the pathways by which we create value.

Our strategy is straightforward, but how we execute is our competitive advantage. 2025 was an exceptional year for Capital Power.

Our results perfectly highlight our strategy in action: deliberate growth and durable performance driving superior returns. In addition to the strategic wins I just highlighted, our operations team also delivered with excellence in 2025.

Specifically, we generated a record 45 TWh of power across our portfolio, with 52% of total generation coming from our US portfolio, underscoring the successful strategic diversification of our generation portfolio. These achievements are driven by our people, the dedicated experts, innovators, and professionals who are passionately powering North America 24/7/365.

Our 2025 performance demonstrates our team's ability to consistently deliver, diversify our portfolio, and relentlessly execute to drive long-term shareholder value. At our 2025 Investor Day, we outlined our disciplined approach to value creation through growth and clearly defined optimization pathways.

When we acquire assets, we take a strategic approach to value creation. We systematically add value through three optimization pathways.

First, we focus on operating and optimizing the assets themselves, driving reliability, availability, and performance across the fleet. Second, we enhance value commercially through contracting and hedging, using our market expertise to improve cash flow visibility and risk-adjusted returns.

Third, we create value at the enterprise level, leveraging our differentiated funding model to lower our cost of capital and improve overall returns. Together, these three pillars enable us to consistently unlock value beyond the initial acquisition, positioning us to meet or exceed our return targets of 13% to 15%.

Our 2025 performance is a clear example of this strategy in action. As we look to build on our performance in 2026, our approach to growth through acquisitions remains purpose-driven.

We acquire assets in high-demand markets that enhance our strategic position and diversify our portfolio. Why does that matter?

By buying the right assets, we are increasing our scale, allowing us to optimize a large, complementary, flexible generation fleet, diversifying our footprint, increasing our exposure to multifaceted demand growth across North America, and finally, enhancing fleet efficiency, lowering the age and heat rates of our assets, positions us to create value on a merchant basis and for long-term contracts. The operation, optimization, and integration of our PJM assets demonstrate another clear example of our disciplined growth and ability to execute.

In the first two quarters under Capital Power ownership, the Hummel and Rolling Hills facilities delivered strong adjusted EBITDA contribution, performing ahead of expectations with higher dispatch and strong pricing. That transaction increased diversification of our cash flows and lowered market-specific risks, with no single market representing more than 30% of our total flexible generation capacity.

At the fleet level, we continue to apply our industry-leading expertise to optimize our assets. Asset optimization is core to Capital Power's DNA.

We deliberately acquire assets with strong optimization potential and apply disciplined operating, maintenance, and risk management practices to deliver reliable megawatts and enhance value. We have added, or are in the process of adding, 385 MW to our fleet from asset optimization, including 170 MW through our two battery energy storage facilities in Ontario, 110 MW in capacity uprates across three facilities, York, Goreway, and Arlington Valley, and advanced 105 MW in expansion capacity at East Windsor.

As we continue to grow through acquisition, this sets us apart from other buyers in the market, enabling us to identify and deliver values others cannot. It's our competitive advantage compared to other IPPs.

The returns associated with optimizing existing capacity are strong and reinforce our focus on existing generation as a way to address society's need for more power. At a portfolio level, our approach to commercial optimization is fundamental to driving incremental value.

We have been very deliberate in constructing a portfolio of assets in regions with strong supply-demand fundamentals. In the regions where we operate, we see customers looking to contract supply much earlier than in the past, owing to growing demand.

These discussions are anchored in cost of replacement rather than recovery of cost as they have been in the past. As a result, Capital Power's contracted portfolio is poised to see significant growth in contracted EBITDA through recontracting, enhancing margins, reducing volatility, and improving returns for longer duration.

Our new contract for MCV, announced last fall, is a prime example of this strategy in action. Extending to 2040, this new long-term contract provided 10 years of incremental contracted cash flow.

The contract is expected to generate a full-year increase in adjusted EBITDA for the facility of approximately $100 million annually, representing an 85% increase over current contract pricing for the whole facility. To kick off 2026, we also completed the recontracting of Arlington Valley.

The extension of the summer tolling agreement through 2038 secures 13 years of contracted revenue, includes a 35 MW uprate, and resets pricing at 140% above the existing contract, positioning us for continued growth and value creation in the US Southwest. Commercial optimization is about maximizing the value of our capacity with a continued focus on contracting longer duration at better pricing.

Our North American portfolio includes 12 GW of total capacity, with 4.8 GW long-term contracted between 2032 and 2047, 2.4 GW medium-term contracts expiring in the '26 to '31 window, and 4.8 GW of merchant, primarily in Alberta and PJM. Looking forward, our focus is the merchant and medium-term portfolio, where we can extend duration when pricing is attractive.

As always, we will continue to hedge our merchant generation to manage risk near term while preserve the ability to realize long-term upside. I'll now hand it over to Scott to discuss enterprise optimization and financial performance.

Thanks, Avik. Our proven, return-driven model forms the foundation of how we optimize at an enterprise level.

It underpins all that we do, improving efficiency and strengthening organizational resilience. We are focused on maintaining our investment-grade balance sheet, which enables us to acquire high-value assets, secure low-cost capital, and become the counterparty of choice for utilities and other high credit quality counterparties, driving a clear competitive advantage and stronger returns.

Disciplined capital allocation, allowing us to offer a rising dividend while most of our cash flow will be reinvested to fund our strategic fleet expansion. Enhancing our differentiated funding model positions us to accelerate our growth pathways through partnerships like our MOU with Apollo.

Enterprise optimization creates resilient, long-term shareholder value. It drives cost discipline, process improvements, and enables disciplined growth without proportional increases in overhead.

Our full-year 2025 results reflect the execution we outlined throughout the year and underscores the strength of our increasingly diversified portfolio. We delivered adjusted EBITDA of $1.58 billion, an increase of $237 million, or 18%, compared to 2024, and AFFO of $1.07 billion, up $242 million, or 29%, year-over-year.

The increase in adjusted EBITDA was driven primarily by higher contributions from our US flexible generation segment, reflecting the acquisition of Hummel and Rolling Hills in June 2025 and the full-year contribution from La Paloma and Harquahala, which were acquired in February 2024. Results were further supported by lower emission costs in Canada following the repowering of Genesee in late 2024 and lower corporate expenses following the 2024 reorganization.

These gains were partially offset by lower contributions from our Canadian renewable segment following the sell-down transaction we executed in December 2024. The AFFO increase reflects higher EBITDA and lower current income tax expense, partially offset by higher finance expense associated with increased borrowings to fund growth.

While net income for the year was lower than 2024, this primarily reflects non-cash items, including unfavorable changes in unrealized fair value adjustments on commodity derivatives and emission credits, higher depreciation and amortization related to assets acquired or placed into service, and the absence of prior-year divestiture gains. Importantly, these items do not detract from the underlying cash generation strength of the business.

Overall, 2025 was a transformative year that strengthened our platform, expanded our US flexible generation footprint, and materially increased cash flow, positioning the company well for sustained long-term value creation. Our performance in 2025 reinforces that our people, processes, and strategy are aligned and built for this moment.

We see three fundamentals clearly: power demand growth is strong, natural gas is critical, and Capital Power is well positioned to win. We have a proven platform, deep expertise, and a track record of disciplined execution that differentiates us as we move into 2026.

We are reaffirming our 2026 guidance for the year that we laid out at Investor Day. Our outlook reflects the strength of the platform we've built, a larger, more diversified fleet, increased exposure to US flexible generation, and more stable, predictable cash flows.

The guidance is supported by three factors: full-year contributions from 2025 acquisitions, structural improvements that carry forward, and conservative market assumptions supported by disciplined hedging and capital allocation. As discussed at Investor Day, sustaining capital in 2026 will be higher than historical levels.

This increase is planned and deliberate, reflecting the scale and composition of today's portfolio. It's not catch-up spending or related to asset performance, but proactive investment to maintain reliability, protect cash flows, and support long-term earnings durability.

Our MCV recontract is a great example. We've secured a contract that extends through the facility's 50th year of operation.

Executing commercial optimizations like this is only possible with the requisite investment needed to ensure extension of the life of the facility. Even with higher sustaining capex, we continue to generate strong AFFO and support the dividend within our targeted payout ratio.

We remain focused on disciplined growth, supporting the dividend, and maintaining balance sheet strength, exactly as outlined at Investor Day. At Investor Day, we highlighted something really important.

We have multiple opportunities on our existing asset base that require little to no growth capital that can grow adjusted EBITDA by up to $1 billion per year. That growth primarily comes from two levers: resetting contracts at superior pricing for longer duration and capturing rising merchant power prices in Alberta and PJM.

This is embedded upside in our existing fleet. Importantly, we're already executing.

We've recontracted MCV and Arlington Valley, extending duration and materially improving economics. This materially de-risks a significant portion of the $1 billion of potential.

That's why we say existing capacity represents the most compelling opportunity for growth. The assets are already built, operating, and positioned to capture higher value.

Our 2030 targets remain unchanged and continue to frame our long-term strategy, with capital allocation decisions explicitly prioritized towards opportunities that drive AFFO per share growth, support disciplined US expansion, and maintain balance sheet strength. Our 2026 strategic priorities will set the foundation for meeting our 2030 targets.

Thanks, Scott. Before we begin Q&A, I would like to highlight our recent announcement regarding our leadership.

We are pleased to have Kevin McIntosh join Capital Power as our incoming CFO. Kevin has over 30 years of experience as a finance leader working in large, complex organizations within the global energy industry and brings expertise across multi-jurisdictional operations, cross-border transactions, energy trading, and diverse regulatory landscapes.

On behalf of the board, the executive team, and all of Capital Power, I would like to extend our gratitude to Scott Manson for his strong leadership and expertise and his service across many parts of the organization and as interim CFO. Scott will continue to support the onboarding process and transition until the end of April 2026.

With that, I will hand the call back over to Roy.

Thanks, Avik. This concludes the formal part of the presentation.

Operator, you can now begin Q&A portion of the meeting.

Hey, good morning, guys. How's everything?

Great, Nick. How are you?

It's something that you guys outlined in the annual report here. The AESO, and just the ability and kind of ongoing negotiations at Genesee Units 1, 2, and 3 to kind of uprate those, just is there any kind of sense of timing or any clarity to be gleaned surrounding any of those, like the potential increase in generation?

To be clear, it's not an uprate. We have volumes that are already available and subject to a maximum capacity limit on the grid.

We've got a engineering solution to try and unlock those in our 2026 plan. We're expecting those volumes to be unlocked towards the back end of the year.

Just to reiterate, we do have significant expansion capacity at the Genesee site. We see it as probably one of the most attractive generation sites anywhere in North America, with access to land, access to water, access to transmission.

Right. Great.

Perfect. Then, Avik, just cuz we know, I guess some of the Calpine assets are going to be hitting the market soon within the PJM, the ones that need to be divested and everything.

As we think about kind of the right way or the right asset and kind of portfolio allocation, between the PJM and Alberta, and since we're at kind of that 60% that was previously conveyed, any kind of direction that we should be looking, or kind of threshold that we should be seeking when we think of it to the portfolio composition perspective?

Sure. We are deeply committed to maintaining our investment grade rating.

Our contracted floor is 60%. We're near 75% today.

As you think about our portfolio, we are currently not evaluating any acquisition opportunities in Alberta. Our acquisition effort is heavily focused on US generation or generation that can increase overall contractedness.

We will maintain being above that floor of 60%, but we're comfortable with where we are with regard to our ratings. That is a strategic barrier and threshold that we wouldn't expect to fall below.

Great. I'll pass it on.

Morning, everyone. Hoping you can add a little bit of color on the conversations that are ongoing at MCV regarding the 250 MW data center offtake.

Have you opened up that process to other parties as I see it's no longer exclusive?

We have not, Rob. We continue to work with our partners there and continue to advance it.

All right. Thank you for that.

Then in your prepared remarks, you mentioned that recontracting pricing is now moving to cost of replacement versus a cost-recovery model. In the annual report, you do highlight that recontracting is a focus for 2026.

Can you provide an update on how those discussions are going? You've already announced one recontracting in 2026.

Should we assume that there could be some incremental recontracting announcements for the balance of 2026?

I think it's safe to assume that we are actively evaluating multiple recontracting opportunities. In the US, we've got multiple plants that are expiring between '29 and '31, between Freddie, La Paloma, Decatur.

I think if you reflect back to our Investor Day, we've got $1 billion of adjusted EBITDA opportunity to go capture. Within that or over and above that, we've got incremental recontracting opportunities.

I won't pinpoint a specific outcome in a specific period of time, but I think we've delivered on that already between the announcements at MCV and Arlington Valley and continue to explore other opportunities. We feel confident about the opportunity set, though.

Great. Excellent.

I'll pass it on. Thank you.

Morning. Thanks very much for taking my questions.

Maybe starting with the environment for gas-fired M&A. Could you just maybe give us a sense of how that's evolving relative to the last time we dug in on this a bit at the Investor Day, and maybe initial progress on the MOU with Apollo and your discussions there?

Sure. Thanks for the question, John.

I'd say it's a robust market for M&A, and there's a number of opportunities in the marketplace. For us, as Avik mentioned earlier, it's a focus on finding the right opportunities, ensuring that it fits within our mix and ensures we remain investment grade.

For us, the ability to partner with someone like Apollo opens up the aperture of opportunities for us to ensure that we remain investment grade and onside our 60% contracted mix. It gives us a number of incremental opportunities to look at as a result of that.

We continue to work through two agreements with Apollo, and we'll update once we have something to update on that front, but making some progress there.

Oh, go ahead.

I would just add to that, John, just a general market commentary. We're seeing increasing focus from market participants on the value of contractedness, which we think the market's coming towards us in terms of capabilities.

Overall, I think we're seeing a broader opportunity set of acquisition opportunities that extend beyond PJM. I think last year, it was heavily focused on PJM and ERCOT, and I think we're seeing a broader opportunity set than that now.

We're encouraged.

Thanks for that detail. Then maybe just turning to Alberta, just thoughts on your progress on the overall regulatory framework for additional data center load.

I can appreciate you can get into the weeds on how the Phase 2 process is going, but I'm thinking more just bigger picture. How are you feeling about the progress in creating the right conditions in Alberta to attract additional data center load beyond the initial 1.2 GW from AESO Phase 1 that's making its way through FID processes right now?

I'd just go back to my comment to Nick's question, John. We feel really good about the value of Genesee.

I could not be more emphatic about the fact that we think we've got a world-class site that can materially increase generation. I think from the DC perspective, between the government into Phase 1, now into the Phase 2 process, the market environment is increasingly becoming more attractive for Alberta.

The pace at which the announcements are coming out may not be at the pace that the market is expecting, but I think below the surface, the work that's being done to facilitate new generation coming in, the work around contracting and how that will work, and then the general market environment of Alberta, where prices are, where transmission distribution is, and the upfront work that I think the ministry, the regulator has put in place to allow for new load coming in, I think has been in some ways, leading North America. When you compare and contrast that against PJM, who just recently announced the special auction, in many ways, yeah, Alberta's move on Phase 1 front-ran what other markets are looking to do in the US.

I think we continue to be excited about it. Frankly, more excited today than I've been at any other point in time.

It's not changing our disciplined approach to monetizing what we think is the best site in North America. I recognize the boldness of that statement, but I think the facts support just how high-quality Genesee is.

I'll leave it there. Thanks very much for all that context.

Thank you, and good morning, everyone. I just wanted to first touch on the statement of principles by the White House and certain PJM governors.

What do you see as being the biggest risk to what's being recommended, and what can PJM or FERC do to avoid that risk?

Hi, Maurice. I think the biggest risk we as generators see is somehow bifurcating the market in PJM between existing gen and new gen, and the risk of somehow new gen being supported by a different pricing regime.

That's the conversation we and all the generators are having. I think from a supply-and-demand perspective, the good news is if you're a state governor looking at increasing reliability and affordability issues, the incentive to provide incentives through the existing BRA process for existing generators is still there.

What I find incredibly interesting through that exercise is the call to action for 12 GW through the RBA process was coupled with a call for extension of the existing cap and floor. I think that's the single biggest risk.

I think we and all generators in PJM take a great deal of comfort in two key facts, which is the existing cap and floor is not clearing the market currently. It's showing that existing short- to medium-term demand is in excess, well in excess of what existing supply can take, but also secondly, the spread between CONE and existing generation, at call it $60 a megawatt, is a wide enough spread that you're still going to need to encourage new generation and existing generation to increase capacity through the existing BRA process.

Does the 12-gig RBA motivate someone like yourself to want to partake from a new-gen perspective, or do you think the extension of the collars to 2030 is as far as you want to go in this market?

No, I think, like any generator, when you have the opportunity to capture 15-year PPAs with what would notionally be investment-grade counterparties, you have to look at that. Now whether that is for new build or expansions at existing sites, that remains to be seen and negotiated.

I shouldn't say we feel confident, but we're hopeful that we'll have opportunities to do that as well. The short answer and clear answer is yes, we are evaluating it, and we'll look at it.

That's great color. If I could finish off with the revised social objectives agreement, or SOA, with the City of Edmonton.

From your perspective, what flexibilities were you trying to achieve, or perhaps any risks that you were trying to avoid with this new agreement? I'm hoping that you could focus your comments on the two things, like the special limited voting share, as well as the head office location.

The head office location, I'll start with that secondly. There was no objective there other than to reaffirm our commitment to the City of Edmonton through this agreement.

Edmonton is our home. It's been our head office.

It's where the company was created. Frankly, it's a huge advantage, the core that we have built in Edmonton.

It's probably one of the best cities in North America to build out technical, engineering, construction, project management expertise anywhere in North America. Our track record has demonstrated the formidable team that we've built from Edmonton in that regard.

I would say that the SOA piece of this was really about our reaffirming and extending our commitment to the city, which is what the agreement provided for. The real key for this was the special voting share or what others would refer to as the golden share.

When the company spun off in 2009, there was a special golden share that gave certain and specific rights to the city to, in effect, have a veto over the organization. It was important for us to have full governance control and be in full alignment with our shareholders.

It was an opportunity that we took and brought to the city to say, look, the company's been incredibly successful. We're growing.

We've emerged as a leading IPP in North America, and as a result, having flexibility around our governance commensurate with other large, publicly traded companies was the right thing to do, and the city supported us in that.

Understood. Thanks for the color, and my thanks, as well, to Scott for all your help.

Thanks, Maurice.

Thanks. Good morning, everyone.

Just wanted to go back to PJM, Avik, just in terms of the comments about the RBA. Just where are you with conversations with clients?

Is there a bit of an impasse until there's clarity on how this kind of comes out with the governors and the White House proposal? I'm just interesting in terms of conversations you're having right now with potential customers.

We're not having active conversations yet with customers. The ball is in the PJM's court in response to the governors and the National Energy Defense Council.

They've responded in kind with they've received the recommendation and are now evaluating it. We and other generators are in consultation with PJM on what the framework for that could be.

I'm sure some of us are having conversations, but we're focused on ensuring that the framework works for us and all generators currently. Then in due course, we'll prepare.

What I would say, separate and aside from that, since closing the acquisition last year, we've been actively marketing our capacity from a wholesale perspective. It's not like we're not actively marketing it, but I would say we have not specifically responded to the RBA with an outreach tied to the RBA yet.

Can you just clarify what that means in terms of the wholesale marketing efforts?

We're talking to any and all potential wholesale customers on long-term offtakes for capacity and energy.

They're willing to contract, at the range of customers, until there's clarity on the RBA?

That hasn't changed in the market.

Okay. Just going back to the Apollo

I'll just clarify that. The reason is that when you look at the RBA process, that RBA process is specifically for hyperscalers for 15-year PPAs that are looking at CODs that are 2030 or later.

If I'm in the market now, then your needs haven't changed, which is why I think this is important as investors consider this RBA auction, because it's a one-to-one. We're sitting here today in the BRA process, and we're not clearing the auctions.

Short-, medium-term demand isn't explicitly being driven by data center demand, but the RBA process is explicitly focused for long-term data center demand.

Okay. Just going back to the comments on the Apollo partnership, it's still at the MOU stage.

Would that limit your ability to do any larger transactions until you turn that into a definitive deal, or do you think that can get ironed out in the next couple weeks or months, and that keeps you having all that sort of ample opportunity and breadth that Scott mentioned in terms of M&A potential?

What I would say, Mark, simply is we've been advancing the MOU with Apollo. They've been a great partner to date, and we can walk and chew gum at the same time.

Got it. Then just with the Alberta-fed MOU starting to get closer to us here with April, just updated views in terms of where there's making progress in terms of how TIER gets revisited and whether or not the CER goes away?

We expect it to go away. The negotiations are ongoing.

We've participated in the outreaches for consultation as requested. I don't have a further update than that, but we expect it to get ratified as was stated by the Prime Minister and the Premier back in December.

Any possibility there's an extension, just given obviously there's a lot of different things that have to get solved here?

I don't have visibility on that today.

Got it. Okay.

Appreciate the time today.

Hi, thanks. Good morning.

I want to first start off with the AESO Phase 2 large load allocation. Can you comment on what you or the industry expect to see from that to get the DC energy continuing to go forward?

I the Phase 2 Hey, Ben. Phase 2, we're we'll expect to see, bring your own generation result in deals and data center announcements.

I think we're explicitly focused on monetizing Genesee, as I've stated a few times today. What that means for us is we're in the business of selling power and getting PPAs with strong counterparties.

That's going to be our focus. I think the continuing focus across North America on reliability and understanding, how additional transmission distribution affects affordability for consumers, particularly in the US as we're in a in an election year running up until midterms, is continuing to draw interest in Alberta.

Relative to last year or the year before, I would say there's more interest in Alberta today than there ever has been. I think Phase 2, we're focused on investment-grade counterparties that can sign long-term PPAs.

I think the broader universe of opportunities, there'll be others that come in that'll look more like, merchant data centers. I think rising tides lifts all boats.

I think any and all activity in the province is going to support, increased demand and closing that supply closing that supply-demand gap. Our attention, if it's not clear, is on large customers that can sign long-term PPAs that are creditworthy.

Maybe to follow up on that a bit more. The bring your own generation, that's been discussed for some time.

The Phase 1 where it was a pro-rated allocation. Do you expect Phase 2, it's more in the vein of X megawatts each year over a set period of time, RFP-like style allocation, or is it something totally different than that?

No, I think our indications are is the government means what they've said, which is they will work with parties so long as they're not unduly burdening consumers with that solution. I think the trick will be not can you go do a deal if you have behind-the-fence generation, I think the province has been incredibly clear that they welcome that.

I think the trick becomes is if you need a grid connect, what does that mean? How are those costs borne?

That's the distinction between Phase 1 and Phase 2. I think Phase 2 will result in transactions coming forward.

By the way, this is the same issue that is in the US. There's a pipeline of over 50 GW in ERCOT of development deals that have been announced, but the next phase of that is how do you convert that into a revenue model between long-term contract and potential energy exposure?

We're not in a position to say, I'll just be very blunt: for us as Capital Power, would I go do a greenfield power plant in Alberta with a 15-year PPA in a merchant market? Unlikely.

Unless it had full contract coverage or material contract coverage that allowed us to make our rate of return. Now do we have more flexibility to do a lot more on what I think is North America's leading site at Genesee?

Yeah. Which is why I'm able to speak with such confidence around our positioning in the market.

At the end of the day, for me, the opportunity in Alberta, because the market structure affords us the ability to go sell power flexibly with duration, pricing, and shape, it allows us to meet whatever the customer needs, whether it's on the energy side, selling energy, or it's through colocation or building a site. We feel really good about the opportunity set.

It'll take time to get the right deal. We could go do any deal tomorrow; we're going to do the right deal.

I think I've been consistent in that messaging for the last two years.

Got it. Maybe one more topic from me, the Genesee 1, 2, 3 MSCC, let's say you get the clearance this year is 500 MW of addition to supply.

I know you've spent the capex, makes a lot of sense for that. I'm just wondering, I'm not too sure the market wants 500 MW of supply in this oversupplied market right now.

Is that MSCC, is that more of a bridge to the MOU you may be working on or a Phase 2 opportunity?

I wouldn't read anything into that, whether it's a bridge or a subsequent negotiation. It's a technical requirement, the 466 of the AESO for a single-node limit.

I think we're committed to unlocking those megawatts for the grid, which we think is net beneficial because we are effectively baseload for the province, given our efficiency and heat rate on those plants. In any scenario where you look at the merit curve, having more efficient megawatts is net beneficial to the grid.

Then even within our own complex, when you look at G1, G2 versus G3, it's of net benefit to have more from G1 and G2 versus G3. I think in the context of how the province and the AESO look at overall megawatts, I think all of us are collectively aligned in the interest of the consumers to unlock those volumes.

We've just got to get through the permitting process and the testing process.

Got it. Thanks, Avik.

Thanks. Good morning, everyone.

Just maybe back on the PJM market and the RBA. Wondering if we could dive a little bit deeper into the opportunity for Rolling Hills, just in terms of what a balance of plant investment opportunity could look like in terms of potential size and scope.

I know your team is still working on the technical aspects, but just wondering if you had some ballpark figures that you can throw out there.

Hey, Pat. I don't have ballpark figures that I can refer to on Rolling Hills, other than to say it was a plant that we acquired that was running at a 20% capacity factor.

We're doing materially better than that. We've got permits that are air permits that give us capacity of almost twice that.

Then we've got land available and transmission available that would allow for a potential expansion, that would allow for a potential repowering. We are excited about the opportunity set around Rolling Hills, but I'm not in a position to quantify capex or timing or capacity at this point.

Fair enough. I guess now that we have clarity on capacity prices through 2028, and the pricing cap is being held in place there through the end of the decade, wondering if you had an update for us on your financial outlook from Hummel and Rolling Hills now that things have changed since you initially announced the transaction last year, relative to your initial capacity price and utilization assumptions.

Thanks for the question, Patrick. I'd say overall to date, the assets have performed better than expected from a cash flow perspective.

As we look out into the future capacity auctions, including the couple of expected ones that are coming as a result of the RBA, the price expectation that we had is very low relative to where we've seen the auction settle to date and also the relative shortfall that we're seeing coming into the two upcoming auctions here. It is a case where our cash flows were more conservative and the expectation is that it is going to outperform through that 2030 period.

That's great. Thanks, Scott.

Last one if I could, just to follow up on the Alberta Phase 2 process. The 2% levy on new data center investments, I guess 0% if fully off the grid, 1% somewhere in the middle.

Can you just provide us with any feedback, if you have any, on how potential customers are viewing this in terms of competitiveness of this legislation, and whether or not you see this as helping or impeding the development of large-scale projects in the province?

Hello, are we still connected?

Thank you. If there are no more questions at this point, we prefer to conclude the call, we do thank everyone for joining and listening in today and continue to follow the Capital Power story.