TRANSALTA CORP(TAC)Q2 2026 法說會逐字稿

Good morning. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the TransAlta Corporation Second Quarter 2026 Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star then 1 on your telephone keypad. If you would like to withdraw your question, please press star then 1 again. Thank you. Ms. Paris, you may begin your conference.

Thank you, Michelle. Good morning, everyone. My name is Stephanie Ann Paris, and I am the Vice President of Investor and Corporate Strategy of TransAlta. Welcome to TransAlta's second quarter 2026 conference call. With me today are Joel E. Hunter, President and Chief Executive Officer, Mike Politeski, EVP Finance and Chief Financial Officer, and Christopher D. Fralick, EVP Generation and Chief Operating Officer. Today's call is being webcast, and I invite those listening on the phone lines to view the supporting slides that are posted on our website. A replay of the call will be made available later today, and the transcript will be posted to our website shortly thereafter. All the information provided during this conference call is subject to the forward-looking statement qualification set out here on slide 2, detailed further in our MD&A and incorporated in full for purposes of today's call. All amounts referenced are in Canadian dollars unless otherwise noted. The non-IFRS terminology used, including adjusted EBITDA and free cash flow, are reconciled in the MD&A for your reference. On today's call, Joel and Mike will provide an overview of TransAlta's quarterly results. After these remarks, we will open the call for questions. With that, I will turn the call over to Joel.

Thanks, Stephanie. Good morning, everyone, and thank you for joining our second quarter conference call. TransAlta delivered solid operational and financial performance during the second quarter of 2026, demonstrating our fleet's continued resilience during challenging market conditions. During the quarter, we delivered adjusted EBITDA of $291 million, free cash flow of $143 million or $0.47 per share, and average fleet availability of 90.2%. Our Alberta merchant portfolio continues to be impacted by softer prices. Our hedging strategy and active asset optimization generated realized prices that were well above spot prices during the quarter, along with our hydro and wind assets providing significant environmental offsets to our gas fleet's 2025 carbon compliance obligation. We remain confident in achieving our 2026 guidance range, which Mike will talk about later. In the quarter, we continued to advance our data center strategy with CPP Investments and Brookfield. More broadly in Alberta, recent developments reinforce the momentum and collective commitment across government and industry to develop AI infrastructure. In June, the Government of Alberta published their data center regulations, giving authority to the AESO to proceed with the next phase of their large load integration plan. The regulation includes provisions that permit the AESO to determine underutilized capacity that can be used to serve incremental data center load. Consistent with our messaging at Investor Day, we believe that our gas-fired steam units constitute underutilized generation that can support both grid reliability and the continued buildout of AI infrastructure in the province. Our gas-fired steam units are designed to operate as baseload and can produce capacity factors greater than 90%. The recent performance and lower capacity factors averaging around 20% in 2025 have been driven by economic decisions, not capability. Speed to power is critical, and we view the data center regulations as an important step toward framework clarity. The determination on how underutilized assets will be incorporated into the buildout of AI infrastructure will be made by the AESO, and we remain actively engaged with them. Also in the quarter, we fully integrated the four gas-fired facilities in connection with the acquisition of Far North. In June, the U.S. Department of Energy issued its third temporary order requiring that Centralia Unit 2 remain available for operation if needed for a period of 90 days. TransAlta is adhering to the order, and we plan to submit a request for reimbursement to the FERC for costs related to the second order. Progress continues with the conversion of the unit to natural gas, and I am pleased to report that our timeline for a final investment decision in the first quarter of 2027 remains on schedule. Last month, we announced that TransAlta has entered into an agreement to acquire two natural gas-fired peaking facilities in Colorado for US$1 billion paired with a common share offering for $350 million. Both assets are fully contracted to investment-grade counterparties under long-term tolling agreements that include full cost pass-through of all operations and maintenance, fuel, and capital expenses, which meaningfully reduce the risk profile of the acquired assets. The acquisition is expected to deliver $110 million per year in low-risk, high-quality adjusted EBITDA to our portfolio and is immediately accretive to free cash flow per share. We expect closing to occur in the fourth quarter following receipt of all regulatory approvals as well as Canyon Peak Power achieving commercial operations. Adding stable operating assets like this delivers immediate cash flow that can be redeployed into our most compelling growth initiatives, including the Centralia coal-to-gas conversion and Alberta data center projects. Finally, we realigned our executive management team, adding Mike Politeski as our EVP Finance and Chief Financial Officer and Grant Arnold as our EVP Growth and Chief Commercial Officer. In addition, Nancy L. Brennan assumed an expanded role as Chief Legal, People, and Corporate Affairs Officer and Christopher D. Fralick's new title is EVP, Generation, and Chief Operating Officer. Supported by an exceptional team across the organization, I am confident that we have the right people and structure to execute our strategy and realize long-term value creation for TransAlta. I will now turn the call over to Mike to talk more about our financial performance in the second quarter of 2026.

Thanks, Joel. Good morning, everyone. During the quarter, we generated adjusted EBITDA of $291 million despite challenging market pricing in Alberta. Our Hydro segment adjusted EBITDA was $87 million, down $39 million from the same quarter in 2025 due to lower Alberta spot and hedge prices as well as lower intercompany sales of emissions credits. Our Wind and Solar segment reported adjusted EBITDA of $90 million, consistent with the prior year as higher U.S. wind resource mitigated lower Alberta pricing and reduced wind resource in Eastern Canada. Within our Gas segment, adjusted EBITDA was $14 million higher than the prior year due to strong optimization of our Alberta fleet and positive contributions from our Far North acquisition. Consistent with prior years, our second quarter results benefited from the realization of emissions credits against our prior-year carbon obligation. For the balance of 2026, we expect additional contributions to our segments from the realization of carbon credits against in-year carbon compliance costs. Our Energy Marketing adjusted EBITDA decreased by $16 million primarily due to subdued market volatility in western power markets and lower realized gains within the quarter. We expect to have more gains realized by year end as favorable trade positions settle. In our Corporate segment, costs were 8% lower than the prior year due to initiatives to control spend. And finally, our Energy Transition segment adjusted EBITDA was lower than the prior year due to the Centralia contract expiry at the end of 2025. We also generated strong free cash flow during the second quarter totaling $143 million. Our sustaining capital expenditures were down $18 million year over year; however, this was primarily timing related and we continue to expect sustaining capital of $140 million to $160 million in 2026. Turning to the Alberta portfolio, spot prices averaged $29 per megawatt hour in the second quarter, notably lower than the $40 per megawatt hour in the second quarter of 2025. The decline was primarily due to seasonally lower demand and continued strong supply in the market. Although prices were low, we enhanced our margins by meeting portions of our higher price hedge commitments through power purchases when market prices were below our variable production costs. We benefited from approximately 2.4 thousand gigawatt hours of hedges at an average price of $63 per megawatt hour, which was $34 per megawatt hour higher than the average spot price. Our gas fleet realized an average price of $68 per megawatt hour, a significant 134% premium to the average spot price, largely due to our dispatch optimization during high-price hours, which materially raised our realized price. The hydro fleet also continued to capture merchant upside, delivering an average realized price of $36 per megawatt hour, a 24% premium to the average spot price. Our merchant wind fleet realized an average price of $14 per megawatt hour, which was impacted by increased thermal production and intermittent wind and solar generation. During the quarter, we also delivered approximately 900 gigawatt hours of ancillary service volumes at a 14% premium to the average spot price. Through effective fleet optimization and meeting hedge obligations with purchased power, we consistently addressed the AESO's need for reliability products. We continue to have a strong hedge book to support our Alberta cash flows. For the balance of the year, we have approximately 4.5 thousand gigawatt hours of our Alberta generation hedged at an average price of $64 per megawatt hour, well above current forward pricing. For 2027, we have approximately 6.6 thousand gigawatt hours hedged at an average price of $64 per megawatt hour, also well above current forward levels. Looking ahead, we expect the Alberta supply-demand imbalance will correct later this decade with anticipated load growth. We believe we are well positioned to manage through the current pricing environment and to capture growth opportunities to drive long-term value creation for our shareholders. Turning to the balance sheet, in June, Moody's reaffirmed our Ba1 rating with a stable outlook, and last week, S&P reaffirmed our BB+ rating while shifting the outlook to negative. We remain committed to strengthening our balance sheet through multiple levers, including asset recycling. In addition, the forecast tightening of the Alberta market and recovery of power prices along with expected cash flows from Centralia after conversion will provide cash flow growth to further strengthen our financial position. Overall, we are pleased with our year-to-date operational and financial performance across all our business segments and we remain confident in our ability to meet our 2026 guidance range. Our contracted fleet, strong hedge position, and consistent optimization provide us with core cash flows even in a low merchant power pricing environment. The Colorado acquisition is not factored into our reaffirmation of guidance and upon closing, which is expected in the fourth quarter of 2026, will add to our financial results. I will now turn the call back over to Joel.

Thanks, Mike. This year, we remain focused on the following priorities: improving our leading and lagging safety performance indicators while achieving strong fleet availability; delivering adjusted EBITDA and free cash flow within our 2026 guidance ranges; maximizing the value of our legacy thermal sites by advancing our Alberta data center strategy; advancing our coal-to-gas conversion at Centralia toward a final investment decision; pursuing strategic M&A opportunities; and enhancing our financial strength and flexibility through disciplined capital allocation and cost control. I believe TransAlta offers a compelling investment opportunity. We have operated a safe and reliable power generation fleet for over 115 years, providing strong and consistent cash flows. This strength is grounded in a diversified portfolio of hydro, wind, solar, storage, and thermal assets across three countries, enhanced by our industry-leading asset optimization and energy marketing capabilities. Our legacy sites continue to represent considerable and increasing value. We are proactively pursuing repurposing initiatives at these facilities to address the growing demand for reliable power in our operating markets. Concurrently, we maintain a leadership position across multiple technologies, consistently prioritizing responsible and reliable generation. We are disciplined in how we grow. Our priority is creating shareholder value as we diversify our portfolio within our core geographies and continue to increase the stability and contracted nature of our cash flows. This strategy is supported by a strong financial foundation. We have a flexible balance sheet and ample liquidity, giving us the ability to pursue and deliver multiple growth opportunities while continuing to return capital to shareholders. And finally, and most importantly, we have our people. Everything we achieve is powered by the dedication and expertise of our employees and contractors. I want to thank them for their commitment and for positioning TransAlta for continued success in 2026 and beyond. Thank you, and I will now turn the call back over to Stephanie.

Thank you, Joel. Michelle, would you please open the call for questions from the analysts?

Thank you. Star 1 on your telephone, and wait for your name to be announced. To withdraw your question, please press star then 1 again. In fairness to all, we ask that you please limit yourself to one question and one follow-up. One moment as we compile our Q&A roster. Our first question is going to come from the line of Mark Jarvi with CIBC. Your line is open. Please go ahead.

Good morning, everyone. Just in terms of those discussions with the AESO and the underutilized assets, do you have any sense of when you might have clarity and just how that is impacting anything about getting from the MOU to a definitive agreement with Brookfield and CPP?

Thanks, Mark, and good morning. There are ongoing discussions with the AESO, and we are encouraged by the data center regulations, which assign the AESO to determine what is underutilized capacity as it relates to our gas-fired steam units. We are working with them collaboratively as we move forward. The MOU and the definitive agreements we have with CPP Investments and Brookfield continue to advance as we highlighted when we announced the MOU in February. We are working alongside those two parties, and we remain confident in our ability to bring forward our data center option later in the year.

So the expectation is a matter of months, could be a couple quarters, before you have clarity on the underutilized assets?

It is hard to say. We cannot speak for the AESO, but we are actively engaged with them. We are hopeful it will be in the next quarter or so, but we cannot speak on behalf of them as to the timing.

And then obviously, that might influence how you think about scaling beyond the 230 megawatts. So if that dragged on a little bit, would you look at possibly moving to FID on the first phase of the 230 megawatts from phase 1 allocation and then subsequent scale up after that through a follow-on agreement? Is there a way to sequence moving through FID?

That is very possible. It will be up to us along with Brookfield and CPP Investments to determine that. We were pleased with the 230 megawatts in the Phase 1 load allocation, and we are looking forward to how we can build upon that. There is a possibility we could advance the 230 megawatts before we get the remaining clarity on underutilized capacity.

Okay. I will leave it there for now.

Thank you. And our next question is going to come from the line of Maurice Choy with RBC Capital Markets. Your line is open. Please go ahead.

Thank you, and good morning, everyone. Just wanted to touch on any updates you have on the asset recycling initiatives that were mentioned earlier to reduce debt. What are some of the things influencing the timing and perhaps selection of some of these assets for sale?

We are very active. We have a few processes well underway, but we cannot provide all details while processes are ongoing. Given the amount of opportunities we see—Centralia coal-to-gas conversion, AI data centers, M&A opportunities, and organic growth—portfolio rotation will become more active. We have a few processes underway and are certainly active in that space right now.

I am looking forward to hearing more on that. If I could finish with a broader discussion about forward power prices: since the announcements, we've seen forwards move up a bit, particularly for 2029, yet it is still below the $80 to $120 range you laid out at Investor Day. You mentioned positive developments in the province. What else are you expecting in the coming months that would prompt the forwards to rise into your projected range?

When you look further out to Cal 2028 and 2029, liquidity is limited and forwards generally show reliable pricing out approximately 12 to 18 months. Cal 2029 is currently around $81, which is within the $80 to $120 range discussed at Investor Day. We have seen an improvement in forward prices since the announcement of Meta's data center project with Kineticor and Pembina, and we remain encouraged. Further clarity around the ramping of load growth will support forward pricing. As the market gains better visibility on load ramp, that should further support forward prices and could push them higher.

Maybe on that last note: historically when we had triple-digit power prices in 2021 to 2023, the regulator looked into the industry. In an affordability context, is there such a thing as a balanced number where most stakeholders would be comfortable?

When you consider CONE, or the cost of new entry, recent announcements put it in the low 100s, which makes sense given current new build costs versus 2021–2023. That underscores the value of legacy generation, such as our gas-fired steam units, which can support infrastructure buildout at prices below CONE. The market will tighten and if new generation is required, pricing will reflect the cost of new build and the return required by providers. Also remember that Alberta's average power bill is roughly one-third the price of energy and two-thirds transmission and distribution. As load increases, transmission and distribution costs can be spread across more consumers, which affects overall affordability. So it's not solely the cost of energy that matters.

That is a really good point. Thank you very much for the color, Joel.

Thank you. And one moment for our next question. Next question is going to come from the line of Robert Hope with Scotiabank. Your line is open. Please go ahead.

Good morning, everyone. I appreciate the commentary on the asset sales potentially strengthening the balance sheet and acknowledge that you may be limited on what you can say. How do you think about an asset sale program when you have uncertainty regarding the Brookfield hydro option, which could provide a significant amount of capital for TransAlta?

It is both. We factor in the Brookfield option as one lever to strengthen the balance sheet. At conversion, it could provide a cash infusion and remove about $750 million of debt from our balance sheet as it relates to how rating agencies view our leverage. Asset sales are another lever. We see many opportunities for the company—Centralia conversion, AI data centers, M&A opportunities such as the Colorado acquisition, and other greenfield opportunities—which will require capital. There is no shortage of uses of capital, so as we look to strengthen the balance sheet and provide incremental cash, we consider both Brookfield's potential conversion and asset recycling.

Appreciate that. Going back to the bring-your-own-generation process and repurposing assets: when you think about the decision tree for using your steam conversions on an interim basis as a bridge to a larger brownfield expansion, how do you work through the uncertainty of what AESO will ultimately decide?

Part of the decision tree is determining how much of the gas-fired steam units can be classified as underutilized or bring-your-own generation. We have significant gas-fired steam capacity and saw capacity factors around 20% in 2025, which suggests excess capacity that could be used as bring-your-own generation. Using these units to support AI infrastructure is attractive because new builds today are expensive and face supply chain constraints. Deploying existing units can support AI infrastructure now and lead to new builds next decade, when repowering will be needed to run for decades thereafter. This approach is compelling for Alberta since we have surplus generation, and it allows for long-term, underpinned contracts with customers.

Thank you.

And one moment for our next question. Next question will come from the line of John Mould with TD Securities. Your line is open. Please go ahead.

Good morning, everybody. Maybe a follow-up on repowering projects such as Keephills and Sundance. How active are you on costing, planning, and readiness to proceed rapidly if meaningful load growth arises, or should investors think of these as longer-dated options into the next decade?

Keephills 1 and Sundance 5 total just over 2 gigawatts. There is still a lot of work going on, and it is early days, but we are actively doing the planning. The first step is utilizing underutilized capacity from our gas-fired steam units, which is the most effective approach. We would then potentially build out these sites next decade. We are not looking to build these immediately because the assets, gas, transmission, and water are already in place; the staged approach is to use existing units first for speed to power for AI infrastructure, then repower those sites down the road. The planning, stakeholder engagement, and other preparatory work is underway because these projects take a long time.

Thanks for that. On hedges, you added about 20% incrementally in volume for next year. What kind of appetite are you seeing from customers to contract at more normalized pricing levels versus holding spot exposure, and how does that contribute to your ability to add meaningful length to your hedges between now and year end?

We remain active managing our hedge portfolio. About half of the portfolio is our C&I business, which functions like rolling three-year contracts, and those transactions generally occur at a premium to forward pricing. The team looks for opportunities with attractive spreads and locks them in. For next year, we have around 6.6 thousand gigawatt hours hedged at $64, which is well above current spot pricing, driven by our C&I business and adding financial hedges where appropriate. This capability is a core competency of TransAlta and we expect the team will continue to find opportunities to roll in hedges going forward.

Okay. I will get back in the queue. Thank you.

Thank you. And one moment for our next question. Our next question is a follow-up from the line of Mark Jarvi with CIBC. Your line is open. Please go ahead.

Thanks. Following up on underutilized assets: if you got a meaningful amount granted by the AESO, say a gigawatt or more, would that likely be used to scale up increased opportunities around Keephills, or might you look at another site like Sundance?

Right now we are focused around Keephills. Depending on the ultimate amount granted, we certainly have the land, gas supply, and transmission at Keephills to support additional buildout. So up to a gigawatt or higher could be supported at the Keephills facility.

Okay. Thanks.

Thank you. And one moment for our next question. Our next question is going to come from the line of Patrick Kenny with National Bank Capital Markets. Your line is open. Please go ahead.

Good morning. On Centralia, I know you are working on the Class 3 estimate for Unit 2. Has there been any progress on potentially getting more gas supply or looking at repowering Unit 1? How should we think about the timing of that opportunity and how brownfield returns might compare with Alberta greenfield or other U.S. M&A opportunities?

We are progressing the Class 3 estimate on schedule; we expect to have it by the end of the year and be in a position to make FID very early in 2027, subject to required permits and approvals including WUTC approval from Puget Sound Energy. That work is well underway. The returns are attractive: we estimated a $600 million capital cost at a 5.5x build multiple, which is very compelling. Gas supply for Unit 2 is the responsibility of Puget Sound Energy, and there is sufficient supply nearby with the gas line roughly 1.5 thousand feet from the facility. Unit 1 is longer term; discussions have begun but it is early, and pipeline capacity in the Northwest is constrained today. Unit 1 would be a potential next-decade opportunity, but we do not place a high probability on it currently. Our focus is getting Unit 2 to FID early next year and moving toward commercial operation in the fourth quarter of 2028.

That is perfect. Thanks for that. On the M&A front, after the Colorado transaction closes, how would you describe your wish list regarding geography, asset type, or technology? How are you thinking about maximizing portfolio value through M&A, in terms of synergies or other factors?

We are pleased with the Colorado acquisition: it offers long-dated cash flows with a weighted average contract duration of 27 years and full cost pass-through. Our M&A strategy remains focused on our four core geographies. We remain technology-agnostic and pursue the highest risk-adjusted returns. Recent activity has included more gas-fired assets, but we will consider renewables when they meet our return criteria. The Heartland acquisition in Alberta and Hut 8 in Ontario are examples of differing risk profiles and multiples. We also remain conscious of our balance sheet. Active asset optimization and portfolio rotation will support future opportunities, and we will evaluate each opportunity on risk-adjusted returns within our geographic focus.

Okay. That is great. Thanks, Joel.

Thanks. Thank you. And one moment for our next question. Our next question will come from the line of Benjamin Pham with BMO. Your line is open. Please go ahead.

Hi. Thank you. Good morning. Following up on returns and risk profiles across energy infrastructure: can you put some bookends on the returns and how you adjust for different risk profiles?

We evaluate opportunities across a spectrum. For example, Heartland was older vintage assets with substantial contracting and transacted at around a 5.4x multiple. Hut 8 had older assets and shorter contracts and was acquired at a lower multiple. Colorado is a higher multiple, but it is brand-new generation with 27-year contracts and full cost pass-through. We evaluate transactions on overall portfolio fit. A useful metric is free cash flow yield: the Colorado acquisition offers about a 13% free cash flow yield, versus our corporate free cash flow yield around 7%, so Colorado is accretive on a free cash flow basis. We also consider EV/EBITDA, the leverage on acquired assets, and per-share metrics to ensure accretion and not dilution. Returns vary by asset vintage, contract length, and risk profile, and each opportunity must stack up on a risk-adjusted basis.

Can you comment on whether recent credit rating updates constrain your ability to pursue M&A over the next 12 months?

We view the negative outlook from S&P as a temporary hurdle. Soft Alberta power pricing and Centralia being offline have impacted cash flows, but we see a glide path forward to recover the balance sheet. Alberta forward markets show uplift in the back half of 2028 into 2029 and our hedge book sets up 2027 nicely with 6.6 thousand gigawatt hours hedged at $64. Our optimization capabilities are strong, as demonstrated in Q2. The Alberta data center opportunity is capital-light and credit positive. Progressing Centralia to FID and COD timing in late 2028 provides a wave of cash flows. Asset recycling will also generate proceeds to help the balance sheet. Overall, we see many incremental improvements to progress the balance sheet; in the meantime, it is not hampering our flexibility materially. We remain conscious of leverage levels and how rating agencies view it, and we are actively working to improve our position.

One quick one to squeeze in: you mentioned work and stakeholder engagement at Keephills. When you went through the multiphase process for that asset, did you do community engagement work? What was the community feedback and support for that site?

We engage stakeholders early and throughout the development and operating life of any asset. Keephills has long-standing community engagement; we have operated there for decades. There is considerable community support at Keephills given the existing infrastructure. We remain transparent and communicate with stakeholders, listen to their needs and concerns, and treat development as a partnership with communities. Stakeholder engagement is critical across all jurisdictions in which we operate.

Thank you. There are no further questions at this time. And I would like to hand the conference back over to Stephanie Ann Paris for closing remarks.

Thank you, everyone. That concludes our call for today. If you have any further questions, please contact the TransAlta Investor Relations team.

This concludes today's conference call. Thank you for participating. You may now disconnect. Everyone, have a great day.