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Welcome to the Talen Energy Corporation Q3 2023 Earnings Call. Our host for today's -- is Ellen Liu, Senior Director of Investor Relations. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. I would now like to turn the conference over to your host, Ellen Liu. You may begin.

Thanks, Danielle. Welcome, everyone to Talen Energy's third quarter 2023 conference call. Participating on today's call are Chief Executive Officer, Mac McFarland and Chief Financial Officer, Terry Nutt. I'd like to highlight that we have posted materials on the Investor Relations section of our website, www.talenenergy.com that provide additional information about our operations and third quarter results. We have also provided information reconciling our non-GAAP financial measures to the most directly comparable GAAP financial measures in our earnings materials. Today, we are making some forward-looking statements based on current expectations, including updating 2023 and establishing 2024 guidance. Actual results could differ due to risk factors described in our financial disclosures and other periodic public filings. As a reminder, we have allotted additional time for a question-and-answer session at the end of our prepared remarks. We ask participants to please limit their questions to one primary and one follow-up. With that, I will now turn the call over to Mac.

Great and thank you, Ellen. Good morning, everyone and thank you for joining us today. At Talen, we remain focused on operating our assets in a safe and reliable manner, ensuring we deploy robust commercial hedging strategies and emphasizing disciplined cost management and returning capital to our shareholders. You can see these highlights on Slide 3 of our earnings presentation. Today, we are reporting solid operational and financial performance for the third quarter. During the quarter, our fleet generated $224 million of adjusted EBITDA and $146 million of adjusted free cash flow. The PJM plants ran well in a mild summer with strong cash flows supported by hedge gains. Our commercial hedging strategy provided the appropriate risk mitigation for a weak market and allowed Talen to lock in prices for our PJM fleet, which continues to support our cash flow generation for the year. In ERCOT, record temperatures and elevated spark spreads enabled our plants to generate significant physical energy margin, which we define as unhedged margin from generation and ancillary services. However, these results were negatively impacted by unplanned outages, including at our Nueces Bay plant, as well as abnormally high congestion costs in ERCOT at our plants. Terry will talk more about this in greater detail later and I'll try to unpack it as well. As a result of these outages and congestion costs, we are narrowing our 2023 guidance by reducing the upper end of our adjusted EBITDA range provided in August to $1.175 billion. This reflects the loss of upside opportunities from these events. The impact on 2023 adjusted cash flow is minimal, despite this loss and potential upside due to certain cash flow improvement activities that we have taken to offset the EBITDA. Turning to 2024, we are also establishing '24 adjusted EBITDA and adjusted free cash flow guidance ranges with midpoints higher than the January 27 disclosure forecast. These increases are driven by our new company-wide cost savings initiative, which is expected to result in $50 million of annual run rate cost reductions. Terry will provide more detail about these ranges and the cost initiatives in a bit, but this is allowing us to drive higher free cash flow per megawatt and increase our guidance. While we were unable to get into specifics, given this is an active ongoing process, we're making significant progress on the monetization of our data campus and remain excited about the ability to unlock significant value for Talen, through both an upfront return of capital and through future contracted nuclear cash flow growth from attractive long-term purchase power agreements or PPAs. A few weeks ago, we highlighted this value proposition at our site visit day, hosting over 70 investors and analysts for tours of Susquehanna and the Cumulus campus. Lastly, we continue to prioritize disciplined capital allocation and return of capital to shareholders. As announced last month, given our cash flow generation and modest leverage, our Board has authorized a $300 million share repurchase program through the end of 2025. Turning to some of our results on Slide 4 of the presentation, we performed reliably and safely, with an OSHA total recordable incident rate of 0.7 on a year-to-date basis and we continue to emphasize safety across our fleet. RTR IR is one of the best among peers. Our fleet ran well, generating 24 terawatt hours year-to-date with an equivalent forced outage factor of 3.5% so far this year. Approximately 53% or just over half of that generation was carbon-free from our Susquehanna nuclear facility. The solid operational foundation and strong commercial strategy we've built translated to $998 million of adjusted EBITDA year-to-date. And after funding interest, maintenance CapEx, pension payments and taxes, we generated $609 million of adjusted free cash flow for the same period. However, you'll note that our guidance for 2023 is $550 million to $585 million of adjusted free cash flow. This is because in the fourth quarter, certain cash payments will reduce our full year cash flow. For example, debt service payments that happen twice a year, pension payments and certain capital expenditures. I'd like to take this opportunity to recognize and thank our employees across the fleet who have worked safely to deliver impressive results. These team members are key to our overall financial performance as they operate, maintain and improve our generation assets even during times of unseasonable weather. Without their hard work and commitment to excellence, none of this could be possible. Turning to Slide 5 and taking a closer look at our key operational updates, we saw contrasting stories for physical margin versus hedge performance in PJM and ERCOT this quarter. Our PJM fossil and nuclear fleet performed reliably, with a forced outage factor of approximately 4% and 9 terawatt hours of generation in the third quarter. This fleet, the PJM fleet, faced mild summer temperatures that reduced power demand to one of the lowest levels seen in years. This, in combination with low natural gas prices, weakened power prices and led to lower physical energy margins. However, this was largely mitigated in our PJM cash flows by significant gains from our hedge program. One other PJM operational update is that as of last Friday, Susquehanna Unit 1 went into an unplanned outage which is not associated with the reactor. The unit was manually brought off-line and there are no safety or environmental issues. The team is currently working to bring the unit back to service and I am confident that Brad and his team will return Susquehanna to full operations safely. Turning to ERCOT. Strong performance from our fleet during the summer of record heat and spark spreads drove healthy physical energy margins. We collected additional revenues from taking advantage of ancillary services, especially at our Quick Start Laredo plant. However, this physical energy margin was largely offset by unplanned outages and elevated congestion costs across the ERCOT fleet. Nueces Bay experienced two outages during the quarter. One during tropical storm Harold in late August that was eventually resolved, and another that started in September due to a failure of the main power transformer. We're currently working to repair the transformer as quickly as possible, and the plan is estimated to return to service later this month. In addition to repairing the existing transformer, we also purchased a spare, which is expected to be on site later this year. And that spare has the advantage of providing backup for both Nueces Bay, as well as Barney Davis. The record demand levels this quarter, along with the transmission line constraints and derates materially worsened congestion in South Texas. Thus causing our generation assets to experience lower pricing at the node pricing point when compared to the south zone hub price. To give you a sense of these congestion costs, during the third quarter in '21 and '22, these costs average less than $5 a megawatt hour. But in 2023, they averaged over $25 a megawatt hour. These increased congestion costs, while somewhat mitigated, reduced our hedged EBITDA in ERCOT. Lastly, we recently decided to keep our Barney Davis Unit 1 running rather than suspending it in November and have notified ERCOT of our intent to operate the unit in 2024. We believe that the market dynamics in ERCOT provide opportunity to dispatch thermal generation during periods when renewable generation is not able to meet the incremental demand, such as during the peak demand hours of the summer as well as year-round during the hours when solar generation is ramping down at Sunset. Turning to Cumulus. We're making continued progress on monetizing the campus via a potential sale or JV. Both of these alternatives can unlock value, as I've said before, through a significant upfront, return of invested capital and through future Susquehanna cash flow growth through long-term purchase power agreements that would be at a premium to the nuclear PTC. To give you an example of the cash flow growth at Susquehanna through a PPA, assuming 240 megawatts, which is our campus infrastructure ready to support next year, an illustrative price of $70 per megawatt hour, which is $25 above PTC floor 45, would translate into over $50 million of incremental Susquehanna annual cash flows at the 240 megawatt level. And given recent nuclear transactions have created a cash flow yield of 10% or less, using this metric, it implies a significant value creation opportunity. And we think about scaling that to a full 950 megawatts, which would provide a clear line of sight to incremental compounded cash flow growth at Susquehanna over the next decade. That is why we think the combination of Susquehanna and the Cumulus data campus is so compelling. Given our progress on data, we have also started evaluating how we will recapitalize Cumulus and the strategic alternatives for our coin business. We are excited about the value creation opportunity across the Cumulus family of businesses and we are working hard to make it a reality. And with that, I'll turn it over to Terry.

Thank you, Mac and good morning to everyone on the call. Turning to our financial results. For the third quarter 2023, Talen reported adjusted EBITDA of $224 million and adjusted free cash flow of $146 million. Building on our strong financial performance in the first half of the year resulted in $998 million of adjusted EBITDA year-to-date and $609 million of adjusted free cash flow. Our financial performance for the year has been anchored by our operational performance across the generation fleet, complemented by our commercial hedging strategies. Our year-to-date results for 2023 have been one of Talen's best financial performances in the company's history, and we expect full year results to meet that milestone as well. As Mac touched on earlier, our plants ran well across the fleet, though the balance of profitability from physical generation versus hedge results differed between PJM and ERCOT. The PJM fleet performed reliably, earning adjusted EBITDA of $166 million during the quarter. Similar to the second quarter, below average temperatures in the PJM market resulted in lower demand for cooling needs, contributing to lower on-peak power prices, lower power load and physical energy margin. For example, cooling degree days in Philadelphia, a relevant demand location for our plants were approximately 18% lower than the same period last year. However, our commercial hedging strategy allowed us to realize prices that were higher than the prevailing market price during the period. Turning to ERCOT. This quarter driven by the persistent heat in Texas, ERCOT saw its highest third quarter electricity demand in the last five years, leading to wide spark spreads and increased generation. This summer, ERCOT set 10 new all-time peak demand records including the new record of 85,464 megawatts on August 10. This heat drove significant physical margin that was offset by the Nueces Bay outages and significant congestion costs that Mac discussed previously. Despite these challenges, together, our ERCOT and WECC assets earned adjusted EBITDA of $58 million for the quarter. Turning to guidance. With three quarters of performance behind us, we are narrowing our 2023 guidance range for adjusted EBITDA by lowering the top end of the range we provided in August, from $1.245 billion to $1.175 billion. This is largely driven by reduced upside opportunity from the ERCOT outages and ERCOT congestion costs. However, for adjusted free cash flow, we're only bringing the top end of that range down by $10 million to $585 million, because we've taken certain corrective actions to mitigate impacts on cash flows. Moving now to 2024. We are excited to announce that we are establishing 2024 adjusted EBITDA and adjusted free cash flow ranges with midpoint higher than the previous January 27 forecast refresh. Our adjusted EBITDA range is $600 million to $800 million, and adjusted free cash flow is $150 million to $300 million. The midpoints of these ranges elevate our expectations due to several factors, including, number one, our new cost savings initiative; two, higher projected ERCOT summer spark spreads, offset by the impact of lower expected PJM winter pricing; and three, continued capital management. I'll provide more detail about the cost initiatives shortly. But first, I'd like to briefly discuss the 2024 outlook of the power and gas markets and how that view has changed from January 27 to the end of September. The domestic natural gas market remains fundamentally oversupplied, experiencing strong production growth in the advance of new gas export capacity expected to start in late 2024 and 2025. Recently, dry gas production in the U.S. has exceeded 103 Bcf per day, outstripping production records set in 2022. As a result, PJM forward power prices have traded lower within a narrow range. 2024 PJM West Hub prices as of September 29 are generally lower than January 27, with pricing noticeably lower and weaker in January and February. In ERCOT, spark spreads have widened significantly since January 27, on tight fundamentals and market structure changes, creating attractive upside opportunities for our generation assets and commercial team. Now turning to our cost savings initiatives. Since exiting restructuring, we've been focused on assessing the overall business, including identifying areas for cost efficiencies. During the third quarter, we performed a holistic assessment of our operating model and cost structure across the entire company, including support functions and our operational teams. We determine specific actions to take and are executing a substantial portion of them in Q4 of 2023. We expect this initiative to decrease our annual run rate of O&M and G&A cost by approximately $50 million. These structural changes are not onetime items. Along with these changes, we expect to incur approximately $5 million to $7 million and cost to achieve savings. We believe these savings will be ongoing and align with our goal of maximizing cash flow per megawatt hour of generation. To give more detail on areas of focus, we performed an evaluation of all areas of spending, including third-party spend related to vendors and contractors and current staffing levels and organization structures across the business. We are eliminating unnecessary open positions across the business and also consolidating functions where appropriate. We believe our disciplined cost management strategy will unlock enterprise value by improving productivity across the company and increasing adjusted EBITDA and free cash flow. Moving to our share repurchase program. As Mac mentioned, last month, our Board authorized a $300 million share repurchase program. This program is supported by our robust cash flow generation, ample liquidity and modest leverage. Our projected net leverage ratios using 2023 or 2024 adjusted EBITDA are still below our target of 3.5 times, and we feel confident about our ability to maintain this. At recent share prices of $52 to $54 a share, a $300 million share repurchase program reflects approximately 10% of our current market cap, a relatively modest program that can be expanded as we see fit. We intend to execute share buybacks on an opportunistic basis with cash on hand and cash generated from the business. The shares may be repurchased in a variety of ways, including open market transactions, negotiated private transactions and structured purchase plans. Furthermore, we have discussed this program with the rating agencies and this will not impact our credit ratings. This share repurchase program is evidence of both management and the Board's conviction in our operating performance and long-term cash flow generation. Turning now to the balance sheet. We remain committed to maintaining modest leverage levels and using excess cash flows to maximize return on capital. Our net debt-to-EBITDA ratios using both '23 and '24 guidance ranges are still below our target of 3.5 times. That's partly supported by $149 million increase in our unrestricted cash since the August 11 balance that we provided on our Q2 call. As of November 10, we have total available liquidity of $989 million, comprised of $289 million of unrestricted cash on hand and a $700 million completely undrawn revolving credit facility. With that, I'll turn the call back over to Mac.

Great. Thanks, Terry. To reiterate Talen's value proposition, we're focused on generating power safely, reliably, profitably and unlocking value from our assets like the data campus. We believe the combination of Susquehanna and our Cumulus campus provides compounding cash flow growth for Susquehanna, as well as a very compelling enterprise value growth for Talen. Thank you for your interest in Talen and joining us on today's call. I'll now open the line for questions and turn it back to Danielle, the operator. Danielle?

Great. We do realize that our earnings call is on the third and final day of EEI. And -- but do appreciate everybody taking time out for their busy schedule to join us today and look forward to hearing from you in the next several weeks. Take care, everyone.