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Q2 2026 Results Talen Energy Corporation | August 5 , 2026 TALEN ENERGY
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1 The information contained herein, as well as any information that has been supplied orally in connection herewith, speaks only as of the date of this presentation. Talen Energy Corporation (“Talen,” “TEC,” the “Company,” “we,” “our,” or “us”) and our affiliates and representatives expressly disclaim any obligation to update any information contained herein, whether as a result of new information or circumstances, future events or otherwise. The information contained herein is summary. For additional information, see the Company’s historical financial statements and other information included in its periodic reports and other filings with the U.S. Securities and Exchange Commission (the “SEC”) (available at www.sec.gov/edgar). Nothing contained herein should be construed as legal, business, tax, accounting or other professional advice, and you should consult your own advisors regarding such matters. These materials should not be relied upon for the maintenance of your books and records for any tax, accounting, legal or other procedures, or other professional advice, and you should consult your own advisors regarding such matters. These materials should not be relied upon for the maintenance of your books and records for any tax, accounting, legal or other procedures. Non-GAAP Financial Measures We include in this presentation Adjusted EBITDA and Adjusted Free Cash Flow, which we use as measures of our performance and liquidity, and which are not financial measures prepared under U.S. Generally Accepted Accounting Principles (“GAAP”). Non-GAAP financial measures, such as Adjusted EBITDA and Adjusted Free Cash Flow, do not have definitions under GAAP and may be defined differently by, and not be comparable to, similarly titled measures used by other companies or used in our credit facilities, the indentures governing our notes or any of our other debt agreements. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions investors not to place undue reliance on such non-GAAP measures, but to consider them along with their most directly comparable GAAP measures. Adjusted EBITDA and Adjusted Free Cash Flow have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP. Please see the Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail. Due to the difficulty in predicting certain components of Adjusted EBITDA and Adjusted Free Cash Flow for the Lawrenceburg, Waterford, and Darby assets with a reasonable degree of certainty, we are unable to reconcile these non-GAAP financial measures to the comparable GAAP measures without unreasonable efforts. Figures identified as “pro forma” in this presentation are calculated to give effect only to the adjustments specifically identified and have not been prepared in accordance with Article 11 of Regulation S-X. Market and Industry Data This presentation includes market data and other information from independent industry publications, as well as surveys and our own research and knowledge of the industry. Some data is also based on management’s estimates, which are derived from our review of internal sources, as well as the independent sources described above. Although we believe these sources are reliable, the third-party information contained in this presentation has not been independently investigated, verified or audited and, therefore, we cannot guarantee the accuracy or completeness of such information. As a result, you should be aware that market share, ranking and other similar data set forth in this presentation, and estimates and beliefs based on such data, may not be reliable. Forward-Looking Statements Statements contained in this presentation concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance, shareholder returns and underlying assumptions, and other statements that are not statements of historical fact are “forward-looking statements,” and should be considered estimates, assumptions or projections. These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would” “goal,” “predict,” “continue,” “potential” or similar expressions. Any such forward-looking statements reflect various estimates and assumptions. Although we believe that the expectations and assumptions reflected in these statements are reasonable, there can be no assurance that they will prove to be correct. No representations or warranties are made by Talen or any of its affiliates, shareholders, directors, officers, employees, agents, partners or professional advisors as to the accuracy or achievability of any such forward-looking statements. Except as otherwise required by law, Talen undertakes no obligation to update any forward-looking statement to reflect new information or circumstances, future events or otherwise after the date on which such statement is made. Forward-looking statements are subject to many risks and uncertainties, and actual results may differ materially due to many factors. New factors emerge from time to time, and it is not possible for us to predict all of these factors. In addition to the specific factors discussed in the sections entitled “Cautionary Note Regarding Forward-Looking Information” and “Risk Factors” in our periodic reports and other filings with the SEC, the following are among the important factors that could cause actual results to differ materially from forward-looking statements: Talen’s or its subsidiaries’ levels of indebtedness; the terms and conditions of debt instruments that may restrict Talen’s ability to operate its business; operational, price and credit risks in the wholesale and retail electricity markets (including as a result of increases in the supply of electricity generally due to new power or intermittent renewable power generation); the effectiveness of Talen’s risk management techniques, including hedging, with respect to electricity and fuel prices, interest rates and counterparty and joint venture partner credit and non-performance risks; methods of accounting and developments in or interpretations of accounting requirements that may impact reported results, including with respect to, but not limited to, hedging activity; Talen’s ability to forecast and provide the actual load needed to perform sales contracts; the effects of transmission congestion due to line maintenance outages and the performance of transmission facilities and any changes in the structure and operation of, or the pricing limitations imposed by, the Regional Transmission Organizations and Independent System Operators that operate those facilities; blackouts due to disruptions in neighboring interconnected systems; the impacts of federal, state, local and market legislation, regulation, proceedings and other actions, including but not limited to those related to energy, the environment and tax, the outcomes thereof and the costs of compliance therewith; the impacts of new or revised United States and/or international trade tariffs, treaties, policies, and regulations; the costs of complying with environmental, social and related worker health and safety laws and regulations; the impacts of climate change, including changes in regulation or their enforcement; the availability and cost of emission allowances; the performance of Talen’s subsidiaries and affiliates, on which our ability to meet our debt obligations largely depend; the risks inherent with variable rate indebtedness; disruption in or adverse developments of financial markets; acquisition or divestiture activities, including Talen’s ability to realize expected synergies and other benefits from such business transactions; Talen’s ability to achieve anticipated cost savings; the execution and development of proposed future enterprises, including the ability to permit, develop, construct and operate proposed renewable energy, energy storage and/or data center facilities, realization of assumptions underlying the statements regarding future enterprises, and realization of estimates of valuations of future enterprises; Talen’s ability to optimize its competitive power generation operations and the costs associated with any capital expenditures; the integration of and anticipated benefits from the recent Cornerstone acquisition and the Freedom and Guernsey acquisitions; significant increases in operation and maintenance expenses, such as health care, and pension costs, including as a result of changes in interest rates; the loss of key personnel, the ability to hire and retain qualified employees, and the possibility of union strikes or work stoppages; war (including supply chain disruptions as a result of war, and including the effects of the Ukraine/Russia and Middle East conflicts, attendant sanctions and related disruptions in oil and natural gas production and the supply of nuclear fuel), armed conflicts or terrorist attacks, including cyber-based attacks; and pandemics, including COVID-19. Recipients are cautioned to not place undue reliance on such forward-looking statements. Disclaimer
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2 Key Highlights Progressing ~4 GW site development pipeline and new capacity projects to support data center contracts Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA and Adjusted Free Cash Flow. 1. Data from PJM; based on internal estimates of 10-year weather-adjusted data. Based on closing the Cornerstone Acquisition, increased sparks, and fundamentals Repurchased 550k shares for ~$200mm; $1.7B SRP remaining through December 2028 Closed on Lawrenceburg, Waterford, and Darby asset acquisition (the “Cornerstone Acquisition”) Delivered $374mm Adjusted EBITDA and $212mm Adjusted Free Cash Flow in Q2 2026 Strong 2028/2029 PJM Capacity Auction results; cleared over 10 GW at $325/MWd cap Executing on Core Business Strengthening PJM Fundamentals Raising 2026 Guidance; Increasing 2027 and 2028 Outlooks Advancing Growth through Talen Flywheel ~3% load growth year-over-year1, and growth forecasted to continue through 2030 2027/2028 PJM West Hub sparks increasing by ~50% year-over-year
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3 YTD 2026 Financial and Operational Performance 1. Calculated as ~$0.5B Unrestricted Cash plus $1.35B RCF availability as of 7/31/2026. 2. Calculated as Total Debt of $9.7B less Unrestricted Cash of $0.5B as of 7/31/2026. 3. OSHA Total Recordable Incident Rate (“OSHA TRIR”): The number of recordable incidents x 200,000 / total number of manhours worked. Only includes Talen-operated generation facilities (i.e., excludes Conemaugh and Keystone). 4. Fleet Equivalent Forced Outage Factor (“Fleet EFOF”): The percentage of a given period in which a generating unit is not available due to forced outages and forced derates. Represents Talen generation facilities, excluding RMR facilities (Brandon Shores and H.A. Wagner). 5. Capacity Factor: The ratio of the electrical energy produced by a generating unit for the period of time considered to the electrical energy that could have been produced at continuous full power operation during the same period. Key Operational Metrics 0.27 OSHA TRIR3 3.9% Fleet EFOF4 ~30 TWh Total Generation Key Financial Metrics $847mm Adjusted EBITDA $562mm Adjusted Free Cash Flow ~$1.9B Liquidity1 Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA and Adjusted Free Cash Flow. Metrics include 6/15/2026 – 6/30/2026 contribution from the Cornerstone Acquisition. $9.2B Net Debt2 ~51% Capacity Factor5
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4 156 160 166 172 183 2026 2027 2028 2029 2030 145 150 155 160 165 02-Jul-26 01-Jul-26 23-Jun-25 15-Jul-26 24-Jun-25 18-Jul-13 19-Jul-13 03-Jul-26 17-Jul-13 16-Jul-26 32 36 YTD 2025 YTD 2026 +13% US Energy Demand Forecasted to Grow through 2030 (TWh) 2 PJM Load Growth Materializing and Forecasted to Continue 1. Represents peak hourly integrated loads from 2013–2026. PJM service territory remained nearly unchanged since the addition of East Kentucky Power Cooperative in 2013. 2. Bank of America, “Industrials/Multi-Industry, Power Gap: a Deep Dive into US Electricity Supply & Demand”, (July 8, 2026). 3. YTD 2025 generation is pro-forma to include contribution from Guernsey, Freedom, and the Cornerstone Acquisition prior to ownership; excludes Camden and Dartmouth. YTD 2026 generation is pro-forma to include contribution from the Cornerstone Acquisition prior to ownership. 4. PJM Load Forecast Report (January 2026). PJM Summer Coincident Peak Load for PJM RTO. Talen PJM Generation (TWh)3 PJM Top 10 Peak Load Days Since 2013 (GW)1 124 285 613 258 2020 Data Center Load Growth Non-Data Center Load Growth 2025 Data Center Load Growth Non-Data Center Load Growth 2030E 3,998 4,407 5,278+20% +17% PJM Demand Growth (GW)4
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5 $10 $20 $30 $40 $50 Jul-25 Aug-25 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 $40 $50 $60 $70 Jul-25 Aug-25 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 2028 PJM Power ($/MWh) …Leading to Increased PJM Pricing 2027 PJM ATC Spark Spreads ($/MWh)1 2027 PJM Power ($/MWh) 2028 PJM ATC Spark Spreads ($/MWh)1 Note: Percentages calculated between 2025 Investor Day prices (7/31/2025) and 6/30/2026 prices. 1. PJM WHUB spark spreads are computed based on day-ahead West Hub ATC prices and TETCO M3 natural gas prices. PPL Zone spark spreads are computed based on day-ahead PJM PPL Zone ATC prices and TETCO M3 natural gas prices. ADHUB sparks spreads are computed based on day-ahead PJM ADHUB ATC prices, and TETCO M2 natural gas prices. All spark spreads are based on a heat rate of 7 MMBtu/MWh. $40 $50 $60 $70 Jul-25 Aug-25 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 PJM WHUB PPL ZoneADHUB Zone $10 $20 $30 $40 $50 Jul-25 Aug-25 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 $53.02 $47.91 $43.38 $61.59 $52.55 $47.44 $66.39 $54.86 $49.04 $66.73 $54.98 $47.84 $62.76 $53.02 $48.47 $52.97 $48.05 $43.36 $38.33 $34.35 $20.97 $32.23 $31.60 $18.08 $25.97 $26.98 $16.33 $39.90 $36.00 $21.01 $32.67 $31.97 $18.38 $26.09 $27.11 $16.48 +26% +14% +10% +25% +15% +13% +53% +33% +27% +48% +27% +28%
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6 0.2 2.5 6.7 10.7 13.3 14.8 15.0 2026E 2027E 2028E 2029E 2030E 2031E 2032E PPL zonal price in recent years1 < $10 negative basis to WHUB (80%) o Widening since Q4 2025 to ~$20 (70%) Recent widening driven by: o Transmission work to support new system upgrades – expected to be completed in phases o Forward marks on zonal pricing are driven by near-term recency bias Basis could improve to better than historical levels due to: o New transmission upgrades scheduled to come online over next several years o Load growth materializes within zone PPL Basis Changing Over Time 1. Average monthly West Hub to PPL zonal price January 2024 – September 2025. 2. Based on 2025 ICAP generation data from PJM, 2025 peak and average demand from PJM, and internal estimated 2024 and 2025 total generation reported to EIA. 3. “PPL Electric Utilities – Large Load Adjustment Request for 2026 PJM Load Forecast”, (September 16, 2025). PPL Load Growth Under ESA (GWs)3 Near Term Load Growth 8 5 Generation Load 15 7+3 Current Net Exporter PPL Zone – Peak Load (GW)2PPL Basis Average
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7 $90 ($78) $374 $212 Q2 2025 Q2 2026 Q2 2025 Q2 2026 Q2 and YTD 2026 Financial Results Key Q2 Drivers: Contribution of Freedom and Guernsey assets Higher capacity prices Higher generation volumes at Susquehanna and fossil plants Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA and Adjusted Free Cash Flow. Key YTD Drivers: Consistent with Q2 drivers Plus, the effect of higher realized market prices$290 $9 $847 $562 Adjusted Free Cash FlowAdjusted EBITDA Q2 2025 and 2026 Results ($mm) YTD 2025 and 2026 Results ($mm) YTD 2025 YTD 2026 YTD 2026YTD 2025
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8 Raising 2026 Guidance Initial Guidance Revised Guidance1 Adjusted EBITDA $1,750 - $2,050 million $2,025 - $2,225 million Adjusted Free Cash Flow $980 - $1,180 million $1,200 - $1,350 million Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA and Adjusted Free Cash Flow. 1. Excludes Keystone as of 7/1/2026.
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9 Attractive Growth: Increasing 2027 and 2028 Outlooks 1. Updated from 2025 Investor Day including Cornerstone Acquisition; assumes 47.9 million shares outstanding for 2027 and 2028. Excludes Keystone as of 7/1/2026.. 2. Represents impacts of future share buybacks using ~70% of annual Adjusted Free Cash Flow; assumes $334.10 share price as of 7/31/2026. 3. Calculated between 2026 Base and 2028 Share Buyback Impact. Calculated as ~20% excluding SRP. 4. Pricing as of 6/30/2026. 23.60 ~34 ~36 ~8% ~11% ~14%Adjusted FCF Yield @ $3342 ~$26.60 2026E Midpoint Guidance ~$3 ~$34 2027E Outlook ~$8 ~$40 2028E Outlook +30%3 Base1 Share Buyback Impact2 Upside Opportunity Levers $48+ $37+ Upside Opportunity Levers Potential 10%+ additional Adjusted Free Cash Flow per Share growth per lever ~$1.3B additional cash generation available for allocation through 2028 Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted Free Cash Flow. Continued spark expansion4 Zonal basis partially normalizes Existing PPA acceleration New data center PPA(s) Accretive M&A Adjusted Free Cash Flow Per Share ($/share) 1
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10 Multi GW Development Pipeline Flywheel in Motion: Enabling Data Center PPAs Pipeline of several 1+ GW speed-to-market opportunities for long-term PPAs ~4 GW DC Sites 1+ GW 2+ GW Existing Queue Submissions New Build Capacity Advanced Development1 Early Development 1. Advanced Development includes data center sites with utility load commitment and other developmental milestones; Advanced New Build Capacity backed with interconnection queue positions New Build CCGTs (existing gen required until online) Hybrid solution pairs existing baseload gen portfolio with batteries and/or CTs Existing baseload generation portfolio (energy & capacity) Hyperscaler Co-locator Neo-cloud Large C&I Hyperscaler Illustrative Counterparty PPA Powering Solution via Grid Data Center Powering Solutions Solution Timing Now - 2040+ 2028 - 2040+ 2032 - 2040+ Includes uprates & additional new capacity project Priority solutions Focus is on providing a variety of grid-connected, long-term, durable customer solutions backed by existing Talen portfolio
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11 Gross Margin1 Mix Progression to Significantly Contracted Portfolio Assumes additional premium contracts with mix of long-term counterparties 30% 480 MWLT Contract: 25% 35% 35% 5% LT Contracted RMR PJM Energy PJM Capacity Full Contract Ramp3 (2028-2030) 30% 55% 10% 5% 2028 Outlook 15% 20% 60% 5% Illustrative Portfolio Mix4 (2030+) 1,920 MW 4,000 MW Full value of existing contract by 2030; line of sight for contracted capacity into 2030 ✓Existing contract at minimum ramp schedule; locked in capacity ✓ ✓ ✓ 1. Margin is comprised of: (i) capacity revenue, (ii) margin associated with electric generation, (iii) bilateral physical electricity sales, RMR annual fixed-cost payments, and other contracts, and (iv) expected hedge settlements. Margin excludes nuclear fuel amortization. Rounded to nearest 5%. Excludes Keystone. 2. Brandon Shores and H.A. Wagner RMR extension through 5/31/2031 is pending FERC approval. 3. Based on existing 1.9 GW PPA terms and structure. 4. Assumes additional PPAs with similar terms and structure to existing 1.9 GW PPA. Would significantly reduce reliance on capacity markets beyond 2030 Exposure to widening spark spreads ✓ Continued exposure to widening spark spreads ✓ 2
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12 High quality cash flows with disciplined capital allocation Executing the Talen Flywheel Strategy Multiple transactions delivering strong and immediate Adjusted FCF/Share accretion Reshaping fleet by adding baseload MWs that are the equivalent to two more nuclear plants Diversified portfolio across Pennsylvania, Ohio and Indiana within PJM Locked-in ~2 GW of long-term contracts Continuing to progress several land development options and new capacity opportunities
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Appendix
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14 Asset State Primary Fuel Type(s) Plant Type Ownership Owned Capacity (MW)1 Commercial Operations Date Region Susquehanna2 PA Nuclear Baseload 90% 2,245 1983 – 1985 PJM-PPL/MAAC Guernsey OH Natural Gas Baseload 100% 1,771 2023 PJM-AEP/RTO Martins Creek PA Natural Gas Peaker 100% 1,710 1975 – 1977 PJM-PPL Montour PA Natural Gas Intermediate 100% 1,505 1972 – 1973 PJM-PPL Brunner Island3, 4 PA Coal / Natural Gas Intermediate 100% 1,419 1961 – 1969 PJM-PPL Brandon Shores5 MD Coal RMR 100% 1,273 1984 – 1991 PJM-BGE Lawrenceburg IN Natural Gas Baseload 100% 1,207 2004 PJM-AEP/RTO Freedom PA Natural Gas Baseload 100% 1,049 2018 PJM-PPL/MAAC Waterford OH Natural Gas Baseload 100% 880 2003 PJM-AEP/RTO H.A. Wagner5, 6 MD Oil RMR 100% 702 1966 – 1972 PJM-BGE Lower Mount Bethel PA Natural Gas Baseload 100% 607 2004 PJM-PPL Darby OH Natural Gas / Oil Peaker 100% 475 2001 PJM-AEP/RTO Conemaugh2, 4 PA Coal Intermediate 22% 392 1970 – 1971 PJM-PN/MAAC Colstrip Unit 32 MT Coal Baseload 30% 222 1984 – 1986 WECC Keystone2, 4, 7 PA Coal Intermediate 12% 213 1967 – 1968 PJM-PN/MAAC Talen Total 15,670 Generation Portfolio Summary 1. Generation capacity (summer rating, where applicable) is based on factors, among others, such as operating experience and physical conditions, which may be subject to revision. 2. See Note 7 to the FY 2025 Financial Statements for additional information on jointly owned facilities. 3. Coal-fired electric generation is restricted during the EPA Ozone Season, which is May 1 to September 30 of each year. 4. Coal-fired electric generation is required to cease at Brunner Island by December 31, 2028 and at Keystone and Conemaugh by December 31, 2034. 5. See Note 9 in the Q2 Financial Statements for additional information on the Brandon Shores and H.A. Wagner RMR arrangements. 6. Includes H.A. Wagner Units 3 and 4. 7. Currently held for sale. See Note 17 to the Q2 2026 Financial Statements for additional information on acquisitions and divestitures.
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15 Total Fleet Power Price Sensitivities3, 5 Balance of 20261 2027 2028 Margin Impact from Change in Power Price +$10/MWh +$55mm +$235mm $450mm +$5/MWh +$30mm +$120mm $225mm $(5)/MWh $(30)mm $(130)mm $(220)mm $(10)/MWh $(60)mm $(260)mm $(440)mm Hedging Program as of 6/30/2026 © Talen Energy Corporation 1. “Balance of 2026” is July – December 2026. 2. Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M3 natural gas prices and a heat rate of 7 MMBtu/MWh. 3. Where applicable, natural gas prices are adjusted to maintain consistent heat rate relationships with corresponding power prices. Figures rounded to nearest $5mm. 4. Figures rounded to the nearest 5%, excludes Keystone. 5. Margin is comprised of: (i) capacity revenue, (ii) margin associated with electric generation, (iii) bilateral physical electricity sales, RMR annual fixed-cost payments, and other contracts, and (iv) expected hedge settlements. Margin excludes nuclear fuel amortization. Figures rounded to the nearest $5mm, excludes Keystone. Market Price Summary Balance of 20261 2027 2028 PJM West Hub ATC ($/MWh) $71.08 $66.73 $66.39 PJM West Hub ATC Spark Spreads2 ($/MWh) $50.04 $39.90 $38.33 TETCO M3 ($/MMBtu) $3.01 $3.83 $4.01 Total Fleet Hedge Position Balance of 20261 2027 2028 % Hedged of Expected Generation4 ~85% ~70% ~30% Hedge Value vs Market3 $(345)mm $(210)mm $(20)mm
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16 Maintaining Balance Sheet Strength Completed financing transactions to: Increase existing Revolving Credit Facility to $1.35B Upsize existing Letter of Credit Facility to $1.5B and extend maturity Talen is committed to net leverage target of <3.5x Leverage and Liquidity Snapshot Capitalization Summary ($mm unless otherwise noted) July 31, 2026 Unrestricted Cash $525 Secured Debt $2,875 Total Debt1 $9,696 Net Debt2 $9,171 Credit Metrics 2026E Adjusted EBITDA Midpoint3 $2,125 Total Liquidity4 $1,875 1. Total Debt excludes $1.5B standalone LCF. 2. Calculated as Total Debt less Unrestricted Cash. 3. Only includes partial year (6/15/2026 – 12/31/2026) of the Cornerstone Acquisition. 4. Calculated as Unrestricted Cash plus $1.35B RCF availability as of 7/31/2026. Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA and Adjusted Free Cash Flow. Balance Sheet Strength Provides Strategic Flexibility
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17 $837 $1,194 $131 $1,500 $2,500 $1,400 $1,290$1,350 $844 2026 - 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037+ Agency IDR / Secured Debt Rating Outlook S&P BB- / BB+ Stable Moody’s Ba3 / Baa3 Stable Fitch BB- / BB+ Negative Long-Dated Debt Maturities Debt Overview1 Debt Maturity Summary1 ($mm) Revolving Credit Facility (Undrawn) Term Loan B2Tranche Maturity Principal ($mm) Interest Rate RCF Dec 2029 - SOFR + 150bps 2031 TLB2 Dec 2031 837 SOFR + 175bps 2032 TLB-12 Nov 2032 844 SOFR + 175bps 2032 TLB-22,3 Nov 2032 1,194 SOFR + 200bps Secured Debt $2,875 2031 Unsecured Notes May 2031 1,500 6.125% 2033 Unsecured Notes May 2033 2,500 6.375% 2034 Unsecured Notes Feb 2034 1,400 6.25% 2036 Unsecured Notes Feb 2036 1,290 6.50% PEDFA 2009B Bonds4 Dec 2037 81 5.25% PEDFA 2009C Bonds4 Dec 2038 50 5.25% Unsecured Debt $6,821 Total Debt5 $9,696 PEDFA Bonds5 Unsecured Notes 1. As of 7/31/2026. 2. Subject to mandatory 1% annual amortization, not shown in graph. 3. Subject to a reduction in margin upon submission of Q2 2026 Compliance Certificate by 50 bps due to first lien leverage based step-downs. 4. Subject to mandatory remarketing in 2027. 5. Total Debt excludes $1.5B standalone LCF.
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Reconciliation of Non-GAAP Financial Measures
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19 Definitions of Non-GAAP Financial Measures Non-GAAP Financial Measures Adjusted EBITDA and Adjusted Free Cash Flow, which we use as measures of our performance and liquidity, are not financial measures prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measures, but to also consider them along with their most directly comparable GAAP financial measures. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP. Adjusted EBITDA We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results;(ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness. Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the nuclear facility decommissioning trust (“NDT”); (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xi i) legal settlements, liquidated damages, and contractual terminations;(xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business. Pursuant to TES’s debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital credit facility and associated cash flow sweep. Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired. Adjusted Free Cash Flow Adjusted Free Cash Flow is utilized by our chief operating decision makers to evaluate cash flow activities. Adjusted Free Cash Flow is computed as Adjusted EBITDA reduced by capital expenditures (including nuclear fuel but excluding development, growth, and (or) conversion capital expenditures), cash payments for interest and finance charges, cash payments for income taxes (excluding income taxes paid from the NDT, taxes paid or deductions taken as a result of strategic asset sales, and benefits of the Nuclear PTC utilized to reduce income taxes paid), and pension contributions. We believe Adjusted Free Cash Flow is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to determine a company’s ability to meet future obligations and to compare business performance across companies and across periods. Adjusted Free Cash Flow is widely used by investors to measure a company’s levered cash flow without regard to items such as ARO settlements; nonrecurring development, growth and conversion expenditures; and cash proceeds or payments for the sale or purchase of assets, which can vary substantially from company to company and from period to period depending upon accounting methods, book value of assets, capital structure, and the method by which assets were acquired. © Talen Energy Corporation
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20 Adjusted EBITDA / Adjusted Free Cash Flow Reconciliation (Unaudited) The reconciliation from “Net Income (Loss)” presented on the Consolidated Statements of Operations to Adjusted EBITDA and Adjusted Free Cash Flow for: 1. Includes the periodic amortization of fair value adjustments associated with acquired fuel supply contract liabilities and intangible assets. 2. Includes the non-recurring: (i) advisory fees associated with completed acquisitions and divestitures; (ii) remaining settlements on contracts of divested assets; and (iii) non-recurring finance fees charged to the Consolidated Statement of Operations associated with acquisition financing fee arrangements. Three Months Ended June 30, Six Months Ended June 30, ($mm) 2026 2025 2026 2025 Net Income (Loss) $ (92) $ 72 $ (29) $ (63) Adjustments Interest expense and other finance charges 214 62 333 136 Income tax (benefit) expense (37) 25 (19) (27) Depreciation, amortization and accretion1 88 67 151 137 Nuclear fuel amortization1 22 18 46 44 Unrealized (gain) loss on commodity derivative contracts 211 (92) 365 90 Nuclear decommissioning trust funds (gain) loss, net (134) (80) (112) (68) Stock-based and other long-term incentive compensation expense 71 18 73 31 Acquisition and divestiture activities2 28 (3) 37 4 Other 3 3 2 6 Total Adjusted EBITDA $ 374 $ 90 $ 847 $ 290 Capital expenditures, net (56) (35) (123) (99) Interest and finance charge payments (102) (84) (154) (107) Income taxes 2 (42) 6 (51) Pension contributions (6) (7) (14) (24) Total Adjusted Free Cash Flow $ 212 $ (78) $ 562 $ 9
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21 Adjusted EBITDA / Adjusted Free Cash Flow Reconciliation: 2026E Guidance The reconciliation from forecasted “Net Income (Loss)” to Adjusted EBITDA and Adjusted Free Cash Flow for the year ended December 31: ($mm) Net Income (Loss) 2026E1 (initial) 2026E (revised)2 Low High Low High $ 875 $ 1,125 $ 1,010 $ 1,180 Adjustments Interest expense and other finance charges 460 480 460 480 Income tax (benefit) expense 15 45 10 20 Depreciation, amortization and accretion 300 300 445 445 Nuclear fuel amortization 100 100 100 100 Adjusted EBITDA $ 1,750 $ 2,050 $ 2,025 $ 2,225 Capital expenditures, net (280) (300) (330) (340) Interest and finance charge payments (460) (480) (460) (480) Income taxes (15) (45) (10) (20) Pension contributions (15) (45) (25) (35) Adjusted Free Cash Flow $ 980 $ 1,180 $ 1,200 $ 1,350 Note: Figures are rounded to the nearest $5mm. 1. Excludes impact of the Cornerstone Acquisition. 2. Excludes Keystone as of 7/1/2026.