Slides
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Q3 2026 Results Talen Energy Corporation | November 3, 2026
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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 2028E Outlook with a reasonable degree of certainty, we are unable to reconcile these non-GAAP financial measures to the comparable GAAP measures without unreasonable efforts. 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 leadership transition, the timing, size, completion, and impacts of the capacity monetization, ASR, and remaining SRP; 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 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. Executing on Core Business Advantaged Assets in Advantaged Locations – PJM Fundamentals Continue to Improve Strong Cash Flow Growth Amplified By Disciplined Share Repurchases Advancing Growth through Talen Flywheel – Multiple Ways to Contract Existing Portfolio
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3 YTD 2026 Financial and Operational Performance 1. See slide 17 for calculation. 2. 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). 3. 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). 4. Capacity Factor: The ratio of the electrical energy produced by a generating unit to the energy that could have been produced at continuous full power operation during the same period, excluding RMR facilities (Brandon Shores and H.A. Wagner). Key Operational Metrics 0.31 OSHA TRIR2 4.3% Fleet EFOF3 ~53 TWh Total Generation Key Financial Metrics $1,516mm Adjusted EBITDA $995mm Adjusted Free Cash Flow ~$1.6B 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 contribution from the Cornerstone Acquisition starting on 6/15/2026. $9.5B Net Debt1 ~64% Capacity Factor4
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4 $10 $20 $30 $40 $50 $60 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 Jul-26 Aug-26 Sep-26 $10 $20 $30 $40 $50 $60 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 Jul-26 Aug-26 Sep-26 $50.14 $42.74 $23.04 $40 $50 $60 $70 $80 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 Jul-26 Aug-26 Sep-26 $40 $50 $60 $70 $80 Sep-25 Oct-25 Nov-25 Dec-25 Jan-26 Feb-26 Mar-26 Apr-26 May-26 Jun-26 Jul-26 Aug-26 Sep-26 2028 PJM Power ($/MWh) PJM Forward Pricing Continued to Improve in Q3 2027 PJM ATC Spark Spreads ($/MWh)1 2027 PJM Power ($/MWh) 2028 PJM ATC Spark Spreads ($/MWh)1 Note: Percentages calculated between 6/30/2026 and 9/30/2026 prices. 1. PJM WHUB spark spreads computed based on day-ahead West Hub ATC prices and TETCO M3 natural gas prices. PPL Zone spark spreads computed based on day-ahead PJM PPL Zone ATC prices and TETCO M3 natural gas prices. ADHUB sparks spreads computed based on day-ahead PJM ADHUB ATC prices, and TETCO M2 natural gas prices. All spark spreads based on a heat rate of 7 MMBtu/MWh. PJM WHUB PPL ZoneADHUB $77.41 $61.80 $52.15 $75.41 $60.39 $48.32 $48.57 $40.90 $23.31 +13% +10% +1% +17% +13% +6% +26% +19% +10% +27% +19% +11% $66.73 $54.98 $47.84 $66.39 $54.86 $49.04 $38.33 $34.35 $20.97 $39.90 $36.00 $21.01
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5 PJM Demand Outlook Remains Strong AEP Cumulative Contracted Load Additions in PJM 1 1. AEP, “American Electric Power Third Quarter 2026 Earnings,” (October 28, 2026). Contracted load is supported by fully executed LOAs and ESAs. 2. PPL, “PPL Corporation 2nd Quarter 2026 Investor Presentation,” (August 7, 2026). Contracted load supported by ESAs. 3. PJM Data. Measured in GWs. Not weather normalized. 4. Capacity Factor: The ratio of the electrical energy produced by a generating unit to the energy that could have been produced at continuous full power operation during the same period. Includes Brunner Island, Conemaugh, Darby, Martins Creek, and Montour. Q3 PJM Average Electricity Demand3 Talen Intermediate Assets Capacity Factor 4 36% 52% Q3 2025 Q3 2026 PPL Cumulative Contracted Data Center Additions 2 90,000 95,000 100,000 105,000 110,000 2022 2023 2024 2025 2026 5 Year Average 1.4 3.7 7.1 9.3 10.7 2027E 2028E 2029E 2030E 2031E 6 12 17 25 31 2027E 2028E 2029E 2030E 2031E (GW) (GW)
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6 Talen Offers Range of Long-Term Contracting Solutions Talen Offers Customers Desired Solutions That Meet Multiple Needs Fixed retail power contracts (energy and/or capacity) ~6 GW baseload generation portfolio1 Data center campus 24x7, low-carbon intensity New grid capacity resources (additionality) ~4 GW across multiple powered land sites with 2028/2029 grid power 3+ GW new capacity development projects (e.g., uprates, batteries, peakers) ~300 MW carbon-free at Susquehanna (uncontracted), plus battery development pipeline, high-efficiency CCGT portfolio Customer Needs Talen’s Advantaged Position Locks-in price certainty and capacity resource commitments Benefits Provides speed-to-market across GW+ scale campuses Addresses ratepayer protection pledges and potential regulatory outcomes Maintains long-term ESG goals and commitments Note: Advanced development/powered land sites includes data center sites with utility load commitment and other development milestones; New build capacity includes 2 GW+ backed with interconnection queue positions. 1. Excludes the MWs contracted with AWS.
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7 Key Q3 and YTD Drivers: Overall net earnings contribution from Freedom, Guernsey, Lawrenceburg, Waterford, and Darby Higher settled power prices, generation volumes, and cleared capacity revenues on existing assets Partially offset by realized hedge results Higher interest payments associated with acquisition financing $363 $223 $669 $433 Q3 2025 Q3 2026 Q3 2025 Q3 2026 Q3 and YTD 2026 Financial Results 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. $653 $232 $1,516 $995 Adjusted Free Cash FlowAdjusted EBITDA Q3 2025 and 2026 Results ($mm) YTD 2025 and 2026 Results ($mm) YTD 2025 YTD 2026 YTD 2026YTD 2025
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8 Reaffirming 2026 Guidance and Introducing 2027 Guidance 2026 Guidance1 2027 Guidance Adjusted EBITDA $2,050 - $2,200 million $2,500 - $2,850 million Adjusted Free Cash Flow $1,225 - $1,325 million $1,500 - $1,750 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. 2026 Guidance narrowed by $25 million per side.
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9 Adjusted Free Cash Flow Per Share ($/share) 1 Attractive Growth Through End of the Decade 1. Pricing as of 9/30/2026. Assumes 42.9 million shares outstanding for 2026E – 2029E which would reflect completion of the ASR at $343.12 share price as of 10/30/2026. 2. Represents impacts of future share buybacks using ~70% of annual Adjusted Free Cash Flow; assumes $343.12 share price as of 10/30/2026. 2029 yield calculated using mid-point range. 3. CAGR calculated between 2026E original midpoint guidance including Cornerstone of $26.60/share and 2029E Share Buyback Impact midpoint. 4. 2027E - 2029E assume the impact of potential debt repayment with excess annual free cash flow. 23.60 ~34 ~36 9% 12% 15%Adjusted Free Cash Flow Yield @ $343.122 $30 2026E Midpoint Guidance $2 $38 2027E Midpoint Guidance $5 $48 2028E Outlook4 $10 $46-50 2029E Outlook4 30% CAGR3 Base1 Share Buyback Impact2 Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted Free Cash Flow. Single point adjusted free cash flow per share numbers are estimates and represent midpoint of ranges. 17% $40 $53 $56-60 Incremental Opportunity Levers Provide FCF/Share Upside
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10 Upside Opportunity Lever Sensitivity1 Adjusted Free Cash Flow Guidance Impact ($/share) Accretive M&A 1 GW M&A Deal2 $2 - $3 Existing PPA acceleration 1 Year Acceleration of AWS Contract ~$2 New data center PPA(s) 1 GW Premium Data Center Deal3 $3 - $5 Continued spark expansion $5/MWh Change in Spark Spread4,5 ~$5 Zonal basis normalizes $5/MWh Change in Zonal Basis4 ~$5 Focused on Incremental Value Drivers 1. Sensitivities are not intended to be additive. 2. Assuming similar economics as recent M&A transactions. 3. Assuming similar economics as existing AWS contract at full ramp. 4. Pricing as of 9/30/2026. 5. Assumes change in power price and no change in gas price, across portfolio.
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11 Executing on Capital Allocation Strategy Share repurchases remain capital allocation benchmark Target to return ~70% of Adjusted Free Cash Flow to shareholders $6B cash through 2029, $4B+ for buybacks2 Ability to achieve 3.5x net leverage target by 2H 2027 3 Accelerated Share Repurchases Upsized $3.0B SRP through 2028 (including the ASR) Announced $1.5B ASR Efficiently funded through capacity monetization that pulls forward cash flows through May 2029 Expect to complete by end of Q1 2027 ~3.8mm shares retired upfront; additional shares expected to be retired upon completion1 1. To be calculated based on VWAP through duration, less a pre-negotiated discount. Final shares to be trued-up at completion. 2. Includes ASR. 3. Based on next 12 months Adjusted EBITDA.
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12 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%. 2. Brandon Shores and H.A. Wagner RMR arrangements extended through 5/31/2031. 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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13 Strong Growth in Adjusted Free Cash Flow per Share with Meaningful Upside Advantaged Assets in Advantaged Locations Strong PJM Fundamentals Multiple Contracting Opportunities High quality cash flows with disciplined capital allocation Executing the Talen Flywheel Strategy
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Appendix
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15 Asset State Primary Fuel Type(s) Plant Type Ownership Owned Capacity (MW)1 Commercial Operations Date Region Susquehanna2 PA Nuclear Baseload 90% 2,247 1983 – 1985 PJM-PPL/MAAC Guernsey OH Natural Gas Baseload 100% 1,792 2023 PJM-AEP/RTO Martins Creek PA Natural Gas Intermediate 100% 1,704 1975 – 1977 PJM-PPL Montour PA Natural Gas Intermediate 100% 1,522 1972 – 1973 PJM-PPL Brunner Island3, 4 PA Coal / Natural Gas Intermediate 100% 1,431 1961 – 1969 PJM-PPL Brandon Shores5 MD Coal RMR 100% 1,273 1984 – 1991 PJM-BGE Lawrenceburg IN Natural Gas Baseload 100% 1,212 2004 PJM-AEP/RTO Freedom PA Natural Gas Baseload 100% 1,015 2018 PJM-PPL/MAAC Waterford OH Natural Gas Baseload 100% 882 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% 602 2004 PJM-PPL Darby OH Natural Gas / Oil Intermediate 100% 463 2001 PJM-AEP/RTO Conemaugh2, 4 PA Coal Intermediate 22% 385 1970 – 1971 PJM-PN/MAAC Colstrip Unit 32 MT Coal Baseload 30% 222 1984 – 1986 WECC Talen Total 15,452 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 Conemaugh by December 31, 2034. 5. See Note 9 to the Q3 2026 Financial Statements for additional information on the Brandon Shores and H.A. Wagner RMR arrangements. 6. Includes H.A. Wagner Units 3 and 4.
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16 Total Fleet Power Price Sensitivities3, 4 Balance of 20261 2027 2028 Margin Impact from Change in Power Price +$10/MWh +$25mm +$215mm +$415mm +$5/MWh +$10mm +$110mm +$205mm $(5)/MWh $(15)mm $(105)mm $(200)mm $(10)/MWh $(25)mm $(210)mm $(390)mm Hedging Program as of 9/30/2026 © Talen Energy Corporation 1. “Balance of 2026” is October – December 2026. 2. Figures rounded to the nearest 5%. 3. 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. 4. Where applicable, natural gas prices are adjusted to maintain consistent heat rate relationships with corresponding power prices. Figures rounded to the nearest $5mm. Market Price Summary Balance of 20261 2027 2028 PJM West Hub ATC ($/MWh) $71.54 $75.41 $77.41 AD Hub ATC ($/MWh) $60.16 $60.39 $61.80 PPL Zone ATC ($/MWh) $43.42 $48.32 $52.15 TETCO M2 ($/MMBtu) $2.16 $2.52 $2.99 TETCO M3 ($/MMBtu) $2.68 $3.61 $4.12 Total Fleet Hedge Position Balance of 20261 2027 2028 % Hedged of Expected Generation2 ~80% ~70% ~35% Hedge Value vs Market3 $(130)mm $(510)mm $(185)mm
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17 Maintaining Balance Sheet Strength Talen is committed to long-term net leverage target of <3.5x Leverage and Liquidity Snapshot Capitalization Summary ($mm unless otherwise noted) October 30, 2026 Unrestricted Cash $220 Secured Debt $2,868 Total Debt1 $9,689 Net Debt2 $9,469 Credit Metrics 2026E Adjusted EBITDA Midpoint3 $2,125 Total Liquidity4 $1,570 1. Total Debt excludes $1.5B standalone LCF and $1.5B capacity monetization. 2. Calculated as Total Debt less Unrestricted Cash. 3. Only includes contribution from the Cornerstone Acquisition starting on 6/15/2026.. 4. Calculated as Unrestricted Cash plus $1.35B RCF availability as of 10/30/2026. Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA. Balance Sheet Strength Provides Strategic Flexibility
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18 $835 $1,191 $131 $1,500 $2,500 $1,400 $1,290$1,350 $842 2026 - 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037+ Agency IDR / Secured Debt Rating Outlook S&P BB- / BB+ Stable Moody’s Ba3 / Baa3 Negative Fitch6 B+ / BB+ Stable Long-Dated Debt Maturities Debt Overview1 Debt Maturity Summary1,5 ($mm) Revolving Credit Facility (Undrawn) Term Loan B2 Tranche Maturity Principal ($mm) Interest Rate RCF Dec 2029 - SOFR + 150bps 2031 TLB2 Dec 2031 835 SOFR + 175bps 2032 TLB-12 Nov 2032 842 SOFR + 175bps 2032 TLB-22 Nov 2032 1,191 SOFR + 150bps Secured Debt $2,868 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 2009C Bonds3 Dec 2037 81 5.25% PEDFA 2009B Bonds3 Dec 2038 50 5.25% Unsecured Debt $6,821 Total Debt4 $9,689 Other Obligation – Capacity Monetization5 $1,500 PEDFA Bonds3 Unsecured Notes 1. As of 10/30/2026. 2. Subject to mandatory 1% annual amortization, not shown in debt maturity summary. 3. Subject to mandatory remarketing in 2027. 4. Total Debt excludes $1.5B standalone LCF and $1.5B capacity monetization. 5. Capacity monetization not included in debt maturity summary. Closed on 10/1/2026. Amortization June 2027 – May 2029. 6. Downgrade on corporate and unsecured ratings by one notch due to the capacity monetization liability.
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Appendix Modeling Assumptions and Supplemental Asset Detail
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20 2027E 2028E Generation (TWhs) Prices ($/MWh)2 Energy Revenue ($mm) Generation (TWhs) Prices ($/MWh)2 Energy Revenue ($mm) PJM 78.9 $56 $4,445 80.0 $60 $4,765 Other Markets 1.3 $60 $80 1.4 $63 $90 Revenue 80.3 $56 $4,525 81.4 $60 $4,855 Expected Hedge Settlements $(510) $(185) Fuel and Energy Purchases $(1,760) $(1,960) Energy Margin1 $2,255 $2,710 Note: Represents the midpoint of each guidance and outlook range provided. All projections in presentation are net to Talen’s ownership interest, unless otherwise noted. Numbers are rounded to the nearest $5mm. 1. Energy margin is comprised of: (i) margin associated with electric generation, (ii) bilateral physical electricity sales, RMR annual fixed-cost payments, and other contracts, and (iii) expected hedge settlements. Margin excludes nuclear fuel amortization. Figures rounded to the nearest $5mm. 2. Expected realized prices incorporate forward prices as of 9/30/2026 and reflect the effect of basis risk and AWS PPA ramp. Energy Revenue and Energy Margin Projections
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21 PJM Capacity Revenue Projections Note: Volumes include the impact of incremental BRA auctions in 2026E/2027E but reflect only the BRA in 2027E/2028E and 2028E/2029E. Excludes Keystone cleared volumes for 2026E/2027E. 1. Reflects cleared capacity and all other related capacity revenues, including bilateral contracts. All uncleared years are assumed at the $338 cap. Figures rounded to the nearest $5mm. Planning Year 2026E/2027E 2027E/2028E 2028E/2029E Volumes (MW) Prices ($/MWd) Revenues ($mm) Volumes (MW) Prices ($/MWd) Revenues ($mm) Volumes (MW)1 Prices ($/MWd) Revenues ($mm) PJM Capacity Revenue MAAC 10,357 $329.17 $1,244 10,437 $333.44 $1,274 10,001 $325.00 $1,186 Fiscal Year 2027E 2028E 2029E Revenues ($mm) Revenues ($mm) Revenues ($mm) PJM Capacity Revenue Total Capacity Revenue1 $1,250 $1,225 $1,220
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22 Modeling Assumptions and Supplemental Asset Detail 2027E 2028E O&M Expenses $725mm $735mm G&A / Other $105mm $110mm Nuclear Fuel Capital Expenditures $135mm $170mm Maintenance & Other Capital Expenditures $235mm $165mm Total Capital Expenditures $370mm $335mm Cash Income Taxes as % of Adjusted EBITDA 2% 3% Pension Contributions $20mm $25mm Asset Retirement Obligations and Environmental Liabilities $50mm $60mm Susquehanna Outage Outage Duration 30 – 35 days 30 – 35 days O&M / Capital Expenditure Cost $60mm - $65mm $60mm - $65mm Projected Capacity Factors Susquehanna1 ~95% ~95% PJM Baseload Gas Assets2,3 ~85% ~85% PJM Other Assets2,4 ~40% ~40% Note: Represents the midpoint of each guidance and outlook range provided. 1. Capacity factor based on maximum summer capacity rating. 2. Weighted average capacity factor based on maximum summer capacity rating. 3. Includes Freedom, Guernsey, Lawrenceburg, Lower Mount Bethel, and Waterford. 4. Includes Brunner Island, Darby, Martins Creek, Montour, and Conemaugh.
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Reconciliation of Non-GAAP Financial Measures
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24 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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25 Adjusted EBITDA / Adjusted Free Cash Flow Reconciliation: Q3 and YTD (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 September 30, Nine Months Ended September 30, ($mm) 2026 2025 2026 2025 Net Income (Loss) $ 138 $ 207 $ 109 $ 144 Adjustments Interest expense and other finance charges 148 67 481 203 Income tax (benefit) expense 57 97 38 70 Depreciation, amortization and accretion1 122 61 273 198 Nuclear fuel amortization1 27 27 73 71 Unrealized (gain) loss on commodity derivative contracts 190 (36) 555 54 Nuclear decommissioning trust funds (gain) loss, net (18) (81) (130) (149) Stock-based and other long-term incentive compensation expense 54 18 127 49 (Gain)loss on asset sales, net (66) (25) (69) (36) Non-cash impairments and other charges 1 1 2 11 Acquisition and divestiture activities2 2 8 39 12 Operational and other restructuring activities 4 3 11 6 Other 10 16 7 20 Total Adjusted EBITDA $ 669 $ 363 $ 1,516 $ 653 Capital expenditures, net (77) (65) (200) (164) Interest and finance charge payments (149) (36) (303) (143) Income taxes (1) - 5 (51) Pension contributions (9) (39) (23) (63) Total Adjusted Free Cash Flow $ 433 $ 223 $ 995 $ 232
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26 Adjusted EBITDA / Adjusted Free Cash Flow Reconciliation: 2026E and 2027E Guidance The reconciliation from forecasted “Net Income (Loss)” to Adjusted EBITDA and Adjusted Free Cash Flow for the years ended December 31: ($mm) Net Income (Loss) 2026E 2027E Low High Low High $ 960 $ 1,080 $ 1,105 $ 1,405 Adjustments Interest expense and other finance charges 460 480 585 615 Income tax (benefit) expense 15 25 50 70 Depreciation, amortization and accretion 515 515 650 650 Nuclear fuel amortization 100 100 110 110 Adjusted EBITDA $ 2,050 $ 2,200 $ 2,500 $ 2,850 Capital expenditures, net (325) (335) (355) (385) Interest and finance charge payments (460) (480) (585) (615) Income taxes (15) (25) (50) (70) Pension contributions (25) (35) (10) (30) Adjusted Free Cash Flow $ 1,225 $ 1,325 $ 1,500 $ 1,750