Investor Day Talen Energy Corporation | September 5, 2024
2 Disclaimers 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 in summary. For additional information, see the Company’s historical financial statements and other information included in its periodic reports and other filings with the 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. 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. 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 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” 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" (or "Cautionary Note Regarding Forward-Looking Statements") 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 risks associated with cryptocurrency mining projects due to the volatility of such currencies and oversight from federal and state agencies; 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 the actual load needed to perform full-requirements 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; federal and state legislation and regulation, including federal and state tax laws and regulations, and costs of complying with governmental permits and approvals; 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 the proposed renewable energy, energy storage, data center and digital currency facilities, realization of assumptions underlying the statements regarding future enterprises, and the 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; 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 and Russia conflict and attendant sanctions imposed on Russia and the related disruptions in oil and natural gas production), 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.
3 Agenda Executive Summary1 Growth Platform3 Appendix4Power Markets & Hedging2
Executive Summary
5 Pure play independent power producer that directly benefits from growing power demand in premium markets Disciplined track record of safe, reliable and cost-effective operations Why Talen? Focused on unlocking value and returning capital to shareholders First mover on providing direct-connect power to data center customers and well-positioned to use this advantage
6 $4.80 $7.70 $10.50 $5.60 $11.70 $17.50 2024E Guidance 2025E Guidance 2026E Outlook Substantial Cash Flow per Share Growth, Enhanced by Share Repurchase Program Adjusted Free Cash Flow per Share Forecasted Adjusted Free Cash Flow growing quickly, increasingly driven by stable sources2 Reloading our share repurchase program (SRP) capacity to $1.25B ✓ ✓ Evaluating multiple options across the fleet for our next data center power arrangements+ Continuous evaluation and reshaping of our asset portfolio+ Additional Upside Potential 3 Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted Free Cash Flow. Per share amounts rounded to nearest $0.10. 1. Calculated using the midpoint of each range provided. 2. Anticipated sources include AWS revenues, capacity revenues, Nuclear PTC and other. 3. Includes January – April contribution from the ERCOT generation fleet. Assuming Current Share Count of ~51mm
7 Track Record of Unlocking Value Since May 2023, Talen has identified and executed on multiple actions to unlock value with minimal capital spend Future Announced $50mm cost savings initiative Settled PPL litigation with $115mm payment to Talen $650mm sale of Cumulus Data campus to and long-term contracts with AWS $785mm sale of ERCOT portfolio Upsized share repurchase program to $1B Repurchased $612mm of stock in tender offer Repurchased $280mm of stock from largest shareholder Listed on NASDAQ Announced $300mm share repurchase program Began trading on OTCQX Jul - Aug 2023 Refinanced LMBE-MC project financing, bringing cash flows to corporate level Sep - Oct 2023 Bought out a third party’s warrants in TEC and minority interest in Cumulus Nov - Dec 2023 Mar 2024 Paid off Orion project financing and bought out Orion minority interest in Cumulus Bought out remaining minority interests in Cumulus Apr - May 2024 Repriced Term Loans B and C at lower interest rates Jun 2024 Remarketed PEDFA bonds, eliminating LC support Jul 2024 Aug - Sep 2024 Reloading share repurchase capacity to $1.25B Positioned for further growth and actions to unlock valueReceived $300mm of remaining AWS proceeds from escrow
8 Growing Power Demand Creates Opportunity for the Sector Significant growth in forecasted power demand, largely driven by data centers Minimal excess capacity and few dispatchable assets, leading to reliability concerns Development queues, still mostly renewables, lack a solution for intermittency Increasing energy and capacity prices Expanding spark spreads Unprecedented Change in the Power Markets Electrifying the Future Creates Opportunity Talen is Well-Positioned to Capture the Opportunity Protection through stable, high quality and diverse sources of margin1 Data center market opportunity Power price and spark spread upside Data centers need increasing amounts of power that is quick to access, cost- effective and reliable Supporting this growth requires a balance of direct-connected and grid- connected solutions Talen’s data center transaction is a first- mover and just one of many potential solutions to growing supply needs Economic opportunity for all stakeholders: generators, T&D, consumers, local communities 1. Anticipated sources include AWS revenues, capacity revenues, Nuclear PTC and other.
9 >50% carbon-free generation ~10.7 GW total generation capacity 12 generation facilities ~1,900 employees 1H 2024 Generation Mix Generation Portfolio Breakdown1 56% 32% 9% 3% Generation Portfolio Overview ISO-NE Dartmouth Colstrip MAAC EMAAC Lower Mount Bethel Martins Creek Keystone Conemaugh Brunner Island RTO WECC Brandon Shores H. A. Wagner Montour Camden Susquehanna Susquehanna Nuclear Facility Premium PJM Gas Assets OtherReliability Assets PJM BGE Capacity by Region PJM 97% WECC 2% ISO-NE 1% Note: Same legend as the map. Talen by the Numbers Note: As of 6/30/2024. 1. Excludes January – April contribution from the ERCOT generation fleet.
10 $245 $395 $535 $285 $595 $895 2024E Guidance 2025E Guidance 2026E Outlook $720 $925 $1,130 $780 $1,175 $1,530 2024E Guidance 2025E Guidance 2026E Outlook Introducing 2025 Guidance and 2026 Outlook Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA and Adjusted Free Cash Flow. 1. Calculated using the midpoint of each range provided. 2. Adjusted Free Cash Flow Conversion calculated as the midpoint of the Adjusted Free Cash Flow range divided by the midpoint of the Adjusted EBITDA range for each year. 3. 2024E includes January – April contribution from the ERCOT generation fleet. Adjusted EBITDA ($mm) Adjusted Free Cash Flow (after Taxes, $mm) ~35% ~45% ~55% Adjusted Free Cash Flow Conversion2 Dynamic hedging program; as of July 31, 2024: ▪ ~100% hedged for balance of 2024 ▪ ~67% hedged for 2025 ▪ ~31% hedged for 2026 PJM capacity auction ▪ ~$270/MW-day capacity price for ’25/’26 planning year ▪ Assumed ~$270/MW-day for ’26/’27 ▪ $50/MW-day change in ‘26/’27 capacity price changes 2026E Adjusted EBITDA by ~$50mm Contractual AWS PPA ramp: 120 MW starting in mid-’25, ramping to 240 MW in mid-’26 Key Drivers of 2025 & 2026 Ranges 3 3
11 Reloading Share Repurchase Capacity to $1.25 Billion Existing SRP through YE 2025 (+) Upsizing SRP New Total SRP through YE 2026 Share Repurchase Program Overview ($mm) Executed Repurchases Additional Capacity Note: Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted Free Cash Flow. 1. Unrestricted cash as of 8/30/2024. 2. Calculated using the midpoint of each range provided. Targeting return of ~70% of Adjusted Free Cash Flow to shareholders going forward✓ Increasing SRP capacity, given confidence in cash flows, modest leverage, ample liquidity and limited need for growth capex ✓ Supported by $692mm of unrestricted cash1 and >$1.2B of projected cumulative Adjusted Free Cash Flow in 2025 – 20262 ✓ Flexibility to support growth if economically justified, while remaining disciplined+ $931 $931 $107 $1,250 $1,143 $1,038 $2,181
12 50%50% 28% 72% Significant Expected Margin Growth, with Increasing Stability 2024E 2025E 2026E Generation and Other3 Stable2 1. Calculated using the midpoint of each guidance and outlook range provided and rounded to nearest 5%. 2. Anticipated sources include AWS revenues, capacity revenues, Nuclear PTC and other. 3. Includes margin from generation, hedges and other. Talen’s margin is expected to grow over time, with an increasing share coming from stable sources2 Reduces hedging activity and liquidity needs Increases balance sheet strength and flexibility ✓ ✓ Margin Composition1 30% 70% 40% 60%
13 Talen is Now Eligible for Multiple Indices Index S&P TMI / Completion CRSP TMI / Small Cap MSCI Small Cap 1750 Russell 1000 S&P 400 Potential Inclusion Date September 2024 September 2024 November 2024 June 2025 September 2025 or later Note: Inclusion is to be determined by the governing body of each index. Table is illustrative based on the current index methodologies, which are subject to change at any time. There can be no assurance that Talen’s common stock will be included in any particular index at a specific time or at all. After uplisting to NASDAQ, Talen is now eligible for several indices, which could drive substantial institutional / passive stock demand:✓ + Talen may qualify for additional value, growth and/or sector-related indices, leading to further demand
Power Markets & Hedging
15 © Talen Energy Corporation Proprietary and Confidential Sources: Grid Strategies, “The Era of Flat Power Demand is Over” (December 2023); U.S. Department of the Treasury, “Unpacking the Boom in U.S. Construction of Manufacturing Facilities” (June 2023); Schneider Electric Sustainability Research Institute, “The untold potential and rationale of industrial electrification in the United States” (June 2024). 1. PJM Load Forecast Reports (Jan 2022, Jan 2023, Jan 2024). 5-Year Nationwide Growth Forecast PJM Demand Forecast1 U.S. Power Demand is Growing, Especially in PJM 140 150 160 170 180 190 200 20 21 20 22 20 23 20 24 20 25 20 26 20 27 20 28 20 29 20 30 20 31 20 32 20 33 20 34 20 35 20 36 20 37 20 38 20 39 Su m m er L oa d (G W ) 2024 Forecast 2023 Forecast 2022 Forecast +18 GW increase from 2024 to 2030 Demand Growth Drivers Forecast 2028 Peak: 835 GW 2.6% Growth Forecast 2028 Peak: 852 GW 4.7% Growth 0 10 20 30 40 2022 Forecast 2023 Forecast Su m m er P ea k D em an d G ro w th (G W ) 17 GW Increase Domestic industry & manufacturing: Manufacturing construction spending has increased substantially since 2023, also supported by government funding Electrification: Nearly half of industrial energy consumption could be electrified in the near-term Data centers: U.S. energy demand has 5% CAGR or 7 GW total growth from 2023 to 2030
16 PJM Market Fundamentals are Tightening Note: Reserve Margin includes Fixed Resource Requirement + Reliability Pricing Model (Total ICAP / Total Peak – 1). Each planning year runs from June 1 through May 31 of the following year. Resource Clearing Prices rounded to nearest $/MW-day. 1. PJM, “Energy Transition in PJM: Resource Retirements, Replacements and Risks” (February 2023). High New Entry and Low New Entry refers to the pace of generation entry driven by construction and retirement of new resources. Resource Clearing Price ($/MW-day) Reserve Margin Historical Capacity Auction Results by Planning Year (RTO) PJM Reserve Margin Forecast (%)1 Low New EntryHigh New Entry ▪ PJM reserve margins are shrinking as power demand grows while supply faces retirements and lack of new builds ▪ The 2025/2026 PJM capacity auction results demonstrate the growing need for reliable supply ▪ We expect this dynamic to persist in upcoming auctions, further increasing the importance of existing generation 15% 11% 8% 8% 5% 19% 17% 16% 17% 15% 2026E 2027E 2028E 2029E 2030E $ 100 $ 77 $ 140 $ 50 $ 34 $ 29 $ 270 ? 22% 23% 22% 20% 20% 20% 19% '19/'20 '20/'21 '21/'22 '22/'23 '23/'24 '24/'25 '25/'26 '26/'27
17 Note: Includes the impact of the Nuclear PTC. 1. Measured at end of each calendar year. 2. Margin is comprised of hedged energy margin, capacity revenues and Nuclear PTC. Excludes the effects on bitcoin margin. Figures rounded to nearest $5mm. 3. Where applicable, sensitivities adjusted monthly gas prices to maintain consistent heat rate relationships with corresponding power prices for each power market served by a particular gas supply. Hedging Strategy Well-Positioned in Current Market Total Fleet: % Hedged and Power Price Sensitivities as of July 31, 2024 2025E 2026E % Hedged 67% 31% Margin2 Impact of Change in Power Price3 +$10/MWh +$190 +$285 +$5/MWh +$90 +$145 -$5/MWh -$35 -$135 -$10/MWh -$50 -$240 Commercial Hedging Strategy Margin & Cash Flow Protection (Table Stakes) Macro & Geopolitical Factors Point of View on Power Markets Commercial Liquidity Operating & Regulatory Risk Hedge Counterparty Credit Risk Talen’s commercial strategy creates asymmetric returns ▪ Protects against downside, providing cash flow stability ▪ Retains exposure to upside through both generation and opportunistic hedging Hedging targets are based on % of generation1 ▪ Prompt Months 1 – 12: 60% – 80% ▪ Prompt Months 13 – 24: 40% – 60%
Growth Platform: Powering the Future
19 Long-Term Agreements with AWS Create Stable Cash Flow Growth Progress Update ▪ Susquehanna PPA for up to 960 MW direct-connect, carbon-free power ▪ Increasing by 120 MW in commitments per year, with option to accelerate power ramp ▪ Fixed price over 10-year terms, repriced at market ▪ Additional revenue from carbon-free energy sales (CFE) Overview of AWS Contracts ✓ May 2024: Township zoning changes approved for data center use ✓ Jun 2024: Building permit received to fit-out existing data center shell ✓ Jul 2024: Master Site Plan approved; unlocks full campus development ✓ Aug 2024: $300mm escrow released
20 Financial Impact of AWS Contracts ($mm/year, rounded to nearest $5mm) Contractual Minimums 480 MW Power Sales + Additional Revenue Related to CFE 960 MW Power Sales + Additional Revenue Related to CFE Illustrative Incremental Impact Above Nuclear PTC on Adjusted EBITDA Notes ▪ Incremental impact based on comparison of (1) Susquehanna revenues including AWS power sales and additional revenue from AWS related to sales of CFE vs. (2) Susquehanna revenues assuming the “PTC Reference Price,” which represents max price of the Nuclear PTC floor (assuming 2% annual inflation) until “Complete Campus (2034 – 2042 Avg.).” ▪ Reference pricing shown for 2034 – 2042 represents the simple average of SSES node energy prices + MAAC capacity prices; projected SSES node prices are assumed to be at a discount to West Hub energy prices; all of these reference prices are for illustrative purposes only and not Company projections of long-dated energy or capacity prices. ▪ Financial outcomes and schedules depicted here are base cases subject to confidential contractual provisions that may affect the non-minimum commitment depictions in either direction; outcomes may also be impacted by IRS guidance regarding the Nuclear PTC. Year-End Power Sales: 480 MW & 960 MW Cases 120 / 120 240 / 240 480 / 480 480 / 840 480 / 960 PTC Reference Price ($/MWh) $45 $45 $46 $51 $54 +$20 +$55 +$85 +$125 +$75 +$35 +$80 +$140 +$215 +$255 +$150 +$135 2025 2026 2028 2031 Complete Campus (2034 - 2042 Avg.) For every $1/MWh above the PTC Reference Price, the annual incremental EBITDA impact decreases by ~$1mm per 120 MW
21 Update on FERC ISA Process Reliability Review by PJM and PPL ISA Amendments FERC Review Prior Amendment to 300 MW Current Amendment to 480/960 MW Two Separate FERC Processes ▪ Allows up to 300 MW co- located load ▪ Allows up to 480 MW co-located load ▪ Includes enhanced reliability safeguards (Schedule F) ▪ Talen will pay 100% of costs to address the minor stability concern (<$3mm) ▪ No issues ▪ Up to 480 MW: No issues ▪ Up to 960 MW: Identified a minor grid stability concern under extreme conditions ▪ FERC approval received ▪ FERC issued deficiency letter, requesting more information on part of Schedule F 1 ISA 2 Technical Conference ▪ PJM has responded to FERC, with PPL and Talen’s support ▪ FERC expected to complete review by November 4 ▪ Set for November 1 ▪ Separate from ISA, to address broader topic as industry ▪ No specific proceedings to be discussed Talen is optimistic that FERC will approve the filed amendments after the Commission has fully reviewed PJM’s response to FERC’s deficiency letter The Process
22 Talen Has Built a Valuable Platform to Power the Data Center Economy Talen Understands What is Important to Hyperscalers… … And Has Built Industry-Leading Expertise & Team Speed of Access to Space and Power Scalable to Support 1 GW+ AI Customers 24x7 Reliable + Low-Carbon Power Access to Critical Data Center Infrastructure (Fiber, Water) Technical Development Stakeholder Engagement Commercial Contracting Talen is using this platform to develop multiple options across the fleet for our next data center power arrangements
23 Talen is Uniquely Positioned to Power the Future Diverse fleet of nuclear, gas, and reliability assets Able to capitalize on power demand growth through dispatchable generation in premium PJM market Disciplined track record of safe, reliable and cost-effective operations First-mover in delivering carbon-free power to data centers, with plans to replicate this success Balance sheet is a strategic asset, allowing Talen to target the return of ~70% Adjusted Free Cash Flow to shareholders Strong Adjusted Free Cash Flow growth enabling reloading of SRP to $1.25B
24 Talen is Powering the Future Reliability Assets Premium PJM Gas Assets Disciplined Cost and Capital Management Powering Data Centers Susquehanna Nuclear Facility Dynamic Commercial Hedging Strategy
Appendix: Modeling Assumptions
26 2024E1 2025E 2026E Generation (TWhs) Prices ($/MWh) Energy Revenue ($mm) Generation (TWhs) Prices ($/MWh) Energy Revenue ($mm) Generation (TWhs) Prices ($/MWh) Energy Revenue ($mm) PJM Fleet2 34.5 $36 $1,235 34.5 $48 $1,665 34.5 $53 $1,835 Montana 1.4 $75 $105 1.5 $78 $120 1.6 $77 $125 Total Unhedged Energy Revenue3 35.9 $37 $1,340 36.0 $50 $1,785 36.1 $54 $1,960 % Generation Hedged Prices ($/MWh) Hedge Margin ($mm) % Generation Hedged Prices ($/MWh) Hedge Margin ($mm) % Generation Hedged Prices ($/MWh) Hedge Margin ($mm) Margin from Non-PTC Hedges 70% $8 $200 54% $2 $40 22% $1 $5 Fuel Expense & Purchased Power $(610) $(660) $(675) Total Hedged Energy Margin $930 $1,165 $1,290 Note: Represents the midpoint of each guidance and outlook range provided. All projections in presentation are net to Talen’s ownership interest, unless otherwise noted. 1. Excludes January – April contribution from the ERCOT generation fleet. 2. Includes Susquehanna, Lower Mount Bethel, Martins Creek, Montour, Dartmouth, Camden, Brunner Island, Conemaugh, Keystone, Brandon Shores and H.A. Wagner. Includes revenues from AWS contracts. 3. Reflects revenues earned from generation. Energy Revenue and Margin Projections
27 Planning Year 2023/2024 2024E/2025E 2025E/2026E 2026E/2027E Volumes (MW) Prices ($/MW- day) Revenues ($mm) Volumes (MW) Prices ($/MW- day) Revenues ($mm) Volumes (MW) Prices ($/MW- day) Revenues ($mm) Volumes (MW) Prices1 ($/MW- day) Revenues ($mm) PJM Capacity Revenue MAAC 6,792 $ 49.35 $ 123 7,281 $ 53.30 $ 142 6,705 $ 269.92 $ 661 6,283 $ 269.92 $ 619 EMAAC 142 49.35 3 142 53.60 3 115 269.92 11 112 269.92 11 BGE 1,836 70.64 47 1,786 80.16 52 - - - - - - Total 8,770 $ 53.81 $ 173 9,208 $ 58.51 $ 197 6,820 $ 269.92 $ 672 6,395 $ 269.92 $ 630 Fiscal Year 2024E 2025E 2026E Volumes (MW) Prices ($/MW- day) Revenues ($mm) Volumes (MW) Prices ($/MW- day) Revenues ($mm) Volumes (MW) Prices ($/MW- day) Revenues ($mm) PJM Capacity Revenue MAAC 7,006 $ 53.54 $ 137 7,031 $ 173.17 $ 446 6,530 $ 269.92 $ 643 EMAAC 142 51.90 3 130 162.69 8 114 269.92 11 BGE 1,818 75.95 50 1,044 56.56 22 - - - Total 8,966 $ 58.06 $ 190 8,205 $ 158.16 $ 475 6,644 $ 269.92 $ 655 PJM Capacity Revenue Projections Note: Volumes include the impact of incremental auctions in 2023/2024 and 2024E/2025E but reflect only the base residual auctions (“BRA”) in 2025E/2026E and 2026E/2027E. Volumes are adjusted for expected reductions associated with the AWS PPA. Fiscal year capacity revenues represent the midpoint of each guidance and outlook range provided. 1. BRA clearing price for 2026E/2027E reflects Company assumptions.
28 $570 $570 $580 2024E 2025E 2026E $100 $100 $135 $80 $100 $90 2024E 2025E 2026E Nuclear Fuel Maintenance & Other $225 $200 $180 Increases due to investments in continuing operations and hardening assets for reliability purposes Note: Represents the midpoint of each guidance and outlook range provided. 1. Includes January – April contribution from the ERCOT generation fleet. O&M and Capital Expenditure Projections O&M Expenses ($mm) Capital Expenditures ($mm) 1 1
29 Agency IDR / Secured Debt Rating Outlook S&P B+ / BB Positive Moody’s B1 / Ba3 Positive Fitch BB- / BB+ Stable Note: Total Debt excludes $470mm Term Loan C, given that the associated cash proceeds are held in interest-bearing restricted accounts to secure LCs. Also excludes $75mm bilateral secured LC facility. 1. Revolving Credit Facility’s interest rate formula is SOFR + 3.0%, and Term Loans B and C’s interest rate formula is SOFR + 3.5%. 2. Subject to mandatory 1% annual amortization, not shown in graph. 3. Subject to mandatory remarketing in 2027. Long-Dated Debt Maturities and Solid Credit Ratings Debt Overview Debt Maturity Summary ($mm) $ 700 $2,061 $ 131 2024 2025 2026 2027 2028 2029 2030 2037+ Revolving Credit Facility (Undrawn) Term Loan B2 / Secured Notes PEDFA Bonds3 No Material Near-term Debt Maturities Tranche Maturity Principal ($mm) Interest Rate1 as of 8/30 Revolving Credit Facility May 2028 $- ~8% Secured Notes June 2030 1,200 8.625% Term Loan B2 May 2030 861 8.60% Secured Debt $2,061 PEDFA 2009B Bonds3 December 2038 50 5.25% PEDFA 2009C Bonds3 December 2037 81 5.25% Unsecured Debt $131 Total Debt $2,192 Excluded: Term Loan C May 2030 $470 8.60%
30 Note: Excludes $470mm Term Loan C, given that the associated cash proceeds are held in interest-bearing restricted accounts to secure LCs. Also excludes $75mm bilateral secured LC facility. Please refer to Reconciliation of Non-GAAP Financial Measures section of the Appendix for more detail on Adjusted EBITDA. 1. Includes January – April contribution from the ERCOT generation fleet. 2. Calculated using Net Debt as of 8/30/2024. 3. Calculated as $692mm unrestricted cash as of 8/30/2024, plus $700mm revolver availability. 4. Calculated as Total Debt less Unrestricted Cash as of 8/30/2024. Strong Credit and Liquidity Metrics $mm August 30, 2024 Unrestricted Cash $692 Secured Debt $2,061 Total Debt $2,192 Net Debt4 $1,500 Capitalization Summary Credit Metric Summary Credit Metrics 2024E Adjusted EBITDA Guidance Midpoint ($mm)1 $750 Net Debt / 2024E Adjusted EBITDA2 ~2.0x Total Liquidity ($mm)3 $1,392
31 2024E 2025E 2026E Nuclear PTC ($mm) $190 $0 $0 Other Margin ($mm)1 $60 $50 $40 Cash Taxes as % of Adjusted EBITDA2 1% 7% 11% Pension Contributions ($mm) $(60) $(60) $(30) Asset Retirement Obligations and Environmental Liabilities ($mm) $(20) $(40) $(60) Other Modeling Inputs Note: Represents the midpoint of each guidance and outlook range provided. 1. Represents 100% of Nautilus JV revenues less power costs. Minority interest is eliminated through non-controlling interest. 2. Excludes amounts expected to be paid on the sale of ERCOT and Cumulus Data assets in 2024.
32 ▪ Starting in 2024, the PTC benefit is calculated based on a year’s annual “gross receipts” divided by annual generation ▪ Talen is awaiting additional regulatory guidance about PTC mechanics ▪ Talen’s current assumption for gross receipts: physical energy margin, capacity revenues and ancillary revenues; no hedges or sales to affiliates ▪ Max potential benefit of $15/MWh1 in 2024, escalating with inflation ▪ PTC decreases linearly for gross receipts between $25/MWh and $43.75/MWh and is fully phased out at gross receipts above $43.75/MWh ▪ 2025+ Inflation Adjustment = GDP price deflator in preceding year GDP price deflator in 2023 ▪ IRA has transfer procedures that permit project owners to transfer (sell) their PTCs to unrelated taxpayers for cash o Advanced contractual arrangements are allowed Note: Per U.S. Congress. 1. Starting in 2024 and excluding inflation, PTC has a “base” amount of $3/MWh, which can increase 5x to $15/MWh under certain wage requirements that Susquehanna expects to meet. 2. Maximum PTC increases in increments rounded to the nearest $2.50/MWh. 3. Gross Receipts Threshold increases in increments rounded to the nearest $1/MWh. Nuclear Production Tax Credit Overview Year Maximum PTC2 Gross Receipts Threshold3 Receipts At Which PTC = $0 2024 $15.00 $25.00 $43.75 2025 $15.00 $26.00 $44.75 2026 $15.00 $26.00 $44.75 2027 $15.00 $27.00 $45.75 2028 $17.50 $27.00 $45.75 2029 $17.50 $28.00 $49.88 2030 $17.50 $28.00 $49.88 2031 $17.50 $29.00 $50.88 2032 $17.50 $29.00 $50.88 $20 $25 $30 $35 $40 $45 $50 $55 $60 $20 $25 $30 $35 $40 $45 $50 $55 $60 G ro s s R e c e ip ts + P T C ( $ /M W h ) Gross Receipts ($/MWh) Above $43.75/MWh: No PTC benefit Between $25 and $43.75/MWh $1/MWh increase in gross receipts → $0.80/MWh decrease in PTC benefit Below $25/MWh $1/MWh increase in gross receipts → No decrease in PTC benefit ($15/MWh) Nuclear PTC Overview Nuclear PTC Impact1 Illustrative PTC Inflation Adjustments (2% Inflation)
Appendix: Supplemental Asset Detail
34 Asset Location Fuel Type Plant Type Plant Configuration Ownership Owned Capacity (MW)1 Commercial Operations Date (COD) Region Susquehanna Nuclear Facility Susquehanna2 PA Nuclear Baseload Dual-Unit 90% 2,228 1983 – 1985 PJM-PPL/MAAC Premium PJM Gas Assets Brunner Island3, 4 PA Natural Gas / Coal Intermediate Three-Unit 100% 1,429 1961 – 1969 PJM-PPL Camden NJ Natural Gas Peaker Dual-Unit 100% 145 1993 PJM-PSEG Lower Mt. Bethel PA Natural Gas Baseload Dual-Unit 100% 606 2004 PJM-PPL Martins Creek PA Natural Gas Peaker Dual-Unit 100% 1,716 1975 – 1977 PJM-PPL Montour PA Natural Gas Peaker Dual-Unit 100% 1,508 1972 – 1973 PJM-PPL Reliability Assets Brandon Shores5 MD Coal Peaker Dual-Unit 100% 1,283 1984 – 1991 PJM-BGE H.A. Wagner5 MD Oil Peaker Four-Unit6 100% 848 1956 – 1972 PJM-BGE Colstrip Unit 32 MT Coal Baseload Single-Unit 30% 222 1984 – 1986 WECC Other Conemaugh2, 4 PA Coal Intermediate Dual-Unit 22% 386 1970 – 1971 PJM-MAAC Keystone2, 4 PA Coal Intermediate Dual-Unit 12% 214 1967 – 1968 PJM-MAAC Dartmouth MA Natural Gas Peaker Three-Unit 100% 80 1992 – 2009 ISO-NE Total 10,665 Generation Portfolio Summary as of June 30, 2024 1. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision. 2. See Note 10 to the FY 2023 Financial Statements for additional information regarding 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, Keystone, and Conemaugh by December 2028. 5. See Note 8 to the Q2 2024 Financial Statements for additional information on the Brandon Shores and H.A. Wagner deactivations and RMR Cost of Service Filings. 6. Includes ~14 MW oil-fired peaking units.
35 Talen’s Diverse Asset Fleet Premium PJM Gas Assets (Brunner Island, Camden, Lower Mount Bethel, Martins Creek, Montour) Valuable, low-carbon dispatchable generation The mix of baseload, intermediate and peaking assets creates multiple ways to capture generation margin in a volatile power market Low-cost Marcellus shale natural gas nearby Reliability Assets (Brandon Shores, Wagner, Colstrip) Brandon Shores and H.A. Wagner are important for PJM grid reliability and part of a reliability-must-run (RMR) proceeding to potentially remain online through 2028 Colstrip operates at high capacity factors in an energy-only market and is important to the region’s grid and economy 1. Based on 2023 average EUCG benchmarking for all-in costs across the U.S. nuclear industry, which includes opex, capex and allocated corporate G&A. 2. Maximum Nuclear PTC benefit in 2024, excluding impact of inflation. Susquehanna Nuclear Facility ▪ 6th largest U.S. nuclear facility, with dual units; operated and 90% owned by Talen (~2.2 GW) ▪ Highly reliable baseload asset, with capacity factors >90% ▪ Supplies power to AWS data center campus ▪ Licensed through 2042 and 2044 and beginning work on additional 20-year extensions ▪ Top-decile cost efficiency1 (~$24/MWh all-in cost in 2023) ▪ Downside protected by up to $15/MWh Production Tax Credit2 ▪ Fuel fully contracted through 2026 outage and substantially through 2028 outage
36 Susquehanna: Generation and Capacity Factors % of Total Fleet Annual Generation1 1. 2024E excludes January – April contribution from the ERCOT generation fleet. 2. Capacity factor based on maximum summer capacity rating. 18.4 18.7 18.8 2024E 2025E 2026E 51% 52% 52% 94% 96% 96% 2024E 2025E 2026E Projected Annual Generation (TWh) Projected Capacity Factors2
37 ▪ Engaged workforce at all levels to focus on safety, reliability and cost efficiency ▪ Improved cost structure and simplified organization and processes ▪ Maintained safety better than nuclear industry average ▪ Operations in keeping with the highest performers in the industry ▪ Continue to identify and eliminate risk through proactive maintenance ▪ Continue to focus on keeping reliability high ▪ Continue applying capital where we get the best return Total Recordable Incident Rate (TRIR)1 0.1 0.0 0.3 0.1 2016 2024 YTD Susquehanna Nuclear Industry Average² $32 $24 $26 2016 2023 Susquehanna 2023 Nuclear Industry Top Quartile 1. The number of recordable incidents x 200,000 / total number of hours worked. 2. Per the Bureau of Labor Statistics and INPO. 3. Based on EUCG benchmarking; 2023 Nuclear Industry Top Quartile is across the U.S. nuclear fleet. Susquehanna: Operational Highlights Journey to Today Looking Forward All-In Cost ($/MWh)3
38 Susquehanna: Nuclear Fuel Update % Nuclear Fuel Contracted by Outage Year12025 Outage Fuel Cost Breakdown 25% 25% 7% 43% Uranium (U308) Conversion Enrichment Fabrication 100% 100% 87% 97% 13% 3% 2025E 2026E 2027E 2028E Open Contracted Note: As of July 2, 2024. 1. % of nuclear fuel capex that is open is calculated assuming recent market prices.
39 Premium PJM Gas Assets: Generation and Capacity Factors % of Total Fleet Annual Generation1 Note: Premium PJM Gas Fleet includes Brunner Island, Camden, Lower Mount Bethel, Martins Creek and Montour. 1. 2024E excludes January – April contribution from the ERCOT generation fleet. 2. Weighted average capacity factor based on maximum summer capacity rating. Projected Annual Generation (TWh) Projected Capacity Factors2 37% 34% 33% 13.2 12.3 12.1 2024E 2025E 2026E 28% 26% 25% 2024E 2025E 2026E
40 Premium PJM Gas Assets: Brunner Island MAAC RTO 1,429 MW Owned Capacity1 PJM-PPLMarket ~10 MMBtu/MWhHeat Rate IntermediatePlant Type 1961 - 1969COD Three-unit, dual-fuel plant near the Susquehanna River Can switch between coal and gas within hours without going offline, a big advantage during peaking periods Low-cost Marcellus gas supply (TETCO M3) No coal-fired generation in May to September of each year or after YE 2028 1. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision. Meaningful revenues from capacity payments
41 Premium PJM Gas Assets: Lower Mount Bethel MAAC RTO 606 MW Owned Capacity1 PJM-PPLMarket ~7 MMBtu/MWhHeat Rate BaseloadPlant Type 2004COD Dual-unit combined cycle gas turbine plant near the Delaware River that shares a site with Martins Creek Low-cost Marcellus gas supply (TETCO M3), with firm transportation agreement through 2029 Long-term service agreement with Siemens Energy for maintenance and reliability Low heat rate, fuel costs and operating costs enable plant to run at ~80% capacity factors 1. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision.
42 Premium PJM Gas Assets: Martins Creek MAAC RTO 1,716 MW Owned Capacity1 PJM-PPLMarket ~10 MMBtu/MWhHeat Rate PeakerPlant Type 1975 - 1977COD Dual-unit gas plant near the Delaware River that shares a site with Lower Mount Bethel Meaningful revenues from capacity payments Low-cost Marcellus gas supply (TETCO M3) Units capable of cycling daily to capture peak energy prices 1. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision.
43 Premium PJM Gas Assets: Montour MAAC RTO 1,508 MW Owned Capacity1 PJM-PPLMarket ~9.5 MMBtu/MWhHeat Rate PeakerPlant Type 1972 - 1973COD Dual-unit gas plant in the heart of the Marcellus shale near Leidy Hub Leidy gas typically trades at discount to TETCO M3 in winter and often is the cheapest natural gas in PJM 1. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision. Meaningful revenues from capacity payments Both units converted from coal to gas in Q3 2023, which has resulted in meaningful O&M and capex savings
44 Reliability Assets: Brandon Shores MAAC RTO 1,283 MW Owned Capacity1 PJM-BGEMarket Peaker / ReliabilityPlant Type 1984 - 1991COD Dual-unit coal plant on a large site near Baltimore Harbor that shares a site with H.A. Wagner Assuming acceptable RMR arrangement is reached, only revenues would be monthly payments from PJM Several attractive options after 2028 depending on economics, such as sale of the land, data centers, repowering or battery storage 1. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision. State-of-the-art environmental controls and modern landfill for CCR disposal near plant PJM has determined that plant is needed through 2028 for reliability
45 Reliability Assets: H.A. Wagner Four-unit1, oil-fired plant on a large site near Baltimore Harbor that shares a site with Brandon Shores Assuming acceptable RMR arrangement is reached, only revenues would be monthly payments from PJM MAAC RTO 848 MW Owned Capacity2 PJM-BGEMarket Peaker / ReliabilityPlant Type 1956 - 1972COD PJM has determined that Units 3 and 4 are needed through 2028 for reliability 1. Units 1, 3, 4 and the CT are currently operating. Unit 1 and the CT will retire with PJM in June 2025. Units 3 and 4 are subject to ongoing RMR proceedings. 2. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision. Several attractive options after 2028 depending on economics, such as sale of the land, data centers, repowering or battery storage
46 Reliability Assets: Colstrip 222 MW Owned Capacity2 WECC / Mid-ColumbiaMarket BaseloadPlant Type 1984 – 1986 (Units 3 & 4) COD WECC WY MT ND SDID Coal plant with two active units in which Talen has a minority stake and is the operator Other co-owners include Puget Sound Energy, Portland General Electric, Avista, PacifiCorp and NorthWestern Energy1 Important part of Montana’s economy and grid, which is experiencing elevated power pricing due to tightening reserve margins Environmental rules like MATS and GHG may impact the plant’s operating lifespan 1. NorthWestern is acquiring Avista and Puget Sound’s stakes in January 2026. 2. Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions which may be subject to revision. Adjacent coal mine supplies plant with low-cost fuel via conveyor
Appendix: Reconciliation of Non-GAAP Financial Measures
48 Definitions of Non-GAAP Financial Measures Non-GAAP Financial Measures The following non-GAAP financial measures of Adjusted EBITDA and Adjusted Free Cash Flow discussed below, 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 of this financial information not to place undue reliance on these non-GAAP financial measures, but to also consider it with its most directly comparable GAAP measure. Non- GAAP measures have limitations as an analytical tool 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 the Company's 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; (xii) 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 Q1 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 period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of the 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 EBITDA is not intended to replace “Net Income (Loss),” which is the most comparable measure calculated and presented in accordance with GAAP. Adjusted Free Cash Flow Adjusted Free Cash Flow, a key non-GAAP financial measure, is a useful metric 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 taxes (excluding income taxes paid from the NDT) 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 period to period depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired. © Talen Energy Corporation
49 © Talen Energy Corporation ($Millions) 2024E Low High Net Income (Loss) $730 $790 Adjustments Interest expense and other finance charges $240 $240 Income tax (benefit) expense 180 180 Depreciation, amortization and accretion 300 300 Nuclear fuel amortization 120 120 Unrealized (gain) loss on commodity derivative contracts 45 45 (Gain) loss (885) (885) Other (10) (10) Adjusted EBITDA $720 $780 Capital expenditures, net $(175) $(185) Interest and finance charge payments (240) (240) Tax payments (a) (5) (5) Pension contributions (55) (65) Adjusted Free Cash Flow $245 $285 Adjusted EBITDA / Adjusted Free Cash Flow Reconciliation: 2024 Guidance The reconciliation from forecasted "Net Income (Loss)" to Adjusted EBITDA and Adjusted Free Cash Flow for the year ended December 31: Notes a) Excludes income taxes paid from the NDT. Note: Figures include Cumulus and are rounded to the nearest $5mm.
50 © Talen Energy Corporation ($Millions) 2025E Low High Net Income (Loss) $ 190 $ 410 Adjustments Interest expense and other finance charges $ 215 $ 225 Income tax (benefit) expense 90 110 Depreciation, amortization and accretion 295 295 Nuclear fuel amortization 105 105 Unrealized (gain) loss on commodity derivative contracts 30 30 Adjusted EBITDA $ 925 $ 1,175 Capital expenditures, net $ (195) $ (205) Interest and finance charge payments (215) (225) Tax payments (a) (65) (85) Pension contributions (55) (65) Adjusted Free Cash Flow $ 395 $ 595 Adjusted EBITDA / Adjusted Free Cash Flow Reconciliation: 2025 Guidance The reconciliation from forecasted "Net Income (Loss)" to Adjusted EBITDA and Adjusted Free Cash Flow for the year ended December 31: Notes a) Excludes income taxes paid from the NDT. Note: Figures include Cumulus and are rounded to the nearest $5mm.
51 © Talen Energy Corporation ($Millions) 2026E Low High Net Income (Loss) $ 350 $ 720 Adjustments Interest expense and other finance charges $ 205 $ 215 Income tax (benefit) expense 180 200 Depreciation, amortization and accretion 290 290 Nuclear fuel amortization 100 100 Unrealized (gain) loss on commodity derivative contracts 5 5 Adjusted EBITDA $ 1,130 $ 1,530 Capital expenditures, net $ (220) $ (230) Interest and finance charge payments (205) (215) Tax payments (a) (145) (155) Pension contributions (25) (35) Adjusted Free Cash Flow $ 535 $ 895 Adjusted EBITDA / Adjusted Free Cash Flow Reconciliation: 2026 Outlook The reconciliation from forecasted "Net Income (Loss)" to Adjusted EBITDA and Adjusted Free Cash Flow for the year ended December 31: Notes a) Excludes income taxes paid from the NDT. Note: Figures include Cumulus and are rounded to the nearest $5mm.