EX-99.2 3 d937235dex992.htm EX-99.2

Talen Energy June 2015 Investor Presentation Creating Value from Day 1 We Generate Energy for a Brighter Tomorrow Exhibit 99.2

© Talen Energy Corporation 2015 2 Safe Harbor Forward Looking Statements: Any statements made in this presentation about future operating results or other future events are forward-looking statements under the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from such forward-looking statements. A discussion of factors that could cause actual results or events to vary is contained in the Supplemental Information to this presentation and in the Company’s SEC filings, including the factors discussed under “Risk Factors” in the Company’s Registration Statement on Form S-1.

© Talen Energy Corporation 2015 3 Agenda Introduction to Talen Energy Commercial & Operational Overview Financial Overview Key Investment Considerations Q&A P. Farr P. Farr J. McGuire P. Farr

© Talen Energy Corporation 2015 4 Introduction to Talen Energy

© Talen Energy Corporation 2015 5 Talen in 20 Great Assets Attractive Markets Strong Balance Sheet Execution Track Record Focused on Free Cash Flow Poised for Growth Significant

© Talen Energy Corporation 2015 6 Re-Introducing Talen Energy New independent power producer (“IPP”) formed by the contemporaneous spin-off of PPL Energy Supply (“Energy Supply”) and synergistic merger with RJS Power Holdings (“RJS”), a portfolio company of Riverstone Holdings that owned conventional competitive power generation assets Assets primarily located in two of the largest and most liquid, competitive electricity markets in the United States: PJM and ERCOT A highly diverse fleet with multiple ways to capture value including: - Flexible gas and highly efficient coal units - Significant carbon-free nuclear capacity - Portfolio optimizing dual-fuel capability Strong balance sheet with superior growth prospects Management team with extensive experience in competitive power generation, a demonstrated track record of strong operations, solid market calls and ahead-of-the-curve strategic execution Note: Does not reflect sale of approximately 1.3 GW of generating capacity that is required to comply with the FERC Order MT PA TX NJ MD 530 MW ownership in Colstrip facility 1,900 MW of flexible CCGT and CT natural gas generation in ERCOT Over 12,500 MW of PJM generation with a diverse fuel mix 89 MW Dartmouth facility MA Capacity by Market Capacity by Fuel Type Gas Dual Fuel Coal Nuclear Hydro Fuel Type Operating Capacity (MW) < 300 300 – 750 750 – 1,000 > 1,000 15,079 MW Oil Hydro/Renewables Natural Gas Dual Fuel Oil Coal Nuclear WECC/MT ISO-NE PJM ERCOT 83% 12% 1% 4% 22% 18% 3% 40% 15% 2%

© Talen Energy Corporation 2015 7 Merger with RJS creates a vibrant company with sufficient scale and asset diversity to be an attractive and competitive IPP Clear line-of-sight cost synergies and portfolio margin benefits Valuation multiple expansion Benefits derived from consolidation are an extremely powerful lever for value creation Rate regulated utilities and competitive generation in the same corporate structure does NOT optimize value Freedom to pursue strategies as a pure-play IPP with respect to: - Hedging and portfolio management - Capital allocation - Growth Creates Immediate Shareowner Value Provides Significant, Sustainable Long-Term Value Formation of Talen Energy Validates the Thesis Talen Energy Value Proposition Then Now Value Creation EPS / Decrease Volatility / Support Dividend Cash Flow / Consolidation / Synergy Capture Growth Negative: Sell downs to raise capital Significant: Talen Energy a result of consolidation Asset Diversity Fuel Only Fuel + Markets Liquidity & Hedging Longer-term / Excess Liquidity / Ratings Driven Shorter-term / Adequate Liquidity / Extrinsic Capture A Complete Transformation

© Talen Energy Corporation 2015 8 Talen Energy’s Strategy Safety is a core value Value is built on a foundation of excellence in operations Strong unit availability and performance during extreme load periods The balance sheet is a strategic asset Enhanced flexibility and capacity Absorb volatility and pursue growth opportunities Management incentives aligned with investors driven by EBITDA and free cash flow Cash generation fuels growth and investment opportunities Investment for growth subject to rigorous returns-based analysis Primary focus on delivering visibility 1-year forward Manage and monetize intra-year volatility Retail activities oriented to hedge the generation fleet in related markets Safety & Excellent Plant Operations Strategic Balance Sheet Management Strong Cash Returns Active Hedging & Portfolio Management Growth Focus Growth in value, not size alone Right assets in the right markets Not restricted by markets or fuel types

© Talen Energy Corporation 2015 9 ERCOT – 75 GW Focus on Growth in Key, Competitive Markets (1) Key Growth Initiatives & Opportunities Talen Energy’s Growth Prospects Robust Competitive Power Asset Market Focused on liquid, developed competitive markets Operating assets have a priority over development opportunities – Immediate cash flow and EBITDA contribution – Synergies fit with existing portfolio value capture and risk mitigation Recent history reflects a very robust market for competitive generation assets Approximately 300 GW (1) of market-based generation capacity in key markets; provides significant opportunity for growth Select development sites and repowering opportunities within Talen Energy portfolio currently being evaluated Source: SNL (1) Excludes generation capacity from principal competitive generators (CPN, DYN, NRG, TLN and EXC) About 350 GW sold over past 5 years PJM – 130 GW NYISO – 60 GW ISO-NE – 25 GW Substantial acquisition opportunity in key markets 75 48 65 65 91 2010 2011 2012 2013 2014

© Talen Energy Corporation 2015 10 Talen Energy Measures of Success Goals based on these metrics form the backbone of management incentive compensation Operations Focus Execution Key Metrics Result Growth Sustainable share price appreciation driven by improvements in EBITDA and Free Cash Flow Safety O&M and Capex efficiency Availability Beyond plan synergies Asset commercialization Disciplined strategic acquisitions Select “in inventory” development and repowering opportunities Employee lost time, OSHA recordables, Total Case Incidence Rate (TCIR) $/MW & $/MWh: G&A, O&M, Totex Commercial Availability IRR Synergies Cash flow accretion Portfolio effects Credit impacts

© Talen Energy Corporation 2015 11 Seasoned leaders with the right experience to successfully execute Talen Energy’s strategy Extensive Operational Experience Management team has extensive experience in fossil and nuclear power generation, commercial operations, strategy, corporate finance and governance Senior leadership team averages nearly 30 years of experience in the power sector Extensive public company experience Strong Board comprised of individuals with competitive, sector and technology-specific experience Strong History of Strategic Execution PPL’s cash acquisition of E.ON U.S. LLC, parent company of Louisville Gas & Electric Company and Kentucky Utilities Company, for $7.6 billion in 2010 PPL’s acquisition of Central Networks from E.ON UK plc for $5.8 billion in cash and assumption of $800 million of existing public debt in 2011 PPL’s acquisition of 660 MW Ironwood CCGT for a cash purchase price of $85 million and $217 million of net project debt in 2012 PPL’s sale of hydroelectric facilities in Montana to NorthWestern Energy Corporation for $900 million in cash in 2014 Management Bios Paul Farr President, Chief Executive Officer and Director • Previously the President of PPL Energy Supply • Served as Executive Vice President and CFO of PPL for seven years • Five years leading PPL’s International Operations and Strategy function Jeremy McGuire Senior Vice President and Chief Financial Officer • Previously the Vice President of PPL Strategic Development • Served as a Director in the Global Power & Utilities Group at Lehman • 20 years of financial advisory and strategic and capital markets execution experience Russ Clelland Vice President and Treasurer • Previously the Assistant Treasurer and VP at PPL • Has more than 35 years of experience in corporate finance Joe Hopf Senior Vice President and Chief Commercial Officer • Previously Senior VP - Fossil and Hydro Generation at PPL • Has more than 30 years experience in the electricity generation and marketing business, as well as expertise in risk management and credit Tim Rausch Senior Vice President and Chief Nuclear Officer • Previously Senior VP - Chief Nuclear Officer at PPL • Has 25 years of experience in virtually every discipline of the nuclear power industry Experienced Management Team

© Talen Energy Corporation 2015 12 Commercial & Operational Overview

© Talen Energy Corporation 2015 13 Source: Monitoring Analytics, LLC’s 2014 State of the Market Report for PJM PJM Highlights 2014 PJM Fuel Mix (1) Strong capacity market, plant retirements and market reforms support long-term fundamentals Supportive market fundamentals due to limited import capacity, significant capacity retirements, improving demand outlook, and a forward capacity market providing cash flow certainty to generation asset owners Projected Decrease in Reserve Margins Reserve margin decline driven by retirements of less- efficient coal generators facing rising environmental costs and challenged dark spreads Source: PJM’s February 2, 2015 Forecasted Reserve Margin Graph Capacity by Fuel Type Generation by Fuel Type (1) Installed capacity as of December 31, 2014 and generation breakdown from January 1 to December 31, 2014 Exposure to Key Markets – PJM PJM Spark Spreads 16 22 24 26 5/1/14 6/1/14 7/1/14 8/1/14 9/1/14 10/1/14 11/1/14 12/1/14 1/1/15 2/1/15 3/1/15 4/1/15 18 20 PJM West Hub On-Peak vs Henry Hub - 2016 PJM West Hub On-Peak vs Henry Hub - 2017 PJM West Hub On-Peak vs TETCO M-3 - 2016 PJM West Hub On-Peak vs TETCO M-3 - 2017 21.4% 20.2% 19.1% 19.1% 17.9% 2015E 2016E 2017E 2018E 2019E Renewables 5% Oil 6% Nuclear 18% Natural Gas 31% Coal 40% Other <1% Renewables 4% Oil <1% Nuclear 34% Natural Gas 17% Coal 44% Other 1% PJM capacity performance product supports potential capacity price increase, benefiting reliable generation units Increasing spark spreads due to lower gas prices

© Talen Energy Corporation 2015 14 (1) Excludes EFORd for 354 MW of combustion turbines; EFORd: Equivalent Forced Outage Rate demand (2) Includes Ironwood and Lower Mount Bethel (3) Excludes statistics for 354 MW of combustion turbines Diverse PJM Dispatch Capabilities Talen Energy’s PJM Fuel Mix PJM Fleet Highlights Talen Energy’s assets are diverse in fuel and dispatch, providing operational flexibility and reliable generation to PJM under a variety of market conditions Assets earn strong capacity revenues that provide margin support and predictability Assets positioned across various regions and serve as natural hedges to basis risk from congestion constraints Expansion and development capabilities provide opportunities to enhance the portfolio 2011 – 2014 EFORd (1) The Right Assets in Key Markets – PJM Capacity by Fuel Type Generation by Fuel Type Strong unit availability an important factor in Capacity Performance auction outcomes 12,553 MW Well situated to serve retail and default supply load 0% 5% 10% 15% 20% 25% 2011 2012 2013 2014 Average Coal Nuclear Natural Gas CCGT Natural Gas/ Oil (2) (3) Natural Gas 11% Dual Fuel 22% Oil 3% Coal 44% Hydro 2% Nuclear 18% Natural Gas 18% Dual Fuel 7% Coal 42% Hydro 2% Nuclear 31% Note: Does not reflect sale of approximately 1,300 MW of generating capacity that is required to comply with the FERC Order or immaterial renewable capacity

© Talen Energy Corporation 2015 15 Historical Capacity Prices PJM Capacity Performance (“CP”) Product Proposal to add enhanced product to the capacity market structure to provide additional compensation for generators to make necessary investments to maintain system reliability in exchange for stronger performance requirements If approved by FERC, Capacity Performance is expected to benefit generators like Talen Energy that have demonstrated reliability during peak load and extreme weather conditions Project 95% of fleet to be eligible to be bid in as “CP” under proposed rules Fleet is substantially leveraged to PJM capacity prices – a $10/MW Day increase = a projected ~$45 million increase in potential capacity revenues Talen Energy Capacity Revenues Leverage to PJM Capacity Prices ($ in millions) $0 $25 $50 $75 $100 $125 $150 $175 $200 2014/2015 2015/2016 2016/2017 2017/2018 PJM MAAC & SWMAAC PJM RTO $733 $655 $618 $540 2014 2015E 2016E 2017E

© Talen Energy Corporation 2015 16 Above-average historical demand growth, increasing price caps and an increasing reliance on flexible and quickly-dispatchable natural gas-fired assets ERCOT’s supply stack can provide significant margin opportunities driven by unforeseen weather anomalies coupled with variability, resulting in periods of extremely high power prices known as “scarcity pricing” - Electricity prices are subject to a system-wide offer cap of $9,000/MWh The Texas population and gross state product (“GSP”) are growing well above the national rate ERCOT System-Wide Offer Cap ($/MWh) 2014 ERCOT Fuel Mix Tracking double the national average Texas GSP / U.S. GDP Growth Rate Sources: ERCOT, Bureau of Economic Analysis, Texas Office of Comptroller and Federal Open Market Committee ERCOT Highlights Capacity by Fuel Type Generation by Fuel Type Exposure to Key Markets – ERCOT 0.7% (0.5%) 3.0% 4.2% 6.9% 3.7% 3.8% 2.6% 3.8% 3.7% (0.6%) (2.7%) 2.2% 1.6% 2.5% 1.8% 2.4% 2.5% 2.5% 2.2% (4.0%) (2.0%) 0.0% 2.0% 4.0% 6.0% 8.0% 2008 2009 2010 2011 2012 2013 2014(E) 2015E 2016E 2017E Texas GSP U.S. GDP $1,500 $2,250 $3,000 $3,000 $3,000 $4,500 $5,000 $7,000 $9,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 Coal 16% Natural Gas 60% Nuclear 2% Renewables 21% Other 1% Wind 14% Nuclear 6% Coal 24% Natural Gas 55% Other 1% Positive outlook due to strong demand growth and increased price caps

Highly reliable, flexible natural gas fleet designed to ramp up quickly to support grid stability - Majority of units ramp up at 20 MW per minute Opportunities to take advantage of higher scarcity pricing in ERCOT due to weather variability, unplanned transmission and generation outages, and potential coal generation retirements resulting from upcoming EPA regulations - Potential scarcity pricing benefits: a one hour period at the $9,000/MWh cap equates to about $20 million in revenue Quick-Dispatch Assets Positioned for Scarcity Supportive Ancillary Revenues ERCOT Fleet Highlights Declining Reserve Margins The Right Assets in Key Markets – ERCOT (1) Assumes all owned ERCOT generation is running and unhedged when prices hit system-wide offer cap (1) Source: SNL Source: 5/4/15 ERCOT CDR Report 13.75% Target Reserve Margin 0 100 200 300 400 500 600 0 20,000 40,000 60,000 80,000 100,000 Coal Natural Gas Other Fuel Oil Renewable Nuclear Talen 76% 83% 79% 24% 17% 21% 2012 2013 2014 Energy Revenue Ancillary Revenue 17 © Talen Energy Corporation 2015 17.0% 18.5% 21.4% 18.7% 17.1% 16.1% 14.6% 13.2% 11.8% 10.4% 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Cumulative Summer Capacity (MW)

© Talen Energy Corporation 2015 18 Hedging & Commercial Management Strategy Note: As of March 31, 2015 Hedging & Commercial Strategy Coal and Nuclear Fuel Hedge Levels Portfolio Generation Hedge Position Average Hedge Prices Portfolio Targets Focused on providing margin and cash flow visibility on a one year forward basis Lower level of financial leverage and strong liquidity allow for greater resilience to operating cash flow volatility enabling a shorter-term hedging program Substantially reduces program costs Execute strategies in both wholesale and retail markets Utilize FTRs and basis swaps to reduce the risk of price differentials between plants and hubs 75% 25% 2015 2016 East: Power: Nuclear/Coal/Hydro ($/MWh) $41-43 $44-46 Spark Spread ($/MWh) $10-11 $8-9 Consumed Coal (Delivered $/ton) $73-75 $72-74 West: Power: Coal ($/MWh) $40-42 $39-41 Spark Spread ($/MWh) $14-15 - Consumed Coal (Delivered $/ton) $27-31 $27-33 100% 25% 74% 48% 93% 49% 37% 0% 90% 29% 2015 2016 East Nuclear, Coal & Hydro East Gas/Oil West Coal West Gas/Oil Total Portfolio 100% 100% 97% 81% 100% 100% 2015 2016 Nuclear East Coal West Coal © Talen Energy Corporation 2015 18

© Talen Energy Corporation 2015 19 Turbine Blade Design Issues Resolved Historical Equivalent Availability (“EQA”) Historical Station Output Lower EQA primarily driven by turbine blade cracking Turbine blade related outage Set operational records in back-to-back years prior to turbine blade cracking Strong track-record of safety and performance May 2011: First identified cracked blades on both units; first instance for Siemens 2011 – 2014: 10 blade-related outages; first one lasted 38 days, more recent outages were as little as 12 days Installation of monitoring gear allowed operations to proceed within OEM specifications 2014: Installed new shorter last stage blade design on one turbine Seeing significantly reduced blade tip vibration No evidence of root cracking Plant efficiency unaffected 2015: Completed Root Cause Analysis confirming equipment deficiencies and installed short blades on two Unit 2 turbines during scheduled refueling outage 2016: Will install short blades on two additional Unit 1 turbines and perform validation inspections on short blades installed in 2014 as part of the scheduled Unit 1 refueling outage Expect validation inspections to confirm short blade solution efficacy 2017: Will install short blades on final Unit 2 turbine Project ~89% EQA for 2015 – highest in 6 years No special turbine-related maintenance outages are projected 2015 or thereafter © Talen Energy Corporation 2015 19 16.0 16.4 17.1 17.5 16.7 15.6 15.2 17.0 16.9 18.2 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 E Susquehanna Nuclear Operations

© Talen Energy Corporation 2015 20 Financial Overview

© Talen Energy Corporation 2015 21 Expected Synergies On track to deliver at least $155 million on an annual basis by 2017 as originally forecasted Synergy attainment through multiple channels: - Overhead reductions - Asset focused commercial strategy - Streamlined operational workforce - Supply chain savings through greater discounts and enhanced inventory management - Margin enhancement through improved fuel sourcing and commercial management - Fleet-wide economies of scale Infrastructure in place to add MWs in a cost-effective manner Synergies Projected Synergies ($ in millions) Breakdown of Projected Synergies $155 million $115 $140 $155 2015 2016 2017 Operations 42% Overhead 46% Margin 12%

© Talen Energy Corporation 2015 22 Transition Support Costs ($ in millions) Estimated TSA Costs by Category Projected Range for TSA Cost Category % of Total Cost Information Technology 84% Business Support (2) 16% Transition Service Agreements (TSAs) TSAs are temporary agreements put in place to help facilitate Talen Energy’s transition to its new operating model Transition services are contractually available for up to two years - Talen Energy expects to end TSAs by early 2017 The largest portions of service costs support the development of reliable information technology systems and infrastructure (1) TSA costs to begin June 1, 2015 (2) Business Support includes Financial, Legal, Human Resources, Facilities, and Commercial Services (1) $30 $40 $10 $40 $50 $20 2015 2016 2017

© Talen Energy Corporation 2015 23 Notes: Does not reflect sale of approximately 1.3 GW of generating capacity that is required to comply with the FERC Order 2015 Adjusted EBITDA Expected transitional or restructuring costs that will not be experienced on a “run-rate basis” (2) (3) (1) ($ millions) Estimate provided at 6/9/2014 transaction announcement $1,067 $1,010 $910 $25 ($37) ($5) ($40) ($40) ($35) ($25) $500 $600 $700 $800 $900 $1,000 $1,100 2015 Model Year EBITDA Margins O&M & Other Net ARO Expense Partial Synergies 2015 Adjusted EBITDA Pre-spin PPL Charges TSA Restructuring Cost 2015 Adjusted EBITDA, including special items (Midpoint) (1) Additional item identified as an adjustment to EBITDA, but was not adjusted in the original $1,067 million model year EBITDA estimate. Net ARO expense means ARO expense net of NDT income (2) Synergies below full run-rate projection of $155 million per year (3) Reflects 3 months of Energy Supply actuals Refer to “Supplemental Information – Regulation G Reconciliations” for reconciliation of non-GAAP financial measures

© Talen Energy Corporation 2015 24 2015 Guidance ($ in Millions) Low Mid High EBITDA: Adjusted EBITDA $935 $1,010 $1,085 Adjusted EBITDA, including special items $835 $910 $985 Free Cash Flow: Adjusted Free Cash Flow $265 $340 $415 Adjusted Free Cash Flow, including special items $205 $280 $355 Projected Net Debt Outstanding at 12/31/2015 $3,700 Projected Net Debt / Adjusted EBITDA 3.7x (1)(2) (2) (3) (1) (1) Special items include pre-spin PPL charges, TSA costs and restructuring costs (2) Does not include growth capex of $48 million (3) Includes projection of $170 million in short-term debt outstanding Notes: Does not reflect sale of approximately 1.3 GW of generating capacity that is required to comply with the FERC Order Refer to “Supplemental Information – Regulation G Reconciliations” for reconciliation of non-GAAP financial measures

© Talen Energy Corporation 2015 25 2016 Adjusted EBITDA ($ millions) $1,010 $885 $840 $25 ($130) ($20) ($45) $500 $600 $700 $800 $900 $1,000 $1,100 2015 Adjusted EBITDA Margins O&M & Other Partial Synergies 2016 Adjusted EBITDA TSA 2016 Adjusted EBITDA, including special items (Midpoint) Notes: Does not reflect sale of approximately 1.3 GW of generating capacity that is required to comply with the FERC Order Refer to “Supplemental Information – Regulation G Reconciliations” for reconciliation of non-GAAP financial measures (1) (1) Reflects year-over-year increase in expected synergies to $140 million in 2016 from $115 million in 2015

2015 Gas +/- $0.50/mmBtu Heat Rate +/- 1.0 mmBtu Power +/- $5/MWh ERCOT 1 hour @ Offer Cap 2016 PJM Capacity + $10/MW-Day Margin Sensitivities ($ millions) Gas +/- $0.50/mmBtu Heat Rate +/- 1.0 mmBtu Power +/- $5/MWh ERCOT 1 hour @ Offer Cap Notes: Does not reflect sale of approximately 1.3 GW of generating capacity that is required to comply with the FERC Order Gas price sensitivity assumes system heat rate is unchanged. Heat Rate sensitivity assumes power price moves and gas price is unchanged. Power price sensitivity assumes gas price is unchanged. © Talen Energy Corporation 2015 26 $52 $37 $50 $18 $318 $208 $275 $18 $26 ($16) ($26) ($35) ($240) ($153) ($200) ($300) ($200) ($100) $0 $100 $200 $300 $400

© Talen Energy Corporation 2015 27 Fully committed $1,850 million 5-year senior secured revolving credit facility $800 million secured trading facility, cash, and bilateral agreements bring total liquidity sources to $3.0 billion Bilateral credit facilities are expected to be effective in 2 nd /3 rd quarter 2015 Significant Liquidity Resources ($ in millions) Liquidity Summary Liquidity and Financing Forecasted Long-Term Debt Maturities Financing Highlights Issued $600 million of 6.5% senior unsecured notes in May 2015 Assumed $1,250 million of RJS senior unsecured notes in connection with the transaction. The covenants are now comparable to Energy Supply’s senior unsecured notes covenants. Interest rate will step down from 5.125% to 4.625% following next interest payment in July 2015. Plan to remarket $231 million of tax-exempt securities in 3 rd quarter 2015 $3,050 $1,850 $800 $200 $200 Syndicated Secured Credit Facility Secured Trading Facility Bilateral Credit Facilities Cash on Hand $533 $354 $4 $403 $1,254 $1,538 2015 2016 2017 2018 2019 Thereafter

© Talen Energy Corporation 2015 28 Leverage Lane Capital decisions will be made on a cash returns basis Capital Priorities $2.4B of Projected Capital Spending Capital Allocation Modest Environmental Spending Growth through strategic acquisitions – Accretive and supportive of long-term value proposition – Focus on synergy opportunities and portfolio diversification Growth through higher return asset development or expansion – Brunner Island co-firing project “Leverage Lane” of 3x – 5x Net Debt/EBITDA – 3x – bias towards growth investment/capital return – 5x – bias towards debt retirement Fleet substantially compliant with current regulations and future environmental compliance-driven capital expenditures projected at a modest $160 million from 2015 through 2019 Represents less than 10% of total capital expenditures for the same period Talen Energy is actively engaged with policy makers at the state and federal levels to promote regulatory flexibility and develop least-cost implementation scenarios, including regional programs Utilize balance sheet for accretive growth opportunities, asset optimization projects and return of capital Rebalance capital structure through debt retirements 3.0 x 5.0 x $516 $543 $466 $495 $395 2015 2016 2017 2018 2019 Sustenance Nuclear Fuel Environmental / Regulatory Discretionary / I.T. Growth

© Talen Energy Corporation 2015 Key Investment Considerations 29

© Talen Energy Corporation 2015 30 Key Investment Considerations Attractive fleet composition High degree of strategic optionality across fuels, dispatch and markets Hedging strategy and balance sheet construction harmonized to extract maximum value and positioned for growth opportunities Experienced management team with demonstrated track record of delivering value through asset management and strong execution on strategic initiatives Management incentives tied directly to investors’ objectives: EBITDA and Free Cash Flow

© Talen Energy Corporation 2015 31 Supplemental Information

© Talen Energy Corporation 2015 32 Asset Location Fuel Type Ownership Net Heat Rate (Btu / kWh) Owned Capacity COD Region East Assets Brandon Shores (2) MD Coal 100% 10,252 1,273 1984 - 1991 PJM-SWMAAC Brunner Island PA Coal 100% 9,842 1,411 1961 - 1969 PJM-MAAC C.P. Crane (2) MD Coal 100% 10,616 399 1961 - 1967 PJM-SWMAAC Conemaugh PA Coal 16% 9,700 278 1970 - 1971 PJM-RTO Keystone PA Coal 12% 9,600 211 1967 - 1968 PJM-RTO Montour PA Coal 100% 9,661 1,504 1972 - 1973 PJM-MAAC H.A. Wagner (2) MD Coal/NG/Oil 100% 10,663 976 1956 - 1972 PJM-SWMAAC Eastern Hydro (3) PA Hydro 100% N/A 293 1910 - 1926 PJM-MAAC Ironwood PA Natural Gas 100% 7,127 660 2001 PJM-MAAC Lower Mt. Bethel PA Natural Gas 100% 7,170 538 2004 PJM-MAAC York (2) PA Natural Gas 100% 9,551 52 1989 PJM-MAAC Bayonne (2) NJ Natural Gas/Oil 100% 8,857 174 1988 PJM-PS North Camden (2) NJ Natural Gas/Oil 100% 8,675 151 1993 PJM-PSEG Dartmouth (2) MA Natural Gas/Oil 100% 8,715 (CCGT) / 11,326 (Peaker) 89 1996 ISO-NE Elmwood Park (2) NJ Natural Gas/Oil 100% 9,500 73 1989 PJM-PS North Martins Creek 3&4 PA Natural Gas/Oil 100% 11,744 (Gas) / 10,676 (Oil) 1,700 1975 - 1977 PJM-MAAC Newark Bay (2) NJ Natural Gas/Oil 100% 8,680 129 1993 PJM-PS North Peakers PA Natural Gas/Oil 100% Various 354 1967 - 1973 PJM Pedricktown (2) NJ Natural Gas/Oil 100% 8,455 132 1992 PJM-EMAAC Susquehanna PA Nuclear 90% N/A 2,245 1983 - 1985 PJM-MAAC Renewables (1) NH, NJ, PA, VT Renewables 100% Various 25 Various Various Subtotal 12,667 West Assets Colstrip 1 & 2 MT Coal 50% 10,941 307 1975, 1976 WECC Colstrip 3 MT Coal 30% 10,660 222 1984 WECC Barney Davis 1 (2) TX Natural Gas 100% 10,100 335 1974 ERCOT-South Barney Davis 2 (2) TX Natural Gas 100% 7,100 674 2010 ERCOT-South Laredo 4 (2) TX Natural Gas 100% 8,900 98 2008 ERCOT-South Laredo 5 (2) TX Natural Gas 100% 8,900 98 2008 ERCOT-South Nueces Bay 7 (2) TX Natural Gas 100% 7,100 678 2010 ERCOT-South Subtotal 2,412 Total Talen Energy 15,079 Talen Energy Asset Overview Note: Does not reflect sale of approximately 1.3 GW of generating capacity that is required to comply with the FERC Order (1)Talen Energy is presently considering divesting its renewables plants (2)Total net generating capacities are based on average summer and winter capacity (3)Includes Holtwood and Wallenpaupack

© Talen Energy Corporation 2015 33 Group 1 Mitigation Overview PPL and RJS recognized possible FERC horizontal market power concerns in PJM submarket 5004/5005 in their FERC application for approval on July 15, 2014 and proposed two divestiture options Each divestiture option requires divestiture of one of two proposed groups of approximately 1,300 MW of generating capacity (based on summer ratings), with some overlapping assets On December 19, 2014, FERC conditionally approved the transaction pending additional mitigation measures - Option 1: Divest all assets from one group while limiting assets retained from other group to cost-based rates - Option 2: Divest all 2,000 MW of capacity from both groups - Option 3: Propose an alternative mitigation plan PPL and RJS accepted Option 1 and told FERC they would divest all assets from one group and bid the retained assets at cost-based rates in the energy market Decisions on which group of assets will be divested have not been made Group 2 (1) Total net generating capacities are based on average summer and winter capacity (2) Pedricktown capacity includes capacity dedicated to serving landlord load (which has historically averaged 9 MW) Facility MW Bayonne 0 174 Camden 0 151 Elmwood Park 00 73 Newark Bay 0 129 Pedricktown 0 132 York 00 52 Ironwood 0 660 Total 1,371 Facility MW Bayonne 0 174 Camden 0 151 Elmwood Park 00 73 Newark Bay 0 129 Pedricktown 0 132 York 00 52 C.P. Crane 0 399 Holtwood 0 249 Wallenpaupack 00 44 Total 1,403 FERC Required Mitigation (1) (2) (2) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1)

© Talen Energy Corporation 2015 34 Net Generation (GWh) EAF Capacity Factor EFORd 2013 2014 2013 2014 2013 2014 2013 2014 East Coal 24,191 22,580 80.6% 82.7% 48.3% 45.4% 5.9% 3.1% Hydro 662 931 85.3% 88.5% 40.5% 36.3% 3.1% 1.8% Nuclear 17,009 16,903 84.7% 84.1% 85.6% 85.6% 0.4% 0.3% Natural Gas CCGT 8,794 9,411 82.0% 88.7% 83.9% 89.4% 4.0% 3.5% Natural Gas/ Oil 2,283 3,822 91.8% 84.5% 11.8% 17.2% 6.4% 10.2% Net Generation (GWh) EAF Capacity Factor EFORd 2013 2014 2013 2014 2013 2014 2013 2014 West Coal 3,502 3,449 81.0% 86.4% 76.0% 74.4% 15.6% 6.9% Natural Gas 4,678 3,451 88.0% 84.0% 28.4% 21.1% 6.6% 7.8% Operational Statistics (1) Includes Ironwood and Lower Mount Bethel (2) Excludes statistics for 354 MW of combustion turbines (2) (1)

© Talen Energy Corporation 2015 35 Asset Unit Low NOx Burners (Nox) SCR/SNCR (Nox) Scrubbers (SO ) Chemical Additive (Mercury) ESP/ Baghouse (PM) Dry Injection (Acid Gases) Closed-Cycle Cooling Tower Water Intake, 316(b) Dry Handling/ Disposal/ Beneficial Use (CCRs) Waste Water Treatment (Mainly Metals) Brunner Island Unit 1 NR (1) (3) (6) Unit 2 NR (1) (3) (6) Unit 3 NR (1) (3) (6) Montour Unit 1 NR (3) (6) Unit 2 NR (3) (6) Colstrip Units 1 & 2 (2) (2) (2) (2) NR (3) NR (5) Units 3 & 4 NR NR (3) NR (5) Keystone Units 1 & 2 (6) Conemaugh Units 1 & 2 (6) Brandon Shores Units 1 (6) Units 2 (6) Wagner Unit 2 (7) (7) (4) (4) (1) (6) Unit 3 (4) (4) (1) (6) Crane Unit 1 (7) (7) (4) (4) (1) (6) Unit 2 (7) (7) (4) (4) (1) (6) NR = Not Required by Applicable Current or Proposed Regulations = Installed = Under Consideration/Construction Environmental Controls (1) 316(b) regulations finalized in 2014 will likely require intake structure modifications for some sites, particularly those with once-through cooling water systems. If needed, Brunner Island, Crane and Wagner will install necessary equipment or make operational changes to comply (2) New and pending NOx, SO2, and PM requirements will be met through boiler and scrubber modifications; Talen Energy is appealing EPA's final Regional Haze FIP for Montana (3) CCR regulations finalized in 2015 will likely require modifications to existing operations or new controls at plants which utilize CCR disposal impoundments. Operation of the recently installed Wastewater Treatment Plant at Brunner Island (which would replace the only remaining active disposal impoundment) will commence following renewal of NPDES permit (4) Wagner Unit 3 will install a new DSI system, Wagner Unit 2 will burn a low chlorine coal (Adaro from Indonesia or Colorado) and they will average emissions with Brandon Shores for MATS compliance. Crane burns low-sulfur PRB (sub-bituminous) coal and DSI systems will also be installed at Crane for MATS compliance. Crane and Wagner could also use ultra-low sulfur Adaro coal to comply with MATS, or if needed, to meet future ambient SO2 standards (5) Colstrip is a Zero-Liquid Discharge operation and therefore does not have discharge permit (6) Pending ELG revisions and NPDES permit renewals could require additional waste water treatment (7) Crane is a cyclone boiler and is equipped with over-fired air with SNCR for NOx control. MDE is developing new NOx requirements for MD coal plants which could require additional controls or operational changes in 2020. Wagner Unit 2, which has low NOx burners with SNCR for NOx control, could also be required to install additional controls or make operational changes in 2020 as a result of MDE’s pending rule 2

© Talen Energy Corporation 2015 36 Projected Capital Expenditures $107 $85 $120 $126 $129 $1 $1 $1 $29 $24 $23 $12 $2 $6 $20 $7 $6 $6 $516 $543 $466 $495 $395 2015 2016 2017 2018 2019 Sustenance Nuclear Fuel Growth Information Technology Environmental Regulatory Discretionary $228 $42 $50 $48 $254 $28 $41 $85 $252 $39 $21 $307 $20 $15 $214 $32 $11

© Talen Energy Corporation 2015 37 Long-term Debt Outstanding (1) Required to be put by existing holders on October 15, 2015 for either (a) purchase and remarketing by a designated dealer or (b) repurchase by Energy Supply (2) As a result of meeting the “merger ratings event”, effective with the interest period beginning July 15, 2015, the Senior Notes coupon will step down to 4.625% (3) Fair Market Value = $689 million (4) Put date September 2015 (5) Amortizing Security; Fair Market Value = $47 million Debt Coupon Maturity Date Balance as of 5/31/2015 Senior Notes 5.700% Oct 2035 (1) $300 Senior Notes 6.200 May 2016 350 Senior Notes 6.500 May 2018 400 Senior Notes 5.125 Jul 2019 (2) 1,250 Senior Notes 4.600 Dec 2021 (3) 712 Senior Notes 6.000 Dec 2036 200 Senior Notes 6.500 May 2025 600 Muni Bonds Various Dec 2038 (4) 100 Muni Bonds Various Dec 2038 (4) 50 Muni Bonds Various Dec 2037 (4) 81 Secured Notes 8.857 Nov 2025 (5) 44 Total as of 5/31/2015 $4,086

© Talen Energy Corporation 2015 38 Regulation G Reconciliations Adjusted EBITDA ($ in Millions) 6/9/2014 (1) – 2015E (2) Low – 2015E (2) Midpoint - 2015E (2) High - 2015E (2) Midpoint – 2016E Net Income/(Loss) $214 $55 $100 $145 $105 Income Taxes 143 23 53 83 56 Interest Expense 244 327 327 327 209 Depreciation & Amortization 439 410 410 410 422 EBITDA 1,040 815 890 965 792 Non-Cash Compensation 27 23 23 23 21 ARO (3) 35 35 35 37 MTM losses (gains) (28) (28) (28) NDT losses (gains) (10) (10) (10) (10) Adjusted EBITDA, including special items 1,067 835 910 985 840 Special items: TSA costs and allocations (4) 75 75 75 45 Other (5) 25 25 25 Adjusted EBITDA $1,067 $935 $1,010 $1,085 $885 (1) Estimate provided at 6/9/2014, the date of the transaction announcement. (2) RJS Power will be consolidated into Talen Energy’s financials as of June 1, 2015. Forecasted amounts include twelve months of performance from RJS Power, including the five-month period prior to acquisition with respect to 2015 estimates. Low, midpoint and high forecast 2015 reflects three months of Energy Supply actuals. Adjusted EBITDA from RJS Power for the five-month period prior to acquisition is estimated at $41 million. (3) Additional item identified as an adjustment to EBITDA that was not included in the original $1,067 model year Adjusted EBITDA estimate. (4) Low, midpoint, and high 2015 amounts include $40 million of allocations from PPL and $35 million of TSA costs that are not expected to continue in future periods. (5) Restructuring costs that are not expected to continue in future periods.

© Talen Energy Corporation 2015 39 Regulation G Reconciliations Adjusted Free Cash Flow ($ in Millions) Low - 2015E Midpoint – 2015E High – 2015E Cash from Operations (1) $752 $797 $842 Sustenance Capital Expenditures (547) (517) (487) Adjusted Free Cash Flow, including special items 205 280 355 Special items: TSA costs & allocations (after tax) (2) 45 45 45 Other (after tax) (3) 15 15 15 Adjusted Free Cash Flow $265 $340 $415 (1) RJS Power will be consolidated into Talen Energy’s financials as of June 1, 2015. Forecasted amounts include twelve months of performance from RJS Power, including the five- month period prior to acquisition with respect to 2015 estimates. Reflects three months of Energy Supply actuals. Adjusted Free Cash Flow from RJS Power for the five-month period prior to acquisition is estimated at $14 million. (2) Includes $24 million of allocations from PPL and $21 million of TSA costs that are not expected to continue in future periods. (3) Restructuring costs that are not expected to continue in future periods.

© Talen Energy Corporation 2015 40 Forward-Looking Information Statement Statements contained in this presentation, including statements with respect to future earnings, EBITDA results, cash flows, financing, regulation and corporate strategy are "forward-looking statements" within the meaning of the federal securities laws. Although Talen Energy Corporation believes that the expectations and assumptions reflected in these forward-looking statements are reasonable, these statements are subject to a number of risks and uncertainties, and actual results may differ materially from the results discussed in the statements. The following are among the important factors that could cause actual results to differ materially from the forward-looking statements: market demand and prices for energy, capacity and fuel; weather conditions affecting customer energy usage and operating costs; competition in power markets; the effect of any business or industry restructuring; the profitability and liquidity of Talen Energy Corporation and its subsidiaries; new accounting requirements or new interpretations or applications of existing requirements; operating performance of generating plants and other facilities; the length of scheduled and unscheduled outages at our generating plants; environmental conditions and requirements and the related costs of compliance, including environmental capital expenditures and emission allowance and other expenses; system conditions and operating costs; development of new projects, markets and technologies; performance of new ventures; asset or business acquisitions and dispositions; any impact of hurricanes or other severe weather on our business, including any impact on fuel prices; receipt of necessary government permits or approvals; capital market conditions and decisions regarding capital structure; the impact of state, federal or foreign investigations applicable to Talen Energy Corporation and its subsidiaries; the outcome of litigation against Talen Energy Corporation and its subsidiaries; stock price performance; the market prices of equity securities and the impact on pension income and resultant cash funding requirements for defined benefit pension plans; the securities and credit ratings of Talen Energy Corporation and its subsidiaries; political, regulatory or economic conditions in states, regions or countries where Talen Energy Corporation or its subsidiaries conduct business, including any potential effects of threatened or actual terrorism or war or other hostilities; foreign exchange rates; new state, federal or foreign legislation, including new tax legislation; and the commitments and liabilities of Talen Energy Corporation and its subsidiaries. Any such forward-looking statements should be considered in light of such important factors and in conjunction with Talen Energy Corporation's Registration statement on Form S-1 and other reports on file with the Securities and Exchange Commission.

© Talen Energy Corporation 2015 41 In this presentation the company presents EBITDA, Adjusted EBITDA and Adjusted EBITDA, including special items, each of which are non-GAAP financial measures. EBITDA represents net income (loss) before interest expense, income taxes, depreciation and amortization. Adjusted EBITDA, represents EBITDA adjusted for certain items as detailed in the reconciliation. Adjusted EBITDA, including special items, is Adjusted EBITDA prior to adjustment for items management considers special including TSA costs, pre-spin PPL charges and restructuring costs. EBITDA, Adjusted EBITDA and Adjusted EBITDA, including special items, are not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as indicators of operating performance and are not necessarily comparable to similarly-titled measures reported by other companies. We believe EBITDA, Adjusted EBITDA and Adjusted EBITDA, including special items, are useful to investors and other users of our financial statements in evaluating our operating performance because they provide additional tools to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to such items as interest expense, income taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. We adjust for these and other items as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. In summary, our management uses EBITDA, Adjusted EBITDA and Adjusted EBITDA, including special items, as measures of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as measures for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance. Definitions of Non-GAAP Financial Measures

© Talen Energy Corporation 2015 42 Adjusted free cash flow is derived by deducting sustenance capital expenditures and after-tax special items from cash flow from operations, while adjusted free cash flow, including special items, is derived from adjusted free cash flow prior to adjustment for after-tax special items. These two non-GAAP measures should not be considered alternatives to cash flow from operations, which is determined in accordance with GAAP. We believe that adjusted free cash flow and adjusted free cash flow, including special items, although both non-GAAP measures, are important measures to both management and investors as indicators of the company’s ability to sustain operations and growth without additional outside financing beyond the requirement to fund maturing debt obligations. These measures are not necessarily comparable to similarly-titled measures reported by other companies as they may be calculated differently. Definitions of Non-GAAP Financial Measures