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Talen Energy

September 8, 2015

Barclays CEO Energy-Power Conference

We Generate Energy for a Brighter Tomorrow

© 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 prospectus filed with

the SEC pursuant to Rule 424(b)(3) on May 1, 2015 and the

Company’s Quarterly Report on Form 10-Q for the quarter ended

June 30, 2015.


72%10%

7%

2%

9%

35%

32%

16%

13%

2% 2%

Talen Energy Asset Overview

Assets primarily located in the largest and most

liquid, competitive electricity markets in the United

States: PJM, ERCOT, NYISO and ISO-NE

A highly diverse merchant generation fleet

designed to capture value under a variety of

market conditions including:

- Flexible gas plants located in regions with access

to low-price natural gas

- Highly efficient coal units positioned to capture

margins in moderate to peak load environments

and periods of higher gas prices

- Significant carbon-free nuclear and hydro

capacity

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

(1) Does not reflect sale of between 1,300 and 1,400 MW of generating capacity that is required to comply with the FERC order approving the combination with RJS Power.

Reflects pending acquisition of 2,500 MW MACH Gen portfolio and pending sale of Talen Renewable Energy, which are both expected to close by 12/31/2015

MT

PA

TX

NJ MD

MA

Gas Dual Fuel Coal Nuclear Hydro

Fuel Type

Operating Capacity (MW) < 300 300 – 750 750 – 1,000 > 1,000

Oil

NY

AZ

Capacity by Market Capacity by Fuel Type

17,471 MW

Hydro/Renewables

Natural Gas

Dual Fuel

Oil

Coal

Nuclear

WECC

ISO-NE

PJM ERCOT

NYISO

Talen Energy Highlights Geographic and Fuel Diverse Fleet (1) (1)


Key Priorities

(1) Project under review and dependent on development of certain natural gas pipelines

Execution on these fronts will deliver significant shareholder value

Catalyst

2018/19 PJM Capacity Auction Results

Announce Mitigation Divestitures

MACH Gen Closing/Begin Integration

Brunner Island Dual-Fuel Project

Keystone & Conemaugh Operational Improvements

Harquahala Optimization

Montour Dual-Fuel Project

Expected Timing

Q3 2015

Q4 2015

Q4 2015

Q4 2016 COD

2016-2017

2017

2018 (1)


8,380 MW 88%

664 MW 7%

483 MW5%

CP Gen Cleared Base Gen Cleared Base DR/EE Cleared

Breakout driven by limited base capacity requirement in

PPL Zone for Transitional Auctions and not expected occur

in auctions under 100% CP requirement

0%

5%

10%

15%

20%

25%

2011 2012 2013 2014 Average

Coal Nuclear Natural Gas CCGT Natural Gas/ Oil

55%

21%

19%

5%

PPL SW-MAAC MAAC E-MAAC

2018/19 PJM Capacity Auction

Talen Energy 2011 – 2014 PJM EFORd Breakout of PPL Zone in the Base Product

Strong unit availability an important factor to retain

Capacity Performance revenues

Note: Does not reflect sale of between 1,300 and 1,400 MW of generating capacity that is required to comply with the FERC order approving the combination with RJS Power. Reflects sale of Talen Energy Renewables which is

expected to close by 12/31/2015

(1) Weighed averages based upon summer capacity ratings. 2018/19 potential uplift based on 95% of Talen Energy PJM capacity being CP eligible

(2) EFORd – Equivalent Forced Outage Rate demand; excludes EFORd for 354 MW of combustion turbines

(3) Includes Ironwood and Lower Mount Bethel

(3)

(2)

Talen Energy Potential Capacity Price Uplift Breakdown of TLN PJM Capacity by Region

($ /MW-Day)

(1)

CP: $164.77

Base: $75.00

CP: $225.42

Base: $210.63

CP: $164.77

Base: $149.98

CP: $164.77

Base: $149.98

Only 7% of

generation

in PPL zone

cleared as

base

$124

$166

Weighted Avg. (2017/18) Weighted Avg. (2018/19)


MACH Gen: Achieving Strategic Objectives

Grow asset base in accretive manner 1

Extend track record of originating transactions 2

Expand presence in attractive markets 3

Further diversify fuel mix 4

Take advantage of cash taxpayer status 5

Strategic Priorities: MACH Gen:


$0

$100

$200

$300

+45% Gas,+25% Pwr

Base Case -45% Gas,-25% Pwr

Brunner Island Dual-Fuel Project

Very attractive capital allocation that supports plant upside & creates substantial value at low gas prices

Install natural gas firing capability on all 3

Brunner Island generating units

- Location near Marcellus/Utica provides significant

spark spread margin opportunity

Retain current 100% coal firing capabilities

- Boiler modifications will allow use of either coal

or gas, or combinations of the two

- Flexibility to seamlessly change fuel blend

during operation

- Enhances station’s risk/reward profile relative to

PJM’s Capacity Performance product

Key aspects of the project include:

- Construction of a 3 mile long pipeline from the

existing Texas Eastern Pipeline to the plant

- Modification of existing oil fired duct burners and

igniters to also burn natural gas

Total estimated cost of less than $110 million

- $6 million spent to date

Project completion projected by end of 2016

Project Overview, Scope and Cost Projected Economic Benefit

Project Milestones

Pipeline Permitting Complete

2017

Pipeline Construction

Complete

Target COD

2015

2016

Project NPV ($ in millions)


2015 2016

Capital Expenditures:

Maintenance $515 $490

Growth 50 85

Debt Maturities:

5.70% REPs due 10/2035 300

6.20% Senior Notes due 5/2016 350

MACH Gen Acquisition 625

Total $1,490 $925

3.0 x

5.0 x

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 dual-fuel project

“Leverage Lane” of 3x – 5x Net Debt/EBITDA - ≤ 3x – bias towards growth investment/capital return

- ≥ 5x – bias towards debt retirement

Capital Allocation

Utilize balance sheet

for accretive growth

opportunities, asset

optimization projects

and return of capital

Rebalance capital

structure through

debt retirements

Capital Priorities 2015-16 Projected Capital Requirements

Leverage Lane

(1) $300 million 5.70% REPS required to be put by existing holders on 10/15/2015 for

either (a) purchase and remarketing by a designated dealer or (b) repurchase by

Talen Energy Supply

(2) Expected to close by 12/31/2015

($ in millions)

(1)

(2)


2015 Guidance 2016E

Low Midpoint High Midpoint

Adjusted EBITDA $935 $1,010 $1,085 $990

Adjusted Free Cash Flow $265 $340 $415 $310

Projected Net Debt Outstanding at 12/31/2015 $3,700 $4,785

Projected Net Debt / Adjusted EBITDA 3.7x 4.8x

($ in millions)

2015 & 2016 EBITDA and FCF

Notes: Does not reflect sale of between 1,300 and 1,400 MW of generating capacity that is required to comply with the FERC order approving combination with RJS Power.

Refer to “Supplemental Information – Regulation G Reconciliations” for reconciliation of non-GAAP financial measures

(1) 2015 forecasted amounts include twelve months of performance from RJS Power, including the five-month period prior to the acquisition and an adjustment for PPL

allocations not expected to continue in future periods

(2) Assumes MACH Gen acquisition and sale of Talen Renewable Energy close by 12/31/2015

(3) Does not include growth capex of $48 million in 2015 and $84 million in 2016

(4) Includes $170 million in projected short-term debt outstanding

(1) (2)

(3)

(4)


($ in millions)

EBITDA Driver Low High Expected Realization

Reduce/Eliminate Harquahala Negative EBITDA $5 $10 2017

Expiration of Sapphire HRCOs (Dec-2016) $30 $30 2017

Expiration of Longview PPA (Dec-2016) $30 $30 2017

Brunner Island Dual-Fuel Project $20 $35 2017

Keystone/Conemaugh O&M Efficiency Gains $0 $10 2017

Reduced Coal Cost $5 $5 2017

Improved Synergies (Over $155 million base) $10 $20 2017 - 2018

Total EBITDA Drivers $100 $140

Implied Impact on Equity Valuation:

@ Talen Energy's current consensus 2017 EBITDA multiple (6.5x) $650 $910

@ IPP Average consensus 2017 EBITDA multiple (8.5x) $850 $1,190

Plus:

Harquahala Monetization $50 $150

Total Potential Impact on Equity Valuation $700 $1,340

Talen Shares Outstanding as of August 31, 2015 (in millions) 128.5

Positive EBITDA Drivers for 2017 and Beyond

(1)

(2)

(4)

(5)

(3)

(6)

Note: Refer to footnotes on slide 15 in “Supplemental Information”

+

+

$5 - $10

per share

of implied

value **Excluding any PJM

capacity revenue uplift**


Talen Energy Investment Highlights

Power production and marketing through wholesale and retail

channels Focused Purpose

Best Markets

Superior Fleet

Attractive Value

Value

Catalysts

With the addition of MACH Gen, will have presence in the most

constructive and liquid competitive markets

Modern gas, flexible dual-fuel, low-cost nuclear and hydro and

efficient supercritical coal requiring modest environmental capital.

Very strong fleet wide reliability

Strong free cash flow generation and lower relative financial

leverage

PJM Capacity Auction Results, Mitigation divestitures, MACH

Gen close, Brunner Island dual-fuel project, Harquahala

optimization


Supplemental Information


$126

$171

$34$7 $6 ($2)

Q2 2014Adjusted EBITDA

Margins Energy RelatedBusiness

O&M Other Q2 2015Adjusted EBITDA

2nd Quarter Financial Highlights

Adjusted EBITDA Walk – Q2 2015 vs. Q2 2014

Adjusted EBITDA by Segment Adjusted EBITDA Highlights

East margins up 14% year-over-year

Supported by strong output from Susquehanna

- Unit 1 operated at a 101% capacity factor

Significantly higher output from Martins Creek

- +500% output year-over-year due to low natural

gas prices and robust market heat rates

Reduced Corporate O&M costs

East West Other

Notes: Refer to “Supplemental Information – Regulation G Reconciliations” for reconciliation of non-GAAP financial measures

(1) RJS Power was consolidated into Talen Energy’s financials as of June 1, 2015. 2015 Adjusted EBITDA excludes contributions from the two-month period prior to

acquisition of RJS Power. 2014 Adjusted EBITDA reflects no contributions from RJS Power

(1)

($ in millions)

($ in millions)

(1)

$170

-$44

$202

$2

-$33

Q2 2014 Q2 2015


Net Generation (GWh) Capacity Factor EAF

2Q 2015 YTD 2Q 2015 YTD 2Q 2015 YTD

East Segment:

Coal - PJM 3,332 9,214 36.8% 49.5% 82.5% 86.6%

Coal - Montana 707 1,743 61.2% 68.7% 72.6% 85.2%

Hydro 308 529 48.1% 41.6% 99.1% 99.1%

Natural Gas CCGT 2,129 4,678 80.9% 89.4% 81.3% 88.8%

Natural Gas/Oil 1,294 1,633 25.2% 18.6% 77.2% 83.9%

Nuclear 3,678 8,707 75.0% 89.3% 73.9% 86.8%

West Segment:

Natural Gas 292 292 22.7% 22.7% 74.1% 74.1%

TOTAL 11,739 26,796 43% 50% 79% 85%

82.5%

102.7% 103.6% 101.5%

Q3 2014 Q4 2014 Q1 2015 Q2 2015

Unit 2

99.5% 95.3%104.0% 100.5%

Q3 2014 Q4 2014 Q1 2015 Q2 2015

Unit 1

2nd Quarter Operational Review

Solid Asset Performance Unit Reliability – EFOF

Safety - TCIR Improved Susquehanna Operations

Capacity F

acto

r (%

)

(1) Contains only one month of data for RJS assets per consolidation on June 1, 2015. Full QTD and YTD views provided in the supporting material – see “Supplemental Information – Operational Statistics”

(2) EFOF – Equivalent Forced Outage Factor

(3) EAF – Equivalent Availability Factor, which includes scheduled outages

(4) TCIR – Total Case Incidence Rate using OSHA measurement standards. Reflects six months of RJS Power statistics

(5) Based upon 2013 average incident rate for the utilities sector (NAICS 221)

(4)

(1) (1) (2)

49.5%

(3)

Outstanding Unit 1 performance

following turbine blade modifications

in 2Q 2014

Adjusting for a 2Q 2015 refueling

outage, Unit 2 operated at a CF > than

100% since last turbine blade outage

3%

7%

0% 1%2%

0%

20%

4%

9%

1% 1% 2%0%

3%

Q2 2015 Q2 2014

Primarily driven by a single unit outage and

reflects only one month of operations

1.51

1.70

YTD 2014 YTD 2015

Average recordable incident rate per Bureau of Labor Statistics

2.10

(5)


Slide 10 Footnotes

(1) Assumes Brunner Island Dual-fuel project COD in 4Q 2016

(2) Improvement is reflective of Talen Energy’s ownership percentages in the facilities

(16.25% of Conemaugh and 12.34% of Keystone). High case assumes collaboration

of joint ownership to reduce plant operating costs to level comparable with the

Montour facility. Low case assumes no improvement achieved

(3) High and low cases assume annual contract reset adjusts to current forward NAAP

coal price levels

(4) Based on FactSet consensus estimates for 2017 EBITDA as of August 31, 2015

(5) IPP average multiple based on FactSet consensus estimates of Calpine, Dynegy and

NRG for 2017 EBITDA as of August 31, 2015

(6) Low case assumes EBITDA drivers valued at Talen Energy consensus valuation

multiple (6.5x EV/EBITDA). High case assumes EBITDA drivers valued at IPP

average consensus valuation multiple (8.5x EV/EBITDA)


2015 2016

East Segment:

PJM Power: Nuclear, Coal, Hydro ($/MWh) $41-43 $40-42

PJM Consumed Coal (Delivered $/ton) $73-75 $72-74

Spark Spread ($/MWh) $14-15 $12-13

Montana ($/MWh) $40-42 $39-41

Montana Consumed Coal (Delivered $/ton) $27-30 $27-33

West Segment:

Spark Spread ($/MWh) $9-10 -

99%

67%

82%

45%

95%

56%62%

0%

93%

56%

2015 2016

East Nuclear, Coal & Hydro East Gas/Oil Montana Coal West Gas Total Portfolio

Hedging & Commercial Management

Notes: As of June 30, 2015. Does not reflect sale of between 1,300 and 1,400 MW of generating capacity that is required to comply with the FERC order approving combination with RJS Power

(1) Gas price sensitivity assumes system heat rate is unchanged. Heat Rate sensitivity assumes power prices moves and gas price is unchanged. Power price sensitivity assumes gas price is unchanged

(2) Assumes MACH Gen transaction closes by 12/31/2015

(3) The 2015 and 2016 average hedge prices were estimated by determining the impact on the existing collars resulting from power prices at the 5th and 95th percentile confidence levels

(4) Excludes out of the money heat rate call options related to the Sapphire portfolio that were assumed in the RJS Power acquisition and expire by the end of 2016

Portfolio Targets:

Expected Generation Hedge Position Coal and Nuclear Fuel Hedge Position

Average Hedge Prices Margin Sensitivities

2016

($ millions)

2015

(3) (1)

(4) $33 $32$57

$18

$187$150

$240

$18 $26

($0) ($12) ($21)

($143) ($126)

($201)

(2)

PJM

Capacity

+ $10/MW-Day

Gas

+/-

$0.50/mmBtu

Heat Rate

+/-

1.0 mmBtu

Power

+/- $5/MWh

ERCOT

1 hour

@ Offer Cap

75% – 1-year forward

25% – 2-years forward

Note: Excludes expected generation from MACH Gen assets

100% 100%97%

77%

100% 100%

2015 2016

Nuclear East Coal Montana Coal (mine mouth)


Quarter-to-date

Q2 2015 Q2 2014 Q2 2015 Q2 2014 Q2 2015 Q2 2014 Q2 2015 Q2 2014

East:Coal - PJM 4,358 6,090 33.0% 46.0% 76.7% 79.3% 2.6% 2.5%

Coal - Montana 707 605 61.2% 41.0% 72.6% 73.2% 6.6% 9.0%

Hydro 308 365 48.1% 57.2% 99.1% 95.7% 0.4% 0.6%

Natural Gas Combined Cycle 2,129 2,576 80.9% 98.3% 81.3% 96.4% 1.1% 1.2%

Natural Gas/Oil 1,669 585 27.1% 9.6% 73.8% 87.3% 1.8% 0.9%

Nuclear 3,678 3,226 75.0% 65.3% 73.9% 65.0% 0.1% 0.0%

West:Natural Gas 777 900 19.8% 22.1% 65.8% 85.2% 28.1% 3.3%

TOTAL GENERATION 13,625 14,348 41.6% 43.3% 75.0% 80.8% 5.2% 2.0%

Year-to-date

YTD 2015 YTD 2014 YTD 2015 YTD 2014 YTD 2015 YTD 2014 YTD 2015 YTD 2014

East:Coal - PJM 12,341 15,244 47.0% 57.9% 83.2% 84.2% 2.7% 2.5%

Coal - Montana 1,743 1,616 68.7% 55.0% 85.2% 74.4% 5.1% 15.9%

Hydro 529 639 41.6% 50.4% 99.1% 94.6% 0.2% 1.4%

Natural Gas Combined Cycle 4,678 4,438 89.4% 85.2% 88.8% 86.6% 2.1% 4.4%

Natural Gas/Oil 2,226 1,407 18.1% 11.5% 80.7% 88.1% 2.7% 3.1%

Nuclear 8,707 7,486 89.3% 76.1% 86.8% 75.0% 0.1% 0.0%

West:Natural Gas 1,451 1,764 18.4% 21.6% 70.0% 79.7% 24.1% 2.0%

TOTAL GENERATION 31,676 32,594 48.5% 49.3% 82.6% 83.0% 4.9% 2.9%


EFOF

EFOF


Operational Statistics

(1) Includes full three and six month RJS Power operating statistics for comparative purposes

(2) Includes Ironwood and Lower Mount Bethel

(3) EAF – Equivalent Availability Factor, which includes scheduled outages

(4) EFOF – Equivalent Forced Outage Factor

(1)

(2)

(2)

(1)

(3) (4)


Projected Capital Expenditures

$235 $258 $255

$317

$214

$107 $85

$120

$126

$129

$48 $85

$1

$1

$1

$50

$42

$21

$14

$11

$42

$28

$39

$20

$32

$29 $24

$23

$12

$2

$6 $20

$7

$6

$6

$516

$543

$466

$495

$395

$-

$100

$200

$300

$400

$500

$600

2015 2016 2017 2018 2019

Sustenance Nuclear Fuel Growth Information Technology Environmental Regulatory Discretionary

($ in millions)

(1) Reflects RJS Power expenditures for the five months of 2015 prior to the acquisition

(1)


($ millions) 6/30/2015 12/31/2014

Cash & cash equivalents $352 $352

Liquidity facilities 2,350 4,550

Total Liquidity $2,702 $4,902

Less: Current liquidity facility usage 309 911

Total Available Liquidity $2,393 $3,991

$352

$500

$1,850

$-

$500

$1,000

$1,500

$2,000

$2,500

$3,000

Cash CDS Backed Syndicated

Liquidity

(1) Excludes $800 million secured trading facility

(2) Includes $3,250 million of credit facilities that matured or were terminated upon the spinoff

(3) $309 million of letters of credit outstanding on the $1,850 million syndicated secured credit facility as of 6/30/2015

Available Liquidity Liquidity Facilities as of 6/30/2015

($ millions)

$2,702

$2,393 Available (3)

(2)

Substantial liquidity to support

asset optimization

(1)

(1)


$302 $354

$4

$403

$1,254

$1,770

2015 2016 2017 2018 2019 2020 & Beyond

Long-term Debt Maturities

Note: As of June 30, 2015. Includes Talen Ironwood principal amortization.

(1) Includes the $300 million 5.70% REPS required to be put by existing holders on 10/15/2015 for either (a) purchase and remarketing by a

designated dealer or (b) repurchase by Talen Energy Supply

(2) Includes $231 million of municipal bonds that were remarketed on September 1, 2015

(1)

($ in millions)

(2)


Asset Location Fuel Type Ownership Net Heat Rate (Btu / kWh) Owned Capacity COD Region

East Assets

Brandon Shores MD Coal 100% 10,252 1,284 1984 - 1991 PJM-SWMAAC

Brunner Island PA Coal 100% 9,842 1,411 1961 - 1969 PJM-MAAC

C.P. Crane MD Coal 100% 10,616 404 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 MD Coal/NG/Oil 100% 10,663 982 1956 - 1972 PJM-SWMAAC

Eastern Hydro 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 PA Natural Gas 100% 9,551 47 1989 PJM-MAAC

Bayonne NJ Natural Gas/Oil 100% 8,857 165 1988 PJM-PS North

Camden NJ Natural Gas/Oil 100% 8,675 145 1993 PJM-PSEG

Dartmouth MA Natural Gas/Oil 100% 8,715 (CCGT) / 11,326 (Peaker) 83 1996 ISO-NE

Elmwood Park NJ Natural Gas/Oil 100% 9,500 71 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 NJ Natural Gas/Oil 100% 8,680 123 1993 PJM-PS North

Peakers PA Natural Gas/Oil 100% Various 354 1967 - 1973 PJM

Pedricktown NJ Natural Gas/Oil 100% 8,455 118 1992 PJM-EMAAC

Susquehanna PA Nuclear 90% N/A 2,245 1983 - 1985 PJM-MAAC

Renewables PA Renewables 100% Various 6 Various PJM-MAAC

Colstrip 1 & 2 MT Coal 50% 10,941 307 1975, 1976 WECC

Colstrip 3 MT Coal 30% 10,660 222 1984, 1986 WECC

Subtotal 13,151

West Assets

Barney Davis 1 TX Natural Gas 100% 10,100 318 1974 ERCOT-South

Barney Davis 2 TX Natural Gas 100% 7,100 646 2010 ERCOT-South

Laredo 4 TX Natural Gas 100% 8,900 92 2008 ERCOT-South

Laredo 5 TX Natural Gas 100% 8,900 89 2008 ERCOT-South

Nueces Bay 7 TX Natural Gas 100% 7,100 648 2010 ERCOT-South

Subtotal 1,793

MACH Gen Assets

Athens NY Natural Gas 100% 7,100 1,138 2004 NYISO

Millennium MA Natural Gas 100% 6,975 335 2001 ISO-NE

Harquahala AZ Natural Gas 100% 7,100 1,054 2004 WECC

Subtotal 2,527

Total Talen Energy 17,471

Talen Energy Asset Overview

Note: Does not reflect sale of between 1,300 and 1,400 MW of generating capacity that is required to comply with the FERC order approving the combination with RJS Power

(1) Includes Holtwood and Wallenpaupack

(2) Reflects pending acquisition of 2,500 MW MACH Gen portfolio and pending sale of Talen Renewable Energy, which are both expected to close by 12/31/2015

(1)

(2)

(2)

(2)


Group 1 Mitigation Overview

PPL and RJS Power 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 between 1,300 and 1,400 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, Talen Energy and RJS Power accepted Option 1

and committed that Talen Energy 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; Talen Energy has until June 2016 to

enter into definitive agreements

Group 2

(1) Pedricktown capacity includes capacity dedicated to serving landlord load (which has historically averaged 9 MW)

Facility MW

Bayonne 0165

Camden 0145

Elmwood Park 0071

Newark Bay 0123

Pedricktown 0118

York 0047

Ironwood 0660

Total 1,329

Facility MW

Bayonne 0165

Camden 0145

Elmwood Park 0071

Newark Bay 0123

Pedricktown 0118

York 0047

C.P. Crane 0404

Holtwood 0249

Wallenpaupack 0044

Total 1,366

FERC Required Mitigation

(1)

(1)


Regulation G Reconciliations

Quarter-to-date Adjusted EBITDA (2015) ($ in millions)

Note: Please refer to Regulation G Reconciliation footnotes for quarter-to-date and year-to-date EBITDA on slide 27

Three Months Ended June 30, 2015

East West Other Total

Net income (loss) $ 26 (Income) loss from discontinued operations (net of tax) .............. (1 )

Interest expense ................................................................ 55

Income taxes ................................................................... (43 )

Other (income) expense - net ............................................... (3 )

Operating income (loss) $ 132 $ (6 ) $ (92 ) $ 34 Depreciation .................................................................... 83 3 1 87

Other income (expense) - net ............................................... 4 — (1 ) 3

Sapphire EBITDA (a) ........................................................ 1 — — 1

EBITDA $ 220 $ (3 ) $ (92 ) $ 125 Unrealized (gain) loss on derivative contracts (b) ...................... (12 ) 5 — (7 )

Stock-based compensation expense (c) ................................... (8 ) — 39 31

(Gain) loss from nuclear decommissioning trust funds ................ (4 ) — — (4 )

Asset retirement obligation accretion ..................................... 8 — — 8

Transition Services Agreement costs ...................................... — — 5 5

Separation benefits ............................................................ — — 2 2

Terminated derivative contracts (f) ........................................ (13 ) — — (13 )

Revenue adjustment (g) ...................................................... 7 — — 7

RJS transaction costs ......................................................... — — 5 5

Restructuring costs (h) ....................................................... — — 8 8

Other (i) ......................................................................... 4 — — 4

Adjusted EBITDA $ 202 $ 2 $ (33 ) $ 171



Quarter-to-date Adjusted EBITDA (2014) ($ in millions)


Three Months Ended June 30, 2014


Net income (loss) $ 13

(Income) loss from discontinued operations (net of tax) .............. (11 )


Income taxes .................................................................... (11 )

Other (income) expense - net ................................................ (7 )

Operating income (loss) $ 86 $ — $ (70 ) $ 16

Other income (expense) - net ................................................ 6 — 1 7

Depreciation .................................................................... 76 — — 76

EBITDA $ 168 $ — $ (69 ) $ 99

Unrealized (gain) loss on derivative contracts (b) ...................... (1 ) — — (1 )

Stock-based compensation expense (c) ................................... — — 3 3


Asset retirement obligation accretion ...................................... 7 — — 7

Separation benefits (e) ........................................................ — 22 22

Other (i) .......................................................................... 1 — — 1

Adjusted EBITDA $ 170 $ — $ (44 ) $ 126



Year-to-date Adjusted EBITDA (2015) ($ in millions)


Six Months Ended June 30, 2015


Net income (loss) $ 122 (Income) loss from discontinued operations (net of tax) .............. (1 )


Income taxes ................................................................... 10

Other (income) expense - net ............................................... (10 )

Operating income (loss) $ 362 $ (6 ) $ (144 ) $ 212 Depreciation .................................................................... 160 3 1 164

Other income (expense) - net ............................................... 11 — (1 ) 10

Sapphire EBITDA (a) ........................................................ 1 — — 1

EBITDA $ 534 $ (3 ) $ (144 ) $ 387 Unrealized (gain) loss on derivative contracts (b) ...................... (58 ) 5 — (53 )



Asset retirement obligation accretion ..................................... 17 — — 17

Transition Services Agreement costs ...................................... — — 5 5

Separation benefits ............................................................ — — 2 2

Corette closure costs (e)...................................................... 4 — — 4

Terminated derivative contracts (f) ........................................ (13 ) — — (13 )

Revenue adjustment (g) ...................................................... 7 — — 7

RJS transaction costs ......................................................... — — 5 5

Restructuring costs (h) ....................................................... — — 10 10

Other (i) ......................................................................... 7 — — 7

Adjusted EBITDA $ 488 $ 2 $ (82 ) $ 408



Year-to-date Adjusted EBITDA (2014) ($ in millions)


Six Months Ended June 30, 2014


Net income (loss) $ (53 )

(Income) loss from discontinued operations (net of tax) .............. (3 )


Income taxes .................................................................... (58 )

Other (income) expense - net ................................................ (13 )

Operating income (loss) .................................................... $ 65 $ — $ (128 ) $ (63 )

Other income (expense) net ................................................. 11 2 13

Depreciation .................................................................... 151 — — 151

EBITDA ........................................................................ $ 227 $ — $ (126 ) $ 101

Unrealized (gain) loss on derivative contracts (b) ...................... 218 — — 218



Asset retirement obligation accretion ...................................... 15 — — 15

Separation benefits (d) ........................................................ — — 22 22

Other (i) .......................................................................... 4 — — 4

Adjusted EBITDA $ 453 $ — $ (92 ) $ 361



Quarter-to-date and Year-to-date Adjusted EBITDA Footnotes

(a) Sapphire, excluding related heat rate call options, has been classified as discontinued operations

since its June 1, 2015 acquisition.

(b) Represents unrealized gains (losses) on derivatives. Amounts have been adjusted for option

premiums of $4 million and $9 million for the three and six months ended June 30, 2015 and

insignificant amounts for the same periods in 2014.

(c) For periods prior to June 2015, represents the portion of PPL's stock-based compensation cost

allocable to Talen Energy. Amounts for the 2014 periods were cash settled with a former affiliate.

(d) In June 2014, Talen Energy Supply's largest IBEW local ratified a new three-year labor agreement.

In connection with the new agreement, estimated bargaining unit one-time voluntary retirement

benefits were recorded.

(e) Operations were suspended and the Corette plant in Montana was retired in March 2015.

(f) Represents net realized gains on certain derivative contracts that were early-terminated due to the

spinoff transaction.

(g) Relates to a prior period revenue adjustment for the receipt of revenue under a transmission

operating agreement with Talen Energy Supply's former affiliate, PPL Electric Utilities Corporation.

(h) Costs related to the spinoff transaction, including FERC-required mitigation plan expenses and

legal and professional fees.

(i) All periods include other comprehensive income amortization on non-active derivative positions

and the 2015 periods include an asset write-off.



Year-to-Date Adjusted Free Cash Flow ($ in millions)

June YTD 2015 June YTD 2014

Cash from Operations $ 355 $ 290

Sustenance Capital Expenditures (191 ) (193 )

Counterparty collateral paid (received) (31 ) 15

Adjusted Free Cash Flow, including other adjustments 133 112

Cash adjustments (after tax):

Transition Services Agreement costs 3 —

Separation benefits 1 13

Corette closure costs (a) 2 —

RJS transaction costs 3 —

Restructuring costs (b) 6 —

Adjusted Free Cash Flow $ 148 $ 125

(a) Operations were suspended and the Corette plant was retired in March 2015.

(b) Costs related to the spinoff transaction, including FERC-required mitigation plan expenses and legal and professional fees.


Net Income/(Loss) $ 55 $ 100 $ 145 $ 98

Income Taxes ………………………………………………………………. 23 53 83 56

Interest Expense ……………………………………………………………. 327 327 327 290

Depreciation & Amortization ……………………………………………….. 410 410 410 453

EBITDA $ 815 $ 890 $ 965 $ 897

Non-Cash Compensation ………………………………………………….. 23 23 23 21

Asset Retirement Obligation ………………………………….……..……… 35 35 35 37

MTM losses (gains) ………………………………………………………… (28) (28) (28) —

Nuclear decommissioning trust losses (gains) ………………………………… (10) (10) (10) (10)

Adjusted EBITDA, including other adjustments $ 835 $ 910 $ 985 $ 945

Other adjustments:

Transaction Services Agreement costs and allocations (d) ………………….. 75 75 75 45

Other (e) ……………………………………………………………….….. 25 25 25 —

Adjusted EBITDA $ 935 $ 1,010 $ 1,085 $ 990

Midpoint -

2016E

Low -

2015E

Midpoint -

2015E

High -

2015E


Adjusted EBITDA Forecast ($ in millions)

(a) 2015 forecasted amounts include twelve months of performance from RJS Power, including the five-month period prior to the acquisition and an adjustment for PPL

allocations not expected to continue in future periods

(b) Assumes MACH Gen transaction closes by 12/31/2015

(c) Sale of Talen Renewable Energy expected by 12/31/2015

(d) 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

(e) Restructuring costs that are not expected to continue in future periods

(b)(c) (a) (a) (a)



Adjusted Free Cash Flow Forecast ($ in millions)

Cash from Operations (a) $ 752 $ 797 $ 842 $ 770

Capital Expenditures, excluding growth ……………………… (547) (517) (487) (487)

Adjusted Free Cash Flow, including other adjustments $ 205 $ 280 $ 355 $ 283

Cash adjustments (after tax):

Transaction Services Agreement costs & allocations (d) ……. 45 45 45 27

Other (e) …………………………………………………...... 15 15 15 —

Adjusted Free Cash Flow, including other adjustments (f) $ 265 $ 340 $ 415 $ 310

Midpoint -

2015E

High -

2015E

Midpoint -

2016E

Low -

2015E

(a) 2015 forecasted amounts include twelve months of performance from RJS Power, including the five-month period prior to the acquisition and an

adjustment for PPL allocations not expected to continue in future periods

(b) Assumes MACH Gen transaction closes by 12/31/2015

(c) Sale of Talen Renewable Energy expected by 12/31/2015

(d) Low, midpoint, and high 2015 amounts includes $24 million of allocations from PPL and $21 million of TSA costs that are not expected to

continue in future periods

(e) Restructuring costs that are not expected to continue in future periods

(f) Does not include growth capex of $48 million in 2015 and $84 million in 2016

(b)(c)


Forward-Looking Information Statement Statements contained in this presentation, including statements with respect to future earnings, EBITDA, Adjusted EBITDA or Adjusted

Free Cash Flow results, cash flows, tax attributes, 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. Among the important factors that could cause actual results to differ

materially from the forward-looking statements are: 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; unanticipated difficulties or delays in

our ability to successfully integrate the RJS Power businesses and to achieve anticipated synergies and cost savings as a result of the

spinoff transaction and combination with RJS Power delays in and/or additional costs to complete the proposed acquisition of MACH Gen,

the sale of Talen Renewable Energy and/or the Brunner Island dual-fuel project; unforeseen difficulties in successfully integrating the

MACH Gen power facilities into Talen Energy's portfolio and/or in successfully executing efforts to optimize and/or monetize the value of

the Harquahala plant; unexpected costs or liabilities associated with the MACH Gen power 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; receipt of

necessary governmental 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; changes in earnings estimates or buy/sell recommendations

by analysts; volatility in market demand and prices for energy, capacity, transmission services, emission allowances and RECs;

competition in retail and wholesale power and natural gas markets; 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 prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b)(3) on May 1, 2015, its

Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 and its other reports on file with the Securities and Exchange

Commission.


This presentation contains non-GAAP financial measures, EBITDA and Adjusted EBITDA, which we use as measures of

our performance. EBITDA represents net income (loss) before interest expense, income taxes, depreciation and

amortization. Adjusted EBITDA represents EBITDA further adjusted for certain non-cash and other items including

unrealized gains and losses on derivative contracts, stock-based compensation expense, asset retirement obligation

accretion, gains and losses on securities in the nuclear decommissioning trust fund, gains or losses on sales,

dispositions or retirements of assets and transition, transaction and restructuring costs. EBITDA and Adjusted EBITDA

are not intended to represent cash flows from operations operating income (loss) 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 and Adjusted EBITDA 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 and Adjusted EBITDA 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


Adjusted free cash flow is derived by deducting maintenance capital expenditures, excluding growth-related capital

expenditures, and after-tax from cash flow from operations. This non-GAAP measure should not be considered an

alternative to cash flow from operations, which is determined in accordance with GAAP. We believe that adjusted free

cash flow although a non-GAAP measure, is an important measure to both management and investors as an indicator of

the company’s ability to sustain operations without additional outside financing beyond the requirement to fund maturing

debt obligations. This measure is not necessarily comparable to similarly-titled measures reported by other companies as

they may be calculated differently.

Definitions of Non-GAAP Financial Measures

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