Talen EnergyEnergy+Investor... · - Increased run-rate target to $165 - $175 million Added scale and fuel and geographic diversity to the portfolio with MACH Gen acquisition (2,500

Talen Energy

February 25, 2016

Fourth Quarter Conference Call

We Generate Energy for a Brighter Tomorrow

© Talen Energy Corporation 2016 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 November 3, 2015, as amended

or supplemented, and the Company’s Quarterly Report on Form 10-Q

for the quarter ended September 30, 2015.


Agenda

P. Farr

P. Farr

J. McGuire

2015 Review & Strategic Update

Commercial & Operational Review

Financial Review

Q&A


$154

$759

$237

$1,002

$241

$1,082

4th Quarter Full Year

2014 2015 2015 (Guidance Basis)

$1,050

$1,082$1,100

2015 GuidanceRange

FY 2015(Guidance Basis)

$375

$403$425

2015 GuidanceRange

FY 2015(Guidance Basis)

…And Achieving Financial Objectives

2015 Performance Review

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

(1) Reported Adjusted EBITDA excludes results from RJS Power for the first 5 months of 2015 prior to Talen Energy’s acquisition on June 1, 2015

(2) Includes full year 2015 results from RJS Power including the first 5 months of 2015 prior to Talen Energy’s acquisition, adjusts for PPL Corporation allocated costs incurred prior to the Talen

Energy spinoff not expected to continue in future periods, and excludes results from MACH Gen for November and December of 2015 following Talen Energy’s acquisition

2015 Highlights

Successfully executed spinoff & merger with RJS

- Achieved over $135 million of synergies in 2015 vs. initial

guidance of $115 million

- Increased run-rate target to $165 - $175 million

Added scale and fuel and geographic diversity to

the portfolio with MACH Gen acquisition

(2,500 MW of CCGTs)

Announced FERC required asset sales at

attractive values for a combined $1.5 billion in

gross proceeds

- East hydro sold for ~$3,000/kW; Ironwood CCGT sold for

over $900/kW

- Ironwood and C.P. Crane sales closed; East hydro sale

expected to close at the end of March 2016

Strong performance from nuclear and eastern

natural gas fleet drove outperformance relative to

Adjusted EBITDA & Adjusted FCF targets

- Susquehanna Nuclear delivered plant-record output

- Robust PJM spark spreads continued to support margins

from gas-fired assets

Delivering Strong Results...

(2) (1)

($ in millions)

Adjusted EBITDA Adjusted FCF

(2)

($ in millions)

Adjusted EBITDA

(2)


2016 Key Objectives

2016 Guidance Ranges (1)

($ in millions)

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

(1) Excludes contributions to Adjusted EBITDA and Adjusted Free Cash Flow from assets Talen Energy has sold or has announced it will sell in 2016

2016 Value Drivers

Close sale of East hydro facilities:

$860 million of pre-tax proceeds

Achieve O&M and capital reductions

Updated 2016 guidance reflects reductions of over $70

million of O&M and $45 million of capital costs vs.

estimate provided in mid-2015

Improve Harquahala operations (short-term)

Ran one unit more than 50% of the days from date of

purchase (November 2nd) through January versus ~1%

over similar period last year

Reviewing contracts/agreements to lower fixed costs

Reduce cash taxes

Bonus depreciation and NOLs reduce projected 2016

cash taxes from operations and tax liability associated

with the sale of assets

Strong potential to have a portion of Brunner Island

gas-fired capability operational as early as August

Deployment of asset sale net proceeds of $1.2 billion

Key Strategic Initiatives in Focus

Brunner Island Gas Co-fire Project Project COD expected by end of 2016

Montour Gas Co-fire Project Evaluating project cost and pipeline options

Expect decision on project 1H 2016

Keystone & Conemaugh Improvements Owners committee to review moving from a three year

major outage cycle to a four year cycle

Harquahala Optimization Finalize plan to pursue long-term value


Key Strategic Initiatives Update

(1) Project currently under review; not included in current capital expenditure projections

Harquahala Optimization Montour Gas Co-fire Project

Deliver value from a 1,040 MW, 7,100 heat rate

CCGT located in a challenging market; multiple

opportunities outlined below

Project under review that would enable our 1,500

MW Montour coal-fired facility to prospectively

operate on coal and/or natural gas

Long-term PPA or sale to local entity:

Option for single or multiple units

Efficient gas plant with little run time provides opportunities

for local entities looking at supply options

Trend of environmental regulations and low gas prices

expected to pressure coal facilities

Relocation of the plant:

Multiple existing sites within Talen Energy’s portfolio

Cost estimates range $315/kW - $500/kW

Timeline dependent on site

Next steps:

Review PPA or sale with regional counterparties

Evaluate target sites for relocation and continue to refine

cost estimates

Expect action by end of 2016

Locational advantage to access Marcellus gas:

Multiple options to tap into high pressure pipelines

Margin opportunity from high spark spreads due to the low

cost gas available in the region

Ability to retain current 100% coal-firing capability:

Boiler modifications would allow use of either coal or gas,

with flexibility to seamlessly change fuel blend during

operation

Enhances station’s risk/reward profile relative to PJM’s

Capacity Performance product

Next steps:

Expect project go/no-go decision in 1H 2016

If approved, permitting, construction and development to

begin by year end 2016

Expect a 18-24 month construction cycle

Preliminary economics appear very similar to Brunner

Island gas co-fire project

(1)


Commercial & Operational Review


Net Generation (GWh) Capacity Factor EAF

Q4 2015 YTD Q4 2015 YTD Q4 2015 YTD

East Segment:

Coal - PJM 2,698 18,185 20.3% 39.5% 77.5% 84.2%

Hydro 191 903 29.6% 35.2% 90.6% 96.5%

Natural Gas Combined Cycle 2,449 9,430 92.6% 89.7% 88.0% 88.5%

Natural Gas/Oil 1,313 5,202 21.0% 23.7% 75.3% 83.0%

Nuclear 4,815 18,505 97.1% 94.1% 95.1% 92.1%

West Segment

Coal - Montana 1,006 3,776 86.1% 77.5% 91.6% 88.5%

Natural Gas 696 2,190 18.7% 24.3% 89.9% 90.1%

TOTAL 13,168 58,191 40.2% 48.3% 82.9% 86.8%

2015 Operational Review Solid Asset Performance EFOF

Safety - TCIR Susquehanna Returns to Strong Performance (5)

(4)

(3)

Generation (GWh) Availability (EQA)

Strong fleet-wide reliability supporting solid 2015 results

BLS Utility Average 2.4 (6)

(1)

(1) YTD results reflect seven months of RJS assets, which were acquired in June 2015 as part of the spinoff transaction. Results do not reflect MACH Gen assets, which were acquired in November 2015. Includes results

from assets Talen Energy has sold or has announced it will sell in 2016

(2) Results include Corette coal facility in Montana, which was retired in March 2015

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

(4) EFOF – Equivalent Forced Outage Factor

(5) TCIR – Total Case Incidence Rate using OSHA measurement standards. Reflects 12 months of RJS statistics

(6) Based upon 2014 Bureau of Labor Statistics (BLS) average incident rate for the utilities sector (NAICS 221)

(2)

+9%

16,903

18,505

2014 2015

84%

92%

2014 2015

2%

10%

1%3%

7%

<1%

6%

2%

6%

0%2%

3%

1%

4%

Coal - PJM Coal - MT Hydro CCGTs -East

Gas/Oil -East

Nuclear Gas - West

2014 2015

1.4

2015


$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$20

$30

$40

$50

12/31/2014 3/31/2015 6/30/2015 9/30/2015 12/31/2015 3/31/2016

PJM WestHub Peak - 2016 PJM WestHub Peak - 2017

TETCO M-3 - 2016 TETCO M-3 - 2017

Updates/Developments: Regional haze federal implementation plan and low

gas prices could lead to retirements of coal assets

Extension of tax credits could lead to additional

renewable growth in market

What to watch: Potential changes to Operating Reserve Demand

Curve (ORDC) price adder designed to ensure that

sufficient generation reserves remain available during

periods of scarcity

Market Review – PJM & ERCOT 2016-2017 PJM Forward Prices PJM Update & Outlook

ERCOT Update & Outlook 2016-17 ERCOT Forward Prices

Source: ICE, Talen Energy. Spark spread assumes PJM West Hub Peak vs. TETCO M3 forward prices at 7 heat rate

Source: ICE, Talen Energy. Spark spread assumes ERCOT North Hub Peak vs. Henry Hub forward prices at a 7 heat rate

Updates/Developments: PJM release of capacity sensitivities suggests full

transition to CP provides capacity price uplift

FERC approval of offer cap increase to $2,000/MWh

Supreme Court ruling on demand response

Revised demand curve reflects limited growth and

impacts of energy efficiency in region

What to watch: Supreme Court ruling on state subsidized generation

(New Jersey & Maryland cases)

Ohio PPA decisions

2016 On-peak spark spread ▲ 13.1%


2016 On-peak spark spread ▼ 33.3%


-51%

-34%

-18%

-11%

-39%

-33%

-37%

-33%

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$15

$25

$35

$45

$55

12/31/2014 3/31/2015 6/30/2015 9/30/2015 12/31/2015 3/31/2016

ERCOT North Hub Peak - 2016 ERCOT North Hub Peak - 2017

Henry Hub - 2016 Henry Hub - 2017

Pow

er

($/M

Wh)

Pow

er

($/M

Wh)

Natu

ral G

as

($/m

mbtu

) N

atu

ral G

as

($/m

mbtu

)


$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

$6.00

$6.50

$30

$40

$50

$60

12/31/2014 3/31/2015 6/30/2015 9/30/2015 12/31/2015 3/31/2016

Mass Hub Peak - 2016 Mass Hub Peak - 2017

Algonquin - 2016 Algonquin - 2017

$2.75

$3.25

$3.75

$4.25

$4.75

$5.25

$5.75

$6.25

$30

$40

$50

$60

12/31/2014 3/31/2015 6/30/2015 9/30/2015 12/31/2015 3/31/2016

NY Zone G Peak - 2016 NY Zone G Peak - 2017

Algonquin - 2016 Algonquin - 2017

Market Review – NYISO & ISO-NE 2016-17 NYISO Forward Prices NYISO Update & Outlook

ISO-NE Update & Outlook 2016-17 ISO-NE Forward Prices

Source: ICE, Talen Energy. Spark spread assumes NY Zone G Peak vs. Algonquin Citygate forward prices at 7 heat rate





Updates/Developments: Announced retirement of challenged nuclear facilities

could tighten the market

Locational Capacity Requirement (LCR) decreased in

all zones except Rest of State (where Athens is

situated)

What to watch: Constitution pipeline updates on remaining permits and

full Notice to Proceed from FERC

Updates on Reforming the Energy Vision (REV) and

Clean Energy Standard (CES) initiatives

Updates/Developments: Forward Capacity Auction 10 clears at $7.03/kW

($234/MW-day), lower than prior auction with 900 MW

of net new supply – prices remain strong relative to

other capacity markets

What to watch: Northern Pass and Clean Power Link project updates;

potentially 2 GW of hydro power capacity

Impact of gas infrastructure development including

Algonquin Incremental Market (AIM) Project expected

in service by end of 2016

-46%

-35% -35%

-20%

-46%

-36% -35%

-26%

Source: ICE, Talen Energy. Spark spread assumes Mass Hub Peak vs. Algonquin Citygate forward prices at 7 heat rate

Pow

er

($/M

Wh)

Pow

er

($/M

Wh)

Natu

ral G

as

($/m

mbtu

) N

atu

ral G

as

($/m

mbtu

)


2016 2017

East Segment:

PJM Power: Nuclear & Coal ($/MWh) $40-42 $38-42

PJM Consumed Coal (Delivered $/ton) $65-67 $64-67

Spark Spread ($/MWh) $10-12 -

West Segment:

MT Power: Coal ($/MWh) $35-37 $40-41

MT Consumed Coal (Delivered $/ton) $26-32 $26-32

Spark Spread ($/MWh) $7-9 -

Hedging & Commercial Management

Notes: As of December 31, 2015. Excludes mitigation assets (East Hydro, Ironwood and CP Crane)

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

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

Expected Generation Hedge Position Coal and Nuclear Fuel Hedge Position

Average Hedge Prices Margin Sensitivities ($ millions) (1)

Gas

+/-

$0.50/mmBtu

Heat Rate

+/-

1.0 mmBtu

Power

+/- $5/MWh

ERCOT

1 hour

@ Offer Cap

2017 2016

(2)

74%

21%

35%

0%

66%

41%

30%

0%

62%

15%

2016 2017

East Nuclear & Coal East Gas/Oil West Coal West Gas Total Portfolio

100% 100%

54% 55%

100% 100%

2016 2017

Nuclear East Coal West Coal

$121$97

$168

$18

$294$222

$363

$18

($69) ($79)($136)

($260)($198)

($324)


Financial Review


4th Quarter Financial Highlights

Adjusted EBITDA Walk – Q4 2014 to Q4 2015

Adjusted EBITDA by Segment Adjusted EBITDA Highlights

Higher margins quarter-over-quarter primarily

driven by:

+ Addition of RJS assets

+ Higher PJM capacity prices

+ Improved spark spreads

Partially offset by higher O&M:

- Primarily due to the addition of RJS assets

+ Lower outage costs and corporate cost reductions

partially offset the increase in O&M

East West Other


($ in millions)

($ in millions)

$154

$237$106 ($15)

($8)

Q4 2014Adjusted EBITDA

Margins O&M Other Q4 2015Adjusted EBITDA

$180

$18

($44)

$262

$4

($29)

4Q 2014 4Q 2015


$759

$1,002$1,082

$246 $80

($3)

2014 Adjusted EBITDA Margins O&M and Other 2015 Adjusted EBITDA Guidance BasisAdjustment

2015 Adjusted EBITDA(Guidance Basis)

2015 Financial Highlights

Adjusted EBITDA Walk – 2014 to 2015

Adjusted EBITDA by Segment Adjusted EBITDA Highlights

Higher margins year-over-year primarily driven by:

+ Addition of RJS assets

+ Higher realized energy prices

+ Increased spark spreads

+ Improved nuclear availability

- Lower capacity revenues

- Gains realized in 2014 on certain commodity positions

- Net effect of unusual weather and market volatility in the first quarter of

2014

- Lower volumes on full-requirements sales contracts

O&M increase from RJS assets was primarily offset by

cost reductions and lower outage expenses

East West Other


(1) Includes results from RJS assets for the first 5 months of 2015 prior to Talen Energy’s acquisition, adjusts for PPL allocated costs incurred prior to the Talen Energy spinoff not expected to continue in

future periods, and excludes results from MACH Gen for November and December of 2015 following Talen Energy’s acquisition

($ in millions)

($ in millions)

(1) (1)

$898

$40

($179)

$1,080

$56

($134)

2014 2015


2016 Adjusted EBITDA $635 - 835

Capex (excluding growth) (433)

Interest (cash) (223)

Nuclear Fuel Amortization 143

Taxes (cash) 102

Working Capital / Other 26

2016 Adjusted FCF $250 - 450

$1,082

$635 - 835

($142)

($165)

($20) ($20)

2015AdjustedEBITDA

MitigatedAssets

Margins O&M Other 2016AdjustedEBITDA

2016 Outlook

2015 to 2016 Adjusted EBITDA Walk


(1) Includes full year 2015 results from RJS Power including the first 5 months of 2015 prior to Talen Energy’s acquisition, adjusts for PPL Corporation allocated costs incurred prior to the Talen Energy

spinoff not expected to continue in future periods, and excludes results from MACH Gen for November and December of 2015 following Talen Energy’s acquisition

(2) Reflects actual 2015 results from assets Talen Energy has sold or has announced it will sell in 2016

(3) Includes $15 million of capitalized interest related to capital expenditures classified as growth projects, which was previously excluded from the calculation of Adjusted Free Cash Flow

(4) Excluding capitalized interest, which is reflected in capex

Key Assumptions/Drivers to 2016 Estimates

(2)

(1)

($ in millions)

2016 Adjusted Free Cash Flow Guidance

Adjusted EBITDA:

Assume no EBITDA contributions from assets sold in

conjunction with FERC mitigation

Ironwood & Crane closed in February; East hydro

close expected late March

Margins expected to decline:

Lower expected realized energy prices

Lower capacity prices

Partially offset by addition of MACH Gen

O&M is higher year-over-year:

Lower costs from resource optimization and

efficiency

Offset by addition of MACH Gen and timing of major

outages vs. prior year (primarily fossil fleet)

Adjusted Free Cash Flow:

Asset sales enable use of additional tax benefits:

Bonus depreciation

Acquired NOLs

(3)

(4)

($ in millions)


$260

$250 - 450

$135 $45

$35

($110)

($15)

2016Adjusted

FCF (PriorMidpoint)

EBITDADrivers

Taxes(cash)

Capex Pension/Other

Change inPresentation

Basis

2016Adjusted

FCF

$845 $635 - 835

$70 $10

($190)

2016 AdjustedEBITDA

(Prior Midpoint)

Margins O&M Other 2016 AdjustedEBITDA

2016 Comparison to Prior Estimates

Change in 2016 Adjusted EBITDA Estimate


(1) Based on prior guidance

(2) Includes $15 million of capitalized interest related to capital expenditures classified as growth projects, which was previously excluded from the calculation of Adjusted Free Cash Flow

Primary Drivers to Change in Estimate ($ in millions)

2016 Adjusted Free Cash Flow Estimate

Adjusted EBITDA:

Margins expected to decline:

Lower expected realized energy prices driven by

natural gas prices and basis

Partially offset by change in outage schedule and

acceleration of Brunner Island co-fire availability

O&M cost reductions:

Reduced outage scope for fossil fleet

Cost optimization throughout the company

Adjusted Free Cash Flow:

Non-growth capital expenditure reductions

Extension of bonus depreciation and additional

NOL utilization improve FCF projections

(2)

(1)

(1)

Cut O&M ($70 million) and Capex ($45 million)

in response to lower margins

($ in millions)


$1,220

$526

$758

$500

$55

$396

$611

Sources Uses

3.0x

5.0x

2016E

3.0x

5.0x

2015

Projected

Cash

Total

Planned Capex

2016

Maturities

Revolver

Repayment

De-lever balance sheet with proceeds from

asset sales

- Paid down revolver balance in February 2016, drawn

primarily to finance a portion of the MACH Gen

transaction

- Reviewing various liability management options

including maturing and pre-payable debt

Assess growth opportunities to further diversify

the portfolio and drive long-term value

Enhance portfolio via value-accretive projects

- Coal plant co-firing

- Harquahala optimization

- Possible uprates at Athens & Millennium

Capital allocation decisions with regard to

projected cash position to be made following:

- Hydro sale to Brookfield closes (targeting end of

March) and;

- Complete Montour gas co-fire project evaluation

Capital Allocation Capital Priorities 2016 Planned Sources & Uses

4.8x

(1) Return of restricted cash

(2) Repaid in February 2016

4.3x

Mitigation proceeds provide cash available to extinguish

maturing, pre-payable and other currently discounted debt

Maintaining the Leverage Lane

Cash from

Operations

Net

Asset Sale

Proceeds

(1)

Well within portfolio Net Debt/Adjusted EBITDA leverage lane

despite the recent decline in commodity prices

(2)

($ in millions)


The current commodity and high yield environment has pressured Talen Energy’s bond prices

Multiple tranches of debt currently trade at prices well below par

Maturities beyond 2018 average a discount of over 30%

Talen Energy will continue to assess market conditions and alternatives to manage upcoming maturities,

reduce interest expense and optimize its debt structure, including, but not limited to, potential de-

levering strategies

Deeply Discounted Debt Complex

Market Prices as of February 19, 2016:

Potential to retire debt at discounts could generate attractive returns and

improve the credit profile of the company

(1)

Source: Bloomberg, Talen Energy

(1) Based on a weighted average discount to par

(2) Actual coupon is 4.625% after a rate step-down following the spinoff of Talen Energy

($ in millions)

Price YTW Par Market % Discount

TES - 6.2% due 2016 $99.75 7.2% $350 $349 0.2%

TES - 6.5% due 2018 93.50 9.9% 400 374 6.5%

TES - 5.125% due 2019 78.00 12.8% 1,220 952 22.0%

TES - 4.6% due 2021 60.50 15.0% 712 431 39.5%

TES - 6.5% due 2025 68.00 12.4% 600 408 32.0%

TES - 6.0% due 2036 38.00 16.8% 200 76 62.0%

(2)


Talen Energy Investment Thesis

Portfolio with diverse fuel mix and geographic diversity

Over 80% of generation assets are located in markets that offer capacity

revenue (PJM, NYISO and ISO-NE)

History of high reliability with forced outage factors below industry

averages (2015 average less than 4% EFOF across entire fleet)

Quality

Assets in Key

Markets

Strategic Focus

on Long-Term

Value

Compelling

Valuation &

Significant

Liquidity

Visible Value

Catalysts on the

Horizon

Positioning portfolio to be more balanced with gas via strategic activity

Added 2,500 MW of CCGTs with MACH Gen acquisition in 4Q 2015

Projects to co-fire up to ~3,000 MW of coal generation on natural gas

with access to low priced gas in the Marcellus region

Currently trading at a discount to recent observable transaction prices,

peer multiples and historical multiple levels

Expected 2016 Free Cash Flow Yield over 45%

Talen Energy has over $3 billion of unused liquidity capacity

$1.2 billion of total net proceeds from asset sales

Co-fire projects expected to add value to PJM coal fleet in 2017-2018

Potential for operational improvements at Keystone/Conemaugh

Optimization of >1,000 MW Harquahala CCGT expected in 2017

(1) Based on midpoint of 2016 Adjusted Free Cash Flow guidance and market prices as of February 19, 2016

(2) As of December 31, 2015

(1)

(2)


Supplemental Information


Quarter-to-date

Q4 2015 Q4 2014 Q4 2015 Q4 2014 Q4 2015 Q4 2014 Q4 2015 Q4 2014

East:Coal - PJM 2,698 3,690 20.3% 27.8% 77.5% 75.8% 0.9% 1.1%

Hydro 191 166 29.6% 25.7% 90.6% 84.0% 0.0% 0.1%

Natural Gas Combined Cycle 2,449 2,359 92.6% 88.6% 88.0% 84.5% 2.0% 1.3%

Natural Gas/Oil 1,313 846 21.0% 13.5% 75.3% 66.4% 3.8% 21.2%

Nuclear 4,815 4,908 97.1% 99.0% 95.1% 96.0% 4.3% 0.1%

West:Coal - Montana 1,006 1,186 86.1% 79.3% 91.6% 89.2% 6.8% 4.5%

Natural Gas 696 717 18.7% 17.4% 89.9% 81.9% 0.6% 14.6%

TOTAL GENERATION 13,169 13,873 40.2% 41.6% 82.9% 79.3% 2.2% 6.6%

Year-to-date

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

East:Coal - PJM 21,312 22,705 40.5% 43.1% 84.0% 83.0% 1.5% 2.2%

Hydro 903 931 35.2% 36.3% 96.5% 83.8% 0.1% 1.5%

Natural Gas Combined Cycle 9,430 9,411 89.7% 89.4% 88.5% 88.7% 1.9% 3.2%

Natural Gas/Oil 5,796 3,705 23.5% 15.1% 82.1% 84.8% 3.4% 7.1%

Nuclear 18,505 16,903 94.1% 85.6% 92.1% 84.1% 1.1% 0.3%

West:

Coal - Montana 3,776 4,029 77.5% 67.9% 88.5% 82.4% 6.0% 10.1%

Natural Gas 3,349 3,440 21.2% 21.1% 81.9% 83.9% 3.8% 5.9%

TOTAL GENERATION 63,071 61,125 48.3% 46.2% 85.5% 84.1% 2.3% 3.5%

Net Generation (GWh) Capacity Factor Availability

EFOF

EFOF

Net Generation (GWh) Capacity Factor Availability

Operational Statistics

(1) Results do not reflect MACH Gen assets, which were acquired in November 2015 or Montana hydro assets, which were sold in November 2014. Includes results from assets Talen Energy has sold

or has announced it will sell in 2016

(2) Reflects a full 12 months of RJS results for comparative purposes. The RJS assets were acquired in June 2015 as part of the spinoff transaction

(3) Q4 2014 and YTD results include Corette coal facility in Montana, which was retired in March 2015

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

(5) EFOF – Equivalent Forced Outage Factor

(1)(2)

(1)

(3)

(3)

(4)

(4)

(5)

(5)


$233

$305 $295 $257

$220

$82

$114 $132

$137

$143

$108

$3 $1

$1

$54

$15 $20

$17

$14

$17

$15 $16

$50

$39

$26

$26 $8 $1

$-

$6

$6 $7 $6

$6

$526

$484 $479 $469

$422

2016 2017 2018 2019 2020

Sustenance Nuclear Fuel Growth Information Technology Environmental Regulatory Discretionary

Projected Capital Expenditures ($ in millions)

Note: Excludes projected capital expenditures related to assets Talen Energy has sold or has announced it will sell in 2016

(1) Reflects Talen Energy’s best estimate of environmental capital expenditures that may be required within the next five years. Actual costs may be significantly lower or higher depending of the

final compliance expenses, which are not now determinable, but could be significant.

(1)


Cash & cash posted for collateral 247$ 714$

Liquidity facility commitments 3,810 2,350

Total Liquidity 4,057$ 3,064$

Less: Current liquidity facility usage 856 334

Total Available Liquidity 3,201$ 2,730$

($ in millions) 12/31/2015 9/30/2015

Liquidity

Available Liquidity Liquidity Facilities

($ millions)

Talen Energy has substantial liquidity to support asset optimization

(1)

As of December 31, 2015

Facility Expiration Date Capacity

Letters of Credit /

Lien-Based Borrowed

Unused

Capacity

Cash $247 $0 $0 $247

CDS Backed Jun-17 $500 $0 $0 $500

MACH Gen Revolver Jul-21 $160 $31 $108 $21

Secured Trading Dec-20 $1,300 $54 $0 $1,246

Talen Revolver Jun-20 $1,850 $163 $500 $1,187

Total $4,057 $248 $608 $3,201


2021

Talen Energy Supply, LLC 2016 2017 2018 2019 2020 & Beyond

Senior Notes: Maturity (yr)

Talen ES 6.20% 2016 350 - - - - -

Talen ES 6.50% 2018 - - 400 - - -

Talen ES 5.125% 2019 - - - 1,220 - -

Talen ES 4.60% 2021 - - - - - 712

Talen ES 6.50% 2025 - - - - - 600

Talen ES 6.00% 2036 - - - - - 200

Total Senior Notes 350 - 400 1,220 - 1,512

Municipal Bonds: Maturity (yr)

Talen ES variable-rate Series A 2038 - - - - - 100

Talen ES variable-rate Series B 2038 - - - - 50

Talen ES variable-rate Series C 2037 - - - - 81

Total Municipal Bonds - - - - 131 100

Talen Ironwood, LLC Maturity (yr)

Talen Ironwood 8.857% 2025 41 - - - - -

New MACH Gen, LLC Maturity (yr)

Term Loan B 2022 5 5 24 24 48 368

Total Maturities 396 5 424 1,244 179 1,980

Long-term Debt Maturities

Note: As of December 31, 2015

(1) Actual coupon is 4.625% after a rate step-down following the spinoff of Talen Energy

(2) Bonds are subject to mandatory repurchase and optional remarketing in 2020

(3) Bonds were redeemed in January 2016 in connection with the sale of Ironwood

(4) Includes principal amortization

($ in millions)

(3)

(2)

(2)

(4)

(1)


Talen Energy Corporate Structure

Talen Energy Corporation

(NYSE: TLN)

Talen Energy Holdings, Inc.

Talen Energy Supply, LLC

Legacy Energy

Supply Subs

RJS

Subs

$3,713mm Senior Unsecured Notes Outstanding

As of December 31, 2015

Note: Reflects Talen Energy capital structure following the sale of Ironwood in February 2016. $41 million of senior secured debt was redeemed in January in connection with the sale

(1) Debt is non-recourse to Talen Energy entities other than the MACH Gen entities

MACH Gen LLC

$474mm MACH Gen Term Loan B (1)

(in millions)

First Lien New MACH Gen Term Loan B 474$

Senior Unsecured Talen Energy Supply Notes 3,713

Total Long-Term Debt 4,187$


Talen Energy Asset Overview

Note: Reflects the sale of Ironwood and C.P.Crane which occurred in Q1 2016

(1) Announced sale of Eastern Hydro plants (Holtwood and Wallenpaupack) on 10/8/2015, which is expected to close in March 2016

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

East Assets

Nuclear, Coal & Hydro

Susquehanna PA Nuclear 90% N/A 2,262 1983 - 1985 PJM-MAAC

Brandon Shores MD Coal 100% 10,252 1,274 1984 - 1991 PJM-SWMAAC

Brunner Island PA Coal 100% 9,842 1,428 1961 - 1969 PJM-MAAC

Conemaugh PA Coal 16% 9,700 285 1970 - 1971 PJM-RTO

Keystone PA Coal 12% 9,600 212 1967 - 1968 PJM-RTO

Montour PA Coal 100% 9,661 1,528 1972 - 1973 PJM-MAAC

H.A. Wagner MD Coal/NG/Oil 100% 10,663 966 1956 - 1972 PJM-SWMAAC

Eastern Hydro(1)

PA Hydro 100% N/A 308 1910 - 1926 PJM-MAAC

Natural Gas / Oil

Athens NY Natural Gas 100% 7,100 969 2004 NYISO

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) 82 1996 ISO-NE

Elmwood Park NJ Natural Gas/Oil 100% 9,500 70 1989 PJM-PS North

Lower Mt. Bethel PA Natural Gas 100% 7,170 555 2004 PJM-MAAC

Martins Creek 3&4 PA Natural Gas/Oil 100% 11,744 (Gas) / 10,676 (Oil) 1,708 1975 - 1977 PJM-MAAC

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

Newark Bay NJ Natural Gas/Oil 100% 8,680 122 1993 PJM-PS North

Pennsylvania Peakers PA Natural Gas/Oil 100% Various 370 1967 - 1973 PJM

Pedricktown NJ Natural Gas/Oil 100% 8,455 117 1992 PJM-EMAAC

York PA Natural Gas 100% 9,551 46 1989 PJM-MAAC

Renewables

Renewables PA Renewable 100% Various 7 Various PJM-MAAC

East Subtotal 12,954

West Assets

Natural Gas / Oil

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

Harquahala AZ Natural Gas 100% 7,100 1,040 2004 WECC

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

Coal

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

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

West Subtotal 3,362

Total Talen 16,316


Regulation G Reconciliations

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

Note: Please refer to Regulation G Reconciliation footnotes for quarter-to-date and year-to-date EBITDA on slide 29

Three Months Ended December 31,

2015 2014

East West Other Total East West Other Total

Net income (loss) $ (62 ) $ 362

(Income) loss from discontinued operations (net of tax) — (213 )

Interest expense 65 29

Income taxes (38 ) 100

Other (income) expense - net 129 (7 )

Operating income (loss) $ 165 $ (16 ) $ (55 ) $ 94 $ 283 $ 39 $ (51 ) $ 271

Depreciation 83 13 1 97 71 1 — 72

Other income (expense) - net 7 (2 ) (134 ) (129 ) 7 — — 7

EBITDA $ 255 $ (5 ) $ (188 ) $ 62 $ 361 $ 40 $ (51 ) $ 350

Unrealized (gain) loss on derivative contracts (a) (55 ) 8 — (47 ) (187 ) (22 ) — (209 )

Stock-based compensation expense (b) — — (1 ) (1 ) — — 3 3

(Gain) loss from NDT funds (4 ) — — (4 ) (5 ) — — (5 )

ARO accretion 8 1 — 9 9 — — 9

Impairments (d) 66 — — 66 — — — —

REPS Remarketing — — 134 134 — — — —

Transition services agreement costs — — 10 10 — — — —

Separation benefits (f) — — — — — — 3 3

RJS transaction costs — — 14 14 — — — —

Restructuring costs (j) — — 2 2 — — 1 1

Other (k) (8 ) — — (8 ) 2 — — 2

Adjusted EBITDA $ 262 $ 4 $ (29 ) $ 237 $ 180 $ 18 $ (44 ) $ 154



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

Note: Please refer to Regulation G Reconciliation footnotes for quarter-to-date and year-to-date EBITDA on slide 29

Year Ended December 31,

2015 2014

East West Other Total East West Other Total

Net income (loss) $ (341 ) $ 410 (Income) loss from discontinued operations (net of

tax) —

(223 )

Interest expense 211 124

Income taxes (27 ) 116

Other (income) expense - net 118 (30 )

Operating income (loss) $ 198 $ 2 $ (239 ) $ (39 ) $ 558 $ 71 $ (232 ) $ 397

Depreciation 327 26 3 356 296 1 — 297

Other income (expense) - net 19 (2 ) (135 ) (118 ) 29 — 1 30

EBITDA $ 544 $ 26 $ (371 ) $ 199 $ 883 $ 72 $ (231 ) $ 724

Unrealized (gain) loss on derivative contracts (a) (175 ) 25 — (150 ) 15 (32 ) — (17 )

Stock-based compensation expense (b) — — 40 40 — — 18 18

(Gain) loss from NDT funds (15 ) — — (15 ) (26 ) — — (26 )

ARO accretion 33 1 — 34 32 — — 32

Coal contract adjustment (c) 41 — — 41 — — — —

Impairments (d) 657 — — 657 — — — —

REPS Remarketing — — 134 134 — — — —

Mechanical subsidiary revenue adjustment (e) — — — — (17 ) — — (17 )

Transition service agreement costs — — 29 29 — — — —

Separation benefits (f) — — 2 2 — — 33 33

Corette closure costs (g) — 4 — 4 — — — —

Terminated derivative contracts (h) (13 ) — — (13 ) — — — —

Revenue adjustment (i) 7 — — 7 — — — —

Transaction costs — — 20 20 — — — —

Restructuring costs (j) — — 12 12 — — 1 1

Other (k) 1 — — 1 11 — — 11

Adjusted EBITDA $ 1,080 $ 56 $ (134 ) $ 1,002 $ 898 $ 40 $ (179 ) $ 759

MACH Gen, RJS and PPL Allocations (l) 80

Adjusted EBITDA (Guidance) $ 1,082



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

(a) Represents unrealized gains (losses) on derivatives. Amounts have been adjusted for option premiums of $8 million and $(10) million

for 2015 and 2014.

(b) 2015 includes a charge for the acceleration of expense as a result of the spinoff. 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.

(c) To mitigate the risk of oversupply, Talen Energy incurred pre-tax charges of $41 million in 2015 in connection with an agreement to

reduce its contracted coal deliveries.

(d) 2015 includes charges for goodwill and certain long-lived assets. 2013 includes a charge for the Corette plant and related emission

allowances.

(e) In 2014, Talen Energy recorded $17 million to "Energy-related businesses" revenues related to prior periods and the timing of revenue

recognition for a mechanical contracting and engineering subsidiary.

(f) 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 of $17 million were recorded. In addition, 2014 includes

separation costs of $16 million related to the spinoff transaction.

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

(h) Represents net realized gains on certain derivative contracts that were early-terminated due to the spinoff transaction.

(i) 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.

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

(k) All periods include OCI amortization on non-active derivative positions and 2015 includes a gain on the sale of the renewable energy

business.

(l) Includes performance from RJS and removes PPL allocations for the five month period prior to spinoff and removes two months of

performance from MACH Gen.



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

(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

(c) Includes performance from RJS and removes PPL allocations for the five month period prior to spinoff and removes two months of performance

from MACH Gen

Year Ended December 31,

2015 2014

Cash from Operations $ 768 $ 462

Capital Expenditures, excluding growth (491 ) (447 )

Counterparty collateral paid (received) (63 ) 17

Adjusted Free Cash Flow, including other adjustments 214

32

Cash adjustments (after tax):

Coal contract adjustment 25 —

MACH Gen Bridge Financing 4 —

Tax related to gain on sale of Renewables 28 —

Tax related to gain on sale of Montana hydro business — 176

Transition Services Agreement costs 17 —

Insurance proceeds 4 —

Separation benefits 1 20

Corette closure costs (a) 2 —

RJS transaction costs 12 —

Restructuring costs (b) 7 1

Adjusted Free Cash Flow $ 314 $ 229

MACH Gen, RJS and PPL allocations (c) 89

Adjusted Free Cash Flow (Guidance) $ 403


Low - 2016EMidpoint -

2016E High - 2016E

Net Income/(Loss) $ (44) $ 16 $ 76

Income Taxes (36) 4 44

Interest Expense 223 223 223

Depreciation & Amortization 409 409 409

EBITDA 552 652 752

Non-Cash Compensation 12 12 12

ARO 40 40 40

MTM losses (gains) - - -

NDT losses (gains) (10) (10) (10)

Adjusted EBITDA, including other adjustments 594 694 794

Other adjustments:

TSA costs 41 41 41

Other - - -

Adjusted EBITDA 635 735 835


Adjusted EBITDA Forecast ($ in millions)


Low - 2016E

Midpoint -

2016E High - 2016E

Cash from Operations $ 678 $ 758 $ 838

Capital Expenditures, excluding growth (453) (433) (413)

Adjusted Free Cash Flow, including other adjustments 225 325 425

Cash adjustments (after tax):

TSA costs & allocations 25 25 25

Other - - -

Adjusted Free Cash Flow $ 250 $ 350 $ 450


Adjusted Free Cash Flow Forecast ($ in millions)

(a) Includes allocated capitalized interest associated with growth capital expenditures of $15 million. This capitalized interest was previously excluded from the

calculation of Adjusted Free Cash Flow

(a)


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

or Margin results, net debt, cash flows, tax attributes, financing, regulation and corporate strategy are "forward-looking statements" within the meaning

of the federal securities laws. 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. Although Talen Energy 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: adverse economic conditions; changes in commodity prices and related costs; the effectiveness of

Talen Energy's risk management techniques, including hedging; accounting interpretations and requirements that may impact reported results;

operational, price and credit risks in the wholesale and retail electricity markets; Talen Energy's ability to forecast the actual load needed to perform full-

requirements sales contracts; weather conditions affecting generation, customer energy use and operating costs and revenues; disruptions in fuel

supply; unforeseen circumstances that may impact the levels of coal inventory that are held; the performance of transmission facilities and any changes

in the structure and operation of, or the pricing limitations imposed by, the RTOs and ISOs that operate those facilities; blackouts due to disruptions in

neighboring interconnected systems; competition; federal and state legislation and regulation; costs of complying with environmental and related worker

health and safety laws and regulations; the impacts of climate change; the availability and cost of emission allowances; changes in legislative and

regulatory policy; security and safety risks associated with nuclear generation; Talen Energy's level of indebtedness; the terms and conditions of debt

instruments that may restrict Talen Energy's ability to operate its business; the performance of Talen Energy's subsidiaries and affiliates, on which its

cash flow and ability to meet its debt obligations largely depend; the risks inherent with variable rate indebtedness; disruption in financial markets; Talen

Energy's ability to access capital markets; acquisition or divestiture activities, including the pending sale of the Holtwood and Lake Wallenpaupack

plants, and Talen Energy's ability to realize expected synergies and other benefits from such business transactions, including in connection with the

completed MACH Gen acquisition; changes in technology; any failure of Talen Energy's facilities to operate as planned, including in connection with

scheduled and unscheduled outages; Talen Energy's ability to optimize its competitive power generation operations and the costs associated with any

capital expenditures, including the Brunner Island dual-fuel project; significant increases in operation and maintenance expenses; the loss of key

personnel, the ability to hire and retain qualified employees and the impact of collective labor bargaining negotiations; war, armed conflicts or terrorist

attacks, including cyber-based attacks; risks associated with federal and state tax laws and regulations; any determination that the transaction that

formed Talen Energy does not qualify as a tax-free distribution under the Internal Revenue Code; Talen Energy's 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;

costs of complying with reporting requirements as a newly public company and any related risks of deficiencies in disclosure controls and internal

control over financial reporting as a standalone entity; and the ability of affiliates of Riverstone Holdings, LLC, to exercise influence over matters

requiring Board of Directors and/or stockholder approval. 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 Nov.

3, 2015, as supplemented, Form 10-Q for the quarter ended September 30, 2015 and its other reports on file with the Securities and Exchange

Commission.


EBITDA as presented in this presentation represents net income (loss) before interest expense, income taxes, depreciation and certain

amortization. Adjusted EBITDA represents EBITDA further adjusted for certain non-cash and other items that management believes are not

indicative of ongoing operations, including, but not limited to, 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, impairments, gains or

losses on sales, dispositions or retirements of assets, debt extinguishments, and transition, transaction and restructuring costs. EBITDA and

Adjusted EBITDA 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. Talen Energy believes

EBITDA and Adjusted EBITDA are useful to investors and other users of its financial statements in evaluating its operating performance because

they provide additional tools to compare business performance across companies and across periods. Talen Energy believes 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, it believes 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.

Talen Energy adjusts for these and other items, as its management believes that these items would distort their ability to efficiently view and

assess its core operating trends. In summary, Talen Energy’s 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 its Board of

Directors, shareholders, creditors, analysts and investors concerning its financial performance.

Adjusted Free Cash Flow as presented in this presentation represents Cash from Operations less capital expenditures, excluding growth-related

capital expenditures, adjusted for changes in counterparty collateral and further adjusted for after-tax transaction and restructuring costs, and

certain other after-tax cash items that management believes are not indicative of ongoing operations. Adjusted Free Cash Flow should not be

considered an alternative to Cash from Operations, which is determined in accordance with GAAP. Talen Energy believes 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. These measures are not

necessarily comparable to similarly-titled measures reported by other companies as they may be calculated differently.

Net debt as presented in this presentation represents total debt less cash and cash equivalents.

Definitions of Non-GAAP Financial Measures

Documents

Talen EnergyEnergy+Investor... · - Increased run-rate target to $165 - $175 million Added scale and fuel and geographic diversity to the portfolio with MACH Gen acquisition (2,500