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TRANSCRIPT
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.
© Talen Energy Corporation 2015 3
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)
© Talen Energy Corporation 2015 4
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)
© Talen Energy Corporation 2015 5
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)
© Talen Energy Corporation 2015 6
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:
© Talen Energy Corporation 2015 7
$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)
© Talen Energy Corporation 2015 8
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)
© Talen Energy Corporation 2015 9
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 $170 million in projected short-term debt outstanding
(1) (2)
(3)
(4)
© Talen Energy Corporation 2015 10
($ 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 Corporation 2015 11
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
© Talen Energy Corporation 2015 12
Supplemental Information
© Talen Energy Corporation 2015 13
$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
© Talen Energy Corporation 2015 14
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)
© Talen Energy Corporation 2015 15
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)
© Talen Energy Corporation 2015 16
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)
© Talen Energy Corporation 2015 17
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%
Net Generation (GWh) Capacity Factor EAF
EFOF
EFOF
Net Generation (GWh) Capacity Factor EAF
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)
© Talen Energy Corporation 2015 18
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)
© Talen Energy Corporation 2015 19
($ 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)
© Talen Energy Corporation 2015 20
$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)
© Talen Energy Corporation 2015 21
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)
© Talen Energy Corporation 2015 22
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)
© Talen Energy Corporation 2015 23
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
© Talen Energy Corporation 2015 24
Regulation G Reconciliations
Quarter-to-date Adjusted EBITDA (2014) ($ 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, 2014
East West Other Total
Net income (loss) $ 13
(Income) loss from discontinued operations (net of tax) .............. (11 )
Interest expense ................................................................ 32
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
(Gain) loss from nuclear decommissioning trust funds ................ (5 ) — — (5 )
Asset retirement obligation accretion ...................................... 7 — — 7
Separation benefits (e) ........................................................ — 22 22
Other (i) .......................................................................... 1 — — 1
Adjusted EBITDA $ 170 $ — $ (44 ) $ 126
© Talen Energy Corporation 2015 25
Regulation G Reconciliations
Year-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
Six Months Ended June 30, 2015
East West Other Total
Net income (loss) $ 122 (Income) loss from discontinued operations (net of tax) .............. (1 )
Interest expense ................................................................ 91
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 )
Stock-based compensation expense (c) ................................... — — 40 40
(Gain) loss from nuclear decommissioning trust funds ................ (10 ) — — (10 )
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
© Talen Energy Corporation 2015 26
Regulation G Reconciliations
Year-to-date Adjusted EBITDA (2014) ($ in millions)
Note: Please refer to Regulation G Reconciliation footnotes for quarter-to-date and year-to-date EBITDA on slide 27
Six Months Ended June 30, 2014
East West Other Total
Net income (loss) $ (53 )
(Income) loss from discontinued operations (net of tax) .............. (3 )
Interest expense ................................................................ 64
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
Stock-based compensation expense (c) ................................... — — 12 12
(Gain) loss from nuclear decommissioning trust funds ................ (11 ) — — (11 )
Asset retirement obligation accretion ...................................... 15 — — 15
Separation benefits (d) ........................................................ — — 22 22
Other (i) .......................................................................... 4 — — 4
Adjusted EBITDA $ 453 $ — $ (92 ) $ 361
© Talen Energy Corporation 2015 27
Regulation G Reconciliations
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 $9 million for the three and six months ended June 30, 2015 and
insignificant amounts for the same periods in 2014.
(c) For periods prior to June 2015, represents the portion of PPL's stock-based compensation cost
allocable to Talen Energy. Amounts for the 2014 periods were cash settled with a former affiliate.
(d) In June 2014, Talen Energy Supply's largest IBEW local ratified a new three-year labor agreement.
In connection with the new agreement, estimated bargaining unit one-time voluntary retirement
benefits were recorded.
(e) Operations were suspended and the Corette plant in Montana was retired in March 2015.
(f) Represents net realized gains on certain derivative contracts that were early-terminated due to the
spinoff transaction.
(g) Relates to a prior period revenue adjustment for the receipt of revenue under a transmission
operating agreement with Talen Energy Supply's former affiliate, PPL Electric Utilities Corporation.
(h) Costs related to the spinoff transaction, including FERC-required mitigation plan expenses and
legal and professional fees.
(i) All periods include other comprehensive income amortization on non-active derivative positions
and the 2015 periods include an asset write-off.
© Talen Energy Corporation 2015 28
Regulation G Reconciliations
Year-to-Date Adjusted Free Cash Flow ($ 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.
© Talen Energy Corporation 2015 29
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
Regulation G Reconciliations
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 $35 million of TSA costs that are not expected to continue in future periods
(e) Restructuring costs that are not expected to continue in future periods
(b)(c) (a) (a) (a)
© Talen Energy Corporation 2015 30
Regulation G Reconciliations
Adjusted Free Cash Flow Forecast ($ 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)
© Talen Energy Corporation 2015 31
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.
© Talen Energy Corporation 2015 32
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
© Talen Energy Corporation 2015 33
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