THIRD QUARTER 2017 REVIEW NOVEMBER 1, 2017 FORWARD-LOOKING - - PowerPoint PPT Presentation

NOVEMBER 1, 2017

THIRD QUARTER 2017 REVIEW

FORWARD-LOOKING STATEMENTS

Cautionary S ry Statement R Regard arding ng F Forw rward rd-Looki king ng S Statement nts

This presentation contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward looking statements.” You can identify these statements by the fact that they do not relate strictly to historical or current facts. Management cautions that any or all of Dynegy’s forward- looking statements may turn out to be wrong. Please read Dynegy’s annual, quarterly and current reports filed under the Securities Exchange Act of 1934, including its 2016 Form 10-K and first, second and third quarter 2017 Forms 10-Q, when filed, for additional information about the risks, uncertainties and other factors affecting these forward-looking statements and Dynegy generally. Dynegy’s actual future results may vary materially from those expressed or implied in any forward-looking statements. All of Dynegy’s forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward- looking statements. In addition, Dynegy disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

No Non-GAAP F Fina nancial M Measure sures

This presentation contains non-GAAP financial measures including EBITDA, Adjusted EBITDA and Adjusted Free Cash

• Flow. Reconciliations of these measures to the most directly comparable GAAP financial measures to the extent

available without unreasonable effort are contained herein. To the extent required, statements disclosing the definitions, utility and purposes of these measures are set forth in Item 2.02 to our current report on Form 8-K filed with the SEC on November 1, 2017, which is available on our website free of charge, www.dynegy.com.

2

TABLE OF CONTENTS I. Overview and Outlook II. Operations and Commercial Activities III. Third Quarter 2017 Financial Results IV. Summary

3

4

OVERVIEW AND OUTLOOK

• Top decile safety performance for second quarter in a row
• Generated 34.2 MM MWh in 3Q 2017, Dynegy record for quarterly generation
• PJM CCGT fleet continues its outstanding performance with a 1.2% Equivalent Unplanned

Outage Factor for 3Q 2017

REAFFIRMING 2017 GUIDANCE

• Reaffirming 2017 Adjusted EBITDA guidance range of $1,200 – 1,400 MM
• Reaffirming 2017 Adjusted Free Cash Flow guidance range of $300 – 500 MM
• M&A timing and asset sales have impacted 2017 Adjusted EBITDA by ~$70 million
• Dighton and Milford (MA) sale closed in September, generating proceeds of ~$125 MM ($119

MM purchase price plus working capital adjustment)

• Lee sale closed in October, generating proceeds of ~$180 MM
• Awaiting final approval for purchase of AES’ ownership interests in Miami Fort and Zimmer,

expected by year-end

• 3Q 2017 Net Loss of $133 MM versus $249 MM Net Loss for 3Q 2016
• 3Q 2017 Adjusted EBITDA of $397 MM versus $350 MM for 3Q 2016
• Repaid / refinanced $1.25 billion of 2019 bonds, $200 million of Term Loan C and $300

million of revolver borrowings

(1) Note: Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures; reconciliations to GAAP can be found in the Appendix

OPERATIONAL HIGHLIGHTS PORTFOLIO UPDATES FINANCIAL HIGHLIGHTS

OPERATIONS AND COMMERCIAL OVERVIEW

5.0 4.6 5.0 4.6 4.2 3.4 4.2 3.4 9.7 9.5 5.4 5.0 15.1 14.5 5.0 5.7 0.4 5.4 5.7 0.5 1.0 0.5 1.0 3.9 1.1 5.0

3Q16 3Q17 3Q16 3Q17 3Q16 3Q17 IPH MISO PJM NY/NE CAISO ERCOT Coal Gas

(1) Excludes corporate and retail personnel; (2) 3Q16 excludes Casco Bay (Facility was under a tolling arrangement which expired 12/31/16); (3) Excludes Brayton Point; (4) Cooling

Degree Days based on National Oceanic and Atmospheric Association (NOAA) data

70% 66% 56% 67%

Gas (CCGT) Coal 3Q16 3Q17 1.97 1.05 0.98 1.34 0.85 0.78 Gas Coal Total 3Q16 3Q17

OPERATIONS SUMMARY

6 2016 EEI top-decile TRIR (1.09)

Rac achel C Cas asey Safety Performance - Total Recordable Incident Rate (TRIR) Net Capacity Factors Generation Volumes (MM MWh) Operations Update Total D Dynegy Saf Safety ty P Performance i in th the Top De Decil ile f for Se Second Str Strai aight Q t Quar arter Generation V n Volum umes

• Gas fleet increased primarily due to the addition of the

ENGIE assets

• Coal fleet decreased primarily due to the shutdown of

Brayton Point, Baldwin unit 3 and sale of Conesville

Net t Cap apac acity F Fac acto tors

• Gas fleet decreased primarily due to lower spark spreads

as a result of a decline in cooling degree days(4) driven by milder weather

• Coal fleet relatively flat quarter over quarter

(3) (2)

15.0 14.1 20.1 15.2

(1) (1)

30.2 34.2 Consolidated

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Dynegy’s PRIDE program continues to deliver results

PRIDE ENERGIZED (2016-2018)

PRIDE Energized EBITDA ($ MM) PRIDE Energized Balance Sheet ($ MM)

$135 $150

Goal Actual 2016

$200 $422

Goal Actual 2016

$65 $70

Goal Expected 2017

$50 $50

Goal Identified 2018

$100 $150

Goal Expected 2017

$100 $15

Goal Identified 2018

84% 87% 91% 100% 79% 100% 78% 73%

Financial/Physical Hedges Retail and Wholesale Contracts

61% 71% 41% 60% 63% 79% 54% 59%

Financial/Physical Hedges Retail and Wholesale Contracts

8

COMMERCIAL SUMMARY

(1) Hedge percentages for the balance of the year (June 30, 2017= 7/1/17 through 12/31/17 & Sep 30, 2017 = 10/1/17 through 12/31/2017 ); (2) Hedge percentages for the balance of

the year 10/1/17 through 12/31/17; Note: Hedge percentages take into account the announced retirements of Stuart and Killen as of their expected retirement dates

~45% ~50% ~5%

Gross Margin Distribution Unhedged Energy Margin Hedged Energy Margin Capacity/Retail/Tolls

Generati tion Volum umes Hedged (1

(1)

PJM NY/NE ERCOT MISO PJM NY/NE ERCOT MISO

68% 66% 1%

Gas Coal Volume Contracted and Priced Volume Contracted but Not Priced

Impact o t of H Hedges

• Hedge position and hedge value for balance of the year
• Hedge value represents value which should be added to a 9/30/17 open

valuation for modeling purposes to properly incorporate existing contracts

• Gross margin distribution for full year 2017

88% 97% 3%

Gas Coal Volume Contracted and Priced Volume Contracted but Not Priced

Fu Fuel Suppl pply Hedged a as o

• f 9/30

30/2017 (2)

2)

Impact o t of H Hedges

• Hedge position and hedge value for full year 2018
• Hedge value represents value which should be added to a 9/30/17 open

valuation for modeling purposes to properly incorporate existing contracts

• Gross margin distribution for full year 2018

~50% ~25% ~25%

Gross Margin Distribution Unhedged Energy Margin Hedged Energy Margin Capacity/Retail/Tolls

Hed edge Va e Value $1.46/MWh Hedge ge P Position ion 21.6 MM MWh Hed edge Va e Value $(0.10)/MWh Hedge ge P Position ion 79.1 MM MWh

2017 2018

Generati tion Volum umes Hedged Fu Fuel Suppl pply Hedged a as o

• f 9/30

30/2017

3Q 2017 FINANCIAL RESULTS

$(249) $(133) 3Q16 3Q17 $350 $397 3Q16 3Q17

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FINANCIAL SUMMARY

Net Loss ($ MM) Adjusted EBITDA Results ($ MM) Liquidity ($ MM) Net et Lo Loss

• Decrease in net loss primarily due to the contribution from

ENGIE assets and lower impairment charges, partially offset by a loss on sale of assets and a loss on the early extinguishment

• f debt

Ad Adju justed E EBI BITDA DA

• Increase primarily due to a $108 MM contribution from the

ENGIE assets, partially offset by lower spark spreads net of higher capacity revenues and lower O&M costs

Gui uidanc nce

• Reaffirming 2017 Adjusted EBITDA and Free Cash Flow

guidance; Adjusted EBITDA expected to be near the bottom of the range

Liquid idit ity

• Liquidity as of 9/30/2017 excludes $180 MM in cash proceeds

from the Lee sale received in October 2017

• Repaid the outstanding revolving credit facility balance of

$300 MM in October 2017

Financial Update

9/30/17 10/26/17 Revolving facilities and LC capacity $1,650 $1,650 Less: Outstanding revolver draws (300)

• Outstanding LCs

(405) (419) Revolving facilities and LC availability 945 1,231 Cash and cash equivalents 613 600 To Total L Liqu quidi dity $1,558 558 $1,831 831

Guidance ($ MM) 2017 Adj EBITDA 2017 Adj FCF $1,200 $1,400 $500 $300

(1) Note: Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures; reconciliations to GAAP can be found in the Appendix

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THIRD QUARTER SEGMENT PERFORMANCE

Adjusted EBITDA Changes by Segment

PJM PJM Q3 Contribution of ENGIE $26 MM Realized Energy Margin $(44) MM Capacity $30 MM O&M $7 MM Other $13 MM NY NY/NE NE Q3 Contribution of ENGIE $36 MM Capacity $14 MM Realized Energy Margin $(15) MM MI MISO Realized Energy Margin $(14) MM Capacity $4 MM O&M $5 MM IPH Realized Energy Margin $(41) MM Capacity $7 MM O&M $5 MM CAISO Realized Energy Margin $11 MM Capacity / Tolls $(20) MM O&M $3 MM

(1) Note: Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures; reconciliations to GAAP can be found in the Appendix

Three Months Ended Operating Income / (Loss) ($ MM)

3Q1 Q16 3Q1 Q17 PJM $29 $86 NY/NE (15) (30) ERCOT

• 50

MISO/IPH (91) 2 CAISO 10

• Other

(50) (50) Con

• nsol
• lidat

ated $(117) 117) $58 58

Three Months Ended Adjusted EBITDA ($ MM)

3Q1 Q16 3Q1 Q17 PJM $215 $243 NY/NE 55 92 ERCOT

• 46

MISO/IPH 66 33 CAISO 24 18 Other (10) (35) Con

• nsol
• lidat

ated $350 50 $397 97

12

REAFFIRMING 2017 GUIDANCE

(1)

(1) Reflects timing of actual cash payments under long-term service agreements; Note: Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures; reconciliations

to GAAP can be found in the Appendix

Current Guidance ($ MM)

2017 A 2017 Adjus usted E EBITDA $1, $1,20 200 – 1, 1,400 400 Cash Maintenance CapEx(1) (200) Environmental CapEx (10) Cash Interest (600) Other Cash Impacts (90) 2017 A 2017 Adjus usted F Free Ca Cash F Flow

• w

$300 $300 – 500 500

2017 Capital Allocation ($ MM)

Required Principal Amortization $(45) Uprate Investments (30) Mandatory Preferred Dividend (20) $(95) $(95)

Reaffirming 2017 Guidance

• Initial forecast used to set 2017 guidance included the

following assumptions: − Based on October 12, 2016 forward pricing − Assumed ENGIE closing completed in 2016 − Assumed a full year of activity for Troy, Armstrong, Dighton, Milford (MA) and Lee

• Current forecast used to reaffirm 2017 guidance reflects

the following assumptions: − Based on October 11, 2017 forward pricing − ~$70 MM reduction to Adjusted EBITDA for M&A differences compared to initial guidance forecast

• ~$20 MM impact for delayed ENGIE closing
• ~$35 MM impact for mid-year closing of the Troy

and Armstrong sale

• ~$15 MM impact for Sep/Oct closing of Dighton,

Milford (MA) and Lee

SUMMARY

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KE KEY T TAKE AKEAWAYS

Ach chiev eved top d deci ecile s e safet ety p per erformance for s seco econd consecu ecutive q quarter er PR PRIDE E Ene nergized g goals a ahead o

• f sc

f schedule fo for E r EBI BITDA a and nd balance s e sheet Nea ear t ter erm deb ebt m maturities es a addres essed ed t through a asset et s sale e procee eeds and r refinanc nancing ng 201 2017 Adjusted E EBITDA a and A d Adj djusted F Free C Cash F Flo low guidanc ance r ranges r reaffi ffirm rmed

APPENDIX

PJM GENERATION FACILITIES (as of 10/12/2017)

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Portfolio/Facility(1) Location Net Capacity(2) Primary Fuel/ Technology Type Power Curve Fuel Curve

PJM JM

Calum lumet Chicago, IL 380 Gas / CT NiHub Chicago CG Dicks C Creek eek Monroe, OH 155 Gas / CT AD Hub Columbia Gulf Fay ayette tte Masontown, PA 726 Gas / CCGT AD Hub Tetco M2 Hangin ging R g Rock Ironton, OH 1,430 Gas / CCGT AD Hub Tetco M2 Hopew ewel ell Hopewell, VA 370 Gas / CCGT PJM W Hub TCO Kendal all Minooka, IL 1,288 Gas / CCGT NiHub Chicago CG Kille llen* Manchester, OH 204 Coal / ST AD Hub IL Basin Kin incaid id Kincaid, IL 1,108 Coal / ST NiHub PRB Liber erty Eddystone, PA 607 Gas / CCGT PJM W Hub Tetco M3 Miami F i Fort

• rt*

North Bend, OH 653 Coal / ST AD Hub 25% IL Basin / 75% NAPP Miami F i Fort

• rt

North Bend, OH 77 Oil / CT AD Hub No Northea heaster ern McAdoo, PA 52 Waste Coal / ST PJM PPL Waste Coal Ontela laune unee Reading, PA 600 Gas / CCGT PJM W Hub Tetco M3 Plea easants Saint Marys, WV 388 Gas / CT AD Hub Dom South Richla land nd Defiance, OH 423 Gas / CT AD Hub Michcon Str tryke ker Stryker, OH 16 Oil / CT AD Hub Sayreville lle* Sayreville, NJ 170 Gas / CCGT JCPL Tetco M3 / Transco Zone 6

• ex. NYC

Stu tuar art* Aberdeen, OH 679 Coal / ST AD Hub IL Basin Washingt gton

• n

Beverly, OH 711 Gas / CCGT AD Hub Tetco M2 Zimmer er* Moscow, OH 971 Coal / ST AD Hub 25% IL Basin / 75% NAPP PJM Seg egmen ent T Total 11,008 008

NOTES: S: 1) Dynegy owns 100% of each unit listed except for those marked by an asterisk (*). Total Net Capacity set forth in this table for partially owned units includes only Dynegy’s proportionate share of that facility’s gross generating capacity 2) Unit capabilities are based on winter capacity ratings

ISO-NE, NY and ERCOT GENERATION FACILITIES (as of 10/12/2017)

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Portfolio/Facility(1) Location Net Capacity(2) Primary Fuel / Technology Type Power Curve Fuel Curve

ISO O - NE NE & & NYI NYISO

Be Bellingham am Bellingham, MA 566 Gas / CCGT Mass Hub Algonquin Bel ellingham NEA NEA* Bellingham, MA 157 Gas / CCGT Mass Hub Algonquin Bl Blac acks kstone Blackstone, MA 544 Gas / CCGT Mass Hub Tennessee Z6 Cas asco Bay Bay Veazie, ME 543 Gas / CCGT Mass Hub Maritimes Lake ake R Road ad Dayville, CT 827 Gas / CCGT Mass Hub Algonquin MASSPOWER ER Indian Orchard, MA 281 Gas / CCGT Mass Hub Tennessee Z6 Milfor ford Milford, CT 600 Gas / CCGT Mass Hub Iroquois Z2 Independ ndenc nce Oswego, NY 1,212 Gas / CCGT NY Zone C Dom South NY NY/NE NE Seg egmen ent T Total 4, 4,73 730

ERCOT OT

Colet eto C Creek eek Goliad, TX 650 Coal /ST ERCOT South PRB Enni nnis Ennis, TX 366 Gas / CCGT ERCOT North WAHA Hays ys San Marcos, TX 1,047 Gas / CCGT ERCOT South Katy Midloth thian an Midlothian, TX 1,596 Gas / CCGT ERCOT North WAHA Whar arto ton Boling, TX 83 Gas / CT ERCOT HOU HSS Wi Wise Poolville, TX 787 Gas / CCGT ERCOT North WAHA ERCOT To T Total 4, 4,52 529

NOTES: S: 1) Dynegy owns 100% of each unit listed except for those marked by an asterisk (*). Total Net Capacity set forth in this table for partially

• wned units includes only Dynegy’s

proportionate share of that facility’s gross generating capacity 2) Unit capabilities are based on winter capacity ratings

CAISO, MISO AND IPH GENERATION FACILITIES (as of 10/12/2017)

18

Portfolio/Facility(1) Location Net Capacity(2) Primary Fuel / Technology Type Power Curve Fuel Curve

CAISO SO

Moss

• ss Landin

ing 1 1&2 Moss Landing, CA 1,020 Gas / CCGT NP15 PGECG Oakl aklan and Oakland, CA 165 Oil / ST NP15 CAISO S Seg egmen ent T Total 1, 1,18 185

MI MISO

Bal Baldwin Baldwin, IL 1,185 Coal / ST Indy Hub PRB Havan ana Havana, IL 434 Coal / ST Indy Hub PRB Hen ennep epin(3) Hennepin, IL 294 Coal / ST Indy Hub PRB MIS ISO Segment T t Total tal 1, 1,91 913

IPH PH

Coffeen een Coffeen, IL 915 Coal / ST Indy Hub PRB Duck Cr Creek eek Canton, IL 425 Coal / ST Indy Hub PRB Edw dwards ds Bartonville, IL 585 Coal / ST Indy Hub PRB Joppa ppa/EEI*(4) Joppa, IL 802 Coal / ST Indy Hub PRB Jop

• ppa U

Unit its 1 s 1-3(4) Joppa, IL 165 Gas / CT Indy Hub Michcon Jop

• ppa U

Unit its 4 s 4-5* 5*(4) Joppa, IL 56 Gas / CT Indy Hub Michcon New Newton Newton, IL 615 Coal / ST Indy Hub PRB IP IPH T Total tal 3, 3,56 563

TO TOTA TAL 26,928 928

NOTES: S: 1) Dynegy owns 100% of each unit listed except for those marked by an asterisk (*). Total Net Capacity set forth in this table for partially

• wned units includes only Dynegy’s

proportionate share of that facility’s gross generating capacity 2) Unit capabilities are based on winter capacity ratings 3) A portion of this facility’s capacity (260 MW) is available to move to PJM beginning June 1, 2017 4) Not located within MISO

As Assets in Multi tiple Mar arke kets

(Net C Capac apacity by by ISO)

MISO PJM Coffeen een 764 151 New Newton 308 307 Duck Cr Creek eek 96 329 Edw dwards ds 435 150

COMMODITY PRICING AROUND-THE-CLOCK POWER (OCTOBER 11 PRICING)

19 $0 $10 $20 $30 $40 $50 $60 J F M A M J J A S O N D $0 $2 $4 $6 $8 J F M A M J J A S O N D $0 $10 $20 $30 $40 $50 $60 J F M A M J J A S O N D $0 $10 $20 $30 $40 $50 $60 $70 J F M A M J J A S O N D

Indiana Hub ($/MWh) New York Zone C ($/MWh) NP-15 ($/MWh) Natural Gas ($/MMBtu)

2018 2017 A/F (Oct)(1)

2017 A/F (Oct): $29.58 2018 Forward: $30.74

(2) (3)

2017 A/F (Oct): $23.39 2018 Forward: $25.64

(2) (3)

2017 A/F (Oct): $33.06 2018 Forward: $32.76

(2) (3)

2017 A/F (Oct): $2.98 2018 Forward: $3.02

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 10/11/2017 and quoted forward ATC monthly prices for 10/12/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through Oct 11, 2017 and 2017 forward monthly prices for the balance of the year based on Oct 11, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on Oct 11, 2017 pricing

COMMODITY PRICING AROUND-THE-CLOCK POWER (OCTOBER 11 PRICING) (CONTINUED)

20 $0 $10 $20 $30 $40 $50 $60 $70 $80 J F M A M J J A S O N D $0 $10 $20 $30 $40 $50 $60 J F M A M J J A S O N D $0 $10 $20 $30 $40 $50 $60 J F M A M J J A S O N D $0 $10 $20 $30 $40 $50 $60 $70 J F M A M J J A S O N D

Mass Hub ($/MWh) PJM-W ($/MWh) AD-Hub ($/MWh) Ni-Hub($/MWh)

2017 A/F (Oct): $31.01 2018 Forward: $37.90

(2) (3)

2017 A/F (Oct): $29.11 2018 Forward: $30.48

(2) (3)

2017 A/F (Oct): $29.20 2018 Forward: $31.02

(2) (3)

2017 A/F (Oct): $26.71 2018 Forward: $27.48

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 10/11/2017 and quoted forward ATC monthly prices for 10/12/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through Oct 11, 2017 and 2017 forward monthly prices for the balance of the year based on Oct 11, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on Oct 11, 2017 pricing

2018 2017 A/F (Oct)(1)

COMMODITY PRICING AROUND-THE-CLOCK POWER (OCTOBER 11 PRICING) (CONTINUED)

21 $0 $10 $20 $30 $40 $50 $60 $70 J F M A M J J A S O N D

ERCOT N ($/MWh)

2017 A/F (Oct): $23.27 2018 Forward: $25.85

(2) (3)

2018 2017 A/F (Oct)(1)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 10/11/2017 and quoted forward ATC monthly prices for 10/12/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through Oct 11, 2017 and 2017 forward monthly prices for the balance of the year based on Oct 11, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on Oct 11, 2017 pricing

SPARK SPREADS AROUND-THE-CLOCK (OCTOBER 11 PRICING)

22 $0 $5 $10 $15 $20 $25 $30 J F M A M J J A S O N D $0 $5 $10 $15 $20 $25 $30 J F M A M J J A S O N D $0 $5 $10 $15 $20 $25 $30 J F M A M J J A S O N D $0 $5 $10 $15 $20 $25 $30 J F M A M J J A S O N D

PJM West/TetM3 ($/MWh) Mass Hub/Algonquin ($/MWh) Ni-Hub/ChiCG ($/MWh) NP-15/PGE ($/MWh)

2017 A/F (Oct): $12.55 2018 Forward: $9.33

(2) (3)

2017 A/F (Oct): $6.50 2018 Forward: $7.58

(2) (3)

2017 A/F (Oct): $7.25 2018 Forward: $7.02

(2) (3)

2017 A/F (Oct): $10.32 2018 Forward: $11.09

(2) (3)

2018 2017 A/F (Oct)(1)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 10/11/2017 and quoted forward ATC monthly prices for 10/12/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through Oct 11, 2017 and 2017 forward monthly prices for the balance of the year based on Oct 11, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on Oct 11, 2017 pricing

SPARK SPREADS AROUND-THE-CLOCK (OCTOBER 11 PRICING) (CONTINUED)

23 $0 $5 $10 $15 $20 $25 $30 J F M A M J J A S O N D $0 $5 $10 $15 $20 $25 $30 J F M A M J J A S O N D

NY Zone C/DOM ($/MWh) AD-Hub/DOM ($/MWh)

$0 $5 $10 $15 $20 $25 $30 J F M A M J J A S O N D

ERCOT N / WAHA($/MWh)

2017 A/F (Oct): $8.39 2018 Forward: $8.20

(2) (3)

2017 A/F (Oct): $4.64 2018 Forward: $8.58

(2) (3)

2017 A/F (Oct): $14.11 2018 Forward: $13.03

(2) (3)

2018 2017 A/F (Oct)(1)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 10/11/2017 and quoted forward ATC monthly prices for 10/12/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through Oct 11, 2017 and 2017 forward monthly prices for the balance of the year based on Oct 11, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on Oct 11, 2017 pricing

$111 $62 $56 $49 $5 $7 $2 $8 $8 $4 $33 $9 $5 $6 $2 $1 $1 $1 $11 $2

YTD 2016 YTD 2017 YTD 2016 YTD 2017 YTD 2017 YTD 2016 YTD 2017 YTD 2016 YTD 2017 YTD 2016 YTD 2017 YTD 2016 YTD 2017

Environmental Maintenance

CAPITAL AND MAJOR MAINTENANCE O&M

24

PJM

• Capital spending decreased due to fewer

maintenance outages at our CCGT fleet,

• ffset slightly by an increase in spend at

some of the gas fueled assets acquired from ENGIE

NY/NE

• Capital spending decreased due to fewer

maintenance outages at our CCGT fleet,

• ffset by the inclusion of the ENGIE fleet

MISO

• Capital spending decreased due to

fewer planned outages

IPH

• Capital spending decreased due to

reduced Environmental CapEx spend in 2017

CAISO

• Capital spending increased due to major
• utage work at Moss Landing 1&2 in 2017

Corporate

• Capital spending decreased primarily due

to systems upgrades in 2016

Capital Expenditures by Segment(1)(2) ($ MM) Total O&M Outage Expense ($ MM)

All Segments

• Increase in maintenance expense mostly

due to larger planned major outages at PJM Coal and Moss Landing; offset by lower outage costs in MISO

• Lower capital removal due to fewer PJM

CCGT outages

(1) Excludes capitalized interest; (2) Excludes discretionary investments for growth and reliability

$40 $42 $31 $19

YTD 2016 YTD 2017 Major Maintenance Capital Removal/Other

$71 $61

PJM NY/NE ERCOT MISO IPH CAISO Corp/Other

70% 58% 84% 87% 80% 60% 79% 68% 90% 85% 83% 87% 49% 70% 8% 9% 10% 9% 7% 6% 9% 10% 9% 9% 8% 11% 13% 4% 0% 1% 0% 4% 4% 6% 2% 0% 18% 33% 5% 10% 30% 6% 21% 0% 6% 7% 36% 26%

2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2017 2017

PJM

25

3Q16 & 3Q17 FLEET PERFORMANCE – GAS FLEET (CCGTs)

72% 55% 73% 66% 69% 52% 67% 67% 48% 43% 28% 10% 53% 68% 62% 31% 9% 11% 9% 8% 10% 8% 11% 11% 9% 9% 7% 8% 9% 11% 5% 0% 8% 5% 5% 8% 14% 9% 16% 17% 33% 16% 20% 14% 35% 21% 18% 43% 40% 65% 79% 30% 28% 21% 42%

2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2017 2017 2017 2017 Net Capacity Factor Seasonal Derate Planned Outage Unplanned Outage Uneconomic

ISO-NE/NY

(1)

Kendall Ontelaunee Washington Hanging Rock Fayette Liberty Hopewell Sayerville Independence Casco Bay Lake Road Milford Dighton(2) MASSPOWER Bellingham (ANP) Bellingham (NEA) Blackstone Milford MA(2)

(1) Net Capacity Factor is based on the NERC method of calculation, which uses a maximum capacity rating (2) Includes September data up to date of sale of plant

26

3Q16 & 3Q17 FLEET PERFORMANCE – GAS FLEET (CCGTs)

(CONTINUED) 54% 55% 46% 34% 20% 43% 13% 19% 20% 7% 7% 20% 6% 29% 19% 32% 39% 74% 53% 2017 2017 2017 2017 2016 2017 Net Capacity Factor Seasonal Derate Planned Outage Unplanned Outage Uneconomic

ERCOT

Ennis Hays Midlothian Wise Moss Landing 1 & 2

CAISO

(1) Net Capacity Factor is based on the NERC method of calculation, which uses a maximum capacity rating

57% 52% 77% 71% 74% 79% 68% 82% 59% 49% 75% 5% 6% 5% 7% 12% 8% 11% 25% 12% 32% 47% 6% 36% 38% 15% 16% 18% 10% 7% 6% 9% 19%

2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2017

Net Capacity Factor Seasonal Derates Planned Outage Unplanned Outage Uneconomic

Coleto Creek Kincaid Zimmer Miami Fort Killen(2) Stuart(2)

80% 85% 69% 76% 58% 76% 64% 69% 68% 60% 65% 68% 51% 46% 52% 69% 5% 5% 5% 5% 13% 10% 7% 6% 24% 6% 12% 17% 15% 21% 13% 10% 9% 7% 5% 8% 6% 22% 13% 16% 15% 10% 13% 14% 16% 19% 17% 40% 40% 40% 24%

2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016 2017

MISO – Coal

27

3Q16 & 3Q17 FLEET PERFORMANCE – COAL FLEET & IPH

(1) Net Capacity Factor is based on the NERC method of calculation, which uses a maximum capacity rating; (2) Jointly owned facilities not operated by Dynegy

PJM – Coal

Baldwin Havana Hennepin Coffeen Duck Creek Edwards Joppa Newton

IPH

(1)

ERCOT – Coal

OPERATIONAL STATISTICS

28

Combined Cycle Generation 3Q16 3Q17 YTD 2016 YTD 2017

Total tal G Generat ation (MM MWh) CAISO 0.5 1.0 1.8 1.5 ERCOT N/A 3.9 N/A 6.4 NY/NE 5.0 5.7 11.6 13.4 PJM 9.3 9.1 26.0 24.0 91.7% 85.5% 95.9% 85.2% In In-Mar arke ket-Av Availa ilabilit ility CAISO ERCOT N/A 85.8% N/A 88.9% NY/NE 98.2% 87.2% 95.2% 91.3% PJM 96.9% 98.2% 97.4% 92.8% 20.0% 43.2% 27.1% 22.7% Averag age C Cap apac acity ty Fac acto tor

(1) 1)

CAISO ERCOT N/A 46.7% N/A 30.4% NY/NE 63.2% 51.6% 49.7% 42.2% PJM 79.4% 69.5% 74.7% 62.6%

(1) Average Capacity Factor is based on the NERC method of calculation, which uses a maximum capacity rating

OPERATIONAL STATISTICS (CONTINUED)

29

Coal Generation 3Q16 3Q17 YTD 2016 YTD 2017

Total tal G Generat ation (MM MWh) Coleto Creek N/A 1.1 N/A 2.4 MISO 4.2 3.4 11.2 8.8 PJM 5.4 5.0 12.6 13.9 Brayton Point 0.4 N/A 1.5 1.1 In In-Mar arke ket-Av Availa ilabilit ility Coleto Creek N/A 92.5% N/A 95.3% MISO 89.8% 93.9% 88.7% 89.6% PJM 83.3% 75.2% 80.8% 71.3% Brayton Point 75.0% N/A 87.5% 83.1% Averag age C Cap apac acity ty Fac acto tor Coleto Creek N/A 74.6% N/A 63.2% MISO 75.6% 81.6% 60.9% 70.7% PJM 64.8% 62.4% 51.3% 54.4% Brayton Point 13.0% N/A 15.1% 21.4%

IPH(1) 3Q16 3Q17 2016 2017

Tota tal Ge Generati tion (MM MWh) 5.0 4.6 11.6 12.6 In In-Mar arket-Av Availa ilabilit ility 87.5% 85.1% 88.2% 86.5% Average C Cap apac acity F Fac acto tor(2)

2)

58.5% 62.0% 45.0% 57.4%

(1) In-Market Availability and Average Capacity Factor do not include CTs; (2) Average Capacity Factor is based on the NERC method of calculation, which

uses a maximum capacity rating

MARKET PRICING

30

Average Actual Power/Gas Prices ($/MWh)

3Q16 3Q17 YTD 16 YTD 17

On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak Indy Hub $40.19 $24.38 $37.04 $24.79 $32.32 $22.31 $34.91 $24.84 Mass Hub $41.31 $23.57 $31.94 $19.89 $34.44 $23.40 $33.97 $25.37 NP-15 $37.70 $29.57 $46.71 $31.92 $29.92 $23.64 $36.95 $26.49 NY - Zone C $34.79 $21.24 $29.86 $18.00 $26.74 $16.91 $29.01 $18.67 PJM-W $40.74 $24.36 $35.10 $23.29 $34.77 $24.08 $33.62 $24.82 AD Hub $38.75 $23.53 $36.30 $23.72 $32.66 $22.72 $33.76 $24.62 NiHub $38.41 $22.57 $34.03 $20.34 $31.54 $20.81 $32.49 $22.02 Ercot N $33.25 $22.67 $31.21 $23.37 $25.72 $17.77 $27.17 $21.07

Average Trading Hub Spark Spreads ($/MWh)

3Q16 3Q17 YTD 16 YTD 17

On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak PJM West/TetM3 $31.48 $15.10 $23.21 $11.41 $23.79 $13.10 $16.79 $7.99 NiHub/ChiCG $18.93 $3.09 $14.23 $0.55 $15.41 $4.68 $12.12 $1.66 NP-15/PGE $15.44 $7.31 $23.84 $9.05 $12.32 $6.03 $13.89 $3.43 NY-Zone C/Dominion $26.04 $12.49 $18.52 $6.66 $17.37 $7.55 $13.30 $2.96 Mass Hub/Algonquin $21.58 $3.85 $16.17 $4.12 $14.49 $3.46 $11.63 $3.03 AD Hub/Dominion $27.27 $14.78 $24.95 $12.38 $28.88 $13.36 $18.05 $8.90 Ercot N/Waha $14.51 $3.93 $12.65 $4.81 $10.60 $2.65 $8.16 $2.06

31

MISO CAPACITY POSITION (excludes PJM exports)

Price in $/kw-mo MISO MISO - IPH Total EBITDA Contribution PY 17/1 17/18 MWs 1,075 2,431 3,506 Average Price $3.39 $4.37 $4.07 $171 MM PY 18/1 18/19 MWs 342 1,971 2,313 Average Price $2.69 $4.77 $4.46 $124 MM PY 19/2 19/20 MWs 185 930 1,115 Average Price $2.60 $4.71 $4.36 $58 MM PY 20/2 20/21 MWs 385 674 1,059 Average Price $3.03 $5.19 $4.41 $56 MM Total tal M MWs 1, 1,98 987 6, 6,00 006 7, 7,99 993 Av Avera rage Price ce $3. $3.13 $4. $4.65 $4. $4.27 $40 $409 MM MM

MISO EXPORTS TO PJM CAPACITY POSITION

32

PJM Region Planning Year Average Price ($/MW-day) MW Position Average Price ($/MW-day) MW Position Legacy/Base Product Capacity Performance Product RTO 2017 - 2018 $85.49 572 $151.50 472 2018 - 2019

• $164.77

835 2019 – 2020 $80.00 260 $100.00 356 2020 – 2021

• $76.53

444

Note: PJM capacity position represent volumes cleared and purchased in primary annual auctions, incremental auctions, and transitional auctions.

Also includes bilateral transactions

PJM CAPACITY POSITION (excludes MISO imports)

33 PJM Region Planning Year Average Price ($/MW-day) MW Position Average Price ($/MW-day) MW Position Legacy/Base Product Capacity Performance Product

RTO 2017-2018 $126.07 2,002 $151.50 3,364 2018-2019 $162.02 1,397 $164.77 3,948 2019-2020 $94.04 1,048 $100.00 4,025 2020-2021(1) N/A N/A $88.32 4,209 ComEd 2017-2018 $123.99 309 $151.50 2,261 2018-2019 $200.21 317 $215.29 2,254 2019-2020 $182.77 317 $203.10 2,267 2020-2021 N/A N/A $188.12 2,549 MAAC 2017-2018 $26.50 3 $151.50 508 2018-2019 $149.98 $166.83 508 2019-2020 $80.00 $127.21 515 2020-2021 N/A N/A $116.74 547 EMAAC 2017-2018 $122.12 154 $151.50 533 2018-2019 $210.63 148 $232.83 507 2019-2020 $99.77 $120.68 669 2020-2021 N/A N/A $187.87 684 ATSI 2017-2018 $125.46 356 $151.50 2018-2019 $149.98 $164.77 195 2019-2020 $80.00 $100.00 224 2020-2021 N/A N/A $76.53 73 PPL 2017-2018 $121.53 49 $151.50 2018-2019 $75.00 48 $164.77 2019-2020 $80.00 48 $100.00 2020-2021 N/A N/A $86.04

(1) Includes DEOK zone which broke out from RTO at $130.00 $/MW-day; Note: PJM capacity position represent volumes cleared and purchased in primary annual

auctions, incremental auctions, and transitional auctions. Also includes bilateral transactions

ISO-NE / NYISO / CAISO CAPACITY POSITIONS

34

Capacity / Resource Adequacy

ISO/Region Contract Type Average Price Size (MW) Tenor ISO-NE(1) ISO-NE Capacity $6.97/kw-Mo 3,277 June 2017 to May 2018 $9.99/kw-Mo 3,244 June 2018 to May 2019 $7.02/kw-Mo 3,233 June 2019 to May 2020 $5.39/kw-Mo 3,229 June 2020 to May 2021 NYISO(2)(3) NYISO Capacity $1.95/kw-Mo 1,171 Winter 2016/2017 $3.36/kw-Mo 953 Summer 2017 $2.08/kw-Mo 1,021 Winter 2017/18 $3.34/kw-Mo 745 Summer 2018 $2.75/kw-Mo 430 Winter 2018/2019 $3.39/kw-Mo 255 Summer 2019 $2.94/kw-Mo 160 Winter 2019/2020 $3.15/kw-Mo 75 Summer 2020 CAISO RA Capacity 752 Avg Bilateral Sold Cal 2017 444 Avg Bilateral Sold Cal 2018 850 Avg Bilateral Sold Cal 2019

(1) ISO-NE represents capacity auctions results, supplemental auctions and bilateral capacity sales; (2) NYISO represents capacity auction results and bilateral

capacity sales; (3) Winter period covers November through Oct and the Summer period covers May through October

REG G RECONCILIATIONS

APPENDIX

36

REG G RECONCILIATION – 3RD QUARTER 2017 ADJUSTED EBITDA

37

REG G RECONCILIATION – 3RD QUARTER 2016 ADJUSTED EBITDA

38

REG G RECONCILIATION – 2017 GUIDANCE