SECOND QUARTER 2017 REVIEW AUGUST 3, 2017 FORWARD-LOOKING - - PowerPoint PPT Presentation

AUGUST 3, 2017

SECOND 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 and second 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 August 3, 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. Second Quarter 2017 Financial Results IV. Near-Term Priorities

3

4

OVERVIEW AND OUTLOOK

• PJM and ISO-NE have proposed capacity market reforms to stabilize and support proper

capacity price formation

• PJM has also proposed energy market reforms to support proper energy price formation
• Appeal filed in the Illinois ZEC case

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
• ~$55 MM in 2017 Adjusted EBITDA foregone due to delayed ENGIE closing and mid-year

closing of the Troy and Armstrong sale; guidance ranges reaffirmed despite these impacts

• Sale of Troy and Armstrong closed on July 11, 2017, generating approximately $480 MM
• Agreements reached to sell Dighton, Lee, and Milford (MA) for approximately $300 MM
• Completed 43 MW of uprates at Liberty and Milford (CT) at a cost of ~$175/kW
• 2Q 2017 Net Loss of $296 MM versus $803 MM Net Loss for 2Q 2016
• 2Q 2017 Adjusted EBITDA of $240 MM versus $187 MM for 2Q 2016
• Liquidity of $1,384 MM as of June 30, 2017

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

COMPETITIVE MARKETS PORTFOLIO UPDATES 2Q 2017 FINANCIAL HIGHLIGHTS

THE EVOLUTION OF DYNEGY

5

~75% ~25% ~20% ~80%

Generation Fleet

• Built scale to leverage existing

infrastructure

• Repositioned fleet to focus on most

constructive markets

• Increased scale of natural gas-fueled

generation, particularly CCGTs with fuel supply advantage

• Add capacity via low-cost uprates
• Continuously work to lower dispatch

costs

• Allocate capital to the most economic

units

Business Mix

• Entered the retail business with a

generation backed retail portfolio

• Expand retail business in core markets

through organic growth and/or acquisitions

Cost Structure

• PRIDE program has generated more

than $1.8 billion in total cash and liquidity benefits since 2011

• $370 MM in synergies captured through

M&A activity

• Expand PRIDE program to recently

acquired ENGIE assets

• Leverage external expertise to further
• ptimize our operating model

Balance Sheet

• Balance sheet capacity used for

transformative M&A

• Allocate asset sale proceeds to debt

reduction

• Strengthen the balance sheet
• Improve leverage profile

Transformative Steps Positioning for Long Term Success

6

~$780 MM in asset sale proceeds to be allocated to debt reduction

PORTFOLIO OPTIMIZATION – ASSET SALES

Dig Dighton Milf ilford Lee Lee Capacity (MW)

161 149 625 ISO/Zone NE/SENE NE/SENE PJM/COMED Primary Fuel Natural Gas Natural Gas Natural Gas Dispatch Type Intermediate Intermediate Peaking Heat Rate (btu/kWH) 7,700 8,300 11,000 Operation Year 1999 1993 2001

• Dynegy to sell Dighton and Milford (MA) for

$119 MM − Fulfills the mitigation plan agreed upon with FERC to satisfy Dynegy’s purchase of ENGIE

• Dynegy to sell Lee for $180 MM

− Eliminates up to $75 MM of capital expenditures needed for CP readiness

• Combined with the sale of Troy and Armstrong,

a total of approximately $780 MM in asset sale proceeds expected to be generated Dighton, Lee and Milford (MA) Transaction Summary

Dig ighton

• n

(1) Summer capacity ratings (1)

Milfo ford rd Lee ee

7

FERC and the ISOs must protect the markets or states need to assume full responsibility for resource adequacy

SUPPORTING COMPETITIVE MARKETS

Defending competitive markets to deliver the lowest cost power to consumers

FERC

• MOPR complaints pending at

FERC

• Court decisions point to FERC’s

ability to address problems created by ZEC programs; we will press FERC to do so

• PJM IMM supports application
• f MOPR

PJM/ISO-NE

• PJM and ISO-NE capacity

market improvements include MOPR and/or two-tier pricing to mitigate subsidies

• PJM energy market price

formation improvements include: − Valuing units needed for reliability by allowing them to set the marginal price − Eliminating negative pricing − Procuring additional resources to secure the system for natural gas contingencies

Federal Court

• Appeal filed in Illinois
• Seventh circuit (IL) has set an

expedited schedule to hear the case

• No other court has held that

the Federal Power Act could not be enforced by private actions

• Case will be heard without

consideration of prior decision

Multiple Pathways

OPERATIONS AND COMMERCIAL OVERVIEW

3.3 4.2 3.3 4.2 3.6 2.7 3.6 2.7 7.4 6.9 3.8 4.0 11.2 10.9 3.5 4.1 0.3 0.1 3.8 4.2 0.8 0.2 0.8 0.2 2.1 1.1 3.2

2Q16 2Q17 2Q16 2Q17 2Q16 2Q17 IPH MISO PJM NY/NE CAISO ERCOT Coal Gas

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

56% 46% 38% 58%

Gas (CCGT) Coal 2Q16 2Q17 0.00 2.24 1.41 0.61 1.62 1.03 Gas Coal Total 2Q16 2Q17

OPERATIONS SUMMARY

9 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 Dy Dynegy S Safety P Performance in in the Top De Decil ile Generation V n Volum umes

• Gas fleet increased primarily due to the addition of the

ENGIE assets, offset by lower spark spreads and more

• utages
• Coal fleet increased primarily due to favorable power

pricing and the addition of Coleto Creek, offset by retirements

Net t Cap apac acity F Fac acto tors

• Gas fleet declined primarily due to increased outages and

lower spark spreads

• Coal fleet increased primarily due to favorable power

pricing

(3) (2)

11.0 12.1 13.3 11.7

(1) (1)

22.7 25.4 Consolidated

10

Dynegy’s PRIDE program continues to evolve and deliver results

PRIDE ENERGIZED (2016-2018)

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

$65 $65 MM in n 2017 E 2017 EBITDA i ini nitiatives i ident ntified t to date:

• Coal and transportation contract reductions
• Gas transport rate reduction
• Chemical usage optimization and price improvements

Over $100 $100 MM i MM in 2017 b 2017 balanc nce s sheet i ini nitiatives ident ntified to to d date ate:

• Term loan repricing
• Supply chain optimization
• Return of collateral
• AMT credit monetization

2017 Progress Enhancing PRIDE

$135 $250 $65 $50 2016 2017 2018 Total $200 $400 $100 $100 2016 2017 2018 Total

2016 results achieved of $150 MM 2016 results achieved of $422 MM

Increasing PRID IDE t to dr drive a e addi dditional ben benefits:

• Rollout of PRIDE program to ENGIE plants with new

initiatives identified

• Leveraging external expertise to further optimize our

internal operating model

93% 84% 82% 91% 52% 79% 80% 78%

Financial/Physical Hedges Retail and Wholesale Contracts

50% 61% 21% 41% 42% 63% 44% 54%

Financial/Physical Hedges Retail and Wholesale Contracts

11

COMMERCIAL SUMMARY

(1) Hedge percentages for the balance of the year (Mar 31, 2017 = 4/1/17 through 12/31/17 & June 30, 2017= 7/1/17 through 12/31/17); (2) Hedge percentages for the balance of the

year 7/1/17 through 12/31/17; Note: Hedge percentages take into account the announced retirements of Brayton Point, 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

46% 63% 2%

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 6/30/17 open

valuation for modeling purposes to properly incorporate existing contracts

• Gross margin distribution for full year 2017

82% 92% 6%

Gas Coal Volume Contracted and Priced Volume Contracted but Not Priced

Fu Fuel Suppl pply Hedged a as o

• f 6/30

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 6/30/17 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 $1.02/MWh Hedge ge P Position ion 53.7 MM MWh Hed edge Va e Value $0.07/MWh Hedge ge P Position ion 62.3 MM MWh

2017 2018

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

• f 6/30

30/2017

12

Leveraging our expertise in municipal electricity aggregations to expand into new markets

DYNEGY RETAIL – MASS MARKET EXPANSION

• Entered New England market in July, with 84,000 customers enrolled in Massachusetts
• Tripled retail customer count in fewer than four years
• More than 550 communities served

2Q 2017 FINANCIAL RESULTS

$187 $240 2Q16 2Q17

14

FINANCIAL SUMMARY

Net Loss ($ MM) Adjusted EBITDA Results ($ MM) Liquidity as of 6/30/2017 ($ MM) Net et Lo Loss

• Decrease in net loss primarily due to $645 MM in impairment

charges recorded in 2016

Ad Adju justed E EBI BITDA DA

• Increased primarily due to a $60 MM contribution from the

ENGIE assets and higher capacity revenues at the IPH segment, partially offset by lower energy margin primarily at the PJM segment

Gui uidanc nce

• Reaffirming 2017 guidance even with M&A timing reducing

results: − ~$20 MM ENGIE delay − ~$35 MM Troy and Armstrong mid-year closing

Liquid idit ity

• Liquidity as of 6/30/2017 excludes ~$480 MM in cash proceeds

from the Troy and Armstrong sale received in July 2017

Financial Update Revolving facilities and LC capacity $1,650 Less: Outstanding revolver draws (300) Outstanding LCs (413) Revolving facilities and LC availability 937 Cash and cash equivalents 447 Total L l Liquid idit ity $1, $1,38 384 Guidance ($ MM) 2017 Adj EBITDA 2017 Adj FCF $1,200 $1,400 $500 $300 $(803) $(296) 2Q16 2Q17

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

15

SECOND QUARTER PERIOD-OVER-PERIOD SEGMENT PERFORMANCE

Adjusted EBITDA Changes by Source

PJM PJM Q2 Contribution of ENGIE $33 MM Realized Energy Margin $(23) MM Capacity $(3) MM O&M $4 MM Other $5 MM NY NY/NE NE Q2 Contribution of ENGIE $26 MM Realized Energy Margin $(2) MM O&M $ 2 MM MI MISO Realized Energy Margin $(9) MM Capacity $2 MM O&M $6 MM IPH Realized Energy Margin $(4) MM Capacity $13 MM AER (contingent proceeds) $25 MM CAISO Capacity $(7) MM O&M $(3) MM 2016 supplier settlement $(12) MM

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

2Q Period-over-Period Operating Income / (Loss) ($ MM)

2Q 16 16 2Q 17 17 PJM $71 $6 NY/NE (5) (1) ERCOT

• (30)

MISO/IPH (726) (87) CAISO 4 (19) Other (46) (51) Con

• nsol
• lidat

ated $(702) 702) $(182) 182)

2Q Period-over-Period Adjusted EBITDA ($ MM)

2Q 16 16 2Q 17 17 PJM $152 $168 NY/NE 34 60 ERCOT

• 1

MISO/IPH 15 50 CAISO 21 (1) Other (35) (38) Con

• nsol
• lidat

ated $187 87 $240 40

16

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)

Principal Payment $(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

• Current forecast used to reaffirm 2017 guidance reflects

the following assumptions: − Based on July 13, 2017 forward pricing − ~$55 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

NEAR-TERM PRIORITIES

18

DYNEGY’S NEAR-TERM PRIORITIES

PORTFOLIO PLANNING

• Close pending asset sales
• Complete Ohio JOU consolidation
• Grow retail business in core markets

SUPPORT THE COMPETITIVE MODEL

• Pursue market designs that protect price formation
• Neutralize or eliminate out-of-market subsidies
• Appeal recent Illinois ZEC ruling

FINANCIAL GOALS

• Reduce 2019 debt maturity
• Improve leverage profile
• Achieve 2017 financial targets

OPERATING EXCELLENCE

• Improve upon excellent safety record
• Deliver strong plant reliability
• Exceed PRIDE targets & launch the next phase

APPENDIX

20

FORECAST INFORMATION – MODELING ASSISTANCE

Fixed = ~80% Variable = ~10% (varies with generation volumes) Outage = ~10%

Annual O O&M E Expense o

• f $

$950 50 -

• 1

1,050 M MM Highlighted numbers represent material changes from our previous estimate. PJM sold capacity revenues declined due to finalizing the sale of Troy and Armstrong. Total uses of cash declined due to a reduction in cash maintenance capital expenditures, further deferral of the PJM capacity monetization settlement and lower cash interest driven by the Troy and Armstrong asset sale proceeds being allocated to debt reduction.

(1)

(1) Assumes ~$480 MM in proceeds from the Armstrong and Troy sale are allocated to debt repayment by Jan 1, 2018. Assumes no other voluntary debt repayments at this time.

(1)

2017 2018 2019 2017 2018 2019 Sold Capacity Revenues: Included in Adj FCF: PJM 545 $ 645 $ 580 $ Cash Maintenance CapEx (200) $ (235) $ (255) $ NY/NE 270 395 365 Environmental CapEx (10) (15) (20) MISO 160 145 85 Interest (600) (590) (585) CAISO 20 10 20 Asset Retirement Obligation (30) (25) (35) 995 $ 1,195 $ 1,050 $ Pension (5) (30) (20) O&M - Outage Costs (90) $ (100) $ (100) $ Capital Allocation: O&M - Shutdown Costs (25) $ (10) $

• $

PJM Capacity Monetization

• (5)

(75) Environmental Capital Projects

• (10)

(60) G&A Costs (140) $ (140) $ (140) $ Principal Payments (45) (50) (45) Uprate Investments (30) (20) (10) Mandatory Preferred Dividend (20)

• 2017

2018 2019 PJM 225 265 265 Total Uses of Cash (940) $ (980) $ (1,105) $ NYISO 40 375 800 MISO

• 555

1,540 265 1,195 2,605

Calendar Year Unsold Capacity (MW) Known Adjusted EBITDA Components ($ MM) Uses of Cash ($ MM)

PJM GENERATION FACILITIES (as of 08/03/2017)

21

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 Lee ee Dixon, IL 787 Gas / CT NiHub Chicago CG 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 40% IL Basin / 60% 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 904 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 40% IL Basin / 60% NAPP PJM Seg egmen ent T Total 12,020 020

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 8/03/2017)

22

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 Digh ghton

• n

Dighton, MA 185 Gas / CCGT Mass Hub Algonquin 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 Milfo ford rd Milford, MA 171 Gas / CCGT Mass Hub Algonquin Independ ndenc nce Oswego, NY 1,212 Gas / CCGT NY Zone C Dom South NY NY/NE NE Seg egmen ent T Total 5, 5,08 086

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 ERTCOT 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 8/03/2017)

23

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 28,296 296

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 (JULY 13 PRICING)

24 $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 (July)(1)

2017 A/F (July): $29.17 2018 Forward: $30.12

(2) (3)

2017 A/F (July): $23.89 2018 Forward: $26.41

(2) (3)

2017 A/F (July): $31.29 2018 Forward: $31.51

(2) (3)

2017 A/F (July): $3.02 2018 Forward: $2.99

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 7/13/2017 and quoted forward ATC monthly prices for 7/14/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through July 13, 2017 and 2017 forward monthly prices for the balance of the year based on July 13, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on July 13, 2017 pricing

COMMODITY PRICING AROUND-THE-CLOCK POWER (JULY 13 PRICING) (CONTINUED)

25 $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 (July): $31.59 2018 Forward: $38.10

(2) (3)

2017 A/F (July): $28.64 2018 Forward: $29.49

(2) (3)

2017 A/F (July): $28.82 2018 Forward: $30.20

(2) (3)

2017 A/F (July): $27.11 2018 Forward: $27.35

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 7/13/2017 and quoted forward ATC monthly prices for 7/14/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through July 13, 2017 and 2017 forward monthly prices for the balance of the year based on July 13, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on July 13, 2017 pricing

2018 2017 A/F (July)(1)

COMMODITY PRICING AROUND-THE-CLOCK POWER (JULY 13 PRICING) (CONTINUED)

26 $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 (July): $24.49 2018 Forward: $26.07

(2) (3)

2018 2017 A/F (July)(1)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 7/13/2017 and quoted forward ATC monthly prices for 7/14/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through July 13, 2017 and 2017 forward monthly prices for the balance of the year based on July 13, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on July 13, 2017 pricing

SPARK SPREADS AROUND-THE-CLOCK (JULY 13 PRICING)

27 $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 (July): $10.56 2018 Forward: $8.51

(2) (3)

2017 A/F (July): $6.77 2018 Forward: $7.56

(2) (3)

2017 A/F (July): $7.17 2018 Forward: $7.49

(2) (3)

2017 A/F (July): $8.44 2018 Forward: $9.68

(2) (3)

2018 2017 A/F (July)(1)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 7/13/2017 and quoted forward ATC monthly prices for 7/14/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through July 13, 2017 and 2017 forward monthly prices for the balance of the year based on July 13, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on July 13, 2017 pricing

SPARK SPREADS AROUND-THE-CLOCK (JULY 13 PRICING)

(CONTINUED)

28 $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 (July): $7.15 2018 Forward: $9.07

(2) (3)

2017 A/F (July): $5.55 2018 Forward: $8.37

(2) (3)

2017 A/F (July): $11.90 2018 Forward: $12.16

(2) (3)

2018 2017 A/F (July)(1)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 7/13/2017 and quoted forward ATC monthly prices for 7/14/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through July 13, 2017 and 2017 forward monthly prices for the balance of the year based on July 13, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on July 13, 2017 pricing

$102 $57 $54 $43 $8 $6 $2 $5 $5 $3 $30 $7 $4 $4 $1 $1 $1 $8 $1

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

29

PJM

• Capital spending decreased due to less

LTSA work at the gas facilities and fewer

• utages at the coal facilities, offset by an

increase in spending due to the addition of the ENGIE fleet

NY/NE

• Capital spending decreased due to less

LTSA work, offset by inclusion of the ENGIE fleet

MISO

• Capital spending decreased due to

fewer planned outages

IPH

• Capital spending decreased due to the

cancellation of Newton scrubber project and lower ELG spend

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

• Lower capital removal due to fewer PJM

CCGT outages

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

$34 $37 $28 $18

YTD 2016 YTD 2017 Major Maintenance Capital Removal/Other

$62 $55

PJM NY/NE ERCOT MISO IPH CAISO Corp/Other

51% 56% 60% 61% 35% 67% 78% 52% 65% 16% 77% 59% 55% 28% 6% 8% 5% 7% 8% 8% 8% 7% 4% 8% 5% 12% 25% 13% 29% 26% 45% 9% 16% 25% 64% 11% 28% 2% 0% 0% 1% 2% 1% 1% 8% 10% 0% 4% 11% 15% 24% 6% 14% 25% 4% 17% 4% 6% 4% 22% 68%

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

PJM

30

2Q16 & 2Q17 FLEET PERFORMANCE – GAS FLEET

37% 20% 73% 60% 65% 41% 47% 59% 35% 36% 6% 6% 54% 28% 56% 15% 7% 8% 7% 6% 9% 6% 6% 8% 8% 9% 10% 6% 7% 33% 14% 5% 6% 38% 27% 0% 9% 9% 37% 8% 6% 6% 23% 58% 17% 27% 20% 12% 17% 26% 56% 54% 80% 81% 31% 72% 32% 38%

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 MASSPOWER Bellingham (ANP) Bellingham (NEA) Blackstone Milford MA

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

31

2Q16 & 2Q17 FLEET PERFORMANCE – GAS FLEET (CONTINUED)

23% 39% 29% 8% 32% 11% 10% 8% 12% 15% 8% 10% 11% 12% 6% 37% 32% 59% 41% 46% 48% 77% 63% 49% 2017 2017 2017 2017 2017 2016 2017 Net Capacity Factor Seasonal Derate Planned Outage Unplanned Outage Uneconomic

ERCOT

Ennis Hays Midlothian Wharton Wise Moss Landing 1 & 2

CAISO

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

35% 24% 43% 67% 62% 64% 39% 38% 64% 78% 48% 41% 81% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 13% 56% 48% 12% 15% 19% 9% 25% 16% 9% 11% 10% 9% 13% 7% 26% 19% 28% 55% 44% 10% 9% 11% 19% 7% 39% 30% 10% 8% 19%

2016 2017 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(2) Miami Fort Conesville(3) Killen(3) Stuart(3)

61% 72% 58% 57% 50% 47% 60% 68% 44% 40% 58% 60% 24% 53% 20% 58% 8% 15% 30% 38% 15% 14% 10% 7% 18% 8% 15% 17% 17% 11% 20% 13% 6% 4% 24% 8% 34% 32% 16% 14% 24% 14% 14% 27% 29% 17% 67% 32% 75% 38%

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

MISO – Coal

32

2Q16 & 2Q17 FLEET PERFORMANCE – COAL FLEET & IPH

(1) Net Capacity Factor is based on the NERC method of calculation, which uses a maximum capacity rating; (2) Completion of Zimmer planned outage extended from

November 2015 to May 2016 due to failure of the LP generator at start-up; (3) Jointly owned facilities not operated by Dynegy

PJM – Coal

Baldwin Havana Hennepin Coffeen Duck Creek Edwards Joppa Newton

IPH

(1)

ERCOT – Coal

OPERATIONAL STATISTICS

33

Combined Cycle Generation 2Q16 2Q17 2016 2017

Total tal G Generat ation (MM MWh) California 0.7 0.2 1.4 0.5 ERCOT N/A 2.1 N/A 2.5 NY/NE 3.5 4.1 6.7 7.8 PJM 7.2 6.6 16.6 15.0 98.6% 77.5% 98.7% 85.0% In In-Mar arke ket-Av Availa ilabilit ility California ERCOT N/A 91.4% N/A 93.1% NY/NE 94.8% 95.6% 92.1% 96.5% PJM 98.3% 86.6% 97.9% 87.8% 32.0% 10.7% 30.7% 12.2% Averag age C Cap apac acity ty Fac acto tor

(1) 1)

California ERCOT N/A 26.5% N/A 19.7% NY/NE 45.8% 37.4% 42.8% 37.2% PJM 61.8% 51.2% 72.3% 59.3%

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

OPERATIONAL STATISTICS (CONTINUED)

34

Coal Generation

(1)

2Q16 2Q17 2016 2017

Total tal G Generat ation (MM MWh) Coleto Creek N/A 1.1 N/A 1.3 MISO 3.6 2.7 7.0 5.4 PJM 3.8 4.0 7.2 8.9 Brayton Point 0.3 0.1 1.1 1.1 In In-Mar arke ket-Av Availa ilabilit ility Coleto Creek N/A 99.7% N/A 97.7% MISO 86.1% 84.3% 87.2% 86.5% PJM 78.6% 70.2% 77.7% 67.6% Brayton Point 95.0% 90.3% 93.0% 83.1% Averag age C Cap apac acity ty Fac acto tor

(2) 2)

Coleto Creek N/A 80.7% N/A 56.2% MISO 58.5% 64.9% 54.3% 65.2% PJM 46.3% 50.3% 44.4% 55.2% Brayton Point 8.1% 4.9% 16.2% 21.4%

IPH(1) 2Q16 2Q17 2016 2017

Tota tal Ge Generati tion (MM MWh) 3.3 4.2 6.6 8.0 In In-Mar arket-Av Availa ilabilit ility 90.7% 88.3% 89.5% 87.5% Average C Cap apac acity F Fac acto tor(2)

2)

38.3% 57.8% 38.4% 55.1%

(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

35

Average Actual Power/Gas Prices ($/MWh)

2Q16 2Q17 YTD 16 YTD 17

On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak Indy Hub $31.14 $22.37 $35.03 $24.56 $28.38 $21.27 $33.84 $24.86 Mass Hub $28.17 $20.43 $32.19 $23.02 $31.01 $23.32 $34.98 $28.11 NP-15 $25.99 $19.93 $32.39 $22.65 $26.04 $20.67 $32.06 $23.77 NY - Zone C $24.09 $15.86 $26.67 $15.35 $22.71 $14.75 $28.59 $19.01 PJM-W $32.07 $22.29 $33.24 $23.84 $31.78 $23.94 $32.88 $25.59 AD Hub $30.43 $21.71 $33.59 $23.95 $29.61 $22.32 $32.49 $25.06 NiHub $28.87 $19.32 $33.16 $21.68 $28.11 $19.93 $31.71 $22.86 Ercot N $24.29 $15.83 $26.76 $20.74 $21.95 $15.33 $25.15 $19.93

Average Trading Hub Spark Spreads ($/MWh)

2Q16 2Q17 YTD 16 YTD 17

On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak PJM West/TetM3 $21.15 $11.38 $15.76 $6.36 $19.94 $12.09 $13.57 $6.28 NiHub/ChiCG $14.23 $4.68 $12.72 $1.24 $13.64 $5.47 $11.06 $2.21 NP-15/PGE $10.76 $4.71 $9.50 ($0.25) $10.74 $5.37 $8.92 $0.63 NY-Zone C/Dominion $13.73 $5.50 $9.63 ($1.69) $13.04 $5.08 $10.69 $1.11 Mass Hub/Algonquin $11.02 $3.28 $12.07 $2.90 $10.92 $3.23 $9.35 $2.48 AD Hub/Dominion $27.53 $11.32 $16.56 $6.92 $29.68 $12.64 $14.59 $7.17 Ercot N/Waha $10.64 $2.18 $7.71 $1.69 $8.64 $2.01 $5.91 $0.69

36

MISO CAPACITY POSITION (excludes PJM exports)

Price in $/kw-mo MISO MISO - IPH Total EBITDA Contribution PY 17/1 17/18 MWs 1,075 2,350 3,425 Average Price $3.39 $4.51 $4.16 $171 MM PY 18/1 18/19 MWs 242 1,943 2,185 Average Price $2.68 $4.88 $4.64 $122 MM PY 19/2 19/20 MWs 185 918 1,103 Average Price $2.60 $4.81 $4.44 $59 MM PY 20/2 20/21 MWs 185 789 974 Average Price $2.71 $5.10 $4.65 $54 MM Total tal M MWs 1, 1,68 687 6, 6,00 000 7, 7,68 687 Av Avera rage Price ce $3. $3.13 $4. $4.76 $4. $4.40 $40 $406 MM MM

MISO EXPORTS TO PJM CAPACITY POSITION

37

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)

38 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 $126.08 2,001 $151.50 3,364 2018-2019 $156.59 1,447 $164.77 3,948 2019-2020 $80.00 1,274 $100.00 4,025 2020-2021(1) N/A N/A $88.32 4,209 ComEd 2017-2018 $121.34 919 $151.50 2,261 2018-2019 $200.21 317 $215.00 2,599 2019-2020 $182.77 317 $202.77 2,830 2020-2021 N/A N/A $188.12 3,154 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 $225.42 532 2019-2020 $99.77 $119.77 679 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

39

Capacity / Resource Adequacy

ISO/Region Contract Type Average Price Size (MW) Tenor ISO-NE(1) ISO-NE Capacity $6.98/kw-Mo 3,583 June 2017 to May 2018 $10.08/kw-Mo 3,562 June 2018 to May 2019 $7.01/kw-Mo 3,560 June 2019 to May 2020 $5.38/kw-Mo 3,595 June 2020 to May 2021 NYISO(2)(3) NYISO Capacity $1.95/kw-Mo 1,171 Winter 2016/2017 $3.39/kw-Mo 934 Summer 2017 $2.23/kw-Mo 930 Winter 2017/18 $3.50/kw-Mo 670 Summer 2018 $3.00/kw-Mo 380 Winter 2018/2019 $3.39/kw-Mo 255 Summer 2019 $3.40/kw-Mo 118 Winter 2019/2020 $3.45/kw-Mo 50 Summer 2020 CAISO RA Capacity 753 Avg Bilateral Sold Cal 2017 420 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 July and the Summer period covers May through October

REG G RECONCILIATIONS

APPENDIX

41

REG G RECONCILIATION – 2ND QUARTER 2017 ADJUSTED EBITDA

42

REG G RECONCILIATION – 2ND QUARTER 2016 ADJUSTED EBITDA

43

REG G RECONCILIATION – 2017 GUIDANCE