FIRST QUARTER 2017 REVIEW MAY 4, 2017 FORWARD-LOOKING STATEMENTS - - PowerPoint PPT Presentation

MAY 4, 2017

FIRST QUARTER 2017 REVIEW

FORWARD-LOOKING STATEMENTS

Cau auti tionary State Statement R t Regarding F Forward-Looking State Statements ts 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 quarter 2017 Form 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. Non

• n-GAAP

AP F Financia ial M l Measures 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 May 4, 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. First Quarter 2017 Financial Results IV. Summary

3

4

OVERVIEW AND OUTLOOK

2019 UNSECURED DEBT MATURITY

• Callable in May 2017 at 103.375; currently trading above par
• Free cash flow, proceeds from announced and in-process asset sales and existing liquidity

sufficient to to repay th the enti tire m matu aturity ty

2017 GUIDANCE

• Reaffirming 2017 Adjusted EBITDA guidance range of $1,200 – 1,400 MM
• Raising 2017 Adjusted Free Cash Flow guidance range from $150 – 350 MM to $300 – 500 MM
• ~90% of 2017 gross margin from capacity sales, tolls, retail and hedged energy margin
• Second round of bidding underway for the sale of Dynegy assets to meet FERC’s market

mitigation requirement in Southeastern New England

• Received early termination of the Hart-Scott-Rodino Act waiting period for Armstrong and

Troy sale

• Agreed to purchase remaining ownership interests in Miami Fort and Zimmer
• Stuart and Killen facilities announced for retirement

1Q 2017 FINANCIAL HIGHLIGHTS

• 1Q 2017 Net Income of $597 MM versus $10 MM of Net Loss for 1Q 2016
• 1Q 2017 Adjusted EBITDA of $230 MM versus $251 MM for 1Q 2016
• Available liquidity of $1,366 MM as of March 31, 2017

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

PORTFOLIO TRANSFORMATION

POSITIVE MOVEMENT IN KEY AREAS

2019 DEBT MATURITY

• Visible pathway to repaying the maturity without reliance on

capital markets

• Many options available to further enhance liquidity
• Beyond 2019 bonds, no major maturities until 2022
• Interest expense of $142 M

$142 MM per year reduced as debt is repaid

MARKET DESIGN

• FERC and ISOs acknowledge negative impact from subsidies on

competitive markets

• FERC Technical Conference on May 1-2, 2017
• PJM capacity market proposal to offset impact of subsidies made

public on May 2, 2017

− Capacity Price Sensitivity: $10/M $10/MW-day = = ~$45 ~$45-50 M 0 MM

• ISO-NE capacity market proposal to offset impact of subsidies

made public on April 24, 2017

− Capacity Price Sensitivity: $1/k $1/kw-mont nth = = ~$45 ~$45 MM

ELG CAPITAL SPEND

• Under existing rule, Dynegy will defer spend by at least two years
• Stuart and Killen retirements eliminate future ELG spend; cleared

capacity revenues reassigned to other Dynegy plants

• On April 12, 2017, ELG rule remanded back to EPA for further

evaluation - potential for further delays and/or spending adjustments to forecasted spend of $252 M $252 MM (as disclosed in DYN’s First Quarter 2017 10-Q)

5

OPERATIONS AND COMMERCIAL OVERVIEW

3.3 3.8 3.3 3.8 3.3 2.7 3.3 2.7 9.5 8.5 3.5 4.9 13.0 13.4 3.1 3.7 0.8 1.0 3.9 4.7 0.7 0.3 0.7 0.3 0.4 0.2 0.6

1Q16 1Q17 1Q16 1Q17 1Q16 1Q17 IPH MISO PJM NY/NE CAISO ERCOT Coal Gas

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

65% 42% 44% 55%

Gas (CCGT) Coal 1Q16 1Q17 0.00 3.08 1.95 0.70 1.50 1.03 Gas Coal Total 1Q16 1Q17

OPERATIONS SUMMARY

7 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

Safe fety P Perform rformance

• Total Dynegy safety performance in the top decile
• Gas fleet continues to perform at high level
• Coal fleet performance improved over 50% due to focused safety

initiatives Generation ion Vo Volumes es

• Gas fleet decreased due to lower spark spreads and more
• utages in 1Q 2017
• Coal fleet increased primarily due to favorable pricing and fewer
• utages in 1Q 2017, offset by retirements

Net t Cap apac acity ty F Fac actors

• Gas fleet declined primarily due to introduction of the ENGIE

ERCOT fleet, increased outages and lower spark spreads

• Coal fleet increased primarily due to favorable pricing and fewer
• utages

(3) (2)

10.9 12.6 12.9 13.3

(1) (1)

24.2 25.5 Consolidated

8

Portfolio transformation has a favorable impact on Dynegy’s emissions profile

IMPROVING OUR ENVIRONMENTAL PROFILE

Rac achel C Cas asey Declining Greenhouse Gas (GHG) Intensity Declining SO2 and NOx Impact (lbs/MWh) Coal Combustion Byproduct Reuse on the Rise(1) Highlights

2014 2015 2016 2017E 1,000 1,200 1,400 1,600 1,800 2,000

CO2 (lb/MWh)

Average CCGT GHG Intensity Dynegy GHG Intensity 0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

1 2 3 2014 2015 2016 2017E

% R Reuse Ash Ash P Prod roduction

• n (MM tons)

Ash Production Ash Reuse % Reuse

0.0 0.5 1.0 1.5 2.0 2014 2015 2016 2017E

SO2 (lbs/MWh) NOx (lbs/MWh)

(1) Excludes non-operated plants

• Transformation to a predominantly gas generation portfolio

driving reduced carbon footprint and emissions reductions

• Lowering our emissions profile reduces exposure to current

and future regulations

• 100% goal for beneficial reuse of coal ash by 2020
• Benefits of reusing coal ash:

− Reduces CO2 by using ash to replace cement and other products − Reduces costs associated with handling and storage of ash − Provides incremental revenue

9

PRIDE Energized remains on track to meet 2017 targets and three year goal

PRIDE ENERGIZED (2016-2018)

PRIDE Energized EBITDA ($ MM) PRIDE Energized Balance Sheet ($ MM) $65 MM in 2017 EBITDA initiatives have been identified to date:

• Coal and transportation contract reductions
• Gas transport rate reduction
• Gas turbine uprates (incremental to 2016)

2017 PRIDE EBITDA Initiatives Progress 2017 PRIDE Balance Sheet Initiatives Progress Despite already exceeding our three year target in PRIDE balance sheet initiatives, Dynegy continues to find additional opportunities with over $75 MM in new initiatives identified in 2017:

• South Bay lease LC reduction
• Term loan repricing
• Tax credit monetization
• Railcar LC reduction

$135 $250 $65 $50

2016 2017 2018 Total

$200 $400 $100 $100

2016 2017 2018 Total 2016 Results

• f $150 MM

2016 Results

• f $422 MM

82% 93% 69% 82% 19% 52% 74% 80%

Financial/Physical Hedges Retail and Wholesale Contracts

37% 50% 13% 21% 10% 42% 43% 44%

Financial/Physical Hedges Retail and Wholesale Contracts

10

COMMERCIAL SUMMARY

(1) Represents 4/1/17 – 12/31/17; Note: Hedge percentages take into account the announced retirements of Brayton Point, Stuart and Killen as of their expected retirement dates

~40% ~50% ~10%

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

Generati tion Volum umes Hedged (1

(1)

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

29% 64% 44% 4%

Gas Coal IPH 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 (4/1 – 12/31)
• Hedge value represents value which should be added to a 3/31/17 open

valuation for modeling purposes to properly incorporate existing contracts

• Gross margin distribution for full year 2017

69% 91% 75% 24%

Gas Coal IPH Volume Contracted and Priced Volume Contracted but Not Priced

Fu Fuel Suppl pply Hedged (1

(1)

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 3/31/17 open

valuation for modeling purposes to properly incorporate existing contracts

• Gross margin distribution for full year 2018

~50% ~20% ~30%

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

Hed edge Va e Value $1.38/MWh Hedge ge P Position ion 77.3 MM MWh Hed edge Va e Value ($0.26)/MWh Hedge ge P Position ion 50.9 MM MWh

2017 as of 3/31/17 2018 as of 3/31/17

Generati tion Volum umes Hedged Fu Fuel Suppl pply Hedged

11

Successfully securing MISO capacity revenues outside of MISO auction

MISO FLEET CAPACITY REVENUES

$57 $149 $171 $118 $18 $39 $44 $50 $30 $24

PY 15/16 PY 16/17 PY 17/18 PY 18/19

Bilateral/Wholesale/Retail PJM Exports MISO Capacity Auction Transfers From Stuart and Killen (PJM Exports)

$188 $215

MISO Capacity (MW)

PY 17/18 PY 18/19

Available UCAP Capacity(1)

4,900 4,340

Sold in MISO Auction

• n/a

PJM Exports

1,045 1,230(2)

Bilateral/Wholesale/Retail Sales

3,425 2,119

Total Capacity Sold

4,470 3,349

Open Position

430 991

% of UCAP Capacity Sold

91% 77%

Average Price of Sold Capacity ($/kw-month)

$4.01 $4.79

$192

(1) Decline in PY 18/19 UCAP primarily driven by anticipated mothballing of Baldwin unit 1; (2) Includes Hennepin and Joppa MW which will be used to fulfill Stuart and Killen

capacity commitment when those facilities retire

Secured Capacity Revenues ($ MM)

$105

(2)

Avg price sold by DYN well over auction clearing price of $0.045/kw-month

904 (904) 204 (204) 653 367 1,020 628 722 1,350 312 (312)

Dec 2016 Ohio Coal Capacity Asset Retirements Decrease in Ownership Increase in Ownership Pro forma Ohio Coal Capacity

Net t Cap apac acity ty ( (MW)(1

(1)

Stuart Killen Miami Fort Zimmer Conesville 12

Acquiring full ownership of the most profitable JOU plants

CONSOLIDATING OWNERSHIP OF OHIO JOINTLY OWNED UNITS (JOU)

Conesville ille a and Z Zimmer C Consolid idatio ion ( (AEP)

• Dynegy to sell its ownership interest in Conesville to AEP

and acquire AEP’s interest in Zimmer

• Triggers $58 MM return of previously posted letter of

credit

• Expected to close second half of 2017

Miam ami F Fort an t and Z Zimmer C Consolidati tion ( (AES) S)

• Dynegy to purchase AES’ ownership interests in Miami

Fort and Zimmer for $50 MM, plus working capital adjustment, or ~$68/kW based on summer capacity rating

• Acquisition of AES’ interest at ~1.5 – 2.0x annual EBITDA
• Expected to close second half of 2017

Reti tirement o t of Stu Stuart an t and K Killen

• Partners agreed to retire Stuart and Killen in mid-2018
• Dynegy and its partners will retain their current ownership

interests through shutdown

• Dynegy’s portion of previously cleared capacity will be

transferred to other Dynegy plants with length

Expected Changes to Dynegy’s Ohio Coal Capacity Overview of Changes

(1) Net capacity based on winter ratings and reflects Dynegy’s proportionate share of each facility’s generating capacity

Dyn ynegy Owner ershi hip P Per ercen entages es Current Pro Forma Miami Fort 64 100 Zimmer 46.5 100 Conesville 40 Stuart 39 Retired Killen 33 Retired 2, 2,70 701 2, 2,37 370

1Q 2017 FINANCIAL RESULTS AND GUIDANCE UPDATE

14

FINANCIAL SUMMARY

Net Income/(Loss) ($ MM) Adjusted EBITDA Results ($ MM) Liquidity as of 3/31/2017 ($ MM)

Net I Incom come/(Los

• ss)
• Increased primarily due to a deferred tax valuation allowance

release in 2017 and a gain on the extinguishment of debt associated with the Genco reorganization Adjusted EB EBITDA

• Declined primarily due to lower capacity revenues and energy

margins in PJM and ISO-NE, partially offset by the contribution of the ENGIE assets and lower O&M costs from plant retirements Guidan ance ce

• Reaffirming 2017 Adjusted EBITDA guidance of $1,200 - 1,400 MM
• Raising 2017 Adjusted Free Cash Flow guidance from $150 - 350

MM to $300 – 500 MM − Incorporates previously disclosed ~$150 MM reduction in 2017 cash maintenance capital expenditures

• ~90% of gross margin from hedged energy margin, capacity sales,

tolls and retail

Financial Update

Revolving facilities and LC capacity $1,675 Less: Outstanding revolvers (300) Outstanding LCs (476) Revolving facilities and LC availability 899 Cash and cash equivalents 467 Total D Dyn ynegy y Inc. L Liquidity y $1,366 366

Guidance ($ MM)

2017 Adj EBITDA 2017 Adj FCF

$1,200 $1,400 $500 $300

$(10) $597

1Q16 1Q17

$251 $230

1Q16 1Q17

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

$177 ($2) $27 ($14) ($43) $145 $86 ($41) ($28) $35 ($14) ($87) ($49) 1Q16 1Q17 $209 $53 $20 $0 ($31) $251 $191 $42 ($9) $41 ($3) ($32) $230 1Q16 1Q17

15

FIRST QUARTER PERIOD-OVER-PERIOD SEGMENT PERFORMANCE

1Q P Q Period

• d-ove
• ver-Period A

d Adj djusted d EBIT ITDA ($ MM) 1Q P Q Period

• d-ove
• ver-Period Ope

Operating I g Income/(Loss) ss) ($ MM)

Adjuste sted E EBITD TDA Chang nges b by Sour urce

PJM PJM Q1 Contribution of ENGIE $16 MM Realized Energy Margin ($16) MM Capacity ($18) MM NY NY/NE NE Q1 Contribution of ENGIE $8 MM Realized Energy Margin ($12) MM Capacity/Tolls ($6) MM MI MISO Realized Energy Margin $3 MM Capacity $1 MM O&M $7 MM IPH Realized Energy Margin ($8) MM Capacity $17 MM CAISO Realized Energy Margin ($3) MM Capacity $2 MM O&M ($1) MM

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

Other NY/NE PJM MISO/IPH Consolidated CAISO ERCOT Other NY/NE PJM MISO/IPH Consolidated CAISO ERCOT

16

GUIDANCE UPDATE ($MM)

(1)

(1) Reflects timing of actual cash payments under long-term service agreements

Initial Guidance Current Guidance Comments on Material Changes

2017 Ad Adju just sted E EBITDA $1,200 200 – 1, 1,400 400 $1,200 200 – 1, 1,400 400 Cash Maintenance CapEx(1) (370) (210) Outage deferrals and reduced scope of work Environmental CapEx (20) (10) Stuart and Killen retirement Cash Interest (625) (600) Term loan repricing Other Cash Impacts (35) (80) Includes: pension, ARO spend, and other 2017 Ad Adju just sted F Fre ree Cash F h Flow $150 50 – 350 350 $300 00 – 500 500 2017 C Capital A Alloc

• cation

ion PJM Capacity Monetization ($65)

• Deferred PJM monetization repayment

Environmental Capital Projects ($65) ($5) Primarily ELG investment delayed two years Principal Payment ($55) ($45) Change in term loan amortization due to 1Q17 ENGIE close Uprate Investments ($30) ($30) Mandatory Preferred Dividend ($20) ($20)

Actively managing capital allocation

$2,100 ~$735 $480 ~$650

Debt Maturity (Nov 2019) Peaker Sale (Troy & Armstrong) Cash Generation (2017 & 2018) Mitigation Asset Sale Proceeds & Other Balance After Visible Inflows Sources of Funding

17

Visible path to repaying the 2019 maturity

MANAGING 2019 UNSECURED DEBT MATURITY ($ MM)

Other s sour urces o

• f f

fund unding in n addition to l liquid idit ity:

• 2019 cash generation
• Restructure second tranche of PJM

capacity monetization ($110 MM in 2018/2019)

• Retail receivable securitization
• Asset sales
• Further capacity monetization
• Debt offering/refinancing

Liqui uidity o

• f $1,

$1,36 366 M 6 MM as o

• f 3/31/1

3/31/17: 7:

• $467 MM cash
• $899 MM revolver and LC availability

(1)

(1) Expected cash generation for 2017 and 2018 calculated using the April 11, 2017 disclosed Adjusted EBITDA, adjusted for the sale of Troy and Armstrong assuming a

12/31/2017 closing date, less updated uses of cash as reflected on slide 21

$220 - 250

SUMMARY

19

KEY TAKEAWAYS

Ass sset sa sales p pro roceeding as s planned Op Optimizi zing th the Oh Ohio j joi

• intly ow
• wned u

units th through cons nsolidation a and nd re retirement nts Suff ufficient so sour urces o

• f l

f liquidity a y available to re repay e ent ntire 201 2019 de debt bt m maturity Eff ffective c cost st st structure m mana nagement re resu sults i in n ra raisi sing 2017 Adj djusted F d Free C Cash Flow g w guida dance

APPENDIX

21

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 that were driven by Dynegy’s active cost structure management. Total uses of cash have declined significantly from our previous estimate primarily due to deferring settlement of the PJM capacity monetization, a delay in forecasted ELG spend by two years and a reduction in cash maintenance capital expenditures.

2017 2018 2019 2017 2018 2019 Sold Capacity Revenues: Included in Adj FCF: PJM 580 $ 715 $ 630 $ Cash Maintenance CapEx (210) $ (295) $ (235) $ NY/NE 270 390 365 Environmental CapEx (10) (15) (15) MISO 160 140 85 Interest (600) (625) (620) CAISO 20 10 20 Asset Retirement Obligation (30) (25) (35) 1,030 $ 1,255 $ 1,100 $ Pension (5) (30) (20) O&M - Outage Costs (100) $ (115) $ (95) $ Capital Allocation: O&M - Shutdown Costs (25) $ (10) $

• $

PJM Capacity Monetization

• (65)

(115) Environmental Capital Projects (5) (30) (55) G&A Costs (140) $ (140) $ (140) $ Principal Payments (45) (50) (45) Uprate Investments (30) (10) (10) Mandatory Preferred Dividend (20)

• 2017

2018 2019 PJM 10 110 330 Total Uses of Cash (955) $ (1,145) $ (1,150) $ NYISO 75 455 820 MISO 595 1,605 85 1,160 2,755

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

PJM GENERATION FACILITIES (as of 3/31/2017)

22

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

PJM JM

Arm Armst strong Shelocta, PA 753 Gas / CT AD Hub Dom South Calum lumet Chicago, IL 380 Gas / CT NiHub Chicago CG Conesville lle* Conesville, OH 312 Coal / ST AD Hub NAPP 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 605 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 Troy roy Luckey, OH 770 Gas / CT AD Hub ANR Washingt gton

• n

Beverly, OH 711 Gas / CCGT AD Hub Tetco M2 Zimmer er* Moscow, OH 628 Coal / ST AD Hub 40% IL Basin / 60% NAPP PJM Seg egmen ent T Total 13,510 510

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 3/31/2017)

23

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 Br Bray ayto ton P Point Somerset, MA 1,488 Coal / ST Mass Hub 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 569 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 6, 6,54 543

ERCOT OT

Colet eto Creek eek Goliad, TX 635 Coal /ST ERCOT South PRB Enni nnis Ennis, TX 370 Gas / CCGT ERCOT North WAHA Hays ys San Marcos, TX 1,107 Gas / CCGT ERCOT South Katy Midloth thian an Midlothian, TX 1,712 Gas / CCGT ERCOT North WAHA Whar arto ton Boling, TX 85 Gas / CT ERTCOT HOU HSS Wi Wise Poolville, TX 787 Gas / CCGT ERCOT North WAHA ERCOT To T Total 4, 4,69 696

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 3/31/2017)

24

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 G GENE NERATI TION 31,410 410

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 scheduled 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 (APR 12 PRICING)

25 $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 ($/MWh) New York Zone A ($/MWh) NP-15 ($/MWh) Natural Gas ($/MMBtu)

2018 2017 A/F (Apr)(1)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 4/12/2017 and quoted forward ATC monthly prices for 4/13/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through April 12, 2017 and 2017 forward monthly prices for the balance of the year based on April 12, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on April 12, 2017 pricing

2017 A/F (Apr): $30.18 2018 Forward: $30.38

(2) (3)

2017 A/F (Apr): $26.30 2018 Forward: $28.04

(2) (3)

2017 A/F (Apr): $30.52 2018 Forward: $30.44

(2) (3)

2017 A/F (Apr): $3.24 2018 Forward: $3.08

(2) (3)

COMMODITY PRICING AROUND-THE-CLOCK POWER (APR 12 PRICING) (CONTINUED)

26 $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 (Apr): $34.44 2018 Forward: $38.89

(2) (3)

2017 A/F (Apr): $30.17 2018 Forward: $30.42

(2) (3)

2017 A/F (Apr): $31.16 2018 Forward: $31.94

(2) (3)

2017 A/F (Apr): $27.86 2018 Forward: $27.81

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 4/12/2017 and quoted forward ATC monthly prices for 4/13/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through April 12, 2017 and 2017 forward monthly prices for the balance of the year based on April 12, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on April 12, 2017 pricing

2018 2017 A/F (Apr)(1)

COMMODITY PRICING AROUND-THE-CLOCK POWER (APR 12 PRICING) (CONTINUED)

27 $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 (Apr): $26.33 2018 Forward: $25.18

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 4/12/2017 and quoted forward ATC monthly prices for 4/13/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through April 12, 2017 and 2017 forward monthly prices for the balance of the year based on April 12, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on April 12, 2017 pricing

2018 2017 A/F (Apr)(1)

SPARK SPREADS AROUND-THE-CLOCK (APR 12 PRICING)

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 $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 (Apr): $10.49 2018 Forward: $9.91

(2) (3)

2017 A/F (Apr): $5.82 2018 Forward: $7.24

(2) (3)

2017 A/F (Apr): $7.11 2018 Forward: $7.52

(2) (3)

2017 A/F (Apr): $6.52 2018 Forward: $7.80

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 4/12/2017 and quoted forward ATC monthly prices for 4/13/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through April 12, 2017 and 2017 forward monthly prices for the balance of the year based on April 12, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on April 12, 2017 pricing

2018 2017 A/F (Apr)(1)

SPARK SPREADS AROUND-THE-CLOCK (APR 12 PRICING) (CONTINUED)

29 $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 A/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 (Apr): $7.11 2018 Forward: $10.11

(2) (3)

2017 A/F (Apr): $5.77 2018 Forward: $6.45

(2) (3)

2017 A/F (Apr): $10.98 2018 Forward: $12.48

(2) (3)

(1) Prices reflect actual day ahead ATC settlement prices for 1/1/2017 - 4/12/2017 and quoted forward ATC monthly prices for 4/13/2017 -12/31/2017 (2) Single price provided

reflects full year estimated ATC price for 2017 using a mix of 2017 actuals through April 12, 2017 and 2017 forward monthly prices for the balance of the year based on April 12, 2017 pricing (3) Single price provided reflects full year estimated ATC price for 2018 based on April 12, 2017 pricing

2018 2017 A/F (Apr)(1)

$12 $10 $27 $5 $1 $4 $1 $1 $1 $1 $3 $5 $1 $2 $6 $1

1Q161Q17 1Q161Q17 1Q17 1Q161Q17 1Q161Q17 1Q161Q17 1Q161Q17

Environmental Maintenance

CAPITAL AND MAJOR MAINTENANCE O&M

30

PJM

• Capital spending decreased due to fewer

coal fueled outages, offset by an increase in gas fueled spending due to the addition

• f the ENGIE fleet

NY/NE

• Capital spending decreased due to fewer

planned outages at the legacy fleet

ERCOT

• Capital spending increased due to the

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

Corporate

• Capital spending decreased primarily due

to systems upgrades in 1Q 16

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

All Segments

• Decrease in maintenance expense mostly

due to fewer planned major outages across the fleet

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

$11 $7 $7 $7

1Q16 1Q17 Major Maintenance Capital Removal/Other

$18 $14

PJM NY/NE ERCOT MISO IPH CAISO Corp/Other

77% 72% 91% 92% 92% 58% 92% 61% 61% 74% 85% 86% 31% 6% 5% 5% 6% 7% 11% 5% 21% 30% 19% 98% 3% 2% 1% 2% 0% 0% 2% 14% 5% 1% 2% 7% 17% 20% 7% 4% 17% 1% 15% 0% 12% 9% 10% 40%

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

PJM

31

1Q16 & 1Q17 FLEET PERFORMANCE – GAS FLEET

43% 42% 63% 69% 54% 71% 14% 12% 11% 13% 28% 8% 5% 7% 11% 0% 10% 100% 9% 4% 5% 74% 51% 18% 49% 53% 22% 25% 24% 14% 73% 81% 90% 87% 96% 11% 49% 69% 94%

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(2) Sayerville(2) Independence Casco Bay Lake Road Milford Dighton MASSPOWER Bellingham (ANP)(2) Bellingham (NEA)(2) Blackstone(2) Milford MA(2)

(1) Net Capacity Factor is based on the NERC method of calculation, which uses a maximum capacity rating; (2) Based on February – March

32

1Q16 & 1Q17 FLEET PERFORMANCE – GAS FLEET (CONTINUED)

10% 16% 10% 29% 14% 5% 5% 6% 7% 5% 11% 12% 15% 17% 5% 84% 71% 73% 99% 80% 55% 64% 2017 2017 2017 2017 2017 2016 2017 Net Capacity Factor Seasonal Derate Planned Outage Unplanned Outage Uneconomic

ERCOT

Ennis(2) Hays(2) Midlothian(2) Wharton(2) Wise(2) Moss Landing 1 & 2

CAISO

(1) Net Capacity Factor is based on the NERC method of calculation, which uses a maximum capacity rating; (2) Based on February – March

32% 68% 82% 73% 84% 41% 31% 65% 83% 56% 24% 18% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 100% 8% 6% 35% 11% 5% 16% 6% 11% 16% 51% 23% 15% 30% 74% 57% 27% 21% 43% 10% 12% 9% 43%

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 (4) Kincaid Zimmer(2) Miami Fort Conesville(3) Killen(3) Stuart(3)

52% 64% 49% 66% 46% 71% 43% 70% 48% 41% 46% 68% 29% 32% 35% 48% 14% 15% 6% 8% 20% 8% 14% 13% 21% 15% 16% 17% 6% 10% 8% 34% 21% 44% 26% 34% 19% 43% 18% 31% 45% 38% 15% 66% 58% 62% 44%

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

MISO – Coal

33

1Q16 & 1Q17 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; (4) Based on February – March

PJM – Coal

Baldwin Havana Hennepin Coffeen Duck Creek Edwards Joppa Newton

IPH

(1)

ERCOT – Coal

OPERATIONAL STATISTICS

34

Combined Cycle Generation 1Q16 1Q17

Total tal G Generat ation (MM MWh) California 0.7 0.3 ERCOT N/A 0.4 NY/NE 3.1 3.7 PJM 9.4 8.4 98.9% 94.7% In In-Mar arke ket-Av Availa ilabilit ility California ERCOT N/A 97.1% NY/NE 88.8% 97.6% PJM 97.5% 89.4% 29.3% 13.8% Averag age C Cap apac acity ty Fac acto tor

(1) 1)

California ERCOT N/A 9.3% NY/NE 39.9% 37.1% PJM 83.0% 67.8%

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

OPERATIONAL STATISTICS, CONT.

35

Coal Generation

(1)

1Q16 1Q17

Total tal G Generat ation (MM MWh) Coleto Creek N/A 0.2 MISO 3.3 2.7 PJM 3.5 4.9 Brayton Point 0.8 1.0 In In-Mar arke ket-Av Availa ilabilit ility Coleto Creek N/A 93.4% MISO 89.3% 89.0% PJM 76.6% 64.9% Brayton Point 91.8% 81.6% Averag age C Cap apac acity ty Fac acto tor

(2) 2)

Coleto Creek N/A 18.4% MISO 50.4% 65.4% PJM 42.6% 60.5% Brayton Point 24.0% 32.6%

IPH(1) 1Q16 1Q17

Tota tal Ge Generati tion (MM MWh) 3.3 3.8 In In-Mar arket-Av Availa ilabilit ility 86.1% 86.3% Average C Cap apac acity F Fac acto tor(2)

2)

38.5% 52.4%

(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

36

Average Actual Power/Gas Prices ($/MWh)

1Q16 1Q17

On-Peak Off-Peak On-Peak Off-Peak Indy Hub $25.61 $20.18 $32.65 $25.17 Mass Hub $33.85 $26.21 $37.76 $33.19 NP-15 $26.09 $21.40 $31.74 $24.90 NY - Zone A $25.67 $13.89 $29.75 $22.05 PJM-W $31.49 $25.59 $32.52 $27.33 AD Hub $28.80 $22.92 $31.39 $26.17 NiHub $27.34 $20.55 $30.27 $24.04 Ercot N $19.62 $14.82 $23.54 $19.11

Average Trading Hub Spark Spreads ($/MWh)

1Q16 1Q17

On-Peak Off-Peak On-Peak Off-Peak PJM West/TetM3 $18.73 $12.82 $11.38 $6.20 NiHub/ChiCG $13.06 $6.27 $9.40 $3.18 NP-15/PGE $10.71 $6.03 $8.34 $1.50 NY-Zone A/Dominion $16.69 $4.90 $10.99 $3.29 Mass Hub/Algonquin $10.82 $3.18 $6.63 $2.06 AD Hub/Dominion $19.81 $13.94 $12.63 $7.41 Ercot N/Waha $6.65 $1.85 $4.11

• $0.31

37

MISO CAPACITY POSITION (excludes PJM exports)

Price in $/kw-mo MISO MISO - IPH Total EBITDA Contribution PY 16/1 16/17 MWs 1,011 2,246 3,257 Average Price $2.75 $4.30 $3.81 $149 MM 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 1,877 2,119 Average Price $2.68 $4.91 $4.65 $118 MM PY 19/2 19/20 MWs 185 881 1,066 Average Price $2.60 $4.85 $4.46 $57 MM PY 20/2 20/21 MWs 185 669 854 Average Price $2.71 $5.21 $4.67 $48 MM Total tal M MWs 2, 2,69 698 8, 8,02 023 10,721 721 Av Avera rage Price ce $2. $2.98 $4. $4.64 $4. $4.22 $54 $543 MM MM

MISO EXPORTS TO PJM CAPACITY POSITION

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

RTO 2016-2017 $153.00 50 $134.00 730 2017-2018 $86.55 573 $151.50 472 2018-2019 $0.00 $164.77 835 2019-2020 $80.00 260 $100.00 356

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)

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

RTO 2016-2017

$97.24 1,116 $134.00 4,478

2017-2018

$127.20 2,042 $151.50 3,965

2018-2019

$155.80 1,754 $164.77 4,367

2019-2020

$80.00 1,356 $100.00 4,378

ComEd 2016-2017

$59.37 974 $134.00 2,122

2017-2018

$121.33 919 $151.50 2,261

2018-2019

$200.21 317 $215.00 2,504

2019-2020

$182.77 317 $202.77 2,830

MAAC 2016-2017

$119.34 451 $134.00 51

2017-2018

$26.50 3 $151.50 508

2018-2019

$149.98 $166.83 508

2019-2020

$80.00 $127.21 515

EMAAC 2016-2017

$119.43 634 $134.00 53

2017-2018

$122.12 154 $151.50 533

2018-2019

$210.63 148 $225.42 532

2019-2020

$99.77 $119.77 679

ATSI 2016-2017

$115.05 981 $134.00

2017-2018

$127.56 405 $151.50 592

2018-2019

$149.98 $164.77 815

2019-2020

$80.00 $100.00 845

PPL 2016-2017

$119.13 52 $134.00

2017-2018

$121.53 49 $151.50

2018-2019

$75.00 48 $164.77

2019-2020

$80.00 48 $100.00

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

40

Capacity / Resource Adequacy

ISO/Region Contract Type Average Price Size (MW) Tenor ISO-NE(1) ISO-NE Capacity $3.19/kw-Mo 4,167 June 2016 to May 2017 $6.98/kw-Mo 3,581 June 2017 to May 2018 $10.08/kw-Mo 3,562 June 2018 to May 2019 $7.02/kw-Mo 3,544 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 $3.41/kw-Mo 915 Summer 2017 $2.48/kw-Mo 780 Winter 2017/18 $3.66/kw-Mo 620 Summer 2018 $3.32/kw-Mo 330 Winter 2018/2019 $3.39/kw-Mo 255 Summer 2019 $3.43/kw-Mo 118 Winter 2019/2020 $3.45/kw-Mo 50 Summer 2020 CAISO RA Capacity 746 Avg Bilateral Sold Cal 2017 400 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 April and the Summer period covers May through October;

REG G RECONCILIATIONS

APPENDIX

42

REG G RECONCILIATION – 1ST QUARTER 2017 ADJUSTED EBITDA

43

REG G RECONCILIATION – 1ST QUARTER 2016 ADJUSTED EBITDA

44

REG G RECONCILIATION – DYNEGY 2017 ADJUSTED EBITDA AND UPDATED ADJUSTED FREE CASH FLOW GUIDANCE

45

REG G RECONCILIATION – DYNEGY 2017 ADJUSTED EBITDA AND PRIOR ADJUSTED FREE CASH FLOW GUIDANCE