2 Forward Looking Statements Cautionary Statement Regarding Forward-Looking Statements 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 2013 Form 10-K, 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-GAAP Financial Measures This presentation contains non-GAAP financial measures including EBITDA, Adjusted EBITDA and 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 February 27, 2014, which is available on our website free of charge, www.dynegy.com.

6 Geographic and Fuel Diversification Note: Net capacity shown based on winter capacity; (1) Dynegy owns 50% interest in Black Mountain; (2) Net MW reflecting 80% interest in EEI, which owns Joppa Steam and MEPI Joppa 6B Oakland 165 MW Moss Landing 1&2 1,020 MW Moss Landing 6&7 1,509 MW Baldwin 1,800 MW Havana 441 MW Wood River 446 MW Hennepin 293 MW Ontelaunee 580 MW Kendall 1,200 MW Independence 1,064 MW Black Mountain (1) 43 MW Casco Bay 540 MW Duck Creek 425 MW Edwards 695 MW Joppa 802 MW(2) Coffeen 915 MW Newton 1,225 MW Morro Bay Today Dynegy operates a 13 GW portfolio with diverse generation complemented by an integrated retail portfolio Coal Segment IPH Retail Gas Segment Development ~3,000 MWs of baseload capacity Environmentally compliant with current regulations Burns low sulfur Powder River Basin coal Low-cost fuel due to favorable long-term rail contracts ~4,000 MWs of baseload capacity Environmentally compliant with current regulations Burns low sulfur Powder River Basin coal Retail business serving ~13 TWh of load in Illinois Serves C&I and Municipal Aggregation customers in Ameren and ComEd service territories ~6,000 MWs of total generating capacity ~4,400 MWs of combined cycle capacity Exploring renewable energy alternatives at Morro Bay site Evaluating peaking capacity at Oakland 80 MW uprate at Kendall

Market Trends 7 Market recovery gaining momentum spurred by plant retirements Rising Gas and Power Prices Signed bilateral MISO capacity contracts for planning years 14/15 through 19/20 at weighted average price of ~$2.00/kw-month, but for relatively small volume ISO-NE capacity prices (Casco Bay) more than doubled in last auction Flexible capacity market in California expected 2015 Developing Capacity Markets 9.1 GW of announced MISO retirements to-date; 4.9 GW announced at year end 2012 556 MW Kewaunee Power Station nuclear plant in Wisconsin shut down Illinois-based Clinton, Quad Cities and Byron nuclear stations may also be considered at-risk Increasing Retirements 2014 2015 Prices As of Jan 13(1) As of Mar 14(2) As of Jan 13(1) As of Mar 14(2) NYMEX (per MMBtu) $3.97 $4.61 $4.19 $4.20 Indy Hub on-peak (per MWh) $36.85 $51.01 $37.95 $41.37 NY Zone A on-peak (per MWh) $39.61 $65.76 $40.21 $48.46 (1) As of 1/2/2013; (2) As of 3/31/14 – Jan-Mar are average of daily settlement

2014 Adjusted EBITDA Potential 8 $505 Adjusted Unhedged EBITDA Potential (in $MM) Our $500MM Adjusted EBITDA potential discussed at 2013 Investor Day delivered sooner than expected Sustainable Earnings and Cash Flow 2014 Adjusted EBITDA Contract Rolloffs Mitigated Independence benefitting from Marcellus gas supply and higher power prices Moss Landing 6&7 contracted through 2016(3) PRIDE Reloaded PRIDE Reloaded targeted to deliver additional $75MM EBITDA in 2015-2016 Environmental Spend Manageable Assuming the final EPA rules on Effluent Limit Guidelines and Coal Combustion Residuals follows a “preferred technology” and designates coal ash as “non-hazardous material,” average spend estimated at ~$25MM per year over 5 year compliance horizon for the fleet Assuming proposed Federal and State Once-Through Cooling regulations are finalized with few changes, compliance costs are expected to average ~$8MM per year over 5 year compliance horizon for the fleet Targeting end of decade for recycling 100% of our coal ash and scrubber waste (1) Forecasted hedge settlements as of February 10,2014; (2) Midpoint of 2014 Adjusted EBITDA guidance as presented on February 27, 2014; (3) 2016 subject to approval by the California Public Utilities Commission

Dynegy’s Investment Thesis 9 Upside Potential Doubled This year’s story – 2x’s better than last year Greater Opportunities for Deploying Excess Capital Significantly Strengthened Financial Base One Year Ago Today Limited Downside Risk Multiple Avenues for Substantial Upside Capital Allocation Opportunities PRIDE Reloaded savings doubled EBITDA sensitivities doubled Share repurchases Portfolio acquisitions Redevelopment No corporate level maturities until 2020 Over $1 billion of liquidity as of 3/31/14

Upside Potential Doubled – MISO Recovery 11 Coal plant retirements Highly leveraged to MISO market recovery, but not dependent on it EBITDA Sensitivities(1) Market Recovery Dynamic Annual Impact of One Year Ago Today $2/kW-month MISO Capacity price increase ~$65MM ~$150MM MISO ATC Power Clearing Price increases by $4/MWh ~$85MM ~$175MM $1/MMBtu increase in Natural Gas prices (net of ~0.6 heat rate contraction) ~$80MM(2) ~$180MM(2) Dynegy MISO MWs ~3,000 ~7,000 (1) Assumes full annual contribution from unhedged portfolio; (2) Reflects revised approach of treating basis as percentage of INDY Hub price Reserve margin tightens Natural gas generation backfills retirements Energy and capacity prices rise

Greater Opportunities for Capital Allocation 13 Development Investments Extrinsic Opportunities Share Repurchases Excess capital allocated based on risk-adjusted returns Safety, Environmental, Reliability Intrinsic Investments PRIDE Excess Capital for Allocation First order of Capital Allocation Typical payback periods < 12 months; compelling IRRs Non- Discretionary Discretionary

Value Drivers 14 Our two pillars of value creation Commercial Retail Regulatory Operations PRIDE Reloaded Financial Customer Focus Continuous Improvement Creating multiple channels to market for energy and capacity Efficient and effective hedging of energy and capacity Active participation in market design and environmental rule making Achieving best-in-class operating performance PRIDE, the “self-help” solution Driving increased Return on Invested Capital while lowering the cost of capital

Customers Customer Focus 15 Working with customers to achieve stakeholders’ goals Commercial Retail Regulatory Utilities Municipalities Cooperatives Retail Aggregators Large C&I customers Municipal Aggregation consultants Brokers and agents Federal regulators Federal and state policy makers ISOs PUCs Bilateral multi-year capacity contracts Wholesale block energy and capacity sales Request for Proposals Sales calls Municipal Aggregation contract award process Shape regulatory outcomes Ensure constructive market design Advocate for achievable environmental rules Perspective on customers’ market views Value of existing generation vs. new build Leading indicator of market shifts Understanding emerging customer needs Identify common goals for compliance Multi-year bilateral capacity and energy sales $10 - 20MM normalized annual EBITDA contribution Manageable environmental spend and functioning competitive markets Engagement Insight Expected Results

Continuous Improvement PRIDE Delivered $146MM of EBITDA improvement and $715MM of balance sheet improvement Synergies Captured $95MM in synergies from the Ameren Energy Resources acquisition 16 A culture of continuous improvement in everything we do 2011-2013 2014-2016 Objectives Operations PRIDE Reloaded Financial Safety Top decile safety performance Plant Performance Coal segment and IPH targeting long-term Equivalent Availability Factor (EAF) of >90% Capex Ensuring reliability and environmental compliance 2014-2016 Targets $135MM EBITDA uplift and $165MM balance sheet improvement over next 3 years Continuous Improvement Culture New Operations Support organization created to leverage scale and drive best practices throughout the portfolio Financial Optimization Reduce capital required to run the business Ensure adequate liquidity Drive Return on Invested Capital Allocate excess capital to the highest risk-adjusted rate of return investments

Valuation 17 Net Debt 2014 Adjusted EBITDA Potential 7.3x EV/EBITDA $ millions except share price Share Price ~$25.00 Shares Outstanding 100 Equity Value ~2,500 Value of Equity Enterprise Value Implied EV/EBITDA Multiple External Drivers Potential Upside EBITDA Impact vs. 2014 ($ MM) $5.00 per MMBtu Natural Gas $76 $1/kw-mo MISO Capacity Price $75 $2 Around-the-Clock MISO Power Price Uplift $88 $325(1) $ MM except share price Dynegy Net Debt 594 IPH Net Debt 595 Total Net Debt 1,189 $ millions except share price Net Debt $1,189 Equity Value ~2,500 Enterprise Value 3,689 Enterprise Value Multiple drivers – any one providing substantial equity value upside (1) Midpoint of 2014 Adjusted EBITDA guidance as presented on February 27, 2014; (2) Forecasted hedge settlements as of February 10, 2014 2016 EBITDA Impact ($ MM) 2015-16 PRIDE Reloaded $75 2015 Net Contract Expirations ($27) 2016 EBITDA Impact $48 Internal Drivers ($MM) Equity Impact Examples Impact of $50MM EBITDA on Share Price Multiple $/share % DYN 7.3x $3.65 14.6% CPN 9.0x $1.06 5.1% NRG 8.0x $1.23 3.8% $180(2)

Commercial Markets Overview 19 Illinois Northeast West MISO PJM, NYISO, ISO-NE CAISO 7,042 MWs of low-cost PRB coal fired generation MATS and CSAPR compliant 13 TWh of retail load 1,780 MWs of efficient CCGT in PJM (before Kendall uprate) 1,064 MWs of efficient CCGT in NYISO 540 MWs of efficient CCGT in ISO-NE 80 MW uprate planned at Kendall – 40 MW underway 1,020 MWs of efficient CCGT 1,509 MWs fast-ramping peaking capacity Development opportunities at Morro Bay and Oakland Coal fleet positioned to benefit from market improvements while Retail portfolio provides efficient channel to market Gas segment driving strong EBITDA from advantageous fuel supply and constructive capacity markets California portfolio supporting California’s energy needs

MISO Overview 20 MISO Snapshot MISO Zonal Map MISO is responsible for system reliability, market design, operation and regional planning for all or part of 14 states and part of Canada MISO South, comprised of zones 8 and 9, integrated into MISO in December 2013 Capacity of 111 GW in MISO Classic; 45 GW of capacity in MISO South; total MISO capacity of 156 GW Projected investment of $11 billion for MISO Transmission Expansion Plan through 2019 Initial MISO capacity auction conducted in March 2013 for the 2013/2014 resource adequacy planning year Subsequent capacity auctions conducted on two-month forward look in March for planning year commencing June 1st 2013 Generation Fuel Mix

MISO Reserve Margins 21 “Only in one regional power market, MISO, is our forecast of additional coal plant retirements sufficiently large as to bring reserve margins materially below NERC’s target levels by 2015.” Bernstein Research. “EPA MATS Rule Will Drive 59 GW of Coal Plant Retirements Through 2017; What Does It Mean for Gas and Coal Consumption?” - March 21, 2014 MISO required reserve margin ~15%; estimated reserve margin ~10%

MISO Classic Capacity – Current Forecast 22 GWs We expect retirements will drive down MISO installed capacity, triggering a 2015-2016 market recovery 85 Units Average Size – 107 MWs Average Age – 50 Years 24 Units Average Size – 83 MWs Average Age – 51 Years Excludes any at-risk nuclear retirements (1) Source: MISO 2013 Summer Assessment, Table 1-1 (2) Net of coal to gas conversions (3) In site preparation, testing or under construction (4) Likely to retire due to prohibitive cost and short time frame for MATS compliance (5) Dynegy estimate: Includes Entergy South and other imports net of PJM exports (see slide 24) (6) Peak Load Obligation, net of Demand Response resources plus 15% Reserve Margin

Economics of MISO Environmental Compliance 23 MATS Compliance Deadline with 1-Year Extension MATS Compliance Deadline (1) Source: EEI; 2008 $/kw based on 100 MW unit; (2) Source: MISO study; (3) ESP cost and timeline based on Dynegy estimates; (4) DSI cost based on MISO study PRB plants require a baghouse or Electrostatic Precipitator (ESP) and Activated Carbon Injection (ACI) to comply with MATS particulate and mercury limits; PRB coal meets acid gases limit Bituminous coal plants require a baghouse or ESP and ACI to comply with MATS particulate and mercury limits; additional controls required to address acid gases Environmental compliance economics likely to drive retirements Control $/ kW Cost for 100 MW Unit(1) Wet-FGD $799 Dry-FGD $697 SCR $492 Baghouse $438 ESP Upgrade(3) $150 ACI $27 DSI(4) $40 Control Equipment Installation Timeline(2) 2014 Compliance Requirements (3) Minimum time Maximum time

Change in Import/Export Our MISO reserve margin analysis includes 1.1 GW of net imports Import/Export Source -3.4 GW of exports to PJM +3.1 GW of imports into MISO +1.4 GW of imports from MISO South MISO’s LongTerm Resource Assessment (LTRA) and PJM’s Base Residual Auction (BRA) MISO’s LTRA MISO Engineering transmission study(1) +1.1 GW of Net Imports 24 Import / Export Assumptions – Impact on MISO Capacity Market Capacity Import Limit 1.4 GW Transmission constraints dictate Import and Export limitations Imports from MISO South Exports to PJM 3.4 GW Exports to PJM (1) May 2013 MISO transmission study

Additional Potential Impact on MISO Supply/Demand 25 – MISO supply/demand shortfall remains likely; potentially offsetting factors could impact order of magnitude + MISO South to North transmission constraint, assumed at 1.4 GW, could be higher depending on the resolution of MISO/SPP dispute MISO has identified up to 5.7 GW of “trapped” capacity within the system constrained by transmission; MISO Transmission Expansion Plan projects could ease some of these constraints Additional Demand Side Management resources could come into the market as a result of higher auction clearing prices Unforeseen retirements, such as nuclear plants, would further tighten the MISO system Asset derates could trend higher over time due to plant age and limited capital reinvestment Annual load growth could be in excess of MISO’s 0.8% estimate in the 2013 Summer Resource Assessment

26 MISO Capacity Market Design When resources fall short of requirements in a market with a vertical demand curve, prices spike to the Cost of New Entry (CONE) Plant retirements drove resources below the vertical demand curve resulting in the capacity price spiking to the administrative cap MISO’s capacity auction construct uses a vertical demand curve, similar to ISO-NE Cleared at the Floor ISO-NE Crossed Vertical Demand Curve (1) MISO Zone 4 CONE for 2014/2015 planning year ISO-NE Auction Clearing Prices $/kw-month MISO Vertical Demand Curve Market Structure Illustrative P Peak Demand Price jump Last MW Available Clears Supply Curve CONE $7.49/kw-mo(1) Vertical Demand Curve (Planning Reserve Margin) Q Example: Recent ISO-NE results

MISO Resource Adequacy Construct 27 Planning Reserve Margin Requirement Anticipated Peak Demand Bilateral Transactions Five Options to Satisfy Capacity Requirement Planning Reserve Margin Self-Scheduling Fixed Resource Adequacy Plan (FRAP) Annual Capacity Auction Capacity Deficiency Charge MISO advising LSE’s to procure longer-term bilateral capacity contracts

28 Multiple Channels to Sell MISO Capacity Channel Products/Market Results Wholesale Full requirements; cost-based; fixed-priced capacity Long term capacity contracts in place Recent long-dated bilateral capacity contracts signed Retail Municipal aggregation/Commercial & Industrial 13 TWh of Retail load Exports PJM ~840 MWs into PJM in place 200 MWs from Hennepin and 1,000 MWs from Joppa in PJM queue Auctions MISO Compensation for capacity Dynegy 2014/2015 MISO Capacity Sales Volume (in MWs) Dynegy Future MISO Capacity Sales Volume (in MWs) Recent bilateral capacity contracts signed at weighted average price of ~$2.00/kw-month, sending strong pricing signal to the market

MISO Dispatch Stack with Retirements 29 (1) MISO Central includes Zones 4-7; reflects announced and projected retirements and new builds; reflects 2016 forward prices as of 02/28/2014 (2) Assumes 44MM MWh of generation 2016 No Retirements Expected retirements add ~$60MM(2) to consolidated energy revenues; higher natural gas prices would further impact results 2016 With Retirements Projected Pricing Impact ($/MWh) Retirements alone ~$1.40 ATC

30 MISO South Impact on Energy Prices High Heat Rate MISO South Energy Resources MISO South Dispatch Generation dispatch merit order matters MISO South relies on higher cost Combustion Turbine and Steam Gas units to serve load during high demand Despite length in MISO South, power has flowed North to South, particularly in periods of high demand In periods of high demand we expect energy to flow North to South GWs

31 Maximizing Locational Marginal Prices THEN NOW IPH historically dispatched in a “Must Run” mode, resulting in higher production, but negative margins for some output Economic Dispatch We bid all units based on economics Economic dispatch can reduce congestion and mitigate basis Hedges executed at INDY Hub Hedging Hedges at INDY Hub primarily executed as “matched hedges” which pairs an FTR or busbar swap with the INDY Hub hedge Locational Marginal Prices may differ from INDY Hub prices for unhedged generation, but there is no direct financial cost to Dynegy for the basis differential No active role in transmission development Transmission Investment Signed Letter of Intent to jointly develop Baldwin Transformer Upgrade and line reconductoring Estimated cost of $15-20MM will be shared with partners Initiatives in place to realize higher Locational Marginal Prices

32 Gas Segment Markets Overview CAISO ISO-NE NYISO PJM High capacity factors for natural gas fired generation Constructive forward looking capacity market 2013 Generation Fuel Mix Flexible capacity market being developed in California should benefit Moss Landing’s baseload and peaking capacity Market expected to commence in 2015; Moss 6&7 has contract cover through 2016(1) Higher NYISO capacity prices Region benefits from gas procurement from Marcellus Longer term, we expect strengthening Rest of State capacity pricing On February 5, 2014, ISO-NE capacity results for the 2017/2018 auction cleared at the administrative cap of $7.025 / kW-month Gas access from Deep Panuke supports higher run times and improving margins Wind Other Hydro Nuclear Natural Gas Coal Oil Kendall, Ontelaunee Independence Casco Bay Moss Landing, Oakland (1) 2016 subject to approval by California Public Utilities Commission

Gas by Wire Advantageous gas supply upstream of natural gas pipeline bottlenecks combined with power sales into northeast drive strong spark spreads Infrastructure bottlenecks are expected to persist given difficulty of securing pipeline right-of-way in Northeast population centers Spark spreads expand significantly when the system is constrained and driving commodity price volatility Independence 33 (1) Through 3/31/2014 Gas Pipeline Bottlenecks Independence Independence EBITDA Waterfall Expiration of Consolidated Edison contract largely offset On-Peak Spark Spread $/MWh Marcellus Gas Supply 2011 $12.90 0% 2012 $14.02 60% 2013 $14.29 86% YTD 2014(1) $72.26 90% Benefits from lower cost Marcellus gas supply Sells power into constrained markets

Ontelaunee, Casco Bay and Kendall 34 Benefitting from strong eastern power demand Attractive spark spreads and capacity factors 2013 on-peak spark spread of $15.38 per MWh and year-to-date on-peak spark spread of $42.84 per MWh(1) Robust capacity market Improving natural gas supply from Deep Panuke improving capacity factors year-to-date; targeting 25% Expect additional capacity factor improvement in shoulder months Recent 2017/2018 capacity auction cleared at $7.025/kw-month, which increases Casco Bay’s EBITDA by ~$20MM 2013 on-peak spark spread of $9.54 per MWh and year-to-date on-peak spark spread of $6.81 per MWh(1) 40 MW uprate online in 2014; additional 40 MW uprate online in 2016 Uprates captured in renegotiated service agreement Positioned to benefit from tightening ComEd region Ontelaunee Casco Bay Kendall Gas segment’s gross margin expected to continue to strengthen (1) Through 3/26/2014

Support for Wind and Solar California Portfolio Strategy 35 Moss Landing 1&2 1,020 MW modern efficient CCGT Pursuing renewable energy alternatives 1,509 MW fast-ramping peaking capacity Contracts in place covering 2014-2016(1) Oakland Morro Bay Supporting California’s Energy Needs Uniquely positioned in Bay Area “load pocket” for repowering Retained 650 MWs of transmission rights Moss Landing 6&7 Redevelopment Alternative Energy Platform Efficient Baseload Resource Pursuing baseload alternative energy projects for site such as Energy Storage and Wave Energy Converting technology Potential technologies include fast-start peaking capacity and/or energy storage Positioning portfolio to meet California’s energy needs (1) 2016 subject to approval by the California Public Utilities Commission

2014E Sales by Customer (MWh) 38 Retail portfolio provides a channel to monetize generation assets Located in Collinsville, Illinois Largest retail supplier in Ameren territory, with a growing presence in ComEd (PJM) 13 TWh volume in 2013 ~40 employees related to retail functions, including support groups Retail Business Snapshot Homefield Energy is the largest retail electricity supplier in Southern Illinois Fast Facts Serves ~500,000 Commercial, Industrial and Residential customers in Illinois Residential customers served through Opt-Out Municipal Aggregation deals, brokered through Agents – not marketed directly to consumers Customers 2014E Sales by Territory (MWh) 2014E MISO Competitive Market (MWh)(1) (1) Based on ICC utility switching statistics, MISO load data, and internal analysis; “Other” category includes additional 25 registered Retail Electricity Suppliers in Southern Illinois Homefield Ameren Illinois Supplier A Supplier B Other

39 Linking load and generation provides a cost-efficient, long-term hedge for both energy and capacity Insight Earnings Risk Reduction Delivers an incremental source of EBITDA Brings a customer focus and consumer-level insight to the portfolio Strategy Description Retail Strategy In addition to an anticipated normalized $10-$20MM in annual Adjusted EBITDA contribution, the Retail portfolio has important benefits for Dynegy Actively acquire load from target customer base in MISO to match generation length Tailor product offerings to meet emerging MISO customer needs Opportunistically grow the business in PJM Diversify revenue streams and provide source of upside in challenging power markets Benefits of Retail Business

Retail Customers 40 Large Commercial & Industrial Municipal Aggregation Cost competitive Expertise in wholesale markets Knowledgeable sales team Win Rate 80% Renewal Rate 83% Cost competitive Reputation and proven track record Local community presence Win Rate 75% Renewal Rate 95% Our target customers offer large amounts of load and are inexpensive to serve Target Customers Low Cost to Serve Accounts range from 5-100 MWs 2 Year RFP for 25-100 aggregated communities up to 1,000 MWs Typical Customer Size Compelling Product Offering Margins $1.00 - $4.00 per MWh Margins vary by customer type and by market Large amounts of load per customer translates to low overhead costs per MWh Low acquisition costs Credit collection and billing handled through utility Outsourced call center

Retail Cost Advantage in MISO Illinois (Cost per MWh) Hedge from Market Hedge from IPH Difference Comment Indy Hub $36.00 ask $35.50 mid $0.50 Saves bid/ask spread Credit Charge $0.25 $0.00 $0.25 No third party credit charges Competitive Cost Advantage $0.75 41 In 2013, the Retail portfolio served ~11 MM MWh of load in MISO Illinois, backed by IPH wholesale generation No additional collateral posting is required for hedges with IPH generation Sourcing energy from IPH provides $0.75 per MWh cost advantage for Retail Illustrative Example The link with IPH generation assets provides Homefield with a competitive cost and liquidity advantage in MISO territory

Pricing and Risk Management 42 $1-$4 per MWh Margin Renewables Delivered Energy and Capacity(1) Broker Fees Utility Costs ISO Charges Distribution Losses Retail risks are actively managed to secure margins Energy is secured at the time of sale to the customer through IPH wholesale trades Commercial group manages transmission rights and renewables portfolio Additional power procured or sold in Day Ahead or Real Time markets for “load shaping” Pricing includes a volumetric risk premium that, over the life of the contract, helps protect against price spikes in periods of high demand Risk Premium Effectively hedged by Generation Portfolio and ARRs Largely fixed or predictable Hedged with portfolio of renewable credits (1) Includes basis and any ARR Credits Full Requirement Price Components

Demand Side Management Product Offering 44 Operates for the benefit of utilities and power pools Requires load curtailment of 60 hours or more per year for up to 6 hours at a time Penalties for non-compliance Operates for the benefit of large C&I customers Identifies handful of hours per year that can determine up to 20% of energy bill No penalties except for cost of lost opportunities Level of curtailment automation determined by customer Traditional Demand Response Demand Side Management Customer Value Proposition Benefits to Homefield In addition we are developing a new product offering for our large C&I customers - Demand Side Management Branded product with particular appeal to large commercial verticals such as Retailers, Schools and Healthcare Responds to increasing customer interest in real-time energy monitoring and management Stickiness of integrated software product decreases customer churn Sales tool for customer acquisition Reduces exposure to price spikes during periods of peak demand Integrated Service Offering

45 PJM Opportunities Ontelaunee Kendall PJM Service Territory Target Markets Northern Illinois Though smaller geographically, ComEd Illinois territory is 70% of Illinois state load Pennsylvania Over 100 TWh competitively served C&I customers account for ~60% of load; markets are mature and customers are educated purchasers Ohio Active competitive retail market with large increases in residential and non-residential switching since 2010 Municipal aggregation – offered on an opt-out basis – accounts for ~90% of competitively served residential customers We plan to grow opportunistically in PJM, leveraging existing infrastructure to build a presence and gain market intelligence

Regulatory Approach 48 Identify strategic allies; build coalitions and partnerships Publicly advocate for policy that supports Dynegy Promote and educate about contribution to local and state communities and economies Increase visibility with key state and federal political leaders and policy makers Vision and visibility are the keys to our regulatory success

Gas Fleet Coal Fleet Regulatory Resources 49 ISONE, NYISO, PJM Key Experience: Supervisor of NYISO Customer Relations CAISO Key Experience: 15 years of policy engagement across all ISOs FEDERAL Key Experience: Various roles at NYISO, including Manager of Transmission Studies Trade Association Advocacy Electric Power Supply Association (EPSA) Utility Water Act Group (UWAG) Utility Solid Waste Activities Group (USWAG) Utility Air Regulatory Group (UARG) Western Power Trading Forum (WPTF) Independent Power Producers of NY (IPPNY) Electric Power Generators Association (EPGA) Retail Energy Supply Association (RESA) Several State and Local Associations, such as Illinois Energy Association (IEA), Illinois Competitive Energy Association (ICEA) and Illinois Manufacturers Association (IMA) Dynegy leverages internal and external resources to influence issues that most affect shareholder value Significant Accomplishments Issue Result Air Emissions Variance for IPH Plants Variance granted by Illinois Pollution Control Board California Contracts 2014-2016 Moss Landing 6&7 contracts(1) MATS non-compliant units seeking special dispensation in MISO capacity auction No dispensation for MATS non-compliant units MISO Key Experience: Director of Regulatory Affairs at MISO 25 years of lobbying experience ICC legal and policy advisor, ICC ALJ (1) 2016 subject to approval by the California Public Utilities Commission

Meeting New Build Challenge in MISO 51 Actively promoting value proposition of Dynegy’s fleet versus new build Incentives New Build Dynegy Response Compete Educate utilities and regulators on value of existing resources Engage in state proceedings; highlight Dynegy value proposition Focus on states neighboring Illinois Sell Seasoned origination team actively marketing our portfolio Participate in RFPs Active media campaign and legislative efforts New build increases vertically integrated utilities’ rate base States want to maintain control over generation New build associated with jobs creation Various projects are being considered Very few have been permitted Value Proposition Lower prices for end consumers Available today Does not require additional supporting infrastructure build out

EPA Effluent Limit Guidelines – Assumed Compliance Requirements 52 Wastewater Streams Addressed US EPA Preferred Technologies Impacted Plants FGD Wastewater Best Professional Judgment, Chemical Precipitation + Biological Treatment None Fly Ash Transport Water Dry Handling Havana, Wood River, Newton Bottom Ash Transport Water Impoundment, Dry Handling for units >400 MW Baldwin, Havana, Coffeen, Duck Creek, Newton Combustion Residual Leachate Impoundment Hennepin, Joppa FGMC Wastewater Dry Handling Wood River, Newton Gasification Wastewater Evaporation None Nonchemical Metal Cleaning Waste Chemical Precipitation All Dynegy’s compliance period begins in 2018 and runs through 2022, coincident with NPDES (water discharge) permit cycle Units smaller than 400 MWs exempt from dry bottom ash handling Compliance with effluent limits largely satisfies compliance with coal combustion residuals rule Coal ash designated as non-hazardous Compliance with ELG under a reasonable set of assumptions varies by plant, but in a number of cases is limited Additional Assumptions

Limited impact, especially units below 400 MW threshold Assumed Compliance Timeline Effluent Limit Guidelines and Coal Combustion Residuals 53 Coal Segment IPH ELG CCR Based on our assumptions, full compliance with ELG and CCR rules would not be required until early next decade Issuance of US EPA final rules Compliance coincident with NPDES permit expiration Baldwin Balance of Fleet Limited impact, especially units below 400 MW threshold Balance of Fleet All Plants Compliance date

Assumed Compliance Timeline Once-Through Cooling Rules(1) 54 Coal IPH Issuance of final US EPA 316(b) rule Compliance date – either coincident with NPDES permit expiration or California Rule No Impact Gas (1) Includes 316(b) Federal rule and California state rule; (2) Assumes Baldwin and Duck Creek cooling ponds are not classified as Waters of the U.S. and, therefore, the intakes on these ponds have no significant exposure to 316(b); (3) Baldwin and Kendall may have some limited exposure with their make-up water intakes Based on our assumptions, limited impact on our fleet Casco Bay Closed-cycle cooling Independence Closed-cycle cooling Duck Creek Cooling Pond(2) Oakland Air cooled Havana Closed-cycle cooling Ontelaunee Closed-cycle cooling Baldwin Cooling Pond(2)(3) Kendall Closed-cycle cooling(3) Minor Impact

Regulatory Summary 55 Regulatory focus is on issues that most affect shareholder value Promoting MISO capacity market reform Advocating for non-compliant generator retirements as MATS compliance deadlines draw near Actively promoting the value proposition of Dynegy’s fleet versus new build Actively addressing environmental regulations; compliance is manageable based on our assumptions about EPA requirements

Net Capacity (MW) Environmental Compliance 2013 Production MM MWh Produced MM Tons of PRB Coal Burned Equivalent Availability Factor (EAF) CSAPR MATS Baldwin 1,800 P P 12.5 7.3 85% Havana 441 P P 2.8 1.9 84% Hennepin 293 P P 1.6 1.0 68%(1) Wood River 446 P P 3.4 2.0 95% Coffeen 915 P P 4.6 2.9 73% Duck Creek 425 P P 2.5 1.4 80% Edwards 695 P P 4.3 2.6 88% Joppa 802 P P 6.9 4.3 94% Newton 1,225 P P 6.9 4.0 79% Total 7,042 45.5 27.4 Coal Operations Snapshot Near and longer-term EAF goals targeted through PRIDE Coal Segment IPH (1) Significant extended planned outage; 2012 EAF for Hennepin was 95% 57

58 Environmental Equipment SO2 NOx Mercury Particulate Matter Scrubber Low NOx burners Overfire Air SCR Injection/Oxidation Systems Electrostatic Precipitator Baghouse Baldwin 1-2 Dry P P P P P P Baldwin 3 Dry P P P P P Havana 6 Dry P P P P P P Hennepin 1-2 P P P P P Wood River 4-5 P P P P Coffeen 1 Wet P P P P Coffeen 2 Wet P P P P Duck Creek 1 Wet P P P P Edwards 1 P P Edwards 2 P P P P Edwards 3 P P P P P Joppa 1-6 P P P P Newton 1-2 P P P P Coal Segment IPH Dynegy’s coal plants are compliant with current state and federal regulations Meets CSAPR Meets MATS

IPH Plant Profile – Coffeen, Newton and Joppa Genco Subsidiary Coffeen Newton Joppa 2013 IPH Generation Improvement Opportunities Cyclones Unit 1 and Unit 2 Boiler tubes Boiler reheater Windbox repairs Coal yard Boiler tubes Boiler burner nozzles Boiler reheater/superheater Precipitators Coal yard Boiler Superheat area Turbines Coal yard Units Coffeen 1 1965 Newton 1 1977 Joppa 1-6 1953-1955 Coffeen 2 1972 Newton 2 1982 Capacity: 915 MW Capacity: 1,225 MW Capacity: 802 MW(1) 59 (1) Reflects 80% ownership

Coal Operations Operating Expense and Capital Spending Operations and maintenance spending held relatively flat over the next five years (1) Includes capital spending to meet Coal Combustion Residuals, Effluent Limit Guidelines and Once-Through Cooling requirements based on our assumptions 61 Coal Segment and IPH Operating Expense ($ MM) Coal Segment and IPH Capital Expenditures(1) ($ MM) IPH $349 Pre-IPH Acquisition $131 $150 $277 $88 $96 $89 $41 $115

62 FGMC Waste Fly Ash Transport Water Bottom Ash Transport Water FGD Waste Water Combustion Residual Leachate Nonchemical Metal Cleaning Waste Baldwin 1-3 Havana 6 Hennepin 1-2 Wood River 4-5 Coffeen 1-2 Duck Creek Edwards 1-3 Newton 1-2 Joppa 1-6 Coal Segment IPH We estimate that compliance with ELG and CCR rules will require an average of ~$25MM of annual spending over the five year compliance horizon(1)(2) (1) Assumes EPA classifies coal ash as “non-hazardous” and the EPA final rule is within its four stated preferred solutions; (2) Excludes ARO for coal ash pond closure No Capital Required Limited Capital Spending Required Capital Spending Required ELG and CCR Compliance Assumptions – Spend Profile

OTC Compliance Assumptions – Spend Profile 63 Coal Segment Baldwin Havana Hennepin Wood River We estimate that compliance with OTC rules will require an average of ~$8MM of annual spending over the five year compliance horizon(1) (1) Assumes EPA largely follows the proposed 316(b) rule issued in 2011, and the Baldwin and Duck Creek cooling ponds are not classified as Waters of the U.S.; assumes no cooling towers required Gas Segment Casco Bay Independence Kendall Moss Landing Oakland Ontelaunee No Capital Required Capital Spending Required IPH Coffeen Duck Creek Edwards Newton Joppa

Safety Promote, monitor and report safety practices across the fleet Environmental Support permitting and compliance activities across the fleet Monitor and plan for future regulations Outage Management Schedule, coordinate and manage planned outages Procurement Support all O&M and corporate support activities from sourcing through payment Engineering and Projects Develop and implement operations support and improvement projects 66 Operations Support PRIDE Identify and implement projects to increase EBITDA and improve balance sheet efficiency Center of Excellence Centralized organization to aggregate and promulgate best practices across the organization Operations Support leads PRIDE initiatives and serves as a Center of Excellence for critical support services

EBITDA Improvement (in $MM) Balance Sheet Efficiency (in $MM) 67 PRIDE Reloaded PRIDE Reloaded Starts with a year-2013 baseline for our expanded portfolio Baseline measured after achievement of $95MM in IPH synergies Approximately 40% of 2014-2016 EBITDA improvement is derived from the IPH portfolio PRIDE driving substantial shareholder value regardless of market environment IPH Highlights Producing Results through Innovation by Dynegy Employees $135 IPH

PRIDE Reloaded – Coal Plant Performance 69 Focus on Plant Performance Selected Initiatives Coffeen 2013 EAF 2014 Target EAF Boiler Windbox Leaks Leak of hot combustion air can damage surrounding equipment 4 forced outages in the past two years Replace metal duct in most problematic areas 73% 82% Duck Creek 2013 EAF 2014 Target EAF SCR Catalyst 60 MW uprate in 2009 increased quantity of fly ash and velocity of flue gas to SCR Plugging and erosion of catalyst has resulted in 5% lost availability due to derates and forced outages in the past two years Installation of ash sweepers will slow catalyst issues 80% 83% Havana 2013 EAF 2014 Target EAF Tube Assembly Replacement Tube assemblies in the Primary Superheater, the Secondary Superheater and the Reheater Outlet Pendents are being replaced 84% 85% Targeting 2014 coal fleet EAF >87%

PRIDE Reloaded – Refined Coal 70 Plant In Service Coffeen P Duck Creek P Joppa P Newton P Edwards Q2 Hennepin Q2 Baldwin Q3 Havana Q3 Wood River Q3 Implementing Refined Coal across the fleet expected to generate an additional ~$7MM in 2014 EBITDA Refined Coal Process Chemically treats coal to lower emissions Process executed by third party provider at no cost to Dynegy Benefits Generates tax credits which are monetized through financial partners Lowers use of environmental equipment consumables like activated carbon Reduces mercury emissions No Dynegy implementation cost Effectively lowers price of delivered coal by ~$1 per ton

PRIDE Reloaded - Recycled Coal Ash(1) 71 Working toward converting a liability into a revenue stream Current Situation Aspiration Description Nine coal plants generating coal ash waste requiring safe disposal 25% of fly ash currently sold All coal ash recycled and resold Generates a revenue stream that more than offsets cost of ash pond closure Economics Disposal costs Landfill construction costs Remediation costs New technology improves the quality of coal ash as feedstock for the cement industry beyond current use Potentially all coal ash becomes a commercially viable product including existing ash in ponds and landfills Environmental Subject to environmental regulation Reduces carbon emissions by replacing portland cement Cost associated with legacy ash disposal offset by revenue stream (1) Not included in PRIDE Reloaded 2014-2016 targets

PRIDE Reloaded Summary 72 Continuous improvement is a key part of Dynegy’s culture embodied by PRIDE Centralized Operations Support - a Center of Excellence for critical support services Key initiatives identified and quantified to deliver PRIDE Reloaded results PRIDE initiatives typically have outsize returns relative to their cost to achieve and paybacks of less than one year

Balance Sheet Optimization Achievements since last Investor Day Restructured collateral program to reduce capital employed First lien for power hedging and gas procurement Optimize netting positions Focus on highest value hedging activities Reduced collateral posted by $200MM since year-end 2012 Reduced working capital by $65MM Refinanced Dynegy Inc. debt complex, lowering cost of debt to 4.72% from 9.25% Released $335MM of restricted cash First Dynegy Inc. debt maturity in 2020 IPH acquisition within double ring-fencing that protects Dynegy Inc.’s balance sheet Over $1 billion of liquidity at Dynegy Inc. as of 3/31/2014(1), including revolver availability of ~$300MM (excludes ~$230MM of IPH cash on hand) Established $475MM revolver to protect liquidity and reduce reliance on cash Established restricted payments flexibility No limit in unsecured bonds ~$375MM capacity at year-end 2013 in secured term loan Drove Down Cost of Capital Reduced Capital Intensity Positioned Dynegy to Allocate Excess Capital Reduced capital requirements and cost while improving flexibility (1) Preliminary 1 2 3 75

2014 Balance Sheet/Liquidity Initiatives 76 PRIDE Reloaded Balance Sheet Initiatives Top Initiatives Emissions credit monetization FTR sleeve Working capital optimization Illinois Power Marketing Credit Facility Targeting new credit facility at Illinois Power Marketing to support IPH collateral requirements Working with banks to establish revolving credit facility Reduces reliance on cash balances, particularly for long-dated obligations Leverage Statistics (preliminary 3/31/2014) Liquidity Profile (preliminary 3/31/2014) ~$50MM ~$15MM In $MM Dynegy Inc. IPH Term Loan $794 - 5.875% Senior Notes $500 - 7.0% Senior Notes - $300 6.30% Senior Notes - $250 7.95% Senior Notes - $275 Total Debt $1,294 $825 Less: Cash ~$700 ~$230 Net Debt $594 $595 (1) Revolver provided by Dynegy Inc. In $MM Dynegy Inc. IPH Cash ~$700 ~$230 Revolver $475 $25(1) Less: LCs and borrowings ($165) ($13) Available $310 $12 Total Liquidity ~$1,010 ~$242 Continuing to find opportunities to streamline balance sheet and enhance liquidity

Driving Improvements in ROIC and Leveraging Upside 77 ROIC Completed and Targeted Initiatives Upside Levers Executing on initiatives within our control to improve returns and magnify upside for shareholders ROIC used to gauge our performance improvement Actions taken to date improved ROIC by ~350 bps 2015-2016 PRIDE initiatives improve ROIC by incremental ~170 bps Significant upside with power market recovery (1) Midpoint of 2014 Adjusted EBITDA guidance as presented on February 27, 2014; (2) CAPM calculation Current WACC(2) ~7.0%

79 Capital Allocation Increased clarity on capital allocation to be provided in 2H14 Capital Allocation Options $200MM+ Balance Sheet Management Intrinsic Investment M&A Return to Shareholders $1.3 billion in total Dynegy Inc. debt; weighted average cost of 4.72% Dynegy Inc. securities at or near par $825MM in IPH total debt; weighted average cost of 7.1% Transmission Plant performance improvement Innovative coal ash technology California redevelopment Dynamic M&A environment Dynegy continues to monitor the market for opportunities Open market share repurchases/block trades; dividends unlikely in foreseeable future ~$375MM of restricted payments capacity at year-end 2013 Modest trading volume limits size and pace of open market repurchases Benchmark against which other uses of capital compete Balance sheet capacity and access to capital sufficient to finance potential transaction, but must be more compelling than share repurchases Compelling investments in various stages of development; greater clarity on path forward, timing and capital requirement expected in months ahead Conservative Dynegy Inc. leverage and limited upside from debt reduction currently make this option less attractive

MWs with negative results PRIDE Reloaded and improving market conditions more than offset higher rail transportation costs Segment Level Unhedged EBITDA and FCF By Plant 80 Coal Segment 2013 2014 EBITDA EBITDA FCF FCF MWs with positive results MWs with negative results 2013 2014 EBITDA EBITDA FCF FCF MWs with positive results IPH Note: Free cash flow represents plant level unhedged gross margin less operating expenses and maintenance and environmental capital expenditures IPH plants positioned to be FCF positive one year early if targeted plant operations are achieved Synergies, including new Coffeen rail contract, and improving market conditions drive positive results in 2014

Earnings Potential of Existing Dynegy Fleet Impact of Significant “Known” Items 81 $325(1) Contract Expirations Captured in 2014 Guidance Moss Landing 6&7 contract expiration partially offset by new contracts Two months of Independence contract expiration (November and December 2014) Major Cost Driver Captured in 2014 Guidance New Coal segment rail agreement 2015 & 2016 Remaining impact of Independence contract expiration partially offset by expiring gas transport agreement and rest of state (ROS) capacity sales PRIDE Reloaded Factors Beyond 2016 Not Included Casco Bay 2017/2018 capacity auction results Increased capacity revenues from Kendall expansion IPH rail and coal costs as contracts expire or are renegotiated Retail growth Potential Adjusted EBITDA Drivers (in $MM) Earnings potential maintained even before market upside (1) Midpoint of Adjusted EBITDA guidance provided February 27, 2014; (2) Forecasted hedge settlements as of February 10, 2014

NOL Carryforwards Available to Shield Cash Taxes 82 Projected Threshold For Utilizing NOLs (in $MM) Shielding Cash Taxes NOL Position (12/31/2013) Federal tax NOL carryforward of ~$3 billion ~$1 billion of NOL carryforwards currently available without limitation ~$2 billion of NOL carryforwards subject to annual use limitations(1) ~$820MM of limited NOL carryforwards available over the next five years plus aggregate taxable losses, if any Dynegy not a cash taxpayer even in market recovery scenarios (1) Subject to IRC 382 limitations; limitation on NOL carryforwards could be further limited if the company experiences another ownership change as defined in IRC 382

Finance Summary 83 Dynegy remains focused on balance sheet efficiency in 2014 On an unhedged basis, all plants in the Dynegy and IPH fleet are expected to be FCF positive at the segment level and net contributors in 2014 toward IPH and DI overhead expenses Dynegy’s earnings power outlook remains robust despite contract expirations and the Coal segment’s new rail agreement Capital allocation remains a priority with more specifics to be provided in second half of 2014 as clarity around available opportunities improves

Our Executive Management Team 87 Hank Jones EVP and Chief Commercial Officer Prior Experience: Deutsche Bank – Managing Director, North American Power and Gas Sales and Origination EDF North American – COO and Head of Trading Carolyn Burke EVP and Chief Administrative Officer Prior Experience: J.P. Morgan – Global Controller, Commodities NRG Energy – VP & Corporate Controller, Financial Planning & Analysis Mario Alonso EVP, Strategic Development Prior Experience: Dynegy – VP & Treasurer; VP, Mergers & Acquisitions Clint Freeland EVP and Chief Financial Officer Prior Experience: NRG Energy – SVP, Strategy & Financial Structure, CFO, Treasurer Enron – Director, Finance Catherine Callaway EVP, General Counsel and Chief Compliance Officer Prior Experience: NRG Energy – General Counsel, NRG Gulf Coast Calpine – VP & Managing Counsel, Corporate Restructuring Reliant Energy – General Counsel Bob Flexon President and Chief Executive Officer Prior Experience: UGI Corporation – CFO Foster Wheeler AG - CEO NRG Energy – CFO, COO Hercules and ARCO – various financial roles

Pat Wood Chairman of the Board Principal – Wood3 Resources Currently serves on Board of Directors of Quanta Services Inc. and SunPower Corp. Prior Experience: Federal Energy Regulatory Commission - Chairman Public Utility Commission of Texas - Chairman Hilary E. Ackermann Prior Experience: Goldman Sachs Bank USA – Chief Risk Officer; Chaired Operational Risk, Credit Risk and Middle Market Loan Committees, Vice Chair of Bank Risk Committee; Chair GS Group level Operational Risk Committee Goldman Sachs & Co – Managing Director, Credit Risk Management & Advisory Swiss Bank Corporation – Assistant Department Head Paul M. Barbas Prior Experience: DPL Inc. and DP&L – President and Chief Executive Officer; Served on Board of Directors Chesapeake Utilities Corporation – Executive Vice President & Chief Operating Officer; Vice President; Chesapeake Service Company – President; Allegheny Power – Executive Vice President; President of Ventures unit Bob Flexon President and Chief Executive Officer Prior Experience: UGI Corporation – CFO Foster Wheeler AG - CEO NRG Energy – CFO, COO Hercules and ARCO – various financial roles Board of Directors 88 Richard Kuersteiner Currently serves on Board of Directors of Dex One Corporation Prior Experience: Franklin Templeton Investments – Associate General Counsel; Director of Restructuring; Managing Corporate Counsel Member of Stanford Institutional Investors Forum Jeffrey S. Stein Co-Founder and Managing Partner of Power Capital Partners LLC Currently serves on Board of Directors of Granite Ridge Holdings, LLC and US Power Generating Company Prior Experience: Durham Asset Management LLC – Co-Founder and Principal; Co-Director of Research The Delaware Bay Company – Director Shearson Lehman Brothers – Associate in Capital Preservation & Restructuring Group John R. Sult EVP and CFO Marathon Oil Prior Experience: El Paso Corporation – Executive Vice President Chief Financial Officer; Senior V.P. and CFO; Senior V.P. and Controller; Chief Accounting Officer El Paso Pipeline GP Company – Executive Vice President and Chief Financial Officer; Senior Vice President and CFO and Controller El Paso Pipeline Group - Senior Vice President, CFO and Controller Halliburton Energy Services – Vice President and Controller Arthur Andersen LLP – Audit Partner

Dynegy Generation Facilities Portfolio/Facility(1) Location Net Capacity(2) Primary Fuel Dispatch Type Market Region Coal Segement Baldwin Baldwin, IL 1,800 Coal Baseload MISO Havana(3) Havana, IL 441 Coal Baseload MISO Hennepin Hennepin, IL 293 Coal Baseload MISO Wood River Units 4-5 Alton, IL 446 Coal Baseload MISO Coal Segment TOTAL 2,980 Illinois Power Holdings Coffeen Montgomery County, IL 915 Coal Baseload MISO Joppa/EEI(4) Joppa, IL 802 Coal Baseload MISO Newton Jasper County, IL 1,225 Coal Baseload MISO Duck Creek Canton, IL 425 Coal Baseload MISO E.D. Edwards Bartonville, IL 695 Coal Baseload MISO IPH TOTAL 4,062 Gas Segment Casco Bay Veazie, ME 540 Gas - CCGT Intermediate ISO-NE Independence Scriba, NY 1,064 Gas - CCGT Intermediate NYISO Kendall Minooka, IL 1,200 Gas - CCGT Intermediate PJM Ontelaunee Ontelaunee Township, PA 580 Gas - CCGT Intermediate PJM Moss Landing Monterey County, CA Units 1-2 1,020 Gas - CCGT Intermediate CAISO Units 6-7 1,509 Gas Peaking CAISO Oakland Oakland, CA 165 Oil Peaking CAISO Black Mountain Las Vegas, NV 43 Gas Baseload WECC Gas Segment TOTAL 6,121 TOTAL GENERATION 13,163 NOTES: Dynegy owns 100% of each unit listed, except that it owns a 50% interest in the Black Mountain facility and an 80% ownership interest in the Joppa facility. Total Net Capacity set forth in this table for Joppa and Black Mountain includes only Dynegy’s proportionate share of those facilities’ gross generating capacity. Unit capabilities are based on winter capacity ratings. Represents Unit 6 generating capacity. Joppa has an additional 235 MW of natural gas-fired capacity currently in maintenance status. 89

2014 Adjusted EBITDA and Free Cash Flow Guidance(1) 90 Dynegy Inc. Adjusted EBITDA $300 - $350 Capital Spending ($160) Cash Interest ($145) (1) As presented on February 27, 2014 Note: Adjusted EBITDA and Free Cash Flow are non-GAAP measures; reconciliations to GAAP can be found on Slide 95 and 96 Assumptions Guidance based on February 10, 2014 commodity curves Year-to-date results incorporated into guidance Gen Weighted ATC LMP of $30.27 per MWh for Coal Segment (vs. $25.47 per MWH in 2013); $32.50 per MWh for IPH IPH Adjusted EBITDA (before G&A allocation) contribution of ~$75MM and ~($25MM) of free cash flow (before G&A allocation) Consolidated operating expense of $475MM Includes $50 million of operations support and insurance; 57% allocated to Dynegy Inc. and 43% allocated to IPH Consolidated G&A of $100MM 57% allocated to Dynegy Inc. and 43% allocated to IPH Consolidated capital spending of $160MM Excludes potential transmission investments Other Cash Impacts $15 Free Cash Flow $10 - $60

91 Gas Segment: Tolling, Capacity and Other Tolling Agreements Plant Contract Type Size (MW) Tenor Moss Landing 6&7 Tolling Agreement Jan-2014 to Dec 2016(1) Oakland RMR 165 Through Dec-2014 Independence Steam & Energy 44 Through Jan-2017 Kendall Tolling Agreement 50-85 Through Sep-2017 Capacity / Resource Adequacy Plant Contract Type Clearing Price(2) Size (MW) Tenor Casco Bay ISO-NE Capacity Auction $2.34/kw-Mo 488 Jun-2013 to May-2014 $3.21/kw-Mo 435 Jun-2014 to May-2015 $3.43/kw-Mo 445 Jun-2015 to May-2016 $3.15/kw-Mo 425 Jun-2016 to May 2017 Kendall PJM Capacity Auction $27.73/MW-day 1,044 Jun-2013 to May-2014 $125.99/MW-day 1,016 Jun-2014 to May-2015 $136.00/MW-day 1,033 Jun-2015 to May 2016 $59.37/MW-day 1,021 Jun-2016 to May 2017 Ontelaunee PJM Capacity Auction $226.15/MW-day 519 Jun-2013 to May-2014 $136.50/MW-day 492 Jun-2014 to May-2015 $167.46/MW-day 503 Jun -2015 to May 2016 $119.13/MW-day 503 Jun-2016 to May 2017 Moss Landing 1&2 RA Capacity 693 Avg Bilateral Sold Q3 2014 200 Avg Bilateral Sold Q3 2015 Moss Landing 6&7 RA Capacity(3) Independence ICAP - Con Ed 740 Through Oct-2014 (1) Jan –Dec 2016 pending California Public Utility Commission approval; (2) Publicly disclosed clearing prices have been added where applicable; (3) Unable to disclose per confidentiality terms in the agreement

Current Wastewater Technologies and Containment Methods 92 FGMC Waste Fly Ash Transport Water Bottom Ash Transport Water FGD Waste Water Combustion Residual Leachate Nonchemical Metal Cleaning Waste Baldwin 1-3 Dry handling Dry handling Impoundment None None Impoundment Havana 6 Dry handling Impoundment Impoundment None None Impoundment Hennepin 1-2 Dry handling Dry handling Impoundment None Future Impoundment Wood River 4-5 Impoundment Impoundment Impoundment None None Impoundment Coffeen 1-2 Dry handling Dry handling No discharge No discharge No discharge Impoundment Duck Creek Dry handling Dry handling Impoundment No discharge No discharge Impoundment Edwards 1-3 Dry handling Dry handling Impoundment None None Impoundment Newton 1-2 Dry handling Dry handling Impoundment None No discharge Impoundment Joppa 1-6 Impoundment Dry handling Impoundment None Future Impoundment Coal Segment IPH

Links to reference material 93 MISO 2013 Summer Assessment: https://www.misoenergy.org/Library/Repository/Meeting%20Material/Stakeholder/MSC/2013/20130430/20130430%20MSC%20Item%2003a%20Summer%20Assessment.pdf Potomac Economics/Independent Market Monitor, 2012 State of the Market Report: https://www.misoenergy.org/Library/Repository/Report/IMM/2012%20State%20of%20the%20Market%20Report.pdf MISO’s Planning Year 2014 LOLE Study Report: https://www.misoenergy.org/Library/Repository/Study/LOLE/2014%20LOLE%20Study%20Report.pdf MISO’s OMS Survey Results: https://www.misoenergy.org/Library/Repository/Meeting%20Material/Stakeholder/SAWG/2013/20131205/20131205%20SAWG%20Item%2003%20OMS%20MISO%20Survey%20Results.pdf MISO’s OMS Resource Adequacy Survey Update: https://www.misoenergy.org/Library/Repository/Meeting%20Material/Stakeholder/SAWG/2014/20140206/20140206%20SAWG%20Item%2004%20OMS-MISO%20Survey%20Update.pdf

95 Reg G Reconciliation – Dynegy 2014 Adjusted EBITDA and Free Cash Flow Guidance Low High Net Income (Loss) (111) $ (83) $ Plus / (Less): Interest expense 145 145 Operating Income (Loss) 34 $ 62 $ Depreciation expense 225 235 Amortization of intangible assets and liabilities 40 50 EBITDA (1) 299 347 Plus: Acquisition and integration costs 1 3 Adjusted EBITDA (1) 300 $ 350 $ (1) Low High Adjusted EBITDA 300 $ 350 $ Cash Interest Payments (145) (145) Other Changes 15 15 Cash Flow from Operations 170 220 Maintenance Capital Expenditures (125) (125) Environmental Capital Expenditures (35) (35) Free Cash Flow 10 $ 60 $ Dynegy Consolidated EBITDA and Adjusted EBITDA are non-GAAP measures. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating Income (Loss) as the most directly comparable GAAP measure. Regulation G Reconciliation DYNEGY INC. 2014 Guidance (IN MILLIONS) Free Cash Flow Guidance - Regulation G Reconciliation (IN MILLIONS) Dynegy Consolidated

96 Reg G Reconciliation – IPH 2014 Adjusted EBITDA and Free Cash Flow Guidance Regulation G Reconciliation Illinois Power Holdings (IPH) 2014 Guidance (IN MILLIONS) Operating Income $ 47 Depreciation expense 32 Amortization of intangible assets and liabilities (6) EBITDA (1) 73 Plus: Acquisition and integration costs 2 Adjusted EBITDA (1) $ 75 (1) EBITDA and Adjusted EBITDA are non-GAAP measures. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating Income as the most directly comparable GAAP measure. Free Cash Flow Guidance - Regulation G Reconciliation (IN MILLIONS) Adjusted EBITDA $ 75 Cash Interest Payments (60) Cash Flow from Operations 15 Maintenance Capital Expenditures (15) Environmental Capital Expenditures (25) Free Cash Flow $ (25)