Dynegy Inc. Robert C. Flexon President and Chief Executive Officer Power and Gas Deep Dive Conference Wolfe Trahan & Co. April 11, 2013

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 2012 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 and Adjusted EBITDA. 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 Dynegy’s current report on Form 8-K filed with the SEC on March 14, 2013, which is available on Dynegy’s website free of charge, www.dynegy.com. 2 Forward-Looking Statements

3 Agenda Company Overview Refinancing Overview Dynegy’s Proposed Acquisition of Ameren Energy Resources Summary and Q&A

4 Company Overview

5 Dynegy’s diverse asset portfolio Oakland 165 MW Moss Landing 1&2 1,020 MW Moss Landing 6&7 1,509 MW Morro Bay 650 MW 6,771 MW of generation with ~4,400 MW combined cycle capacity Fleet located across six states and five power markets Dispatch increases as natural gas prices decrease GasCo Assets CoalCo Assets 2,980 MW baseload dispatch portfolio Environmentally compliant with current EPA regulations All units burn ultra-low sulfur Powder River Basin coal Low cost structure as a result of favorable long-term rail agreements 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 9,751 MW Note: Excludes ~4,100 MW of generation capacity from recently announced acquisition of Ameren Energy Resources. Net capacity shown based on winter capacity. For detailed plant information, please see Appendix Slide 35; (1) Dynegy owns 50% interest in Black Mountain.

Dynegy: Key Investment Considerations Clean capital structure with low leverage As a result of restructuring, Dynegy’s balance sheet and liquidity profile are well positioned for a low commodity price environment Lowest net debt among IPPs Refinancing further improves liquidity by freeing up $318 million of cash currently trapped at GasCo, CoalCo and DI Low-cost, environmentally compliant fleet Dynegy’s fleet of gas and coal plants have favorable dispatch positions in their respective market supply stacks Efficient gas plants located near load pockets Low-cost coal plants compliant with all known EPA regulations Attractive market fundamentals Significant portion of supply stack within MISO, PJM and NYISO are at risk for retirement due to EPA driven environmental regulation Dynegy’s fleet of environmentally compliant coal and gas-fired plants is well positioned to benefit from strengthening markets Proactive risk management Senior Secured Facilities give lenders a first lien on substantially all of Dynegy’s assets and provide significant collateral protection Comprehensive hedging program reduces gross margin volatility and improves Dynegy’s ability to meet financial targets Well maintained fleet with proven record of operating excellence Disciplined management team focused on efficiency During 2011 and 2012, PRIDE initiative created $107 million of fixed cash savings and gross margin improvements and improved balance sheet efficiencies by $524 million Targeting $42 million of additional margin and cost improvements and $83 million of additional balance sheet improvements in 2013 Refinancing expected to reduce annual cash interest expense by over $50 million; incremental to $30 million annual savings from repayment of $325 million in November 2012 6 1 3 4 5 2

7 Clean capital structure with low leverage 1 IPP Net Debt ($/kW) IPP Net Debt / 2013E Adjusted EBITDA Note: (1) Pro forma based on 3/21/2013, adjusted for $25MM CoalCo loan prepayment on 3/28/2013 and interest payments made on 3/31/2013; (2) Restricted Cash is part of the Term Loan Facility; (3) Letters of Credit are cash collateralized; amount includes a required reserve of 3%. Source: Calpine and NRG net debt balances as of 12/31/2012 per company filings. Note: Calpine net debt includes net debt from unconsolidated projects. NRG net debt comprised of total debt less unrestricted cash and equivalents. 2013 Adjusted EBITDA per midpoint of management guidance. $74 $344 $296 Dynegy PF Calpine NRG ($ in millions) Current as of 3/21/2013 Pro Forma (1) Cash & Cash Equivalents $389 $550 Collateral Posting Account (2) 68 – Revolver Capacity 150 500 L/C Capacity (2)(3) 250 – L/C & Revolver Outstanding (3) (245) (245) Total Liquidity $612 $805 2.7x 5.1x 5.1x Dynegy PF Calpine NRG

GasCo fleet benefits in both low and high gas price environments Benefits from expanding spark spreads in a high gas environment in regions dominated by gas generation In a low gas environment, coal-to-gas switching in PJM and NYISO has led to increased runtimes in off-peak and shoulder hours Ontelaunee and Independence benefit from lower gas costs as Marcellus gas supplies increase in the regions Strong In-Market Availability (“IMA”) performance despite increased runtimes ~4,400 MW of efficient combined-cycle generation plus ~2,300 MW in peaking capacity Kendall and Ontelaunee in PJM near high density Chicago and Philadelphia load pockets Kendall’s 2012 capacity factor greater than any two previous years combined Ontelaunee’s capacity factors in 2011 and 2012 were highest in plant’s history Single CCGT plants in NYISO and ISO-NE regions (Independence and Casco Bay) Independence’s 2012 capacity factor highest in Dynegy history by over 30% Moss Landing one of the largest gas plants in California 1,020 MW CCGT with ~7,000 heat rate 1,509 MW peaker with fast ramping capability Other California peakers near load pockets 8 Low-cost, environmentally compliant fleet 2 GasCo plant capacity factors GasCo’s fleet consists of competitive assets with regional diversity 39% 36% 22% 56% 19% 28% 63% 49% 71% 50% Casco Bay Independence Kendall Ontelaunee Moss Landing 2011 2012

MISO-CENTRAL 2014 DISPATCH COSTS(1) ($/MWh) MISO-CENTRAL DISPATCH ORDER Entire fleet MATS compliant Consent Decree environmental capital expenditures complete Burns low cost, low sulfur PRB coal Advantageous long-term rail contract in place Region has limited coal-to-gas switching as MISO is a coal-dominated market ADVANTAGES COAL FLEET CAPACITY FACTORS(2) (1) Based on Dynegy analysis; $4.00 Henry Hub; (2) Source: Ventyx, 2012 data is YTD through September 2012. Capacity factors based on weighted average of CoalCo fleet. Low-cost, environmentally compliant fleet (cont’d) 2 CoalCo’s sustainable low-cost competitive advantage 9 Baldwin1-3, Hennepin 1-2, Wood River 4-5, Havana 6 Estimated range of 80 – 90%

 Attractive market fundamentals 10 Rising Natural Gas Prices Rising Capacity Prices Rising Power Prices As more plants retire, reserve margins drop and capacity payments should rise A $2/kW-mo capacity price in MISO translates into $65MM annually in capacity revenue for CoalCo PJM and NYISO already seeing higher forward capacity pricing due to retirements(2) Over 27 GW of aging or coal-fired generation capacity is expected to retire in the MISO, NYISO and PJM regions, net of additions, during 2013-2016(1) 3 Dynegy’s MATS-compliant coal fleet and combined-cycle fleet are well-positioned to benefit from the tightening supply dynamics (1) See Slide 39 in appendix for annual net retirement projections and assumptions (2) PJM RTO pricing in base residual auctions increased from $16.46/MW-day for 2012/2013 to $136.00/MW-day for 2015/2016. Average NYISO May-Oct summer strip actual price ~$0.29/kW-mo for 2011; $2.27/kW-mo for 2012; current forecast of $4.25/kW-mo for 2013 As lower cost coal generation resources come off the grid, gas is on the margin more often Based on 2012 load, expected retirements could increase MISO-Central prices by ~$4/MWh and PJM prices by ~$1.35/MWh Gas-fired generation increasingly replaces retiring assets, natural gas demand should grow Coal retirements and new gas-fired capacity expected to add 3 to 4 Bcf/day of gas demand by 2017

11 (1) Source: MISO, Ventyx and Dynegy Analysis Attractive market fundamentals (con’t) Expected MISO Net Retirements(1) 6,500 MW of gas fired capacity coming online during the period with 2,300 MW in early development An additional 1,700 MW of other capacity additions likely with 180 MW in early development 21,000 MW of Retirements already announced Average age ~40-55 years, and Average size ~65-225 MW An additional 2,800 MW likely to retire in 2015 due to MATS 1,500 MW of coal additions including a second 800 MW Prairie State unit 545 MW likely CC/CT Gas additions 12,500 MW of retirements, including 5,500 already announced Average age ~40-55 years, and Average size ~ 65-200 MW Majority of retirements take place in 2015-2016 as MATS rules take effect 170 MW of nuclear uprates 1,800 MW of retirements announced, including Danskammer Average age ~45-55 years, and Average size ~ 25-120 MW Excludes possible retirement of Indian Point Expected PJM Net Retirements(1) Expected NYISO Net Retirements(1) Likely Additions Likely Retirements Likely Additions Likely Retirements Likely Additions Likely Retirements 3 Expected Retirements by Region (MWs)

12 Attractive market fundamentals (con’t) 3 Based on expected retirements, PJM and MISO reserve margins projected to be between ~16%-18% by 2015 Additional retirements expected in 2016 would reduce reserve margins to ~13% -14% in PJM and MISO NYISO reserve margin anticipated to be decline steadily over several years Impact of expected retirements on forecasted reserve margins Retirements expected to tighten reserve margins and improve capacity pricing

Value Creation We hedge power and fuel to meet or exceed targeted EBITDA and Free Cash Flow requirements Our coal portfolio is largely open to realize upside in natural gas and power market recovery Upside Participation Downside Protection Extrinsic Value Capture Financial Targets Intrinsic Value Capture For our at-the-money assets, we pursue commercial strategies to capture temporary opportunities that exist as spark spreads change due to volatility in power and gas markets For our assets that operate deeper in-the-money, we transact to capture intrinsic value We employ “collar” strategies to provide downside price protection while retaining exposure to improved pricing Primarily Coal Portfolio Total Portfolio Total Portfolio Proactive risk management 4 Our flexible hedging strategy limits downside risk while allowing participation in market recovery 13

Commercial Activity (as of 3/31/2013) 14 Fuel Supply and Coal Transport Hedged Proactive risk management (cont’d) 4 Coal segment hedges added as market price and trading liquidity improve Gas segment hedges added as spark spreads improve 2014 Coal and Gas segment hedged as 22% and 20%, respectively Will continue to increase hedging activity as price targets are met Coal supplies are typically purchased in advance of forward power sales due to the long-term nature of coal contracts Gas supplies are generally hedged simultaneous with forward power sales through spark spread transactions Tolls/Swaps

15 Environmentally Compliant (with all known EPA regulations) Coal Fleet If gas prices stay low If gas prices rise Benefits from rising capacity payments and “heat rates” due to increased retirements Significant upside leverage in a rising natural gas environment Benefits from increased capacity factors and rising capacity payments due to increased retirements Benefits from spark spread expansion as energy prices rise If gas prices stay low If gas prices rise CoalCo GasCo Efficient Combined-Cycle Gas Fleet Proactive risk management (cont’d) 4 Dynegy’s portfolio embeds a natural hedge to changing gas prices

GasCo has consistently exhibited high annual availability factors, averaging ~90% over the last five years, improving EFOR rates due to PRIDE efforts and IMA of ~95% past 2 years during period of historic runtimes CoalCo has also demonstrated high availability, averaging ~87% over the last five years, improving EFOR rates due to PRIDE efforts and consistent IMA of 92% for the past 2 years 16 Proactive risk management (cont’d) 4 Consistent operating performance with proven track record (1) Portfolio equivalent availability reflects weighted average (by capacity) of annual equivalent availability. Excludes Black Mountain and assets from recently announced acquisition of Ameren Energy Resources; (2) EFOR stands for equivalent forced outage rate. IMA stands for in-market-availability. GasCo portfolio equivalent availability(1) CoalCo portfolio equivalent availability(1) GasCo EFOR and IMA(2) CoalCo EFOR and IMA(2) 4.1% 2.5% 0% 2% 4% 6% 8% 2011 2012 EFOR 7.1% 6.2% 0% 2% 4% 6% 8% 2011 2012 EFOR 86% 85% 87% 88% 86% 0% 20% 40% 60% 80% 100% 2008 2009 2010 2011 2012 Average: 86.6% 94% 95% 0% 20% 40% 60% 80% 100% 2011 2012 IMA 92% 92% 0% 20% 40% 60% 80% 100% 2011 2012 IMA 16

 Fixed Cash Savings $MM Gross Margin Improvements $MM Balance Sheet Efficiency $MM Producing Results through Innovation by Dynegy Employees Exceeded 2012 PRIDE fixed cash target by $6 million, achieving a $31 million improvement from 2011 actuals Exceeded 2012 PRIDE target of $100 million by ~50%, a $148 million improvement over 2011 actuals Met gross margin improvement target, a $13 million increase over 2011 actuals Disciplined management team focused on efficiency 5 17 $51 $31 $22 $104 PRIDE delivered over $100MM of fixed cash savings and gross margin improvement since 2011 with an additional $42MM targeted for 2013

18 Refinancing Overview

Capitalizing on opportunities to refinance in competitive capital market Dynegy Inc seeking to raise $1,800 million of new Senior Secured First Lien Credit Facilities consisting of: Up to $500 million, 5-year Senior Secured Revolving Credit Facility $800 million, 7-year Senior Secured Term Loan B Facility $500 million, 2-year Senior Secured Term Loan B Facility Intent to refinance 2-year term loan with $500 million of unsecured notes in the near term after pro forma financials are available for Dynegy’s acquisition of Ameren Energy Resources Dynegy is only allowed to refinance the 2-year term loan with unsecured debt Refinancing opportunistically accesses capital markets to improve Dynegy’s capital structure Removes bankruptcy-remote, ring-fenced structures at GasCo and CoalCo Increases corporate liquidity Releases restricted cash of $318 million(1) Reduces interest and administrative costs Use of Proceeds: Repay $1,330 million in outstanding indebtedness under the existing senior secured credit facilities at wholly owned subsidiaries Dynegy Power, LLC (“GasCo”) and Dynegy Midwest Generation, LLC (“CoalCo”) (the “Refinancing”) Pay related transaction fees and expenses Upon closing, Dynegy Inc. will continue to be least levered IPP in the sector 19 (1) Based on balances as of 3/21/2013

Dynegy Inc. (DI) Dynegy Midwest Generation, LLC (CoalCo) Dynegy Power, LLC (GasCo) Simplifying to create an established capital structure Proposed Capital Structure (1) Up to $500 million 5-year Revolving Facility $500 million 2-year Senior Secured TLB $800 million 7-year Senior Secured TLB ~$550 million cash & cash equivalents Dynegy Coal Investments Holdings, LLC 20 Dynegy Gas Investments Holdings, LLC Note: Above chart represents an abbreviated organizational structure; (1) Current capital structure based on balances as of 3/21/2013; Pro forma based on 3/21/2013, adjusted for $25MM CoalCo loan prepayment on 3/28/2013 and interest payments made on 3/31/2013; (2) Includes various subsidiaries of Dynegy Inc.; (3) Restricted Cash is part of the Term Loan Facility; (4) Letters of credit are cash collateralized. Amount includes a required reserve of 3%. Ring-fenced group Ring-fenced group Bankruptcy-remote entities Dynegy Gas Investments Holdings, LLC Current Capital Structure (as of 3/21/2013) (1) Dynegy Coal Investments Holdings, LLC ($MM) Dynegy Gas HoldCo, LLC Cash & cash equivalents $1 Dynegy Coal HoldCo, LLC Cash & cash equivalents $0 Dynegy Midwest Generation, LLC (CoalCo) 1st Lien Term Loan $493 Cash & cash equivalents 18 Collateral posting account (3) 4 L/C capacity (4) 12 L/C outstanding (4) (11) Total Liquidity $23 Dynegy Power, LLC (GasCo) 1st Lien Term Loan $837 Cash & cash equivalents $95 Collateral posting account (3) 64 Revolver capacity 150 L/C capacity (4) 210 L/C and revolver outstanding (4) (207) Total Liquidity $312

21 Dynegy’s Proposed Acquisition of Ameren Energy Resources

AER’s coal generation and retail marketing business is a natural fit with CoalCo Portfolio Overview ~4,100 MW of baseload coal generation in MISO and PJM ~900 MW in PJM by 2016 Ameren Energy Marketing and Homefield Energy – established retail and commercial energy providers 22 MISO Kendall Hennepin Wood River Baldwin Havana Edwards Coffeen Newton Duck Creek Joppa DYN Transaction Summary Dynegy’s newly created, non-recourse subsidiary(1), Illinois Power Holdings, acquires AER equity for no cash consideration At closing, AER and its subsidiaries will have $226 million in cash, $160 million in working capital and 2 years of collateral support from Ameren Synergy run-rate in 2014 targeted to exceed ~$60 million Accretive to Adj. EBITDA in 2014 and Free Cash Flow by 2015(2) Regulatory approvals include FERC, FCC and Illinois Pollution Control Board Estimated close during 4th quarter 2013 (1) Excluding a $25 million Dynegy guarantee to Ameren Corp; (2) Definitions of Adjusted EBITDA and Free Cash Flow are set forth in Item 2.02 to Dynegy’s current report on Form 8-K filed with the SEC on March 14, 2013.

(1) Genco owns an 80% interest in EEI, which owns Joppa Steam and MEPI Joppa 6B. The transaction has been structured to mitigate risk and ensure liquidity 23 Merchant Generation (AEE) (AER) Illinois Power Holdings, LLC (IPH) Ameren Energy Generating Co. (Genco) Ameren Energy Resources Generating Co. (AERG) Ameren Energy Marketing Co. (AEM) Electric Energy, Inc. (EEI) 80% (1) Dynegy Midwest Generation LLC (CoalCo) Dynegy Power, LLC (GasCo) 1 2 Ameren, prior to closing, purchases Elgin, Grand Tower and Gibson City gas assets from Genco for a minimum price of $133 million to satisfy Genco put option 1 2 IPH acquires 100% equity of AER for no cash consideration Transaction Steps (ring-fenced)

$25 million guarantee at signing, that extends for 2 years from closing for certain payment obligations of IPH prior to closing and certain indemnifications and reimbursement obligations of IPH post-closing The terms of the acquisition require minimal capital commitment from Dynegy Prior to closing, Ameren to satisfy Genco Put Agreement for a minimum of $133 million Cash contribution of $60 million to AERG and Genco for general corporate purposes AER subsidiaries also retaining $25 million in existing cash balances and ~$8 million in proceeds from sale of property AER net working capital at closing of $160 million, excluding cash, and two years of collateral support to AER Retention of non-operating locations and offsite environmental responsibilities subject to limited indemnification from IPH 24 AER and subsidiaries to retain the on-site environmental and business obligations, excluding the Duck Creek rail embankment Genco’s debt of $825 million remains outstanding Indemnify Ameren for future potential offsite liabilities associated with beneficial re-use and disposal of coal ash as follows: Up to $10 million – 50/50 AEE/IPH >$10-$30 million – 100% IPH >$30 million – 100% AEE Illinois Power Holdings, LLC

PJM Export ~900 MW of fleet capacity available for the 2016/17 PJM capacity auction, pending MISO approval Retail Business Established marketing business with expertise in MISO and PJM Opportunities for growth potential, which aligns with Dynegy’s retail initiative Provides basis management opportunities for the entire coal fleet MISO Market Recovery Upside Entire fleet expected to be MATS compliant As noncompliant or uneconomic generation retires, tightening supply dynamics should improve power and capacity pricing Acquisition of AER offers significant benefits to Dynegy stakeholders $60MM+ Synergies Year 1 Lower fuel cost and other procurement opportunities due to increased scale G&A and operating cost reductions by leveraging Dynegy’s existing infrastructure PRIDE Dynegy will expand successful PRIDE program to AER’s business Lower Allocation Sharing infrastructure costs across a broader asset base will benefit Dynegy’s business Ample Liquidity Sufficient liquidity and collateral support provided at closing to meet expected operating needs Earnings Accretive Targeted synergies, along with the current forward market for natural gas prices and Dynegy’s view of forward power and capacity prices, are expected to result in AER being accretive to Adjusted EBITDA in 2014 and Free Cash Flow in 2015 (1) Transaction Benefits (1) Definitions of Adjusted EBITDA and Free Cash Flow are set forth in Item 2.02 to Dynegy’s current report on Form 8-K filed with the SEC on March 14, 2013. 25

Summary and Q&A

AER Acquisition Dynegy Investment Thesis In summary, the portfolio acquisition enhances Dynegy’s fundamental investment thesis 27 Capital Allocation Opportunities Multiple Avenues for Substantial Upside Limited Downside Risk Increasing shareholder value while protecting and preserving Dynegy’s balance sheet Minimal financial exposure with downside risk ring-fenced Natural synergies and market recovery benefits Preserves future capital allocation opportunities

Appendix 28

29 Dynegy Generation Facilities Portfolio/Facility(1) Location Net Capacity(2) Primary Fuel Dispatch Type Market Region Coal Baldwin Baldwin, IL 1,800 Coal Baseload MISO Havana Havana, IL 441 Coal Baseload MISO Hennepin Hennepin, IL 293 Coal Baseload MISO Wood River Units 4-5 Alton, IL 446 Coal Baseload MISO CoalCo TOTAL 2,980 Gas 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 Morro Bay Morro Bay, CA 650 Gas Peaking CAISO Oakland Oakland, CA 165 Oil Peaking CAISO Black Mountain Las Vegas, NV 43 Gas Baseload WECC GasCo TOTAL 6,771 TOTAL GENERATION 9,751 NOTES: Dynegy owns 100% of each unit listed, except that it owns a 50% interest in the Black Mountain facility. Total Net Capacity set forth in this table for Black Mountain includes only Dynegy’s proportionate share of such unit’s gross generating capacity. The list also does not include several facilities that are retired or in agreement to be sold. Those facilities include Havana 1-5 and Wood River 1-3 which are retired and out of operation; Morro Bay 1-2 which are in mothball status and out of operation; and Danskammer and Roseton, which were deconsolidated effective October 1, 2012 and are under agreement to be sold. Unit capabilities are based on winter capacity.

Summary of Indicative Terms 30 Borrower: Dynegy Inc. (the “Company” or the “Borrower”, and together with all subsidiaries, the “Credit Group”) Use of proceeds: To refinance the GasCo and CoalCo facilities and to pay fees and expenses associated with the transaction Facilities: $500 million revolving credit facility (the “Revolver”) Up to $1,300 million term loans, comprised of: (i) $500 million first lien term loan (the “Tranche B-1 Term Loan") and (ii) $800 million first lien term loan (the “Tranche B-2 Term Loan”) (collectively, the “Term Loans”) Tenors: Revolver: 5 years Tranche B-1 Term Loan: 2 years Tranche B-2 Term Loan: 7 years Assumed corporate rating: B2 / B Interest rate: [TBD] LIBOR floor: [TBD] OID: [TBD] Revolver commitment fee: 50 bps per annum, to be paid on the undrawn portion of the Revolver and subject to leverage-based step-downs Term loan amortization: 1% per annum Guarantors: Each of the Borrower's present and future, direct and indirect domestic restricted subsidiaries (the "Guarantors") Security: First priority perfected lien on all property and assets (tangible and intangible, and including all outstanding capital stock of the Company and each of its restricted subsidiaries) of the Credit Group and subject to customary exceptions. Unrestricted subsidiaries’ equity will not be required to be pledged and unrestricted subsidiaries will not be required to grant security interest in their assets Optional redemption Tranche B-1 Term Loan: Prepayable at par Tranche B-2 Term Loan: 101 soft call, par thereafter Mandatory prepayments: Customary for facilities of this type and including prepayments from the net proceeds of asset sales and the issuance of debt securities Affirmative covenants: Customary for facilities of this type Negative covenants: Customary for facilities of this type and including limitations on indebtedness, liens, guarantees, mergers and acquisitions, asset sales, restricted payments, transactions with affiliates and investments Financial covenants: Revolver: Maximum Senior Secured Leverage Ratio (with springing covenant set at 25%) Term Loans: None; covenant-lite

Preliminary Sources/Uses and Pro forma Capitalization 31 Note: Funded debt excludes LCs posted under revolver; (1) Unrestricted cash, restricted cash and existing debt balances as of 3/21/2013, proforma for $25MM CoalCo loan prepayment on 3/28/2013 and interest payments made 3/31/2013; (2) Assumes call price of 104.619 as of 4/15/2013; (3) EBITDA based on midpoint of management guidance. ($ in millions) Sources Uses Dynegy Inc. Tranche B-1 Term Loan $500 Repayment of Existing Loans at CoalCo and GasCo (1) $1,330 Dynegy Inc. Tranche B-2 Term Loan 800 Total Refinancing Premium (2) 61 Unrestricted Cash (1) 357 Total Fees, Expenses and OID 36 Released Restricted Cash (1) 320 Cash to Balance Sheet (Unrestricted) 550 Total Sources $1,977 Total Uses $1,977

Compliance Profiles: Environmental Control Technologies 32 DI Plant Acid Gases (SO2) Mercury (Hg) NOx Particulates Baldwin 1 Dry FGD CaBr Overfire Air, SCR ESP, FF Baldwin 2 Dry FGD CaBr Overfire Air, SCR ESP, FF Baldwin 3 Dry FGD ACI & CaBr Low NOx burners, Overfire Air ESP, FF Havana 6 Dry FGD ACI Low NOx burners, Overfire Air, SCR ESP, FF Hennepin 1-2 Ultra low sulfur coal ACI & CaBr Low NOx burners, Overfire Air ESP, FF Wood River 4 Ultra low sulfur coal ACI & CaBr Low NOx burners, Overfire Air ESP Wood River 5 Ultra low sulfur coal ACI & CaBr Low NOx burners, Overfire Air ESP AER Plant Acid Gases (SO2) Mercury (Hg) NOx Particulates (Nox) Coffeen 1 Wet FGD Overfire Air, SCR ESP Coffeen 2 Wet FGD Overfire Air, SCR ESP Joppa Steam 1-6 ACI Low NOx burners, Separated Overfire Air except Unit 2 ESP Newton 1-2 (1) Scrubbers under construction ACI & CaBr Low NOx burners, Overfire Air ESP Duck Creek 1 Wet FGD Low NOx burners, SCR ESP E. D. Edwards 1 ACI Low NOx burners, Overfire Air ESP -upgrades planned 2014 E. D. Edwards 2 ACI Low NOx burners, Overfire Air ESP E.D. Edwards 3 ACI Low NOx burners, Overfire Air, SCR ESP (1) In order to comply with the Multi-Pollutant Standard, Ameren Energy Resources has retired two of its facilities, Meredosia and Hutsonville, and has spent $237 million on scrubbers at Newton to date, which must be completed by December 31, 2019. FGD – Flue Gas Desulphurization (“scrubber”) CaBr – Calcium Bromide ACI – Activated Charcoal Injection ESP – Electrostatic Precipitator FF – Fabric Filter SCR – Selective Catalytic Reduction Abbreviations

Tolling Agreements Plant Contract Type Size (MW) Tenor Moss Landing 6&7 Tolling Agreement 1,509 Through 2013 Oakland RMR 165 Through Dec-2013 Independence Steam & Energy 44 Through Jan-2017 Kendall Tolling Agreement 50-85 Through Sep-2017 Capacity / Resource Adequacy Plant Contract Type Clearing Price (1) Size (MW) Tenor Casco Bay ISO-NE Capacity Auction $2.95/kw-mo 410 Jun-2012 to May-2013 $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 Kendall PJM Capacity Auction $16.46/MW-day 1,019 Jun-2012 to May-2013 $27.73/MW-day 1,008 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 Ontelaunee PJM Capacity Auction $133.37/MW-day 503 Jun-2012 to May-2013 $226.15/MW-day 504 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 Moss Landing 1&2 RA Capacity 321 Avg Bilateral Sold 2013 25 Avg Bilateral Sold 2014 Independence ICAP - Con Ed 740 Through Oct-2014 Gas Segment: Tolling, Capacity and Other (1) Publicly disclosed clearing prices have been added where applicable. 33

34 Reg G Reconciliation – 2013 Guidance Low High Low High Low High Low High Gross Margin 92 $ 131 $ 252 $ 277 $ - $ - $ 369 $ 408 $ Plus: Amortization of Intangibles 120 130 120 132 - - 240 262 Adjusted Gross Margin 212 261 372 409 - - 609 670 Operating Expenses (152) (176) (118) (129) - - (270) (305) Adjusted EBITDA excluding General and Administrative Expenses 60 85 255 280 - - 340 365 General and Administrative Expenses - - - - (90) (90) (90) (90) Adjusted EBITDA 60 $ 85 $ 255 $ 280 $ (90) $ (90) $ 250 $ 275 $ Low High Low High Low High Low High Adjusted Gross Margin 212 $ 261 $ 372 $ 409 $ - $ - $ 609 $ 670 $ Amortization of Intangibles (120) (130) (120) (132) - - (240) (262) Operating Expenses (152) (176) (118) (129) - - (270) (305) Depreciation Expense (33) (47) (137) (151) (2) (2) (172) (200) General and Administrative Expenses - - - - (90) (90) (90) (90) Operating Income (Loss) (93) $ (92) $ (2) $ (3) $ (92) $ (92) $ (162) $ (187) $ Low High Low High Low High Low High Net Income (Loss) (306) $ (332) $ Add Back: Interest Expense 145 145 Operating Income (Loss) (93) $ (92) $ (2) $ (3) $ (92) $ (92) $ (162) $ (187) $ Depreciation Expense 33 47 137 151 2 2 172 200 EBITDA (1) (60) (45) 135 148 (90) (90) 10 13 Plus: Amortization of Intangibles 120 130 120 132 - - 240 262 Adjusted EBITDA (1) 60 $ 85 $ 255 $ 280 $ (90) $ (90) $ 250 $ 275 $ (1) Low High Adjusted EBITDA 250 $ 275 $ Cash Interest Payments (120) (120) Cash Tax Payments - - Collateral 20 20 Other Changes 20 20 Cash Flow from Operations 170 195 Maintenance Capital Expenditures (100) (100) Environmental Capital Expenditures (10) (10) Costs to refinance debt (45) (45) Return of restricted cash posted as collateral, net (2) 125 125 Free Cash Flow 140 $ 165 $ (2) Dynegy Consolidated EBITDA and Adjusted EBITDA are non-GAAP Measures. Management does not allocate interest expenses and income taxes on a segment level and therefore uses Operating Income (Loss) as the most directly comparable GAAP measure. Dynegy Consolidated Corporate GasCo Amount represents the return of restricted cash posted as collateral net of $150 million used to repay existing debt. Regulation G Reconciliation DYNEGY INC. 2013 Guidance (IN MILLIONS) Dynegy Consolidated CoalCo GasCo Corporate and Other Dynegy Consolidated CoalCo GasCo Corporate Free Cash Flow Guidance - Regulation G Reconciliation (IN MILLIONS) CoalCo