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30th Annual Platts Global Power Markets Conference April 14, 2015 Bob Flexon, President and Chief Executive Officer Energizing you, powering our communities. 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 2014 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. 2 Dynegy - Scale and Diversification with a Purpose In MWs Legacy Dynegy IPH EquiPower Asset Mix 20% Retail CCGT Coal Peakers Total PJM ~4,500 ~3,600 ~2,900 ~11,000 ~40% ISO-NE ~2,500 ~1,100 ~400 ~4,000 ~20% MISO 0 ~7,000 0 ~7,000 ~25% NYISO ~1,100 0 0 ~1,100 ~5% CAISO ~1,000 0 ~1,500 ~2,500 ~10% TOTAL ~9,100 ~11,700 ~4,800 ~25,600 100% CCGT 35% 45% Duke Market % of Portfolio Coal Peakers Diversified fleet with critical scale in key US power markets 3 System Stretched Too Thin What is Causing the Stress Economic Pressure Natural Gas Intermittent Resources Renewables Environmental Regulations Distributed Generation State Demand Response Market Design Federal Loss of Baseload Generation Need for Natural Gas Infrastructure BuildOut Coal Nuclear Stress On System Reflected In Prices Financial Stress Physical Stress Every market suffers from these issues to varying degrees 5 Financial Stress From Natural Gas Prices Natural Gas Basis Differentials(1) (in $ per mmbtu) 2015 2016 $1.65 $1.12 Henry Hub Natural Gas Price(1) (in $ per mmbtu) $8.85 $8.69 $6.74 $2.32 2017 ($0.03) ($0.10) ($0.15) ($0.03) ($0.19) ($1.00)($0.82) ($1.06) ($1.14) $6.94 Dominion $4.37 $3.99 $3.92 Chicago CG Algonquin CG Natural Gas Price(1) (in $ per mmbtu) $4.32 2015 $3.37 $3.72 $2.75 TETCO M3 $2.83 $3.14 2016 2017 $5.46 $5.02 $3.11 $3.27 $3.95 $2.99 $3.18 $2.80 $2.37 $2.01 $1.69$2.08 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Dominion TETCO M3 Chicago CG Declining Natural Gas Prices Regional Natural Gas Pricing • • Prolific shale production has preceded natural gas demand growth Algonquin CG Expansion of shale gas production in basins with limited infrastructure has resulted in significant regional natural gas price differentials Economic pressure from low natural gas prices initiated the first wave of asset retirements; regional natural gas price differentials amplify the problem 6 (1) Prices as of March 26, 2015; basis differential versus Henry Hub; Henry Hub price per mmbtu: 2015 - $2.83; 2016 - $3.14; 2017 - $3.37; 2015 represents balance of year pricing Federal Environmental Policy Onslaught Adds To Financial Stress CSAPR Phase I Begins Air Water MATS Compliance Begins Solid Waste MATS Compliance 1 Year Extension MATS Compliance 1 Year Federal Exemption 316(b) Compliance Begins 2015 2016 2017 2018 2019 2020 Effluent Limits Guidelines Compliance Expected CSAPR Phase II Begins Attainment for 2010 SO2 and NOX Clean Power Plan Interim Period Begins Coal Combustion Residual Compliance Begins The weak economic backdrop and compliance dates drive the second round of retirements 7 Loss of Baseload Generation to Retirements Historical and Projected Asset Retirements by Market(1) (in GW) 18,000 16,000 ISO-NE Retirements ISO-NE • Approximately 15% of capacity retired from 2010 through 2017 PJM 14,000 MISO 12,000 PJM Retirements 10,000 • Approximately 15% of capacity retired from 2010 through 2017 8,000 MISO Retirements • Approximately 8% of capacity retired from 2010 through 2017 6,000 4,000 2,000 0 2010 2011 2012 Economic Retirements 2013 2014 2015E 2016E 2017E 2018E… Environmental Retirements Economic & Environmental Retirements Past and pending asset retirements removing 10-15% of the installed capacity across three major US power markets 8 (1) Source: MISO, PJM, ISO-NE $1,000 $900 $800 $700 $600 $500 $400 $300 $200 $100 $0 25,000 PJM West Pricing and Load Comparisons 1H2012 1H2013 1H2014 Average Demand ISO-NE Pricing and Load $800 $700 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 Demand (MWs) $500 $/MWh (Day-Ahead) $400 MISO Pricing and Load 1H2012 1H2013 1H2014 $600 $500 Average Demand $400 $300 $200 $100 Average Demand $300 $/MWh (Day-Ahead) $/MWh (Day-Ahead) Impact of Stress on the System Reflected in Prices $0 8,000 13,000 18,000 23,000 Demand (MWs) $200 1H2012 1H2013 1H2014 $100 $0 40,000 45,000 50,000 55,000 60,000 65,000 Demand (MWs) 70,000 75,000 80,000 Baseload plant retirements shrink supply, tighten the energy market, and amplify volatility 9 Significant Generation from Plants Slated to Retire Energy Generated from Assets Slated to Retire(1)(2) 4.4% 4.3% 4.5% 4.3% 3.7% 3.0% 3.2% PJM 3.4% 3.0% MISO 2012 2013 ISO-NE 2014 Removing low-cost generation from supply expected to drive energy prices higher 10 (1) Internal Source: Energy Velocity, Dynegy Fundamental; (2) Reflects MISO Classic, PJM, and ISO-NE announced retirements Changing Natural Gas Market Dynamics U.S. Natural Gas Consumption by Sector (Bcfd) 80 Exports 60 Residential 40 Industrial 20 Electric Power Commercial 0 2005 Historical Natural Gas Flows(1) 2010 2015 2020 Future Natural Gas Flows(1) Natural gas market dynamics have fundamentally changed, but the evolution of natural gas infrastructure has lagged 11 (1) Source: Morgan Stanley Constrained New England Natural Gas Supply New England Natural Gas Prices(1) ($ per mmbtu) Iroquois Gas Transmission Tennessee Gas Pipeline Algonquin Gas Transmission Maritimes & Northeast Pipeline Winter 15/16 Summer 16 $9.85 $3.13 $3.07 NYMEX Henry Hub $2.89 Algonquin CG Constrained Natural Gas Transmission • Natural gas transmission into New England is constrained • Constraint becomes particularly acute in the winter as the natural gas demand for heating rises • Limited supply infrastructure as a result of public and political opposition to infrastructure development Pipeline Expansion Needed For Price Relief • Transmission charges have increased by 500% since 2005 • Spent $7 billion on transmission since 2003; plans to spend an additional $4.5 billion by 2018 • Additional transmission lines are not the answer Efficient combined cycle assets are underutilized in high demand periods due to lack of natural gas infrastructure 12 (1) Winter 15/16 comprised of prices for November 2015-March 2016, Summer 2016 comprised of prices for April 2016-October 2016, prices as of March 26, 2015 Dependency on Intermittent Resources Brings Reliability Risks PJM Supply Mix(1)(2) (in GW) ISO-NE Supply Mix(1) (in GW) 34 Reserve Margin 34 222 Reserve Margin Demand Response Demand Response Renewable Renewable 199 Hydro Hydro Baseload & Intermediate 2010 2020 CAISO Supply Mix(1) (in GW) 63 76 Reserve Margin 2010 2020 Demand Response Renewable Hydro Baseload & Intermediate 2010 Baseload & Intermediate Reliance on Intermittent Resources to Serve Load • • • • Hydro, wind, and solar generation are subject to rainfall, wind, and solar resource availability Wind and solar are incapable of being actively dispatched Demand response capabilities remain somewhat untested Minimum demand response contribution to winter supply 2020 Intermittent resources increasingly represent a key component of supply across multiple markets 13 (1) Source: ICF; (2) PJM scale expanded to improve detail; 2010 reserve margin estimated due to change in PJM footprint Intermittent Resources and Price Impact MISO CAISO Annual Percentage of Negative MISO Real Time Hours(1) 4.4% 4.0% 2.1% 2012 Intermittent Resources Physically Stress the System • Fast-ramping peaking capacity becomes increasingly necessary as penetration of renewables creates intraday volatility 2013 2014 Intermittent Resources Financially Stress the System, Suppressing Off-Peak Pricing • Nuclear plants are unable to cycle and must pay the system to remain on line when wind power puts negative prices on the system, typically overnight Intermittent resources not only stress the physical system, but they also have a negative financial impact on reliable, low-cost baseload generation 14 (1) Hubs included are Arkansas, Cinergy/Indiana, Illinois, Louisiana, Michigan, and Minnesota Incentivizing Investment Incentivizing Investment: Why Does It Matter? Future reliability hinges on how private capital is invested today Investment decisions based on cumulative capacity and energy revenue Current tariffs and practices need to reflect the evolving system stresses When markets are allowed to function, uneconomic resources retired Weak price signals in times of shrinking supply reflect market design and public policy flaws Regulatory conditions need to be examined before the investment climate erodes further Well-functioning, sustainable competitive wholesale markets provide the price signals for new investment 16 Incentives Versus Interference Out of Market Revenues • Propping up uneconomic resources fails to value those that are economic Out of Market Revenues Inconsistent Market Design • Significantly different market designs lead to barriers (a.k.a. seams) across markets Mandated RPS and Energy Efficiency Inconsistent Market Design Market Distortion Preferential treatment for DR, variable, and distributed resources Inconsistent Federal and State Regulations Inconsistent Regulations • Inconsistent implementation of regulations such as the Clean Power Plan shifts investment and jobs from one state to another Increased Demand Response • Increased DR with compensation equal to traditional generation but with reduced performance expectations Mandated RPS and Energy Efficiency • State-mandated RPS and EE targets lead to expensive fees on consumers’ bills Markets with the least interference and best design such as PJM are those most likely to attract private capital and investment 17 Destructive Out of Market “Solutions” Out of Market Subsidies Being Pursued in Illinois Out of Market Subsidies Being Pursued in New York Low Carbon Portfolio Standard • Designed to provide subsidy to uneconomic generation • Subsidy akin to Wind Production Tax Credit distorts market outcomes Reliability Support Services Agreement • Allows asset under reliability contract to continue offering into energy and capacity markets, distorting market outcomes Above Market Contracts with Utility Affiliate Out of Market Subsidies Being Pursued in Ohio • Distorts market outcomes by preserving uneconomic generation • Makes suppliers agnostic to offering at real costs Out of market subsidies take decisions about winners and losers out of the hands of the market and places decisions in the hands of policy makers at the expense of consumers and businesses 18 Positioning Power Portfolios for the Future Need For Well-Designed Markets PJM ISO-NE MISO ERCOT CAISO High Scarcity Price Caps Capacity Market Forward Capacity Market Sloped Demand Curve Stable Market Rules Performance Incentives * Both PJM and ISO-NE are leading the way with market designs that send appropriate price signals to address system stresses 20 *Planned but not approved Constructive Performance Incentives PJM Capacity Performance Capacity Performance Payments • Payment to generators over performing during shortage events • Penalty to generators under performing during shortage events • Provides incentive for generators to invest in reliability ISO-NE Performance Incentives PJM and ISO-NE are leading the industry by implementing market design solutions that address system reliability 21 Constructive Forward Capacity Markets PJM Projected Reserve Margin(2) PJM Capacity Auction Results(1) 20% ($ per kw-month) $3.86 $3.99 15% $4.62 18.0% 18.8% 18.8% 18.2% $3.65 $2.71 $2.28 17.1% 10% 5% 12/13 13/14 14/15 15/16 16/17 17/18 0% ISO-NE Capacity Auction Results ($ per kw-month) PY 15/16 PY 16/17 PY 17/18 PY 18/19 PY 19/20 Sending Appropriate Price Signal, But Market Response Takes Time $11.08 $9.55 Price Signal Inconsistent With Desired Result ISO-NE Projected Reserve Margin(2) 25% Cleared at the Floor $3.21 $3.43 14/15 15/16 16.0% 11.0% 10% $2.95 $2.95 24.0% 20% 15% $7.03 24.0% 11.0% 5% $3.15 0% 12/13 13/14 16/17 17/18 18/19 Rest 18/19 of Pool SEMA/RI PY 15/16 PY 16/17 PY 17/18 PY 18/19 PY 19/20 PJM’s constructive market design facilitates market stabilization; ISO-NE recognized the need to evolve to a more constructive model (1) 22 Average of RTO and MAAC pricing; (2) Source: PJM and ISO-NE MISO Market Does Not Address Pending Supply Shortfall MISO Capacity Auction Results(1) ($ per kw-month) $3.99 $3.86 $3.21 $2.95 $0.51 $0.03 13/14 14/15 MISO ISO-NE PJM MISO Projected Reserve Margin(2) 18% 16% 14% 12% 10% 8% 6% 4% 2% 0% 16.6% Target Reserve Margin 11.5% 12.3% 10.6% 9.0% PY 15/16 PY 16/17 PY 17/18 PY 18/19 PY 19/20 Lack of Forward Capacity Auction Vertical Demand Curve • • Sends no price signal to indicate an impending shortfall • Capacity is worthless when market is oversupplied and invaluable when market is short • MISO executes its capacity auction six weeks before the start of the planning year Timing of price signal inconsistent with assets that take years to build Six week forward capacity market with opaque rules does not send new build price signal until it is too late (1) 23 PJM price shown is average of RTO and MAAC pricing; (2) Source: MISO Refining The Market Construct to Meet Future Requirements Needed Reforms Coordinated State and National Energy Policy Energy Market & Ancillary Services Price Formation Capacity Market & Resource Adequacy Rules Out of Market Entry & Uneconomic Supply • Reliability commitments need to be reflected in LMPs • Administratively-mitigated prices skew true market prices • Sloped demand curve and forward commitment reflect supply-demand balance • Buyer-side mitigation prevents undue price suppression • Flexible capacity needed to balance variability of intermittent resources • RMR resources should be held out of energy and capacity markets to avoid artificial price suppression Proper Role for Demand Response • Comparable obligation if receiving comparable compensation • If a capacity product, then should have similar “must offer” requirements and be an annual product Transmission and Seams • Greater transparency and coordination between ISOs will lead to price convergence and market efficiency Dynegy strongly supports competitive wholesale power markets, which provide significant consumer benefits but require improved market designs 25 Stresses continue to affect each market, and only select markets are changing their market designs to relieve the pressure. Well-designed markets must consistently send appropriate price signals to address system needs. Competitive markets should also reflect a level playing field resulting in optimum outcomes without interference from outside forces. Interference through subsidies shifts risks from shareholders to customers, distorting the market and driving higher prices to the consuming public. 26