1. Potential Cost Savings in MISO from Demand Response MWDRI Steering Committee September 24, 2007

2. Purpose of study: It’s Helpful to Quantify DR Benefits Identify the Potential Capacity and Energy Cost Savings and Avoided Generation due to demand and energy reductions at various participation levels Identify impacts on Emissions from demand and energy reductions Allocate benefits of demand reductions to states and regions and demonstrate merits of regional cooperation

3. Methodology Use the MTEP 2008 Assumptions and apply demand and energy reductions to the 20 year study period Run “Base Case” and Benchmark against –All modeled cases include “Legacy” Demand Response MW values reported in the 2007 Module E as interruptible and Direct Load Control are applied each year of the study period. Reduce the growth rate of demand only, then both demand and energy (10 cases) –Reductions are from.1 to.5% from base growth rates Run models on a regional level and present results on MISO as a whole and at the state level using a load based multiplier

4. Limitations of Study Does not include the Cost of demand response in the model –Results identify potential cost savings –The outer limit of “What would you be willing to pay?” Models given reductions in demand and energy growth rates. Does not identify the potential for demand response. No specific type (DLC, Demand Bid etc.) of demand response is modeled, only demand and energy reductions Production costs are based on an economic dispatch without transmission system constraints –However, benefits are benchmarked from the reference case, which identify the impact of demand and energy reductions Models and Results only represent MISO companies –Potential benefits for Demand Response to load served outside the MISO market are not captured

5. Presentation of Results The Study Results are data intensive. In consideration of various audiences interested at different levels of interest the results are presented in 2 sections –By MISO Footprint –By State Focus on case “DE5” with 0.5% demand reduction and 0.5% energy reduction from reference case growth rates

6. Results for the MISO Footprint

7. Results from Reducing Demand and Energy (All MISO) Scenario Demand Growth Rate Energy Growth Rate 2027 Coincident Peak 2027 Total Energy Demand Reduction Energy Reduction 20 Year Demand Reduction 20 Year Energy Reduction Average Demand Reduction %MWGWHMWGWH% REF*1.28%1.27%140,588745,187 D11.18%1.27%138,543745,1872,04501.45%0.00% 1,981 MW per.1% Demand Growth Rate Decrease D21.08%1.27%136,534745,1874,05502.88%0.00% D30.98%1.27%134,560745,1876,02904.29%0.00% D40.88%1.27%132,621745,1877,96805.67%0.00% D50.78%1.27%130,683745,1879,90607.05%0.00% DE11.18%1.17%137,975731,3352,61313,8531.86% 2,523 MW per.1% Demand & Energy Growth Rate Decrease DE21.08%1.07%135,408717,7265,18027,4613.68%3.69% DE30.98%0.97%132,886704,3577,70240,8305.48% DE40.88%0.87%130,409691,22510,17953,9627.24% DE50.78%0.77%127,976678,32512,61366,8628.97% *REF – Reference Case Demand & Energy are from 2007 Module E forecasts by each company Demand Reduction – Difference in Demand from Reference Case Energy Reduction (Cases DE1-DE5 Only) – Difference in Energy from Reference Case 20 Year Demand Reduction – Percent decrease in Demand = Demand Reduction / Reference Demand 20 Year Energy Reduction - Percent decrease in Demand = Energy Reduction / Reference Energy Demand Reduction Only Demand and Energy Reduction

8. Demand Reductions from Base Case (All MISO) Demand Reductions from Base Case 9,906 12,613

9. Generation Expansion (All MISO) Scenario20 Year Generation Additions (In MW) Generation Reduction from Reference Average Generation Reduction Queue*CoalCCCTWind**TotalMW REF6,32621,6006,0003,52012,60050,028 D16,32622,8003,6002,24012,60047,5482,480 2,448 per.1% Demand Growth Rate Decrease D26,32619,2003,6003,52012,60045,2284,800 D36,32620,40003,20012,60042,5087,520 D46,32619,2001,2001,28012,60040,5889,440 D56,32616,8001,20064012,60037,54812,480 DE16,32620,4004,8001,92012,60046,0284,000 3,397 per.1% Demand & Energy Growth Rate Decrease DE26,32618,0003,6002,56012,60043,0686,960 DE36,32616,8001,2003,20012,60040,1089,920 DE46,32614,4001,2002,56012,60037,06812,960 DE56,32613,2001,2001,92012,60035,22814,800 * Queue Generation includes only generation in the Midwest ISO Queue with a signed Interconnection Agr. ** Wind Additions were fixed at 12,600 MW to meet state mandates (Wind contributes 15% to Reserve Margin Requirements and Runs at a 40% Capacity Factor for new Wind units and 33% Capacity Factor for existing Wind Units)

10. MISO Queue with Signed IA Coal 3,050 CC 2,236 CT 550 Wind 490 Total 6,326

11. Reductions in Emissions from Reducing Demand,Energy ( All MISO ) Change in Emissions from Reference Case = Reference Case Emissions – Scenario Emissions Percent Emission Reduction = 100 x Change in Emissions / Reference Case Emissions Average Emission Reduction = Change in Emissions / (1, 2, 3, 4 or 5 Respective of the scenario modeled) Scenario Change in Emissions from Reference Case (In Tons) Percent Change in Emissions (in %) Average Emission Reduction for each 0.10% Reduction (In Tons) CO2NoxSO2HgCO2NoxSO2HgCO2NoxSO2Hg Negative (values in red) indicate an increase in emissions from Reference Case REF10,873,595,44030,168,12328,347,730125 D1-2,128,352264,281435,9350.23-0.020.881.540.18-2,128,352264,281435,9350.23 D2-5,826,256-344,156-334,746-0.25-0.05-1.14-1.18-0.20-2,913,128-172,078-167,373-0.13 D3-6,618,848-104,01450,757-0.08-0.06-0.340.18-0.06-2,206,283-34,67116,919-0.03 D4-4,260,400-367,718-371,222-0.34-0.04-1.22-1.31-0.27-1,065,100-91,930-92,806-0.08 D5-10,252,512-705,575-852,074-0.60-0.09-2.34-3.01-0.48-2,050,502-141,115-170,415-0.12 DE1109,569,552505,970683,9961.231.011.682.410.98109,569,552505,970683,9961.23 DE2228,896,080617,703684,0571.772.112.052.411.41114,448,040308,851342,0280.89 DE3330,775,040693,041742,1652.653.042.302.622.11110,258,347231,014247,3880.88 DE4437,102,176714,144762,0323.464.022.372.692.76109,275,544178,536190,5080.87 DE5543,499,328901,581951,1724.43 5.002.993.363.53 108,699,866180,316190,2340.89

12. Capital & Production Costs (All MISO) Scenario Accumulated Present Value Capital Cost Accumulated Present Value Production Cost Accumulated Present Value Total Cost Accumulated Present Value Capital Cost Savings Accumulated Present Value Production Cost Savings Accumulated Present Value Total Cost Savings Average Cost Savings for each 0.10% Reduction Maximum Demand Response Value ($Million) $/KW REF48,519241,342289,861 D148,362239,808288,1701581,5341,692 827 D244,270241,783286,0534,250-4413,8091,904939 D343,637240,541284,1784,8828015,6831,894943 D441,761241,590283,3516,759-2486,5111,628817 D539,084242,370281,4549,436-1,0288,4081,682849 DE147,614237,271284,8859054,0714,977 1,904 DE244,306235,715280,0204,2145,6279,8414,9201,900 DE341,196233,118274,3147,3248,22415,5485,1832,019 DE438,051231,190269,24110,46810,15220,6205,1552,026 DE536,311228,687264,998 12,20812,65524,863 4,9731,971 Note: Production Costs Include costs for all emissions except CO2. Production costs with a CO2 tax are on the next slide. Average Cost Savings = Total Cost Savings / (1, 2, 3, 4 or 5 Respective of the Scenario Modeled) Maximum Demand Response Value = 1000 x Total Cost Savings / Demand Reduction in the Scenario

13. Reference Installed Capacity Cost Data No AFUDC ($/kW) - 2007$s Coal (CFB)2426 Coal (Pulverized)1936 CT (25MW)662 CT (50MW)524 CTCC730 Fuel Cell5820 IGCC2058 Nuclear2633 Solar6040 Wind2059 Maximum Demand Reduction Value/kW: Case D5 $849 Case DE5 $1971 Source: Vermont Deliberative Polling Reference Document

14. Reference Cost of Demand Response v. Peaking Capacity Peakers cost roughly $75/kW-yr (50-110) –Capacity in excess markets can be cheaper Typical Demand Response Program Costs –Direct Load Control: $55/kW/yr –Demand Bid/Buyback: $25/kW-yr or less –Interruptible rates: $50/kW-yr –Source: Quantec, Demand Response Proxy Supply Curves 2006 Energy Efficiency also cheap

15. Case DE5 Summary Compared with REF case in 2027 –Peak is 12,600 MW lower, -9% –66,000 fewer GWh used, -9% –14,800 MW of new generation avoided –Additional 35,200 MW still needed –Significant emissions savings from energy reductions –PV savings from production cost reductions and capital cost reductions equal to $24.9 B

16. Conclusions Reducing the energy growth in addition to demand growth adds to effective demand reduction Capacity Value of Load Reduction >> Cost of DR/EE Demand-only reductions result in more emissions produced because older less efficient units are running more and more energy is needed, requiring more combustion. There are regional differences in the benefits of demand response. Regions with a higher reserve margin benefit less with demand only reductions because the demand reductions do not defer capacity build until later years. With Energy reductions, the benefits are more uniform.

17. Results by State

18. Methodology to Represent Demand Response By State State Representations are derived from regional results using the following methods: –Regional Averages – represented at state level –Load Based Multiplier This is a representation of the load in each state as compared to MISO as a whole. The load participation of a company by state was developed from company websites and from company representatives and is summarized in the following two tables –Data is in supplemental slides

19. Potential Cost Savings By State ( Calculated using Load Based Multiplier) Scenario 20 Year Accumulated Present Value of Cost Savings MNWIIANDSDMTILMOINOHMI $Million D1118.6134.931.411.54.61.3158.3133.2262.8367.8467.6 D2207.7236.355.020.18.02.2540.7455.0768.2751.3764.3 D3303.5345.280.429.311.73.2608.4512.0972.21,265.01,551.9 D4403.8459.3107.039.015.64.3840.8707.61,228.31,299.71,405.3 D5488.2555.3129.347.118.85.21,130.7951.51,633.41,676.21,771.8 DE1597.3679.3158.257.723.06.4579.4487.6713.0867.41,025.8 DE21,214.31,381.1321.6117.346.912.9845.5711.51,344.31,731.92,113.7 DE31,745.01,984.8462.2168.567.318.61,437.81,209.92,253.22,817.13,383.2 DE42,334.52,655.3618.4225.590.124.82,025.31,704.33,088.43,635.94,217.9 DE52,815.43,202.2745.7271.9108.729.92,539.22,136.73,809.84,315.94,888.2 Cost Savings does not include a Cost for Demand Response Program or a Tax on CO2 Emissions Savings are based on load served by MISO within each state – additional savings could be gained by other load serving entities

20. Total sums approximately to the $24.9 billion from slide 12

21. Maximum DR Value By State (Calculated From Regional Average) ScenarioMISOWest RegionCentral Region Central & East Region East Region MNWIIANDSDMTILMOINOHMI $/KW D11,0466096659111,4791,822 D29655381,1461,1251,0781,049 D31,0175288671,0121,3461,547 D48855329079501,0501,111 D58945129841,0001,0371,060 DE12,1131,8072,2542,2562,2602,263 DE21,9411,8531,6591,8022,1322,331 DE32,0771,7911,8982,0372,3582,552 DE42,0701,8132,0232,0972,2702,374 DE52,0071,7642,0472,0802,1572,203 Source: From Regional Expansion with values applied to the state level. IN & OH have a load weighted calculation since they are in multiple study regions. Note: Values do not include a Cost for the Demand Response Program or a Tax on CO2 Emissions

22. On Mutual Benefit of Reductions among All States States are within MISO and three sub- MISO regional markets Individual state actions affect regional markets, are diluted from state perspective States get full benefit of their demand resources if all states are producing demand resources Brattle Report for MADRI illustrates this – possible further work for MISO

23. Central Region Reserve Margins After Expansion Note: No Firm Transmission is included in the Central Region Reserve Margins After Expansion

24. East Region Reserve Margins After Expansion

25. West Region Reserve Margins After Expansion

26. Regional Background Information on Demand Response, Reserve Margins and Allocation to States

27. 2007 Demand Response Levels

28. *Source: 2007 NERC Reliability Assessment **Source: 2007 MISO Module E

29. 2007 Demand Response Levels

30. Central Region Generation Reductions Scenario Queue Generation Additions Expansion Generation Additions Total New Generation Additions Generation Expansion Reduction Average Generation Reduction Per each 0.10% Reduction Central RegionMW REF1,70012,36014,060 D11,70011,16012,8601,200 D21,70010,28011,9802,0801,040 D31,7009,32011,0203,0401,013 D41,7008,1209,8204,2401,060 D51,7007,2408,9405,1201,024 DE11,70011,16012,8601,200 DE21,7009,96011,6602,4001,200 DE31,7009,08010,7803,2801,093 DE41,7007,8809,5804,4801,120 DE51,7007,0008,7005,3601,072

31. East Region Generation Reductions Scenario Queue Generation Additions Expansion Generation Additions Total New Generation Additions Generation Expansion Reduction Average Generation Reduction Per each 0.10% Reduction East RegionMW REF010,560 D109,920 640 D209,040 1,520760 D307,920 2,640880 D407,840 2,720680 D507,200 3,360672 DE109,920 640 DE209,040 1,520760 DE307,600 2,960987 DE406,640 3,920980 DE506,320 4,240848

32. West Region Generation Reductions Scenario Queue Generation Additions Expansion Generation Additions Total New Generation Additions Generation Expansion Reduction Average Generation Reduction Per each 0.10% Reduction West RegionMW REF4,62620,78225,408 D14,62620,14224,768640 D24,62619,58224,2081,200600 D34,62618,94223,5681,840613 D44,62618,30222,9282,480620 D54,62616,78221,4084,000800 DE14,62618,62223,2482,160 DE24,62617,74222,3683,0401,520 DE34,62617,10221,7283,6801,227 DE44,62616,22220,8484,5601,140 DE54,62615,58220,2085,2001,040

33. Company Demand Distribution by State (In Percent) % Demand by StateRegion Multi State MNWIIANDSDMTILMOINMIOH Alliant EastWn 1.00 Alliant WestWy0.10 0.90 AmerenCILCOCn 1.00 AmerenCIPSCn 1.00 AmerenIPCn 1.00 AmerenUECn 1.00 Cincinnati Gas & Electric Co.Cn 1.00 City Water, Light & Power (Springfield, IL)Cn 1.00 Consumers Energy Co.En 1.00 Detroit Edison Co.En 1.00 FirstEnergy OhioEn 1.00 Great River EnergyWy0.980.02 Hoosier Energy Rural Electric Coop, Inc.Cn 1.00 Hutchinson Utilities CommissionWn1.00 Indianapolis Power & Light Co.Cn 1.00 Lansing Board of Water & LightEn 1.00 Madison Gas & Electric Co.Wn 1.00 Minnesota Power, Inc.Wn1.00 Montana Dakota Utilities Co.Wy 0.70 0.30 Northern Indiana Public Service Co.En 1.00 Northern States Power Co.Wy0.750.16 0.050.04 Otter Tail Power Co.Wy0.46 0.450.09 PSI Energy, Inc.Cn 1.00 Southern Illinois Power CoopCn 1.00 Southern Minnesota Municipal Power AgencyWn1.00 Vectren (SIGE)Cn 1.00 We EnergiesWn 1.00 Wisconsin Public Power, Inc. SystemWn 1.00 Wisconsin Public Service Corp.Wn 1.00 Wolverine Power Supply Coop, Inc.En 1.00 Source: Midwest ISO

34. TOTAL 2008 MISO PEAK DEMNAD = 115,154Region Multi StateMNWIIANDSDMTILMOINMIOH Alliant EastWn02,861000000000 Alliant WestWy40403,63400000000 AmerenCILCOCn0000002,0660000 AmerenCIPSCn0000003,9460000 AmerenIPCn0000004,1280000 AmerenUECn00000009,317000 Cincinnati Gas & Electric Co.Cn00000000005,889 City Water, Light & Power (Springfield, IL)Cn0000004770000 Consumers Energy Co.En0000000009,5520 Detroit Edison Co.En00000000012,3850 FirstEnergy OhioEn000000000013,982 Great River EnergyWy2,60953000000000 Hoosier Energy Rural Electric Coop, Inc.Cn000000001,42200 Hutchinson Utilities CommissionWn640000000000 Indianapolis Power & Light Co.Cn000000003,24200 Lansing Board of Water & LightEn0000000004640 Madison Gas & Electric Co.Wn0759000000000 Minnesota Power, Inc.Wn1,7870000000000 Montana Dakota Utilities Co.Wy000340014600000 Northern Indiana Public Service Co.En000000003,59100 Northern States Power Co.Wy7,6991,6420493431000000 Otter Tail Power Co.Wy5030049298000000 PSI Energy, Inc.Cn000000007,26700 Southern Illinois Power CoopCn0000004540000 Southern Minnesota Municipal Power AgencyWn6550000000000 Vectren (SIGE)Cn000000001,35900 We EnergiesWn06,596000000000 Wisconsin Public Power, Inc. SystemWn0983000000000 Wisconsin Public Service Corp.Wn02,711000000000 Wolverine Power Supply Coop, Inc.En0000000006500 TOTAL MISO DEMAND IN STATE 13,72115,6063,6341,32553014611,0729,31716,88223,05019,872 Load Based Multiplier* (State to MISO).1191.1355.0316.0115.0046.0013.0961.0809.1466.2002.1726 Calculation of Load Based Multiplier Load Based Multiplier = Total MISO Demand in State / Total 2008 MISO Peak Demand