Michigan IRP

1. Michigan IRP September 8, 2005

2. Agenda • The objective of this meeting is to present a draft action plan for future Michigan Generation Expansion plan to the Integration team • Process Overview • Assumptions Review • Fuel and Emission Forecast • External Market Forecast • Base Case Expansion Plan • Scenarios and Sensitivities Expansion Plan • Draft Action Plan

3. Process Overview • The Capacity Need Forum (CNF) was created as a collaborative industry-wide process to assess the projected need for electrical generating capacity in Michigan over the short-, intermediate-, and long-term future. Demand Central Station Demand & Energy Forecast Economic Parameters Demand & Energy Sensitivities Demand Side Alternatives Integration Team Existing Generation Inventory and Assumptions New Generation Alternatives and Assumptions Alternative Generation T&D Existing Renewable & Cogen Inventory and Assumptions New Renewable & Cogen Assumptions Existing and Future Transmission Capability Transmission Sensitivities

4. Assumptions Review • Demand • The Demand and Energy forecast from the LOLP study (including High and Low load sensitivities). • Date Received 5/17/2005 • The Demand and Energy forecasts were applied to 2003 actual load shapes aggregated to the areas (UP, LP, & SE Mich.) • Energy Efficiency modeled as a uniform reduction in demand throughout the year. • Load Management data was not available and not modeled.

5. Assumptions Review • Demand Notes: Construction Escalation 2.47% Construction Escalation uses GDP Fuel Escalation Coal N. Appalachian 2.64% C. Appalachian 2.48% Fuel Escalations represent delivered costs Rocky Mountain 3.42% 2.29% Powder River Basin Gas 2.50% Uranium 2.80% Variable O&M Escalation 2.47% O&M escalation uses GDP Fixed O&M Escalation 2.47% GDP 2.47% http://www.eia.doe.gov/oiaf/aeo/pdf/aeotab_19.pdf Debt Interest Rate 9.28% Calculated to Yield an After Tax Cost Of Capital of 8.04%

6. Assumptions Review • Central Station • Existing Generation reviewed by Detroit Edison, Consumers, Wolverine, and Lansing. • Unit Retirements for all existing and future resources • Coal – 65 Years • Combined Cycle – 40 Years • Combustion Turbine – 30 Years • Fixed O&M for Combined Cycles will include a year round gas reservation charge ($20.52/kW, 2005) • Fixed O&M for Combustion Turbines will include three months of gas reservations charges for the Summer Months. ($5.13/kW, 2005) • No Capital Improvements for existing generation. • No assumptions for Emissions Controls. All emissions to be modeled through a “cap and trade” market. • Future expansion unit’s capital costs will include an interconnection fee based on 5% of the capital investment for a generic coal unit ($74.49/kW, 2005)

7. Assumptions Review • Central Station • Erickson 1-6 and Marysville 6,7, & 8 can not meet Mercury reductions of 85%. • All new coal units will burn Powder River Basin Coal, except IGCC • Financing 50% Debt/50% Equity … After Tax Weighted Cost of Capital 8.04% • No existing CT are to retire in the study horizon.

8. Assumptions Review • Central Station – Future Generation Assumptions (2005$)

9. Assumptions Review • Central Station – Future Generation Assumptions

10. Assumptions Review • Central Station – Future Generation Assumptions With CO2 Sequestering

11. Assumptions Review • Alternative Generation • Alternatives for consideration: Landfill Gas, Anaerobic Digestion, On-Shore Wind, and Cogeneration • 79 MW of existing LFG growing by 5% per year. • Digestion potential capacity is 52 MW, in blocks of 26 MW • No construction lead time for Digestion or LFG • LFG has zero net emissions • Wind 420 MW Potential • Wind units have a 2 year lead time, minimum size is 35 MW • Cogeneration 547 MW Potential • Cogeneration is assumed to result in zero net emissions • All Alternative Generation potential was broken down by Michigan zones (UP, LP, SE Michigan)

12. Assumptions Review • Alternative Generation • Retirements • Wind – 25 Years • No retirement for Hydro, Storage, or Interruptible Load • All new alternative generation is purchased at 7¢/kWH (2005), escalating at GDP (2.47%)

13. Assumptions Review • Transmission & Distribution • Sources of Assumptions • Base Case • Low Import Case • High Import Case

14. Assumptions Review • Transmission & Distribution • Assumptions from ATC • Upper Peninsula to Lower Peninsula 50 MW • ATC to external Market 224 MW in 2005, 300 MW in 2006, 325 MW in 2008 and 525 MW in 2010 • Base Model is 2009 MTEP • The High Import case represents Tier 1 Transmission improvements

15. Upper Peninsula 50 MW Ontario 525 MW 350 MW 0 MW METC TN 2850 MW ITC MAPP 350 MW 650 MW 3400 MW TN 3000 MW 2800 MW TN 3200 MW MAIN 2900 MW MAAC 3050 MW VACAR TVA Assumptions Review • Base Case - 2010

16. Upper Peninsula 50 MW Ontario 525 MW 350 MW 1500 MW METC TN 1800 MW ITC MAPP 350 MW 200 MW 1450 MW TN 1650 MW 2800 MW TN 3200 MW MAIN 2900 MW MAAC 3050 MW VACAR TVA Assumptions Review • Low Import Case - 2010

17. Upper Peninsula 50 MW Ontario 525 MW 350 MW 0 MW METC TN 3950 MW ITC MAPP 350 MW 1150 MW 4750 MW TN 4250 MW 2800 MW TN 3200 MW MAIN 2900 MW MAAC 3050 MW VACAR TVA Assumptions Review • High Import Case - 2010

18. Assumptions Review • Integration • Interchange with the external market will represent non-firm spot market purchases and sales of energy only. • We will not represent an external capacity market selling into Michigan nor selling out of Michigan • For the purposes of this study, we will use a statewide reserve margin of 15%. This figure is not representative of the individual companies’ planning criteria. • Due to planning criteria deficiencies and construction lead times, the reserve margin criteria is feathered in and full 15% is realized in 2014. • In the Low Import Case, we are not modeling any direct sales from Michigan to Ontario Hydro. It is our assumption that the “external market” is wheeling across Michigan to sell 1500 MW to Ontario Hydro.

19. Fuel Forecast Methodology and Forecast • Coal • 13 separate demand regions, 10 of which have been used in this analysis • 14 supply regions, of which we used 4 (Powder River Basin, Central Appalachia, Northern Appalachia, and Rocky Mountain) NE CW YP PRB OH EN N. App SA Rocky Mtn KY C. App WS AL GA

20. Fuel Forecast Methodology and Forecast • Coal • EIA provides average transportation costs between these demand and supply regions, as well as a mine price for each of the supply regions • NEA calculated the year over year percent change in mine prices in order to keep the same relative shape of the EIA forecasted mine prices while adjusting for recent prices at the mines • A blend for each plant was developed based on filed documents (FERC Form 423), independent research, and client information • The final delivered price of coal is the sum of the recent mine price forecast and the average transportation cost, after adjusting for the different blend of coal

21. Fuel Forecast Methodology and Forecast • The starting point for the forecast is based on the 6 month rolling average price at the mine mouth (source: EIA Coal News and Markets)

22. Fuel Forecast Methodology and Forecast • The starting point for the forecast is based on the 6 month rolling average price at the mine mouth (source: EIA Coal News and Markets)

23. Fuel Forecast Methodology and Forecast

24. Fuel Forecast Methodology and Forecast • Gas • EIA provided a wellhead price of the Lower 48 average, as well as the natural gas price by the 12 distribution regions

25. Fuel Forecast Methodology and Forecast • Gas • EIA WellHead Price was adjusted upward by 12.2% to account for the median between wellhead prices and Henry Hub Prices • An analysis was performed by NewEnergy that compared historical wellhead prices and historical Henry Hub prices for their correlation, standard deviation, average % difference, and median % difference. • Median % difference was used to scale the WellHead price to Henry Hub • Methodology employed by EIA (http://www.eia.doe.gov/oiaf/analysispaper/henryhub/index.html) • The difference in these two sets of prices allowed us to calculate a basis between the distribution region and Henry Hub • A year over year percent difference was calculated from the wellhead price to maintain the basic shape of the EIA forecast

26. Fuel Forecast Methodology and Forecast • The starting point for the forecast is based on a one month rolling average of 18 month futures strips (July ’05 through December ’06)

27. Fuel Forecast Methodology and Forecast

28. Emissions Forecast Methodology and Forecast • In developing the emissions forecast for the Michigan IRP, a methodology was used that incorporated several public sources including: • EIA Analysis of the Clear Skies Initiative May 2004 • Cinergy Presentation to EPA August 2004 • This presentation contains an EPA Forecast • Historical Indices • The forecast covers SO2, SIP NOX, and Mercury emissions

29. Emissions Forecast Methodology and Forecast • The SO2 Forecast begins with a 6 month average historical index prices

30. Emissions Forecast Methodology and Forecast • The SO2 Forecast is then escalated at same rate as the EPA Forecast (7.38%)

31. Emissions Forecast Methodology and Forecast • The NOX Forecast begins with a 6 month average historical index prices

32. Emissions Forecast Methodology and Forecast • The NOX Forecast stays flat until the EPA forecast begins in 2009. After 2009, the shape is consistent with the EPA forecast. After 2020, the downward trend continues to 2025.

33. Emissions Forecast Methodology and Forecast • The Hg forecast was starts at $40,000/lb and escalates at GDP. In 2018, we reflect the effects of phase II with a 40% jump in the price. Prices then continue to escalate at GDP.

34. IMO NY/NE MISO MAPP MISO MAIN MI PJMCOM PJM E NON MISO MAPP PJM W MISO ECAR PJM S SPP SERC FRCC External Market Representation

35. External Energy Market • Spot Energy Price • Fuel Cost based bid • Bid up for start up costs • Interchange with neighboring areas • Firm Energy Price • Spot Energy Price • Capacity Market Price spread across all hours • Megawatt Daily Index Price • Firm 16 hour energy product • Platt’s Megawatt Daily • The Spot Energy Price is used as the external energy market in STRATEGIST.

36. External Market Forecast

37. External Market Forecast

38. Base Case Expansion Plan • PROVIEW Methodology • For each year of the optimization PROVIEW generates all possible combinations of alternatives • Each combination is tested against the constraints for that year and only those combinations that meet all the constraints are passed; these are the feasible states • Cumulative Capital and operations costs are calculated for each feasible state • Feasible states from year X are the starting points for generating new combinations for year X+1 • Repeat to end of Optimization Horizon

39. Base Expansion Plan • Objective Function • Minimize Present Worth Utility Cost • System and Area Constraints • 15% Minimum Reserve Margin for MECS • 10% Minimum Reserve Margin for METC and ITC • Maximum Reserve Margin set to allow at the largest alternative to be selected to cover a 1 MW shortfall • Other Constraints • No more than one “Big” unit per area commissioned at a time

40. Base Case Screening Curves

41. Base Expansion Plan Plan Specifics No Specialties in base expansion plan Alternatives Considered Combustion Turbine Combined Cycle Pulverized Sub-Critical Coal Alternatives Screened Out Pulverized Super-Critical Coal Fluidized Bed Coal IGCC IGCC – PRB Coal Nuclear Base Case Overview

42. 2005 to 2014 Capacity Additions CT 1,280 MW CC 1,500 MW PC 4,000 MW Nuclear 0 MW IGCC-Seq 0 MW Other 0 MW Total 6,780 MW Demand Growth 2.38 % Reserve Margin 15.85 % Plan Costs NPV Utility Cost $ 29,640.7 M NPV Emissions $ 4,089.0 M NPV CO2 $ 0.0 M Base Case Expansion Plan Results • 2005 to 2024 • Capacity Additions • CT 2,880 MW • CC 2,000 MW • PC 12,000 MW • Nuclear 0 MW • IGCC-Seq 0 MW • Other 0 MW • Total 16,880 MW • Demand Growth 2.17 % • Reserve Margin 15.03 % • Plan Costs • NPV Utility Cost $ 54,605.6 M • NPV Emissions $ 7,638.6 M • NPV CO2 $ 0.0 M

43. Base Case Expansion Plan Schedule

44. Base Expansion Plan High Load Sensitivity Plan Specifics Base Expansion Plan with high load case consistent with the LOLP study. Alternatives Considered Combustion Turbine Combined Cycle Pulverized Sub-Critical Coal Alternatives Screened Out Pulverized Super-Critical Coal Fluidized Bed Coal IGCC IGCC – PRB Coal Nuclear High Load Case Overview

45. 2005 to 2014 Capacity Additions CT 2,240 MW CC 3,500 MW PC 4.500 MW Nuclear 0 MW IGCC-Seq 0 MW Other 0 MW Total 10,240 MW Demand Growth 3.35 % Reserve Margin 15.14 % Plan Costs NPV Utility Cost $ 32,282.9 M NPV Emissions $ 4,107.3 M NPV CO2 $ 0.0 M High Load Case Expansion Plan Results • 2005 to 2024 • Capacity Additions • CT 4,320 MW • CC 4,500 MW • PC 12,500 MW • Nuclear 0 MW • IGCC-Seq 0 MW • Other 0 MW • Total 21,320 MW • Demand Growth 2.63 % • Reserve Margin 15.00 % • Plan Costs • NPV Utility Cost $ 60,895.9 M • NPV Emissions $ 7,771.3 M • NPV CO2 $ 0.0 M

46. High Load Case Expansion Plan Schedule

47. Base Expansion Plan Low Load Sensitivity Plan Specifics Base Expansion plan with low load case consistent with the LOLP Study Alternatives Considered Combustion Turbine Combined Cycle Pulverized Sub-Critical Coal Alternatives Screened Out Pulverized Super-Critical Coal Fluidized Bed Coal IGCC IGCC – PRB Coal Nuclear Low Load Case Overview

48. 2005 to 2014 Capacity Additions CT 0 MW CC 1,000 MW PC 2,500 MW Nuclear 0 MW IGCC-Seq 0 MW Other 0 MW Total 3,500 MW Demand Growth 1.30 % Reserve Margin 16.40 % Plan Costs NPV Utility Cost $ 27,146.3 M NPV Emissions $ 4,051.2 M NPV CO2 $ 0.0 M Low Load Case Expansion Plan Results • 2005 to 2024 • Capacity Additions • CT 1,280 MW • CC 2,000 MW • PC 9,500 MW • Nuclear 0 MW • IGCC-Seq 0 MW • Other 0 MW • Total 12,780 MW • Demand Growth 1.66 % • Reserve Margin 15.42 % • Plan Costs • NPV Utility Cost $ 48,710.8 M • NPV Emissions $ 7,536.0 M • NPV CO2 $ 0.0 M

49. Low Load Case Expansion Plan Schedule

50. High Gas Case Screening Curves