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Power Supply Plan July 2009

Power Supply Plan July 2009. Presented by Tim Ponseti July 28, 2009. Purpose of Briefing. Purpose is to review Power Supply Plan (PSP) assumptions, inputs and results that will drive the FY10 budget: PSP overview includes: Load Forecast Generation Plan Capacity Plan

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Power Supply Plan July 2009

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  1. Power Supply PlanJuly 2009 Presented by Tim Ponseti July 28, 2009

  2. Purpose of Briefing • Purpose is to review Power Supply Plan (PSP) assumptions, inputs and results that will drive the FY10 budget: • PSP overview includes: • Load Forecast • Generation Plan • Capacity Plan • Key Drivers and Assumptions • Key Risks

  3. Load Forecast: Peak and Energy

  4. Load Forecast: Summer Peak Summer Peak FY16-28 CAGR: 1.8% FY09-16 CAGR: 2.1% FY16-28 CAGR: 1.3% FY00-08 CAGR: 0.9% FY09-16 CAGR: 2.1% Actual Forecast

  5. Load Forecast: Energy System Energy FY16-28 CAGR: 1.6% FY09-16 CAGR: 0.8% FY00-08 CAGR: 1.9% FY16-28 CAGR: 0.8% FY09-16 CAGR: 1.6% Actual Forecast

  6. Trend of System Peak Demand • 2009 Forecast: 32,572 MW (actual winter peak) • 2% above 2008 actual • Flat to 2009 budget • 2010 Forecast: 31,760 MW (winter peak) • 2% below 2009 peak • 3% below last year’s budget for 2010 • Lower forecast due to: • Loss of Alcoa potlines (350 MW) • Cutbacks for other directly served customers

  7. ٭ ٭ ٭ ٭ Winter Peak Trend of Peak Demand Down 2% from 2009; Down 3% from last year’s budget for 2010 Lower due to loss of Alcoa & direct served cutbacks

  8. Trend of Energy Requirements • 2009 Forecast: 167,169 GWh (with actuals through May) • 7% below 2008 actual • 8% below 2009 budget • 2010 Forecast: 163,991 GWh • 2% below current 2009 forecast • 10% below 2009 budget for 2010 • Lower forecast due to: • Worsening economy • Loss of distributors • Significant reductions to directly served sector (Industrials) • Loss of Tapoco generation (873 GWh)

  9. Trend of Energy Requirements Down 2% from 2009; Down 10% from last year’s budget for 2010 Lower due to economy, loss of distributors, Alcoa & direct served cutbacks

  10. Generation Uses (Demand) Sources (Supply)

  11. Energy Supply and Sales Balance FY 2010 Generation Energy Requirements Total = 165k GWh (164k GWh Excluding Sales) Total = 164k GWh

  12. Capacity vs. Energy - 2010 (163,991 Excluding Sales) 12

  13. Generation Sources - 2010 2010 Budget (Jul09) 2009 Budget (Aug08) Total = 165k GWh 2010 – Jul09 Forecast Load Factor = 59% Total = 183k GWh 2010 – Aug08 Forecast Load Factor = 63%

  14. FY09-FY12 Generation Plan Jul09

  15. Fuel & Purchased Power Costs Aug08 • Overall prices and volume have dropped since last year’s budget • 2010 lower than 2009 due to decrease in purchase volume • Costs include nuclear, hydro, purchases, coal, gas & oil (including non-FCA fuel costs) • Reconciliation under final review Jul09

  16. Capacity Expansion Uses (Demand) Sources (Supply)

  17. Capacity & Peak Demand Balance FY 2010 Firm Supply Firm Requirements Total Firm Requirements = 36k MW Total Firm Supply = 36k MW

  18. Capacity & Peak Demand Balance • Lower load forecast, combined with existing PPA’s and 800 MW increase in hydro assumption, produces slightly long position in 2010 • 2010 hydro assumption assumes additional 800MW of capacity (not yet realized) • Given the increase in hydro energy in 2009, the 2011 hydro forecast was advanced one year • Reserves include interruptible customers

  19. Existing, Approved & Signed Supply GAP Total Requirement (Based on Summer Peak) Total Firm Supply

  20. FY10 Capacity Changes: FY09 Budget Compared to FY10 Budget MW Change in FY10 Firm Requirements

  21. Trend of Firm Requirements

  22. Existing & Approved Capacity ST Market = purchases with less than 60 month duration and do not extend past the end of FY14

  23. Capacity Gap - Expansion Plan 2010 Budget (Jul09) Supports 1100MW Fleet Capacity Reduction Supports 680MW Fleet Capacity Reduction Supports 350MW Fleet Capacity Reduction ST & LT Market: future deals, not yet executed

  24. Cumulative Expansion Costs 2009 Budget Does not include $’s for nuclear fuel or Clean Air 2010 Budget

  25. Capacity Expansion Summary FY10 Budget FY09 Budget • Gleason CT refurbishment in 2014 • DSM impacts handled outside Power Supply Plan • JOF retirement placeholder assumed in 2022 (1,100 MW reduction) • HMODs add ~80 MW hydro capacity from 2010-2016 • 1 BFN EPU in 2013 (205 MW) • Nuclear units after WBN: • 2018, 2022, 2026 & 2030 • Northeast TN CC added for 350MW JSF capacity loss in 2012 • Transmission upgrades for 680MW WCF capacity loss in 2014 • Gleason CC conversion in 2012 • Includes ~1300 MW of DSM by 2012, 140 MW/yr after • JOF retirement placeholder assumed in 2022 (1,100 MW reduction) • HMODs add ~80 MW hydro capacity from 2010-2016 • 3 BFN EPU’s 2010-2011 (527 MW) • Nuclear units after WBN: • 2018, 2019, 2025 & 2026

  26. PSP Key Drivers & Assumptions

  27. PSP Key Risks

  28. Appendix Uses (Demand) Sources (Supply)

  29. Long Term Generation Plan - Jul09

  30. Energy Sources & Uses – Jul09 Actual Forecast (Jul09)

  31. Energy Sources & Uses – Aug08 Actual Forecast (Aug08)

  32. Hydro Energy Assumptions

  33. Hydro Capacity Assumptions * *No change in dry vs. median for Sepa & Tapoco

  34. System Requirements (Summer) 2009 for 2010 2010 for 2010 TVA has an obligation to build or buy capacity to meet expected system requirements (35,989 in 2010) 34

  35. System Load Comparison Total Firm Requirements (Summer) *Planning Reserves: Rule of Thumb – 8.5% of (Load less Interruptible) Operating Reserves: Adjustment necessary to match regulatory requirements 35

  36. Load & Capability – 2010 Budget Based on Summer Peak Demand • 2010 & 2011 Summer Peak is lower than Winter Peak • Capacity Plan is developed based on Summer Peak when fleet capacity is lower due to ambient conditions • Due to more favorable conditions during winter, fleet capacity is increased, offsetting this challenge

  37. Capacity Balance FY10-FY12

  38. L&C Base Capacity Position – Jul09 L&C = Load and Capability

  39. L&C w/Capacity Expansion Plan – Jul09 L&C = Load and Capability

  40. Expansion Plan w/Approved Projects Supports 1100MW Fleet Capacity Reduction Supports 680MW Fleet Capacity Reduction Supports 350MW Fleet Capacity Reduction

  41. Cumulative Expansion Costs Does not include $’s for nuclear fuel or Clean Air

  42. Expansion Plan Bud10 & Bud09 Capacity Additions – 2010 Budget Plan • Green bars represent Nuclear units, beginning with EPU at BFN & WBN2 in 2013, BLN1-4 in 2018, 2022, 2026 & 2030, adding ~4700 MW by 2028. • Brown bars represent Coal plants – none added in current plan. • Orange bars represent CCs, beginning with Lagoon Creek in 2010, Northeast TN CC in 2012 and over 4,000 total by 2028. • Blue bars represent CTs, beginning with two plants in 2014, and totaling over 8,000 MWs by 2028. • Yellow bars and pink bars represent market purchases, <60 months and >/=60 months, respectively. • Light blue bars in 2009 budget plan represent DSM programs projecting peak load relief. 1100MW Fleet Capacity Reduction WBN2 Added NECC Added LGCC Added

  43. PPA’s and Fleet Capacity Changes

  44. Expansion Costs – Jul09 ($)

  45. Expansion Costs – Aug08 ($)

  46. Expansion – Jul09 (MW) 46

  47. Expansion – Aug08 (MW) 47

  48. L&C Capacity Expansion – Aug08

  49. Load Forecast Summary Summer Peak System Energy FY16-28 CAGR: 1.8% FY16-28 CAGR: 1.6% FY09-16 CAGR: 2.1% FY09-16 CAGR: 0.8% FY16-28 CAGR: 1.3% FY00-08 CAGR: 0.9% FY00-08 CAGR: 1.9% FY16-28 CAGR: 0.8% FY09-16 CAGR: 2.1% FY09-16 CAGR: 1.6%

  50. Direct Served Sales (GWh) • FY09 sales to Industrial customers are down 26% from FY08 • FY09 expected sales to total direct served customers are down 17% from FY08 actual and down 17% from FY09 budget forecast for FY09 • FY10 Industrial sales are forecast to drop 10% from FY09, primarily due to the loss of Alcoa • FY10 total direct served sales forecast is down 22% from the FY09 budget for FY10 FY09-12 CAGR: FY04-08 CAGR: 3.6% 0.6% 0.5%

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