City Commission Target Issues Workshop May 19, 2004 Part 1 of Presentation
Questions to be Considered How much energy will our customers use in the future? Will we be able to meet the projected energy use? Are additional resources needed? What alternatives do we have to meet our resource needs? Are there strategic considerations that will limit the alternatives we can consider? How do we properly evaluate all of these resource alternatives? How do we find the best solution? Which alternatives do we choose?
Q: How much energy will our customers use in the future? A: Demand and Energy Forecast Customers and Annual Energy Use By Rate Class (Residential, Commercial, Large Commercial) Seasonal Peak Demand
Forecast Data Requirements Historical customers and annual energy use by rate class, seasonal peak demand Normal weather patterns (Min/max temp, cooling/ heating degree days) Population forecasts (Florida, Leon County) Econometrics (GDP, CPI, taxable sales, real price of electricity) Appliance saturation State government, FSU, FAMU, large customer incremental load additions, Talquin transfers Impact of conservation programs
4200 Gigawatt-hours ANNUAL ENERGY USE HISTORY & FORECAST 3800 3400 3000 2600 2200 1800 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Calendar Year History High Base Low
Retail Sales by Customer Class Calendar Year 2004 Calendar Year 2013 7% 7% 26% 26% 40% 39% 1% 3% 23% 1% 3% 24% Total 2004 Sales = 2,704 GWh Total 2013 Sales = 3,199 GWh Residential Non-Demand Demand Large Demand Curtail/Interrupt Traffic/Street/Security Lights
850 Megawatts SUMMER PEAK DEMAND HISTORY & FORECAST 750 650 550 450 350 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Calendar Year History High Base Low
850 Megawatts WINTER PEAK DEMAND HISTORY & FORECAST 750 650 550 450 350 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 Calendar Year History High Base Low
Ensuring Forecast Accuracy Forecasts subjected to an ex-post analysis Actual customers, annual energy use and seasonal peak demand normalized to projected versus actual forecast inputs (weather, population, etc.) Contribution of each input variable to forecast reviewed and adjusted as necessary Normalized 2003 energy sales forecast within 2% of actual; summer peak demand within 5%; winter peak demand within 1%
Q: Will we be able to meet the projected electricity use? A: Compare resources and requirements Generating units & purchased power Ensure there is a margin for unexpected events (contingencies)
EXISTING AND APPROVED FUTURE GENERATING FACILITIES In- Expected Net Service Retirement Dependable Capability Primary Secondary Date Date Summer Winter Plant Unit Fuel Fuel (mm/yy) (mm/yy) (MW) (MW) S. O. Purdom Steam #7 Nat. Gas No. 6 Oil 06/66 03/11 48.0 50.0 Combined Cycle #8 Nat. Gas No. 2 Oil 07/00 Unknown 233.0 262.0 Combustion Turbine #1 Nat. Gas No. 2 Oil 12/63 03/08 10.0 10.0 Combustion Turbine #2 Nat. Gas No. 2 Oil 05/64 03/09 10.0 10.0 A. B. Hopkins Steam #1 Nat. Gas No. 6 Oil 05/71 03/16 76.0 78.0 Steam #2 Nat. Gas No. 6 Oil 10/77 02/22 228.0 238.0 Combustion Turbine #1 Nat. Gas No. 2 Oil 02/70 03/15 12.0 14.0 Combustion Turbine #2 Nat. Gas No. 2 Oil 09/72 03/17 24.0 26.0 C. H. Corn Hydro #1 Water Water 09/85 Unknown 4.0 4.0 Hydro #2 Water Water 08/85 Unknown 4.0 4.0 Hydro #3 Water Water 01/86 Unknown 3.0 3.0 New Peaking Hopkins CT/ICs, Nat. Gas No. 2 Oil 05/05 Unknown 96.0 101.0 Sub 12 ICs Total Generating Capability 748.0 800.0 EXISTING FIRM PURCHASED POWER CONTRACTS In- Expected Net Service Retirement Dependable Capability Date Date Summer Winter Seller (mm/yy) (mm/yy) (MW) (MW) Progress Energy Florida 10/99 03/16 11.0 11.0 Southern Company 01/04 12/04 34.0 34.0 Morgan Stanley 05/04 09/04 25.0 0.0 Total Firm Purchases 70.0 45.0 GRAND TOTAL POWER SUPPLY 818.0 845.0
EXISTING & APPROVED FUTURE RESOURCES 800 Megawatts 700 600 500 400 300 200 New Peaking Purdom CTs Hopkins CTs Purdom 7 Hopkins 1 Hopkins 2 Purdom 8 Purchases Hydro 100 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Year
CAPABILITY BY RESOURCE TYPE FISCAL YEAR 2005 352 MW or 46.4% 233 MW or 30.7% 152 MW or 20.0% CC Steam CT/Diesel Purch Hydro 11 MW or 1.4% 11 MW or 1.4%
GENERATION BY RESOURCE/FUEL TYPE FISCAL YEAR 2005 1,869 GWh or 63.2% 181 GWh or 6.1% 626 GWh or 21.2% CC - Gas Steam - Gas Steam - Oil CT/Diesel - Gas CT/Deisel - Oil Purch Hydro 9 GWh or 0.3% 117 GWh or 4.0% 152 GWh or 5.1% 1 GWh or <0.1%
Factoring in Unexpected Events Planning Reserve Margin Current 17% criteria (i.e., planned power supply must exceed projected peak demand by at least 17%) Supported by analysis in 2002 IRP Operating Reserve Required capability above regional demand sufficient to replace loss of region s largest generating unit Must be fully available in 15 minutes Reserve sharing among Florida utilities City s portion is 33 MW - 25% must be spinning (reserved capability of units on line), remaining 75% non-spinning may be satisfied with off-line quick start units such as new peaking units planned for summer 2005
Q: Are we long or short on energy resources? A: Determine supply surplus/deficit Increase peak demand forecast by applying the planning reserve margin Compare this adjusted load to existing and planned future resources to identify resource surplus or deficit
EXISTING & APPROVED FUTURE RESOURCES Megawatts 900 800 700 600 500 400 300 Reserve deficient New Peaking Purdom CTs Hopkins CTs Purdom 7 Hopkins 1 Hopkins 2 Purdom 8 200 100 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Year Purchases Hydro Load Load + 17% Res Surplus/Deficit 17% Reserve 12 55 37 25 5 (16) (26) (84) (94) (105)
Q: What alternatives do we have to meet our resource needs? A: Identify resource options to meet needs Reduce demand through conservation, load management, pricing Increase supply by purchasing from others (adequate transmission?), deferring retirements or enhancing capability of existing generation, adding new generation
Resource Considerations Capability of demand-side versus supply-side resources to fulfill the need Purchased power vs. generation additions (transmission/reliability) Technologies acceptable to the City Role of renewable technologies Partnership/alliance opportunities
Data Requirements Demand-Side Available program types by customer class Cost of program versus customer/utility benefit Expected program penetration Supply-Side Economic parameters Environmental considerations/limitations Siting issues Fuel delivery Requirements for interconnection with grid
Q: Are there strategic considerations that will limit the alternatives we can consider? A: With guidance from the City Commission, identify any constraints based on policy or community values such as: Cost-effectiveness criteria for DSM programs Siting generation or transmission facilities Evaluation of coal-fueled resources Willingness to fund investment in regional transmission facilities
Are There Strategic Issues/Concerns? Policy framework that limits what alternatives can be considered and/or how certain alternatives are evaluated Set by City Commission Examples of strategic issues: Cost-effectiveness criteria for DSM programs Constraints on siting generation or transmission facilities Support for coal-fueled resources in the mix Willingness to fund investment in regional transmission facilities not located in our service territory
Can We Reduce the Load to be Served? Existing Demand-Side Management Programs (1996 DSM Plan as amended) Residential Programs HVAC/Water Heater Loans Nat. Gas Homebuilder Rebates Appliance Change-Out Loans Information/Audits Low Income Ceiling Insulation Rebate Commercial Programs HVAC Loans Efficiency/Fuel Switching Loans Efficiency/Lighting Loans Demonstrations Information/Audits Detailed descriptions of each program are provided in the Appendix.
Expected 96 DSM Plan Impacts through 06 Summer Peak Demand Reduction (19.5 MW) Winter Peak Demand Reduction (57.7 MW) Program Percent Contribution to: Summer Winter Annual Peak Peak Energy Reduction Reduction Reduction Residential Programs HVAC/WH Loans 29.6 27.9 26.7 Nat Gas Homebuilder Rebates 32.7 54.2 41.8 Appliance Change-Out Loans 4.6 1.6 4.3 Information/Audits 6.8 7.6 6.8 Low Income Insulation Rebate 1.1 0.4 0.1 Total Residential 74.8 91.7 79.7 Annual Energy Reduction (79.8 GWh) Commercial Programs HVAC Loans 12.3 3.2 7.4 Efficiency/Fuel Switch Loans 7.2 3.3 6.8 Efficiency/Lighting Loans 2.8 0.9 2.6 Demonstrations 1.6 0.5 1.5 Information/Audits 1.3 0.3 2.0 Total Commercial 25.2 8.3 20.3
Demand-Side Options (2002 IRP) (Options considered in 2004 IRP will not necessarily include or be limited to the following)
Can t We Buy Power in the Market? Power Purchase Considerations Determination of available transmission import capability Assessment of short- and long-term purchase opportunities Adequacy of existing grid, cost of grid improvements to accommodate off-system purchase
Could We Modify/Enhance Our Existing Units? Possible options Include: Defer planned retirements Purdom 8 inlet air chilling Hopkins 2 steam turbine upgrade Hopkins 2 conversion to combined cycle Other?