Electric Resource Planning. City Commission Target Issues Workshop May 19, 2004 Part 1 of Presentation

Transcription

1 City Commission Target Issues Workshop May 19, 2004 Part 1 of Presentation

2 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?

3 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

4 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

5 4200 Gigawatt-hours ANNUAL ENERGY USE HISTORY & FORECAST Calendar Year History High Base Low

6 Retail Sales by Customer Class Calendar Year 2004 Calendar Year % 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

7 850 Megawatts SUMMER PEAK DEMAND HISTORY & FORECAST Calendar Year History High Base Low

8 850 Megawatts WINTER PEAK DEMAND HISTORY & FORECAST Calendar Year History High Base Low

9 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%

10 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)

11 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/ Combined Cycle #8 Nat. Gas No. 2 Oil 07/00 Unknown Combustion Turbine #1 Nat. Gas No. 2 Oil 12/63 03/ Combustion Turbine #2 Nat. Gas No. 2 Oil 05/64 03/ A. B. Hopkins Steam #1 Nat. Gas No. 6 Oil 05/71 03/ Steam #2 Nat. Gas No. 6 Oil 10/77 02/ Combustion Turbine #1 Nat. Gas No. 2 Oil 02/70 03/ Combustion Turbine #2 Nat. Gas No. 2 Oil 09/72 03/ C. H. Corn Hydro #1 Water Water 09/85 Unknown Hydro #2 Water Water 08/85 Unknown Hydro #3 Water Water 01/86 Unknown New Peaking Hopkins CT/ICs, Nat. Gas No. 2 Oil 05/05 Unknown Sub 12 ICs Total Generating Capability 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/ Southern Company 01/04 12/ Morgan Stanley 05/04 09/ Total Firm Purchases GRAND TOTAL POWER SUPPLY

12 EXISTING & APPROVED FUTURE RESOURCES 800 Megawatts New Peaking Purdom CTs Hopkins CTs Purdom 7 Hopkins 1 Hopkins 2 Purdom 8 Purchases Hydro Year

13 CAPABILITY BY RESOURCE TYPE FISCAL YEAR 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%

14 GENERATION BY RESOURCE/FUEL TYPE FISCAL YEAR ,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%

15 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

16 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

17 EXISTING & APPROVED FUTURE RESOURCES Megawatts Reserve deficient New Peaking Purdom CTs Hopkins CTs Purdom 7 Hopkins 1 Hopkins 2 Purdom Year Purchases Hydro Load Load + 17% Res Surplus/Deficit 17% Reserve (16) (26) (84) (94) (105)

18 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

19 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

20 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

21 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

22 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

23 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.

24 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 Nat Gas Homebuilder Rebates Appliance Change-Out Loans Information/Audits Low Income Insulation Rebate Total Residential Annual Energy Reduction (79.8 GWh) Commercial Programs HVAC Loans Efficiency/Fuel Switch Loans Efficiency/Lighting Loans Demonstrations Information/Audits Total Commercial

25 Demand-Side Options (2002 IRP) (Options considered in 2004 IRP will not necessarily include or be limited to the following)

26 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

27 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?