Presentation on theme: "Avoided Cost and E3 Calculator Update Workshop March 14-15, 2006."— Presentation transcript:
Avoided Cost and E3 Calculator Update Workshop March 14-15, 2006
Agenda – Day 1 Introduction 10:00 – 10:25 Discussion of major issues Peak definitions 10:25 – 11:40 Load shape development 11:40 – 12:00 Lunch break Critical and super peak periods 1:00 – 2:30 Break Capacity adder and peak reshaping 2:45 – 4:30 Natural gas price update 4:30- 5:00
Agenda – Day 2 Housekeeping from Day 1 9:30 – 9:45 Miscellaneous issues 9:45 - 11:00 Application of E3 tool Recommendation for future tools Overhead double counting EE forecast in resource plans (net vs. gross) Applicability to demand response Other Recap of consensus / non-consensus 11:00 – 12:00 Lunch Action Plan / Next Steps 1:00 – 2:30 Break Load shape development 2:45 – 5:00
Introduction Scope and purpose for the 2006 update (ALJ Gottstein) See handout entitled Purpose and Scope of 2006 Update (per December 27, 2005 ALJ ruling) Workshop focus and approach (E3) Near term changes for rebalancing, tracking achievements and performance basis setting. Recommendations for longer term changes for the 2009-2011 program cycle. Broader consistency across proceedings/ resource types? Help to identify phase III issues. Working workshop second half of day 2 (load shape development) Approach to discussion Brief summary of E3 findings and recommendations Summary of party positions and discussion Identify areas of consensus / non consensus Alternatives for ALJ consideration Consider both near term and long term
Peak Definitions Peak definitions for EE are needed for MW goals, tracking the achievements of goals, evaluation of portfolios to reach goals, and determining performance basis. Consistency within EE applications Consistency with peak definitions for other resources or in other proceedings (DR, DG, RA). Consider both near and longer term definitions as well as the data requirements.
Peak Metrics – 1 DEER kW Available for measures in the DEER database. For temperature sensitive measures, peak demand is defined as the average grid level impact for the measure from 2pm to 5pm on peak days. Pro: Is currently used by utilities for measures where DEER kW is available, though there are some differences among utilities. Both SCE and SDG&E report DEER kW for all programs. PG&E states that only 60% of its program impacts are based on measures in the DEER database (the rest calculated from larger, complex projects) Cons: Not available for all measures. DEER kW is derived using building simulation tools based on prototypical buildings and as such has some limitation in terms of accuracy. Summer on peak kW Based on old utility studies, or can be calculated from hourly end use or impact shapes Pro: Readily available from old utility studies, which often used load research data and conforms with utility time of use period definitions. Con: On peak periods vary for each utility, so the reported on peak demand reduction for the same measure could differ across utility service territory (even if all other things were equal) On peak demand estimates from the TOU studies can differ from the DEER kW estimates. This fact prompted SDG&E to report DEER kW (also referred to as Deemed kW) for all of their programs.
Peak Metrics – 2 Load Factor based kW (CEC kW) Annual energy reductions multiplied by a fixed conversion factor. Pro: Easy to estimate. Requires little additional M&V effort. Con: Does not recognize the fact that peak load factors vary by measure, and could therefore allow an overemphasis on poor peak-load-factor measures such as residential CFLs. Resource Adequacy (RA) consistent peak kW Early discussions centered around requirements for Demand Response which currently counts peak load as the average reduction over 48 hours of operation, 4 summer months, 4 days per month, 3 hours per operation. According to the newly adopted RA counting rules, the RA value of energy efficiency is 115% of its monthly coincident peak impact. Pro: Might reflect the actual avoided costs of capacity if resource adequacy (RA) counting rules were to apply to energy efficiency measures. Con: RA rules are interim. Requires hourly data. Unclear which hours should be designated as the peak period dispatch hours, or the single hour monthly coincident peak. PG&E also cautions that peak impacts calculated from an RA perspective could be significantly lower than peak impacts estimated from past and current methods.
Peak Metrics – 3 Coincident peak kW Requires hourly load shapes and specification of peak hours. For PG&E’s end use shapes, the peak hours were identified as the five top system load hours in each month. Monthly coincident peak kW = average load during the five peak hours. Coincident peak is the average July through September monthly peak kW. Pro: Provides the most precise metric of peak or critical peak load reduction. Con: Requires hourly load data which is not currently available. May be a challenge for M&V ex-post estimations.
E3 Recommendation for EE Proceedings E3 recommends two options for determining peak demand reduction in the near term: 1. Report DEER kW (deemed kW) where available, and utility best estimates in other cases. 2. Use load factors by end use categories. Longer term: (not addressed in the Draft Report) Move toward a concident peak measure that uses a weighted average of many hours. The number of hours will depend upon the extent to which the impact data and cost data are aligned. The better the alignment, the fewer hours needed.
Summary of Party Positions: Peak Definitions and Load Shapes
Peak Definition across applications Discuss as a group Peak MW ApplicationGranularity neededPotential Peak Definitions Resource AdequacySingle coincident hour each month Long term planningSingle annual peak?
Load shape development Requirements for Peak kW metric EE valuation Representation of EE in other applications Calibration issues Working session to develop action plan, second half of day 2.
Load Shapes E3 recommends a research effort to develop calibrated load shapes for use in the 2009-2011 program cycle. Shapes should be impact shapes (not building shapes) that are hourly in resolution Shapes should reflect diversified impacts at the grid level and reflect run time averages Potential data sources DEER CEUS? Building simulations, such as those used for Title-24. Issues Calibration Alignment of loads with generation costs
Sample Impact Shape Results Res A/C is the PG&E residential end use shape DEER AC eff is the DEER impact shape Both shapes normalized so that total annual reductions sum to 1.0
Sample Commercial Impact Shape Office Cool is the PG&E end use shape (CZ 13) DEER Chiller Eff is the corresponding impact shape Note that the DEER reduction is 0 in the second chart
Comparison of TOU Shares Commercial shares are comparable Normalized Residential DEER shape has higher on-peak %, partly because of negative amounts in other periods.
Need for critical or super peak periods Definitional needs kW and TOU shares for use in other proceedings? Recommended definitions Valuation issues Adders to TOU average avoided costs? Short term options and long term ideal
E3 Recommendation Critical peak metric not necessary for non-dispatchable (EE) programs. Super peak periods could reduce the undervaluation of measures like Res AC that occur with the use of TOU average costs. BUT this would require that utilities could develop super peak impact profiles. E3 recommends that super peak periods not be used in the near term because Shape development would be difficult The examples in the Draft Report are based on PG&E’s building end use shapes, not impact shapes Value could be added directly to programs such as Res AC without the construction of super peak periods.
Super Peak Results: PG&E Generation Avoided Costs & Building End Use Shapes CZ13 CZ3
Summary of Party Positions: Critical Peak Periods
Capacity adder and peak reshaping Capacity Adder Need to increase peak avoided costs? Methods to calculate a capacity adder Peak Reshaping TOD profiles Methods to allocate capacity adder to hours Phase 3 issues?
Draft Report E3 does not believe the LRMC methodology should be modified to require entrant of a CT If the price shapes must accommodate a CT, the capacity adder would be $40-50/kW-yr. This may represent a fundamental change in methodology The LRMC is a full hedged physical product, so no hedge value adder is needed TOD factors should not replace the PX shape because They lack granularity Represent a fundamental change to the avoided cost methodology --- move to phase 3.
Draft Report Residual Capacity Adder Using flat annual gas price Using daily spot gas prices
Impact of $50/kW-yr capacity adder on EE valuation Average avoided costs and hourly shapes Average avoided costs using TOU shapes
Summary of Party Positions: Capacity Adder & Peak Reshaping
Natural Gas Update Updated natural gas forecast with EIA Outlook 2006 forecast and the CEC’s IEPR forecast NYMEX values were not updated in the report (but should be updated with the most recent data available)
Gas Price Change New forecasts are about 6-9% higher than the existing prices.
Generation Avoided Cost Change Updated gas price increases electric generation avoided costs by 4-5% The electric avoided cost increase is dampened by O&M and capital costs that do not change. SP-15
Latest NYMEX Forecasts Note: 60 day average prices for all contract on or after April 2006 have been calculated using 60 calendar days of data up to 3/10/2006, as available.
Day 2 Other Issues Application of E3 tool Recommendation for future tools Overhead double counting EE forecast in resource plans (net vs. gross) Applicability to demand response Other Action Plan / Next Steps Load Shape Development
Draft Report No need to depart from E3 calculator in near term E3 requires no modifications to conform to SPM Overhead cost double counting is a caused by reporting rules. Calculator improvements such as links to DEER and load shapes should be held until the next program cycle when new load shape data is available.
Summary of Party Positions: Tool-related Comments