Avoided Cost and E3 Calculator Workshops Energy and Environmental Economics, Inc. October 3, 2005

Review of E3 Avoided Costs Background Overview of the Methodology Valuation of Peak Hours Utility-specific Data

Information on New Avoided Costs Spreadsheets and reports can be downloaded free from the E3 website:

Avoided Cost Objectives Goals:  Provide objectively derived estimates of avoided costs that are suitable for evaluating PUC funded programs  Develop a transparent and repeatable costing methodology that does not rely on either proprietary data or models Deliverables:  Transparent and defensible avoided cost methodology Separate presentations with proposals for each cost component Make use of existing studies and data to the extent possible  Provide software to update estimates of avoided costs  Provide a report describing methodology, results, and data to support estimates

Summary of Project Requirements Forecast values ( ) for: X = RFP Requirement; R = E3 Recommendation Annual Values Monthly Values Hourly Values Vary by Location Traditional avoided costs Electric generationXR Electric T&DXRR Natural gas procurementXR R Natural gas transportationXRR Environmental externalityX R Reliability adderX Demand Reduction BenefitXR Additional avoided costs (gas and electric)

Electric Avoided Cost Dimensions Utilities PG&E SCE SDG&E Voltage Level Transmission Primary Secondary Dimensions of the Electric Avoided Cost (8760 Hours from 2004 to 2023) PG&E: 9 | 18 SCE: 8 | 5 SDG&E: 4 | 1 Climate Zones | Planning Areas

Prior Electric and Gas Avoided Costs

Electric ($/kWh) Gas ($/Therm) Source: Energy Efficiency Policy Manual p /29/01

The New Costing Framework 200?: 2.84% * $60.00/MWh = $1.70/MWh of load

Conceptual Framework Electric Avoided Costs / Benefits Gas Avoided Costs / Benefits Where a = area, t = time dimension (e.g., hour, TOU period), y = year. TotalBenefit a,h,t =GenMC a,t,y + Externality a,t,y + TransMC a,t,y + DistMC a,t,y + Reliability a,t,y + DemandReductionBenefit a,t,y TotalBenefit a,t,y =Commodity a,t,y + Transportation a,t,y + Externality a,t,y + DistMC a,t,y + DemandReductionBenefit a,t,y (if available)

Formulation of Avoided Cost Electric Period 1 ( ) Platt’s / NYMEX Period 2 Transition Period 3 ( ) LRMC 1 + Ancillary Services (A/S) Period 1 ( ) NYMEX Period 2 Transition Period 3 ( ) Long-run Forecast 1 + LUAF + Compression Commodity Natural Gas Commodity Market Multiplier 1 + Energy Losses T&D Costs  (1 + Peak Losses ) Environment  (1+ Energy Losses) T&D Costs Environment     “NYMEX” = “New York Mercantile Exchange” “LRMC “ = “Long-run marginal cost” = all-in cost of a combined cycle gas turbine (CCGT) “LUAF “ = “Loss and unaccounted for”

Components that Contribute to Shape

Components with Peak Shape Energy and capacity Ancillary Services Market Elasticity Transmission and Distribution Capacity Losses Emissions

Inputs that Vary by Utility Energy and capacity (A/S, environment)  Northern and Southern California T&D  Varies by 16 climate zones in the State Losses  Average and peak losses by IOU

Commodity Shape: Example NP15 Average of Hourly Values by Month Average of period 4/1/1998 through 3/31/2000 – Matched by Daytype

Market Price Forecast Results Annual Average Forward Price Estimate Market LRMC Market Prices Updated as of October 15, 2003

Example of Capacity Separation Integral of the light blue area is the capacity cost.

Energy Losses by TOU Period

A/S Cost Computation Average of A/S costs as share of total energy costs, during non-crisis period (8/99-5/00, 8/01- 7/03): 2.84% Apply 2.84% to shaped hourly energy price  2004: 2.84% * $45.57/MWh = $1.29/MWh of load  2005: 2.84% * $46.65/MWh = $1.32/MWh of load A/S Costs are the same multiplier for the entire state.

Market Elasticity Estimates On-Peak: 8am to 6pm, Working Weekdays, May to October Off-Peak: All Other Hours Market Elasticity Market Multiplier (On Peak RNS = 5%)

T&D Formulation T&D Capacity Cost ($/kW-yr) YearUtility Planning Area PeakAllocationHour Climate Zone (1 + Losses) Utility Voltage level T&D Capacity Cost ($/kW-hr) YearHourUtility Planning Area Climate Zone Voltage Level ** = Item Dimension

Climate zones and planning areas Dominguez Hills Foothill Rural Santa Ana Ventura CEC Title 24 Climate Zones

T&D Avoided Costs by Planning Division SDG&E $77.76 SCE $36.00 $21.00 $5.00 PG&E $70.00 $38.00 $5.00

Calculation of the PCAFs is based on Load Duration Curve of Each Area PCAF weights are assigned proportionally to how high the load is compared to the peak. Load Duration Curve Only highest load hours (top standard deviation) receive any weight.

Allocation of T&D Based on Temperature by Climate Zone Temperature Loads T&D Capacity Cost Drives Load Information Missing or Difficult to Obtain in Many Areas Temperature Use temperature as a proxy for load, and as the basis for allocating costs to hours of the year. T&D Capacity Cost

T&D Allocation Actual Load vs. Temperature Fresno Yellow 8am to 10pm Similar analysis done on 33 PG&E areas as part of CEC Title 24 development

PCAF / Load Relationship Shown Chronologically

Example Results for PG&E Stockton based on TMY Weather

Peak Losses

Environmental Cost Formulation

Emission Prices & Plant Heat Rates Includes NOx, PM-10, and CO 2 emission credit prices Lower bound of heat rate is set at a 6,240 heat rate, upper bound is set at a 14,000 heat rate

Putting the Components Together: Base Case Results

Total Electric Avoided Costs Shape is Based on PG&E’s San Jose Planning Division

3 Day Snapshot of Disaggregated Electric Avoided Costs Avoided Cost is Based on PG&E’s San Jose Planning Division

Comparison of Efficiency Programs Levelized Avoided Cost ($/MWh) over 16 Year Life for All Devices AC Load Shape Based on SEER 12 to SEER 13 Change in Fresno New Avoided Costs are based on PG&E, Climate Zone 13, Secondary Based on hourly simulated AC data, proxy outdoor lighting, flat refrigeration