Evaluating Demand-side Policy Initiatives for Impacts on Local Capacity Requirements Mike Jaske California Energy Commission CPUC Load Forecasting Workshop - 6/26/2012

The Context AB 1318 (V. Manuel Perez, 2009) requires ARB, in cooperation with CEC, CPUC, ISO, etc. to determine for South Coast Air Basin: Capacity additions needed for reliability Emission offsets required for capacity additions Recommendations for changes to permitting practices and regulations

Local Capacity Requirements Local capacity areas (LCA) are “pockets” where loads internal to a bounded region exceed the ability to import power to serve loads under various contingencies Sufficient generation must located within the LCA to satisfy NERC/WECC reliability standards The CPUC and ISO resource adequacy programs require LSEs to contract with generation to satisfy the LCR

Local Capacity Areas There are 10 LCAs in the CAISO Balancing Authority Area, with this chart showing eight Since the original purpose for this analysis was AB 1318, the areas assessed were LA Basin and San Diego Only results for the portion of the SCE system within the LA Basin are reported

The Approach California Clean Energy Future process devised a set of scenarios for electricity planning Incremental demand-side policy initiatives not included within the CEC’s adopted demand forecast were translated into bus bar-level load reductions for year 2021 to allow the ISO to conduct transmission studies The ISO used busbar-level load reductions to modify power flow base cases and ran LCR studies Result revealed a major reduction in needed capacity

Incremental EE The CEC uses the idea of “committed” to determine what demand-side policy initiatives to include in its demand forecasts A wide range of additional impacts are expected to occur as a result of demand-side initiatives to satisfy CPUC goals, ARB AB32 Scoping Plan, etc. CPUC adjusts the base CEC demand forecast for such impacts in its Long-Term Procurement Plan (LTPP) rulemakings The CEC developed incremental EE projections, which were largely accepted by the CPUC in the 2010 LTPP

2021 Peak Demand Impacts by IOU(MW) Projected Incremental EE (beyond that included in CEC demand forecasts) 2021 Peak Demand Impacts by IOU(MW) PG&E SCE SDG&E Residential 1512 1560 310 Commercial 540 733 168 Industrial 223 17 Total 2275 2461 496 Note 1: @ customer meter without T&D losses Note 2: Source – CPUC 2010 LTPP Scoping Memo (Feb. 2011)

Approach Extract annual peak load results for each customer class from the CEC Incremental Uncommitted Energy Efficiency report for all years 2013 to 2020, and adjust per Feb. 2011 ALJ Ruling in R.10-04-003 Obtain results of CPUC data request to each IOU (circa spring 2011) that identifies summer peak load by busbar and the split to major customer sector. Multiply total busbar peak load by customer sector proportions to get absolute value of load at peak for each customer sector. For each customer class, tabulate results of step 3 to determine the proportion that each busbar is of total IOU service area end-user demand for each customer sector.

Approach, cont’d For each year 2013 to 2020, multiply the IOU service area peak load savings for each customer sector from step 1 by the customer sector proportion of each busbar from step 4. Add up the three customer sector values at each busbar of step 5 to compute the total program impacts at each busbar. Extend the same values from year 2020 to be savings for year 2021. Verify that the sum of impacts across all busbars matches the service area starting peak load impacts of Step 1. Provide bus by bus results to ISO for use in LCR studies for a mid-net load case.

ISO Power Flow Studies Acquire “seed case” from WECC and update California assumptions to define 2021 base case Request PTOs to develop base load projections by bus for topology using adopted CEC service area demand forecast Update generating resources for retirements and additions Customize base case for renewable and DG additions installed by 2021 (4 scenarios)

ISO Studies, cont’d Assess base cases using a wide range of contingencies: Assure that thermal violations do not exist Verify that stability standards are satisfied Large differences between current conditions and each hypothetical future system can reveal potential problems motivating proposals to avoid the problems before they occur

Modification to Assess Inc EE Modify existing power flow base case by debiting load adjustments from 2021 base projections for each load bus Rerun power flow studies to determine results required to avoid violation of standards by various contingencies Compare to comparable case with base load projections

ISO - LCR Requirements for 2021(MW) Note 1: Environmental RPS Scenario Note 2: Source is 2011-12 Transmission Report, Table 3.3-25 and Table 3.4-2

Conclusions Incremental energy efficiency policy initiatives can have a large impact on local capacity area requirements The 2011-12 Transmission Plan does not rely upon adjustments to CEC demand forecasts, thus there is disagreement among CEC, CPUC and ISO about whether or not to rely upon uncommitted energy efficiency or other demand-side policy initiatives ARB is using these results in its AB 1318 study

Proposed Next Steps Determine options for improved sources of data and methods Evaluate potential benefits from improvements in input data and methods and costs of implementation Provide recommendations to decision-makers Implement decisions in future cycles of analysis