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

2. 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

3. 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

4. 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

5. 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

6. 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

7. 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 customer meter without T&D losses
Note 2: Source – CPUC 2010 LTPP Scoping Memo (Feb. 2011)

8. 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 ALJ Ruling in R
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.

9. 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.

10. 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)

11. 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

12. 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

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

14. Conclusions
Incremental energy efficiency policy initiatives can have a large impact on local capacity area requirements
The 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

15. 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