PG&E filed its final Electrification Impact Study (EIS) Part 2 report with the California Public Utilities Commission this year, refining the draft released last fall. E3 hosted a webinar with PG&E and the project team to walk through the methodology, findings, and implications for how California’s largest utility plans for electrification through 2040.
E3 and Integral Analytics supported the study through analytical design and modeling, developing the geospatial and distribution system models that translate statewide electrification forecasts into utility-specific infrastructure needs. E3’s Forecasting Anywhere platform generated high-resolution, location-specific adoption forecasts, which were integrated into Integral Analytics’ LoadSEER software to model impacts down to the secondary system. Caitlin McMahon, the E3 project manager, presented alongside PG&E’s Tom Huynh and Bill Peter and Integral Analytics’ Jesse Fallick. E3 partner Eric Cutter moderated.
Slides can be found here.
Highlights from the discussion:
- Investment of $23 to $31 billion through 2040 is in line with current distribution spending. PG&E’s projected capacity investment to serve electrification tracks with the utility’s recent ramp-up in distribution spending rather than representing a break from current trends.
- Secondary distribution drives the majority of costs. Secondary infrastructure accounts for 62% of total projected distribution costs, with most of that going toward new service connections for new development rather than upgrades to existing equipment. The study introduced a more detailed long-term modeling approach for the secondary system, using spatial indexing to evaluate where new transformers would be needed beyond the service radius of existing assets.
- Electrification can put downward pressure on rates. Spreading fixed costs across higher kilowatt-hour sales puts downward pressure on distribution rates of as much as 25% by 2040, all else equal. The effect appears across all three scenarios modeled.
- Orchestrated flexibility delivers the cost savings. The Enhanced Demand Flexibility scenario reduces peak demand by 2.2 GW and lowers distribution costs by $1.8 billion (7%) relative to the base case. The savings depend on orchestration: load management has to be coordinated with local grid constraints and dispatchable for planning purposes to deliver infrastructure value. A sensitivity that flexed load without orchestration, meaning load was only managed to bulk system needs, reduced costs by only 0.5%.
- Distribution constraints are becoming more localized and seasonal. Historically, most of PG&E’s distribution system peaks at the same time as the broader California grid: summer evenings. As building electrification adds winter heating load and EVs add new charging patterns, those peaks are spreading out. By 2040, only 51% of PG&E’s substation transformers are projected to peak with the CAISO system (down from 67% today), and about 37% will be winter-peaking.
The webinar Q&A touched on the uncertainty in long-term load forecasts, how the secondary modeling approach handles spatially isolated loads, and how PG&E plans to carry these capabilities into its ongoing distribution planning.
PG&E’s EIS is one of three filed by California’s investor-owned utilities under R.21-06-017; E3 also developed the technology-specific flexible load shapes used in SDG&E’s Enhanced Demand Flexibility scenario.
Read the final Electrification Impact Study Part 2 report >
To learn more about E3’s work on distribution planning and grid modernization, please contact eric@ethree.com.
