SoCalGas, SDG&E outline RAMP and GRC data templates, stakeholders press for tranche and cost detail

SoCalGas and San Diego Gas & Electric (SDG&E) presented proposed data templates for the California Public Utilities Commission’s RAMP and upcoming GRC filings during a CPUC technical working group, and stakeholders pressed the utilities for clearer tranche identifiers, more granular asset mapping and explicit lifetime cost reporting.

Jill Tracy, identified in the meeting as senior director of risk and compliance at SoCalGas, said the companies view the templates as “an important part of increasing transparency and accountability and utility risk mitigation and prioritization.” The utilities framed the proposed template as aligned to the CPUC’s Risk Data Format (RDF) and said it is intended to support their May 2025 GRAMa filing. Jade Tien Swan, SDG&E’s risk governance manager, walked attendees through a hierarchy of sheets that link pre‑mitigation risk summaries to mitigation summaries and to benefit‑cost ratio (BCR) calculations.

The presenters said the template is large: “you could see here that we summarized here of 81 fields in this template, 21 are estimated and 39 are derived,” Jade Tien Swan said. The utilities explained the difference between estimated fields (subject‑matter estimates) and derived fields (empirical or simulated calculations), and said the template includes fields to mark whether a datum is estimated or derived.

During the Q&A, stakeholders asked several recurring questions. Participants pressed for (1) a clear primary key and how tranche records will link to mitigation rows; (2) whether lifetime undiscounted mitigation costs would be included in the BCR tables; (3) how tranches will be described so analysts can see which assets or pipeline segments map to a tranche; and (4) whether the template will include project‑level (rather than only program‑level) data.

On the primary key and tranches, presenters said mitigation ID would serve as the primary linking key and that tranche‑level tables would be produced where required by the RDF. Jade Tien Swan and other presenters confirmed that mitigation IDs will be layered for each tranche and that tranche rows will identify the lower/core pairs or asset classes that form each tranche. Chloe Bled and Alan Catulli (presenters from SoCalGas noted as senior team members) added that tranche descriptions will vary by risk type and that, for medium‑pressure gas, examples in prior materials aggregated by asset class (for example, miles of plastic or steel mains and services) rather than by uniquely identified pipe segments.

On lifetime costs, participants asked whether mitigation tables would show undiscounted lifetime mitigation costs as well as test‑year values. Jamie York, a SoCalGas/SDG&E cost staffer who answered cost questions, said the companies historically did not include a revenue‑requirement calculation in prior RAMP filings and that such calculations are not currently part of their standard RAMP deliverables. She said, however, that the presentation and subsequent discussion clarified expectations: presenters confirmed the template should display lifetime benefits and that they would check whether undiscounted lifetime mitigation costs will be included. One stakeholder referenced recent legislation noted in the meeting as “82847” and said that the new law increases the importance of showing year‑by‑year revenue‑requirement impacts for capital requests feeding the GRC.

Stakeholders also urged more granular, project‑level data where feasible. One participant explained why project‑level granularity matters for services such as PSPS mitigation: a system average can mask pockets of customers who experience higher frequency or longer duration events. Presenters acknowledged the benefits of more granularity but said the companies currently plan program‑level mitigation identifiers in the template and are considering how to provide additional project‑level detail without creating impractical data volume. Presenters said alternatives (for example, different candidate mitigations) will be represented as distinct mitigation IDs (for example, an “alt” suffix) so each alternative’s BCR can be compared.

The utilities also explained that certain cost fields are populated from an internal forecasting system they called GRID (General Rate Case Integrated Database). Presenters agreed to clarify whether references to GRID should appear in the field description rather than in the field value‑constraint column of the template.

On discounting and scenario presentation, utilities showed the BCRs computed under multiple discount rates. One presenter said the approach of adding fields for each discount scenario was a layout preference, while commenters noted an alternative approach (used by another utility) of listing a scenario as a separate row; presenters said either format can be considered if it preserves traceability.

No regulatory votes or formal decisions were taken in the meeting. Presenters and attendees agreed to follow up: utilities said they would consider changes suggested in the workshop, check internal workpapers to confirm whether undiscounted lifetime mitigation costs can be included, and try to provide clearer tranche examples or a sample tranche‑level template in follow‑up materials.

For scheduling, the group agreed the next utility presentations will continue through the week, with PG&E presenting the next day. The CPUC staff facilitator said meeting recordings and any collected answers to chat questions would be circulated to the service list.

Looking ahead, stakeholders asked the CPUC and the utilities to work toward a common, machine‑readable template that includes (at minimum) unscaled/unmodified natural‑unit measures, clear tranche identifiers that map back to assets or asset classes, undiscounted lifetime cost fields, and a documented linkage between mitigation IDs and tranches so reviewers can trace program‑level proposals to the specific assets they affect.