[{"_1":2,"_123":-5,"_124":-5},"loaderData",{"_3":4,"_26":27},"root",{"_5":6,"_17":10,"_18":19,"_20":21,"_22":10,"_23":-5,"_24":-5,"_25":10},"user",{"_7":8,"_9":10,"_11":10,"_12":-5,"_13":-5,"_14":15,"_16":-5},"roles",[],"isAuthenticated",false,"isPremium","planName","subscriptionStatus","featureFlags",{},"insightsBudget","isDevelopmentHost","userPreferences",{},"recaptchaSiteKey","6LcvOJcUAAAAAHsB-gPGfGktcRlKpH7OTIU_dMTD","isImpersonating","impersonation","affiliateStatus","isFreedomPortal","routes/v2/article/layout",{"_28":29,"_30":31},"notFound",true,"relatedArticles",[32,76,88,100,111],{"_33":34,"_35":36,"_37":38,"_39":40,"_41":42,"_43":44,"_45":46,"_47":48,"_49":50,"_51":52,"_53":54,"_55":56,"_57":58,"_59":60,"_61":62,"_63":64,"_65":66,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},"mediaId",6219500,"mediaKeyId","3622432-bfab2d6dccf72b9001367825201e405d","parentId",3622432,"title","Independent Planning Engineer outlines V&V scope; DPAD and post‑DPAG reports to follow utility filings","audioSeconds",966,"startMs",7036000,"endMs",8002000,"viewUrl","/Search/View?dp=1&key=3622432-bfab2d6dccf72b9001367825201e405d&start=7036&end=8002","thumbnailUrl","https://assets.pipeline.soar.com/3622432-bfab2d6dccf72b9001367825201e405d/thumbnail_7036000.jpg","articleUrl","/articles/6219500/California/Independent-Planning-Engineer-outlines-VV-scope-DPAD-and-postDPAG-reports-to-follow-utility-filings","mediaUrl","https://secure.pipeline.soar.com/6219500-1d7def813ac449784eb6468afe4e7689/orig.mp4?Expires=1773643153&Signature=hgdJQBrqmgN5zd3Wj5YmHzJ0PgYDhZihsVzR0STq7VtDo80P5Oa1vChWGcW-cMDRDnWrZsJptfD4OJVaN6tFnx3zkrsf06NRN3cafX8ectqoe6Na4Tuut~3mc60b2yi05WKzULBpwJMfI75uCgQyA3WY77dTzmaVo2sro2LWC5RmBghMJEIX~EbFeh9wEfHLikekg-gDbWt6FKl45XiXOz6rq1ojW2JXwjasC2HFKW~qTz9SgNjkA1fAgZAlZU~q91GrEp1FsvTISMOJS0LiC~plCE~gqz5WLlutiwTmLYXnPsVH4k~maBCxaZum78Qreu9aSnAGMny~0Sg~4RNSmg__&Key-Pair-Id=KUT5TJCACFTXG","author","California Public Utilities Commission","date","2025-06-02T21:19:01.077Z","article","The Independent Planning Engineer (IPE) presented its planned verification and validation (V&V) scope for the 2025 distribution planning cycle at the May 22 DFWG workshop. Barney Speckman of Resource Innovations, speaking on behalf of the IPE (lead Sundar Venkataraman is IPE but traveling), reviewed how the IPE plans to verify utility outputs and validate approaches used to turn IPR inputs into distribution projects.

Why it matters: The IPE provides an independent review of the utilities’ forecasting, disaggregation, and project prioritization processes. Its assessments and recommendations are intended to increase transparency and identify methodological issues that affect planning outcomes.

Scope and changes from prior cycles: Speckman said the IPE’s scope is based on a CPUC/energy‑division statement of work and the 2020 High DER decision. Where business processes have not changed since prior cycles, the IPE plans to skip repetitive verification steps; but the IPE flagged several items newly added to its scope this cycle. In particular the IPE said it will:

• Verify utilities’ use of known and pending loads and check whether previously identified projects remain needed under current assumptions (a refinement of what the IPE called step 13).

• Review project prioritization (step 27) and planned versus deferred project designations.

• For the first time, review project execution tracking data (step 28) that utilities will file to show customer requests, design and construction progress and completion status.

Deliverables and timeline: The IPE said a draft IPE plan would be filed and served the week of the workshop for stakeholder comment; the final plan will be issued in coordination with the utilities’ August GNA filings. The IPE’s preliminary data adequacy analysis is scheduled before DPAG meetings; the IPE intends to publish an IOU‑specific DPAD report (the principal V&V deliverable) in early November, and a combined post‑DPAG report comparing utilities and recommending process improvements is due March 15, 2026.

How V&V is defined: The IPE distinguished verification (an audit‑like check that utility outputs match the declared process and data) from validation (an assessment of whether the approach and its assumptions are appropriate). The IPE invited stakeholder comment on its draft plan and said it will incorporate feedback before finalizing materials.","mediaType","Video","parentTitle","2025 Distribution Forecasting Working Group","oneSentenceSummary","The Independent Planning Engineer (IPE) presented its draft verification and validation plan for the 2025 distribution planning cycle; the IPE will review forecasting, disaggregation, project prioritization and, newly this cycle, project execution tracking data.","taxTitle","California Public Utilities Commission, Boards and Commissions, Executive, California","taxId",77657,"location","California","headline","","shortSummary",{"_33":77,"_35":36,"_37":38,"_39":78,"_41":79,"_43":80,"_45":81,"_47":82,"_49":83,"_51":84,"_53":85,"_55":56,"_57":58,"_59":86,"_61":62,"_63":64,"_65":87,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},6219505,"SDG&E and SCE use bottoms‑up approaches for medium‑ and heavy‑duty EV forecasts; SDG&E finds higher energy due to vehicle mileages",281,4999000,5280000,"/Search/View?dp=1&key=3622432-bfab2d6dccf72b9001367825201e405d&start=4999&end=5280","https://assets.pipeline.soar.com/3622432-bfab2d6dccf72b9001367825201e405d/thumbnail_4999000.jpg","/articles/6219505/California/SDGE-and-SCE-use-bottomsup-approaches-for-medium-and-heavyduty-EV-forecasts-SDGE-finds-higher-energy-due-to-vehicle-mileages","https://secure.pipeline.soar.com/6219505-5ead797b738a64c4c9f6b81bde73d26f/orig.mp4?Expires=1773643153&Signature=Pvq8N6z-DWASwu27j8l~5yx44MxrSJ-VMgFfJX~zFs5HjP93rAWQqdUVEflElL8rQWpq-cC7OVLjyoVoWfyGpTmni9tbR-~ocZOrk4tXBlhpRkZJtAAcwlX8JzctRN6xB98-S7T2EXyzLzvGo7YghYDk0b4ge7WTeMTL1AYjFkEkhYcJGV1Km6CJfq3lWoPKXiU0fT3WURzhRPFH4YsS36KkhW5sKimfd6JSLoEsEdF0wmwMmB5JBWfnOcJZVR0J8caJnF4dIJMXsTZqtNt3QzLd18IvIP-zeoPsNpFkmrldDZhPwsqS7UhFx0tGmFqr3IAxnbQY-PeD4WJVD-H7Nw__&Key-Pair-Id=KUT5TJCACFTXG","SDG&E and SCE presented bottoms‑up methods for forecasting medium‑ and heavy‑duty (MDHD) electrification at the May 22 workshop, telling stakeholders these forecasts aim to capture facility‑level charging requirements that are not well represented by system‑level IPR scenarios.

Why it matters: MDHD charging can be highly concentrated and may require significant distribution upgrades at depots, ports and freight corridors. Bottoms‑up, facility‑level forecasts can identify localized capacity needs that a system‑level forecast might understate.

SDG&E (Anderson Boles, Clean Transportation Analytics) described a three‑pillar methodology: (1) locate facilities using Department of Transportation (RigDig) records, DMV registration aggregates and port data; (2) categorize facilities against California medium/heavy‑duty electrification mandates and estimate likely adoption timing by regulatory class; (3) compute energy by combining vehicle counts, annual vehicle miles traveled and vehicle efficiency to generate facility‑level energy forecasts that are then aggregated to circuits. Boles said SDG&E’s first iteration is a “first‑of‑its‑kind” bottoms‑up forecast that focuses on vehicles domiciled locally. He told the workshop SDG&E found its resulting energy forecast was larger than the IPR MDHD energy forecast primarily because DOT facility data contained higher annual mileages than the datasets the CEC used.

\"This bottoms up approach really showed us very clearly that medium and heavy duty load is not evenly distributed throughout our territory,\" Boles said, and he added that peak estimates are sensitive to charging behavior assumptions: compressed charging windows (i.e., many vehicles charging in a short time) materially increase peak megawatt demand.

SCE (Chris Mervarzi) described using Guidehouse’s vehicle analytics and simulation tool (VAST) to produce a circuit‑level MDHD forecast. Guidehouse identified local fleet operators and their vehicles, combined that with macroeconomic trends to forecast adoption, inferred charging infrastructure needs and used that to estimate circuit‑level loading impacts. SCE said it used the Guidehouse circuit‑level output to derive allocation factors that distribute the CEC MDHD forecast across SCE circuits. SCE noted the Guidehouse study was conducted for SCE and is not currently public, but SCE offered to discuss the methodology with stakeholders.

Backtesting and limitations: Regulators and stakeholders asked whether utilities have backtested feeder simulations against realized installations. Presenters said there has been limited backtesting to date; SDG&E and SCE both said this is an area for improvement. SDG&E also noted its current forecast focuses on fleets domiciled within its territory and does not yet include non‑domiciled corridor traffic or cross‑border charging in this iteration, though the utility expects to iterate the model in future cycles.

Practical takeaway: The MDHD bottoms‑up forecasts surface highly localized needs and tend to increase short‑term peak estimates relative to system‑level IPR energy allocations when local mileage and operational data indicate heavier use than assumed in the IPR. Utilities plan to refine methods and incorporate more observed charging and application‑level data in future cycles.","SDG&E and SCE presented bottoms‑up medium‑ and heavy‑duty electrification forecasts at the May 22 workshop, using facility‑level DOT, DMV and port datasets (SDG&E) and a Guidehouse VAST study (SCE) to estimate localized energy and peak charging needs.",{"_33":89,"_35":36,"_37":38,"_39":90,"_41":91,"_43":92,"_45":93,"_47":94,"_49":95,"_51":96,"_53":97,"_55":56,"_57":58,"_59":98,"_61":62,"_63":64,"_65":99,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},6219495,"Utilities, Energy Division and stakeholders debate pending‑loads treatment and project risk; advice letters due this cycle",2706,284000,2990000,"/Search/View?dp=1&key=3622432-bfab2d6dccf72b9001367825201e405d&start=284&end=2990","https://assets.pipeline.soar.com/3622432-bfab2d6dccf72b9001367825201e405d/thumbnail_284000.jpg","/articles/6219495/California/Utilities-Energy-Division-and-stakeholders-debate-pendingloads-treatment-and-project-risk-advice-letters-due-this-cycle","https://secure.pipeline.soar.com/6219495-497b1ceb9d650f67f68bcb809d05c671/orig.mp4?Expires=1773643153&Signature=ov8tlQm4jFbkoOeu8-Iv5Q3~e3NstL4pNmvuRUEAZ0qpmr4Oz0K1-1lAm9xoZ7lUNjzlcpJJF3JKD0i3BQhzDEY7DKOyPs02xtQw3-Nl8L6fpBpH81j8asI0xPM7Xox9Y88cPrDMK0plWYeAN~iAw4Aa4B1rw651MBbhlA1oFQo1f1B1e24cHKr0D~3F6ZHTQoz5g01SDVGS~cF8F~ICobU3TpfdmwmddDGvMn1J2Pn7pOzQ-spjrHCQ3iTzVXifVCmpma3wgs2xcGQ5A3Om4-2YH1g8Kre-8cvUPMUTk73-P-DZAJFrUzMZCbqaLI4trjTlIDbH2oc57BmBSM0Ttw__&Key-Pair-Id=KUT5TJCACFTXG","Stakeholders at the May 22 workshop pressed utilities and Energy Division for details about how pending loads and project prioritization will be treated in the 2025 distribution planning cycle.

Why it matters: Whether utilities treat pending loads as part of scenario inputs affects project prioritization and whether an area faces higher risk of capacity shortfalls. Pending‑load treatment also informs advice letters and possible CPUC guidance on how to allocate limited capital among competing needs.

Key points from the workshop:

• Pending‑loads advice letter and timing — Workshop facilitators reminded participants that the IOUs planned to file a joint pending‑loads advice letter (tier 3) on June 30, 2025; a CPUC resolution was expected in September under the Track 1 framework discussed at the workshop. PG&E and others noted the pending‑loads advice‑letter process will inform how pending loads are included in scenarios and planning.

• Early implementation and examples — SCE and SDG&E said they included selected pending loads under an early‑implementation arrangement with Energy Division for the current 2024–25 planning cycle. SCE said examples included Tesla‑related charging and Port of Long Beach projects; SDG&E said it included some truck‑stop and port coordination information.

• Risk profiling and categories A/B — Utilities explained that adopting or excluding pending loads changes a risk profile for capacity planning. PG&E described a framework in which pending loads (categories A and B in their pending‑load framework) create higher localized service risk if not incorporated into project designs; Mark Jimenez said using pending‑load data can change where utilities expect to build capacity and what projects they prioritize.

• Project prioritization and execution tracking — The IPE said it will review project prioritization and project execution tracking (the latter is new in the IPE scope for this cycle). Utilities said project prioritization decisions will be included with their GNA filings and that project execution metrics will be tracked for the IPE’s review.

• Regulatory path — Energy Division staff and workshop presenters said the advice‑letter outcome and a forthcoming resolution will clarify pending‑loads treatment and how utilities must document pending‑load assumptions in the GNA filings.

Next steps: Utilities will file the joint pending‑loads advice letter (June 30); stakeholders can comment through the advice‑letter process and the IPE will review execution‑tracking metrics once utilities file them.","Workshop participants discussed how pending loads will be treated in distribution planning, with a joint pending‑loads advice letter due June 30, 2025 and a CPUC resolution expected in September under the Track 1 framework.",{"_33":101,"_35":36,"_37":38,"_39":102,"_41":103,"_43":104,"_45":104,"_47":105,"_49":106,"_51":107,"_53":108,"_55":56,"_57":58,"_59":109,"_61":62,"_63":64,"_65":110,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},6219510,"PG&E, SCE and SDG&E outline distribution forecasting methods: feeder disaggregation, EV energy reconciliation and new AAFS handling",0,1307000,"/Search/View?dp=1&key=3622432-bfab2d6dccf72b9001367825201e405d&start=1307&end=1307","https://assets.pipeline.soar.com/3622432-bfab2d6dccf72b9001367825201e405d/thumbnail_1307000.jpg","/articles/6219510/California/PGE-SCE-and-SDGE-outline-distribution-forecasting-methods-feeder-disaggregation-EV-energy-reconciliation-and-new-AAFS-handling","https://secure.pipeline.soar.com/6219510-7405aa3a4ff0ac528fbcd4339bcfdded/orig.mp4?Expires=1773643153&Signature=KewJAloBCIehaodXCyuKGi5DU6ZOP~csJ7QSIiuCKO8CO84dO7k1rHqgKuBoc~bkOc~hlprj~AX5ib6dBgS442DO3QaOP2gG1H9TY2hcaN8SPv1nDR80mU1hAYZxukxVFdQSUl9Tjxjw~v9GC025bBbAB6LHlNmiw9Q5WIJIQaMljedkozWKOM6TW24MDoh5WOb058ud1pUfPOVxYURg6uxrKWc0moR7OUVx6m18g~ZuOsyfYUF~TOStVfLIIzFKc-1xByROXukuDbLbUYelMjduXHQS1ZrRXX9hv5rgtYhkpmFUFy24QPru90c29BhghgjGyhbT~1Ut42ES9ew1-w__&Key-Pair-Id=KUT5TJCACFTXG","At the Distribution Forecasting Working Group workshop on May 22, PG&E, SCE and SDG&E described how they convert the CEC IPR system‑level forecast into circuit and feeder‑level forecasts used by distribution planners.

Why it matters: Distribution planning depends on circuit‑level forecasts of peak megawatts and hourly shapes. Differences in disaggregation methods — and in how utilities treat mobile loads such as EVs or emerging fuel‑substitution patterns — change where and when planners expect capacity needs.

PG&E (presentation by Mark Jimenez) described a multi‑step disaggregation starting from the 2023 IPR reliability forecast at the TAC level, then mapping that energy to the PG&E service footprint, using AMI and other customer data and a spatial simulation tool the utility calls “LOTS” to allocate growth across about 3,000 feeders. Jimenez said PV, storage and energy efficiency are handled with class‑based adoption potentials, propensity models and characteristic shapes. He emphasized EVs are modeled differently: \"EV is different because the EV load can move around,\" he said, and PG&E applies an energy‑based adoption reconciliation that preserves the IPR energy while allocating hourly shapes to reflect where charging is expected.

On additional achievable fuel substitution (AAFS), Jimenez described a problem the utilities encountered with the 2023 IPR hourly files: the AAFS shape showed two distinct components with different seasonal growth rates (a winter heating component and a summer component). \"The method that we choose to implement was to break the IPR shape into 2 different shapes in our forecast and apply different growth rates,\" Jimenez said, noting PG&E will refine that approach further in the next forecast cycle.

SCE (Lee Xu and Chris Mervarzi) explained a structure‑level disaggregation approach. Lee described a multivariable regression that combines SCADA, AMI, weather, economic and demographic data to produce structure‑level profiles, then allocates embedded growth from project workbooks and disaggregates remaining IPR growth. Chris detailed SCE’s DER allocation methods: residential PV and residential storage use historical adoption models to produce ZIP‑ and circuit‑level indicators; nonresidential DERs, energy efficiency and fuel substitution use allocation factors derived from billing‑system energy usage and third‑party building‑stock forecasts; EV (light‑duty) adoption was regressed against American Community Survey variables and median household income was the strongest predictor.

SDG&E (Waseem Al‑Safi and colleagues) described a process similar to the others, with specific inputs: historical DER adoption variables, local gas consumption for fuel substitution, and geospatial variables; SDG&E aggregates gas consumption to the circuit level (rather than ZIP code) for fuel‑substitution allocation. SDG&E also confirmed it uses an energy‑based approach for EVs and applies a pending‑loads bottoms‑up method for medium/heavy‑duty electrification this cycle.

Common issues discussed: all three utilities flagged EV forecasting as a key challenge because EV energy is mobile and peaks at specific charging sites (public DCFC can be highly peaky). Participants asked whether the utilities backtest feeder‑level simulations against realized installations; the utilities said they have limited backtesting to date and identified this as an area for improvement.

Bottom line: The three IOUs presented broadly similar high‑level workflows — start with an IPR vintage, adjust for local known loads, allocate by geospatial/propensity indicators and apply characteristic hourly shapes — but they differ in data sources, spatial granularity (ZIP vs circuit) and how they reconcile mobile loads and recent changes to AAFS hourly shapes.","At the May 22 DFWG workshop, the three IOUs described how they disaggregate CEC IPR forecasts to feeders and service points. Key themes included starting from IPR vintages, using AMI and geospatial data for allocation, energy‑based reconciliation for EVs, and splitting AAFS shapes into summer/winter components where needed.",{"_33":112,"_35":36,"_37":38,"_39":113,"_41":114,"_43":115,"_45":116,"_47":117,"_49":118,"_51":119,"_53":120,"_55":56,"_57":58,"_59":121,"_61":62,"_63":64,"_65":122,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},6219515,"Joint California utilities submit 2025–26 demand‑selection letter; Energy Division decision expected Aug. 1",144,196000,340000,"/Search/View?dp=1&key=3622432-bfab2d6dccf72b9001367825201e405d&start=196&end=340","https://assets.pipeline.soar.com/3622432-bfab2d6dccf72b9001367825201e405d/thumbnail_196000.jpg","/articles/6219515/California/Joint-California-utilities-submit-202526-demandselection-letter-Energy-Division-decision-expected-Aug-1","https://secure.pipeline.soar.com/6219515-177e16c1bda91bfb640cdcb0d5f08091/orig.mp4?Expires=1773643153&Signature=Tb-9WMZdGJbHPP4Tl02grJ4vhLl~OX6hHykj41SHuUWW5NZT71CDjWm1v9ulAFS44mL~73tBiayYmwM1hbpmMp3wcPIWJ1~5MVhgDKopfw5dAti67mOdJE~epOU0CMUeoHE9hT~GPuv1I5kIQNq0~gv~0w8xoqYNarndQgoBUa-jHBhgvic8IUmiC-~1gZtdMl0Qe4JokKIBGelwf-FYWAyFnARbZPMCkwLjXccVFo1EpMIL6-wwUWBXS2LKo3uqL73aupcqITF6DDnaBqchxVo-6CSktIL1V6ET5xHvnneET7ZlXhbD5SQy3uFga6h51IhmgV3bsNhYS~VTZwA3Mg__&Key-Pair-Id=KUT5TJCACFTXG","The three investor‑owned utilities (PG&E, SCE and SDG&E) told attendees at the Distribution Forecasting Working Group workshop on May 22 that they submitted a joint demand‑selection letter to Energy Division on May 9, 2025 proposing the IPR (Integrated Planning Report) scenario components to use for the 2025–26 distribution planning cycle.

Why it matters: Energy Division’s decision on the utilities’ forecasting proposal will set the IPR components the companies must follow for distribution forecasting and downstream planning products. The chosen scenario affects load allocation, DER disaggregation and the “GNA/duper” (GNA duper / GNA DOPR references in the workshop) deliverables that feed resource and distribution planning.

The utilities laid out the schedule: stakeholder comments on the demand‑selection letter were due June 19, 2025; Energy Division’s decision was expected Aug. 1, 2025; and the utilities said the joint GNA/Jupyter (2025 GNA and related report) work is due Aug. 15, 2025. SDG&E’s Yi Li summarized the background of the forecasting‑working‑group process and the timeline, linking the current forecasting cycle to prior IPR / DPP activity that began with the TRAX‑three decision in the DRP proceeding.

What the utilities proposed: Each utility said it would start from the CEC IPR local reliability scenario and then apply the utilities’ chosen IPR “vintages” and subcomponents (for example, the AAT, AFS and AAE scenario choices). At the workshop SDG&E said it had proposed the 2024 IPR local reliability scenario with AFS‑3 for its local reliability selection (a point SDG&E explained in response to stakeholder questions about differences between AFS‑3 and AFS‑4).

Stakeholder review and next steps: Workshop participants were told the demand‑selection pathway includes the written comment period and the Aug. 1 Energy Division determination. The utilities said they will incorporate Energy Division guidance into the final materials that feed the August GNA deliverables. Stakeholders at the workshop were invited to comment on the demand‑selection letter during the June 19 window.

Context and caveats: Workshop presenters stressed that some aspects of the IPR and the CEC’s scenario modeling are not fully visible in the public datasets and that the utilities had asked the CEC for clarifications (for example, SDG&E reported the CEC explained a difference between AFS‑3 and AFS‑4 as related to electric‑resistance water‑heater assumptions). The Energy Division will resolve the final selection and any procedural questions in its August decision.","The three investor‑owned utilities submitted a joint demand‑selection letter on May 9, 2025, proposing which CEC IPR scenario components to use for the 2025–26 distribution planning cycle. Stakeholder comments are due June 19; Energy Division expects a decision Aug. 1 and the utilities expect the 2025 GNA/Jupyter deliverable Aug. 15.","actionData","errors"]

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Independent Planning Engineer outlines V&V scope; DPAD and post‑DPAG reports to follow utility filings

SDG&E and SCE use bottoms‑up approaches for medium‑ and heavy‑duty EV forecasts; SDG&E finds higher energy due to vehicle mileages

Utilities, Energy Division and stakeholders debate pending‑loads treatment and project risk; advice letters due this cycle

PG&E, SCE and SDG&E outline distribution forecasting methods: feeder disaggregation, EV energy reconciliation and new AAFS handling

Joint California utilities submit 2025–26 demand‑selection letter; Energy Division decision expected Aug. 1