PG&E's 2026-2028 Wildfire Mitigation Plan, submitted to California's Office of Energy Infrastructure Safety, represents the utility's most technology-intensive grid modernization effort to date a genuinely dense combination of physical infrastructure hardening and IoT-driven monitoring aimed at reducing ignition risk across the sprawling Northern and Central California territory PG&E serves, San Jose and the broader Silicon Valley included. Understanding what's actually in this plan, and how it's already performing, matters for any San Jose business or property owner trying to understand where the region's electric grid reliability is actually headed.
PG&E plans to underground 1,077 miles of powerlines between 2026 and 2028 alone, building on a program that had already energized 1,000 miles of undergrounded lines by October 2025 a milestone the utility has credited with achieving roughly 98% wildfire risk reduction on the specific line segments converted. Beyond undergrounding, the plan calls for more than 700 miles of overhead hardening and line removal paired with remote grids through the same 2026-2028 window, using covered conductor, strengthened poles, and wider crossarms to reduce ignition risk on lines that remain above ground. A newer inspection tool, aerial span inspection using drones, is being piloted specifically to catch equipment risk conditions in the mid-span sections between poles that traditional pole-by-pole inspection can miss building on drone inspections that already covered 220,000 poles in 2024 alone.
PG&E's continuous monitoring infrastructure has reached a genuinely significant scale: more than 1,600 weather stations and over 600 high-definition cameras with AI capability, providing both improved weather forecasting for wildfire risk modeling and early visual detection of developing fire activity across the utility's territory. The plan specifically calls for installing sensors capable of detecting vibrations, sounds, and light that could indicate an anomaly on an electric circuit serious enough to cause an ignition a genuinely different, more granular layer of monitoring than weather stations and cameras alone provide, aimed at catching an equipment-level problem before it produces any visible fire activity at all.
Enhanced Powerline Safety Settings, PG&E's program for automatically de-energizing a circuit almost instantly when a fault is detected, now protects 1.8 million customers living in areas of elevated or extreme wildfire risk. In 2024, EPSS contributed to a reduction of more than 72% in CPUC-reportable ignitions on primary distribution lines where enabled, compared to the 2018-2020 baseline average and notably, more than half of customers protected by EPSS didn't experience any power outage at all while the setting was active during that period, addressing one of the more common criticisms of aggressive automated shutoff systems, which is that they trade wildfire risk reduction for a meaningfully worse customer outage experience.
In January 2026, PG&E launched EMBERPOINT alongside Lockheed Martin, Salesforce, and Wells Fargo a genuinely unusual multi-industry partnership aimed at transforming wildfire prevention, detection, and response technology, bringing together aerospace and defense sensing expertise, enterprise data platform capability, and financial sector risk modeling alongside PG&E's own grid operations knowledge. While the specifics of what each partner contributes technically are still emerging, the partnership itself signals something worth noting: wildfire mitigation has grown complex and technically demanding enough that even a utility of PG&E's scale is now actively recruiting expertise from entirely different industries rather than attempting to build every needed capability internally or through traditional utility vendor relationships alone.
PG&E has also stood up what it describes as a first-of-its-kind wildfire monitoring center, consolidating the continuous data streams from weather stations, cameras, and circuit-level sensors into a centralized operational hub where trained staff can assess developing risk across the entire service territory in real time rather than monitoring individual data sources separately. This kind of centralized fusion center reflects a broader pattern across major utility wildfire mitigation programs the individual sensor technologies matter less in isolation than the operational capability to synthesize all of that data into fast, accurate decisions about where to focus limited response resources on any given high-risk day.
San Jose and the broader South Bay sit at a somewhat lower baseline wildfire risk than PG&E's most fire-prone Sierra foothill and North Bay territories, but the utility's grid modernization investment still affects the region directly in a few ways. Silicon Valley's businesses and data centers depend on the same underlying grid reliability infrastructure this modernization program is designed to protect, and EPSS-related outages, even when relatively brief, carry real cost for businesses running continuous operations. San Jose's growing data center and AI infrastructure demand, covered in more depth in this site's coverage of the region's office-to-data-center conversion trend, also means the underlying grid capacity and reliability questions this modernization program addresses matter increasingly to the local economy, not just to the wildfire-prone areas where the physical hardening work is most visibly concentrated.
PG&E's approach shares clear structural similarities with the wildfire-driven grid modernization programs pursued by California's other major investor-owned utilities, including San Diego Gas & Electric's own risk-modeling and undergrounding program covered elsewhere on this site. All three of the state's major utilities operate under the same California wildfire mitigation plan regulatory framework, and all have converged on a broadly similar technology stack weather stations, AI-enabled cameras, undergrounding prioritized by quantified risk, and automated fault-response systems. What differs more between utilities is scale and specific territory risk profile: PG&E's Northern and Central California footprint includes considerably more high-risk wildland-urban interface area than SDG&E's more compact Southern California territory, which is part of why PG&E's absolute mileage and sensor counts run so much higher, even though the underlying technology approach across California's major utilities has become genuinely convergent.
None of this infrastructure investment is free, and it's worth being direct about the tradeoff: wildfire mitigation spending has become one of the largest and fastest-growing components of what PG&E customers pay across the utility's entire territory, San Jose included, even though the most intensive physical hardening work concentrates in higher-risk areas elsewhere in PG&E's service territory. California's Public Advocates Office continues tracking this spending on behalf of ratepayers, and the fundamental tension remains consistent across every major California utility pursuing similar wildfire mitigation programs: the sensor networks, undergrounding, and AI-driven monitoring genuinely reduce wildfire risk, but the bill for that risk reduction is spread across the utility's full customer base, including San Jose businesses and residents who may never experience a wildfire directly but still pay to fund the infrastructure protecting the parts of PG&E's territory that face genuine, elevated risk.
For a San Jose business evaluating its own resilience planning against this backdrop, a few practical considerations follow directly from PG&E's published wildfire mitigation approach. Businesses in or near designated elevated or extreme wildfire risk areas should confirm whether their specific circuits are enrolled in EPSS, since that status directly affects both wildfire protection and the practical likelihood of an automated safety shutoff during high-risk weather conditions. Businesses running continuous or safety-critical operations should treat PG&E's published wildfire mitigation plan documents, updated on a recurring cycle, as a genuine planning input rather than background utility news the specific undergrounding and hardening timeline for a given circuit or substation can meaningfully affect a business's own backup power and continuity planning decisions over a multi-year horizon.
Frequently asked questions
PG&E plans to underground 1,077 additional miles of powerlines between 2026 and 2028, building on 1,000 miles already energized underground as of October 2025.
It's PG&E's program for automatically de-energizing a circuit almost instantly when a fault is detected, currently protecting 1.8 million customers in elevated or extreme wildfire risk areas, contributing to a more than 72% reduction in reportable ignitions where enabled.
A partnership launched in January 2026 between PG&E, Lockheed Martin, Salesforce, and Wells Fargo aimed at advancing wildfire prevention, detection, and response technology, combining expertise from aerospace, enterprise data, and financial risk modeling.
PG&E reports approximately 98% wildfire risk reduction on line segments that have been moved underground, based on its own performance tracking of completed undergrounding projects.
No. San Jose and the broader South Bay generally sit at a lower baseline wildfire risk than PG&E's most fire-prone Sierra foothill and North Bay service areas, though the region still depends on and helps fund the same overall grid modernization program.
PG&E has installed more than 1,600 weather stations and over 600 AI-enabled high-definition cameras across its service territory to support wildfire risk monitoring and early detection.
Related articles
Smart Utilities
