Company: PCG-PB
Filing Date: 2025-02-13
Form Type: 10-K
Source: 0001004980-25-000010
Chunk: 95

Company: PG&E Corp
Filing Date: 2025-02-13
Form: 10-K
Item: Item 1
Chunk 95
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, the PSPS program has become more targeted through the use of more granular risk models, including incorporating more detailed data inputs.  The Utility has also installed sectionalizers for more targeted de-energizations of circuits and transmission lines.  These more targeted scoping criteria are engineered to reduce the number of customers impacted by any particular PSPS event.  In 2024, the Utility executed six PSPS events impacting a total of approximately 50,000 customers.

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•Vegetation management:  The Utility inspects its overhead electric distribution and transmission facilities on an annual basis to identify and clear vegetation that might grow or fall into utility equipment.  

•Asset inspections:  Since 2018, the Utility has reoriented its asset inspections programs toward asset condition and consequence risk, particularly wildfire risk, and these programs have become more thorough, standardized, digitized, and verifiable.  The Utility uses risk-informed inspection cycles.  In 2024, the Utility continued to refine its inspection techniques, transitioning to the use of aerial drones to perform inspections on circuits located in HFTD areas.  As a result of the improved inspection program, the Utility’s inspections in 2024 have further enhanced its ability to identify equipment conditions.

•System hardening:  System hardening entails repairing, replacing, or eliminating existing power lines in HFTD areas and installing stronger and more resilient equipment.  As the Utility’s asset inspections have identified less resilient equipment, the Utility has hardened its system by fixing significantly more equipment than in prior years.  Hardening methods also include replacing bare overhead conductor with covered conductor and installing stronger poles, removing lines, and serving customers through remote grids, or converting lines from overhead to underground.  The Utility has set a goal to underground 10,000 miles of electric distribution lines in high wildfire risk areas.  Undergrounding can substantially reduce ignition risk and improve reliability during storms or periods of high wildfire risk.  In 2024, the Utility undergrounded 259 miles of lines.  When feasible, remote grids can be a more cost-effective option to reduce fire risks by permanently disconnecting end-of-line customers from the grid and serving them with utility owned, locally sited resources.  The Utility brought online five additional remote grids in 2024, for a total of 11 remote grids overall. 

The Utility’s equipment was not involved in the ignition of any major wildfires in 2024.  The Utility experienced an increased number of CPUC-reportable ignitions in 2024