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DPU outlines reliability projects, sensor and SCADA upgrades; warns of rising replacement costs
Summary
DPU electric operations manager Steve Barras briefed the board on distribution configuration, recent outages, a planned "last station" project to split major feeders for redundancy, SCADA and line-sensor upgrades and a long-term replacement need that could total tens of millions over the next decade.
Distribution system manager Steve Barras presented the department's annual electric reliability update to the Board of Public Utilities on April 2, describing the county's feeder configuration, recent outage causes and a set of near-term and long-term projects aimed at improving redundancy and outage response.
Barras reviewed the townsite and White Rock feeder arrangements, noting TA3 is the primary substation for townsite service and that several feeders can be cross-fed for restoration. He said recent outages included an underground fault on Los Pueblos that left about 600 customers without power for several hours before crews located and repaired the fault, and a separate incident where a contractor's heavy equipment struck a three-phase primary in the ice-rink construction area.
Barras said the utility will install additional line sensors, add three-phase reclosers and acquire a new SCADA system (Schweitzer/Artec components) to provide centralized visibility. "This will assist our linemen also with the AMI system. They can see outages, where the meters are out," he said, adding that better real-time data should speed response and reduce outage duration.
A major near-term project is the so-called "last station" that will reconfigure feeders (breaking feeders 13, 15 and 16 into smaller pieces) and add new feeder circuits (s6, sm6, s18 and s3) to provide more redundancy and capacity. Barras said the reconfiguration will make back-feeding safer and reduce simultaneous feeder exposure during faults.
On long-term costs, Barras warned of rising procurement and construction prices: single-phase transformers can face year-long lead times, three-phase transformers can be constrained, and conduit and construction costs have climbed. He estimated an aggressive 10-year replacement and upgrade program could require roughly $30 million and equate to about $25—$30 per month per customer in revenue needs, a figure he presented as a planning-level estimate to illustrate scale.
Barras said the department will continue root-cause analyses for outages, maintain pole inspections and coordinate pole-attachment assessments in advance of the county broadband project. He described safety precautions for a planned manhole/asbestos mitigation work on the Duck Bank conduit and said crews will use ventilation, sensors and an asbestos contractor before conduit work begins.
Why it matters: The projects Barras described are intended to improve reliability as electrification increases local load. Investments in SCADA, sensors and feeder reconfiguration should reduce overall outage minutes and increase operator situational awareness, but the work will require capital and long lead-time procurement.
Next steps: Barras said the DPU will install the next set of reclosers and sensors, complete design work for the last station, begin bids for several subdivisions and continue the phased asset-management program. He recommended continued budgeting for transformer and underground-cable replacement in light of rising construction costs.
