The threat of power grid-sparked wildfires is forcing California utilities to invest billions of dollars in hardening and monitoring their grids and to institute grid blackouts affecting up to hundreds of thousands of customers to reduce the risk of live wires sparking conflagrations.
In some isolated cases, the cost of making remote powerlines safe from fires may not be worth it — if the customers served by them could make do with an on-site power option instead.
That’s the idea behind Pacific Gas & Electric’s ‘Remote Grid Initiative.’ It’s one of a long series of microgrid enablement plans being proposed by the Northern California utility, which is under tight scrutiny for its neglect of grid maintenance that led to the state’s deadliest wildfire to date and its subsequent bankruptcy. PG&E has also engaged in the most widespread power outages to prevent more fires over the past two years.
But unlike the grid-integrated backup power systems being explored by PG&E and the state’s other investor-owned utilities, the remote grid initiative would do away entirely with power lines, and replace them with stand-alone solar, batteries and generators.
This could only be cost-effective for a very small number of customers served by a relatively long section of power line crossing high fire-threat terrain. But in those rare circumstances, a utility-owned and rate-based on-site power option could not only be safer and more reliable for that pocket of customers, but less expensive than the alternative for PG&E’s customers at large.
That’s because the costs of hardening high-risk power lines, replacing them after they’re taken down by high winds or storms, or even maintaining them over their decades-long lifespan may well end up being higher than the cost of installing and maintaining the remote power systems that replace them, Quinn Nakayama, PG&E’s director of integrated grid planning and innovation, explained in a January interview.
“You’re taking a look at a long line that would need to be rebuilt over a certain period of time,” he said. “You factor in all those costs — vegetation costs, patrols and inspections, general outages — and you can get a sense of how much that line costs on a 40-year basis. Then you can think about how many customers are on that line, and do some kind of cost-benefit analysis.”
How remote microgrids could pencil out
The cost of buying power to cover the costs of an on-site solar, battery and generator array would be much higher than the cost of electricity service from an existing power line, he noted. But if PG&E can capitalize the cost of that on-site system as an alternative to even more expensive grid investments, it can offer those customers a rate plan commensurate with what they’d normally be paying.
“A general bill from a customer would never make it pencil,” Nakawama said. “But now that it’s backed by a certain project in our portfolio, it completely makes sense.”
This approach also classifies the on-site power system as a distribution asset, rather than as a generation asset, which avoids complications involved with regulations limiting the expansion of utility-owned generation, he noted. The systems would serve only a handful of customers with no more than 20 kilowatts of load in total, which also helps limit potential sites to those small enough to be served by a relatively small-scale solar array.
PG&E’s proposal before the California Public Utilities Commission would begin with replacing three power lines serving two locations, one in the Sierra Nevada foothills and one in the Carrizo Plain region of central California. But the utility has four to eight projects it could invest up to $6.5 million in this year — and it has identified several hundred more sites that could be suitable for similar treatment, Nakayama said.
This approach won’t work for anything but the smallest sites, given the relatively high costs of installing enough solar PV, batteries and generators to serve 24/7/365 loads compared to supplying electricity from the grid. It also requires a new tariff structure to manage the unusual circumstances involved, such as provisions for how rates may be affected if customers add big new loads like electric vehicles that the on-site system wasn’t designed to handle.
The limits to remote microgrids and alternative structures
Backing up communities for hours or days at a time during fire-prevention power outages will require a different mix of technologies that can also serve cost-effectively during the vast majority of the time that the grid is up and running. They’ll also need regulatory structures to share the costs and benefits of those systems between utilities, private microgrid developers and the communities they serve.
PG&E and the state’s other investor-owned utilities are in the midst of developing a $200 million program to support community microgrids to serve these needs, although that effort will be years in development.
Right now, PG&E is using hundreds of megawatts of mobile diesel generators that can be moved from location to location during its widespread fire-prevention blackouts, fueled with hydrogenated vegetable oil to reduce the worst aspects of their emissions, he said.
PG&E is planning to use propane-fueled generators for its remote grid installations, to ensure that they’ll have a low-cost and commonly available fuel supply for their round-the-clock operations, Nakayama said. But as the cost of solar and batteries continues to decline, and as alternatives to fossil fuels become more cost-effective, it’s possible that cleaner alternatives could replace them to align their growth with California’s aggressive decarbonization goals, he said.
These same technologies and economic imperatives should make grid-integrated microgrids more and more cost-effective in years to come, proponents say. State law directs the CPUC to create tariffs that support the commercialization of third-party microgrids, and developers have been demanding faster action to make them a more central part of the state’s efforts to secure its grid from the impacts of climate change, including increasing wildfire risk.
“As it does scale, I think there is a need for the policymakers to think about the different roles and responsibilities,” Ed Smeloff, director of grid integration at advocacy organization Vote Solar, said of PG&E’s remote grid plan. “There’s the possibility that you may have a better level of reliability with a remote microgrid than with a long line that’s subject to public safety power shutoff.”
Source: Greentech Media