California’s Distributed Energy Grid Plans: The Next Steps

Californias Distributed Energy Grid Plans: The Next Steps

After a year of behind-the-scenes work and much public debate, Californias big three investor-owned utilities turned in their long-awaited distribution resource plans (DRPs). Mandated by state law AB 327, these DRPs are essentially blueprints for how Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric are going to merge rooftop solar, behind-the-meter energy storage, plug-in electric vehicles and other distributed energy resources (DERs) into their day-to-day grid operations and long-range distribution grid planning and investment regimes.

A lot of work has gone into these plans, much of which had never before been done. Each California utility has created mapping tools that show how much capacity is available on each distribution circuit for new DER interconnection, for instance -- something that could be very useful for distributed energy developers.

All three utilities have also agreed on a common set of measures for how DERs could help shore up grid capacity, increase reliability, serve system-wide needs, and otherwise stand in for costly utility upgrades. And each has laid out how it plans to fold these DRP methodologies into their general rate cases (GRCs), the once-every-three-years process that determines how much each can charge its customers for its capital and operating costs for the coming years.

But when it comes to actually turning these software tools and financial guidelines into real-world DER-grid integration, the hard work has just begun. Many questions remain about how to determine which combination of DERs will meet the least-cost models that utilities use to rank their distribution grid upgrades, and what kinds of new capabilities grid-supporting DERs will need to have to serve as replacements for utility investments.

Theres also much uncertainty about how DERs serving as stand-ins for grid infrastructure should be paid for, and how their costs and benefits should be shared. As Patrick Hogan, PG&E vice president of asset management, said in an interview last week, We need to make sure that as we have more DERs entering the system, that weve really thought through how each of the customers out there are paying for their part of the grid, if you will.

These issues are of major interest for solar-storage combinations from SolarCity and Tesla, SunEdison and Green Charge Networks, Sungevity and Sonnenbatterie, and SunPower and partners Stem and Sunverge, which see an opportunity for earning grid services revenues as stand-ins for distribution grid investments. Theyre also important for the commercial building and residential energy management platform providers looking for ways to tap Californias emerging opportunities for distributed demand response.

But these costs and values wouldnt just flow from utilities and their customers to DER providers. Each utilitys DRP asks the California Public Utilities Commission (CPUC) for permission to spend lots of money on beefing up their own systems to enable their visions. Southern California Edison alone is estimating its DRP-related capital expenditures could add up to $347 million to $560 million over the next three years, for example, and PG&E and SDG&E will also be seeking new funding, though they havent yet specified how much.

 All three DRPs add up to nearly 1,000 pages, which makes it hard to summarize all the next steps they contain. But here are a few highlights of the challenges to come.
From static and passive to dynamic and DERMS-enabled

Todays distribution grid planning presumes the one-way flow of electricity from substations to end customers with fairly predictable consumption patterns -- low at night, rising in the morning, falling slightly at midday, and rising to a peak in late afternoon or early evening. But a world of DERs will be far more dynamic -- and that requires a more dynamic way to model and manage their impact.

For instance, at PG&E, We have to figure out what some of the impacts are to our transmission system, in terms of reliability and energy, Hogan said. Even the impacts of distribution switching need to be evaluated. On a minute-by-minute basis, things happen on the system as utility operators open and close switches and reroute power from one part of the grid to another.

In that sense, the circuit-by-circuit DER penetration maps that Californias utilities have built are almost creating a theoretical max, if you will, and recognizing that things like switching and transmission constraints will cause other impacts, he said. That means that, while the new mapping tools will help developers make some early decisions about where to target DERs, folks are still going to have to follow our processes in terms of making an interconnection. Even though youre breaking down 5,000 feeders into five sections, depending on section, on wire size and transformers, you may have some constraints that dont show up in the static models.

Source: Greentech Grid

Smart Grid Bulletin February 2019

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