California is already hosting several of pilot programs to evaluate how distributed energy resources can help utilities at the level of their sprawling, low-voltage distribution grids. Now, the state is exploring how local clean energy resources can support reliability at the transmission level too.
On Wednesday, Pacific Gas & Electric and California grid operator CAISO unveiled a plan that seeks to proactively deploy DERs -- including solar, batteries, smart thermostats and other passive or active energy assets on the grid edge -- as an alternative to fossil fuel generation and transmission-scale infrastructure.
In a first-of-a-kind agreement, PG&E and CAISO will seek over the next five years to contract for enough DERs to replace an aging power plant in Oakland, Calif., without building new transmission lines that would otherwise be needed to keep the entire state’s grid running reliably.
Wednesday’s press conference in Oakland focused on the local clean energy jobs and economic opportunities to come from the project, as well as its innovative structure, which will see PG&E contract for between 20 and 40 megawatts of DERs under a request for proposals (RFP) process, slated to start after CAISO finalizes its own transmission investment plans in March.
PG&E hasn’t put a dollar value on the project, or how much it intends to pay for the DERs it will procure, since it’s hopping to receive a range of competitive bids. But several speakers at Wednesday’s event, including California state Assemblyman Rob Bonta, noted that the plan involved $40 million to be invested in local clean energy.
This isn’t the first big DER investment by a California utility. Southern California Edison and San Diego Gas & Electric have collectively contracted for hundreds of megawatts of solar, storage, demand response and efficiency as part of their plans to replace the San Onofre nuclear power plant. SCE recently announced another DER procurement to help it mitigate reliability issues in the Santa Barbara region. And all three investor-owned utilities have started pilot projects under the California Public Utilities Commission’s distribution resources plan (DRP) proceeding, meant to integrate DERs into how utilities maintain and upgrade their distribution grids.
But this is the first time CAISO has put its trust in distributed energy to cover the reliability needs of its entire system. CAISO’s reliability concerns in the area are based on one key linchpin -- a 168-megawatt, diesel-fired power plant in gritty West Oakland. This power plant only runs about 35 days per year, and owner Dynegy has been trying to sell it for years. But when it is running, CAISO really needs it to be running, Tom Doughty, CAISO’a vice president of customer and state affairs, said at Wednesday’s press event.
That’s because when it’s fired up under its must-run reliability (MRR) contractual obligations, it’s running to prevent a so-called “n-minus-one” event -- a sudden outage, a generator going offline, or other unpredictable yet inevitable contingency -- from sending the statewide system into instability, he said.
U.S. grid operators spend hundreds of millions of dollars per year on transmission system upgrades and extensions to manage these kinds of problems. And they’re understandably leery of alternatives, given that plans made today affect grid reliability more than half a decade in the future.
But in the year since PG&E first brought its proposal to CAISO, the two have come to an understanding on how to put DERs in play in an alternative solution, to do “things that have never been done before,” he said.
CAISO doesn’t have much visibility into what’s happening past the transmission substations, known as the T-D interface. For instance, it still measures rooftop solar PV’s input as a reduction in system-wide demand, not as generation. That’s why it’s relying on PG&E to provide distributed energy resources that are reliable enough to serve its needs, he said.
“We choose the provider, the party that’s going to do the work," said Doughty. "We don’t procure -- PG&E does the procurement.”
Olya Anguelov, PG&E principal product manager for grid integration, declined to say how much the utility expects to spend on DER procurement for the Oakland project. But she did note that it’s expected to be significantly less than an alternative plan to build two new transmission lines, which would have cost $300 million and $280 million respectively.
PG&E’s plan has the backing of local labor and environmental groups, including the Rocky Mountain Institute, which first floated the plan for a clean DER replacement scheme for the Dynegy plant in a report early this year.
PG&E will also invest in upgrading its own transmission substations serving the area, sectionalizing breakers and otherwise increasing redundancy and resilience, she said. But it’s leaving between 20 and 40 megawatts of capacity -- or about 120 megawatt-hours, spread across a 12-hour period during key days -- to be filled by DERs.
PG&E wants to own part of the new infrastructure, in the form of a 10-megawatt, 40 megawatt-hour battery system to be under CAISO’s control, she said. But it’s also seeking a range of resources to build into a portfolio that, taken together, can “provide equivalent reliability to that Dynegy can provide,” starting in 2022.
Many steps remain before PG&E can issue its RFP, she noted. Presuming that CAISO approves the plan as part of its TPP in March, the utility will take its proposal to the CPUC to seek cost recovery for its investments, which could take another year, she said.
CAISO has some experience in aggregating DERs to serve in its energy markets, through its Distributed Energy Resource Provider (DERP) program. While only a handful of aggregators are bidding into the market at present, those participants have provided CAISO with useful information it will be building into its ongoing assessment of PG&E’s efforts, Doughty said.
CAISO is also looking at other DER alternatives being proposed in lieu of building the Puente gas-fired power plant in Southern California, he noted. One of the key issues still to be addressed is how to balance local grid constraints with transmission system needs, he noted.