How can U.S. transmission grids and wholesale energy markets adapt to the gigawatts of energy storage coming online over the next decade?
In the near future, the scale of the batteries serving U.S. power grids is set to explode, increasing from about 1.5 gigawatts today to tens or hundreds of gigawatts by 2030. These batteries will play a vital role in shifting intermittent wind and solar power from when it’s produced to when it’s needed and serving broader grid services needs on an increasingly decarbonizing grid.
But as a resource that can both absorb and discharge energy at a moment’s notice, batteries are very different from both dispatchable generators and intermittent wind and solar farms. That requires new technical and economic systems for managing and valuing them — and the grid operators that run wholesale electricity markets serving about two-thirds of the country are struggling to make those changes to keep up with the pace of growth.
That’s one of the key takeaways from last week’s Energy Storage Association policy forum, where representatives of the country’s regional transmission organizations (RTOs) and independent system operators (ISOs) joined storage industry groups and regulators to describe their work on energy storage integration.
Richard Glick, the newly named chair of the Federal Energy Regulatory Commission, which regulates ISOs and RTOs, noted that storage is one of several new technologies facing barriers to full market participation that FERC is trying to eliminate.
“I think the commission has done a pretty good job on that over the past half-decade or so,” the Democrat said. FERC Order 841 has led to major new opportunities for energy storage to participate in wholesale energy, capacity and ancillary services markets, albeit at different paces and in different ways across ISOs and RTOs. FERC Order 2222 sets a similar path for distributed energy resources, including aggregated batteries.
At the same time, “renewable energy generators see storage as a very important partner,” he said, as wind and solar projects add batteries to firm and shift their power output to meet grid demands. These hybrid resources now make up about two-thirds of all solar projects in the interconnection queue of California grid operator CAISO and constitute a rising share of clean energy projects across other markets. Developers including EDF Renewables, Enel, NextEra Energy, LS Power and many others are increasingly combining renewables and batteries in multiple states.
Gregory Cook, California ISO’s executive director of market and infrastructure, highlighted the work underway to integrate these novel combinations into its interconnection and market structures. CAISO expects its roughly 550 megawatts of energy storage will rise to 1,750 MW by this summer and to 3,300 MW in the next few years.
California’s rolling blackouts last August has led state regulators to push to accelerate battery deployments, and “much of that new storage is going to be in the form of hybrid resources, where we’re seeing storage added to existing solar sites.” Beyond allowing multiple resources to connect at a single point, pairing batteries with solar allows them to access federal tax credits that are, as yet, unavailable to standalone storage.
Other ISOs are seeing similar patterns, if at lower volumes. Manu Asthana, CEO of mid-Atlantic grid operator PJM, noted that of the 145 gigawatts of generation in its interconnection queue, 92 percent is solar, wind, batteries or hybrid resources. That includes about 15 GW of standalone storage and another 18 GW of hybrid storage.
Renuka Chatterjee, executive director of system operations for the Midcontinent Independent System Operator, reported about 4 GW of standalone storage and 5 GW of hybrid resources, much of it linked to solar. Bruce Rew, senior vice president of operations for the Southwest Power Pool, cited about 6 GW of hybrid storage and 3 GW of standalone batteries.
Storage and hybrid hangups, from interconnection to market valuation
But renewable and storage developers are running into problems with how grid operators’ interconnection and market rules manage hybrids. FERC’s technical conference on hybrid resources last summer raised “significant and substantial concerns,” he said, adding, “we’re going to take a serious and…long look at the responses we received.”
The root of these problems, according to a 2019 paper from Grid Strategies’ Rob Gramlich and Michael Goggin and Energy Storage Association interim CEO Jason Burwen, “is that present market rules will represent them as deviations from existing resource types.”
That approach ends up shoehorning hybrids into market rules that treat them as a “variable generator,” or in other words, a solar and wind farm “that is also dispatchable, or as a storage resource that has onsite fuel.” Either choice ends up misapplying interconnection and market concepts that would better be managed by creating a separate hybrid category to deal with them, they argue.
For example, some ISOs and RTOs require renewable projects seeking to add batteries to resubmit interconnection applications, which can push them behind in already long and difficult-to-navigate interconnection queues.
Others may presume that renewables and storage will simultaneously inject power at levels that would cause reliability problems at their interconnection site, even though project operators would have no economic incentive to do that and could easily control their systems to avoid it.
On the market disconnect front, hybrids and standalone storage systems can be subjected to rules that require them to submit to grid operator dispatches that may limit their ability to optimize their economic value. Examples include rules that force batteries to retain minimum states of charge, which are meant to assure they’ll be available at full capacity when dispatched but which developers say constrain their freedom to optimize their storage capacity.
ISOs are taking steps to resolve these disconnects. CAISO allows solar projects adding batteries to submit a “material modification” rather than resubmitting projects to its queue. Its Hybrid Resources Initiative is developing state-of-charge parameters that offer more flexibility, as well as an option for projects to manage the combined dispatch of renewables and storage, both expected to be finalized later this year, Cook said.
The Midcontinent Independent System Operator is developing a similar Surplus Interconnection Service to ease adding batteries to wind and solar projects, Chatterjee said. And New York state grid operator NYISO has developed rules for energy storage to participate in both wholesale energy markets and to provide services to utilities as part of its August implementation of Order 841, according to Michael DeSocio, director of market design.
“Market power mitigation” rules, designed to prevent power plant owners from using their relatively high concentration of resources in an ISO’s footprint to act in ways that shift prices in uncompetitive ways, can also be improperly applied to batteries that make up a fraction of today’s markets, developers argue.
These complications have been compounded by several orders passed by FERC’s Republican majority under the Trump administration that have applied these market mitigation structures on state-subsidized resources, including batteries, in ways that have limited their ability to compete in capacity markets in PJM’s 13-state territory and in downstate sections of NYISO’s grid.
Glick, who voted against these decisions, repeated his previously stated view that they are likely to be overturned by legal challenges. But he also noted that ISO and RTO stakeholders are working on market reform proposals that will need to account not just for resolving conflicts between state and federal jurisdiction over energy policy but also for finding ways to accommodate the shifting mix of resources that supply them.
“Our role is to make sure whatever market rules there are don’t act as barriers,” he said.