If falling costs for renewable energy and batteries and rising carbon-reduction mandates are any indication, hybrid resources are going to be a key part of the future power grid. In vanguard markets like California, hybrids — battery-backed solar, primarily — are expected to be the dominant grid resource as soon as a decade from now.
But integrating hybrid resources into energy markets that were designed around fossil-fueled power plants and standalone renewables, and are just beginning to come to terms with batteries as a primary resource, is a complicated task. The regional transmission organizations (RTOs) and independent system operators (ISOs) that manage the bulk electricity markets serving about two-thirds of the country are taking on this challenge in very different ways and at different speeds.
Some of them are proposing rules that project developers fear will undermine hybrid projects’ value and limit their growth. And some industry participants say it might be better to shift the complexity of integrating hybrid resources from the ISOs and RTOs to hybrid project operators themselves.
That’s a summary of the hybrid-related conversations taking place at technical conferences and regulatory proceedings across the country. Back in July, the Federal Energy Regulatory Commission (FERC) held a technical conference that gave ISO and RTO representatives a chance to meet clean-energy and hybrid developers’ concerns head-on.
Growing hybrid queues and benefits on both sides of the equation
The first point raised at FERC’s conference is that hybrids are a growing share of the grid’s new grid capacity. As of the end of 2019, 125 hybrid projects with 13.4 gigawatts of generation and just under 1 gigawatt of storage were operating, according to a new study from Lawrence Berkeley National Laboratory. But those numbers are set to mushroom in the years to come, report author Will Gorman said — particularly in California, where utilities are turning to battery-backed solar to meet pressing grid reliability shortfalls, but increasingly across the West and Midwest as well.
Storage is included in two-thirds of all new solar and one-half of all new wind resources in the interconnection queue of grid operator CAISO, according to Lawrence Berkeley National Laboratory. Of the 68,188 MW of renewable capacity and 69,193 MW of energy storage in CAISO’s queue, the share of hybrid-connected storage is expected to grow from 162 MW this year to 2,419 MW in 2021 and 3,681 MW in 2022, Deb LeVine, CAISO’s director of infrastructure contracts and management, said at the FERC conference.
Hawaii, Nevada, Colorado and Texas also have large-scale hybrid solar-storage being built, and Pacific Northwest and Rocky Mountain state utility PacifiCorp is seeking additional gigawatts. The queues of Midwest grid operators Southwest Power Pool and Midcontinent Independent System Operator also have a small but significant share of battery-backed solar in their interconnection queues, and to a much lesser extent, wind-battery hybrids. Major developers including EDF Renewables, Enel, NextEra Energy, 8Minute Solar Energy and many others are increasingly combining renewables and batteries in multiple markets.
There are clear reasons for this, as a 2019 paper from Grid Strategies’ Rob Gramlich and Michael Goggin and Energy Storage Association policy director Jason Burwen points out. Beyond falling prices for both solar and batteries, combining both behind a single grid interconnection is cheaper and faster than interconnecting them separately. And at least for the next four years, the federal Investment Tax Credit (ITC) allows batteries that primarily charge from associated solar panels to receive the same credits, boosting the economic case for combining them.
Hybrids also bring grid benefits. Batteries can store and shift renewable output to stabilize its intermittency, provide capacity during hours of peak grid demand, and respond to changing grid conditions more flexibly than can traditional generators, which take time to ramp output up and down.
“Power market designers and regulators have attempted to provide that flexibility to individual market participants,” the paper points out. But despite these efforts, “a legacy of centralized control remains in RTOs/ISOs that reduces market efficiencies.”
Disconnects at the interconnection level
A recent paper from the American Wind Energy Association (AWEA) describes some of these market inefficiencies, starting with the interconnection processes that are key make-or-break points for new projects.
Interconnection problems range from rules that force renewable projects seeking to add batteries to resubmit applications for interconnection queues — a step that could add months or years to project timelines — to interconnection study methods that presume that hybrid systems will overwhelm the capacity of their grid connection through illogical actions, such as charging from the grid during system peaks.
“RTOs are having a little bit of a hard time studying how these resources will operate,” Adam Stern, AWEA’s research and analytics manager, explained in an interview last month. But that shouldn’t lead to assumptions that hybrids will tap the grid when power prices are at their highest, particularly when they’re bound by ITC regulations to charge from their self-generated solar power. “That’s just not economic, and it won’t happen.”
CAISO, which is under more pressure than most grid operators to integrate hybrids, allows developers adding batteries to submit a “material modification” rather than resubmitting projects to its queue, LeVine explained at the FERC conference. That doesn’t let projects increase their point of interconnection maximum or the amount of energy they can transmit to the grid. But CAISO plans to use congestion management to mitigate any overloads that could arise from out-of-the-ordinary operations like batteries charging from the grid, she said.
This makes CAISO’s “material modification” process far less onerous than those of other grid operators so far, according to Susan Schneider, a former CAISO vice president and now principal at Phoenix Consulting. Even so, combining renewables and storage behind a single point of interconnection does carry complications, she said.
For example, until recently, CAISO rules split up the output capacity of “co-located” solar-storage projects — those in which the solar and the batteries are operated as two distinct units — in ways that could limit the amount of either resource that could be sent to the grid at any moment of time.
In other words, 100 MW of solar and 100 MW of battery capacity behind a 100 MW interconnection point might have each resource artificially capped at 50 MW apiece, she explained. But that could prevent the full battery capacity from being available to the grid after the sun goes down or the full solar capacity from being dispatched during peak solar production hours.
CAISO has recently changed this with a software fix instituting an “aggregate capability constraint” that will free up either resource to provide their full output up to the interconnection point’s limit, she noted. Given the cost of reprogramming the legacy software running grid operator markets, “That's a big deal,” she said.
Hybrid vs. co-located projects and capacity complications
It’s important to note that these “co-located” projects are distinct from “hybrid resources” that combine solar and batteries as a single resource, Schneider added. The latter has more flexibility in terms of how they’re dispatched by CAISO’s software.
But until recently, most of the new solar-battery systems being interconnected in CAISO were choosing the co-located configuration, she said. That’s because of another challenge for hybrid systems: calculating their value as grid capacity.
“Capacity value is going to be a big part of the value of these projects,” AWEA’s Stern said. "Calculating the value that a resource provides is going to be critical.” But the novelty of solar-charged battery systems makes for a complicated set of capacity calculations, as California’s experience indicates.
Until a recent change to the California Public Utilities Commission’s resource-adequacy rules — the state’s version of a capacity construct — the capacity of a “hybrid” solar-storage system was set at either the maximum of its solar output or the maximum of its storage output, Schneider explained. But that undercounts the combined solar and battery output that a hybrid can provide during peak hours. As a result, many developers chose co-located configurations instead, she said.
CPUC’s new rules allow hybrids to calculate their resource-adequacy value as a combination of their output, as long as the batteries are charged at least two hours before peak hours begin, to assure they’re not cannibalizing solar output to charge up. This is yet another example of how “energy-limited” resources like batteries must be treated differently than fossil-fueled generators.
A similar disconnect arises with the concept of “must-offer obligations,” or grid operator rules that force capacity resources to commit their maximum power output during peak grid demand hours. Must-offer obligations work for fossil plants, but they could force batteries to discharge too much of their stored energy too early when saving it for later in the peak period would be more valuable.
As part of its Hybrid Resources Initiative, CAISO is working on must-offer obligation rules that account for hybrid resources’ unique characteristics. But that’s a work in progress, dependent on coordinating the CPUC’s new hybrid resource-adequacy valuations with how CAISO software manages that value in its day-to-day operations.
“There’s economics, and then there’s reliability,” Schneider said. “In a properly designed market, those two things should be well aligned. But CAISO has not had experience with any of this, and they’re just not there yet.”
Most industry observers agree that CAISO is further ahead of other RTOs and ISOs on this front, given its pressing need to create rules to manage its gigawatt-scale influx of hybrid solar-storage systems.
From grid operator controls to hybrids as "intelligent agents"
All of these market complications have led some industry participants to press for a different solution: treating hybrid resources just like a standard power plant, complete with bearing the risk of failing to perform to those expectations.
That’s how Mark Ahlstrom, vice president of renewable energy policy for NextEra Energy Resources and board president of the nonprofit Energy Systems Integration Group, believes hybrid resources can best tap their abilities.
“If I’m going to emulate anything, why don’t I emulate a really flexible conventional resource?” he said in an interview this week. “The advantage of that is that hopefully, the ISOs and RTOs don’t have to do any big software changes, which can take tens or hundreds of millions of dollars, given the way their legacy software is written.”
A 2019 paper Ahlstrom co-authored with other grid luminaries, including former CAISO market and infrastructure policy lead Lorenzo Kristov, describes this as an “intelligent agent” approach. It puts the burden on the hybrid system operators to manage its combination of generation, storage, power electronics and software controls to mimic a conventional fossil-fired or hydropower resource, but with more flexibility and fewer constraints to how quickly it can respond to grid needs.
That’s very different than the way grid operators now treat renewables or energy storage, which tend to be the starting points for how they plan for hybrids. For example, renewables are allowed to alter their forecasted output on a five-minute schedule to account for their intermittency. In other rare cases, grid operators allow “flexible solar plants” to curtail excess output to serve grid needs.
Hybrids come with storage capacity that can eliminate these five-minute fluctuations, Ahlstrom said. But hybrids can also tap that five-minute ahead flexibility to help grid operators meet unexpected needs. That’s something that CAISO’s latest hybrid plan will allow, and it’s a good example of tapping the flexibility of a hybrid resource for a positive end, he said.
Hybrids could also have more excess solar capacity beyond their interconnection limit than is economically feasible today, he said, since the batteries could store that excess power and save it for when the grid needs it. That could help California meet the challenges it faced last month, when it was forced to institute rolling blackouts during evening “net peak” hours, when solar output is fading to nothing.
All of this makes an intelligent agent hybrid “really simple from the system operator perspective,” he said. But “it becomes very complicated from the point of view of the market participant,” since failing to orchestrate its capabilities could lead to failure to meet market rules, financial penalties, and other risks.
It’s not clear that every hybrid project out there would be well suited to taking on this level of operational control and subsequent risk. Schneider noted that some of the hybrid and co-located systems in California today are split up among multiple power-purchase agreement counterparties and different operators, which may make coordination behind the point of interconnection more challenging.
“You can see how the ISO needs to make sure these things are going to work [so as] not to screw up the ISO,” she said.
With all of these variables at play, and each ISO and RTO coming up with its own solutions to them, hybrid developers are faced with a lot of uncertainty, AWEA’s Stern said. “What FERC was addressing with the technical conference was getting RTOs on the same page,” he said, “with policies and procedures on how they’re going to help hybrids integrate with their systems.”
FERC Order 841 has taken that approach with energy storage, but that long-running process doesn’t specifically deal with hybrids, he noted. Many industry participants have suggested that FERC needs to create a new proceeding to cover that oversight.
With so many new hybrid systems being developed across the country, now is the time to get the rules right, Stern said. “At this point, there are no big stop signs or roadblocks that people are running into,” he said. But for projects that take careful coordination of financing and development parties, “uncertainty comes with a cost,” according to Stern.