Co-locating battery storage with renewables could transform the power system, and a rush by utilities and developers to build “hybrids” has prompted federal regulators to respond.
The U.S. boom in such projects has put over three times more hybrid capacity into development than the 4.6 GW now online and twelve times more in the pipeline, according to a new paper in Electricity Journal. But wind, solar, and battery storage developers are anxiously waiting for overdue regulatory decisions that could bring hybrids into wholesale markets.
“Renewable hybrids’ disruptive ability to provide low cost dispatchable clean energy make them the closest thing to a perfect resource we’ve ever thought of,” Aaron Bloom, System Planning Group Chair for power system consulting consortium Energy Systems Integration Group (ESIG), told Utility Dive. But regulators “seem to be applying traditional optimization rules to these new technologies and that might not be the best approach.”
Federal and regional regulators’ delayed decisions on the complexities of integrating and compensating paired technologies have not prevented the boom, the Electricity Journal paper showed. Utilities see hybrids as better than standalone storage to meet policy goals and developers see money on the table, they told Utility Dive. At advocates’ urging, FERC has called a technical conference for July to address questions about hybrids’ value.
Utility Dive in 2018 and 2019 found few utility-scale hybrid projects operating in the U.S. market. “It’s like the storm is brewing” but “hasn’t coalesced yet,” InterTran Energy Consulting Founding Principal Rhonda Peters told Utility Dive in 2019. It appears the storm has broken.
There are 61 renewables projects, at least 1 MW or higher, “co-located with batteries” online in the U.S., representing 4.6 GW of capacity, the paper reports. There are also 88 projects, representing 14.7 GW, “in the immediate development pipeline” and “69 GW in the seven main U.S. market interconnection queues.”
The “critical question” is whether the “conventional wisdom” in the power sector that storage and generation should each be optimally and independently sited is still true, Lawrence Berkeley National Laboratory (LBNL) Graduate Student Researcher and paper co-author Will Gorman told Utility Dive.
The current boom in hybrids implies either this conventional wisdom is wrong or there are some potentially inefficient incentives driving development, he said.
“For utilities that want both solar and storage, it is cost effective, especially where the utility can capture multiple values.”
A major driver of the boom is the value advantage of the 30% federal investment tax credit (ITC), which is available only to batteries charged at least 75% of the time from renewable energy, Gorman said. “Hybrid projects basically make the battery cheaper.”
But to qualify for the ITC, hybrid projects are likely to be sited at places where the sun or wind resources are greatest, which may limit their batteries’ service times and returns, the paper said.
There are “significant cost synergies” from co-location in reduced interconnection, transaction and construction costs, but they may not offset the costs of the ITC-related siting and operational constraints, Gorman said.
Solar plus storage hybrids can have total capital costs 8% lower than standalone batteries, the researchers found. But analysis of power purchase agreement (PPA) price data for six online solar hybrid projects showed higher costs than solar-only projects ranging from $4/MWh to $14/MWh depending on the region and storage capacity. That means hybrids’ value “definitely depend on wholesale market prices,” Gorman said.
In California power markets, solar or wind plus storage projects can be worth as much as $26/MWh to $29/MWh more than solar- or wind-only projects but only $5/MWh to $7/MWh more in Texas markets, the research showed. That makes the $4/MWh to $14/MWh higher cost for battery storage a good value proposition in California and a poor one in Texas.
Hybrids would need 2% to 11% higher value for the PPA price to justify adding storage, the researchers concluded. “If cost synergies do not exceed these levels, then investors may prefer standalone plants.”
The California results explain why “96% of PV and 75% of wind projects proposed in 2019 were hybrids,” Gorman said. Hybrid value is also greater in markets that compensate capacity that meets reliability needs at higher prices. “In California, about a third of the value was from the capacity price and the Texas value proposition was lower because we focused on years when capacity revenues were lower.”
This is one example of how “market rules and policy incentives can make or break the finances of a project,” Gorman said. The Federal Energy Regulatory Commission (FERC), and the Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) it regulates, are working to understand the value of hybrids and the challenges in bringing them into wholesale markets.
“Executives must do what’s right for ratepayers and shareholders, but they should also entertain the possibility that, despite the uncertainty, hybrids are a big opportunity and the technology will drive demand.”
System Planning Group Chair, Energy Systems Integration Group
FERC is interested in hearing about technical and market issues prompted by growing interest in hybrid projects, FERC spokesperson Craig Cano emailed Utility Dive.
ERCOT, CAISO and MISO have active stakeholder processes moving the integration of hybrid projects forward, ERCOT spokesperson Leslie Sopko, CAISO spokesperson Anne Gonzales and MISO spokesperson Allison Bermudez emailed Utility Dive. ERCOT is not subject to FERC regulation but the other two system operators welcome FERC’s upcoming technical conference, their spokespeople said.
The obstacles developers face are technical, but relate to rules for participation in wholesale markets. Battery storage is load when it is being charged and generation when it is discharging. Adjustments to market rules are needed to fully value the renewables generation and the stored generation. Special consideration may be needed to protect storage owners’ access to the ITC.
“Regulatory uncertainty may impact whether the hybrids trend continues,” Gorman said. But, as the system operators’ processes demonstrate, mandates and customer demand will continue to drive renewables growth, developers will add storage to provide flexibility for managing those renewables, and “utilities need to recognize what is coming.”
That is happening, utilities and developers told Utility Dive.
Reports from builders
In 2015, NextEra CEO Jim Robo predicted solar plus storage would begin replacing natural gas peakers by 2020. In February 2018, Arizona Public Service (APS) announced a 15-year contract with First Solar for a 65 MW solar-50 MW battery project to go online in 2021 “for peaking capacity.”
Until recently, the cost for storage discouraged utilities, “but that cost has come down,” REPlantSolutions CEO Mahesh Morjaria, who recently left First Solar, told Utility Dive. “For utilities that want both solar and storage, it is cost effective, especially where the utility can capture multiple values.”
Utilities are already showing significant interest in hybrids.
“SoSolar and storage “complement each other, but do not have to be co-located. Hybrids are a bad use of good technology, though regulatory rules changes will be needed to accommodate both.”
Partner, Stoel Rives
The 409 MW Florida Power and Light (FPL) Manatee Energy Storage Center, when online in 2021, will be the world’s largest solar-powered battery, FPL VP of Development Matt Valle emailed Utility Dive. Solar-charged battery storage “has become an economically competitive option” and will allow “near-firm renewable power.” Other utilities and developers agreed, in emails to Utility Dive
Enabling rules and incentives that allow hybrids and technologies with longer storage durations “to compete with existing generation” are “slowly trickling into the marketplace,” Enel Green Power in North America Storage Growth Strategy Leader Ryan Prescott emailed Utility Dive. “And most markets are now considering and/or adopting tariff changes that will begin to pave the way for hybrids.”
Recurrent Energy, a major U.S. utility-scale solar developer, expects to bring its 300 MW solar-180 MWh battery Slate project online in California in 2021 and is moving into Midwestern and Eastern markets, Recurrent Managing Director of Development Mike Arndt told Utility Dive. “Those big markets are critical to hybrid growth and regulators need to make interconnection and capacity market rules clear.”
Market rules are a challenge if they allow dispatch of a hybrid’s generation to benefit the system, even if the price is low, ESIG’s Bloom agreed. “The asset owner may depend on offering that generation when the price is higher.”
But utility executives should recognize that, despite the challenges, markets are being disrupted because “hybrid technology is evolving faster than market structures,” Bloom said. “Executives must do what’s right for ratepayers and shareholders, but they should also entertain the possibility that, despite the uncertainty, hybrids are a big opportunity and the technology will drive demand.”
“More real world data is needed to understand the best bidding and dispatch strategies [for hybrid projects] to maximize the resources’ values to asset owners and the market as market designs evolve.”
Researcher, Lawrence Berkeley National Laboratory
Some power system analysts remain concerned with researchers’ still incomplete analysis of whether storage as part of a hybrid project or standalone storage is more cost-competitive.
There is also some question of the real value of co-locating different resources.
“Solar and storage is a better way to think about it than solar plus storage,” attorney Morten Lund, a partner with Stoel Rives, which represents major renewables developers, told Utility Dive. “They complement each other, but do not have to be co-located. Hybrids are a bad use of good technology, though regulatory rules changes will be needed to accommodate both.”
There are approaches to market processes that can clear the way for hybrids, stakeholders and researchers told Utility Dive.
“More real world data is needed to understand the best bidding and dispatch strategies [for hybrid projects] to maximize the resources’ values to asset owners and the market as market designs evolve,” Gorman said.
Four proposed models could be used for hybrid participation and compensation in wholesale markets and there may not be a single best approach, the Electricity Journal researchers reported. It may be better to make all of them available to asset owners and system operators.
One is for asset owners to bid the renewables and the storage into the wholesale market as individual resources and allow the system operator to take and schedule them as needed.
A similar but more complex option would give the system operator control of the hybrid’s resources to use separately unless system reliability necessitates use “as a single resource,” the researchers said. That approach has been used to assure battery storage owners’ access to the ITC is protected.
A third proposed market model is for the hybrid project to be managed as a single aggregate resource by the system operator in the same way that they have been managing standalone storage, the researchers said.
Storage in hybrid facilities is too often underused, Stoel Rives’ Lund said. If it is sited near a substation instead of co-located with renewables, it can be used by the system operator “more often for more services, like frequency regulation and other ancillary services.”
But ancillary services markets are small compared to the large amount of hybrid batteries being proposed, he acknowledged. And the reported reduction in interconnection, development, and other costs from co-location with renewables have values that should be recognized, he agreed.
Co-location is also important because “reliability is almost synonymous with capacity,” InterTran’s Peters told Utility Dive. Renewables and storage must be paired to have high enough capacity credit to replace the dominance of policy goal-defeating fossil fuels in supplying capacity, she said.
A fourth model would allow the asset owner to bid the hybrid project as a single aggregate resource into the market. This approach was fully outlined in an October 2019 ESIG paper that has won favor with many hybrid project advocates.
Overall, progress on opening the market to hybrids “is still very slow,” InterTran’s Peters said. Because FERC seems to see the addition of storage to renewables projects as a fuel change that requires the very costly restart of the interconnection application, “the only way to remedy this uncertainty is through policy changes.”
FERC could resolve much uncertainty by choosing the ESIG-proposed market participation model that echoed the Electricity Journal researchers’ fourth option, Peters said.
The hybrid’s multiple technologies would be “physically and electronically controlled by an owner/operator behind the point of interconnection and offered to the market or system operator as a single resource,” the ESIG paper said. This “can be done without significant changes to the existing markets and operating practices.”
The owner/operator “manages the characteristics of the components” and “offers energy, ancillary services and resource adequacy capacity” just as a conventional generator would, the paper added. But the hybrid project would have “more flexibility and fewer operating constraints” than a thermal or hydro resource.
Developers with hybrid projects now online or in the near-term queues are “first movers,” Peters said. “There is no market model, which means there can be no dispatch or settlement, so they are risking investments of hundreds of millions of dollars to pressure FERC and system operators to prioritize interconnection and market participation rules for hybrids.”
And with the April 7 announcement of the July 23 FERC technical conference, which offered little detail about what it will cover, the pressure may be working, Peters said.
The conference will “discuss technical and market issues” associated with “projects that are comprised of a generation resource and an electric storage resource paired together as a hybrid resource,” the FERC announcement said.
Original source: Utility Dive