New data shows hybrid renewables+storage projects grew even faster in 2019 than previously reported. The last major obstacle to ever greater deployment may be easing system operators' reliability concerns.
Federal regulators took a big step toward an overdue rulemaking to address those concerns at a July 23 Federal Energy Regulatory Commission conference. Participation by Commissioner Richard Glick suggested action will follow, advocates told Utility Dive. They and system operators are working toward market rules that will enable hybrids' unique value.
Renewables with storage offer many potential benefits, Andrew Levitt, PJM Interconnection senior market design specialist, said in filed comments. Though concerns about reliability are real, hybrids can "mitigate operational issues" from variable renewables' "fluctuating output," by increasing developers' "flexibility to produce more power during times of higher economic and reliability value," Levitt said.
But many system operators are "comfortable with conventional plants' quirks and failure modes, while hybrids are unfamiliar," NextEra Energy Vice President of Renewable Energy Policy and Board President of the Energy Systems Integration Group Mark Ahlstrom, told the conference. "The need for the familiar should not limit services hybrids can offer at their developers' risk," he added.
Hybrids' falling costs and rising value have driven queued capacity to almost ten times the 14 GW in operation today. If FERC does not accelerate rule changes allowing hybrids to be treated like other resources and earn full compensation in wholesale markets, growth could be obstructed, conference participants said. But solutions like congestion mitigation are emerging, they agreed.
Hybrid queues boom
Projects that combine types of generation or generation with storage can take four basic hybrid models, depending on developer and system operator rules, Utility Dive reported in April.
Co-located renewables and storage can participate in markets as individual resources or as a combined renewables+storage resource controlled by a system operator. Two other models would allow the hybrid project to participate only as a single resource, managed either by a system operator or the hybrid owner.
There is a "tsunami" of queued hybrid capacity, California Independent System Operator (CAISO) Infrastructure Contracts and Management Director Deb LeVine told the conference. PJM's Levitt, ISO New England (ISO-NE) Transmission Services and Resource Qualification Director Al McBride and Mid-Continent ISO (MISO) Senior Resource Interconnection Engineer Noel Augustine agreed.
"Two years ago, there were almost no hybrids," Lawrence Berkeley National Laboratory (LBNL) Graduate Student Researcher Will Gorman, co-author of a July 2020 study detailing hybrid data, told the conference. By the end of 2019, at least 125 hybrids greater than 1 MW each were operating, representing over 14 GW of capacity, LBNL found.
At the end of 2019, there were 40 operational solar+storage projects totaling 882 MW of solar with 169 MW/446 MWh of storage and 13 operational wind+storage projects with 1,290 MW of wind and 184 MW/109 MWh of storage around the country, LBNL found. Wind hybrids were most common on the Electric Reliability Council of Texas (ERCOT) and PJM systems. Solar hybrids were most common on the CAISO and ERCOT systems.
Those numbers are dwarfed by the pending projects of the seven U.S. regional systems and 30 utilities covered in LBNL's report. At the end of 2019, there were some 367 GW of solar in U.S. queues and 102 GW of it, or 28%, were proposed as hybrids. Another 11 GW, or 5%, of the 225 GW of queued wind projects was proposed as hybrids.
The boom is impressive, but deployment is threatened by issues raised at the FERC conference, LBNL's Gorman told Utility Dive. "The conference was about getting the rules right now so that a well-designed market can grow in the years ahead."
Why hybrids?
Defining the advantages of hybirds requires defining the term, according to NextEra's Ahlstrom. A hybrid is "multiple technologies that are physically and electronically controlled" by the hybrid owner at a single point of interconnection and offered to the market "as a single resource."
Conference speakers called hybrids that fit Ahlstrom's definition "R1" projects. Separately controlled and bid co-located resources were called "R2" projects.
"If valued services change, and they will, hybrids can quickly adapt. Analytics and software can be improved within weeks and battery storage can be added within months to continue delivering reliable services."
Mark Ahlstrom
Vice President of Renewable Energy Policy and Board President of the Energy Systems Integration Group, NextEra Energy
The owners of R1 hybrids should have the same incentives for supplying the system and penalties for failing to deliver as conventional generators, Ahlstrom wrote in his October 2019 paper detailing hybrid advantages. Owners could optimize returns in energy, capacity and ancillary services markets and eliminate losses due to renewables curtailment through energy price arbitrage.
But the biggest advantage to owners may be hybrids' modularity, Ahlstrom added. "If valued services change, and they will, hybrids can quickly adapt. Analytics and software can be improved within weeks and battery storage can be added within months to continue delivering reliable services."
To the advantage of system operators, R1 hybrids can use "conventional" market participation models, Ahlstrom said. If market models and rules enable and compensate hybrids "in a performance-based, technology agnostic manner," system owners could leave unfamiliar complexities like renewables' variability and storage's two-way power flows to project owners.
The biggest disadvantage of hybrids for system operators may be the loss of control of individual resources, requiring them to focus on the higher-level role of managing markets, he added. But "the fundamental rule for maintaining reliability is to keep the system balanced in real time, and these new, flexible, fast-responding resources, if properly compensated, can help do that."
Those things are important, but a critical near-term determinant of the value of hybrids is the federal investment tax credit (ITC), which typically is for solar+storage projects but also can go to wind+storage projects if the developer chooses it, LBNL's Gorman said. To qualify for the ITC, at least 75% of the electricity discharged by the battery must come from the renewable with which it is paired.
To maximize access to the renewable resource, projects may need to be be sited at resource-rich locations where reduced grid congestion and price volatility limit financial returns, Gorman said. The siting advantage offsets the cost of ITC-related constraints in California markets but not in Texas markets, LBNL found. It is an example of how policy, rules and market models can "make or break" a project, Gorman said.
"Some system operators assume hybrids will threaten reliability by charging their batteries during peak demand, but it is nuts to assume a hybrid owner will charge when prices are highest because that is completely irrational."
Rob Gramlich
President, Grid Strategies
"The surge of market interest in hybrids is moving faster than the evolution of market rules, which are presently unclear at best and in many cases ill-suited to these projects," reported a 2019 paper on enabling hybrids by Grid Strategies President Rob Gramlich, also a conference panelist.
Interconnection rules and market models are needed that allow owners to choose to participate as R1 or R2 hybrids, said Ahlstrom, Gorman, Gramlich, system operators and others. And market models and rules are also needed that enable and compensate hybrids while protecting reliability, conference participants agreed.
Two key barriers
System operators are working to understand and address hybrid needs, their representatives told the conference. There are two immediate barriers to integrating the resources reliably.
MISO's FERC-approved interconnection protocols will help resolve one key barrier to hybrid growth by streamlining the process for adding storage to queued renewables proposals, MISO's Augustine said. But MISO and other systems still make adding batteries to queued renewables a "material modification" to the interconnection agreement and restart those projects in years-long application queues, stakeholders responded. That can trigger burdensome studies and costly network upgrades, hybrid advocates said.
The other key barrier is grid operator rules based on irrational assumptions, Gramlich said. "Some system operators assume hybrids will threaten reliability by charging their batteries during peak demand, but it is nuts to assume a hybrid owner will charge when prices are highest because that is completely irrational," he said.
Reducing the time and cost to prove hybrids are not a threat to reliability and streamlining material modification rules would not interfere with power system operations, Gramlich said. But ignoring the huge developer investments and needed system capacity at stake would be a loss to system operators and stakeholders, he added.
Proposed MISO interconnection process changes represent "good progress" on hybrid rules, Augustine said. And ISO-NE is improving its interconnection procedures and planning to "facilitate co-located projects," ISO-NE's McBride added. But both maintain requirements to protect reliability that can be barriers to hybrid growth, other conference panelists responded.
PJM seems to have begun to understand the developers' perspective.
Unlike other system operators, PJM has concluded that R1 hybrid configurations are preferable to co-located R2 configurations, PJM's Levitt told the conference. With the R1 model, the "complementary, albeit sometimes complex, interactions" between the generation and storage components become the responsibility of the hybrid owner.
Both options will be available in PJM by early 2021, and stakeholder processes will also clarify how current rules should be applied, he added.
CAISO rules for integrating hybrid projects have set the national standard, advocates at the conference agreed.
"Congestion management is a gatekeeping exercise that seems to be working well in California."
Andrew Mills
Research Scientist, LBNL
In response to California's 1,325 MW by 2020 storage mandate, new stakeholder-led rules allow standalone storage to apply through the interconnection process, but that can take two years or more, CAISO's LeVine told the conference. Those new rules also allow interconnection applications for storage added to queued renewables to be processed in 90 days or less.
"Additions are typically not material modifications because we use congestion management to mitigate any threat to reliability," she said. "In 2018, 100% of modification requests to add batteries were approved."
CAISO developers also have the option of operating in the R1 or R2 model, she added. To date, most have chosen the R2 option, "but studies show that will likely change over time."
Has California — the U.S. leader in hybrid deployment, with no reliability threats — found the solution to integrating hybrid resources that could be applied to other systems?
Congestion management in California
California's approach is based on carefully monitoring hybrid impacts to ensure they created no threat to the system.
CAISO implements congestion management through dispatch or operational instructions that increase system flexibility and eliminate the need for network upgrades, CAISO spokesperson Anne Gonzales said in an email. System upgrades are required only if dispatch threatens reliability by exceeding system operating limits, according to CAISO rules.
Charging batteries with system power instead of with paired renewables is allowed, but only if the system operator has recognized that power is available on the system, LeVine said at the conference. That helps protect ITC benefits and eliminates concerns about charging during peak demand.
For developers with queued renewables who want to add storage, CAISO's congestion management approach offers a flexible definition of material modification. Studies must show "the modification either improves or does not adversely impact the costs and benefits (including reliability) of the interconnection."
This has allowed hybrids to add "significant versatility to our system," LeVine told the conference.
"Innovation finds a way. For now, put storage with everything and we will figure out how to use it."
Mark Ahlstrom
Vice President of Renewable Energy Policy and Board President of the Energy Systems Integration Group, NextEra Energy
MISO and other system operators use different "study models" than CAISO, MISO's Noel Augustine said. CAISO's rules could lead to overbuilding transmission and increasing costs to MISO customers, he added. ISO-NE's McBride was non-committal about congestion mitigation for New England. Both, like CAISO, want more operational experience with hybrids.
"Congestion management is a gatekeeping exercise that seems to be working well in California," Research Scientist Andrew Mills, co-author of the LBNL hybrid study said. It limits the time and cost of studies and allows the project to move ahead, but protects reliability by allocating dispatch decisions and the related risk to the hybrid owner. It could apply in other regions.
"System operators are evolving, but some justify unnecessary burdens on developers by playing the reliability card," Gramlich said. "There is a difference between real reliability concerns and legitimate economic choices. California allows developers to make economic choices."
System operators will recognize the value in hybrids' ability to "adapt and innovate" as power sector changes accelerate, Ahlstrom said. "Innovation finds a way. For now, put storage with everything and we will figure out how to use it."
Stakeholder comments on the conference are due Sept. 30.
