By Devonie McCamey

A quick scan of recent energy-related headlines and industry announcements shows rising interest in hybrids — and we are not talking about cars.

Hybrid renewable energy systems combine multiple renewable energy and/or energy storage technologies into a single plant, and they represent an important subset of the broader hybrid systems universe. These integrated power systems are increasingly being lauded as key to unlocking maximum efficiency and cost savings in future decarbonized grids — but a growing collection of National Renewable Energy Laboratory (NREL) analysis indicates there are still challenges in evaluating the benefits of hybrids with the tools used to help plan those future grids.

In comparing hybrids to standalone alternatives, it is important to tackle questions like: Is it always beneficial to combine renewable and storage technologies, instead of siting each technology where their individual contributions to the grid can be maximized? Or are only certain hybrid designs beneficial? Does the energy research community consistently represent the characteristics of hybrids in power system models? And are we using common definitions when studying hybrids and their potential impacts?

Turning over a Magic 8-Ball might bring up the response: Concentrate and ask again.

“At NREL, we’re working to represent hybrid systems in our models in a more nuanced, detailed way to try to answer these questions — and ultimately advance the state of modeling to ensure consistency in how hybrids are treated across different tools,” said Caitlin Murphy, NREL senior analyst and lead author of several recent studies of hybrid systems. “With growing interest in these systems that can be designed and sized in lots of different ways, it’s crucial to determine the value they provide to the grid — in the form of energy, capacity, and ancillary services — particularly relative to deploying each technology separately.”

The results of this body of work highlight some gaps between what different models show and what many in the energy community have — perhaps prematurely — proclaimed when it comes to the value of hybrid systems to the future grid.

“Hybridization creates opportunities and challenges for the design, operation, and regulation of energy markets and policies — and current data, methods, and analysis tools are insufficient for fully representing the costs, value, and system impacts of hybrid energy systems,” said Paul Denholm, NREL principal energy analyst and coauthor. “Ultimately, our research points to a need for increased coordination across the research community and with industry, to encourage consistency and collaboration as we work toward answers.”

First, What Do We Mean When We Talk About Hybrid Systems? NREL Proposes a Taxonomy To Delineate What Makes a System a True Hybrid

Finding answers starts with speaking the same language. To help researchers move toward a shared vocabulary around systems that link renewable energy and storage technologies, Murphy and fellow NREL analysts Anna Schleifer and Kelly Eurek published a paper proposing a new taxonomy.

“Our ability to quantify hybrids’ potential impacts could be hindered by inconsistent treatment of these systems, as well as an incomplete understanding of which aspects of hybridization will have the greatest influence,” Murphy said. “Ultimately, we hope our proposed taxonomy will encourage consistency in how the energy community thinks about and evaluates hybrids’ costs, values, and potential.”

After a thorough literature review, the team developed a new organization scheme for utility-scale systems that combine renewable and energy storage technologies — only a subset of which can truly be called “hybrids.” They came up with three categories based on whether the systems involve locational or operational linkages, or both.

“We found that technology combinations do not represent a meaningful delineation between hybrids and non-hybrids — the nature of the linkages are more important distinctions,” Murphy said.

The resulting categories can help inform policy considerations, as they define system characteristics that could challenge existing permitting, siting, interconnection process, and policy implementations. The taxonomy is also helpful in informing model development efforts, as the categories identify the unique characteristics that must be reflected to adequately represent hybrid systems in a model — including the effects of the linkages on both a project’s costs and the values it can deliver to the grid.

That is where NREL’s next set of analyses comes in.

In a series of recent reports, NREL analysts homed in on a set of technology combinations and linkages that are consistent with a true hybrid system — co-optimizing the design and self-scheduling of linked technologies to maximize net economic benefits.

To do this, NREL modeled hybrid systems using three different tools that underpin many of the laboratory’s forward-looking power system studies. These analyses focus on DC-coupled solar photovoltaic and battery energy storage (PV+battery) hybrids, which are increasingly being proposed for the power system.

Can We Improve How Capacity Expansion Models Assess the Value of PV+Battery Hybrids? “Signs Point to Yes.”

Combining PV and battery technologies into a single hybrid system could lower costs and increase energy output relative to separate systems — but accurately assessing PV+battery systems’ market potential requires improved methods for estimating the cost and value contribution in capacity expansion models, including those that utilities use for integrated resource planning.

In Representing DC-Coupled PV+Battery Hybrids in a Capacity Expansion Model, Eurek, Murphy, and Schleifer teamed up with fellow NREL analysts Wesley Cole, Will Frazier, and Patrick Brown to demonstrate a new method for incorporating PV+battery systems in NREL’s publicly available Regional Energy Deployment System (ReEDS) capacity expansion model.

“The method leverages ReEDS’ existing treatment of separate PV and battery technologies, so the focus is on capturing the interactions between them for a hybrid with a shared bidirectional inverter,” Eurek said. “While we apply this method to ReEDS, we anticipate that our approach can be useful for informing PV+battery method development in other capacity expansion models.”

The research team used the method to explore a range of scenarios for the United States through 2050, using different cost assumptions that are uncertain and expected to influence how competitive PV+battery hybrids will be. These include the cost of hybrid systems relative to separate PV and battery projects, the battery component’s qualification for the solar investment tax credit (ITC), and future cost trajectories for PV and battery systems.

“From the full suite of scenarios, we find that the future deployment of utility-scale PV+battery hybrids depends strongly on the level of cost savings that can be achieved through hybridization. So, greater sharing of balance-of-system costs, reductions in financial risk, or modularity can all lead to greater PV+battery hybrid deployment,” Eurek said. “Deployment is also highly sensitive to the battery component’s ability to arbitrage, based on charging from the grid when prices are low and selling back to the grid when prices are high.”

In all scenarios explored, the synergistic value in a PV+battery hybrid helps it capture a greater share of generation, which primarily displaces separate PV and battery projects. In other words, the model results indicate that there is strong competition between PV+battery hybrids and separate PV and battery deployments — although it is important to note that the modeling does not reflect the faster and simpler interconnection process for hybrid projects, which could shift the competition with other resource types as well. In addition, if the PV+battery hybrid is designed and operated to ensure the battery component can qualify for the solar ITC, that could accelerate near-term deployment of PV+battery hybrids.

The team notes several ways in which future PV+battery system modeling could be improved — regardless of which capacity expansion model is used. A top priority is improving the representation of the battery component, including operations-dependent degradation — which may be distinct for hybrid versus standalone battery systems — and temporary operational restrictions associated with its qualification for the solar ITC. In addition, modeling retrofits of existing PV systems to add batteries may be especially important, since this is often considered one of the fastest ways to get PV+battery hybrids onto the grid.

What About Hybrids’ System-Level Operational Benefits? “Outlook Good.”

The operation and value of PV+battery hybrids have been extensively studied from the perspective of project developers through analyses that maximize plant-level revenue. But hybrid systems’ operational characteristics have rarely been studied from the perspective of grid operators, who work to maintain reliability and maximize affordability by optimizing the performance of a suite of generation and storage assets.

In Evaluating Utility-Scale PV-Battery Hybrids in an Operational Model for the Bulk Power System, NREL analysts Venkat Durvasulu, Murphy, and Denholm present a new approach for representing and evaluating PV+battery hybrids in the PLEXOS production cost model, which can be used to optimize the operational dispatch of generation and storage capacity to meet load across the U.S. bulk power system.

Production cost models are an important tool used by utilities and other power system planners to analyze the reliability, affordability, and sustainability associated with proposed resource plans. Here, NREL demonstrated a technique to enhance a production cost model to represent the operational synergies of PV+battery hybrids.

“We used a test system developed for NREL’s recent Los Angeles 100% Renewable Energy Study — replacing existing PV and battery generators on this modeled system with PV+battery hybrids,” Denholm said.

The research team analyzed different scenarios that were designed to isolate the various drivers of operational strategies for PV+battery hybrids — including how the technologies are coupled, the overall PV penetration on the system, and different inverter loading ratios (or degrees of over-sizing the PV array relative to its interconnection limit).

Results show multiple system-level benefits, as the growing availability of PV energy with increasing inverter loading ratio resulted in increased utilization of the inverter (i.e., resulting in a higher capacity factor), a reduction in grid charging (in favor of charging from the local PV, which is more efficient), and a decrease in system-wide production cost.

“The approach we present here can be used in any production cost modeling study of PV+battery hybrids as a resource in different power system configurations and services,” Durvasulu said. “This is a critical step toward being able to evaluate the system-level benefits these hybrids can provide, and improving our understanding of how a grid operator might call on and use such systems.”

How Could the Value of Hybrids Evolve Over Time? “Reply Hazy, Try Again.”

The third report in the series brings yet another modeling method to the table: price-taker modeling, which quantifies the value that can be realized by PV+battery systems — and explores how this value varies across multiple dimensions.

In “The Evolving Energy and Capacity Values of Utility-Scale PV-Plus-Battery Hybrid System Architectures,” Schleifer, Murphy, Cole, and Denholm explore how the value of PV+battery hybrids could evolve over time — with highly varied results.

Using a price-taker model with synthetic hourly electricity prices from now to 2050 (based on outputs from the ReEDS and PLEXOS models), NREL simulated the revenue-maximizing dispatch of three PV+battery architectures in three locations. The architectures vary in terms of whether the PV+battery systems have separate inverters or a shared inverter and whether the battery can charge from the grid. The locations vary in terms of the quality of the solar resource and the grid mix, both of which influence the potential value of PV+battery hybrids.

“We found that the highest-value architecture today varies largely based on PV penetration and peak-price periods, including when they occur and how extreme they are,” Schleifer said. “Across all the systems we studied, we found that hybridization could either improve or hurt project economics. And no single architecture was the clear winner — in some cases, you want to take advantage of a shared inverter, and in other cases, separate inverters and grid charging are too valuable to give up.”

The results of this price-taker analysis show that a primary benefit of coupling the studied technologies is reduced costs from shared equipment, materials, labor, and infrastructure. But in the absence of oversizing the PV array, hybridization does not offer more value than separate PV and battery systems. In fact, hybridization can actually reduce value if the systems are not appropriately configured — which means appropriately sizing and coupling the battery and likely oversizing the PV array relative to the inverter or interconnection limit.

Another important finding is that both subcomponents stand to benefit from hybridization. As PV penetration grows, the additional energy and capacity value of a new PV system declines rapidly — but coupling the PV with battery storage helps to maintain the value of PV by allowing it to be shifted to periods where the system can provide greater value. In addition, coupled PV can help increase the total revenue of the battery by displacing grid-charged energy, which typically has non-zero cost.

“As the role of PV+battery hybrids on the bulk power system continues to grow, it will be increasingly important to understand the impact of design parameters on economic performance,” Schleifer said. “Additional analysis is needed to tease out the factors that impact the performance and economics of PV+battery hybrid systems — and give system planners and researchers clearer answers about their possible benefits.”

Working Toward “Without a Doubt:” A Call for Coordination To Resolve the Remaining Unknowns

Looking at this collection of work, one thing is clear: No current model is an accurate Magic 8-Ball for predicting hybrids’ future value — but coordinated efforts to improve our models can bring the research community a step closer to a clear outlook.

And momentum is building: The U.S. Department of Energy (DOE) has convened the DOE Hybrids Task Force — which worked with NREL, Lawrence Berkeley National Laboratory, and seven other national laboratories to develop the recently released Hybrid Energy Systems: Opportunities for Coordinated Research, which highlights innovative opportunities to spur joint research on hybrid energy systems in three research areas. That effort touches on the PV+battery hybrids described in this article, and it also considers additional technology combinations that could have a growing role in the future, including PV+wind, nuclear+electrolysis, and other low-emitting hybrid systems.

“While the power system was originally developed as single-technology plants, and many of our research efforts have been siloed to individual technologies, the DOE Hybrid Task Force represents a step toward collaboration,” Murphy said. “We were able to identify several high-priority research opportunities that span multiple technologies, establish common priorities, and lay a foundation for further dialogue.”

In the days ahead, NREL is uniquely poised to further the validation of hybrid system performance and operation with the Advanced Research on Integrated Energy Systems (ARIES) research platform. ARIES introduces both a physical and a near-real-world virtual emulation environment with high-fidelity, physics-based, real-time models that facilitate the connection between hundreds of real hardware devices and tens of millions of simulated devices.

Integrated energy pathways modernizes our grid to support a broad selection of generation types, encourages consumer participation, and expands our options for transportation electrification.

Ultimately, advancing hybrid systems research at NREL and other national laboratories will require more coordination with industry. The DOE Hybrids Task Force report identified the need for a multistakeholder workshop to take a deep dive into what is motivating different stakeholders to propose and deploy different types of hybrid systems.

“By creating opportunities to directly solicit insights from industry, utility planners, and other stakeholders, we can move toward a deeper understanding of what sources of value are driving industry interest in hybrids,” Murphy said. “Is there inherent value that can only be unlocked through hybridization, or is some of the value embedded in the familiar? By adding storage to variable resources, we can make them look and participate more like the controllable resources we are used to having on the power system.

“Bringing the key players together will help us as researchers to recognize these motivations — some of which we might not currently understand — and close the gap in how to represent them in our models.”

Learn more about NREL’s energy analysis and grid modernization research.

Article courtesy of the NREL, the U.S. Department of Energy

Featured photo by Ramón Salinero on Unsplash