A method for investigating the value evolution of utility-scale PV-plus-battery hybrid systems




Schleifer, Anna Harpe

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Deployment of hybrid systems comprising solar photovoltaics (PV) and lithium-ion battery storage is expected to surge in the 2020s and beyond. Approximately 40 utility-scale PV-plus-battery projects were installed on the bulk power system before 2020, and over 25% of PV capacity in U.S. interconnection queues in 2020 was paired with battery systems. By 2023, more than half of all battery capacity in interconnection queues is expected to be paired with PV. However, there is uncertainty around the design and operations of PV-plus-battery systems, especially in the face of a changing grid mix, and how these aspects affect their long-term deployment potential. Few electricity sector modeling tools currently include representations of PV-plus-battery systems, and those that do include only simple representations that do not reflect the range of possible configurations or are limited in their temporal resolution. In this work, a forward-looking, technoeconomic methodology was developed to explore how the value of a wide range of PV-plus-battery hybrid systems could evolve over time and across locations. The methodology enables this exploration through the combination of several existing electricity sector modeling tools with different temporal and geographic scales. The methodology uses simulated electricity prices through 2050 to capture how evolving grid conditions impact the value of PV-plus-battery systems. These hourly prices come from a process that involves the (1) optimization of generation and transmission deployment over a future horizon using a capacity expansion model, (2) optimization of the hourly operations of the resulting bulk power system using a production cost model (or unit commitment and dispatch model), and (3) processing of the resulting hourly data to create combined energy and capacity prices for future years. These hourly prices are then used as inputs, along with hourly PV generation profiles, in a price-taker model to determine the revenue-maximizing dispatch of any PV-plus-battery system of interest. In this context, the revenue-maximizing dispatch of a PV-plus-battery system is also the value-maximizing dispatch from the perspective of a central operator. Using this methodology, the economic performance of PV, battery, and PV-plus-battery systems can be evaluated and compared across many years and locations, with consideration of different architectures and component sizes, to understand the factors that influence the potential benefits of various PV-plus-battery systems to future power systems. The second part of this work explored the energy value and capacity value of three PV-plus-battery system architectures, with fixed component sizing, in various locations in the United States. PV-plus-battery system architectures reflect different coupling types, which vary in terms of whether the PV and battery systems have separate inverters or a shared inverter and whether the battery can charge from the grid. Results from this analysis showed that the highest-value architecture in the near term varies largely based on PV generation shares and the magnitude and timing of peak-price periods. As the share of PV generation increases over time, two trends emerge that indicate a convergence of the values of the systems studied. First, the energy values of the three architectures converge as an increasing fraction of energy from the coupled PV is used to charge the battery. Second, their capacity values converge to that of the battery as the capacity credit of stand-alone PV approaches zero. Of the systems studied, no single architecture had the highest year-one benefit-cost ratio in every region and year, and benefit-cost ratios of PV-plus-battery systems ranged from a 15% reduction to a 25% increase compared to separate PV and battery systems. The third part of this work explored the energy and capacity values of a range of DC-coupled PV-plus-battery configurations in various U.S. locations. These configurations were defined by the inverter loading ratio (ILR, the ratio of the PV array capacity to the inverter capacity, which was varied from 1.4 to 2.6) and the battery-inverter ratio (BIR, the ratio of the battery power capacity to the inverter capacity, which was varied from 0.25 to 1.0). Based on each configuration’s total value, the breakeven costs needed to justify each incremental increase in ILR (holding BIR constant) or BIR (holding ILR constant) were estimated. Results from this analysis showed that, in a future with low-cost renewable energy technologies, PV-plus-battery system ILRs can be economically increased to around 2.0–2.4 at a BIR of 1.0, depending on the quality of the solar resource. Results indicated that a likely evolution of PV-plus-battery system design will be increasingly greater battery power capacity to mitigate the declining PV capacity value, which will, in turn, enable increasingly higher ILRs to further increase energy value. The extent to which PV-plus-systems will be deployed with increasingly higher ILRs depends primarily on whether PV cost declines outpace declining value and increasing curtailment over time. In the fourth part of this work, the interactions of wind and PV generation were evaluated in terms of the effect of wind generation on the value of PV and PV-plus-battery systems. Holding the PV capacity and point-of-interconnection (POI) capacity constant, configurations with wind capacities of 50, 100, and 200 MW and battery capacities of 25 MW and 100 MW were modeled to compare the energy and capacity values of PV-wind and PV-wind-battery systems to metrics that describe the location-specific complementarity of PV and wind. Results demonstrated that complementarity metrics that do not account for the relative sizing of PV and wind components are limited in their usefulness for predicting the value of co-locating or coupling these systems. On the other hand, complementarity metrics that do account for relative sizing are useful in predicting circumstances in which adding wind capacity to PV or to PV-plus-battery hybrids can allow for reducing the battery capacity with minimal change in total value. This body of work provides methods for evaluating and comparing a range of PV-plus-battery hybrid systems—with and without accurate capital and operations and maintenance cost information—in a number of future scenarios. The analyses presented in this dissertation provide insight into the motivations for coupling PV and battery systems and the factors that influence the operation and value of different coupling types and configurations as the bulk power system evolves. Results indicated that the benefits of co-locating and coupling PV and battery systems are largely driven by cost reductions associated with shared equipment and infrastructure and shared project development. The performance-related benefits analyzed have a minor effect on the economics of PV-plus-battery hybrid systems relative to the cost-related benefits. However, the optimal PV-plus-battery configuration is highly dependent on location and grid mix, demonstrating the importance of analyzing hybrid systems under diverse conditions. Because of the potential cost reductions, and in large part due to incentives such as the federal investment tax credit, the ability to couple PV and battery systems will likely result in higher deployment of the total capacity of each technology, resulting in higher shares of PV generation and increased power system flexibility. While the analyses described in this dissertation used electricity sector modeling tools that are specific to the conterminous United States, the overall methodology developed here can be applied to any location, with different modeling tools substituted into the workflow. Furthermore, since the locations analyzed in this work reflect a range of conditions over several years, insights from the results of this work can be extended to other locations, both within the United States and internationally.


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