Equity has become central in the academic and regulatory discourse shaping the future of residential-scale clean energy technologies in the United States, particularly rooftop solar. Here, we develop a holistic perspective on these issues by analyzing rooftop solar adoption trends using two alternative forecasting methods: an inside-view forecast based on historical solar adoption data, and an outside-view forecast based on adoption data for other emerging consumer technologies. We show how rooftop solar, like other emerging consumer technologies, has become more equitably adopted over time. We show that solar diffusion patterns are largely consistent with those of other technologies. Both forecasting methods suggest that clean energy technologies should be expected to become more equitably adopted over time. Policy could accelerate this process by supporting low-income adoption without unduly curbing overall diffusion.

Coupled renewable-battery powerplants differ from the traditional concept of independent siting of electricity resources within transmission networks. Prior research on the value proposition and cost savings from coupling did not consider the geographic constraint of co-location. This paper fills the gap by assessing how pricing volatility differences between nodes within electricity markets impact the system value of coupled renewable-battery projects as compared to independent VRE and battery installations. We use wholesale power market prices from 2012–2019 across the seven main U.S. independent system operators (ISOs) with a linear optimization program to compare the electricity market value of coupled projects to the value of the same underlying sub-components, deployed separately. We find that additional value from adding a 4-hour battery sized to 50% of renewable-plant nameplate capacity is $10/MWh across ISOs on average. The highest boost occurs in California ($15/MWh), where the value of adding storage to solar rises over time in tandem with increased solar penetration in the region. If renewables and batteries are deployed independently, we estimate that $12.5/MWh of additional value could be achieved because of more flexibility on battery siting and operation. The $12.5/MWh coupling penalty is reduced to $1.6/MWh when considering alternative approaches to integrating battery storage. This result implies that renewable-battery power plants will play an increasing role in electricity systems if they can be built for $2–$13/MWh less than independent projects of comparable size. However, the wide regional variation in coupling penalties, along with the importance of conditions captured in our sensitivity cases, suggests the tradeoff between coupling penalties and savings will vary by situation. Therefore, roles exist for independent and coupled projects from a system optimization perspective.

Examining coupled renewable-battery power plants (“hybrids”) in congested areas provides insights into a future of increased wind and solar penetration. Our study focuses on two types of congested regions, Variable Renewable Energy (VRE)-rich Areas and Load Centers, and explores likely plant configuration choices for developers and transmission network planners. This paper examines how hybrid value, comprising energy and capacity value, varies by plant configuration and congested region type considering factors such as storage duration, battery degradation, and ability to charge from the grid. We select plant locations from across the seven main U.S. independent system operators (ISOs). Hybrid value for each configuration is computed based on profit-maximizing plant operation given perfect foresight, according to observed wholesale power market real time prices from 2018 to 2021. In VRE-rich Areas, the median increase in energy value from extending storage duration from one to 4 h is 29.4 % for solar and 26.8 % for wind, assuming low battery degradation costs and storage sized to 100 % of the plant's nameplate generation capacity. Increasing storage duration beyond 4 h does not substantially increase its value from energy markets, even in VRE-rich Areas. We find that solar hybrids reach a 90 % capacity credit with 4 h of storage, while wind hybrids require 8 h of storage, based on the capacity factor of each hybrid during the top 100 net load hours.

Coupling battery storage to renewable plants is increasingly common in the United States, where a third of proposed solar capacity now includes battery storage. Adding batteries to renewable plants increases the average value of energy sold, can reduce energy losses to curtailment, and is incentivized through the investment tax credit. Additionally, coupling renewables with batteries saves on permitting, planning, and construction costs compared to developing the projects separately. However, collocation limits the potential locations at which the batteries might be sited. This limitation leads to an opportunity cost, or “coupling penalty,” which is the missed value that could be realized by independently siting the batteries in an optimal location away from the wind or solar resources. In this paper, we assess the opportunity costs of coupling batteries with wind and solar plants. Our analysis is based on United States wholesale power markets, and we explore how the coupling penalty varies over time (2012–2019) and across location (across the seven major wholesale markets). We find the coupling penalty ranges from $2.3/MWh to $13.7/MWh, depending on battery integration assumptions. This penalty is the same order of magnitude as cost savings estimates for coupled project development and construction. This rough equivalence in opportunity cost and cost savings suggests that the net value of coupling renewables and batteries is highly sensitive to site-level market conditions and configuration decisions. The current structure of the investment tax credit, which only reduces storage costs when charged by a renewable generator, will often ‘tip the balance’ towards coupling.

Increasing the penetration of photovoltaics (PV) reduces the marginal grid value of PV electricity. Various strategies have been proposed for preserving this value. We analyze the net value (accounting for both cost and grid value) of these strategies in the USA. We find that established and emerging strategies designed to shift the timing of standalone PV generation at the expense of total generation - including orienting monofacial PV modules west or bifacial modules vertically - result in minor net-value benefits or penalties. Adding energy storage to such systems magnifies the net-value loss, because configurations that change the timing of PV production become redundant when the energy-shifting capabilities of storage are added. The largest net-value gains come from strategies that maximize generation (solar tracking plus oversized PV arrays) in conjunction with storage, especially at high PV penetrations. PV systems are long-lived assets. Our results suggest that efforts to promote generation-maximizing strategies today may yield increasing netvalue benefits as U.S. PV and storage deployments continue to accelerate over the coming decades.

With continued deployment of solar across the United States, assessing the interactions of solar with the power system is an increasingly important complement to studies tracking the cost and performance of solar plants. This project focuses on the historical contribution to reliability, trends in market value, and impacts on the bulk power system of solar deployed in the U.S. through the end of 2020. The scope of this analysis includes the seven organized U.S. wholesale power markets and is based on historical hourly solar generation profiles for each individual plant larger than 1 MW or county-level aggregate profiles for smaller solar. In addition, we present a limited set of results for ten utilities that are outside of the independent system operator (ISO)/regional transmission organization (RTO) markets. Highlights include: -Solar Generation: Solar deployment in the California Independent System Operator (CAISO), where solar generation was equivalent to 21.2% of annual load in 2020, far exceeds the level in other ISOs. The New England Independent System Operator (ISO-NE) has the second-highest penetration, with solar generation equivalent to 5.2% of annual load in 2020. All other ISOs have annual solar generation shares at or below 3%. -Reliability Contribution: Solar’s contribution to the overall resource adequacy of the power system is measured by its “capacity credit”. While calculation methods vary across ISO/RTOs, summer capacity credits for solar in 2020 range from 39 to 80% of a system’s nameplate capacity. Capacity credits have remained largely stable over the past years except in CAISO where solar’s capacity credit steeply declined in 2018. -Market Value: The market value of solar, defined here as the sum of the energy and capacity values, primarily varies across regions and years because of variations in average energy prices and capacity market prices. The energy value, based on the hourly solar generation and real-time power prices at pricing nodes near each solar plant, is the largest component of the market value across ISOs. In 2020, the average energy value spanned from $21/MWh in CAISO to $24/MWh in SPP. The capacity value of solar is based on the capacity credit of solar and the capacity price. The capacity value in 2020 was highest in the Southwest Power Pool (SPP; $26/MWh), though capacity prices there are based on estimates of bilateral capacity transactions rather than transparent organized capacity market prices, and lowest in the Midcontinent Independent System Operator (MISO; $2/MWh). -Market Value Decline: The market value of solar in CAISO declined between 2012 and 2019, both overall and relative to annual average energy and capacity prices. In 2012, solar’s market value in CAISO was 40% higher than the value of a flat block of power (representing the market value of a generator that operates at full nameplate capacity in all hours of the year). By 2020, however, solar’s value was 30% lower than a flat block of power’s value because of a solar-induced shift in the timing of high and low energy prices and a reduction in solar’s capacity credit. In contrast, the market values of solar in regions where solar penetrations were low did not decline relative to average prices. -Overall Competitiveness: As solar’s market value declined in CAISO, its cost—as measured by levelized power purchase agreement (PPA) prices—declined at a similar pace, thus maintaining solar’s overall competitiveness. Solar was more competitive in SPP and the western non-ISO utilities where the market value in 2020 exceeded the levelized PPA price of contracts signed in 2020. Solar’s wholesale market value in 2020 matched PPA prices in CAISO, ERCOT, PJM, and the southeastern non-ISO utilities. On the other hand, PPA prices in MISO and ISO-NE exceeded solar’s wholesale capacity and energy value. Revenue streams or benefits beyond wholesale market energy and capacity value may help explain continued solar growth across the country. -System Impact: In CAISO, the net load has shifted to resemble the “duck curve,” with particularly low net load during spring days and high ramps as the sun sets in the evening. Similar patterns emerge in real-time prices, with lower prices during the day and higher prices in the early evening. Ancillary service requirements, particularly regulation reserves, have increased during the day, as have regulation prices. Negative real-time prices during low net load days in the spring suggest growing challenges with providing flexibility. However, broader shifts in the system—including growing participation of western utilities in the Western Energy Imbalance Market and variations in hydropower levels—appear to have mitigated some challenges in 2020 relative to 2017, even with greater solar deployment in 2020. Impacts to the net load shape from solar are similarly evident in a number of non-ISO utilities in the Western U.S., for example Arizona and Nevada. With much less solar deployment in the other ISOs, solar impacts on the bulk power system are much less obvious. This report focuses on the empirical trends in system impacts, reliability and market value of stand-alone solar in the United States. For the first time, we also assess the reliability contributions and market value of several PV-battery hybrid projects based on empirical dispatch records from 2020. For more information, see Influence of Business Models on PV-Battery Dispatch Decisions and Market Value.

Increasing the penetration of photovoltaics (PV) reduces the marginal grid value of PV electricity. The declining grid value of PV with higher penetration could limit the technology's economic attractiveness and future demand. Various strategies have been proposed for preserving this value. Using a consistent framework, we analyze the net value (accounting for both cost and grid value) of more than ten strategies in the United States. Here, grid value is estimated from coincident wholesale power market prices and PV generation using observed historical prices or modeled future prices with up to 30% PV penetration. We find that established and emerging strategies designed to shift the timing of standalone PV generation at the expense of total generation—including orienting monofacial PV modules west or bifacial modules vertically—result in minor net-value benefits or penalties. Adding energy storage to such systems magnifies the net-value loss, because configurations that change the timing of PV production become redundant when the energy-shifting capabilities of storage are added. The largest net-value gains come from strategies that maximize generation (solar tracking plus oversized PV arrays) in conjunction with storage, especially at high PV penetrations. PV systems are long-lived assets. Our results suggest that efforts to promote generation-maximizing strategies today may yield increasing net-value benefits as PV and storage deployments continue to accelerate in the United States over the coming decades.

Variable renewable energy (VRE) is not yet meaningfully participating in U.S. ancillary services (AS) markets. VRE participation in AS markets could provide a new source of revenue for VRE resource owners to offset declining energy and capacity values and a new tool for power system operators to address emerging system constraints. This paper uses a price-taker dispatch model and historical prices to estimate the economic value of standalone and hybrid (battery-paired) VRE participation in AS markets, from the resource owner and electricity system perspectives, in each of the seven U.S. independent system operator and regional transmission organization (ISO/RTO) markets where ancillary service prices are set. Across ISO/RTO markets, average (2015–2019) simulated incremental revenues from power regulation market participation were $0.0–2.9/MWh (+0–15% of revenue without participation) for standalone VRE owners and $1–33/MWh (+1–69%) for hybrid VRE owners. However, ISO/RTO reserve markets are relatively thin and have the potential to become saturated by energy storage projects that are currently in ISO/RTO interconnection queues. In most markets, standalone and hybrid VRE could provide power regulation reserves during periods with high power regulation prices, suggesting that VRE participation in AS markets could have high system value. The analysis highlights the relevance of separate upward and downward power regulation products and indicates that ISOs/RTOs might consider initially focusing on enabling hybrid VRE provision of AS.

Solar energy has the potential to be a core energy resource for the southeastern United States. To better understand the implications of higher levels of solar PV (27%-43% of total generation capacity) and electricity storage (13%-49% of peak load) would affect electricity system reliability, costs, and operations in the U.S. Southeast, this study sought to address two main questions. First, how would higher levels of solar PV and electricity storage impact the costs, reliability, and operations of electricity systems in the Southeast in 2035? Second, at different levels of solar PV and electricity storage, what are the benefits of operational coordination among utilities in the Southeast, through more efficient regional dispatch and sharing operating reserves? To answer these questions, the study used detailed capacity expansion and dispatch modeling to develop and examine 15 scenarios with different levels of solar PV, electricity storage, and operational coordination, focusing on the year 2035. The study also evaluates the benefits of operational coordination among utilities through more efficient regional dispatch and reserve sharing, at different levels of solar and storage. The study focuses on five balancing regions that cover Alabama, Georgia, Kentucky, North Carolina, South Carolina, Tennessee, and parts of Mississippi and Missouri.