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Fact sheet describes evaluating and optimizing a PV system on the Mickey Leland Federal Building.
This study assesses the feasibility of solar installations at various sites in Winston-Salem, focusing on factors such as solar resource availability, electricity costs, and rooftop area for photovoltaic systems. The analysis begins by estimating daily energy requirements based on annual electricity use, followed by adjusting for seasonal and operational fluctuations. Using regional solar data from the National Solar Radiation Database (NSRDB), we calculate average peak sun hours to determine effective system sizing. A parametric approach using the System Advisor Model (SAM) refines this sizing process, incorporating a safety margin of 1.2 to address demand peaks. Each PV system is designed to fit available rooftop space, and a coverage threshold of 70% is identified as optimal for maximizing cost savings and sustainability. This threshold allows installations to meet substantial energy demands, supporting energy resilience and enhancing economic returns.
Berkeley Lab’s “Utility-Scale Solar, 2023 Edition” presents analysis of empirical plant-level data from the U.S. fleet of ground-mounted photovoltaic (PV), PV+battery, and concentrating solar-thermal power (CSP) plants with capacities exceeding 5 MWAC (PV plants of 5 MWAC or less, including residential rooftop systems, are covered separately in Berkeley Lab’s companion annual report, Tracking the Sun). Highlights of this year’s update include: -10.4 GWAC of new utility-scale PV capacity came online in 2022, bringing cumulative installed capacity to more than 61.7 GWAC across 46 states. -94% of all new utility-scale PV capacity added in 2022 uses single-axis tracking. -Median installed project costs declined to $\$1.32$/WAC (or $\$1.07$/WDC) in 2022. -Plant-level capacity factors vary widely, from 9% to 35% (on an AC basis), with a sample median of 24%. The report explores drivers of this variation. -Utility-scale PV’s LCOE fell to $\$39$/MWh in 2022 ($\$29$/MWh if factoring in the federal investment tax credit, or ITC). -PPA prices have largely followed the decline in solar’s LCOE over time, but have recently stagnated and even moved slightly higher. Prices from a sample of recent contracts average around $\$20-30$/MWh (levelized) in the West and $\$30-40$/MWh elsewhere in the continental US. -In 2022, solar’s average market value (defined in the report to include only energy and capacity value) rose by 40% to $\$71$/MWh and exceeded average wholesale prices in 4 of the 7 ISOs/RTOs and 11 of 18 other balancing authorities analyzed. -Adding battery storage is one way to increase the value of solar. Our public data file tracks metadata and PPA prices from ~100 PV+battery hybrid projects that are already online or that have secured offtake arrangements. -the end of 2022, there were at least 947 GW of utility-scale solar power capacity within the interconnection queues across the nation, 456 GW of which include batteries. For more information, and to explore related interactive data visualizations, go to utilityscalesolar.lbl.gov.
Berkeley Lab’s “Utility-Scale Solar, 2024 Edition” presents analysis of empirical plant-level data from the U.S. fleet of ground-mounted photovoltaic (PV), PV+battery, and concentrating solar-thermal power (CSP) plants with capacities exceeding 5 MWAC (PV plants of 5 MWAC or less, including residential rooftop systems, are covered separately in Berkeley Lab’s companion annual report, Tracking the Sun). Key findings from this year’s report include: -18.5 GWAC of new utility-scale PV capacity came online in 2023, bringing cumulative installed capacity to more than 80.2 GWAC across 47 states. Installed costs continued to fall in 2023. Relative to 2022, capacity-weighted averages decreased by 8% to -$\$1.43$/WAC (or $\$1.08$/WDC). Costs, based on a 7.1 GWAC sample of 76 plants completed in 2023, have fallen by 75% (averaging 10% annually) since 2010. Plant-level capacity factors vary widely, from 6% to 36% (on an AC basis), with a sample median of 24%. -Levelized cost of energy (LCOE) of new 2023 projects increased slightly to $\$46$/MWh prior to the application of tax credits but continued to fall to $\$31$/MWh when accounting for federal incentives. PPA prices have largely followed the decline in solar’s LCOE over time, but newly signed longer-term PPA prices have increased since 2021, to an average of $\$35$/MWh (levelized, in 2023 dollars). -Solar’s average energy and capacity value (i.e., ability to offset costs of other power generation sources) across the U.S. was $\$45$/MWh in 2023. Solar’s average market value was lowest in CAISO ($\$27$/MWh), the market with the greatest solar generation share, and highest in ERCOT ($\$67$/MWh). -Newer solar projects had greater market value in 2023 than their generation costs, yielding $\$1.1$ billion in benefits. Projects built in 2022 delivered on average $\$15$/MWh more market value than their costs in 2023. -Solar’s combined value from wholesale electricity markets, public health and climate damage reduction were greater than generation costs and incentives, yielding $\$13.7$ billion in net benefits in 2023. We estimate U.S. health benefits of $\$24$/MWh and reduced global climate damages of $\$101$/MWh. -Adding battery storage is one way to increase the value of solar. Deployment of 52 new PV+battery hybrid plants set a record with 5.3 GW installed in 2023. Our public data file tracks metadata and PPA prices from more than 100 PV+battery hybrid projects that are already online or that have secured offtake arrangements. -Looking ahead, a massive pipeline of at least 1,085 GW of solar capacity dominates the nation’s interconnection queues at the end of 2023. Nearly 571 GW, or 53%, of that total was paired with a battery – in CAISO it was a staggering 98%. Historically only 10% of the requested solar capacity is built. -For more information, and to explore related interactive data visualizations, go to utilityscalesolar.lbl.gov.
Rooftop solar photovoltaic systems on houses of worship can provide unique community benefits and can raise local awareness and acceptance of solar energy. Recognizing that potential, a stakeholder team selected under DOE’s Solar Energy Innovation Network is working to develop a scalable model for recruiting and installing solar PV on houses of worship in underserved communities. Berkeley Lab is providing analytical support to this stakeholder team through several work products, including this report, which provides a data-oriented overview of market activity and trends related to solar PV installations on U.S. houses of worship (HoW). Drawing on Berkeley Lab’s project-level dataset of U.S. solar PV installations, the report describes: -market size and growth trends for PV on HoW -demographic characteristics of the communities in which HoW with PV are located, including income, race and ethnicity, and educational levels -key characteristics of the PV systems installed on HoW, including system size, installed costs, prevalence of third-party ownership, and pairing with storage -characteristics of the installer network servicing PV installations on HoW The purpose of the market overview is to inform business development and policy-making efforts aimed at supporting solar adoption by HoW.
If a behind-the-meter solar photovoltaic (BTM PV) system is adopted, how does that influence the total amount of renewable electricity in its state in the long run (i.e., after the existence of the generator is reflected in the relevant utility's generation mix)? Would we expect the total amount of renewable generation to increase on a 1:1 basis with the BTM PV's generation? Or could it be something more, or something less? We show in this paper that the answer can depend on two key elements of how BTM PV is accounted for in a state’s renewable portfolio standard (RPS): (1) whether renewable energy certificates (RECs) from BTM PV can be used for RPS compliance, and (2) whether load served by generation from BTM PV counts as load covered by the RPS. These two elements combine into four possible accounting options, and we characterize the implications of each under the simplifying assumptions that the RPS is binding and the BTM PV RECs are used for compliance when allowed. For example, if load served by BTM PV generation counts toward the RPS load and BTM PV RECs cannot be used for compliance, the presence of BTM does not change the amount of RECs that the utility is required to retire, and yet additional RECs will be retired by the BTM PV owner - therefore, the total amount of renewable generation would increase on a 1:1 basis with the BTM PV generation. In contrast, under a common RPS design in which BTM PV RECs can be used for compliance and the load served by BTM PV generation is not covered by the RPS, the presence of BTM PV and transfer of RECs for compliance can actually decrease the total amount of renewable generation in the state, relative to a situation in which there is no BTM PV.
In this report, we analyze how efficiencies influence residential PV system installed system costs and break-even module prices using a bottom-up cost model. We show that the cost savings associated with efficiency are much higher for area-constrained rooftop than those which are usage-constrained. We also show that simplified models of how efficiency impacts costs overestimate the value of efficiency compared to bottom-up models, particularly for usage-constrained scenarios. We also estimate the fraction of area-constrained residential rooftops in the United States today and explore how that fraction could change in future scenarios with high levels of electrification.
This document provides a comprehensive example of the microgrid hardening framework and the Sandia developed Microgrid Hardening Design Toolkit v0.27 using a census tract in a coastal area of southern Puerto Rico as a case study. The census tract (72123953100) is located in the municipality of Salinas. Currently, the La Margarita neighborhood within this census tract is part of the Department of Energy’s Cohort 5 of the Energy Technology Innovation and Partnership Program (ETIPP). The neighborhood’s local energy cooperative, Abeyno Coop, has been operating several residential solar photovoltaic (PV) and battery energy storage system (BESS) installations (with around 30 rooftop solar systems as of 2026). As part of the ETIPP project, Abeyno Coop is planning to integrate a larger microgrid into the existing distribution feeder in the area, including solar PV and BESS to supply energy for homes and critical loads such as the medical facilities and the community center that provides emergency shelter and backup power during outages.
Despite the rapid growth of solar energy, we still lack a dynamic, high-fidelity database that tracks the spatiotemporal variations of solar PVs and their associated infrastructures across different places at a spatially resolved scale. The absence of such data presents a barrier to various applications such as solar PV growth projection, solar energy integration, solar incentive design, and climate risk assessment. In this project, we aim to bridge this gap by developing AI-based algorithms to extract granular information about solar PV installations and their associated infrastructures (i.e., distribution grids) from widely available unstructured data like remote sensing images and street views. As a result, we have built the Solar Energy Atlas, a fine-grained, large-scale geospatial overlay of distributed solar PVs and distribution grids. On top of it, we have advanced the understanding of solar adoption and distribution grid vulnerability to climate-induced extremes. Our major contributions can be summarized as follow: (1) By developing new AI algorithms, we have built the most comprehensive solar PV spatiotemporal database covering the entire US. This is the first time we obtained the exact GPS locations, size, subtype, and installation year information for rooftop solar PVs across the US. This database can be used for solar PV growth projection, solar energy integration, solar energy policy analysis and design, and spatially-resolved climate risk assessment. (2) Leveraging this database, we have uncovered the socioeconomic driving factors that are correlated with earlier onset of solar adoption and higher saturated adoption levels. We have identified the heterogeneity in the effects of different types of financial incentives on solar adoption and provided implications for tailoring incentive design based on local income levels to promote equitable solar adoption. (3) We have developed a distribution grid GIS mapping algorithm which can obtain granular geospatial and topology information about distribution grids using multi-modal open data, reducing the dependency on hard-to-obtain smart meter data of conventional approaches. It shows effectiveness in both the U.S. and Sub-Saharan Africa. Using this algorithm, we have uncovered the non-uniform vulnerability of distribution grids to wildfires in California in the aspects of undergrounding protection and Distributed Energy Resources (DER) preparedness. This has provided important implications for improving the affordability and equity of grid adaptation approaches. (3) We have made our produced database publicly available and provided user-friendly interface to enable various stakeholders and the general public to interact with the data. We have also integrated the produced data into the Data Commons platform to enable the public to access the data and correlate it with other location-specific characteristics simply using natural language as queries. The impact of our project is three-fold: (1) New algorithms for mapping solar PVs and distribution grids across space and time, which are open source to facilitate researchers and industry; (2) New databases of solar PVs and distribution grids that have been made publicly available for engineering, social, and policy applications; (3) New understandings and actionable insights on the potential approaches to promoting solar adoption and reducing energy infrastructure vulnerabilities. In this report, we start by discussing the project background and motivation (section 5), followed by the overview of project objectives (section 6). Results and discussion for each task are presented in section 7. Significant accomplishments are summarized in section 8. This report will be concluded by discussing the paths forwards (section 9), products (section 10), and team roles (section 11).
The air-glass interface at the front of a photovoltaic (PV) module reflects approximately 4% of incident light, decreasing the potential power output of the module by the same amount. Today’s modules reduce this loss by adding a low-refractive-index (1.25-1.30) SiO2 coating to the sunward side of the module glass; this antireflection coating recovers approximately 3% of the 4% light that would otherwise be lost. While such antireflection coatings work very well on clean, new modules, they do not inhibit soiling—the accumulation of soilants such as dust, pollen, soot, or other foreign material—on the module glass, and soilants reflect and scatter incident light. An improved coating would serve provide not only an antireflection effect, but also an anti-soiling effect. The goal of this project was to develop such a coating and provide a path for it to be manufactured in the U.S. The project successfully designed and fabricated coatings that provided >3% transmittance gain compared to bare glass (matching the performance of commercial antireflection coatings) and displayed anti-soiling behavior in standard laboratory soiling effects. This was achieved by using a Swift Coat proprietary coating deposition technique, aerosol impact-driven assembly (AIDA), to control the porosity and thus refractive index of coatings of photocatalytic materials—such as TiO2—that would otherwise increase (instead of decrease) reflection. These combined antireflection/anti-soiling coatings passed PV industry standard module reliability tests as well as coating-specific abrasion tests, showing that they have the durability needed for decades in the field. Swift Coat scaled the AIDA hardware and deposition process to make mini-modules that were monitored for nearly two years during field tests administered by a third party, as well as demonstrated scaling to the widths of full-sized modules. The fielded mini-modules outperformed reference modules (with commercial antireflection coatings) in two locations, providing a 1% absolute average performance boost and larger increases during periods of heavier soiling. Swift Coat’s cost analysis indicated a coating manufacturing cost below the sales price of today’s antireflection coatings. More than five module manufacturers sampled and assessed the coatings, and three provided letters of support. The coating developed in this project increases the energy output of PV modules, thereby decreasing the cost per kilowatt-hour of solar energy generated. Cheaper solar electricity benefits the public by accelerating the transition to a stable, affordable, carbon-free energy economy. In addition, for select applications in which PV modules are highly visible—such as on residential rooftops—the coating provides an aesthetic benefit because it stays cleaner than today’s modules. Finally, Swift Coat and its prospective customers are U.S. companies, and successful commercialization of this technology will provide U.S. jobs and a secure solar supply chain.
A team from the National Renewable Energy Laboratory (NREL) visited Guam in August 2023 to assess failure modes of solar photovoltaic (PV) systems after Typhoon Mawar and to provide recommendations to increase the resilience of PV systems on Guam. The team visited 30 systems: commercial and utility scale, and rooftop and ground-mounted. The team observed systems with no apparent damage, as well as systems that were completely lost. Systems fared very well overall. The average failure rate of rooftop systems was 18%, with a median failure rate of 2%, meaning the few systems that suffered total loss pulled up the average. Only eight 8 of the 25 rooftop systems suffered more than 5% damage. All ground-mounted systems suffered less than 0.5% damage, aside from a carport that lost 16% of its modules. PV systems at Andersen Air Force Base suffered 5% damage on average, with a median system failure of 0.6%. In almost all cases, failures were the result of: (1) Inadequate clamping of the module frame to the mount, (2) Module mounting clamps rotating out of underlying support rail (i.e., T-bolt that rotates free at less than 60 degrees of rotation), (3) An object hitting the panel resulting in a fracture, and in some cases leading to a cascading failure of several more panels, and (4) Excessive tilt angle (in Guam, greater than 5 degrees can be a risk due to wind speed, and power production trade-offs are insignificant).
Floating solar is a comparatively new concept. Floating solar is about to form a third pillar in the market for solar energy next to ground mounted and rooftop solar. The Asia-Pacific region already dominates the fast-emerging market in floating solar PV (FPV), and it looks set to build on that position as more nations get on board and costs fall. Asia-Pacific is set to increase its market share from 74% in 2020 to 87% in 2026 in terms of global installed FPV capacity. However, since floating solar systems are still a new application, there is a lack of information on its performance, cost, technical complexity, and operations and maintenance (O&M). This seminar series seeks to partially remedy that through presenting case studies that highlight the benefits, challenges, and applications of FPV in South and Southeast Asia.
Residential solar photovoltaic (PV) output in most states is credited at the retail electricity rate, a policy commonly known as net metering. Twelve states have replaced net metering with alternative rate structures that reduce PV adopter bill savings. Proponents of these revisions argue that net metering increases the electricity rates of customers without PV. Here, we analyze the degree to which the timelines of net metering revisions have correlated with potential electricity rate impacts. We estimate that potential rate impacts at the end of 2023 were less than 1% of typical customer bills in 37 of 44 states that have offered net metering. There are no statistically significant differences in average or median estimated rate impacts between states that have and have not revised net metering. Nine of the states that had revised net metering did so when estimated impacts were less than 1% of typical customer bills. Many states have retained net metering into higher PV deployment levels with increased risk of potential rate impacts. Only two states—California and Hawaii—retained net metering beyond estimated rate impacts of 5%, and both have revised net metering. These findings do not suggest a clear, consistent link between net metering revision timelines and potential rate impacts. The timing and nature of net metering revisions are ultimately policy decisions based on state-level priorities and considerations.
In 2014, the Mickey Leland Federal Building in Houston, Texas installed a 192 kW PV system on top of its parking structure. To monitor and optimize its performance, the General Services Administration, which manages the site, responded to the Federal Energy Management Program’s request for federal agency participation in the Federal Energy Management Program Solar PV Performance Initiative.
Over the last two decades, grid-connected solar photovoltaic systems have increased from a niche market to one of the leading power generation capacity additions annually. In 2018 the total installed photovoltaic electricity generation capacity exceeded 500 GW. Another doubling is forecasted until the early 2020s. Therefore, the further development is coupled with the question at what prices solar photovoltaic electricity can be provided and delivered to the customers. The installation of PV systems for self-consumption is already now an interesting option for many people but in general limited to those who have access to a rooftop they own or can use. A new envelopment to enable residents of multi apartment buildings to commonly use electricity generated by a PV system (collective self-consumption) is a relatively new development and is still facing a lot of administrative and regulatory challenges.
Photovoltaic (PV) panels directly convert sunlight into electricity; but, sunlight also heats the panels, negatively impacting their efficiency. Green roofs are vegetative layers grown on rooftops, mainly to provide added insulation on the roof to save energy. Green roofs also cool near-surface air temperature. Hence, the joint installation of PV panels and green roofs may potentially lead to higher efficiency of PV panels in certain climates. We develop a two-stage stochastic programming model to optimally place PV panels and green roofs under climate change uncertainty to maximize the overall profit from energy generated and saved. We calibrate the model using the literature, industry reports, and the data from different, at times conflicting, climate projections. We then conduct a case study for a mid-size city in the U.S., perform extensive sensitivity and robustness analyses and provide insights.
Twenty three small-to-large residential, commercial, and industrial PV installers submitted project-level data for analysis, which included timestamps for major components of the permitting, inspection, and interconnection process as well as contract and installation dates. NREL calculated median timelines for these processes across the authorities having jurisdiction (AHJs) and utilities represented in the data. Also included are relevant permitting requirements for AHJs and interconnection process requirements for utilities. This dataset represents the underlying results shown in the Solar Time-based Residential Analytics and Cycle time Estimator (SolarTRACE) viewer. This dataset has been reviewed but errors may exist, and it may not be comprehensive. Errors in the sources (e.g., AHJ permitting requirements lists from data partners) may be duplicated in the dataset.
Nonuniform irradiance on the rear side of bifacial photovoltaic (PV) systems can cause additional mismatch loss, which may not be appropriately captured in PV energy production estimates and software. We evaluated several scenarios including horizontal single-axis tracking (HSAT) over natural ground-cover and rooftop-mounted systems over high albedo reflective roofs. We found mismatch losses of up to 1.5% annual loss for very close-mounted (0.15 m) rooftop systems, but losses for HSAT systems and high-ground-clearance rooftop systems were lower (<0.5%). A simplified empirical relationship was found that links the spatial variation of irradiance (specifically, the mean absolute difference of irradiance) to the resulting mismatch loss factor, with an R 2 better than .99. Furthermore, this approximate relationship was experimentally validated on mismatched PV modules, and it provides a basis for rapidly estimating bifacial mismatch loss factors for use in hourly PV performance simulations such as PVSyst or SAM. Additional parameters investigated include (a) climate dependence and module orientation, which were not found to have a strong impact on bifacial mismatch losses and (b) PV module fill factor and bifaciality ratio, which did have a strong linear impact on mismatch losses.