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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.

Improving battery technology and the growth of variable renewable generation are driving a surge of interest in “hybrid” power plants that combine, for example, wind or solar generating capacity with co-located batteries. While most of the current interest involves pairing photovoltaic (PV) plants with batteries, other types of hybrid or co-located plants with wide-ranging configurations have been part of the U.S. electricity mix for decades.This annually updated briefing tracks and maps existing hybrid or co-located plants across the United States while also synthesizing data from power purchase agreements (PPAs) and generation interconnection queues to shed light on near- and long-term development pipelines. The scope includes “co-located hybrids” that pair two or more resources (e.g., multiple types of generation and/or generation with storage) that are operated largely independently behind a single point of interconnection, and “full hybrids” that also feature coordinated operations of the co-located resources. The focus is on plants with one megawatt (MW) or more of capacity; smaller (often behind-the-meter) projects are also increasingly common, but are not included in this data synthesis.Key findings from the latest briefing include:-At the end of 2023, there were 469 hybrid plants (>1 MW) operating across the United States (+21% compared to the end of 2022), totaling nearly 49 GW of generating capacity (+19%) and 3.6 GW/11.1 GWh of energy storage (+59%/+67%). PV+storage plants are by far the most common, dominating in terms of plant number (288), storage capacity (7.8 GW/24.2 GWh), storage:generator capacity ratio (54%), and storage duration (3.1 hours). But there are nearly twenty other hybrid plant configurations as well, including several different fossil hybrid categories (each dominated by the fossil component) as well as wind+storage, wind+PV, wind+PV+storage, geothermal+PV, and others.-Last year was another strong year for PV+storage hybrids in particular: 66 of the 80 hybrids added in 2023 were PV+storage. As of the end of 2023, there was roughly as much storage capacity operating within --PV+storage hybrid plants as in standalone storage plants (~7.5 GW each). In storage energy terms, however, PV+storage edged out standalone storage by ~7 GWh (24.2 GWh vs. 17.5 GWh, respectively).-Interconnection queue data show continued strong developer interest in hybridization. At the close of 2023, there were 18% more hybrid plants—representing 33% more generating capacity—in interconnection queues across the United States than there were at the end of 2022. Solar dominates these proposed plants as well: at the close of 2023, there were 599 GW of solar capacity proposed as a hybrid (representing ~55% of all solar capacity in the queues), most typically pairing PV with battery storage. At the same time, there were 51 GW of wind capacity proposed as a hybrid (representing ~14% of all wind capacity in the queues), again most-often pairing wind with storage. Meanwhile, more than half of all storage in the queues is estimated to be part of a hybrid plant. While many of the plants proposed in the queues will not ultimately reach commercial operations, the depth of interest in hybrid plants—especially PV+storage—is notable, particularly in certain regions. For example, in CAISO, 98% of all solar capacity and 34% of all wind capacity in the queues is proposed as a hybrid.-The report also surveys power purchase agreement (PPA) price data from a sample of operating and proposed PV+storage plants. PV+storage PPA prices have begun to increase, and “levelized storage adders” have recently increased as well to ~$10000/MW-month, ~$80/MWh-stored (assuming one full cycle per day), or ~$35/MWh-PV. Some of the recent price increase could simply reflect a trend towards higher battery:PV capacity ratios on the mainland over time (whereas this ratio is typically pegged at 1 to 1 in Hawaii), which will increase costs, all else being equal. The well-publicized impact of inflationary and supply chain pressures on prices in 2022 could also be a short-term contributor, though battery prices have more recently hit all-time lows.For further details on these and other findings, please refer to the short PowerPoint-style briefing, which can be downloaded here. The briefing is accompanied by two data visualizations, one focused on online plants and the other on those in interconnection queues, as well as an Excel data file with details on individual plants.

Berkeley Lab's 2024 edition of its Land-Based Wind Market Report provides an updated overview of data and trends in land-based wind energy in the U.S. Though 2023 was a relatively slow year for new wind power deployment, wind continues to see technological advancements, solid performance, and attractive prices. The Inflation Reduction Act promises new market dynamics in the years ahead, with expanded domestic manufacturing capability and an anticipated resurgence in deployment. Key highlights of the new report include:Wind comprises a significant share of electricity supply. U.S. wind power deployment was relatively low in 2023, totaling 6.5 gigawatts (GW) and representing $10.8 billion in investment. Yet wind energy contributed 10% of the nation’s electricity supply, and as much as 37% in the Southwest Power Pool. A total of 150 GW of wind was installed in the U.S. at the end of 2023. A record-high 366 GW of wind was seeking transmission interconnection.Wind turbines continue to get larger, expanding the market for wind energy. Improved plant performance over the last decades has been driven by larger turbines mounted on taller towers and featuring longer blades. In 2013, no turbines employed rotors that were 115 meters in diameter or larger, whereas 98% of newly installed turbines featured such rotors in 2023.Wind energy prices have risen but remain attractive for purchasers. Wind power purchase agreement prices have been drifting higher since about 2018, with a recent range from below $20/MWh to more than $40/MWh depending on region and other details. These prices, which are possible in part due to federal tax support, are similar to recent solar sales prices and to the projected future fuel costs of gas-fired generation.Wind’s value proposition includes grid and societal benefits. The value of wind in wholesale power markets is affected by the location of wind plants, their hourly output profiles, and how those characteristics correlate with real-time electricity prices and capacity markets. The market value of wind declined in 2023, following a drop in the price of natural gas. Wind also reduces power-sector emissions of carbon dioxide, nitrogen oxides, and sulfur dioxide. These reductions, in turn, provide public health and climate benefits that are larger than wind’s grid-system value. The combination of all three values ($183/MWh) significantly exceeded the levelized cost of wind energy in 2023.The Inflation Reduction Act has created renewed optimism for supply chain expansion. Domestic manufacturing of towers and nacelles was strong in 2023, while blade manufacturing has begun to rise after several years of decline. The Inflation Reduction Act contains, for the first time, production-based tax credits for domestic manufacturing of key wind components like nacelles, towers, and blades; it also extended the tax credit for wind deployment, inclusive of a 10% bonus for projects that meet domestic content requirements. Consequently, there have been at least 15 announcements of manufacturing facilities that plan to open, re-open, or expand to serve the land-based wind industry.Energy analysts project a resurgence of wind deployment in the years ahead. With a long-term extension of tax credits for wind energy along with opportunities for wind plants to earn two 10 percent bonus credits, analysts expect 2023 to be the low-point for wind deployment. Forecasts for wind deployment grow to an average over 15 GW/year from 2026 through 2028.

In 2023 additional electricity transmission would have provided the most value for links that crossed between grid interconnection regions in the United States (the Western Interconnection, the Eastern Interconnection, the Texas Interconnection) or crossed between system operator regions within the same interconnection. Many multi-interconnection or multi-region links had values of greater than $20/MWh, or up to $175 million/yr per 1 GW expanded transmission (subject to limits to the depth of the market at each side of the link). In contrast, many links within regions, or between regions in the northeast, had relatively low values in 2023, following the overall decline in wholesale electricity prices in 2023 compared with 2021-2022. The most valuable link in 2023, at $61/MWh, was between Texas and the Southwest. Multiple events in 2023 (high natural gas prices in the western U.S., and high summer temperatures in Texas and the Southwest) were observed to have driven this high value. Of particular note, high prices in Texas occurred at a largely distinct set of hours from high prices in the Southwest, helping to drive up the value of transmission in total and demonstrating significant value to both regions. This example demonstrates the unique value of transmission (compared to other solutions, such as building local generation resources) in delivering benefits to multiple regions given its ability to connect areas of the country that inevitably face differing circumstances.

Adoption of residential behind-the-meter solar photovoltaic-plus-storage systems (PVESS) is driven, in part, by customer demand for backup power. However, there is limited understanding of how these systems perform over a range of building stock conditions that will evolve with future efficiency and electrification trends, posing challenges for identifying optimal electric resiliency investments. This study quantifies how residential energy consumption impacts the capability of PVESS to provide home backup power during long-duration power interruptions. We model statistically representative distributions of the residential building stock and estimate storage sizes required to provide backup power as a series of building envelope efficiency, load flexibility, and electrification measures are applied. For the baseline building stock, median storage size requirements range from 10 kWh in temperate weather conditions to 90 kWh in hot climates for a 3-day power interruption. Applying energy efficiency and temperature set-point adjustments reduce storage size requirements by 2–45 kWh (16%–53 %). In hot locations, heat pump retrofits reduce median storage sizing by an additional 10–30 kWh while in cold locations, they drive 10–50 kWh of storage capacity increase. Our results suggest that bi-directional EV charging may be essential to enabling PVESS backup of heating and cooling, given their typically large kWh sizes.

Electric transmission system operators (ISOs, RTOs, or utilities) require projects seeking to connect to the grid to undergo a series of impact studies before they can be built. This process establishes what new transmission equipment or upgrades may be needed before a project can connect to the system and assigns the costs of that equipment. The lists of projects in this process are known as “interconnection queues”. The amount of new electric capacity in these queues is growing dramatically, with nearly 2,600 gigawatts (GW) of total generation and storage capacity now seeking connection to the grid (over 95% of which is for zero-carbon resources like solar, wind, and battery storage). However, most projects that apply for interconnection are ultimately withdrawn, and those that are built are taking longer on average to complete the required studies and become operational. Data from these queues nonetheless provide a general indicator for mid-term trends in developer interest.This annually updated briefing and data file compiles and analyzes interconnection queue data from all seven ISOs/RTOs alongside 44 non-ISO utilities, which collectively represent over 95% of the currently installed U.S. electric generating capacity.-The total capacity active in the queues is growing year-over-year, with over 1,570 GW of generation and an estimated 1,030 GW of storage capacity as of the end of 2023.-In total, over 1,480 GW of zero-carbon generating capacity is currently seeking transmission access. Solar (1,086 GW) accounts for the largest share of generation capacity in the queues. Substantial wind (366 GW) capacity is also seeking interconnection, 1/3 of which is for offshore projects (120 GW).-Solar and battery storage are – by far – the fastest growing resources in the queues. Combined, they account for over 80% of new capacity entering the queues in 2023.-Proposed fossil fuel generation much lower, with 79 GW of natural gas and 1.5 GW of coal currently proposed.-Hybrid projects (co-locating multiple generation and/or storage types) comprise a large – and increasing – share of proposed projects, particularly in CAISO and the non-ISO West. 571 GW of solar hybrids (primarily solar+battery) and 48 GW of wind hybrids are currently active in the queues. Over half of the battery storage capacity in the queues is paired with some form of generation (mostly solar).-However, much of this proposed capacity will not ultimately be built. Among a subset of queues for which data are available, only 19% of the projects (and 14% of capacity) seeking connection from 2000 to 2018 have been built as of the end of 2023.-Interconnection wait times are also on the rise: The typical duration from connection request to commercial operation increased from

How much should electric utilities pay to maintain a reliable electricity system? This paper describes an open-ended stated-preference experiment that generates estimates for how advanced notification impacts household willingness-to-pay (WTP) to avoid outages. We find positive and statistically significant WTP to avoid power outages of $10/kWh, consistent with the expectation that outages are costly to the residential sector. We find notification reduces the WTP, but the effects are not statistically significant. There is limited evidence that these results vary by income and wealth levels. Back-up power ownership is positively correlated with respondents’ WTP to avoid outages.

Electric transmission system operators (ISOs, RTOs, or utilities) require new large generators seeking to connect to the grid to undergo a series of impact studies before they can be built. This process establishes what new transmission equipment or upgrades may be needed before a project can connect to the system and assigns the costs of that equipment. Berkeley Lab has collected interconnection cost data for 845 projects from interconnection studies for the Southwest Power Pool (SPP) Territory. The studies were performed between 2002 and 2023 and include all of the most refined cost estimates available. Project-level cost summary data are available for download on this page.We find:-Project-specific interconnection costs can differ widely.-Average interconnection costs are stable for projects that complete all interconnection studies but have escalated for those that withdraw.-Broader network upgrade costs are the primary driver of recent cost increases, especially for withdrawn projects.-Potential interconnection costs of all solar and wind requests have been greater than those of storage and natural gas projects.-Economies of scale exist for completed wind and solar projects but not for other fuel types or withdrawn projects.-Interconnection costs vary by location.Berkeley Lab publishes a series of short analytical papers of generator interconnection costs to the transmission system for MISO, PJM, SPP, ISO-NE and NYISO, which you can find at https://emp.lbl.gov/interconnection_costs.

Proposed large-scale electric generation and storage projects must apply for interconnection to the bulk power system via interconnection queues. While most projects that apply for interconnection are not subsequently built, data from these queues nonetheless provide a general indicator for mid-term trends in developer interest. Berkeley Lab compiled and analyzed data from all seven ISOs/RTOs in concert with 35 non-ISO utilities, representing an estimated 85% of all U.S. electricity load. We include all "active" projects in these generation interconnection queues through the end of 2022, as well as data on "operational" and "withdrawn" projects where those data are available.We find that the amount of new electric capacity in these queues is growing dramatically, with over 2,000 gigawatts (GW) of total generation and storage capacity now seeking connection to the grid (over 95% of which is for zero-carbon resources like solar, wind, and battery storage). Solar (947 GW) and battery storage (~680 GW) are – by far – the fastest growing resources in the queues; combined they accounted for over 80% of new capacity entering the queues in 2022. Substantial wind (300 GW) capacity is also seeking interconnection, 38% of which is for offshore projects (113 GW). In total, about 1,250 GW of zero-carbon generating capacity is currently seeking transmission access, as is 82 GW of natural gas capacity. Hybrids projects (co-locating multiple generation and/or storage types) comprise a large – and increasing – share of proposed projects, particularly in CAISO and the non-ISO West. 457 GW of solar hybrids (primarily solar+battery) and 24 GW of wind hybrids are currently active in the queues; over half of battery storage in the queues is paired with generation.However, much of this proposed capacity will be withdrawn from the queues and not built. Among a subset of queues for which data are available, only 21% of the projects (and 14% of capacity) seeking connection from 2000 to 2017 have been built as of the end of 2022. Additionally, interconnection wait times are on the rise: The typical duration from connection request to commercial operation increased from

Electric transmission system operators (ISOs, RTOs, or utilities) require new large generators seeking to connect to the grid to undergo a series of impact studies before they can be built. This process establishes what new transmission equipment or upgrades may be needed before a project can connect to the system and assigns the costs of that equipment. Berkeley Lab has collected interconnection cost data from interconnection studies for the PJM Territory, representing nearly 86% of all new unique generators requesting interconnection from 2000 to 2022. Project-level cost summary data are available for download on this page.We find:-Average interconnection costs have grown as the number of interconnection requests have escalated-Projects that have completed all required interconnection studies have the lowest cost compared to applicants still actively working through the interconnection process or those that have withdrawn.-Broader network upgrade costs are the primary driver of recent cost increase.-Potential interconnection costs for wind, storage, and solar are larger than for natural gas-Larger generators have greater interconnection costs in absolute terms, but economies of scale exist on a per kW basis.-Interconnection costs vary by locationBerkeley Lab will publish a series of short analytical papers of generator interconnection costs to the transmission system for MISO, PJM, SPP, ISO-NE and NYISO, which you can find at https://emp.lbl.gov/interconnection_costs.

In this updated study, which samples 50% more capacity than the original and adds two additional years of operating history, we assess the performance of a fleet of 631 utility-scale PV plants totaling 31.0 GW-DC (23.6 GW-AC) of capacity that achieved commercial operations in the United States from 2007-2018 and that have operated for at least two full calendar years. We use detailed information on individual plant characteristics, in conjunction with modeled irradiance data, to model expected or “ideal” capacity factors in each full calendar year of each plant’s operating history. A comparison of ideal versus actual first-year capacity factors finds that this fleet has modestly underperformed initial expectations (as modeled) on average, though perhaps due as much to modeling issues as to actual underperformance. We then analyze fleet-wide performance degradation in subsequent years by employing a “fixed effects” regression model to statistically isolate the impact of age on plant performance. The resulting average fleet-wide degradation rate of -1.2%/year (±0.1%) represents a slight improvement (seemingly driven by the oldest plants in our sample) over the -1.3%/year (±0.2%) found in our original study, yet is still of greater magnitude than is commonly found. We emphasize, however, that these fleet-wide estimates reflect both recoverable and unrecoverable degradation across the entire plant, and so will naturally be of greater magnitude than module- or cell-level studies, and/or studies that focus only on unrecoverable degradation. Moreover, when focusing on a sub-sample of newer and larger plants with higher DC:AC ratios—i.e., plants that more-closely resemble what is being built today—we find a more moderate sample-wide average performance decline of -0.7%/year (±0.4%), which is more in line with other estimates from the recent literature.

This study focuses on one potential benefit of transmission infrastructure—congestion relief. It explores historical grid conditions from 2012 through the first half of 2022, and evaluates the marginal value of transmission in facilitating trade within and across regional boundaries by calculating differences in observed nodal wholesale power prices. The study finds that wholesale power prices exhibit stark geographic differences that, in many cases, are stable over time. Many regional and interregional transmission links have significant potential economic value from reducing congestion and expanding opportunities for trade. In fact, many links have hourly average pricing differences in 2021 that exceeded $15/MWh—equivalent to $130 million per year for a 1000 MW link. The value of transmission is correlated with overall energy prices and varies by region and year. Critically, extreme conditions and high-value periods play an outsized role in the value of transmission, with 50% of transmission’s congestion value coming from only 5% of hours. Transmission planners run the risk of understating the benefits of regional and interregional transmission if extreme conditions and high-value periods are not adequately considered. These periods are natural features of actual market operations. As such, the study highlights the need for planners to more-comprehensively assess the value of transmission under both normal and extreme conditions.

The study analyzes the evolving role of solar+storage for home backup power during long-duration power interruptions. In particular, it evaluates how required storage sizing is impacted as homes become more efficient, flexible, and electrified. The study relies on NREL’s ResStock building modeling platform to create statistically representative distributions of the existing building stock in ten locations across the United States. It then shows how the amount battery storage required for backup power rises or falls as a series of building envelope efficiency, load flexibility, and electrification measures are applied across the building stock in each region. The study also includes sensitivities to show how backup power requirements are impacted by the timing and duration of power interruptions, and explores variation in backup power requirements across the building stock within each study location.The results demonstrate the value of pairing solar+storage with efficiency upgrades, smart home controls, and (in mild winter climates) efficient heat pump retrofits. That value comes in the form of reducing the amount of storage required and/or extending the range of interruption conditions over which a given system can provide backup power (i.e., more extreme weather and/or longer interruptions). Heat pumps in cold-weather climates can pose a challenge for solar+storage backup power, given the amount of storage required, though are a vast improvement over electric-resistance heating. Retaining existing fossil-based heating systems for occasional use during power interruptions, as either the primary or supplementary source of heat, can mitigate this challenge. Other forms of building electrification (e.g., cooking and water heating) generally have marginal impacts on backup battery sizing, given their relatively small energy demand.

This technical brief estimates the expected performance of a solar photovoltaic and energy storage system (PVESS) for providing backup power during short-duration power interruption events, accounting for the unpredictable nature of those events. The analysis relies on the Power Reliability Event Simulation TOol (PRESTO), a publicly available model developed by Berkeley Lab to simulate the occurrence of short-duration power interruption events at the county-level. A separate storage dispatch model is then used to simulate PVESS operation and backup performance for each of the large number of interruption events produced by PRESTO. In performing this simulation, the analysis accounts for how the customer operates its battery on a day-to-day basis—in this case, we assume the battery is cycled each day in response to time-of-use rates—and how that, in turn, impacts the battery’s state of charge at the beginning of each interruption event. The analysis presented here is intended to demonstrate an application of the PRESTO model as well as to illustrate some of the key determinants of PVESS backup power performance during short-duration power interruption events. The analysis focuses initially on a typical single-family home in Maricopa County, Arizona, and includes a limited set of scenarios related to system sizing, backup power configuration, and whether the customer charges its battery storage system from the grid during normal operating conditions. The analysis also presents comparative results for two other counties, in Massachusetts (Middlesex) and California (Los Angeles), illustrating how regional differences in climate, interruption patterns, and retail rate structures can affect PVESS performance as a backup power source. In the conclusions, we highlight a number of other important considerations for evaluating PVESS backup power capabilities.

Improving battery technology and the growth of variable renewable generation are driving a surge of interest in “hybrid” power plants that combine, for example, wind or solar generating capacity with co-located batteries. While most of the current interest involves pairing photovoltaic (PV) plants with batteries, other types of hybrid or co-located plants with wide-ranging configurations have been part of the U.S. electricity mix for decades.This annually updated briefing tracks and maps existing hybrid or co-located plants across the United States while also synthesizing data from power purchase agreements (PPAs) and generation interconnection queues to shed light on near- and long-term development pipelines. The scope includes “co-located hybrids” that pair two or more resources (e.g., multiple types of generation and/or generation with storage) that are operated largely independently behind a single point of interconnection, and “full hybrids” that also feature coordinated operations of the co-located resources. The focus is on plants with one megawatt (MW) or more of capacity; smaller (often behind-the-meter) projects are also increasingly common, but are not included in this data synthesis.Key findings from the latest briefing include:-At the end of 2022, there were 374 hybrid plants (>1 MW) operating across the United States (+25% compared to the end of 2021), totaling nearly 41 GW of generating capacity (+15%) and 5.4 GW/15.2 GWh of energy storage (+69%/+88%). PV+storage plants are by far the most common, dominating in terms of plant number (213), storage capacity (4.0 GW/12.5 GWh), storage:generator capacity ratio (49%), and storage duration (3.1 hours). But there are nearly twenty other hybrid plant configurations as well, including several different fossil hybrid categories (each dominated by the fossil component) as well as wind+storage, wind+PV, wind+PV+storage, geothermal+PV, and others.-Last year was another strong year for PV+storage hybrids in particular: 59 of the 62 hybrids added in 2022 were PV+storage. As of the end of 2022, there was roughly as much storage capacity operating within PV+storage hybrid plants as in standalone storage plants (~4 GW each). In storage energy terms, however, PV+storage edged out standalone storage by ~2 GWh (12.5 GWh vs. 10.4 GWh, respectively).-Interconnection queue data show continued strong developer interest in hybridization. At the close of 2022, there were 51% more hybrid plants—representing 59% more generating capacity—in interconnection queues across the United States than there were at the end of 2021. Solar dominates these proposed plants as well: at the close of 2022, there were 457 GW of solar capacity proposed as a hybrid (representing ~48% of all solar capacity in the queues), most typically pairing PV with battery storage. At the same time, there were 24 GW of wind capacity proposed as a hybrid (representing ~8% of all wind capacity in the queues), again most-often pairing wind with storage. Meanwhile, more than half of all storage in the queues is estimated to be part of a hybrid plant. While many of the plants proposed in the queues will not ultimately reach commercial operations, the depth of interest in hybrid plants—especially PV+storage—is notable, particularly in certain regions. For example, in CAISO, 97% of all solar capacity and 45% of all wind capacity in the queues is proposed as a hybrid.-The report also surveys power purchase agreement (PPA) price data from a sample of operating and proposed PV+storage plants. Though PV+storage PPA prices have fallen over time, “levelized storage adders” have recently increased somewhat to ~$7000/MW-month, ~$60/MWh-stored (assuming one full cycle per day), or ~$15/MWh-PV. Some of the recent price increase could simply reflect a trend towards higher battery:PV capacity ratios over time, which increases costs, all else being equal. The well-publicized impact of inflationary and supply chain pressures on battery prices is no doubt a contributor as well.

Customer concerns over electric system resilience could drive early adoption of behind-the-meter solar-plus-storage (BTM PVESS), especially as wildfire, hurricane, and other climate-driven risks to electric grids become more pronounced. However, the resilience benefits of BTM PVESS are poorly understood, especially for residential customers, owing to lack of data and methodological challenges, making it difficult to forecast adoption trends. In this paper, we develop a methodology to model the performance of BTM PVESS in providing backup power across a wide range of customer types, geography / climate conditions, and long duration power interruption scenarios, considering both whole-building backup and backup of specific critical loads. We combine novel, disaggregated end-use load profiles across the continental United States with temporally and geospatially aligned solar generation estimates. We then implement a PVESS dispatch algorithm to calculate the amount of load served during interruptions. We find that PVESS with 10 kWh of storage can meet a limited set of critical loads in most United States counties during any month of the year, though this capability drops to meeting only 86% of critical load, averaged across all counties and months, when heating and cooling are considered critical. Backup performance is lowest in winter months where electric heat is common (southeast and northwest U.S.) and in summer months in places with large cooling loads (southwest and southeast U.S.). Winter backup performance varies by roughly 20% depending on infiltration rates, while summer performance varies by close to 15% depending on the efficiency of the central air-conditioning system. Differences in temperature set-points in Harris County correspond to a 40% range in winter backup performance and a 20% range in summer performance. Economic calculations show that a customer's resilience value of PVESS must be high to motivate adoption of these systems.

Electric transmission system operators (ISOs, RTOs, or utilities) require new large generators seeking to connect to the grid to undergo a series of impact studies before they can be built. This process establishes what new transmission equipment or upgrades may be needed before a project can connect to the system and assigns the costs of that equipment. Berkeley Lab has collected interconnection cost data for 194 projects in New England from interconnection studies performed between 2010 and 2021. Project-level cost summary data are available for download on this page.We find:-Interconnection costs have grown over time, especially for projects that withdraw.-Interconnection costs are highest for onshore wind, followed by solar and storage. Natural gas and offshore wind projects tend to cost less to interconnect, in comparison.-Economies of scale exist for solar and possibly storage projects, but not for other resource types.-Wind and solar projects requesting capacity network resource interconnection service have higher interconnection costs, despite being evaluated using the same interconnection standard in the analyzed studies.-Low and high interconnection costs can be found throughout the ISO-NE footprint.-Costs are split fairly evenly between investments at the point of interconnection and within the broader network for active and withdrawn projects, while complete projects incur most costs at the point of interconnection.

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.

Studies show that a diverse portfolio of zero-carbon resources will be needed to decarbonize the U.S. electricity sector, and that high capacity factor resources like geothermal will become particularly important in later stages of decarbonization as the capacity contribution of variable, weather-dependent resources like wind and solar declines with increasing market penetration. Yet while wind, solar, and—more recently—storage have all seen significant U.S. deployment in recent years, deployment of new geothermal plants has barely budged over the same period. We explain this disparity in historical deployment by analyzing empirical price data from power purchase agreements (PPAs) and wholesale energy and capacity markets, which demonstrate that geothermal has historically offered a lower “net value” (i.e., wholesale market value minus PPA price) than these other resources. Looking ahead through 2026, continued growth in the market share of wind, solar, and storage should improve geothermal's relative market value, yet likely not by enough to overcome the persistent cost gap between geothermal and these other, lower-cost resources. In the face of this challenging market outlook, policy intervention and continued R&D investments may be warranted to sustain a vibrant geothermal industry that stands ready to contribute to the late stages of decarbonization.

Electric transmission system operators (ISOs, RTOs, or utilities) require new large generators seeking to connect to the grid to undergo a series of impact studies before they can be built. This process establishes what new transmission equipment or upgrades may be needed before a project can connect to the system and assigns the costs of that equipment. Berkeley Lab has collected interconnection cost data from interconnection studies for the Midcontinent Independent System Operator (MISO), representing nearly 50% of all projects requesting interconnection from 2010 to 2020. Project-level cost summary data are available for download on this page.We find:-Average interconnection costs have grown as the number of interconnection requests have escalated-Projects that have completed all required interconnection studies have the lowest cost compared to applicants still actively working through the interconnection process or those that have withdrawn.-Broader network upgrade costs are the primary driver of recent cost increase.-Potential interconnection costs for wind, storage, and solar are larger than for natural gas-Larger generators have greater interconnection costs in absolute terms, but economies of scale exist on a per kW basis.-Interconnection costs vary by locationBerkeley Lab will publish a series of short analytical papers of generator interconnection costs to the transmission system for MISO, PJM, SPP, ISO-NE and NYISO, which you can find at https://emp.lbl.gov/interconnection_costs.

The study estimates the performance of behind-the-meter solar PV-plus-energy-storage-systems (PVESS) in providing critical-load or whole-building backup across a wide range of geographies, building types, and power interruption conditions. The study also considers a set of 10 historical long-duration power outage events and evaluates how PVESS could have performed in providing backup power during those specific events. The analysis is the first in what will be a series of studies by Berkeley Lab, in collaboration with the National Renewable Energy Laboratory, on the use of PVESS for backup power. This initial study, which relies on simulated end-use level building loads, solar generation, and storage dispatch, is intended to provide a baseline set of performance estimates and to illustrate key performance drivers.

The U.S. Department of Energy's 2022 edition of its Land-Based Wind Market Report provides an overview of key trends in the U.S. wind power market, with a focus on 2021. You can find a report, data file and presentation on the Files tab, below. Additionally, several data visualizations are available on the Visualizations tab.Despite ongoing supply chain challenges, wind energy in 2021 continued to see strong growth, technology improvements, and low prices in the U.S. Key highlights include:Wind comprises a growing share of electricity supply: U.S. wind power capacity grew at a strong pace in 2021, with the 13.4 GW of new additions representing a $20 billion investment and 32% of all newly added U.S. generation capacity. Wind energy output rose to account for more than 9% of the entire nation’s electricity supply. At least 247 GW of wind are seeking transmission interconnection; 77 GW of this capacity are offshore wind and 19 GW are hybrid plants that pair wind with storage or solar PV.Wind project performance has increased over the decades: The average capacity factor among recently built projects was nearly 40%, considerably higher than projects built earlier. The highest capacity factors are seen in the interior ‘wind belt’ of the country.Turbines continue to get larger: Improved plant performance has been driven by larger turbines mounted on taller towers and featuring longer blades. In 2011, no turbines employed blades that were 115 meters in diameter or larger, but in 2021, 89% of newly installed turbines featured such rotors. Proposed projects indicate that total turbine height will continue to rise.Low wind turbine pricing has pushed down installed project costs over the last decade: Wind turbine prices averaged $800–$950/kW in 2021, a 5% to 10% increase from the year prior but substantially lower than in 2010. The average installed cost of wind projects in 2021 was $1,500/kW, down more than 40% since the peak in 2010, though relatively stable in recent years. The lowest costs were found in Texas and the (non-ISO) West.Wind energy prices are on the rise, but generally remain low, around $20/MWh in the interior of the country with higher prices in the West and East. After topping out above $75/MWh for power purchase agreements (PPAs) executed in 2009, the national average price of wind PPAs has dropped—though supply-chain pressures have resulted in increased prices in recent years. In the interior ‘wind belt’ of the country, recent pricing is around $20/MWh. In the West and East, prices tend to average above $30/MWh. These prices, which are possible in part due to federal tax support, fall below the projected future fuel costs of gas-fired generation.Wind PPA prices are often attractive compared to wind’s grid-system market value: The value of wind in wholesale power markets is affected by the location of wind plants, their hourly output profiles, and how those characteristics correlate with real-time electricity prices and capacity markets. The market value of wind increased in 2021, averaging $16/MWh in MISO, $19/MWh in SPP, $23/MWh in NYISO, $31/MWh in ERCOT, $33/MWh in PJM, $44/MWh in ISO-NE, and $48/MWh in CAISO.The average levelized cost of wind energy was $32/MWh for plants built in 2021: Levelized costs, which exclude the impacts of federal tax incentives, vary across time and geography. The national average stood at $32/MWh in 2021—down substantially historically, though relatively stable in recent years. Levelized costs were lowest in ERCOT, SPP, and the (non-ISO) West.The health and climate benefits of wind in 2021 were larger than its grid-system value, and the combination of all three far exceeds the current levelized cost of wind: Wind generation reduces power-sector emissions of carbon dioxide, nitrogen oxides, and sulfur dioxide. These reductions, in turn, provide public health and climate benefits that vary regionally, but together are economically valued at an average of over $90/MWh-wind for plants built in 2021.

Falling battery prices and the growth of variable renewable generation are driving a surge of interest in “hybrid” power plants that combine, for example, wind or solar generating capacity with co-located batteries. While most of the current interest involves pairing photovoltaic (PV) plants with batteries, other types of hybrid or co-located plants with wide-ranging configurations have been part of the U.S. electricity mix for decades.This annually updated briefing tracks and maps existing hybrid or co-located plants across the United States while also synthesizing data mined from power purchase agreements (PPAs) and generation interconnection queues to shed light on near- and long-term development pipelines. The scope includes co-located hybrid plants that pair two or more generators and/or that pair generation with storage at a single point of interconnection, and full hybrids that feature co-location and co-control. The focus is on plants with one megawatt (MW) or more of capacity; smaller (often behind-the-meter) projects are also increasingly common, but are not included in this data synthesis.Key findings from the latest briefing include:-At the end of 2021, there were nearly 300 hybrid plants (>1 MW) operating across the United States, totaling nearly 36 gigawatts (GW) of generating capacity and 3.2 GW/8.1 GWh of energy storage. PV+storage plants are by far the most common, dominating in terms of plant number (140), storage capacity (2.2 GW/7.0 GWh), storage:generator ratio (53%), and storage duration (3.2 hours). But there are nearly twenty other hybrid plant configurations as well, including several different fossil hybrid categories (each dominated by the fossil component) as well as wind+storage, wind+PV, wind+PV+storage, geothermal+PV, and others.-Last year was a breakout year for PV+storage hybrids in particular: 67 of the 74 hybrids added in 2021 were PV+storage. By the end of 2021, there were more GW of battery capacity installed in PV+storage hybrids (2.2 GW) than as standalone storage plants (1.8 GW). The difference is even starker in energy terms, with PV+storage plants hosting twice as much battery capacity as standalone storage plants (7 GWh vs. 3.5 GWh, respectively). Much of the battery capacity added in hybrid form in 2021 was a battery retrofit to a pre-existing PV plant.-Data on plants under development from the interconnection queues of all seven ISOs/RTOs plus 35 individual utilities suggest that these hybridization trends are likely to continue. At the close of 2021, there were more than 670 GW of solar plants in the nation’s queues; 285 GW (~42%) of this capacity was proposed as a hybrid, most typically pairing PV with battery storage (PV+storage represented nearly 90% of all hybrid capacity in the queues). For wind, 247 GW of capacity sat in the queues, with 19 GW (~8%) proposed as a hybrid, again most-often pairing wind with storage (wind+storage represented ~4% of all hybrid capacity in the queues). Meanwhile, nearly half of all storage in the queues is estimated to be part of a hybrid plant. While many of these proposed plants will not ultimately reach commercial operations, the depth of interest in hybrid plants—especially PV+storage—is notable.-The report also surveys power purchase agreement (PPA) price data from a sample of operating and proposed PV+storage plants. Though PV+storage PPA prices have fallen over time, “levelized storage adders” have recently increased somewhat to ~$5500/MW-month, ~$45/MWh-stored (assuming one full cycle per day), or ~$15/MWh-PV. Some of the recent price increase could simply reflect a trend towards higher battery:PV capacity ratios over time, which increases costs, all else being equal. The well-publicized impact of inflationary and supply chain pressures on battery prices is no doubt a contributor as well.For further details on these and other findings, please refer to the short PowerPoint-style briefing, which can be downloaded here. The briefing is accompanied by two data visualizations, one focused on online plants and the other on those in interconnection queues, as well as an Excel data file with details on individual plants.

This research estimates the economic value of standalone and hybrid (battery-paired) variable renewable energy (VRE) participation in ancillary services (AS) markets, from resource owner and electricity system perspectives, in each of the seven U.S. independent system operator and regional transmission organization (ISO/RTO) markets. Across ISO/RTO markets, average (2015-2019) simulated incremental revenues from 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. In most markets, standalone and hybrid VRE were able to provide regulation reserves during periods with high regulation prices, suggesting that VRE participation in AS markets could have high system value. The analysis highlights the value of separate upward and downward regulation products and suggests that ISOs/RTOs might consider initially focusing on enabling hybrid VRE provision of AS.

One of the most important electric power system trends of the 2010s was the rapid deployment of wind turbines and photovoltaic arrays, but a twist for the 2020s may be the rapid deployment of ‘hybrid’ generation resources. Hybrid power plants typically combine solar or wind (or other energy sources) with co-located storage. While hybridization helps to ease the challenge of balancing variable supply and demand, its relative novelty means that research is needed to facilitate integration and promote innovation. Combining the characteristics of multiple energy, storage, and conversion technologies poses complex questions for grid operations and economics. Project developers, system operators, planners, and regulators would benefit from better data, methods, and tools to estimate the costs, values, and system impacts of hybrid projects. This publication showcases some of Berkeley Lab’s robust research program intended to support private- and public-sector decision-making about hybrid plants in the United States. Our short briefing summarizes articles that we published between 2020 and 2022, links to the in-depth reports, and provides contact details for further engagement on the specific research topics:Growth: Developer interest in hybrid power plants is strong and growingPrice vs. Value: PV+storage hybrids have low PPA prices and high value in some regionsMarket Drivers: Solar hybridization is driven by tax credits and other benefitsConfiguration Choices: Market prices have incentivized shorter duration batteries with PVCapacity Value: The capacity contribution of a hybrid is less than the sum of its partsAncillary Services: AS markets are a valuable yet fleeting option for hybridsMarket Participation: Hybrids can more flexibly engage with electricity marketsOperations: The power system value of hybrids depends on how they are operatedDistributed Hybrids: Growth of customer-sited PV+storage hybrids offers new opportunitiesFuture Research: Where next? Priority areas for hybrid power research

Proposed large-scale electric generation and storage projects must apply for interconnection to the bulk power system via interconnection queues. While most projects that apply for interconnection are not subsequently built, data from these queues nonetheless provide a general indicator for mid-term trends in developer interest. Berkeley Lab compiled and analyzed data from all seven ISOs/RTOs in concert with 35 non-ISO utilities, representing an estimated 85% of all U.S. electricity load. We include all "active" projects in these generation interconnection queues through the end of 2021, as well as data on "operational" and "withdrawn" projects where those data are available.We find that the amount of new electric capacity in these queues is growing dramatically, with over 1,400 gigawatts (GW) of total generation and storage capacity now seeking connection to the grid (over 90% of which is for zero-carbon resources like solar, wind, and battery storage). Solar (676 GW) and battery storage (~420 GW) are – by far – the fastest growing resources in the queues; combined they accounted for nearly 85% of new capacity entering the queues in 2021. Substantial wind (247 GW) capacity is also seeking interconnection, 31% of which is for offshore projects (77 GW). In total, about 930 GW of zero-carbon generating capacity is currently seeking transmission access, as is 74 GW of natural gas capacity. Hybrids now comprise a large – and increasing – share of proposed projects, particularly in CAISO and the non-ISO West. 286 GW of solar hybrids (primarily solar+battery) and 19 GW of wind hybrids are currently active in the queues; nearly half of battery storage in the queues is paired with generation.However, much of this proposed capacity will be withdrawn from the queues and not built. Among a subset of queues for which data are available, only 23% of the projects seeking connection from 2000 to 2016 have subsequently been built. Completion percentages appear to be declining and are even lower for wind and solar than other resources. Additionally, wait times are on the rise: for the regions with available data, the typical duration from connection request to commercial operation increased from ~2.1 years for projects built in 2000-2010 to ~3.7 years for those built in 2011-2021.

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.

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.

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.

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.

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 revenues 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 resource owner and electricity system perspectives, in each of the seven U.S. independent system operator and regional transmission organization (ISO/RTO) markets. Across ISO/RTO markets, average (2015-2019) simulated incremental revenues from 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 were able to provide regulation reserves during periods with high regulation prices, suggesting that VRE participation in AS markets could have high system value. The analysis highlights the value of separate upward and downward regulation products and suggests that ISOs/RTOs might consider initially focusing on enabling hybrid VRE provision of AS.

The U.S. Department of Energy's 2021 edition of its land-based wind market report provides an overview of key trends in the U.S. wind power market, with a focus on 2020. You can find a report, data file and presentation on the Files tab, below. Additionally, several data visualizations are available on the Visualizations tab. Highlights of this year’s update include:-Wind comprises a growing share of electricity supply: U.S. wind power capacity grew at a record pace in 2020, with $25 billion invested in 16.8 GW of capacity. Wind energy output rose to account for more than 8% of the entire nation’s electricity supply, and is more than 20% in 10 states. At least 209 GW of wind are seeking transmission interconnection; 61 GW of this capacity are offshore wind and 13 GW are hybrid plants that pair wind with storage or PV.-Wind project performance has increased over time: The average capacity factor among recently built projects was over 40%, considerably higher than projects built earlier. The highest capacity factors are seen in the interior ‘wind belt’ of the country.-Turbines continue to get larger: Improved plant performance has been driven by larger turbines mounted on taller towers and featuring longer blades. In 2010, no turbines employed blades that were 115 meters in diameter or larger, but in 2020, 91% of newly installed turbines featured such rotors. Proposed projects indicate that total turbine height will continue to rise.-Low wind turbine pricing has pushed down installed project costs over the last decade: Wind turbine prices are averaging $775–$850/kW. The average installed cost of wind projects in 2020 was $1,460/kW, down more than 40% since the peak in 2010, though stable for the last three years. The lowest costs were found in Texas and the (non-ISO) West.-Wind energy prices remain low, around $20/MWh in the interior of the country: After topping out at $70/MWh for power purchase agreements (PPAs) executed in 2009, the national average price of wind PPAs has dropped. In the interior ‘wind belt’ of the country, recent pricing is around $20/MWh. In the West and East, prices tend to average $30/MWh or more. These prices, which are possible in part due to federal tax support, fall below the projected future fuel costs of gas-fired generation.-Wind PPA prices are often attractive compared to wind’s grid-system market value: The value of wind in wholesale power markets is affected by the location of wind plants, their hourly output profiles, and how those characteristics correlate with real-time electricity prices and capacity markets. The market value of wind declined in 2020, following natural gas prices lower and averaging under $15/MWh in ERCOT, MISO, NYISO and SPP; higher values were seen in CAISO, ISO-NE and PJM.-The average levelized cost of wind energy is down to $33/MWh: Levelized costs, which exclude the impacts of federal tax incentives, vary across time and geography, but the national average stood at $33/MWh in 2020—down substantially historically, though consistent with the previous two years. Levelized costs were lowest in ERCOT, SPP, and the (non-ISO) West.-The health and climate benefits of wind in 2020 were larger than its grid-system value, and the combination of all three far exceeds the current levelized cost of wind: Wind generation reduces power-sector emissions of carbon dioxide, nitrogen oxides, and sulfur dioxide. These reductions, in turn, provide public health and climate benefits that vary regionally, but together are economically valued at an average of $76/MWh-wind nationwide in 2020.-The domestic supply chain for wind equipment is diverse: For wind projects recently installed in the U.S., domestically manufactured content is highest for nacelle assembly (>85%), towers (60-75%), and blades and hubs (30-50%), but is much lower for most components internal to the nacelle.

Falling battery prices and the growth of variable renewable generation are driving a surge of interest in “hybrid” power plants that combine, for example, wind or solar generating capacity with co-located batteries. While most of the current interest involves pairing photovoltaic (PV) plants with batteries, other types of hybrid or co-located plants with wide-ranging configurations have been part of the U.S. electricity mix for decades. This updated briefing tracks and maps existing hybrid or co-located plants across the United States while also synthesizing data mined from power purchase agreements (PPAs) and generation interconnection queues to shed light on near- and long-term development pipelines. The scope includes co-located hybrid plants that pair two or more generators and/or that pair generation with storage at a single point of interconnection, and also full hybrids that feature co-location and co-control. The focus is on larger, 1 MW+ systems; smaller (often behind-the-meter) projects are also increasingly common, but are not included in this data synthesis. Based in part on Form EIA-860 data, there were at least 226 co-located hybrid plants (>1 MW) operating across the United States at the end of 2020, totaling more than 30 GW of aggregate capacity. Among these operating plants, the most common configuration is PV+storage (with 73 projects totaling 992 MW of PV and 250 MW of storage), followed by several different fossil hybrid categories (fossil+PV, fossil+hydro, and fossil+storage plants—each dominated by the fossil component) and 14 wind+storage plants (with 1,425 MW wind and 198 MW of storage). But there are roughly a dozen other configurations as well, including wind+PV, wind+PV+storage, biomass+hydro, geothermal+PV, and others. Data on projects under development within interconnection queues across the country demonstrate considerable commercial interest in hybrid power plants, and especially in PV+storage. At the close of 2020, there were more than 460 GW of solar plants in the nation’s queues; 159 GW (~35%) of this capacity was proposed as a hybrid, most typically pairing PV with battery storage. For wind, 209 GW of capacity sat in the queues, with 13 GW (~6%) proposed as a hybrid, again most-often pairing wind with storage. While many of these specific projects will not ultimately reach commercial operations, the depth of interest in hybrid projects—especially PV+storage—is notable. To get a better sense for what the near-term hybrid pipeline looks like, we also track data on PV+battery plants that have announced offtake arrangements. A sample of 134 such projects suggests that the near-term development pipeline features longer storage durations and higher battery-to-PV capacity ratios than are seen among existing hybrids. DC-coupled battery configurations will also likely become more common, and a subset of these DC-coupled plants (particularly those in Hawaii) plan to employ very high DC:AC ratios and store the otherwise-clipped power, leading to expected AC capacity factors in excess of 40%. Finally, PPA prices from a subset of these PV+battery plants reveal that the cost of adding storage increases linearly with the battery:PV capacity ratio, and that PPA prices have declined over time despite increasing (on the mainland) or stable (in Hawaii) battery:PV capacity ratios.

As the distributed solar market evolves toward more dynamic forms of deployment, interest in paired solar-plus-storage applications continues to gain steam, but details on the current state of the market are relatively sparse. To fill that void, Berkeley Lab has released an in-depth analysis of this budding market segment. This report draws on the Lab’s Tracking the Sun dataset to characterize trends in deployment, system sizing and equipment selection, installer-market development, and system pricing. The report also provides indicative analyses of the financial and resilience value that host customers in several key markets presently receive by pairing storage with solar.

Across multiple organized wholesale power markets in the United States, annual average prices declined by $19–64/MWh between 2008 and 2017 while retirements of thermal power plants accelerated. Several prominent changes over the last decade are often discussed as contributors to this decline in prices. These include growth in wind and solar, a reduction in the price of natural gas, and weakened load growth. Here we construct a fundamental supply curve model for each of seven organized wholesale market regions and use counterfactual simulations to assess the degree to which wind and solar—among other factors—have influenced wholesale electricity prices. We find that growth in wind and solar since 2008 reduced average annual wholesale electricity prices by less than $3/MWh. In contrast the decline in natural gas prices reduced wholesale prices by $7–53/MWh, depending on the region. This suggests that recent thermal-plant retirements in the U.S. are primarily due to low natural gas prices, not growth in wind and solar. Fully isolating the impact of individual factors, however, is limited by non-linear interactions between factors.

Highlights from Berkeley Lab’s 2020 update of land-based wind technology data and trends include:-More than 9 gigawatts of new wind power capacity, representing an investment of $13 billion, was installed in the U.S. in 2019. Wind energy output rose to more than 7% of the entire nation’s electricity supply, more than 10% in fourteen states, and more than 40% in two of those states—Iowa and Kansas. At least 225 gigawatts of wind are seeking transmission interconnection, 5% of which are paired with storage.-The average 2019 capacity factor among projects built from 2014 through 2018 was 41%, compared to an average of 31% among projects built from 2004 to 2012 and 25% among projects built from 1998 to 2001.-Improved plant performance has been driven, in part, by larger turbines mounted on taller towers and featuring longer blades. The area swept by the average wind turbine rotor has more than doubled since 2010, compared to a 42% increase in average turbine capacity and a 13% increase in average hub height. Project applications submitted to the FAA suggest that total turbine height (tower plus blade length) will continue to rise in the years ahead.-Wind turbine prices have fallen to $700–$850/kW. The average installed cost of wind projects in 2019 was $1,440/kW, down more than 40 percent since the peak in 2009 and 2010.-After topping out at 7¢/kWh for power purchase agreements (PPAs) executed in 2009, the national average price of wind PPAs has dropped to below 2¢/kWh—though this nationwide average is dominated by projects that hail from the low-priced interior of the country, where the wind resource is strongest. This sub-2¢/kWh average, which is possible in part due to federal tax support, falls below the projected future fuel costs of gas-fired generation. Utility-scale solar PPA prices have also declined precipitously, pressuring wind’s competitive position.-The levelized cost of wind energy, which does not reflect the federal production tax credit, was in the mid-$30/MWh range in 2019, down from the $85-90/MWh range seen a decade ago.-The value of wind in wholesale power markets is affected by the location of wind plants, their hourly output profiles, and how those characteristics correlate with real-time electricity prices and capacity markets. The market value of wind in 2019 was lowest in the Southwest Power Pool and ERCOT (averaging $15/MWh and $16/MWh, respectively) whereas the highest-value market was CAISO (at $37/MWh). Wind energy PPA prices are generally competitive with these value estimates.-For wind projects recently installed in the U.S., domestically manufactured content is highest for nacelle assembly (>90%), towers (65-85%), and blades and hubs (40-70%), but is much lower for most components internal to the nacelle.-With federal tax incentives still available, various forecasts for the domestic market show expected wind power capacity additions of more than 10 gigawatts in 2020, with some contraction anticipated in the years ahead as those tax incentives are phased out.

We assess the performance of a fleet of 411 utility-scale (i.e., >5 MWAC and ground-mounted) photovoltaic (PV) projects totaling 21.1 GWDC (16.3 GWAC) of capacity, which achieved commercial operations in the United States from 2007 to 2016. This fleet of projects contributed more than 50% of all solar electricity generated in the United States in 2017. Using detailed information on individual project characteristics, in conjunction with modeled irradiance data, we assess the extent to which actual first-year performance has lived up to both modeled and stated expectations. We then analyze system-level performance degradation in subsequent years by employing a "fixed effects"regression model to statistically isolate the impact of age on system performance. We find that this fleet of utility-scale PV projects has generally lived up to ex ante expectations for first-year performance but that subsequent system-level degradation - found to be -1.3%/year (±0.2%) - has, on average, been worse than both ex ante expectations (commonly -0.5%/year) and results from past studies (ranging from -0.8%/year to -1.0%/year). We emphasize that -1.3%/year is a system-level estimate that captures more than just module degradation (e.g., including soiling, balance of plant degradation, and downtime for maintenance and/or other events). A side analysis of a variety of project characteristics suggests that system-level degradation rates tend to be of lower magnitude among newer projects and larger projects and at sites with lower long-term average temperatures.

Growth in U.S. utility-scale hybrid battery projects suggests potential advantages currently outweigh disadvantages. Today's 4.6 GW of hybrid capacity is accompanied by 14.7 GW in the immediate development pipeline, and 69 GW in select interconnection queues. Analysis using wholesale market prices finds that additional revenues from adding a 4-hour battery to solar can exceed additional costs. However, realizing hybrid projects’ full value depends on nascent strategies for integrating them in current/future wholesale market design paradigms.

Estimating the overall costs of transmission needed to integrate variable renewable energy (VRE) onto the grid is challenging. An improved understanding of these transmission costs would support electricity system planning as VRE penetrations increase. This paper brackets VRE transmission capital costs using multiple approaches based on interconnection studies, actual transmission projects, capacity-expansion simulation models, and aggregated U.S. VRE-related transmission expenditures. Each approach possesses advantages and drawbacks, and combining the approaches lends confidence to the results. The resulting range of average levelized VRE transmission costs is $1–$10/MWh, which is generally lower than earlier estimates in the literature. These transmission capital costs can increase the direct plant-level levelized cost of VRE by 3%–33%, based on levelized costs of energy of $29–$56/MWh for utility-scale wind and $36–$46/MWh for utility-scale solar. As VRE deployment continues to expand, policy makers can use this information to (1) assess the benefits of transmission avoidance and deferral when comparing distributed energy resources versus utility-scale projects, (2) evaluate the potential costs of large-scale public transmission investments, and (3) better analyze system-level costs of utility-scale VRE technologies. Future research can expand on the framework presented here by providing a review of operation and maintenance costs for transmission systems.

Wholesale power markets have evolved. Some of the most prominent changes over the last decade in the United States include growth in wind and solar, a reduction in the price of natural gas, weakened load growth, and an increase in the retirement of thermal power plants. Here we empirically assess the degree to which wind and solar—among other factors—have influenced wholesale electricity prices. We show that wind and solar have contributed to reductions in overall average annual wholesale electricity prices since 2008, but that natural gas prices have had the largest impact. More notable is that expansion of variable renewable energy has led to significant changes in locational, time of day, and seasonal pricing patterns in some regions. These altered pricing patterns reflect a fundamental shift, and hold important implications for the grid-system value of wind and solar, and for other electric-sector planning and operating decisions.

Distributed solar photovoltaic (DPV) under net-energy metering with volumetric retail electricity pricing has raised concerns among utilities and regulators about adverse financial impacts for shareholders and ratepayers. Using a pro forma financial model, we estimate the financial impacts of different DPV deployment levels on a prototypical Western U.S. investor-owned utility under a varied set of operating conditions that would be expected to affect the value of DPV. Our results show that the financial impacts on shareholders and ratepayers increase as the level of DPV deployment increases, though the magnitude is small even at high DPV penetration levels. Even rather dramatic changes in DPV value result in modest changes to shareholder and ratepayer impacts, but the impacts on the former are greater than the latter (in percentage terms). The range of financial impacts are driven by differences in the amount of incremental capital investment that is deferred, as well as the amount of incremental distribution operating expenses that are incurred. While many of the impacts appear relatively small (on a percentage basis), they demonstrate how the magnitude of impacts depend critically on utility physical, financial, and operating characteristics.