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This paper proposes a stochastic model for hybrid power plants participation in day-ahead electricity markets, considering uncertainty in market prices and renewable generation. Additionally, it presents a methodology to incorporate this hybrid participation into existing production cost models (PCM), allowing the analysis and market design of future systems with high penetration of hybrids. These developments are illustrated using a wind-battery hybrid located in New York Independent System Operator (NYISO) footprint.

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.

Transmission congestion can cause a divergence between wholesale power prices at the individual pricing nodes where power is generated and the more-liquid trading hubs where that power is often delivered and sold. This nodal price difference is commonly referred to as the 'locational basis' (or just 'basis'). Because the basis varies over time, it can--if not hedged--unpredictably affect a wind plant's revenue and/or value, which increases investor risk and potentially slows deployment. We find wind plants typically face a larger and more-negative basis than do thermal generators, and hence are more-negatively impacted by congestion. Moreover, while most thermal generators can effectively hedge basis risk by purchasing conventional fixed-volume financial transmission rights (FTRs), these fixed-volume FTRs do not effectively hedge basis risk for variable wind generation. More-effective hedging mechanisms may be required to support those generators most-impacted by congestion, and to promote continued investment in variable generation resources in congested markets. Keywords: Renewable energy, Financial transmission rights, Basis risk, 1. INTRODUCTION Clean energy deployment continues worldwide, primarily from variable renewable energy sources whose resource quality depends on location and whose output varies with the weather (IEA 2020; Kueppers et [...]

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

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.

PV-battery hybrid projects dominate interconnection queues in some regions in the United States. But few large-scale projects have been in use long enough to assess how the hybrid capabilities may be used in practice and the existing literature scantly discusses observed operational strategies. We interview plant operators and analyze empirical dispatch data for eleven large-scale PV-battery hybrids in three organized wholesale markets in the United States. We estimate the market value of our sample hybrids in 2020. The empirical increase in market value of a PV-battery hybrid relative to a standalone PV plant varies by project and ranges from $1 to $48/MWhsolar, often aided by a large boost in capacity value. This premium is driven by market, location, technical characteristics of the PV and battery asset, and battery dispatch strategies. In contrast to the widespread assumptions in the PV-battery hybrid modeling literature, only three of the eleven project operators optimize battery usage for wholesale market revenue as merchant plants. Instead, load-serving entities target peak load reductions, incentive program participants focus on compliance with program requirements, and large energy consumers prioritize resiliency and utility bill minimization. These alternative business models can result in high revenues for the project operators, but do not optimize the storage dispatch from a grid perspective. Understanding real-world dispatch signals and aligning them closer with system-wide grid needs will be important for electric grid operators and system planners, and can increase the market value of PV-battery hybrids.

As solar energy contributes an increasing share of total electricity generation, solar forecasting errors become important relative to overall load uncertainty and can add costs to electricity systems. We investigated the costs of day-ahead solar forecast errors across 667 existing solar power plants in the United States (years 2012 through 2019). Our analysis was based on hourly real-time and day-ahead nodal prices. We analyzed two types of solar forecasts: persistence forecasts, a simple approach to forecasting, and a numerical weather prediction forecast, the North American Mesoscale Model (NAM), an improvement over persistence forecasts based on public data and modelling software. We modeled hourly energy forecasts using meteorological forecasts and plant specific characteristics. Hourly plant generation was modeled and debiased with multiple sources of generation records. NAM forecast errors had relatively low costs on average, at no more than $1/MWh in all years except 2016, when costs rose to $1.5/MWh. Even after these error costs, the value of solar was marginally higher when simulating solar participation in day-ahead markets versus participation only in real-time markets. On average, the premium for participating in the day-ahead market, based on NAM forecasts, ranged from −0.5 to 5.2 $/MWh across years. Average error costs were higher in regions with higher solar penetration (i.e., California and New England) compared to regions with low solar penetration. However, California and New England had similar error costs despite higher solar penetration in California, indicating that error costs to date have been only loosely correlated with solar penetration levels.

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.

NREL’s Cambium tool generates forward-looking simulations of marginal wholesale electricity costs associated with NREL’s Standard Scenarios. The scenarios include growing shares of variable renewable energy (VRE, i.e. wind and solar), among other power sector assumptions, between 2018 and 2050. The tool’s primary output—hourly costs at more than 130 balancing areas—could serve as public and transparent data source that supports electric-sector decision-making processes across the U.S.Berkeley Lab conducts a large range of analyses that use historical and forward-looking wholesale electricity prices to inform electric-sector decisions. In this report, Berkeley Lab uses its expertise to evaluate the Cambium cost data. We compare Cambium data with historical wholesale prices for the year 2018 and other modeled prices for the year 2030. We then present eight case studies in which Berkeley Lab researchers use Cambium data to replicate previous analyses based on other price datasets. We describe where primary findings and underlying key price dynamics align or differ, and highlight possible novel insights from the Cambium data. Finally, we qualitatively evaluate the suitability of Cambium costs in ten additional Berkeley Lab studies, though a direct comparison with alternative price data was not feasible at this time. The goal is to inform how electric-sector decision-makers and DOE program offices may be able to use this cohesive dataset, and to highlight what improvements to Cambium may make it even more useful.

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.

In 2020, average wholesale electricity prices in the United States fell to $21/MWh, their lowest level since the beginning of the 21st century. Low natural gas prices and the proliferation of low marginal cost resources like wind and solar had already established a trend toward lower wholesale prices, and this trend was exacerbated by declining electricity demand due to the Covid-19 pandemic in 2020. Negative real-time hourly wholesale prices occurred in about 4% of all hours and wholesale market nodes across the United States, but these were not distributed evenly. Regional clusters emerged, for example, in the Permian Basin in western Texas, and in Kansas and western Oklahoma in the Southwest Power Pool (SPP), negative prices accounted for more than 25% of all hours. Negative electricity prices result either from local congestion of the transmission system leading supply to exceed demand locally or due to system-wide oversupply. Looking at the latter condition in SPP, we find that all major generator types contribute to this excess supply, because of limited ramping flexibility or self-scheduled out-of-market unit commitments. Additional monetary production incentives such as renewable energy credits or tax credits also enable negative bids; indeed, negative prices predominantly occur when demand levels are low and wind production levels are high. Frequent negative prices can inform the value of additional renewable energy investments at specific locations, the need for transmission and storage development, and opportunities load growth or adaptation.

PV-battery hybrid projects dominate interconnection queues in some regions in the United States, but few projects have been operational long enough to assess how the hybrid capabilities may be used in practice. We interview plant operators and analyze empirical dispatch data for eleven large-scale PV-battery hybrids in three organized wholesale markets in the United States. We use the dispatch data and wholesale market prices to estimate the market value of our sample hybrids in 2020. The empirical increase in market value of a PV-battery hybrid relative to a standalone PV plant varies by project and ranges from $1 to $48/MWhsolar. The premium is driven by market, location, technical characteristics of the PV and battery asset, and battery dispatch strategies. In contrast to the widespread assumptions in the PV-battery hybrid modeling literature, only three of the eleven project operators optimize battery usage for wholesale market revenue as merchant plants. Instead, the majority of operators in the sample have alternate objectives. For example, load-serving entities target peak load reductions, incentive program participants focus on compliance with program requirements, and large energy consumers prioritize resiliency and utility bill minimization. Understanding prevalent dispatch signals and the degree of alignment with system-wide grid needs can increase the market value of PV-battery hybrids.

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.

The significant upscaling of wind turbine size (nameplate capacity, rotor diameter, and tower height) has, to date, been driven primarily by a goal of minimizing the levelized cost of energy. But with wind’s levelized cost of energy now comparable with that of other generating resources, other design considerations besides cost-minimization have grown in importance—particularly as wind’s increasing market penetration begins to impose challenges on the electric grid. We find that taller towers and larger rotors (relative to nameplate capacity) can enhance the value of wind energy to the electricity system and provide other “hidden” benefits. Specifically, in regions where wind penetration has reached around 20%, we find a boost in wholesale market value of US$2–US$3/MWh. This is augmented by transmission, balancing, and financing benefits that sum to roughly US$2/MWh. The aggregate potential value enhancement of US$4–US$5/MWh is comparable with a 10%–15% reduction in levelized costs.

The value of electricity generated from wind and solar sources declines as supply increases. This decline in value has varied over time and across regions, indicating that strategies to mitigate value decline will need to be carefully targeted. To help guide development of these strategies, we empirically determine wind and solar value at ∼2,100 plants within United States wholesale markets by using local prices and plant-specific generation profiles. We determine how each plant loses (or gains) value because of its output profile, transmission congestion, and curtailment. In regions where wind or solar account for roughly 20% of electricity generation, its value is 30% to 40% below the regional average value of a flat output profile at all plants. Solar value reductions are most sensitive to output profile and wind value reductions are sensitive to both profile and congestion, region dependent. Curtailment was not a major source of value reduction.

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.

Electricity markets in the united states and Canada have evolved since their inception in the late 1990s and early 2000s. Not all states and provinces moved toward restructured organized electricity markets, but rather those that have belonged to markets operated by independent system operators (ISOs) and regional transmission organizations, with designs developed through stakeholder processes and approved through state, provincial, or federal agencies, such as the Federal Energy Regulatory Commission (FERC).

Energy storage is a leading option to enhance the resource adequacy contribution of solar energy. Detailed analysis of the capacity credit of solar energy and energy storage is limited in part due to the data intensive and computationally complex nature of probabilistic resource adequacy assessments. This paper presents a simple algorithm for calculating the capacity credit of energy-limited resources that, due to the low computational and data needs, is well suited to exploratory analysis. Validation against benchmarks based on probabilistic techniques shows that it can yield similar insights. The method is used to evaluate the impact of different solar and storage configurations, particularly with respect to the strategy for coupling storage and solar photovoltaic systems. Application of the method to a case study of utilities in Florida, where solar is rapidly growing and demand peaks in the winter and summer, demonstrates that it can improve on rules of thumb used in practice by some utilities. If storage is required to charge only from solar, periods of high demand driven by cold weather events accompanied by lower solar production can result in a capacity credit of solar and storage that is less than the capacity credit of storage alone.

With an increasing number of jurisdictions considering alternatives to net metering policies to financially compensate behind-the-meter solar photovoltaics (PV), customer economics will increasingly depend on its ability to reduce demand charges. Understanding these demand charge savings from PV—and how behind-the-meter storage can potentially enhance those savings—is essential to understand PV market dynamics and adoption in the coming years. This article explores how these demand charge savings vary with demand charge designs and customer load profiles, modeled for a variety of residential and commercial customers. Our findings indicate that demand charge savings are lowest under a basic, non-coincident demand charge design where the demand charge is based on the maximum demand level over the month, regardless of timing, resulting primarily from the temporal mismatch between the timing of the PV host's demand peak and PV generation. PV provides greater demand charge savings, for both commercial and residential customers, when demand charge designs are based on predefined, daytime peak periods or longer averaging intervals. Demand charge savings from PV combined with storage are almost always greater than the sum of the savings attained through either technology separately. We also explore how well demand charge savings from PV align with corresponding utility savings.

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.

Previous work by the Berkeley Lab describes how high shares of variable renewable energy (VRE) such as wind and solar power could change wholesale electricity price dynamics. These include the timing of when electricity is cheap or expensive, locational differences in the cost of electricity, and the degree of regularity or predictability in those costs. Many decentralized decision-makers on the demand-side may not yet have considered the implications of these possible future changes.In this report, we evaluate the sensitivity of a set of demand-side decisions to different levels of VRE penetration ranging from a low of 5-20% to a high of 40-50%. The analysis builds on hourly wholesale energy and capacity prices in different VRE scenarios for four wholesale markets in the United States for the year 2030 (CAISO, ERCOT, NYISO, and SPP). The principal question for this exploration is whether private and public electric-sector decisions that are made based on assumptions reflecting low VRE levels still achieve their intended objective in a high VRE scenario with 40-50% wind and solar?This scoping report evaluates the impacts of changing patterns of peak system needs on the benefits of demand reductions by examining the altered value of different energy efficiency (EE) measures. Similarly, we investigate new opportunities for large energy consumers that may arise from periods with very low wholesale electricity prices. We calculate the value of new process investments (e.g., hydrogen production and other generalized electro-commodities), showcase the varying value of new product storage investments (such as reservoir extensions at a desalination plant), and estimate the benefits of increased process flexibility that uses electricity as a process-input in addition to traditional fossil fuels (e.g., district energy systems). Finally, many decentralized decision-makers and end-use customers are not directly exposed to wholesale electricity prices but instead receive price signals from their retail electricity rates. As wind and solar shares increase, we compare the economic efficiency of flat retail rates relative to more dynamic time-of-use tariffs with and without critical peak-pricing events.

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.

We synthesize available literature, data, and analysis on the degree to which growth in variable renewable energy (VRE) has impacted or might in the future impact bulk power system assets, pricing, and costs in the United States. Most studies of future scenarios indicate that VRE reduces wholesale energy prices and capacity factors of thermal generators. Traditional baseload generators are more exposed to these changing market conditions than low-capital cost and more flexible intermediate and peak-load generators. From analysis of historical data we find that VRE is already influencing the bulk power market through changes in temporal and geographic patterns areas with higher levels of VRE. The most significant observed impacts have concentrated in areas with significant VRE and/or nuclear generation along with limited transmission, with negative pricing also often occurring during periods with lower system-wide load. So far, however, VRE, has had a relatively modest impact on historical average annual wholesale prices across entire market regions, at least in comparison to other drivers. The reduction of natural gas prices is the primary contributor to the decline in wholesale prices since 2008. Similarly, VRE impacts on thermal plant retirements have been limited and there is little relationship between the location of recent retirements and VRE penetration levels. Although impacts on wholesale prices have been modest so far, impacts of VRE on the electricity market will be more significant under higher VRE penetrations.

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.

Solar’s variable generation limits its contribution to reliably meeting peak demand, or its resource adequacy contribution. Energy storage is a leading option to increase solar’s resource adequacy contribution, yet the contribution from different configurations of solar and storage is not widely understood. We develop methods for exploring the primary drivers of an estimate of the resource adequacy contribution of solar and storage, and we apply the methods to a case study in Florida, where demand peaks in winter and summer. We find that the portion of solar nameplate capacity that contributes to resource adequacy—its capacity credit—is less than 50% and that it declines with increasing solar penetration. The capacity credit of storage, even though it is fully controllable by the system operator, strongly depends on the duration of storage. The capacity credit of 1 hour of storage can be less than the capacity credit of solar.  Achieving a 90% capacity credit requires at least 4–5 hours of storage when storage capacity is small relative to the system peak. As storage deployment increases to 20% of the peak demand, 9 hours—and sometimes more than 10 hours—of storage are needed to achieve a 90% capacity credit. Increased solar deployment at the system level can increase storage’s capacity credit. Directly pairing solar and storage can also impact the capacity credit. Storage with a power rating similar to the solar inverter rating loses capacity credit when coupled with solar if its duration is more than 1–2 hours, because storage competes with solar for use of the inverter. On the other hand, there is no reduction in capacity credit when the storage is small relative to the solar inverter. The approach and tools developed here for exploratory analysis can be useful for many other utilities and regions grappling with similar preliminary questions, prior to evaluation of specific cases using more detailed and resource-intensive modeling.