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Climate change mitigation requires developing zero-carbon, highly renewable energy systems, which require technologies to capture excess renewable electricity such as energy storage. Endeavoring to capture all available excess renewable electricity, however, may require large energy storage capacities and costs. This study therefore investigates how much curtailment is cost-optimal to allow in developing fully decarbonized electricity systems, using compliance with California's Senate Bill 100 goal as a representative case study. We combine electric grid dispatch modeling with an optimization approach for selecting the composition of energy storage technologies to capture excess renewable electricity to minimize overall system costs. We found that overbuilding cheap wind and solar and allowing the curtailment of excess renewable electricity equivalent to 25–43% of the total annual electric load resulted in the lowest cumulative systemwide cost for a fully decarbonized electricity system of about $1.8 trillion, spent between 2020 and 2045. Allowing no renewable curtailment results in significant battery requirements and a cumulative systemwide cost of $5.2 trillion spent between 2020 and 2045. Therefore, allowing some curtailment reduced the cost of building a fully decarbonized electricity system by a factor of 3 when the portfolio of technologies to capture and manage excess renewable electricity is carefully chosen. • Examined cost-minimal renewable curtailment levels for a zero-carbon grid. • Assessed cost-optimal technology mixes for harnessing excess renewable electricity. • Overbuilding renewable capacity is cheaper than vastly expanding energy storage. • Long duration storage is critical to minimize costs to build a zero-carbon grid. • Power-to-gas is well suited for long duration storage alongside batteries. [ABSTRACT FROM AUTHOR]

Highlights • Climate-induced variability in hydropower can increase greenhouse gas emissions. • Higher dispatchable capacity needed to compensate for hydropower variability. • Hydropower under climate change has minimal effects on renewable penetration. • Higher hydropower variability increases natural gas power plant start up events. • Climate-induced hydropower variability increases natural gas power plant downtime. Abstract This study investigates how hydropower generation under climate change affects the ability of the electric grid to integrate high wind and solar capacities. Using California as an example, water reservoir releases are modeled as a function of hydrologic conditions in the context of a highly-renewable electric grid in the year 2050. The system is perturbed using different climate models under the Representative Concentration Pathway 8.5 climate scenario. The findings reveal that climate change impact on hydropower can increase greenhouse gas emissions up to 8.1% due to increased spillage of reservoir inflow reducing hydropower generation, but with minimal effects (<1%) on renewable utilization and levelized cost of electricity. However, increases in dispatchable power plant capacity of +2.1 to +6.3% and decreases in the number of start-up events per power plant unit up to 3.1%, indicate that the majority of dispatchable natural gas power plant capacity is offline for most of the climate change scenarios. While system-wide performance metrics experience small impacts, climate change effects on hydropower generation increase both the need for dispatchable generation and the costs of electricity from these power plants to support large-scale wind and solar integration on the electric grid. [ABSTRACT FROM AUTHOR]

Highlights • Zero-emissions transportation fueling is the most cost-effective use of excess renewable energy. • Energy storage provides limited emission reduction benefits on already low-carbon grids. • Renewable gas production provides limited emissions reduction but significant cost benefits. • Load flexibility is critical for maximizing the cost-effectiveness of emissions reduction options. Abstract Preventing the curtailment of excess renewable generation, caused by mismatches between variable renewable electricity generation and the electric load, is a key strategy for maximizing greenhouse gas emissions reductions by integrating renewable resources into the electric grid. Strategies to harness excess renewable generation for useful purposes exist, but it is unclear which of these end uses provides the most effective use of available excess generation to maximize greenhouse gas emissions reductions in a cost-effective manner. This study investigates and compares three end-use strategies for utilizing excess renewable generation – storage in electrical energy storage systems, production of transportation fuel or vehicle charging, or production of renewable gas – and their diverse technology pathways on the bases of their greenhouse gas emissions reduction potential and the impacts of their implementation on the cost of energy services. This is accomplished by modeling the integration of 46 different technology pathways for using excess renewable generation in a 70% renewable and an 80% renewable electric grid configuration during the year 2050 in California using the Holistic Grid Resource Integration and Deployment (HiGRID) platform, which is a temporally-resolved resource dispatch model of the electricity system. Technology and cost characteristics for batteries, hydrogen energy storage systems, vehicle fueling or charging, and renewable gas production technologies are collected from multiple sources and their effect on reducing greenhouse gas emissions and affecting the Levelized Cost of Energy (LCOE) services in the HiGRID platform are examined. It was discovered that using excess renewable generation to produce transportation fuel for hydrogen vehicles or to charge electric vehicles provided the largest total greenhouse gas emissions reductions and lowest per-ton cost of greenhouse gas reduction. Use in grid energy storage and production of renewable gas provided similar but relatively lower total greenhouse gas reductions than transportation, with the latter imposing lower per-ton costs of greenhouse gas reduction. More generally, greenhouse gas reduction potential of these end uses depended on the intensity of the fuel being displaced by renewables, while LCOE effects depended on the temporal flexibility of the technologies associated with this end use. Overall, this study provides insight into a priority order for directing the use of excess renewable generation towards end uses to achieve greenhouse gas reduction goals such as those in California in a cost-minimal manner, and investigates the sensitivities that influence the effectiveness of these end uses. [ABSTRACT FROM AUTHOR]

In this study, we investigate the extent to which physical water resource availability constraints can limit the deployment of solar thermal and geothermal-based energy resources under future climate scenarios in California. This is accomplished by (1) calculating the water unconstrained potential capacity for solar thermal and geothermal power plants, (2) estimating the available water supply for supporting the water needs of these plants using four climate model simulations under representative concentration pathway (RCP) 8.5, and (3) determining the supportable capacity from the available water supply based on power plant cooling type. We show that regional water availability can limit the installable capacity of solar thermal resources to a range of 10.9–52.6% of solar thermal potential and geothermal resources to between 17.9% and 100% of geothermal potential, depending on cooling system and regional water demand levels by the year 2050. The limiting factor for installable capacity was driven by whether the locations of solar thermal and geothermal resources were spatially aligned with precipitation patterns, with cooling system type acting as a secondary factor. In regions with high solar thermal and geothermal potential, reducing water demand from other sectors was important for alleviating the water constraints on solar thermal and geothermal capacity and increasing total resource potential. Water conservation policies can therefore support the deployment of renewable energy resources and should be considered in future water and energy resource planning. [ABSTRACT FROM AUTHOR]

Climate change and increased electrification of space and water heating in buildings can significantly affect future electricity demand and hourly demand profiles, which has implications for electric grid greenhouse gas emissions and capacity requirements. We use EnergyPlus to quantify building energy demand under historical and under several climate change projections of 32 kinds of building prototypes in 16 different climate zones of California and imposed these impacts on a year 2050 electric grid configuration by simulation in the Holistic Grid Resource Integration and Deployment (HIGRID) model. We find that climate change only prompted modest increases in grid resource capacity and negligible difference in greenhouse gas emissions since the additional electric load generally occurred during times with available renewable generation. Heating electrification, however, prompted a 30–40% reduction in greenhouse gas emissions but required significant grid resource capacity increases, due to the higher magnitude of load increases and lack of readily available renewable generation during the times when electrified heating loads occurred. Overall, this study translates climate change and electrification impacts to system-wide endpoint impacts on future electric grid configurations and highlights the complexities associated with translating building-level impacts to electric system-wide impacts. [ABSTRACT FROM AUTHOR]

Different configurations of a 100% renewable electricity system are possible, but not all are equally desirable in terms of the scale of material resources required to sustain them. This study compares different approaches for developing a 100% renewable electricity system on the basis of the material mass investment required to sustain their physical components. Electric grid modeling accounting for operational constraints is used to determine the scale of energy technology capacities required to achieve a 100% renewable electricity system using California as a representative example and translating those requirements to material mass requirements. Using a wind/solar/storage approach requires exponentially growing capacities of energy storage to meet operational needs and requires significant material mass investments. Material resource efficiency of the system is shown to be improved by maximizing the use of regional non-variable renewables to the extent possible within local capacity constraints. Alternatively, overbuilding the wind and solar capacity in excess of that needed to meet annual demand is also shown to improve material resource efficiency of the system. Overall, different approaches for meeting a 100% renewable electricity penetration are not equally desirable when material resource usage is considered. This should be taken into account in future energy system planning studies. [ABSTRACT FROM AUTHOR]

While many electricity resource mixes can facilitate a zero-carbon electricity system, different pathways can vary significantly in their contribution to environmental impacts. Many current assessments focus on tradeoffs associated with monetary cost, neglecting these wider impacts. Here, electric grid dispatch modeling and electricity mix optimization is combined with data on resource consumption and electricity technology costs to compare five different approaches for developing a 100% zero-carbon electricity system in California: minimum critical metals use, minimum solid construction materials mass, minimum land use, minimum freshwater consumption, and minimum monetary cost under present-day policy goals and constraints. The modeled scenarios show that prioritizing minimum solid construction materials mass in developing such systems also achieve near-minimal monetary cost and land use and did not exhibit the worst performance on either freshwater consumption or critical metals use. In contrast, the strategy that prioritized minimum freshwater consumption exhibited the largest land use and materials use of the five strategies. The minimum monetary cost strategy exhibited near-minimal freshwater consumption, but large land use and the highest demand for critical metals. The modeled monetary unit cost of electricity was lower than the 2030 reference for all zero-carbon electricity system scenarios. The results highlight tradeoffs between contributions to different types of environmental impact in developing a zero-carbon electricity system. Notably, prioritizing certain metrics can result in electricity systems that balance these tradeoffs better than others given the existing suite of zero-carbon options. More broadly, the results show that the planning of zero-carbon electricity systems should more explicitly incorporate non-carbon environmental externalities as co-priorities in their development. • Modeled zero-carbon system development under different non-carbon priorities. • Analyzed the effect of co-priorities on multi-criteria environmental impact & cost. • Co-prioritizing minimum materials throughout yielded lowest multi-criteria impacts. • Prioritizing minimum cost does not necessarily align with minimizing other impacts. • Non-carbon criteria should be considered in zero-carbon electricity planning. [ABSTRACT FROM AUTHOR]

Here we translate the impacts of climate change on hydropower generation, and discuss implications on greenhouse gas (GHG) emissions and operation in California. We integrate a model of major surface-water reservoirs with an electric grid dispatch model, and perturb it by projected runoff based on representative concentration pathways (RCP4.5 and RCP8.5). Results show that climate change and variability is expected to decrease the average annual hydropower generation by 3.1% under RCP4.5, but have negligible impact under the RCP8.5. Model simulations indicate more inflow, caused by more future extremes, in the future that does not necessarily translate to more energy production because of reservoir spillage of water. While overall volume of future available water for energy production may be similar or higher, the delivery of this volume is expected to be significantly more variable in the future climate than the historical average, which has many implications for hydropower generation. Our results show that the expected changes in future climate leads to increases in grid GHG emissions, load-following capacity, fuel usage, and costs for the RCP4.5 due to generation shortfall, and very slight increases in the same metrics for the RCP8.5 case due to variability causing decreased efficiencies in load-following power plants. [ABSTRACT FROM AUTHOR]

A study has been performed to understand the quantitative impact of key differences between vehicle-to-grid and stationary energy storage systems on renewable utilization, greenhouse gas emissions, and balancing fleet operation, using California as the example. To simulate the combined electricity and light-duty transportation system, a detailed electric grid dispatch model (including stationary energy storage systems) was combined with an electric vehicle charging dispatch model that incorporates conventional smart and vehicle-to-grid capabilities. By subjecting smaller amounts of renewable energy to round-trip efficiency losses and thereby increasing the efficiency of renewable utilization, it was found that vehicle-to-grid energy storage can achieve higher renewable utilization levels and reduced greenhouse gas emissions compared to stationary energy storage systems. Vehicle-to-grid energy storage, however, is not as capable of balancing the power plant fleet compared to stationary energy storage systems due to the constraints of consumer travel patterns. The potential benefits of vehicle-to-grid are strongly dependent on the availability of charging infrastructure at both home and workplaces, with potential benefits being compromised with residential charging availability only. Overall, vehicle-to-grid energy storage can provide benefits over stationary energy storage depending on the system attribute selected for improvement, a finding amenable to managing through policy. [ABSTRACT FROM AUTHOR]

Alternative vehicles must appropriately interface with the electric grid and renewable generation to contribute to decarbonization. This study investigates the impact of infrastructure configurations and management strategies on the vehicle–grid interface and vehicle greenhouse gas reduction potential with regard to California's Executive Order S-21-09 goal. Considered are battery electric vehicles, gasoline-fueled plug-in hybrid electric vehicles, hydrogen-fueled fuel cell vehicles, and plug-in hybrid fuel cell vehicles. Temporally resolved models of the electric grid, electric vehicle charging, hydrogen infrastructure, and vehicle powertrain simulations are integrated. For plug-in vehicles, consumer travel patterns can limit the greenhouse gas reductions without smart charging or energy storage. For fuel cell vehicles, the fuel production mix must be optimized for minimal greenhouse gas emissions. The plug-in hybrid fuel cell vehicle has the largest potential for emissions reduction due to smaller battery and fuel cells keeping efficiencies higher and meeting 86% of miles on electric travel keeping the hydrogen demand low. Energy storage is required to meet Executive Order S-21-09 goals in all cases. Meeting the goal requires renewable capacities of 205 GW for plug-in hybrid fuel cell vehicles and battery electric vehicle 100s, 255 GW for battery electric vehicle 200s, and 325 GW for fuel cell vehicles. [ABSTRACT FROM AUTHOR]

The increasing demand on electric grids to support high penetrations of intermittent renewables, enhance power quality, increase reliability and resiliency, and provide ancillary services, is leading to local power generation on both sides of the meter. This paper describes the potential attributes of deploying 10–100 MW scale clusters of fuel cells installed at distribution substations to enable electric grid support through the provision of baseload and various levels of load following services. Such deployments, referred herein as Transmission Integrated Grid Energy Resource (TIGER) Stations, can also contribute to achieving air quality and climate goals through several high value attributes including high efficiency, ultra-low pollutant emissions, and near zero acoustic emissions. To quantitatively assess these benefits, a 5 GW deployment of TIGER Stations in the California electric system was analyzed using the Holistic Grid Resource Integration and Deployment (HiGRID) model at 33%, 43%, and 50% renewable penetration. The analysis establishes that (1) TIGER Stations have the potential to reduce carbon emissions and NO x emissions even when operated as baseload systems, and (2) TIGER Station load following capability is important for continued carbon emission reductions at higher renewable penetrations. Additional features of TIGER Stations, such as heat recovery or hybrid cycles, will further increase the attributes of TIGER Stations. [ABSTRACT FROM AUTHOR]

A study was conducted to compare the technical potential and effectiveness of different water supply options for securing water availability in a large-scale, interconnected water supply system under historical and climate-change augmented inflow and demand conditions. Part 2 of the study focused on determining the greenhouse gas and renewable energy utilization impacts of different pathways to stabilize major surface reservoir levels. Using a detailed electric grid model and taking into account impacts on the operation of the water supply infrastructure, the greenhouse gas emissions and effect on overall grid renewable penetration level was calculated for each water supply option portfolio that successfully secured water availability from Part 1. The effects on the energy signature of water supply infrastructure were found to be just as important as that of the fundamental processes for each option. Under historical (baseline) conditions, many option portfolios were capable of securing surface reservoir levels with a net neutral or negative effect on emissions and a benefit for renewable energy utilization. Under climate change augmented conditions, however, careful selection of the water supply option portfolio was required to prevent imposing major emissions increases for the system. Overall, this analysis provided quantitative insight into the tradeoffs associated with choosing different pathways for securing California's water supply. [ABSTRACT FROM AUTHOR]

The technical potential and effectiveness of different water supply options for securing water availability in a large-scale, interconnected water supply system under historical and climate-change augmented inflow and demand conditions were compared. Part 1 of the study focused on determining the scale of the options required to secure water availability and compared the effectiveness of different options. A spatially and temporally resolved model of California's major surface reservoirs was developed, and its sensitivity to urban water conservation, desalination, and water reuse was examined. Potential capacities of the different options were determined. Under historical (baseline) hydrology conditions, many individual options were found to be capable of securing water availability alone. Under climate change augment conditions, a portfolio approach was necessary. The water savings from many individual options other than desalination were insufficient in the latter, however, relying on seawater desalination alone requires extreme capacity installations which have energy, brine disposal, management, and cost implications. The importance of identifying and utilizing points of leverage in the system for choosing where to deploy different options is also demonstrated. [ABSTRACT FROM AUTHOR]

Abstract: This study has developed metrics to evaluate the impact of intermittent renewable generation on the electric load demand that must be balanced by dispatchable generation resources, allowing examination of the general impacts of accommodating high renewable penetration levels. The metrics focus on the sizing, utilization and coordination of load balancing resources to meet the load demand in time. Insights gained from increasing the renewable penetration level in California as an example indicated the following. The balancing generator fleet displayed low capacity factors at high penetration levels. At penetration levels above 45% with no uninterruptable base load, surplus generation occurred and increased exponentially. The occurrence of daily maximum and minimum load points became increasingly unpredictable, rendering fixed time-of-use electricity pricing inappropriate. Capacities of peaker and base load generator type increased and decreased respectively. Net load variability decreased on the 24-h timescale and increased on all shorter timescales, implying changes in the temporal dispatch of balancing generators. The use of energy management strategies such as energy storage was found to be necessary in order to accommodate high renewable penetration levels with minimal impact. The simple metrics allowed identification of key areas to be addressed in order to accommodate high renewable penetrations. [Copyright &y& Elsevier]

Abstract: A spatial and temporal analysis of wind power generation characteristics was conducted in order to determine the implications of intermittent wind generation dynamics on the profile of the electric loads that must be balanced by dispatchable electrical generators on the electric grid. A parametric analysis was conducted to evaluate the sensitivity of the typical magnitudes of wind power fluctuations on different timescales, power variation range, typical daily and seasonal wind profiles to wind farm size and regional distribution. A methodology to evaluate wind dynamics based on power spectral density analyses have been developed. Results indicate that increasing the size of a local wind farm significantly reduced the magnitude of wind power fluctuations on timescales faster than 12 h, with the largest reductions occurring at the fastest timescales. Additional reductions in power fluctuations can be achieved with the implementation of local and regional distribution of wind turbines in disperse high wind areas. In these cases, it was discovered that the timescale band within which the largest reductions in power fluctuations occurred was dependent on regional geographic features, and did not necessarily correspond to the fastest timescales. In addition, it was also discovered that the aggregation of wind power from different regions could produce a more uniform frequency distribution of power fluctuation reductions. [Copyright &y& Elsevier]

Power grid operations increasingly interact with environmental systems and human systems such as transportation, agriculture, the economy, and financial markets. Our objective is to discuss the modelling gaps and opportunities to advance the science for multisector adaptation and tradeoffs. We focus on power system operational models, which typically represent key physical and economic aspects of grid operations over days to a year and assume a fixed power grid infrastructure. Due to computational burden, models are typically customized to reflect regional resource opportunities, data availability, and applications of interest. We conceptualize power system operational models with four core processes: physical grid assets (generation, transmission, loads, and storage), model objectives and purpose, institutions and decision agents, and performance metrics. We taxonomize the representations of these core processes based on a review of 23 existing models. Using science questions around grid and short term uncertainties, long term global change, and multisectoral technological innovation as examples, we report on tradeoffs in process fidelity and tractability that have been adopted by the research community to represent multisectoral interactions in power system operational models. Our recommendations for research directions are model-agnostic, focusing on core processes, their interactions with other human systems, and consider computational tradeoffs. • 23 power system operational models are reviewed to develop a process-based taxonomy. • The taxonomy of core process representations is model agnostic. • We discuss key core process representation and computational tradeoffs by science question. • We identify technical gaps and opportunities to support multisector dynamics research. [ABSTRACT FROM AUTHOR]

Plug-in electric vehicles charged with zero-carbon electricity are important for decarbonizing regional energy systems. Flexible charging of these vehicles aids with grid integration of wind and solar generation but may require drivers to provide information about their travel patterns and allow grid operators to control the charging of their vehicles. Limited acceptance of flexible charging can potentially limit greenhouse gas emissions reductions from electric vehicle deployment. Therefore, here we assess how varying the extent of consumer acceptance of flexible charging affects electric vehicle greenhouse gas emissions reductions in a highly decarbonized California grid (>70% zero-carbon), a region with mandated zero-emission vehicle deployment and electricity decarbonization targets. We quantify the monetary value of flexible charging based on the reduction in stationary storage required to achieve a given zero-carbon penetration as flexible charging is adopted. We find that increased participation in smart charging and vehicle-to-grid increases zero-carbon generation uptake by up to 5.2% and 11.1%, respectively. The value of smart charging only reaches $87 per vehicle-year while that for vehicle-to-grid can reach $2,850 per vehicle-year. Non-monetary incentives may be needed to increase smart charging participation. These results can inform future analyses on the supply and demand for participation in flexible charging programs. • Modeled how increasing flexible charging adoption affects zero-carbon energy uptake. • Assessed the value of flexible charging adoption for building a decarbonized grid. • Investigated both smart charging and vehicle-to-grid interaction with the grid. • Monetary value of smart charging is small relative to electric vehicle costs. • Monetary value of vehicle-to-grid can be large relative to electric vehicle costs. [ABSTRACT FROM AUTHOR]

• Modeled costs for four zero-carbon electricity narrative scenarios for California. • Analyzed the life cycle freshwater consumption of zero-carbon electricity mixes. • Lowest cost mix has highest water consumption, 9 times that of lowest water mix. • Lowest water consumptive mix has highest cost, 30% greater than lowest cost mix. • Non-carbon criteria should be considered in zero-carbon electricity planning. Characterizing the advantages and disadvantages of different electricity resource mixes in meeting electricity decarbonization goals is an active area of research. Many system-level assessments, however, evaluate different mixes on the basis of minimizing electricity costs without accounting for regional environmental externalities. California represents a highly populated region with both aggressive electricity decarbonization policies and water scarcity issues that are projected to worsen under climate change, representing an interesting case study for assessing the tradeoffs between the costs of electricity decarbonization and water resource consumption. This study therefore combines electric grid dispatch modeling and regional life cycle freshwater consumption data to compare in-state freshwater consumption and levelized cost of electricity for four electricity mix scenarios designed to achieve zero-carbon electricity in California by 2045, compliant with current law (California Senate Bill 100). In modeled scenarios, we find that the lowest costs occurred for mixes with lower energy storage capacity needs enabled by high capacity factor and dispatchable renewables. However these mixes also resulted in high freshwater consumption due largely to heavy reliance on geothermal resources. By contrast, the mix with the lowest freshwater consumption relied exclusively on wind, solar, and hydropower and reduced water consumption by an order of magnitude compared to that of the lowest cost mix. Due to lower capacity factors and greater difficulty in matching supply to demand (increasing energy storage needs), this mix increased the levelized cost of electricity by 30%. Overall, our results show that prioritizing low electricity costs as well as other climate-relevant criteria, such as freshwater consumption, in meeting zero-carbon electricity goals will result in a very different electricity mix than simply considering costs alone. [ABSTRACT FROM AUTHOR]

Abstract: Renewable resources represent an opportunity for environmentally preferred generation of electricity that supports energy security and independence; however integrating renewable technologies is not without challenges. Renewable resources have limitations that can include location, capacity, cost and availability. California is proactive in the implementation of renewable energy through legislation and execution of a Renewable Portfolio Standard. This work explores key challenges to achieving high penetrations of renewables onto California''s grid. The Holistic Grid Resource Integration and Deployment (HiGRID) tool has been developed for this analysis and is verified herein. This tool resolves the hourly operation, performance and cost of renewable and non-renewable generation resources. Three renewable deployment strategies are explored including all wind, all solar photovoltaic, and 50/50 mixture. Initially, wind is the preferred candidate from a cost and required installed capacity perspective; however, as the penetration increases excess wind generation encourages installation of solar. The 50/50 case becomes more cost competitive at high renewable penetrations (greater than 32.4%) and provides the highest system-wide capacity factor and CO2 reduction potential. Results highlight the value of optimizing the renewable deployment strategy to minimize costs and emphasize the importance of considering capacity factor and curtailment when representing the true cost of installing renewables. [Copyright &y& Elsevier]

• A representative model of medium and heavy duty trips in California is presented. • Medium and heavy duty battery electric vehicle charging profiles are developed. • Electric vehicle potential to meet medium and heavy duty trips is quantified. • Uncertainty around future fuel efficiency and charging infrastructure is discussed. Transitioning the medium and heavy-duty vehicle fleet to electric vehicles (EVs) such as battery electric vehicles (BEVs) and fuel cell electric vehicles (FCEVs) is an important step in supporting greenhouse gas and regional air pollutant emission reduction goals. Travel demand patterns for medium and heavy-duty vehicles, however, have a more diverse and stricter set of requirements compared to light duty vehicles. Therefore, it is critical to understand the technical feasibility of using BEVs and FCEVs to meet the medium and heavy duty vehicle travel demands as a function of vehicle capabilities and infrastructure availability. This work develops and applies a representative dataset of California-based medium and heavy duty vehicles trips to evaluate (1) potential electric load demand of future BEVs and (2) the feasibility of EVs to meet state-wide medium and heavy duty travel demand. From a technical perspective, EVs can support between 62 and 76% of commercial Class 2B-7 vehicle miles traveled with technologies in development today. Further increases will require increasing vehicle range, improving fuel efficiency, and/or expanding available charging locations. Class 8 trucks have a much lower BEV feasibility compared to FCEVs due to their weight and longer trip distances, with 100-mile vehicles meeting up to 8% of vehicle miles travelled with home base charging. Class 8 FCEVs with the same range can meet up to 27% and are likely to have expanded ranges that facilitate up to 68% due to inherent benefits of storing on-board hydrogen relative to batteries. Feasibility results indicate that EVs can significantly contribute to reducing emissions from the medium and heavy duty sectors but cannot fully meet demand under the configurations considered. [ABSTRACT FROM AUTHOR]

Energy storage systems, such as flow batteries, are essential for integrating variable renewable energy sources into the electricity grid. While a primary goal of increased renewable energy use on the grid is to mitigate environmental impact, the production of enabling technologies like energy storage systems causes environmental impact. Thus, understanding the impact of producing energy storage systems is crucial for determining the overall environmental performance of renewable energy from a systems perspective. In this study, the environmental impact associated with the production of emerging flow battery technologies is evaluated in an effort to inform materials selection and component design decisions. The production of three commercially available flow battery technologies is evaluated and compared on the basis of eight environmental impact categories, using primary data collected from battery manufacturers on the battery production phase including raw materials extraction, materials processing, manufacturing and assembly. In the baseline scenario, production of all-iron flow batteries led to the lowest impact scores in six of the eight impact categories such as global warming potential, 73 kg CO 2 eq/kWh; and cumulative energy demand, 1090 MJ/kWh. While the production of vanadium redox flow batteries led to the highest impact values for six categories including global warming potential, 184 kg CO 2 eq/kWh; and cumulative energy demand, 5200 MJ/kWh. Production of zinc-bromine flow batteries had the lowest values for ozone depletion, and freshwater ecotoxicity, and the highest value for abiotic resource depletion. The analysis highlight that the relative environmental impact of producing the three flow battery technologies varies with different system designs and materials selection choices. For example, harmonization of the battery system boundary led to freshwater eutrophication and freshwater ecotoxicity values for vanadium redox flow batteries lower than the values for zinc-bromine flow batteries. Regarding alternative material use strategies, we conclude that vanadium redox flow batteries exhibit the lowest potential in four of the eight impact categories including global warming potential at 61 kg CO 2 eq/kWh. In zinc-bromine flow batteries, the titanium-based bipolar plate contributes higher environmental impact compared to carbon-based materials, and the polymer resins used in all-iron flow batteries could be replaced with material with lower potential for ecotoxicity. Overall, the analysis reveals the sources of potential environmental impact, due to the production of flow battery materials, components and systems. The findings from this study are urgently needed before these batteries become widely deployed in the renewable energy sector. Furthermore, our results indicate that materials options change the relative environmental impact of producing the three flow batteries and provide the potential to significantly reduce the environmental impact associated with flow battery production and deployment. Image 1 • Environmental impact assessment of flow battery production was conducted. • Three types of flow batteries with different design parameters were analyzed. • Design factors and materials choices largely affect the environmental impact. • Choices fr cell stack, electrolyte and membrane materials influence total impact. • Design of accessories and balance of plant can reduce environmental impact. [ABSTRACT FROM AUTHOR]

• Combines life cycle analysis and electric grid dispatch modeling methods. • Compares emissions reduced from battery use with emissions from battery production. • Calculates net emissions reductions of flow batteries at increasing grid capacities. • Capacity thresholds exist where emissions reduction benefits are maximized. • Deploying too much flow battery capacity can reduce or negate emissions reductions. Energy storage systems are critical for enabling the environmental benefits associated with capturing renewable energy to displace fossil fuel-based generation, yet producing these systems also contributes to environmental impacts through their materials use and manufacturing. As energy storage capacity is scaled up to support increasingly renewable grids, the environmental benefits from their use may scale at different rates than the environmental impacts from their production. This implies the existence of capacity thresholds beyond which installing additional storage capacity may be environmentally detrimental. Identifying such thresholds are important for ensuring that energy storage capacity selection in future grids are consistent with net emissions reduction goals, but such thresholds have not been studied in the present literature. To identify such thresholds, here we combine electric grid dispatch modeling with life cycle analysis to compare how the emissions reductions from deploying three different flow battery energy storage types on a future California grid (>80% wind and solar) compare with emissions contributions from producing such batteries as total battery capacity installed on the grid increases. Depending on the type of battery and environmental impact indicator (greenhouse gas or particulate matter emissions), we find that the marginal environmental benefits of storage begin to diminish at deployed capacities of 38–76% of the mean daily renewable generation (256–512 GWh in our California scenarios) and reach zero at 105–284% of mean daily renewable generation (700–1810 GWh). Such storage capacities are conceivable, but upstream impacts of storage must be assessed in evaluating the environmental benefits of large-scale storage deployment, or they could negate the environmental benefits of regional electricity system decarbonization. [ABSTRACT FROM AUTHOR]

• Modeled climate change impacts on hydropower in Upper Yangtze River Basin in China. • Assessed simultaneous climate change effects on electricity supply and demand. • Translated climate supply–demand gap to greenhouse gas emissions implications. • Climate change exacerbates supply–demand gap seasonally and inter-annually. • Low-carbon resources are critical for reduce emissions from the supply–demand gap. Hydropower importantly provides flexible low-carbon electricity, however, climate change will affect the hydropower system through altering hydrologic regimes while also affecting electricity demands for heating and cooling that hydropower resources serve. This study assesses the effect of climate change on hydropower and electricity demand in the Upper Yangtze River Basin (UYRB) in China on the regional net electric load and greenhouse gas (GHG) emissions. This is accomplished by using climate projections from five global climate models (GCMs) to simultaneously force (1) a physically-based hydrological model and a statistically-based hydropower model to estimate the future generating capacity of 21 large hydropower plants in the UYRB and (2) an empirical electricity demand model accounting for socioeconomic and climatic factors. Under climate change, the projected hydropower generation in the UYRB tends to increase in the 21st century but is far less than the increase in electricity demand, increasing the gap between demand and supply. Future increases in overall electricity demand are driven by GDP growth, but climate change will alter the distribution of the seasonal electricity demand. Climate warming decreases electricity demand for heating in winter and increases electricity demand for cooling in summer, but ultimately increases demand. Meanwhile, there is an increasing mismatch between electricity demand and hydropower supply associated with inter- and intra-annual variations, owing to the temporal climate change and increase in compound climate extremes (droughts and heatwaves). Finally, meeting the gap between supply and demand due to climate change is estimated to contribute 79.0–184.6 and 50.6–316.2 MMT CO 2e /yr of additional GHG emissions by the mid and end of 21st century, respectively. [ABSTRACT FROM AUTHOR]