U.S. water demand varies sharply by sector and region as land use, population, weather patterns, and economic activity co-evolve. High-resolution water demand data are required to capture these dynamics and to support integrated energy-water-land modeling and local-to-regional water scarcity assessments. We present a gridded (1/8$^{\circ}$), monthly, multi-sector water demand dataset for the contiguous United States (CONUS) covering 1980--2100 across one historical period and eight future scenarios spanning a wide but plausible range of atmospheric conditions, emissions constraints, and economic, technological, and population growth assumptions. The dataset covers six demand sectors --- irrigation, thermoelectric, municipal (public-supply and domestic), livestock, manufacturing, and mining --- aggregated from 25 underlying subsectors, separately for withdrawals and consumption, and includes per-cell groundwater and surface-water source attributions. The historical record is validated against the United States Geological Survey (USGS) 2010--2020 water-use reanalysis for the three largest sectors at the Hydrologic Unit Code 6 (HUC6) scale, with Pearson correlations from 0.73 to 0.95. The dataset advances prior global products through state-resolved sectoral demands, future power-plant siting projections, scenario-consistent population and land-use forcing, and a spatial-resolution refinement from 1/2$^{\circ}$ to 1/8$^{\circ}$.

The electric power sector is expected to grow in size, importance, and complexity around the world as economies expand and electric supply technologies and demand patterns evolve in significant ways. Newer, rapidly growing sectors could alter the temporal profile of electricity demand from historical patterns. In addition, substantial increases in variable renewable energy technologies could occur, adding variability and uncertainty to the diurnal and seasonal profile of electric supply. In this context, the emergence of modular, flexible electricity storage technologies may have profound impacts on the structure and operation of electric power systems. Here we target a gap in multi-sector dynamics models by incorporating grid-based electricity storage investment and operation into the electric sector dynamics of the Global Change Analysis Model-USA (GCAM-USA). We find a potentially significant role for storage technologies in the future of the U.S. power system, with storage capacity ranging from 196.1 to 372.4 GW (5.0 to 10.6%) of capacity in 2050 and 352.1 to 802.6 GW (6.0 to 9.0%) in 2100 across several techno-economic scenarios. We also find that storage can help to smooth variability in residual load arising from evolving electricity demands and the introduction of high shares of variable renewable energy to the electric grid. This reduces reliance on high-cost peaking generators, improves utilization of base-load technologies, increases system-wide capacity factors, and limits curtailment of renewable generation.

To manage the complexity of long-term grid planning, capacity expansion models typically operate at a zonal level, aggregating generation, transmission, and storage capacity. On the other hand, validating and evaluating planning portfolios requires a nodal-level resolution, especially for energy storage, as its performance and value highly depend on local grid conditions. This paper presents a novel method for siting and sizing storage based on transmission capacity and congestion. In particular, each node’s storage need is assessed by summing the products of line utilization and capacity across its incident lines, capturing both congestion severity and transfer capability. This metric is then used to allocate zonal storage capacity to individual nodes based on their severity ranking. The proposed method is demonstrated on the nodal Western Interconnection power grid, highlighting its potential to inform more granular and effective storage planning strategies.

Abstract The US Western Interconnection is facing unprecedented challenges in the form of less predictable peak energy demand, increasingly diverse generating resources, and fast‐growing loads due to the onset of artificial intelligence, hyperscale computing, and electrification. Projecting where future generation may be developed is critical to maintaining a robust and resilient electric grid under this mounting uncertainty and variability. Using an integrated multisectoral, multiscale modeling framework that links a human‐Earth systems model, an hourly load model, a geospatial power plant siting model, and an hourly grid operations model, we evaluate the power plant landscape evolution under eight alternative futures between 2020 and 2055. These futures represent a wide but plausible range of atmospheric conditions, emissions constraints, and economic, technological, and population growth assumptions. We find that local‐level development can vary substantially both by generation type and capacity buildout across these futures. Specific regions of the Western Interconnection are projected to see large amounts of capacity development regardless of the future scenario given local siting drivers. We additionally determine that projected power plant locations are more heavily influenced by the cost to interconnect to the electric grid than the revenue driven by locational energy prices.

The reliability of power grids in the future will depend on how system planners account for the integration of new technologies, extreme weather events, and uncertainties in demand growth from increased electrification and data centers. This study introduces an open-source, multisectoral, multiscale modeling framework that projects grid stress and reliability trends between 2020 and 2055 in the Western Interconnection of the United States. The framework integrates global to national energy-water-land dynamics with power plant siting and hourly grid operations modeling. We analyze future wholesale electricity price shocks and unserved energy events across eight scenarios spanning a range of population growth and economic change, generation mixes, and weather conditions. Our results show future grids with high percentage of non-renewable generation and strong economic growth are characterized by higher reliability and lower wholesale electricity prices than lower growth scenarios because of larger reliance on dispatchable generators and lower fossil fuel extraction costs. Scenarios with high percentage of renewable resources have lower median but more volatile wholesale electricity prices as well as more frequent and severe unserved energy events compared to scenarios relying more on dispatchable generators. These events occur because higher proportion of solar and wind energy causes net demand curves to deepen during midday (duck curves get progressively severe), exacerbating the challenge of meeting demand during summer evening peaks. This study suggests that robust and co-optimized transmission and energy storage planning could help maintain low wholesale electricity prices and high reliability levels in future electricity grids across uncertainties in generation mixes.

Expanding United States electricity infrastructure to meet growing demand could require extensive power plant development footprints and land use conversion, depending on the mix of generation types chosen. Understanding where future power plant sitings are likely to take place and identifying potential conflicts and land-use tradeoffs will be key to identifying feasible and affordable investments and evaluating regional planning coordination needs. Here we use an integrated modeling framework that combines capacity expansion planning, hourly grid operations, and geospatial techno-economic analysis to develop projections (2025-2050) of power plant sitings in the Western United States (US) at a 1 km2 resolution for a business-as-usual scenario and a high renewables penetration scenario. We find that 30% more land will be needed in the high renewables scenario as compared to business-as-usual, and that 75% of that development is projected to be located within 10 km of natural areas.

As variable renewable energy resources become a larger part of the generation mix in the United States (U.S.), so does the potential impact of prolonged periods of low wind and solar generation, known as variable renewable energy (VRE) droughts. In a future decarbonized or low-carbon grid, naturally occurring VRE droughts need to be evaluated for their potential impact on grid reliability. This study is the first of its kind to examine the impacts of compound VRE energy droughts in the Western U.S. across a range of climate change and future infrastructure scenarios. We find that compound VRE drought severity will increase significantly in the future, primarily due to the dramatic increase in wind and solar generation needed to meet decarbonization goals. Climate change is expected to increase the variability of energy drought severity, which has implications for sizing energy storage necessary for mitigating drought events. We also examine the spatial patterns of compound VRE drought events that effect multiple regions of the grid simultaneously. These co-occurring events have distinct spatial patterns depending on the season. We observed overall fewer connected events in the future with the combined effect of climate change and infrastructure growth, although in the fall we observe a climate change-induced shift toward events which impact more regions simultaneously.

If renewable energy resources continue to become a larger part of the generation mix in the United States (U.S.), so does the potential impact of prolonged periods of low wind and solar generation, known as variable renewable energy (VRE) droughts. In such a future, naturally occurring VRE droughts need to be evaluated for their potential impact on grid reliability. This study is the first of its kind to examine the impacts of compound VRE energy droughts in the Western U.S. across a range of potential future climate and infrastructure scenarios. We find that compound VRE drought severity may increase significantly in the future, primarily due to the dramatic increase in wind and solar generation needed in some future infrastructure scenarios. We find that in our future climate scenario, the variability of energy drought severity increases, which has implications for sizing energy storage necessary for mitigating drought events. We also examine the spatial patterns of compound VRE drought events that effect multiple regions of the grid simultaneously. These co-occurring events have distinct spatial patterns depending on the season. We observed overall fewer connected events in the future with the combined effect of potential climate and infrastructure changes, although in the fall we observe a climate-induced shift toward events which impact more regions simultaneously.

There is growing recognition of the advantages of interregional transmission capacity to decarbonize electricity grids. A less explored benefit is potential performance improvements during extreme weather events. This study examines the impacts of cooperative transmission expansion planning using an advanced modeling chain to simulate power grid operations of the United States Western Interconnection in 2019 and 2059 under different levels of collaboration between transmission planning regions. Two historical heat waves in 2019 with varying geographical coverage are replayed under future climate change in 2059 to assess the transmission cooperation benefits during grid stress. The results show that cooperative transmission planning yields the best outcomes in terms of reducing wholesale electricity prices and minimizing energy outages both for the whole interconnection and individual transmission planning regions. Compared to individual planning, cooperative planning reduces wholesale electricity prices by 64.3 % and interconnection-wide total costs (transmission investments + grid operations) by 34.6 % in 2059. It also helps decrease greenhouse gas emissions by increasing renewable energy utilization. However, the benefits of cooperation diminish during the widespread heat wave when all regions face extreme electricity demand due to higher space cooling needs. Despite this, cooperative transmission planning remains advantageous, particularly for California Independent System Operator with significant diurnal solar generation capacity. This study suggests that cooperation in transmission planning is crucial for reducing costs and increasing reliability both during normal periods and extreme weather events. It highlights the importance of optimizing the strategic investments to mitigate challenges posed by wider-scale extreme weather events of the future.

The motivation of the Integrated Water Power Resilience Project is to identify and develop opportunities for improving resilience in the water and power sectors through coordinated planning, investment, and operations and thereby provide benefits to power and water utilities, consumers, and the environment. Water and power systems are interdependent, subject to many of the same natural and manmade hazards, and are critical for the well-being of communities and society. Because of the interconnectedness of water and power systems, there are substantial economic, social, and environmental benefits to co-managing the market sectors for resilience instead of managing them separately. To support this initiative and future research in this area, a county level water and energy flow dataset was developed to build, calculate, and visualize interconnections in water and energy between various sectors. This report presents county and regional water and energy visualizations across nine economic sectors of the United States: agriculture, commercial, electricity generation, industrial, mining, public water supply, residential, transportation, and wastewater treatment.

Utilities and state energy regulators have historically incorporated community participation late in the process of creating programs and policies, often after most or all decisions have already been made. As more organizations seek to address energy inequity, they have engaged stakeholders in a variety of ways and at different stages of program development with varying levels of success. In this paper, we propose a continuous participation and feedback approach to system equity improvements and evaluation that incorporates engagement in planning and decision making processes as an integrated cycle. We provide example methods for increasing participation, developing structures and processes to receive and incorporate feedback, and measuring outcomes. Equity outcomes are particularly difficult to measure due to the impact of other socioeconomic and historic conditions, as well as the qualitative nature of experiences of inequity. To identify a set of equity outcomes that can be impacted by increased participation, we examine the relationship between regulators, utilities, and the community, and propose that folding engagement and continuous feedback into the normal functions of these organizations can improve the outcomes for energy system users.

As climate change impacts become increasingly severe, it is critical to have a comprehensive understanding of interactions between climate, energy, and water. Previous energy-water nexus studies have focused primarily on specific dependencies, such as water for thermoelectric cooling, rather than the potential for cascading impacts of supply disruptions at broader scales. This paper explores relative energy-water interdependencies across multiple sectors at the scale of the three primary electricity interconnections within the United States. Our results indicate the need for and potential benefits of integrated policy, planning, and management of energy and water resources based on an interdependent systems perspective.

Climate change, energy system transitions, and socioeconomic change are compounding influences affecting the growth of electricity demand. While energy efficiency initiatives and distributed resources can address a significant amount of this demand, the United States will likely still need new utility-scale generation resources. The energy sector uses capacity expansion planning models to determine the aggregate need for new generation, but these models are typically at the state or regional scale and are not equipped to address the wide range of location- and technology-specific issues that are increasingly a factor in power plant siting. To help address these challenges, we have developed the Geospatial Raster Input Data for Capacity Expansion Regional Feasibility (GRIDCERF) data package, a high-resolution product to evaluate siting suitability for renewable and non-renewable power plants in the conterminous United States. GRIDCERF offers 264 suitability layers for use with 56 power plant technologies in a harmonized format that can be easily ingested by geospatially-enabled modeling software allowing for customization to robustly address science objectives when evaluating varying future conditions.

While over 1400 GW of distributed wind potential has been documented in the United States, less than 0.01% of that has been deployed to date. Significant amounts of renewable resources will need to be deployed in coming years to meet national clean energy goals, making the identification of opportunities and barriers to deployment for this resource a topic of high interest. Wind resource variability, which can cause uncertainty and instability in the grid and affect the number of attainable and beneficial applications the resource can pursue, is often a common hurdle to deployment. Pairing distributed wind with other technologies, such as solar photovoltaics and/or energy storage, however, has the ability to alleviate this issue through generation complementarity and increased dispatchability. Both characteristics have the potential to increase project value across a range of applications from bulk energy to ancillary services. Understanding where and how value differs under various hybrid configurations (e.g., distributed wind with solar, distributed wind with solar and storage) can overcome barriers to deployment and improve the economic vitality of projects. In this study, we describe the potential value impacts of adding solar photovoltaics and/or energy storage to a distributed wind energy installation, provide a qualitative ranking system for each value stream that might be available for the new hybrid power system, and present quantitative results for the potential dollars per year that might be possible for select value streams. From a benefits perspective, we find that hybridizing has the potential to add value to all value streams, with the addition of energy storage providing greater value impact than that of solar photovoltaics.