Enhanced geothermal systems (EGSs) are an emerging energy technology with the potential to greatly expand the viable resource base for geothermal power generation. Although EGSs have traditionally been envisioned as ‘baseload’ resources, flexible operation of EGS wellfields could allow these plants to provide load-following generation and long-duration energy storage. In this work we evaluate the impact of operational flexibility on the long-run system value and deployment potential of EGS power in the western United States. We find that load-following generation and in-reservoir energy storage enhance the role of EGS power in least-cost decarbonized electricity systems, substantially increasing optimal geothermal penetration and reducing bulk electricity supply costs compared to systems with inflexible EGSs or no EGSs. Flexible geothermal plants preferentially displace the most expensive competing resources by shifting their generation on diurnal and seasonal timescales, with round-trip energy storage efficiencies of 59–93%. Benefits of EGS flexibility are robust across a range of electricity market and geothermal technology development scenarios.
Climate change is expected to intensify the effects of extreme weather events on power systems and increase the frequency of severe power outages. The large-scale integration of environment-dependent renewables during energy decarbonization could induce increased uncertainty in the supply–demand balance and climate vulnerability of power grids. This Perspective discusses the superimposed risks of climate change, extreme weather events and renewable energy integration, which collectively affect power system resilience. Insights drawn from large-scale spatiotemporal data on historical US power outages induced by tropical cyclones illustrate the vital role of grid inertia and system flexibility in maintaining the balance between supply and demand, thereby preventing catastrophic cascading failures. Alarmingly, the future projections under diverse emission pathways signal that climate hazards — especially tropical cyclones and heatwaves — are intensifying and can cause even greater impacts on the power grids. High-penetration renewable power systems under climate change may face escalating challenges, including more severe infrastructure damage, lower grid inertia and flexibility, and longer post-event recovery. Towards a net-zero future, this Perspective then explores approaches for harnessing the inherent potential of distributed renewables for climate resilience through forming microgrids, aligned with holistic technical solutions such as grid-forming inverters, distributed energy storage, cross-sector interoperability, distributed optimization and climate–energy integrated modelling.
The Inflation Reduction Act (IRA) is regarded as the most prominent piece of federal climate legislation in the U.S. thus far. This paper investigates potential impacts of IRA on the power sector, which is the focus of many core IRA provisions. We summarize a multi-model comparison of IRA to identify robust findings and variation in power sector investments, emissions, and costs across 11 models of the U.S. energy system and electricity sector. Our results project that IRA incentives accelerate the deployment of low-emitting capacity, increasing average annual additions by up to 3.2 times current levels through 2035. CO2 emissions reductions from electricity generation across models range from 47%–83% below 2005 in 2030 (68% average) and 66%–87% in 2035 (78% average). Our higher clean electricity deployment and lower emissions under IRA, compared with earlier U.S. modeling, change the baseline for future policymaking and analysis. IRA helps to bring projected U.S. power sector and economy-wide emissions closer to near-term climate targets; however, no models indicate that these targets will be met with IRA alone, which suggests that additional policies, incentives, and private sector actions are needed.
This paper analyzes how the rise of wind and solar power impacts electricity market design, focusing on the shift towards carbon-free technologies. The growth of renewables is expected to increase price volatility daily and seasonally. Traditionally, market designs don’t consider volatility a problem. However, the potential for higher revenue volatility could increase investment costs in competitive markets, raising doubts about the sustainability of such models as renewables grow. We introduce a stochastic equilibrium model with financial entities providing hedging for generation capacity investments. This model uniquely calculates the cost of capital based on revenue volatility and market participants’ risk measures. Initial findings suggest that systems dominated by renewables might have lower investment risks due to less fuel price uncertainty. However, the risk reduction isn’t uniform across all resource types. The paper highlights that increased risk for peaking and backup resources could result in lower reliability in future modeled electricity systems.
To meet ambitious global decarbonization goals, electricity system planning and operations will change fundamentally. With increasing reliance on variable renewable energy resources, energy storage will probably play a critical accompanying role to help balance generation and consumption patterns. As grid planners, non-profit organizations, non-governmental organizations, policy makers, regulators and other key stakeholders commonly use capacity expansion modelling to inform energy policy and investment decisions, it is crucial that these processes capture the value of energy storage in energy-system decarbonization. Here we conduct an extensive review of literature on the representation of energy storage in capacity expansion modelling. We identify challenges related to enhancing modelling capabilities to inform decarbonization policies and electricity system investments, and to improve societal outcomes throughout the clean energy transition. We further identify corresponding research activities that can help overcome these challenges and conclude by highlighting tangible real-world outcomes that will result from pursuing these research activities.
The Inflation Reduction Act (IRA) in the U.S. offers significant incentives for low-carbon hydrogen and liquid fuels, impacting their cost-competitiveness by the early 2030s. This study examines the IRA’s effects on producing hydrogen and synthetic liquid fuel from natural gas, electricity, biomass, and ethanol. Findings show that with IRA credits, green hydrogen and blue hydrogen (from natural gas with carbon capture) become cost-competitive with traditional gray hydrogen. Biomass-derived hydrogen isn’t cost-competitive under current IRA provisions. However, if biomass gasification with carbon capture could claim IRA credits, it would be cheaper than gray hydrogen. For synthetic liquid fuels to compete with petroleum fuels, the IRA’s clean fuels credit, ending in 2027, requires extension or additional policy support. The subsidies per unit of CO2 mitigated for these pathways, except electricity-derived synthetic fuel, range from $65 to $384 per ton, within or below U.S. estimates of the social cost of carbon for 2030–2040.
The paper addresses the inefficiencies in large-scale energy systems planning models, traditionally based on linear programming (LP) or mixed integer linear programming (MILP). These models often struggle with tractability due to necessary abstractions that compromise result quality. To overcome this, the authors introduce a novel Benders decomposition approach. This method separates investment from operational decisions and decouples operational time steps using budgeting variables, enabling parallel processing of subproblems and accommodating policy constraints over time. This new approach significantly improves runtime, scaling linearly with temporal resolution, and shows marked runtime reductions for all MILP and some LP formulations, varying with problem size. Beyond energy, this algorithm is applicable to planning in domains like water, transportation, and production processes. Notably, it can tackle large-scale problems otherwise intractable. The enhanced resolution achieved through this method reduces structural uncertainty, thereby improving the accuracy of planning and investment recommendations.
Addressing global warming in line with the Paris Agreement, the Inflation Reduction Act of 2022 (IRA) in the U.S. stands as a pivotal piece of climate legislation. It encompasses a broad array of programs, targeting clean energy, carbon management, electrification, efficiency, methane emission reduction, bolstering domestic supply chains, and addressing environmental justice. Understanding its complex impact on emissions and energy systems necessitates robust modeling. Analysis from nine advanced models suggests that the IRA might enable the U.S. to reduce emissions by 43 to 48% from 2005 levels by 2035. This multimodal approach provides critical data for international policymakers tracking Paris Agreement commitments and for U.S. policymakers aligning targets with necessary actions. Electric companies can use this analysis to determine the longevity of IRA incentives, linked to reducing electricity emissions. Additionally, it assists investors, technology developers, and companies in identifying market opportunities and planning for industry-specific developments.
Land-use conflicts may constrain the unprecedented rates of renewable energy deployment required to meet the decarbonization goals of the Inflation Reduction Act (IRA). This paper employs geospatially resolved data and a detailed electricity system capacity expansion model to generate 160 affordable, zero-carbon electricity supply portfolios for the American west and evaluates the land use impacts of each portfolio. Less than 4% of all sites suitable for solar development and 17% of all wind sites appear in this set of portfolios. Of these sites, 53% of solar and 85% of wind sites exhibit higher development risk and potential for land-related conflict. We thus find that clean electricity goals cannot be achieved affordably without substantial renewable development on sites with potential for land use conflict. However, this paper identifies significant flexibility across western U.S. states to site renewable energy or alter the composition of the electricity supply portfolio to ameliorate potential conflicts.
Achieving a net-zero emissions goal in the U.S. by mid-century requires a transformation of both the energy system and workforce. A new labor model, incorporating geospatial energy system projections, predicts that the transition could support 3 million direct energy jobs or $200 billion in wages annually in the next decade, growing to 4–8 million jobs or $200–500 billion in the 2040s. The energy workforce, 1.5% of the U.S. labor force in 2020, may increase to 2.5–5% by mid-century. The shift will cause boom-and-bust cycles in employment, with losses in fossil fuels balanced by gains in low-carbon sectors. The study also assesses workforce development needs, predicting larger scale changes than in past transitions. Factors like technology choice, infrastructure expansion, and political decisions will influence labor pathways, with most states potentially experiencing long-term workforce growth in energy, subject to regional variations and political bargaining.