The U.S. introduced a production tax credit (PTC) to encourage low-carbon hydrogen production, essential for a net-zero carbon economy. Hydrogen produced via electrolysis qualifies for the full subsidy if using carbon-free electricity, but may not if the electricity mix includes emitting resources. This study explores the effects of grid-connected electrolysis on the western U.S. power sector through 2030 under various clean hydrogen PTC implementations. It finds that subsidized grid-connected hydrogen production could induce higher emissions than fossil-based methods. Minimizing emissions requires grid-based hydrogen producers to match their electricity consumption hourly with clean, deliverable generation, effectively mirroring behind-the-meter carbon-free generation. Despite this, indirect emissions from competition for clean resources persist. The study suggests that stringent hourly matching standards consistently outperform other methods, with added costs less than $1 per kg and potentially negligible if clean, firm electricity resources are available. This approach addresses indirect emissions without significantly increasing production costs.
This report assesses the role of electricity transmission in enabling the full emissions reduction potential of the Inflation Reduction Act (IRA). Previously, REPEAT Project estimated that IRA could cut U.S. greenhouse gas emissions by roughly one billion tons per year in 2030 and reduce cumulative greenhouse gas emissions by 6.3 billion tons of CO2-equivalent over the decade (2023-2032).1 That outcome depends on more than doubling the historical pace of electricity transmission expansion over the last decade in order to interconnect new renewable resources at sufficient pace and meet growing demand from electric vehicles, heat pumps, and other electrification. While our modeling finds this outcome makes economic sense, current transmission planning, siting, permitting and cost allocation practices can all potentially impede the real-world pace of transmission expansion. We thus model the impact of constrained growth in U.S. electricity transmission on emissions outcomes and the pace of renewable electricity expansion under IRA.
This study aims to assess the most cost-effective pathways for New Jersey to achieve 100% carbon-free electricity, in line with its current laws and policy objectives. It explores the potential roles of in-state solar PV, offshore wind, nuclear power, and imported electricity in meeting the state’s future electricity needs. The study provides an independent analysis of the costs and trade-offs associated with different strategies, offering insights for decision-makers. Using the advanced GenX electricity system optimization model, the study plans investment and operational decisions to meet future electricity demand within engineering, reliability, and policy constraints at minimal cost. It models the electricity system of New Jersey, the PJM Interconnection, and neighboring regions, covering 15 zones in total, to evaluate various policy, technology, and fuel price scenarios. The goal is to find feasible options for New Jersey to achieve a completely carbon-free electricity supply by 2050.
In electricity systems with many variable renewables, flexible operation of natural gas combined cycle (NGCC) power plants with carbon capture and sequestration (CCS) can increase their economic value. This study evaluates NGCC-CCS plants with solvent storage for such operation, using a modular modeling framework for accuracy and efficiency. The model divides NGCC-CCS plants into subcomponents, applying linear constraints for energy and mass balances, and addressing unit commitment (UC) constraints in thermal power plants. This approach employs linear relaxation of UC decision variables alongside a generator clustering method for flexible CCS modeling. Integrated into a power system model, it shows the hourly operations of NGCC-CCS and impacts on system performance. The results indicate faster computational times than traditional binary UC methods, with minimal errors. Flexible NGCC-CCS plants reduce operating costs, especially during peak demand, proving beneficial in grids with increasing renewable energy.
GenX is a highly-configurable, open source electricity resource capacity expansion model that incorporates several state-of-the-art practices in electricity system planning to offer improved decision support for a changing electricity landscape. GenX is a constrained linear or mixed integer linear optimization model that determines the portfolio of electricity generation, storage, transmission, and demand-side resource investments and operational decisions to meet electricity demand in one or more future planning years at lowest cost, while subject to a variety of power system operational constraints, resource availability limits, and other imposed environmental, market design, and policy constraints. GenX features a modular and transparent code structure developed in Julia + JuMP. The model is designed to be highly flexible and configurable for use in a variety of applications from academic research and technology evaluation to public policy and regulatory analysis and resource planning.
The Biden administration aims to cut U.S. greenhouse gas emissions by 50%-52% below 2005 levels by 2030 and achieve net-zero emissions by 2050. These goals are attainable but require a collaborative, nation-building effort involving federal, state, local governments, the private sector, and communities to rapidly transform the U.S. energy system. While macro-scale energy modeling studies inform net-zero planning, they often lack the granularity needed to address real-world challenges. The Net-Zero America (NZA) study stands out for its detailed approach, offering spatial, temporal, and sector-specific pathways. These pathways rely on highly technologically ready solutions (Technology Readiness Level 6 or greater) and can achieve emissions targets akin to the Biden administration’s goals by 2030 and net-zero emissions by 2050. The study reveals similarities among pathways over the next decade, with annual spending on energy services as a percentage of GDP remaining relatively constant throughout the transition.
Achieving net-zero greenhouse gas emissions in the U.S. by mid-century requires a transformation of the energy workforce. This study examines the impact of increased labor compensation and domestic manufacturing on renewable energy technology costs, the overall cost of transitioning to net-zero emissions, and labor outcomes related to utility-scale solar photovoltaics (PV) and wind power. This study reveals that labor cost premiums and higher domestic content in wind and solar PV supply chains result in relatively minor increases in capital and operating costs. These cost increases can potentially be offset by improved labor productivity. Additionally, the study finds that technology cost premiums associated with labor-friendly policies have a minimal impact on renewable energy deployment and the overall transition cost to a net-zero emissions economy. Public policies, including tax credits and workforce development support, can help redistribute technology cost premiums to benefit both firms and workers in the renewable energy sector.
In decarbonized electricity systems with significant variable renewables, having at least one firm electricity generation technology is essential for reliability and cost reduction. These firm resources operate year-round and include low- and zero-carbon options like flexible resources (e.g., biogas or hydrogen combustion), capital-intensive resources (e.g., nuclear and geothermal), and intermediate resources (e.g., natural gas with CCS). This study explores nuclear, CCS, and zero-carbon fuel combustion roles in decarbonized electricity systems, showing their unique contributions. It analyzes data from three long-term electricity system models covering California and the U.S. Western Interconnection. Each firm technology significantly lowers costs compared to portfolios relying solely on renewables and energy storage. Having all these options optimizes utilization rates, reducing system costs by up to 10% compared to single firm resource scenarios. This analysis highlights diverse technology’s value in achieving emissions reduction goals while ensuring power sector reliability and affordability.
Wind, solar, and lithium-ion batteries have become more affordable, driving their adoption in the transition to a decarbonized electricity grid. However, these technologies have limitations in providing consistent power during extended periods of high demand when renewable generation may be insufficient. This challenge has led to increased interest in long-duration energy storage (LDES). LDES encompasses a wide range of options, making it difficult to identify promising pathways or prioritize research efforts. In recent research, we and our colleagues employed a comprehensive long-term electricity system planning model to analyze various combinations of five key LDES parameters across 14 scenarios. This extensive analysis helps navigate the diverse landscape of LDES technologies and provides essential cost and performance targets. It offers valuable insights to guide innovation and commercialization efforts, ensuring the development of efficient long-duration energy storage solutions for reliable grid operations, even in scenarios of prolonged high demand.
Long-duration energy storage (LDES) is a potential solution to intermittency in renewable energy generation. This study evaluated the role of LDES in decarbonized electricity systems and identified the cost and efficiency performance necessary for LDES to substantially reduce electricity costs and displace firm low-carbon generation. We find that energy storage capacity cost and discharge efficiency are the most important performance parameters. Charge/discharge capacity cost and charge efficiency play secondary roles. Energy capacity costs must be ≤US$20 kWh–1 to reduce electricity costs by ≥10%. With current demand profiles, energy capacity costs must be ≤US$1 kWh–1 to displace all modelled firm low-carbon generation technologies. Electrification of end uses in a northern latitude context makes full displacement of firm generation more challenging and requires performance combinations unlikely to be feasible with known LDES technologies. Finally, LDES systems with the greatest impact on electricity cost and firm generation have storage durations exceeding 100 h.