Fusion could be a part of future decarbonized electricity systems, but it will need to compete with other technologies. In particular, pulsed tokamak plants have a unique operational mode, and evaluating which characteristics make them economically competitive can help select between design pathways. Using a capacity expansion and operations model, we determined cost thresholds for pulsed tokamaks to reach a range of penetration levels in a future decarbonized US Eastern Interconnection. The required capital cost to reach a fusion capacity of 100 GW varied from $2,700 to $7,500 kW−1, and the equilibrium penetration increases rapidly with decreasing cost. The value per unit power capacity depends on the variable operational cost and on the cost of its competition, particularly fission, much more than on the pulse cycle parameters. These findings can therefore provide initial cost targets for fusion more generally in the United States.
The REPEAT Project has finalized its analysis of the climate and energy impacts of key legislation from the 117th Congress, focusing on the Inflation Reduction Act of 2022 (IRA) and the Infrastructure Investment and Jobs Act of 2021 (IIJA). This report, updated with the latest data from 2021, includes enhanced evaluations of methane emissions in the oil and gas sector and opportunities for emission reduction in agriculture and forestry. The analysis introduces three ‘Current Policies’ scenarios—’Conservative’, ‘Mid-range’, and ‘Optimistic’—to account for uncertainties in IRA’s effectiveness and potential supply chain constraints. Additionally, it compares a ‘Frozen Policies’ scenario, reflecting laws as of early 2021, and a ‘Net-Zero Pathway’ scenario, aligning with President Biden’s goals to significantly reduce U.S. greenhouse gas emissions by 2030 and achieve net-zero by 2050. This brief report previews the final findings on these laws’ impact on the U.S.’s greenhouse gas emissions trajectory.
This study examines the environmental and economic viability of different fuel production methods as part of U.S. net-zero greenhouse gas emission strategies. It conducts lifecycle assessments for hydrogen (H2), synthetic natural gas (SNG), and Fischer-Tropsch liquid (FTL) fuels, considering three sources: biomass with carbon capture and storage (CCS), natural gas with CCS, and renewable electricity. The study finds that hydrogen production, especially from biomass with CCS, is more cost-effective and efficient in reducing greenhouse gas emissions than FTL and SNG. Sensitivity analysis reveals the significant impact of capital costs and capacity factors on the levelized costs of carbon mitigation (LCCM), with natural gas-based processes being particularly sensitive to feedstock price changes. Biomass-based fuels with CCS show the highest potential for carbon mitigation and become increasingly cost-effective at higher carbon pricing. These results emphasize the critical importance of biomass-based hydrogen production with CCS in achieving U.S. net-zero emissions goals.
Europe’s reliance on Russian natural gas, highlighted by the Russian-Ukraine conflict, poses a significant energy security risk. To address this, Europe must urgently reduce its dependency on Russian fossil fuels through demand reduction, alternative energy sources, and rapid clean energy infrastructure development. The European Commission’s REPowerEU plan targets a two-thirds reduction in Russian gas imports by 2022 end, but stops short of total elimination until 2027 and lacks a detailed policy analysis for immediate energy security. A new report offers detailed strategies for the EU and the UK to quickly sever Russian gas dependence. It suggests enhancing the REPowerEU plan with additional gas reductions for electricity and adjusting gas storage targets. This report, aligning with other studies, outlines immediate strategies for a Russian gas embargo, assessing policy implications and climate commitments. Its integrated electricity and gas models confirm the feasibility of eliminating Russian gas dependency while maintaining supply security.
In electricity systems with high variable renewable energy, flexible operations of natural gas combined cycle (NGCC) power plants with carbon capture and sequestration (CCS) can enhance economic value. A new model efficiently represents these flexible NGCC-CCS plants. It dissects plants into subcomponents with linear constraints for energy and mass balances, and simplifies complex unit commitment (UC) constraints. This study explores linear relaxation of discrete UC variables with a generator clustering method, integrating this into a power system model. A case study shows the hourly operations of NGCC-CCS components and their impacts on environmental and economic performance. The findings reveal that linear relaxation with generator clustering significantly speeds up runtime (18–527 times faster) and minimizes errors. The model demonstrates that flexible NGCC-CCS plants reduce power system operating costs by adjusting output during peak demand, indicating their increased relevance in future grids dominated by renewable resources.
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.
A recent article by Sovacool et al. used cross-sectional regression to examine the relationship between clean energy deployment and national carbon dioxide (CO2) levels. They reported that nuclear energy deployment isn’t significantly linked to lower CO2 emissions, unlike renewable energy, questioning nuclear power’s effectiveness in reducing emissions from fossil fuels. This study critically reviews Sovacool et al.’s claims and methods, identifying several limitations. It conducts a reanalysis using the same data and time frames but with revised cross-sectional and more robust panel data analyses. The findings contradict Sovacool et al., showing that both nuclear power and renewable energy are associated with lower per capita CO2 emissions, with similar magnitude and significance. Sensitivity analysis confirms this association is resilient to potential omitted variables, indicating that both nuclear power and renewable electricity contribute significantly to reducing CO2 emissions.
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.
The Inflation Reduction Act (IRA) significantly impacts the U.S. energy sector, particularly the PJM Interconnection. It’s projected to increase PJM’s clean electricity to 60% by 2030, up from 48% without the IRA, necessitating faster renewable energy and transmission growth. The IRA could reduce PJM’s CO2 emissions by 37% from 2019/2021 levels, but emissions may rise post-2032 without extended policy support. The Act also lowers electricity costs in PJM. Deeper decarbonization in PJM will require more rapid expansion of low-carbon resources, possibly including advanced technologies like carbon capture and storage (CCS) or long-duration storage by 2035. Implementing a clean electricity standard and CO2 emissions cap and trade could help achieve up to a 90% CO2 reduction by 2035, while maintaining or lowering electricity costs.
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.