Official development assistance (ODA) is an important global partnership strategy for promoting global sustainable development and reducing inequality within and among countries, especially for the least developed countries (LDCs). However, little is known about whether ODA can effectively promote social equality while respecting planetary boundary. Therefore, we establish an integrated “Social equality- Planetary boundary-ODA” framework to investigate how ODA influences social equality within planetary boundary. Considering regional development stages and investment preferences, the improvement strategies for ODA are proposed and examined. Taking LDCs as the example, our results show that ODA positively affects education equality and gender equality but negatively impacts income equality, while maintaining the planetary boundary. Moreover, a productive assistance strategy can enhance social equality with minimal impact on planetary boundary. Our research contributes to more effective ODA strategies for promoting sustainable development of underdeveloped regions within a just and safe boundary.

Coffee processing encompasses the conversion of coffee cherries into marketable products, including the removal of outer layers to produce green coffee and, in extended chains, their roasting into roasted coffee, and grinding into ground coffee. Calculating the carbon footprint (CF) in coffee processing is crucial for identifying and mitigating key sources of greenhouse gas (GHG) emissions. Utilizing the Life Cycle Assessment (LCA) methodology, the current study quantifies the CF associated with Robusta dry coffee processing by collecting primary data through interviews with coffee producers and visits to coffee processing units, roasting, and grinding facilities in Wayanad, India. The study identifies GHG emission hotspots across two scenarios. Scenario A includes transportation of dried coffee beans from farm to coffee processing unit, green coffee production, packaging, roasting, and grinding at a local unit, while Scenario B covers local transportation of green coffee beans from India to The Netherlands, green coffee production, packaging, and its transportation from India to The Netherlands. Cultivation and harvesting of coffee cherries, consumer-level preparation and use, and disposal of coffee products are outside the scope of this study. The functional unit is defined as 1 kg of green coffee for both scenarios. Findings show that the CF equals 0.62 and 0.38 kg CO_2eq per kg of green coffee for scenarios A and B, respectively. Roasting (78 % of CF), and sea transportation (66 % of CF) emerged as the main hotspots of GHG emissions for scenario A, and scenario B, respectively.

Due to computational limits, temporal details within Energy System Optimisation Models are often reduced, for example by reducing the time horizon or by resampling via Time Series Aggregation (TSA) techniques. In high RES energy systems, this may lead to undersizing of Long-Duration Energy Storage (LDES) capacities, necessary for system flexibility, due to the omission of long-term interannual weather effects. Via comparative analysis between the capacity expansion results for different subsets of weather years, this paper shows the extent to which single year models underpredict LDES. but also that a small cluster (n=2, 3) of weather years can adequately capture key system-defining weather patterns. Identifying these weather years ex-ante is non-trivial, as there is no obvious correlation with how well they describe the full set of weather years. As this assumed correlation underpins current time series aggregation techniques, new techniques are required.

Off-grid hydrogen supply from solar or wind sources to hydrogen-based steelmaking can reduce CO₂ emissions. However, the techno-economic feasibility of different supply chain configurations remains uncertain. This study evaluates 61 off-grid hydrogen supply chains for a 15 Mt. steel/year plant in 2030, considering renewable energy sources (onshore/offshore wind, solar, and overseas options), transmission technologies (cables, pipelines, trucks, and ships), storage technologies (compressed gaseous hydrogen, liquid hydrogen, ammonia, methanol, and liquid organic hydrogen carriers), and seasonal storage locations (at the energy source or steelmaking plant). Onshore truck transmission of hydrogen is found to be unpromising due to the significantly higher cost compared to alternative transmission technologies. When the transmission technology is not truck, chains with underground compressed hydrogen storage achieve the lowest levelized cost of hydrogen (LCOH) at 3.8–5.6 €₂₀₂₀/kg H₂, outperforming other options. When underground hydrogen storage is not feasible, liquid organic hydrogen carriers present the next lowest cost. Chains utilizing ammonia, methanol, and liquid hydrogen exhibit lower efficiency, higher renewables capacity requirement, and consequently higher LCOH, making them less attractive. Electricity transmission lowers the LCOH of compressed hydrogen chains compared to hydrogen pipeline transmission, but for other chains the trend is reversed. Hydrogen storage near the steelmaking plant reduces costs by enabling the reuse of boil-off hydrogen in liquid hydrogen chains, but for other chains storing hydrogen near the renewable energy source lowers the cost. Impacts of input uncertainties on the LCOH, limitations of this study, and suggestions for future studies are also presented.

To achieve the European Union's goal of climate neutrality by 2050, negative emissions may be required to compensate for emissions exceeding allocated carbon budgets. Therefore, carbon removal technologies such as bioenergy with carbon capture (BECCS) and direct air capture (DAC) may need to play a pivotal role in the power system. To design carbon removal strategies, more insights are needed into the impact of sustainable biomass availability and the feasibility of carbon capture and storage (CCS), including the expensive and energy-intensive DAC on achieving net-zero and net-negative targets. Therefore, in this study the European power system in 2050 is modelled at an hourly resolution in the cost-minimization PLEXOS modelling platform. Three climate-neutral scenarios with targets of 0, -1, and -3.9 Mt CO₂/year (which agree with varying levels of climate justice) are assessed for different biomass levels, and CCS availability. Findings under baseline assumptions reveal that in a climate-neutral power system with biomass and CCS options, it is cost-effective to complement variable renewable energy with a mix of combined cycle natural gas turbines (CCNGT) for flexibility and BECCS as base load to compensate for the CO₂ emissions from natural gas and additional carbon removal in the net-negative scenarios. The role of these technologies becomes more prominent, with -3.9 GtCO₂/year target. Limited biomass availability necessitates additional 0.4–4 GtCO₂/year DAC, 10–50 GW CCNGT with CCS, and 10–50 GW nuclear. Excluding biomass doubles system costs and increases reliance on nuclear energy up to 300 TWh/year. The absence of CCS increases costs by 78%, emphasizing significant investments in bioenergy, nuclear power, hydrogen storage, and biogas. Sensitivity analysis and limitations of the study are fully discussed.

This study evaluates the technoeconomic impacts of direct and indirect electrification on the EU's net-zero emissions target by 2050. By linking the JRC-EU-TIMES long-term energy system model with PLEXOS hourly resolution power system model, this research offers a detailed analysis of the interactions between electricity, hydrogen and synthetic fuel demand, production technologies, and their effects on the power sector. It highlights the importance of high temporal resolution power system analysis to capture the synergistic effects of these components, often overlooked in isolated studies. Results indicate that direct electrification increases significantly and unimpacted by biomass, CCS, and nuclear energy assumptions. However indirect electrification in the form of hydrogen varies significantly, between 1400 and 2200 TWh_H2 by 2050. Synthetic fuels are essential for sector coupling, making up 6–12% of total energy consumption by 2050, with the power sector supplying most hydrogen and CO₂ for their production. Varying levels of indirect electrification impact electrolysers, renewable energy, and firm capacities. Higher indirect electrification increases electrolyser capacity factors by 8%, leading to more renewable energy curtailment but improves system reliability by reducing 11 TWh unserved energy and increasing flexibility options. These insights inform EU energy policies, stressing the need for a balanced approach to electrification, biomass use, and CCS to achieve a sustainable and reliable net-zero energy system by 2050. We also explore limitations and sensitivities.

This research aims to investigate the potential impact of national policies on the attainment of Europe's goal of achieving net-zero greenhouse gas emissions by 2050. Specifically, it analyses the effects of policies on the power sector, by evaluating capacity expansion portfolios, import reliance, and costs by 2050. A linear programming model, the IESA-EUPS, is utilized to optimize the expansion and operation of the power system, considering 28 nodes and hourly temporal resolution. The study includes five scenarios from 2020 to 2050, with varying levels of biomass and nuclear penetration based on existing member state policies. Results show that by 2050, changes mainly occur in the interplay between firm capacities and cross-border transmission levels. Limiting biomass can significantly increase nuclear energy generation, while enforcing all policies leads to a 40 % rise in cross-border transmission by 2050, due to imbalances between countries. Some member states, such as Spain and Finland, are less affected, whereas others are heavily reliant on firm nuclear capacities. Western European countries with strict biomass and nuclear restrictions may see a boost in nuclear installations in countries allowing it. Member states without both nuclear and biomass may rely more on variable renewables, resulting in surplus electricity and increased LCOE.

The transition of the European iron and steel industry (ISI) towards low-carbon manufacturing is crucial for the European Union (EU)’s 2050 climate neutrality objective. One emerging solution is electrification by using hydrogen (H₂) as iron ore reductant, which increases specific electricity use per tonne of steel up to 35 times compared to the conventional, most adopted coal-based technology. This study develops three scenarios, encompassing a moderate to an accelerated ISI transition, to evaluate the impact of the ISI decarbonisation on the power system CO₂ emissions, generation mix and volume, and marginal prices in 2030. The study first estimates future electricity and H₂ demand by considering country-specific technologies deployment and energy intensities. Then, these estimates serves as input to the model METIS to simulate European power system operations through a unit commitment and economic dispatch problem. The study shows that the power system can accommodate a transition of the ISI that substitutes 28% of the coal-based production with low carbon technologies, mainly based on H₂. This leads to a 25% reduction in direct CO₂ emissions and a demand increase of 20 TWh of electricity and 40 TWh_HHV of H₂. Furthermore, a 50% reduction in indirect power system emissions is achieved, compared to 2018, thanks to the substantial renewable power capacity deployment foreseen in the coming years. The study also demonstrates that a reduction of indirect CO₂ emissions by over 85% can be achieved by deploying 1.2 and 2.7 GW of renewable power generators, and 200 and 400 MW of electrolyser capacity for each million tonne of steel produced annually with low-carbon technologies. Additional renewable capacity that ensures green steel production is also key to maintaining stable electricity prices.

Importing substantial amount of green hydrogen from countries like South Africa, which have abundant solar and wind potentials to replace fossil fuels, has attracted interest in developed regions. This study analyses South African strategies for improving and decarbonizing the power sector while also producing hydrogen for export. These strategies include the Integrated Resource Plan, the Transmission Development Plan, Just Energy Transition and Hydrogen Society Roadmap for grid connected hydrogen production in 2030. Results based on an hourly resolution optimisation in Plexos indicate that annual grid-connected hydrogen production of 500 kt can lead to a 20–25% increase in the cost of electricity in scenarios with lower renewable energy penetration due to South African emission constraints by 2030. While the price of electricity is still in acceptable range, and the price of hydrogen can be competitive on the international market (2–3 USD/kgH₂ for production), the emission factor of this hydrogen is higher than the one of grey hydrogen, ranging from 13 to 24 kgCO2/kgh₂. When attempting to reach emission factors based on EU directives, the three policy roadmaps become unfeasible and free capacity expansion results in significant sixteen-fold increase of wind and seven-fold increase in solar installations compared to 2023 levels by 2030 in South Africa.

We model the evolution of the Central Western Europe power system until 2040 with an increasing carbon price and strong growth of variable renewable energy sources (vRES) for four electricity market designs: the current energy-only market, a reformed energy-only market, both also with the addition of a capacity market. Each design is modelled for two decarbonisation pathways: one targeting net-zero emissions by 2040 for a 2 °C warming limit, and the other targeting −850 Mt CO₂ y‾ for a 1.5 °C warming limit. We compare these scenarios against the high-level objectives of delivering low-carbon electricity reliably to consumers at the lowest possible cost. Our results suggest that both 2 °C and 1.5 °C compliant systems could be achieved and deliver electricity reliably. In terms of cost, we find the 1.5 °C warming scenarios lead to system costs which are twice as high as the 2 °C scenarios due to the high cost of negative emission technologies – in particular direct air carbon capture (DAC). To make a 1.5 °C target more affordable, policymakers should investigate lower cost alternatives in other sectors, and increase research and development in DAC to reduce its cost.