James G. Carton

Aviation contributes approximately 2.4% of global CO₂ emissions and 3.5% of total effective radiative forcing when non-CO₂ effects are included, yet Sustainable Aviation Fuel (SAF) accounts for less than 0.5% of European jet fuel consumption. This paper investigates why the gap between policy ambition and deployment persists, asking (i) how misaligned instruments across ReFuelEU Aviation, RED III, CORSIA, and the UK RTFO impede high-integrity production pathways, and (ii) what convergence mechanisms can reduce fragmentation beyond Hydroprocessed Esters and Fatty Acids (HEFA)-dominated supply. Applying the Multi-Level Perspective framework, the study triangulates comparative policy analysis with a stakeholder survey (n = 45) across SAF producers, airlines, policymakers, and investors. Results identify regulatory fragmentation, capacity constraints, and funding barriers as near-equally weighted obstacles, while disaggregation reveals actor-specific priorities: policymakers emphasise regulatory complexity, airlines emphasise funding, and producers emphasise capacity. Most producers declined to disclose volume projections, interpreted here as strategic ambiguity under regulatory uncertainty. Three convergence mechanisms are proposed: harmonised carbon-intensity registries, standardised book-and-claim accounting, and joint feedstock certification protocols. The findings align aviation decarbonisation with SDGs 7, 9, 12, and 13. Without coherent policy architecture, SAF deployment risks entrenching low-ambition compliance pathways that undermine the EU’s contribution to the 2030 Agenda.

The transition to a low-carbon economy is now imperative for the global community as a target for achieving the Sustainable Development Goals (SDGs) and Paris Agreement ambitions. Hydrogen has been identified as an essential tool for attaining decarbonisation targets across several aspects of global energy systems. However, developing countries that themselves can be most affected by climate change are under intense pressure to hold back developing their fossil fuel-based resources in favour of renewable energy systems and, where possible, explore the production of green and low-carbon hydrogen. This work explores the implication of low-carbon hydrogen development in ensuring a just energy transition for developing countries. Through a comprehensive review of relevant materials, the work identifies what role natural gas can serve in achieving the energy transition plans of many fossil fuel-rich developing economies and how, at a larger scale, the production of blue hydrogen from natural gas can help decarbonise hard-to-abate emissions. While green hydrogen is often touted as the ultimate goal for a sustainable hydrogen economy, it faces numerous challenges. The production of green hydrogen is currently more expensive compared to blue hydrogen, which is derived from natural gas with carbon capture and storage (CCS) technologies. This cost disparity makes it difficult for developing countries to adopt green hydrogen on a large scale, especially when they have abundant fossil fuel resources that can be utilised for blue hydrogen production. Moreover, the infrastructure for green hydrogen production and distribution is still in its nascent stages, requiring substantial investments that many developing countries may find prohibitive. In contrast, blue hydrogen can leverage existing natural gas infrastructure, making it a more feasible option in the short to medium term. In essence, while green hydrogen represents the ideal long-term solution for a low-carbon future, blue hydrogen offers a more immediate and practical pathway for developing countries to transition towards a sustainable energy system. This balanced approach ensures that these countries can contribute to global decarbonization efforts without compromising their economic development and energy security. The work aims to inform policymakers, scientists, and the public on the potential role of existing natural gas resources in critical decarbonisation points and their role in establishing a just energy transition for developing economies, while highlighting the financial and infrastructural limitations of green hydrogen adoption and calling for further research on context-specific pathways to hydrogen integration in national energy systems.

The performance of an air-source heat pump water-heater (ASHPWH) system manufactured by Kronoterm was benchmarked in this study for the application of dairy farming in Ireland. The COP of the system was calculated to be 2.27 under normal operating conditions. The device was able to supply water at 80 °C, however a full tank at this temperature was not achieved or deemed necessary for the dairy application. Litres per kWh was used as a performance metric for the device and the usable water per unit of energy for the system was found to be 397 L when using both electric heaters and 220 L when using just the top heater both in conjunction with the heat pump. The performance of the heat pump system in terms of its cost to run and efficiency was also compared with five other water heaters. The heat pump is seen to be very efficient, however due to the carbon intensity of the Irish grid electricity and high water temperatures required, the solar water heater with gas backup was found to be the best performing under energy efficiency and carbon emissions per litre of usable water. In conclusion, although the heat pump was not the best-performing system under these metrics, the cost and complexity of the solar-gas system may be a deterrent for dairy farmers and for this reason, the heat pump is considered a cost-effective, efficient and viable option for dairy farmers trying to reduce their carbon footprint and energy bills.

The results of a techno-economic model of distributed wind-hydrogen systems (WHS) located at each existing wind farm on the island of Ireland are presented in this paper. Hydrogen is produced by water electrolysis from wind energy and backed up by grid electricity, compressed before temporarily stored, then transported to the nearest injection location on the natural gas network. The model employs a novel correlation-based approach to select an optimum electrolyser capacity that generates a minimum levelised cost of hydrogen production (LCOH) for each WHS. Three scenarios of electrolyser operation are studied: (1) curtailed wind, (2) available wind, and (3) full capacity operations. Additionally, two sets of input parameters are used: (1) current and (2) future techno-economic parameters. Additionally, two electricity prices are considered: (1) low and (2) high prices. A closest facility algorithm in a geographic information system (GIS) package identifies the shortest routes from each WHS to its nearest injection point. By using current parameters, results show that small wind farms are not suitable to run electrolysers under available wind operation. They must be run at full capacity to achieve sufficiently low LCOH. At full capacity, the future average LCOH is 6–8 €/kg with total hydrogen production capacity of 49 kilotonnes per year, or equivalent to nearly 3% of Irish natural gas consumption. This potential will increase significantly due to the projected expansion of installed wind capacity in Ireland from 5 GW in 2020 to 10 GW in 2030.