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Green ammonia has received significant interest as a zero-carbon energy vector. However, current techno-economic models used to estimate the cost of producing green ammonia only use historical weather datasets as their inputs. Climate change is beginning to have an observable impact on global weather systems, so it is therefore important to examine how resilient locations for green ammonia production will be to the effects of climate change on renewable energy resources. This work examines how the cost of producing green ammonia from offshore wind farms at four locations in the UK could change due to climate change. It uses the 1981–2000, 2021–2040 and 2061–2080 2.2 km projections under the RCP8.5 scenario from the Met Office's UK Climate Projections 2018 dataset, which were bias corrected with reference to the ERA5 reanalysis dataset. Using an islanded green ammonia production model, the achievable levelised cost of ammonia (LCOA) was evaluated at four sites taken from confirmed projects in the UK's Offshore Wind Licensing Round 4, with the achievable LCOAs found to range between 935 and 1696 USD/t. Results from the three time periods were compared to assess the impact of climate change and were benchmarked against LCOAs from conventional production pathways. At all sites, increases of between 6 % and 8 % of the average LCOAs were observed for the 2021–2040 and 2061–2080 scenarios respectively, with the changes found to be statistically significant through application of a two tailed T-test with a confidence level of 5 %. • Economic modelling of green ammonia typically uses historical weather data. • Climate change may have a substantial impact on global weather patterns. • We examine the climate impacts on offshore ammonia production at four UK locations. • The impact of climate change on the LCOA is found to be statistically significant. [ABSTRACT FROM AUTHOR]

The UK chemical industry is the largest consumer of natural gas for process heating and power generation, with an annual consumption of 26.3 TWh. Reduction in natural gas consumption and associated carbon emissions can be achieved through electrification of heat. However, the adoption of electric boilers is lethargic due to economic barriers. Hence, market-based policy interventions are required. This study aims to accelerate the adoption of electric boilers in the UK's chemical industry, aligning with the UK's ambitious 2035 industrial decarbonisation goals while considering economic impacts, by designing market-based policy interventions and comparing two adoption patterns. A novel multi-period Mixed-Integer Market Penetration Optimisation Model is developed and applied to inform decisions about transitioning from natural gas to electric boilers. The model is applied to a case study of all the heating systems (490 boilers) in the UK chemical industry from 1 MW to 60 MW boilers. Results show that effectively implementing a gas tax, electricity subsidy, annual grant and carbon tax can generate sufficient demand-pull to reduce the cost of electric boilers from 30 to 85 % depending on the boiler size. A carbon tax starting at £280 per tCO 2 e and reducing to £170 per tCO 2 e coupled with electricity subsidies is essential for this transition. The policies are designed such that a win-win is achieved between government and industry; specifically, revenue from the carbon tax and gas tax is used to support the grant and electricity subsidy thereby achieving cost neutrality for government. At 100 % uptake of electric boilers in 2033, the total carbon emissions reduce by 89 %, which is above the 2035 UK industry goal of 60 % reduction. The research establishes a robust policy timeline that can drive industrial electrification in the UK's chemical sector. It highlights the need for a multi-faceted approach, incorporating various policy instruments to overcome the barriers of high initial capital costs. • Market-based optimisation model developed to inform energy transition decisions. • A market penetration study for switching from natural gas to electric boilers. • Total carbon emissions reduce by 89 % above 2035 UK industry goal of 60 % • Policy induced demand-pull can reduce electric boiler cost by at least 30 %. • An optimal adoption pattern can further reduce mitigation cost. [ABSTRACT FROM AUTHOR]

The decarbonisation of industry, heating and transportation is a major challenge for many countries' energy transition. Hydrogen is a direct low-carbon fuel alternative to natural gas offering a higher flexibility in the range of possible applications, yet currently most hydrogen is produced using carbon-intensive steam methane reforming due to cost considerations. Therefore, this study explores the economics of a prominent low-carbon method of hydrogen production, comparing the cost of hydrogen generation from offshore wind farms with and without grid electricity imports to conventional hydrogen production methods. A novel techno-economic model for offshore electrolysis production costs is presented, which makes hydrogen production fully dispatchable, leveraging geological salt-cavern storage. This model determines the lifetime costs aportioned across the system components, as well as the Levelised Cost of Hydrogen (LCOH). Using the United Kingdom as a case study, LCOH from offshore wind power is calculated to be €8.68/kg H2 using alkaline electrolysis (AEL), €10.49/kg H2 using proton exchange membrane electrolysis (PEMEL), and €10.88/kg H2 with grid electricity to backup the offshore wind power. A stochastic Monte-Carlo model is used to asses the uncertainty on costs and identify the cost of capital, electrolyser and wind farm capital costs, and cost of electricity as the most important drivers of LCOH across the different scenarios. Reducing the capital cost to comparative levels observed on today's wind farms alone, could see AEL LCOH fall to €5.32/kg H2 , near competitive with conventional generation methods. • Development of a techno-economic model for offshore electrolysis production cost. • Lifetime hydrogen production and Levelized cost of gas (LCOH) are determined. • LCOH is calculated using deterministic and stochastic Monte-Carlo models. • Alkaline electrolysis with offshore wind power cost is the UK's lowest cost option. [ABSTRACT FROM AUTHOR]

Transport-related activities represented 34% of the total carbon emissions in the UK in 2022 and heavy-duty vehicles (HGVs) accounted for one-fifth of the road transport greenhouse gas (GHG) emissions. Currently, battery electric vehicles (BEVs) and hydrogen fuel cell electric vehicles (FCEVs) are considered as suitable replacements for diesel fleets. However, these technologies continue to face techno-economic barriers, creating uncertainty for fleet operators wanting to transition away from diesel-powered internal combustion engine vehicles (ICEVs). This paper assesses the performance and cost competitiveness of BEV and FCEV powertrain solutions in the hard-to-abate HGV sector. The study evaluates the impact of battery degradation and a carbon tax on the cost of owning the vehicles. An integrated total cost of ownership (TCO) model, which includes these factors for the first time, is developed to study a large retailer's HGV fleet operating in the UK. The modelling framework compares the capital expenditures (CAPEX) and operating expenses (OPEX) of alternative technologies against ICEVs. The TCO of BEVs and FCEVs are 11% to 33% and 37% to 78% higher than ICEVs; respectively. Despite these differences, by adopting a longer lifetime for the vehicle it can effectively narrow the cost gap. Alternatively, cost parity with ICEVs could be achieved if BEV battery cost reduces by 56% or if FCEV fuel cell cost reduces by 60%. Besides, the pivot point for hydrogen price is determined at £2.5 per kg. The findings suggest that BEV is closer to market as its TCO value is becoming competitive, whereas FCEV provides a more viable solution than BEV for long-haul applications due to shorter refuelling time and lower load capacity penalties. Furthermore, degradation of performance in lithium-ion batteries is found to have a minor impact on TCO if battery replacement is not required. However, critical component replacement and warranty can influence commercial viability. Given the high costs, we propose financial incentives and vehicle tax reforms to reduce costs of critical components that will encourage the roll-out of zero emission HGVs. • TCO model employs real-world fleet data to compare HGV powertrain technologies. • Maximising vehicle lifetime is key to reduce the TCO gap and get closer to parity. • BEVs have a TCO 11%–33% higher than ICEVs. • FCEVs have a TCO 37%–78% higher than ICEVs. • Degradation in lithium-ion batteries is found to have a minor impact on TCO value. [ABSTRACT FROM AUTHOR]