Policy & Socio-Economics

Because of the pressure to meet carbon neutrality targets carbon reduction has become a challenge for fossil fuel resource-based regions. Even though China has become the most active country in carbon reduction its extensive energy supply and security demand make it difficult to turn away from its dependence on coal-based fossil energy. This paper analyzes the Chinese coal capital—Shanxi Province—to determine whether the green low-carbon energy transition should be focused on coal resource areas. In these locations the selection and effect of transition tools are key to ensuring that China meets its carbon reduction goal. Due to the time window of clean coal utilization the pressure of local governments and the survival demands of local high energy consuming enterprises Shanxi Province chose hydrogen as its important transition tool. A path for developing hydrogen resources has been established through lobbying and corporative influence on local and provincial governments. Based on such policy guidance Shanxi has realized hydrogen applications in large-scale industrial parks regional public transport and the iron and steel industry. This paper distinguishes between the development strategies of gray and green hydrogen. It shows that hydrogen can be an effective development model for resource-based regions as it balances economic stability and energy transition.

This paper investigates the untapped potential of the Permian Basin a multifaceted energy axis in Texas and adjoining states in the emerging era of decarbonization. Aligned with current policy directives on regional hydrogen hubs this study explores the viability of developing a hydrogen energy hub in the Permian Basin thereby producing low-carbon intensity hydrogen from natural gas in the Basin and transporting it to the Greater Houston area. Diverging from existing literature this study provides an integrated techno-economic evaluation of the entire hydrogen value chain in the Permian Basin encompassing production storage and transportation. Furthermore it comparatively analyzes the scenario of interest against an optimized base scenario thereby underlining comparative advantages and disadvantages. The paper concludes that the delivered cost of Permian based low-carbon intensity hydrogen to the Greater Houston area is $1.85/kg benchmarked to the scenario with hydrogen produced close to the Greater Houston area and delivered at $1.42/kg. Our findings reveal that Permian-based low-carbon intensity hydrogen production can achieve cost savings in feedstock ($0.25/kg) and potentially accrue a higher production tax credit due to a shorter gas supply chain to production ($0.33/kg). Nevertheless a significant cost barrier is the expense of long-haul pipeline transport ($0.90/kg) from the Permian Basin to Houston as opposed to local production. Despite the obstacles the study identifies a potential breakeven solution where increasing the production scale to at least 412000 metric ton per year (about 3 steam reforming plants) in the Permian Basin can effectively lower costs in the transport sector. Hence a scaled-up production can mitigate the cost difference and establish the Permian Basin as a competitive player in the hydrogen market. In conclusion a SWOT analysis presents Strengths Weaknesses Opportunities and Threats associated with Permian-based hydrogen production.

Hydrogen is gaining prominence as a sustainable energy source in the UK aligning with the country’s commitment to advancing sustainable development across diverse sectors. However a rigorous examination of the interplay between the hydrogen economy and the Sustainable Development Goals (SDGs) is imperative. This study addresses this imperative by comprehensively assessing the risks associated with hydrogen production storage transportation and utilization. The overarching aim is to establish a robust framework that ensures the secure deployment and operation of hydrogen-based technologies within the UK’s sustainable development trajectory. Considering the unique characteristics of the UK’s energy landscape infrastructure and policy framework this paper presents practical and viable recommendations to facilitate the safe and effective integration of hydrogen energy into the UK’s SDGs. To facilitate sophisticated decision making it proposes using an advanced Decision-Making Trial and Evaluation Laboratory (DEMATEL) tool incorporating regret theory and a 2-tuple spherical linguistic environment. This tool enables a nuanced decision-making process yielding actionable insights. The analysis reveals that Incident Reporting and Learning Robust Regulatory Framework Safety Standards and Codes are pivotal safety factors. At the same time Clean Energy Access Climate Action and Industry Innovation and Infrastructure are identified as the most influential SDGs. This information provides valuable guidance for policymakers industry stakeholders and regulators. It empowers them to make well-informed strategic decisions and prioritize actions that bolster safety and sustainable development as the UK transitions towards a hydrogen-based energy system. Moreover the findings underscore the varying degrees of prominence among different SDGs. Notably SDG 13 (Climate Action) exhibits relatively lower overall distinction at 0.0066 and a Relation value of 0.0512 albeit with a substantial impact. In contrast SDG 7 (Clean Energy Access) and SDG 9 (Industry Innovation and Infrastructure) demonstrate moderate prominence levels (0.0559 and 0.0498 respectively) each with its unique influence emphasizing their critical roles in the UK’s pursuit of a sustainable hydrogen-based energy future.

Globally a green hydrogen economy rush is underway and many companies investors governments and environmentalists consider it as an energy source that could foster the global energy transition. The enormous potential for hydrogen production for domestic use and export places Africa in the spotlight in the green hydrogen economy discourse. This discourse remains unsettled regarding how natural resources such as land and water can be sustainably utilized for such a resource-intensive project and what implications this would have. This review argues that green hydrogen production (GHP) in Africa has consequences where land resources (and their associated natural resources) are concerned. It discusses the current trends in GHP in Africa and the possibilities for reducing any potential pressures it may put on land and other resource use on the continent. The approach of the review is interpretive and hinges on answering three questions concerning the what why and how of GHP and its land consequences in Africa. The review is based on 41 studies identified from Google Scholar and sources identified via snowballed recommendations from experts. The GHP implications identified relate to land and water use mining-related land stress and environmental ecological and land-related socioeconomic consequences. The paper concludes that GHP may not foster the global energy transition as is being opined by many renewable energy enthusiasts but rather could help foster this transition as part of a greener energy mix. It notes that African countries that have the potential for GHP require the institutionalization of or a change in their existing approaches to land-related energy governance systems in order to achieve success.

The worsening climate crisis has increased the urgency of transitioning energy systems from fossil fuels to renewable sources. However many industrialized countries are struggling to meet their growing demand for renewable energy (RE) through domestic production alone and therefore seek to import additional RE using carriers such as hydrogen ammonia or metals. The pressing question for RE importers is therefore how to select trading partners i.e. RE exporting countries. Recent research has identified a plethora of different selection criteria reflecting the complexity of energy systems and international cooperation. However there is little guidance on how to reduce this complexity to more manageable levels as well as a lack of tools for effective partner evaluation. This article aims to fill these gaps. It proposes a new multidimensional framework for evaluating and comparing potential RE trading partners based on four dimensions: economy and technology environment and development regulation and governance and innovation and cooperation. Focusing on Germany as an RE importer an exploratory factor analysis is used to identify a consolidated set of composite selection criteria across these dimensions. The results suggest that Germany’s neighboring developed countries and current net energy exporters such as Canada and Australia are among the most attractive RE trading partners for Germany. A dashboard tool has been developed to provide the framework and composite criteria including adjustable weights to reflect the varying preferences of decision-makers and stakeholders. The framework and the dashboard can provide helpful guidance and transparency for partner selection processes facilitating the creation of RE trade networks that are essential for a successful energy transition.

This current article discusses the technoeconomics (TE) of hydrogen generation transportation compression and storage in the Australian context. The TE analysis is important and a prerequisite for investment decisions. This study selected the Australian context due to its huge potential in green hydrogen but the modelling is applicable to other parts of the world adjusting the price of electricity and other utilities. The hydrogen generation using the most mature alkaline electrolysis (AEL) technique was selected in the current study. The results show that increasing temperature from 50 to 90 ◦C and decreasing pressure from 13 to 5 bar help improve electrolyser performance though pressure has a minor effect. The selected range for performance parameters was based on the fundamental behaviour of water electrolysers supported with literature. The levelised cost of hydrogen (LCH2 ) was calculated for generation compression transportation and storage. However the majority of the LCH2 was for generation which was calculated based on CAPEX OPEX capital recovery factor hydrogen production rate and capacity factor. The LCH2 in 2023 was calculated to be 9.6 USD/kgH2 using a base-case solar electricity price of 65–38 USD/MWh. This LCH2 is expected to decrease to 6.5 and 3.4 USD/kgH2 by 2030 and 2040 respectively. The current LCH2 using wind energy was calculated to be 1.9 USD/kgH2 lower than that of solar-based electricity. The LCH2 using standalone wind electricity was calculated to be USD 5.3 and USD 2.9 in 2030 and 2040 respectively. The LCH2 predicted using a solar and wind mix (SWM) was estimated to be USD 3.2 compared to USD 9.6 and USD 7.7 using standalone solar and wind. The LCH2 under the best case was predicted to be USD 3.9 and USD 2.1 compared to USD 6.5 and USD 3.4 under base-case solar PV in 2030 and 2040 respectively. The best case SWM offers 33% lower LCH2 in 2023 which leads to 37% 39% and 42% lower LCH2 in 2030 2040 and 2050 respectively. The current results are overpredicted especially compared with CSIRO Australia due to the higher assumption of the renewable electricity price. Currently over two-thirds of the cost for the LCH2 is due to the price of electricity (i.e. wind and solar). Modelling suggests an overall reduction in the capital cost of AEL plants by about 50% in the 2030s. Due to the lower capacity factor (effective energy generation over maximum output) of renewable energy especially for solar plants a combined wind- and solar-based electrolysis plant was recommended which can increase the capacity factor by at least 33%. Results also suggest that besides generation at least an additional 1.5 USD/kgH2 for compression transportation and storage is required.

Countries with high energy demand but limited renewable energy potential are planning to meet part of their future energy needs by importing green hydrogen. For potential exporting countries in addition to sufficient renewable resources industrial preconditions are also relevant for the successful implementation of green hydrogen production value chains. A list of 36 “Green H2 Products” needed for stand-alone hydrogen production plants was defined and their economic complexity was analyzed using international trade data from 1995 to 2019. These products were found to be comparatively complex to produce and represent an opportunity for countries to enter new areas of the product space through green diversification. Large differences were revealed between countries in terms of industrial preconditions and their evolution over time. A detailed analysis of nine MENA countries showed that Turkey and Tunisia already possess industrial know-how in various green hydrogen technology components and perform only slightly worse than potential European competitors while Algeria Libya and Saudi Arabia score the lowest in terms of calculated hydrogen-related green complexity. These findings are supported by statistical tests showing that countries with a higher share of natural resources rents in their gross domestic product score significantly lower on economic and green complexity. The results thus provide new perspectives for assessing the capabilities of potential hydrogen-producing countries which may prove useful for policymakers and investors. Simultaneously this paper contributes to the theory of economic complexity by applying its methods to a new subset of products and using a dataset with long-term coverage.

There is a growing interest in green hydrogen with researchers institutions and countries focusing on its development efficiency improvement and cost reduction. This paper explores the concept of green hydrogen and its production process using renewable energy sources in several leading countries including Australia the European Union India Canada China Russia the United States South Korea South Africa Japan and other nations in North Africa. These regions possess significant potential for “green” hydrogen production supporting the transition from fossil fuels to clean energy and promoting environmental sustainability through the electrolysis process a common method of production. The paper also examines the benefits of green hydrogen as a future alternative to fossil fuels highlighting its superior environmental properties with zero net greenhouse gas emissions. Moreover it explores the potential advantages of green hydrogen utilization across various industrial commercial and transportation sectors. The research suggests that green hydrogen can be the fuel of the future when applied correctly in suitable applications with improvements in production and storage techniques as well as enhanced efficiency across multiple domains. Optimization strategies can be employed to maximize efficiency minimize costs and reduce environmental impact in the design and operation of green hydrogen production systems. International cooperation and collaborative efforts are crucial for the development of this technology and the realization of its full benefits.

The disruption associated with heat decarbonisation has been identified as a key opportunity for hydrogen technologies in temperate countries and regions where established distribution infrastructure and familiarity with natural gas boilers predominate. A key element of such claims is the empirically untested belief that citizens will prefer to minimise disruption and perceive hydrogen to be less disruptive than the network upgrades and retrofit measures needed to support electric and other low carbon heating technologies. This article reports on exploratory deliberative research with residents of Cardiff Wales which examined public perceptions of heating disruptions. Our findings suggest that concerns over public responses to disruption may be overstated particularly as they relate to construction and road excavation for network upgrade. Disruptions arising from permanent changes to building fabric may be more problematic for heat pump retrofit however these may be greatly overshadowed by anxieties over the cost implications of moving to hydrogen fuel. Furthermore the biographical patterning of citizen preferences raises significant questions for hydrogen roll-out strategies relying on regionalised network conversion. We conclude by arguing that far from a non-disruptive alternative to electrification hydrogen risks being seen as posing substantial disruptions to precarious household finances and lifestyles.

National hydrogen strategies are emerging as a critical pillar of climate change policy. For homes connected to the gas grid hydrogen may offer an alternative decarbonisation pathway to electrification. Hydrogen production pathways in countries such as the UK will involve both the gas network and the electricity grid with related policy choices and investment decisions impacting the potential configuration of consumer acceptance for hydrogen homes. Despite the risk of public resistance be it on environmental economic or social grounds few studies have explored the emerging contours of domestic hydrogen acceptance. To date there is scarce evidence on public perceptions of national hydrogen policy and the extent to which attitudes may be rooted in prior knowledge and awareness or open to change following information provision and engagement. In response this study evaluates consumer preferences for a low-carbon energy future wherein parts of the UK housing stock may adopt low-carbon hydrogen boilers and hobs. Drawing on data from online focus groups we examine consumer perceptions of the government's twin-track approach which envisions important roles for both ‘blue’ and ‘green’ hydrogen to meet net zero ambitions. Through a mixed-methods multigroup analysis the underlying motivation is to explore whether the twin-track approach appears compatible with hydrogen acceptance. Moving forward hydrogen policy should ensure greater transparency concerning the benefits costs and risks of the transition with clearer communication about the justification for supporting respective hydrogen production pathways.