This study sought to generate, evaluate, and recommend possible national policies for the government of the Democratic Republic of the Congo (DRC) to implement to most effectively boost growth and investment in renewable energy technologies (RETs) through 2065 using Open Source Energy Modelling System (OSeMOSYS). The novelty of this study stems in-part from the scarcity of RET modelling completed for specific West African countries rather than for broader regions. Market-based instruments were identified as the policy type most practical for DRC. From modelling the resulting energy systems for policy pathways involving a 16% RET subsidy, a 70% fossil fuel tax, and both in combination relative to no-policy baseline scenarios, the scenarios including the tax had the lowest net costs (USD304–306 B) and the highest proportion of RETs (above 90%). Additionally, despite the current reliance on hydropower to fulfil 98% of its energy needs, hydropower played a very minor role in all of a modelled scenarios (no future investment beyond residual capacity). Finally, a post-modelling market potential assessment was performed on the technology that dominated off-grid supply across policy pathways: a 0.3 kW small solar home system (SHS). Based on learning rates for solar photovoltaics (PV), demand for a small SHS in DRC (>160 million units in total) was found to be sufficient to substantially reduce the unit cost as deployment scales. Ultimately, this study yielded four recommendations for the DRC government: (1) Pursue financial incentives to catalyse DRC’s renewable energy supply. (2) Tax fossil fuel energy production. (3) Re-evaluate focus on hydropower. (4) Promote DRC as a healthy market for solar home systems.

Lack of effective policies hinder the uptake of Utility-scale solar PV, even though they are projected to play a pivotal role in achieving Indonesia's 2050 net-zero energy target. This study seeks to identify a cost-effective pathway to increase the capacity of utility-scale solar PV in Indonesia through supportive policies that ensure equitable cost distribution between the government and industry. A novel Market Penetration Optimization Model is developed and applied in simulation mode to assess existing policies, and optimization mode to determine new policy recommendations and compare three policy induced diffusion pathways. Results show that current price-based policies are insufficient to stimulate growth in the solar PV market, only covering ~13% of the investment cost required by the industry. Thus, necessitating a reactivation of Feed-in-Tariffs. The optimal tariffs rates required range from 0.39 to 1.47 cents/kWh for the most economic pathway during the initial 10-year post-construction period. The Innovation Diffusion Theory-based pathway necessitates the lowest initial investment cost while yielding the highest revenue from electricity sales, demonstrating its superior cost-effectiveness compared to both the supply-based and linear pathways. This study enriches the literature by exploring the financial implications of policy induced diffusion pathways.

This paper examines how market-based policy interventions can enhance the economic viability of e-fuels for aviation and shipping, two hard-to-decarbonise sectors. A novel optimisation-based market penetration assessment model is developed and applied to three case studies, one based on a global shipping scenario with e-Ammonia and e-Methanol, and two based on national scenarios: UK aviation with advanced SAF and e-SAF. The optimisation model quantifies the effectiveness of Contracts-for-Difference (CfD), Carbon Contracts-for-Difference (CCfD), and optimised policy mixes in reducing e-fuel costs. Findings reveal that a combined policy approach can close the price gap between e-fuels and conventional fossil fuels. For instance, a carbon tax of $33.6–$162.8 per tonne CO ₂ , paired with subsidies of $32.3–$79.15 per MWh, could lower e-Ammonia costs by 24%, and e-Methanol by 29% in shipping. In the UK aviation sector, CfD schemes designed to stabilise advanced SAF prices have the potential to reduce government support costs by up to 30%, making advanced SAF more competitive. Moreover, implementing CCfDs linked to emissions reductions for e-SAF could achieve cost parity by 2040 when combined with carbon pricing projected at $150 per tonne CO ₂ . This research supports a more informed and data-driven policy design, ensuring that economic barriers to synthetic fuel adoption are addressed through a balanced, market-driven approach. Graphical Abstract

In spite of the benefits from thermal energy storage (TES) integration in dwellings, the penetration rate in Europe is 5%. Effective fiscal policies are necessary to accelerate deployment. However, there is currently no direct support for TES in buildings compared to support for electricity storage. This could be due to lack of evidence to support incentivisation. In this study, a novel systematic framework is developed to provide a case in support of TES incentivisation. The model determines the costs, CO₂ emissions, dispatch strategy and sizes of technologies, and TES for a domestic user under policy neutral and policy intensive scenarios. The model is applied to different building types in the UK. The model is applied to a case study for a detached dwelling in the UK (floor area of 122 m²), where heat demand is satisfied by a boiler and electricity imported from the grid. Results show that under a policy neutral scenario, integrating a micro-Combined Heat and Power (CHP) reduces the primary energy demand by 11%, CO2 emissions by 21%, but with a 16 year payback. Additional benefits from TES integration can pay for the investment within the first 9 years, reducing to 3.5–6 years when the CO2 levy is accounted for. Under a policy intensive scenario (for example considering the Feed in Tariff (FIT)), primary energy demand and CO2 emissions reduce by 17 and 33% respectively with a 5 year payback. In this case, the additional benefits for TES integration can pay for the investment in TES within the first 2 years. The framework developed is a useful tool is determining the role TES in decarbonising domestic energy systems.

CCUS is broadly heralded as a substantive opportunity to deeply offset emissions from the oil refining industry. However, high cost of capture remains a major barrier to adoption. Although developments of new technologies and infrastructure are still ongoing and poised to appreciably improve the economics for CCUS in the future, widescale deployment is still critically dependent on policy interventions. This work develops a novel optimisation-based multi-market potential assessment model to quantify the impact of combined policies in increasing market uptake and reducing mitigation cost of new CCUS technologies by 2030 among refineries considered to be operating under CCUS clusters with a shared transport and storage network business model. The methodology is applied to 512 refineries in 86 countries grouped under 8 different regions worldwide. Results show that sufficient demand among refineries can be generated from policies combined globally to trigger further cost reductions to a target cost of capture of ≤ US$40 /tCO₂. Overall, 33% maximum cost savings is possible at a worldwide cost of US$ 46.3 billion shared between governments and the industry largely in the form of unified carbon taxes and grant support. Moreover, refineries in Asia, North America and Europe are more likely to lead CCUS cost savings as high as 22% due to their huge market potential and policy mix support from capital funding, tax credits for EOR and storage, and emissions allowances, as opposed to potential in Africa and Oceania. Ultimately, there is need for coordinated global efforts for policy measures for CCUS uptake.

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 and accounts for 2% of UK’s total emissions. Industrial electrification enables moving away from fossil fuels to electricity for generation of lower carbon process heating. 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. 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. 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 tCO₂e and reducing to £170 per tCO₂e 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. 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.