(59c) National Priorities in the Net-Zero Transition of Electricity Systems: Policy and Technology Dimensions

The 20^th century electricity system’s challenges include the rapidly increasing demand and fossil fuel price volatility in the last quarter of the century. Accordingly, technology improvements in that period were focused on reducing capital cost and increasing efficiency to not only lower the cost but also to preserve fuel resources. In the 21^st century, however, challenges also include the effort to reduce greenhouse gas emissions to mitigate climate change. Although it has been recognized that various contributions/roles of existing technologies are critical to delivering the net-zero target, the first 2 decades are characterized by different technologies competing to become a technology capable to play all roles in the system with the lowest cost. Notwithstanding this, owing to the unique characteristics of different systems, there is no one-size-fits-all technology to cost-effectively deliver the target.

In addition to the technological approach, policy design to drive the system to decarbonize is also vital. However, the lack of recognition of the unique role each technology may offer to the system may also inspire our current approach by simply focusing on the carbon tax. Whilst this approach can effectively reduce system carbon intensity, the absence of some roles that cannot be incentivized simply by increasing carbon tax may hinder the transition towards net-zero. Accordingly, the objective of this research is to identify priorities to robustly drive the decarbonization of electricity systems in different national contexts.

In the present study, we employed Electricity System Optimization (ESO) framework to understand how the electricity system might transition from 2020 to 2050. ESO is an MILP unit commitment model for electricity systems capacity expansion planning to minimize the total system cost considering system-wide and technology-wise constraints. To capture the impact of future uncertainty, numerous combinations of technology cost, thermal efficiency, and fuel price are implemented in ESO. Moreover, we also implemented different combinations of the carbon tax and CO₂ removal (CDR) credit to drive the system to decarbonize. Similarly, to investigate the impact of different characteristics a system may have, we include the UK, Poland, and ERCOT and PacifiCorp East (PACE) systems in the USA as the systems’ archetypes.

Our results show that the impact of a carbon tax on the total system cost is driven by region-specific factors. For the UK, the impact tends to be marginal as the country has good sources of renewables, moderate price of natural gas, and coal ban. For regions with access to cheap coal and gas, such as ERCOT and PACE, the transition from BAU to low carbon system, which can be delivered by imposing a low carbon tax (£133/t_CO2), can be slightly costly. This is because the regions must switch from cheap coal (4.8-5.9 £/MWh) to a slightly more expensive gas (7.4-19.8 £/MWh). As the result, the total system cost is increased to around 130% (£ 80 billion) and 150% (£ 20 billion) of ERCOT and PACE BAU cost, respectively.

In contrast to the other systems, Poland possesses cheap and domestically sourced coal, but the price of imported natural gas is three times more expensive. Moreover, the load profile is less variable, and therefore the least-cost system has been historically achieved by operating coal for baseload generation. Furthermore, the country also anticipates banning further deployment onshore wind. Accordingly, the system’s decarbonization requires £ 50 billion (30% of BAU) of the additional cost compared to that of BAU.

Whilst the results show that carbon tax alone can consistently significantly reduces 2050’s carbon intensity from 100-800 kg/MWh to 5-20 kg/MWh in all cases, we observe that the incremental reduction of carbon intensity can be achieved drops with the declining system carbon intensity due to the increasing value of low carbon dispatchable technologies, such as CCS-equipped plants. Accordingly, although carbon tax alone can effectively decarbonize the system to around 50 kg/MWh, it is exceptionally unlikely to deliver the net-zero target. The reason is that achieving this target consistently requires negative emissions technologies, such as BECCS, to offset residual emissions which cannot simply be incentivized by increasing the carbon tax. Accordingly, a combination of both the carbon tax and CO₂ removal (CDR) credit is consistently required; in our cases, central carbon tax (£230/t_CO2) and central CDR credit (£125/t_CO2) prove to be the optimal combination that can deliver the net-zero target with the highest probability and the lowest cost of transitions.

The results in the central carbon tax and central CDR credit combination reveal that each technology is expected to offer a unique role in the system. Thus, the focus of technology improvements for each technology is unique and country-specific. For instance, a combination of high fuel price and peaky load pattern in the UK requires thermal plants to provide flexible capacity in the future and drive the system to be more diverse. Hence, focusing on thermal plants cost reduction only reduces the range of total system cost by 2% of the initial cost range. Similarly, as the role of thermal plants is mainly to provide flexible capacity, the value of efficiency improvement is marginal. In contrast, Texas’ access to cheap natural gas allows the system to maintain significant domination of thermal plants capacity in the system. Accordingly, cost reduction of CCS in the state shows more value than that in the UK, i.e., total system cost reduction can be achieved is 5% of the initial range. Moreover, because the system is also benefited by a prospective iRES potential, iRES cost reduction should remain the focus of technology improvement as the effort can reduce the total system cost by 10% of the initial cost.

In contrast to the UK and ERCOT, PACE demand profile tends to be flat as the demand is mainly dominated by industrial sectors. Hence, the deployment of low carbon technologies which can continuously operate is critical. Accordingly, the role of CCS in the system is expected to be significant, and therefore, cost reduction of the technology yields a 5% total system cost reduction. However, although the share of CCGT-CCS generation in ERCOT and PACE is substantial, the value of thermal efficiency improvement is negligible owing to the low cost of natural gas.

Poland has the same load profile as PACE but the country does not have access to cheap natural gas and further development of onshore wind is banned. Hence, the country is expected to heavily rely on thermal plants and much less of that on iRES. This leads to a substantial benefit of CCS cost reduction whilst the value of iRES cost reduction is negligible. Interestingly, the value of efficiency improvement in Poland is the highest among the other cases owing to expensive natural gas prices and higher residual emissions of coal compared to that of gas. In Poland's case, our results show that increasing thermal efficiency can reduce the total system cost by 11% of the initial cost.

Finally, our study concludes that priorities in the net-zero transition of the electricity system are case-specific. While carbon tax alone can decarbonize the system, the combination of the central carbon tax and CDR credit is necessary and adequate to deliver the net-zero target cost-effectively. Moreover, each system needs to focus on key technology improvements that are more likely to substantially reduce the total system cost depending on the system’s characteristics.

References:

1. Heuberger, C.F. et al. Impact of myopic decision-making and disruptive events in power systems planning. Nature Energy 3 (2018) 634–640

2. Heuberger, C.F. et al. Power capacity expansion planning considering endogenous technology cost learning. Applied Energy 204 (2017) 831–845