(371t) Structural Evolution of the Electricity System in a below 2°C World

Daggash, H. A., Imperial College London
Mac Dowell, N., Imperial College London
The 2015 Paris Agreement brought climate change into global political discourse. Through the accord, most nations committed to limiting global temperature rise to 2°C, and to make efforts to further restrict it to 1.5°C. The IPCC Global Warming of 1.5°C report highlighted that the deployment of gigatonne-scale carbon dioxide removal (CDR) is critical to meeting this target. CDR is the direct or indirect removal of carbon dioxide (CO2) from the atmosphere. Several techniques have been demonstrated as technically-feasible means of delivering CDR: afforestation/reforestation (AR), bioenergy with carbon capture and storage (BECCS), and direct air carbon capture and storage (DACCS).

Integrated Assessment Models (IAMs) have estimated that, in addition to AR, 430-740 GtCO2 of cumulative CDR must be achieved by 2100. 20-70 GtCO2 is expected to be provided by the European Union (EU). How much CDR is delivered by individual countries—the level at which climate policy is implemented—is not known because the EU is not further geographically dis-aggregated in the models. In IAMs, CDR is provided by AR and BECCS, with the latter often deployed in the power sector alone. Increasing evidence of the significant challenges for BECCS to deliver large-scale CDR—owing to the limited availability of sustainable biomass and the detrimental effects of large-scale biomass production on the delivery of ecosystem services—has led to an increasing focus on DACCS. The CDR potential of DACCS, however, has only been assessed in the context of isolation. Furthermore, the implications of delivering CDR at the scale suggested by IAMs, via BECCS or DACCS, on country-level energy system transitions has not been investigated.

Using the UK as a case study, this study seeks to address the above research gaps by: 1) quantifying country-level CDR targets for the EU countries according to established burden-sharing principles in climate policy, and 2) assessing the implications of gigatonne-scale CDR on long-term electricity system transitions.

For illustrative purposes, we assume that CDR burdens are allocated to EU countries according to their relative responsibility for climate change, i.e. in proportion to their historic emissions. The UK is responsible for 14% of the EU’s historic emissions, therefore would be expected to deliver 2.8-9.8 GtCO2 of cumulative CDR by 2100. We apply the Electricity Systems Optimization with capacity eXpansion and Endogenous technology Learning (ESO-XEL) model to determine the system transition needed to meet the UK’s CDR burden. ESO-XEL determines the least-cost evolution of power supply capacity that will maintain system reliability and operability throughout the planning horizon (2015 to 2100), and will meet CDR targets.

We find that until 2050, decarbonisation objectives are satisfied by displacing fossil fuel-powered generation with intermittent renewable energy sources (IRES). The increased variability of energy supply necessitates the expansion of interconnection and energy storage capacity; 30 GW of import and storage capacity are added by 2050. 38-41 GW of gas-fired power plants, both unabated and abated (with CCS) remain in the system to provide crucial ancillary services. After the existing 9.6 GW of nuclear power reaches the end of its lifetime, 4-18 GW of new build nuclear power are added. These highlight the importance of dispatchable low-carbon power as IRES penetration rises in a carbon-constrained electricity system.

After 2050, the deployment of BECCS and DACCS becomes necessary to deliver the required CDR. 16-40 GW of BECCS and 3-6 GW of DACCS are deployed by 2100 to meet the lower- and upper-bound CDR burdens, respectively. Together they provide 159-358 MtCO2/yr of CDR by the end of the century. Simultaneously, IRES built in the 2020s begins to reach the end of their operational lifetimes. Instead of being replaced by new build IRES, it proves cheaper to replace old capacity with thermal generation (from gas and nuclear) to complement BECCS. This is a result of several factors: retirement of old fossil and IRES plants, combined with rising demand means there is a significant capacity shortfall to be replaced; energy storage and import capacity are maximally deployed so further grid flexibility is unavailable; technology learning has resulted in cheaper CCS plants which provide firm low-carbon power. The electricity system therefore initially transitions to one dominated by IRES, then in the second-half of the century, it returns to a system dominated by thermal power plants (mostly from BECCS and CCGT-CCS plants).

Favorable policies and incentives have resulted in cheaper IRES, to the extent that small-scale or isolated power systems are commercially-viable. Consequently, the decentralisation energy services is often cited as a feature of the low-carbon energy transition. However, this study has shown that to deliver CDR at the scale consistent with the Paris Agreement, a system dominated by thermal generation is necessary. Such a system is inherently centralized and requires extensive power transmission and distribution networks. Pursuing decentralisation in the near-term may therefore result in the disintegration of infrastructure that appears critical in the long-term, and therefore hinder the ability to deliver the Paris Agreement.

It has been recognized that emitting CO2 imposes a cost on society, i.e. the social cost of carbon. It follows therefore that CO2 removal is a public good, and therefore should be appropriately remunerated. Current carbon pricing mechanisms and emissions trading schemes however do not remunerate the service of CDR. Additionally, the prices and traded volumes of carbon in voluntary carbon offset markets are too low to incentivize investment in CDR technologies. We introduce the concept of a ‘negative emissions credit (NEC)’ as a payment for the net removal of a tonne of CO2 from the atmosphere. A cash flow analysis was then carried out to determine the credit required by BECCS and two archetypes of DACCS (DACCS-CW and DACCS-CE) to achieve internal rates of return that allow for commercial viability. For a first-of-a-kind (FOAK) BECCS plant, a NEC of £52/tCO2 is required in addition to revenue for electricity sales to meet an IRR of 4% (typical for regulated assets). For a similar return, FOAK DACCS plants require £176-342/tCO2. Therefore, although the value of CDR to deep decarbonisation has been shown, the technologies that deliver the service are currently not commercially-viable. Policy must therefore adequately incentivize them to attract investment and encourage innovation to avoid lock-in to a power system that is unable to meet decarbonisation objectives.