Korean objectives to reach economy-wide net zero by 2050 will require significant changes in the power sector

In October 2020, Korea announced its pledge to achieve net zero emissions by 2050. With 586 million tonnes of CO₂-equivalent in 2019, Korea accounts for 2% of global annual emissions. Its power and industrial sectors are major contributors to annual national emissions at 37% and 36% respectively.

Net zero emissions by 2050 would require very strong support measures and incentives that introduce renewable and other low‑carbon energy sources and interventions to rein in emissions of greenhouse gases in all sectors of the Korean economy. The power sector is the largest source of emissions in many countries, including Korea, and should be the first sector to decarbonise as shown in the Net Zero by 2050 roadmap by the International Energy Agency (IEA). 

The purpose of this report is to examine how electricity market design in Korea must change to facilitate national decarbonisation without undermining electricity security. The IEA and the Korean Energy Economics Institute (KEEI) have developed the Korea Regional Power System Model, which includes six power system regions. This model simulates what would happen to the Korean power sector after implementation of the 9th Basic Plan for Long-Term Electricity (BPLE) in 2034, and under the Announced Pledges Scenario (APS) in the World Energy Outlook (WEO) 2021 by the IEA in 2035. The latter is aligned with Korea’s pledge to achieve net zero emissions by 2050.  

Korea’s current electricity market design does not help achieve the objectives of decarbonisation and security

Korea aims to reduce emissions from the power sector in a cost-effective way, without compromising electricity security. In liberalised power markets, like Korea’s, the wholesale market should be the key enabler to reach policy objectives and to ensure the efficient dispatch of all resources. However, Korea’s current cost-based system does not account for factors such as emissions and system security. In recent years, this has resulted in higher profits for technologies with lower fuel costs and higher emissions, like coal-fired generation.

Estimate of profitability for new plant by type in Korea, 2017-2020


Maintaining this pricing regime would not enhance the power system’s ability to secure sufficient low-carbon energy and dispatchable capacity by 2035. Considering the recent introduction of policies to phase out coal-fired generation and limit nuclear electricity, it will be important to secure enough investment in alternative low-carbon dispatchable resources such as hydro, pumped storage hydropower (PSH) and battery storage. 

Valuing both scarcity and avoided emissions is important to achieve long-term objectives

Two enhancements to price formation in the electricity market can significantly contribute to Korea’s decarbonisation objectives. First, incorporate the cost of carbon into wholesale prices, either by allowing the emissions trading scheme to impact wholesale prices, or through taxation. Even low levels of CO2 prices (USD 60-70/tonne), far below those considered in the WEO by the IEA for developed economies with net zero pledges, would improve the profitability of low-carbon assets such as wind, solar, hydropower and PSH. This would also give the right signals to demand-side resources and flexible assets regarding when to consume energy and discharge to minimise emissions.

Second, allow the shortages of operating reserves to be reflected in wholesale pricing during hours of scarcity, which increases the prospects for flexible technologies such as PSH, batteries, hydro and gas plants.

Including both price enhancements would correct the existing biases in the wholesale market design and align the incentives given to market participants with Korea’s decarbonisation objectives. This would foster a gradual substitution process where low‑carbon energy replaces highly polluting sources and provides incentives to invest in assets that can provide the services needed to keep security of supply.

Estimate of profitability by unit type in Korea in the Announced Pledges Scenario, 2035


Decarbonising Korea’s power system will increase its flexibility requirements and require new technologies

Korea’s annual variable renewable energy (VRE) share of electricity supply was 4% in 2020, and the country is in Phase I in the Phases of VRE integration framework developed by the IEA. Following the 9th BPLE would bring their VRE share to around 21% in 2034 and place the country in Phase III. This would require coping with maximum hourly VRE penetrations of 60% relative to load and coping with three-hour ramp-down requirements equivalent to 51% of the daily peak already by 2030.

Annual VRE share in selected countries for 2019 and Korea in 2020, and the Basic Plan for Long-Term Electricity 2034 and Announced Pledges Scenarios, 2035


Korea’s annual variable renewable energy (VRE) share of electricity supply was 4% in 2020, and the country is in Phase I in the Phases of VRE integration framework developed by the IEA. Following the 9th BPLE would bring their VRE share to around 21% in 2034 and place the country in Phase III. This would require coping with maximum hourly VRE penetrations of 60% relative to load and coping with three-hour ramp-down requirements equivalent to 51% of the daily peak already by 2030.

Increased time and locational granularity will allow for better VRE integration and reduce grid expansion costs

For Korea, the current plan to reduce dispatch intervals from hourly blocks to 15 and 5 minutes provides a first good step to facilitate power system decarbonisation. Countries like Australia, which have introduced 5 minute dispatch intervals to cope with a high penetration of solar PV may offer useful experiences for Korea. This, along with intraday and real-time markets, would greatly complement the existing day-ahead market and provide participants with incentives to balance the system and properly forecast their output and demand, ensuring smooth operation of the system.

Korea’s current system has a single bidding zone power market with uniform pricing, which in practice does not recognise any physical constraints in the transmission and distribution networks. The market, therefore, lacks the proper signals for timely investment in transmission and optimal choice of locations for generation assets. This problem will grow larger with higher shares of VRE.

Introducing zonal pricing as a first step would help the Korean market identify and solve critical transmission bottlenecks. Results from the APS in 2035 show that the short-run marginal cost in each region will begin to diverge during many periods of the year. As a dynamic measure, zonal or nodal pricing can help capture these changes as they happen and provide better information for generation and transmission planning.  

Technology neutral capacity payments based on performance are a tool to meet critical power system needs

Even with enhancements in pricing and market design, achieving Korea’s policy objectives of electricity security and decarbonisation may still require additional incentives for investments in certain technologies. Regulatory or revenue uncertainty and the lack of visibility over decarbonisation paths can be significant barriers to securing investment at the scale or pace required.

Capacity payments can thus help to complement market revenues and ensure enough investment. They should be technology neutral and remunerate new technologies, such as battery storage, VRE and demand response, which have typically been excluded from such schemes.

Moreover, the remuneration to these assets should reflect their contribution to the system’s most critical conditions, such as net load peaks or reserve shortfall hours, which may evolve over time. It is also important to remember that capacity payments are not meant to pay twice for the investment, so they need to be designed in such a way that they reflect only the “missing money” required by generators to break even, subtracting net revenues received in the wholesale electricity market. 

Market-based renewable support schemes can accelerate VRE deployment while improving the efficiency of Korea’s wholesale market

Even with wholesale market reforms, market revenues alone may not be enough to bring about sufficient levels of low‑carbon energy, which would still require dedicated support mechanisms to accelerate investment. Currently, Korea’s main instrument for this is a Renewable Portfolio System with incremental requirements for generators, and varying support levels depending on the maturity of individual technologies. The effectiveness of Korea’s support mechanisms could be improved using mechanisms that link the level of support directly to potential revenues from the wholesale market.

Feed-in premiums and competitive auctions that provide additional revenues to generators on top of wholesale market revenues are an option to minimise costs of decarbonisation. These mechanisms can be designed to reward technologies based on the time and locational value of their generation to the system, encouraging system-friendly deployment. Moreover, being benchmarked around wholesale market revenues, these approaches are compatible with the market enhancements listed above.

Since Korean regions have different levels of VRE resource availability and demand, each region will have a different profitability/cost profile. The introduction of feed-in premiums with long-term auctions could help locate new VRE capacity where it adds the most value to the Korean power system. The United Kingdom’s Contract for Differences scheme, the Mexican Long-Term Auction and the German Feed-In Premium Scheme are all support mechanisms that provide more revenues to resources generating energy at times and locations where it is most valuable to the system, providing incentives to properly choose location and technologies.

Certificate mechanisms are compatible with carbon pricing and scarcity revenues, since these price enhancements would reduce the cost of certificates for technologies producing in hours of scarcity and where the marginal source of energy is carbon‑intensive. 

Effective deployment of distributed energy resources in Korea will require accelerating digitalisation

At present, large industrial consumers constitute the largest share of participants in the country’s demand response programmes. However, recent advances in digitalisation technologies for the power sector are already driving the deployment of distributed assets, such as electric vehicles (EVs), battery storage, and cogeneration for active participation in balancing markets. This, however, will require a greater deployment of advanced metering and control technology and, potentially, the entry of new service providers. 

Improving market access is necessary to ensure the participation of distributed energy resources in Korea’s electricity markets

As the share of VRE generation and distributed assets increase in the Korean power system, it may be helpful to review how the costs of keeping the system in balance are managed.

Utilising the full array of distributed resources potentially available in the Korean Power system – including EVs, behind-the-meter batteries, solar panels and diesel emergency backup generators – is likely going to require major changes to the rules for market access. Other system operators in the world delegate the task of handling large numbers of small demand-side assets to retailers and other market participants. Korea needs to create its own schemes for these assets to be represented in the market. 

The increase in renewables will drive an increase in balancing requirements, and in a system where balancing costs are passed directly to consumers, system operators may not see a need to innovate or look for cheaper providers. In this case, introducing incentive‑based regulation for network costs or allowing the entry of new participants in the retail market can be a driver for innovation in the management of balancing requirements.

As the share of VRE increases, retail pricing structures in Korea will need to adapt

In the 2035 Korea APS scenario, optimising the charging pattern of 30% of EVs could lead to significant savings in average energy costs (19%) and peak capacity costs (30%) for the EV fleet. Emissions from EV charging would be reduced by 20%. However, the current retail tariff structure would not encourage such optimisation of EV charging patterns, as Korea’s current schedule for time-of-day tariffs sets the peak load period during the middle of the day in summer. In the future, this would end up discouraging the use of electricity from solar PV for charging EVs, thus increasing costs and emissions.

Moreover, the participation of behind-the-meter battery energy storage systems for flexibility and system services could be encouraged by providing new revenue opportunities, beyond the existing potential for savings through avoided network charges. In other jurisdictions, the shift from so-called critical pricing of network costs to active participation in ancillary services and balancing markets has contributed to reducing system costs and improving the dispatch of battery storage as the system decarbonises.