South Korea’s electricity market could be pushed toward a lower-carbon future by combining stricter emissions trading rules with higher carbon prices and targeted support for power companies, according to a new simulation study from researchers at Pusan National University. The analysis examines how proposed changes to the Korean Emissions Trading Scheme, or K-ETS, could reshape the economics of coal- and gas-fired power generation during the scheme’s fourth implementation phase from 2026 to 2030. Its central finding is clear: no single reform is likely to deliver deep decarbonization on its own. Instead, Korea may need an integrated policy package that changes how permits are allocated, increases the share of allowances sold through auctions, raises the cost of carbon emissions, and helps companies manage the financial shock of the transition.
The K-ETS was launched in 2015 to limit greenhouse gas emissions by requiring covered companies to surrender emission allowances for the pollution they produce. Companies can receive some allowances for free, purchase others at auction, or trade permits in the market. In theory, the system makes emitting more expensive and encourages firms to switch to cleaner technologies. In practice, however, the electricity sector operates under conditions that differ substantially from those of Europe, where the European Union Emissions Trading System has served as a major policy model. Korea’s power market is highly centralized, and electricity generators have limited ability to pass rising production costs directly on to consumers. That distinction could determine whether reforms reduce emissions smoothly or create financial stress for companies and instability across the power system.
A research team led by Assistant Professor Dowon Kim developed a computational model to investigate these effects. The model represents the operation of Korea’s electricity market and simulates how power generators respond when the rules governing emissions allowances and carbon costs change. The researchers tested multiple combinations of three policy variables. The first was the benchmark used to calculate free allowances. Under a fuel-specific benchmark, coal and natural gas plants are evaluated according to different standards. Under a uniform benchmark, all plants face the same allocation standard, regardless of fuel type. The second variable was the share of allowances distributed through auctions rather than free allocation. The third was the carbon price, which represents the cost associated with emitting greenhouse gases during electricity generation.
The results indicate that replacing fuel-specific benchmarks with a uniform benchmark would reduce the number of free allowances available to fossil-fuel generators and weaken their profits. Coal-based companies would experience the sharpest decline because coal plants generally release more carbon dioxide for each unit of electricity produced. Natural gas generators would also be affected, but their lower emissions intensity would make the financial impact less severe. In an emissions trading system, this difference is technically important: a plant with higher emissions must obtain or purchase more allowances to cover its output, so any reduction in free permits exposes it more directly to carbon-market costs. The reform would therefore narrow the economic advantage historically enjoyed by more carbon-intensive generation.
Increasing the auctioning ratio would intensify that pressure, but the model suggests that its overall effects would be relatively modest under current market conditions. When more allowances are auctioned, generators must buy a larger share of the permits required to operate. That adds an emissions-related expense to the marginal cost of electricity generation—the cost of producing one additional unit of power. Coal plants would see a larger increase in this cost than gas plants because their carbon dioxide emissions per megawatt-hour are higher. In principle, this should make gas more competitive in the wholesale dispatch order, gently encouraging a shift away from coal. Yet the simulations indicate that the proposed change in auctioning alone would not be powerful enough to transform the generation mix.
The strongest influence in the study came from carbon pricing. A higher carbon price increases the cost of emissions for every fossil-fuel generator, but it affects coal disproportionately because coal combustion produces substantially more carbon dioxide than natural gas combustion for a comparable amount of electricity. As the carbon charge rises, coal plants become more expensive to operate relative to gas plants. Generators then have an incentive to alter their production decisions, with some electricity output moving from coal to gas. The model shows that this fuel-switching effect can reduce emissions, although it does not eliminate them. Natural gas remains a fossil fuel, meaning that a transition from coal to gas should be understood as a partial decarbonization step rather than a final solution.
The study also highlights why policies that appear effective on paper may produce weaker results in a regulated or centralized electricity market. In a fully competitive system, generators facing higher carbon and permit costs might raise electricity prices to recover their expenses. In Korea, however, electricity pricing and dispatch are strongly shaped by centralized institutions and market rules. Power companies may therefore be unable to transfer the full cost of compliance to consumers. This creates a difficult policy trade-off. If carbon costs rise rapidly without complementary assistance, coal and gas companies could face shrinking margins, reduced investment capacity, or pressure to keep older plants operating despite changing economics. If the carbon price remains too low, meanwhile, the K-ETS may fail to create a sufficiently strong incentive for cleaner generation.
The electricity sector’s importance makes the issue especially urgent. According to Professor Kim, the power sector is expected to contribute nearly 44.3 percent of Korea’s total national emissions reduction target. That share means the success or failure of K-ETS reforms in the electricity market could have consequences far beyond individual generators. A policy that cuts emissions but undermines the financial stability of power companies could create operational risks, while a policy that protects companies but leaves carbon prices too weak may not deliver the reductions required by Korea’s climate goals. The model therefore points toward a coordinated strategy in which allowance allocation, auctioning, carbon pricing, investment, and transition support are designed to reinforce one another rather than implemented as isolated measures.
The researchers argue that targeted investment and transitional support could help companies respond to the reforms without weakening the long-term decarbonization signal. Such measures might support cleaner generation, efficiency upgrades, grid modernization, or the retirement and replacement of high-emitting facilities, although the study emphasizes the need for complementary policies rather than prescribing a single support mechanism. This balance is crucial: assistance that simply protects fossil-fuel profits could delay the energy transition, while assistance tied to measurable emissions reductions could help companies adapt. The findings also suggest that a uniform benchmark and greater auctioning may be most effective when combined with a carbon price high enough to change operational decisions across the market.
The Korean case offers a broader lesson for countries seeking to copy or adapt emissions trading systems developed elsewhere. Carbon markets do not operate in isolation; their outcomes depend on electricity pricing, market concentration, fuel availability, technology costs, regulation, and the ability of companies to recover expenses. Korea’s proposed K-ETS reforms may produce meaningful emissions reductions, particularly by making coal less competitive than gas, but the simulation shows that institutional context will shape their impact. The study, published in Energy Policy, concludes that an integrated approach is essential if Korea is to decarbonize its electricity sector while maintaining a stable power supply and avoiding an excessive burden on generators. The research was published online on April 24, 2026, and appears in Volume 215 of the journal on August 1, 2026.
Subject of Research: Not applicable
Article Title: Impact of changes of allocation and price in emission trading scheme on the electricity market: Korean case study
News Publication Date: 1-Aug-2026
Web References: https://doi.org/10.1016/j.enpol.2026.115331
References: Energy Policy. DOI: 10.1016/j.enpol.2026.115331
Image Credits: Assistant Professor Dowon Kim, Pusan National University, Korea
Keywords: Korean Emissions Trading Scheme; K-ETS; electricity market; carbon pricing; emissions trading; coal power; natural gas; power generation; decarbonization; climate policy; environmental economics; South Korea
