The International Energy Agency (IEA) has published its Energy Policy Review Korea 2025, stating that South Korea’s climate goals remain achievable, but only if renewable energy investments double immediately and the electricity market undergoes structural reform. The country, whose energy mix remains one of the most carbon-intensive in the OECD, generated only 1.2% of its electricity from renewable sources in 2022, the lowest share among all IEA members.
An energy mix still dominated by imported thermal sources
In 2021, nearly 77% of South Korea’s primary energy came from fossil fuels, with 29.1% from coal, 25.8% from oil and 22% from natural gas. The country imports approximately 93% of its energy, including all of its liquefied natural gas (LNG), with over 90% of these volumes handled by Korea Gas Corporation (KOGAS). In 2022, LNG imports reached 46.4 Mt, with Qatar, the United States and Australia among the main suppliers.
The market structure is based on a single buyer model, with the Korea Power Exchange (KPX) centralising purchases from generators on behalf of Korea Electric Power Corporation (KEPCO), which is responsible for transmission, distribution and retail sales. In 2023, KEPCO posted a consolidated net loss of KRW18.8tn ($14.3bn), due to soaring import costs that were not passed on through tariffs.
The rising role of nuclear and limits of the current system
Nuclear accounted for 29% of electricity generation in 2024, surpassing coal (27%) and gas (24%). The development plan to 2038 includes two new large-scale reactors, a small modular reactor (SMR), and an increase in the nuclear share to 35%, with an overall target of 70% decarbonised electricity by combining nuclear and renewables.
KEPCO’s thermal subsidiaries (KOMIPO, KOEN, KOSPO, KOWEPO, EWP) remain exposed to stranded asset risks, especially coal units, some of which will need to be closed or converted to gas over the next ten years. Converting a coal plant to a combined-cycle gas turbine (CCGT) involves investment costs estimated between KRW200bn and KRW400bn ($150mn to $300mn) per plant.
A carbon trading system with limited impact
Launched in 2015, the Korea Emissions Trading System (K-ETS) covers 685 installations, representing nearly 80% of national emissions. In 2024, the average price of Korean carbon allowances stood at KRW13,000 ($9.88) per tonne, compared with over €70 ($76) in the EU market. The 4th Basic Plan for the ETS (2026–2035) includes increasing auctioned allowances (currently around 10%), strengthening the market stability reserve and allowing broader financial participation.
Massive free allocations and an overly high emissions cap have reduced the scheme’s investment signal. The proposed introduction of a price corridor and expanded financial actor access could bring the K-ETS in line with international standards by 2030.
Renewables hindered by land use and infrastructure constraints
Despite a doubling in installed renewable capacity between 2017 and 2022, South Korea remains far from its targets. In 2022, 21.6 GW of renewable capacity were installed, including 16 GW of solar and 2.8 GW of wind. Geographic constraints, high population density and local opposition hinder infrastructure expansion, particularly onshore wind and high-voltage lines.
The energy plan calls for 32 GW of offshore wind by 2038, including 14 GW of floating projects. Curtailment rates on Jeju Island already reach 10% in some periods due to insufficient grid capacity. Connection costs for a typical offshore project exceed KRW100bn ($76mn), limiting attractiveness without public support.
Ongoing but incomplete regulatory reforms
Amendments to the Electricity Business Act in 2021 enabled direct and third-party power purchase agreements (PPAs), but deployment remains limited: less than 600 MW were signed in 2023. Key barriers include contractual complexity, grid fees and limited availability of connected projects.
An independent multi-energy regulator is under consideration to oversee electricity, gas and hydrogen, but no timeline has been announced. This body would reduce the influence of public monopolies and create a more favourable environment for private investment.
Power-intensive industries facing geographic arbitrage pressure
Major South Korean industrial groups – Samsung, LG, SK, Hyundai, POSCO – account for a large share of national electricity consumption. Industrial electricity use exceeded 240 TWh in 2023, or nearly 60% of total consumption. These firms participate in international initiatives such as RE100 and K-RE100 but face difficulties accessing competitive and traceable PPAs.
The cost gap between electricity in South Korea and rates offered in the United States under the Inflation Reduction Act (IRA), or in the European Union via green electricity support schemes, is prompting some manufacturers to consider partial relocation to those jurisdictions.
Hydrogen and storage: emerging but still uncertain levers
The updated hydrogen strategy targets 1.94 Mt of demand by 2030, with a large share to be imported. Logistic corridors are under negotiation with Qatar, Saudi Arabia, Australia and the United Arab Emirates. KOGAS plans to retrofit part of its LNG terminals for hydrogen by 2035.
A storage services market is under design, with remuneration mechanisms for capacity and flexibility expected by 2026. South Korea already has around 1.2 GW of lithium-ion batteries, mainly for grid stabilisation, but the profitability of new projects remains tied to wholesale price volatility and dispatch rules.
