To ensure accessibility for readers without specialized knowledge of the Korean market, we’ll be taking a more conversational approach and in some instances, we have prioritized brevity over conveying the full complexity of the system. The main topics we will be exploring are the following:

Korean market overview
1. The key facts and stats around the Korean market and grid
2. Key routes to market and market structure
3. Major market reforms on the horizon

Key long-term driver of market outcomes
1. Electricity demand
2. State of the grid and transmission expansion
3. Solar and wind generation profiles
4. Coal exits and nuclear expansion

Our insights from long-term electricity market and grid forecasts
1. Korea’s capacity and generation mix to 2060
2. Wholesale pricing dynamics
3. Emissions

Korea, like a lot of markets, is grappling with the multifaceted challenges of decarbonizing its power system. Many of these challenges are exacerbated by the structure of the economy (Asia’s 4th largest and heavily dependent on manufacturing with potential additional demand growth coming from expanding the semiconductor industry and data centers), small landmass (less than half the size of Great Britain), and high population density (52m inhabitants). There are three key tensions we explore:

Approximately ₩500 trillion of generation investment is needed by 2050, but investors are grappling with rising policy, grid, and social license risk.
Renewables may have zero marginal costs, but electricity prices will likely be kept buoyant by international liquified natural gas (LNG) prices.
Market reforms aim to boost efficiency of investment and dispatch, yet the government will want to maintain guardrails on the transition, and interventions and complexity are likely to increase.

While there are likely to be challenges and tensions through Korea’s energy transition, our long-term forecasts see material opportunities for new-build renewables, gas, batteries, and hydrogen infrastructure.

Our Korean Power & Renewables Market Forecast can be downloaded here by subscribers.

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Korean market overview
1) The key facts and stats around the South Korean market and grid

Korea’s electricity supply is currently approximately 90% from thermal generation, split roughly evenly between coal, gas, and zero-emission nuclear. The remaining 10% is mostly renewables, with solar making up the largest chunk.

The system’s nameplate capacity is growing; we have seen an average of 5 GW of new net capacity added each year over the past five years, and renewables—mostly solar—made up 3.7 GW pa of that growth. We have also seen some gas, coal, and nuclear capacity built, while oil-fired generators have been retired.

So why have we seen so much solar growth? A large driver has been the Renewable Portfolio Standard (RPS), which mandates large generators to procure a rising share of power from renewables or buy Renewable Energy Certificates (RECs). REC prices have fluctuated in response to supply and demand for RECs, but since 2022, they have generally trended up from about ₩50,000 to ₩75–80,000/MWh. The RPS target itself has risen from 2% in 2012 to 13.5% in 2024.

However, the RPS percentage targets have been adjusted a few times, creating a more challenging policy environment for investment. In 2021, the target for 2024 was raised to 17% before being dropped back to 13.5% a year later under the Renewable Energy Act Amendment. This amendment also pushed back the date for the RPS to reach 25% from 2026 to 2030.

Today, Korea’s electricity market consists of more than 140 GW of generation capacity, split across two pricing regions: the mainland and Jeju Island. 99% of power demand is on the mainland, where 540 TWh were consumed in 2023—making Korea the 8th largest power user in the world. Peak demand exceeds 90 GW, 50% higher than average demand, and new records for peak demand were set in summer of 2024.

Korea’s wholesale price, the System Marginal Price (SMP), is not particularly volatile compared to other markets; in any trading interval, it rose as high as about ₩300/kWh in the mainland and ₩450/kWh in Jeju in 2023. It has oscillated between ₩70 and ₩120/kWh since 2017, with an exception between 2022 and 2023 when prices were materially higher as gas prices spiked after Russia invaded Ukraine.

The Korean government does map out a medium-term plan for future generation in a document called the 11th Basic Plan for Power Supply and Demand (2024 version). This is augmented by a transmission planning document called the 10th Long-term Transmission and Substation Plan (2023 version).

2) Key routes to market and market structure

The main routes to market for new renewable capacity are Korean Energy Agency-run (KEA-run) auctions, the spot market, or PPAs. Routes to market are likely to evolve because it is expected that consultations will begin this year to design a replacement for the RPS, relying more on long-term fixed-price auctions for renewable capacity.

Some of the renewable capacity that has come to market has actually already been delivered via KEA-run auctions that were designed to ensure RPS obligors (large generators >500MW) could access renewable power.

In 2020 and 2021, these auctions tended to be oversubscribed, with more bidding capacity than there were available contracts. However, from 2022, interest in these auctions fell, as the price caps remained flat despite surging wholesale prices (which improved spot market economics), along with the emergence of a non-KEPCO (Korea Electric Power Corporation) PPA market (e.g. corporate PPAs—almost 1 GW was signed in 2023).

The significance of auctions in the future will largely depend on the extent to which they can offer price support for higher cost technologies. For instance, the Ministry of Trade, Industry, and Energy (MOTIE) has recently announced plans for auctions of 7–8GW of offshore wind capacity over the next two years.

On market structure and rules: there are five main markets we consider in Korea: energy, capacity, RECs, ancillary services, and carbon. The operation and timelines of each of these are mapped out in the below exhibit.

3) Major market reforms on the horizon

Korea, again, like many markets globally, is suggesting a range of market reforms to help manage variable renewable energy and ensure sufficient dispatchable capacity through the transition. The below exhibit maps out the ambitious reform agenda from Korea’s MOTIE. The most significant of these in the short-term for renewables may be shifting from the current RPS system to more direct auctions as an investment signal to renewables.

Given the sheer number of proposed reforms, and the fact most are planned to be introduced over the next three years, there are a lot of details required that MOTIE will need to iron out. Some of these reforms, such as nodal pricing, have generally taken much longer to implement in other markets. The feedback from market participants on the ground in Korea is that many of these reforms are likely to be delayed or partially delivered.

Many of these reforms have been tested on Jeju Island and have materially changed price outcomes, for example, Jeju has seen significantly lower day-ahead prices when renewables are allowed to bid into the market.

It is also worth briefly noting the critical role KEPCO (and its subsidiaries) play in Korea’s energy system. KEPCO is the monopoly transmission operator and retailer but has faced financial challenges over the last few years as the government has been unwilling to allow KEPCO to fully pass on increasing wholesale energy costs to consumers. As such, KEPCO has borne material losses through 2021–2023, seen its credit rating downgraded, and is now selling off parts of its business.

Key long-term driver of market outcomes

In terms of long-term drivers of Korean market outcomes (both in reality and in capacity expansion/dispatch models), there are thousands of variables. For now, we will focus on four inputs that clients bring up with us most frequently: long-term electricity demand; the transmission network; solar and wind generation profiles; and coal exists and nuclear expansion.

1) Electricity demand

The demand assumption for our Central scenario is closely aligned with the near-term demand trajectory as outlined by MOTIE’s 10th Basic Plan. Annual demand has a ~1% pa growth rate over the forecast time horizon, reaching ~720 TWh by 2040. Longer term demand growth is constrained by challenges in rapidly ramping up new sources of supply, as well as long-term population decline.

While there is no final demand forecast, the release of MOTIE’s 11th working plan outlines further increases to peak demand, driven by the growth of data centers, possible chip/semiconductor manufacturing near Seoul in the Yongin Cluster, growth of the industrial sector more broadly, EV demand, and other forms of electrification.

2) State of the grid and transmission expansion

The 10th Long-term Transmission and Substation Plan (TSP) released by KEPCO in 2023 has mapped out a series of transmission expansions and augmentations. The general on-the-ground view in Korea is that many of these new transmission lines are vital both to avoid increased grid losses and curtailment (particularly from south to north) and to increase renewable hosting capacity, but are likely to see some delays in delivery.

Our assumptions about grid expansion are consistent with the 10th Long-term Transmission and Substation Plan. As these plans evolve, we would note that projects are getting pushed backwards. As an example, the Dongducheon-Yangju line in the Seoul Capital Area was initially planned for completion in 2019, as outlined in the 6th Transmission and Substation Plan; however, timings slipped, and by the 9th TSP, the project was expected in 2022. When the 10th TSP came out, timing had slipped a further two years to December 2024.

These grid expansion assumptions are critical as they inform the estimated hosting capacity for new renewable buildout (alongside land constraints and other critical factors) in our modeling suite. Particularly in Honam, additional transmission is required to ensure south to north power flows are less constrained and that there is available hosting capacity for new solar and wind.

Separately, we are rolling out curtailment modeling at a regional level in the next few months with a focus on Jeollanam-do, Gyeongsangnam-do (Ulsan), and Chungcheong-do initially.

3) Solar and wind generation profiles

Korea has a relatively limited land mass (at about half the size of Great Britain) and some challenging coastline in terms of water depth and geology on its east coast, in particular. There is a very pronounced seasonal shape to wind generation with significantly lower output in summer months. Average load factors for onshore and offshore wind are lower than we see in some regions where wind is proposed as a dominant source of supply (e.g., the North Sea, parts of US coasts, Bass Strait in Australia). Our internal wind atlas indicates that wind load factors are approximately 27–32% for fixed offshore and approximately 35–40% floating offshore, typically with the east coast and Honam seeing better load factors than the west coast.

4) Coal exits and nuclear expansion

Korea has delivered new coal plants over the last five years. In addition, Samcheok #1 and #2 are the last coal plants in MOTIE Basic Plan’s construction pipeline.

Moving forward, we assume coal exits will be broadly consistent with the 11th Basic Plan and that coal assets will either close or be converted to ammonia co-firing plants or hydrogen CCGT plants over the longer term. This forecast sees Korea exiting coal entirely by approximately 2050–2055.

In our Central scenario, we assume the nuclear buildout rates are consistent with the 11th Basic Plan which sees 37 GW by 2039 and approximately 30% of total generation being provided by nuclear over the forecast horizon. This increased capacity includes 1 x 0.7 GW Small Modular Reactor and 3 x 1.4 GW Advanced Power Reactors over the next 10–15 years. Korea is one of the very few jurisdictions that has managed to build new nuclear plants relatively on-time and on-budget. Korea builds nuclear plants regularly and has developed sophisticated engineering, delivery, and supply chain capabilities around new nuclear. However, there remains some political disagreement over nuclear policy, with the former president Moon Jae-in announcing a nuclear phase-out policy in 2017, only for President Yoon Suk Yeol to reverse this since coming to power in 2022.

Our insights from long-term electricity market and grid forecasts

We have five off-the-shelf scenarios for the Korean market, but in this section we will largely focus on market outcomes from the Central scenario.

1) South Korea’s capacity and generation mix to 2060

We forecast Korea’s energy mix to evolve in three broad ways. Firstly, in terms of baseload capacity, we forecast a shift from coal + gas + nuclear to a system with nuclear (36 GW by 2050) + gas (60 GW by 2050) as the dominant form of fuel-based supply, with a potential role for hydrogen CCGTs over the longer-term (12 GW by 2050).

Secondly, we forecast material growth in both onshore and offshore renewable capacity. Solar remains the largest portion of renewable capacity, but growth is forecast to be limited by both grid and land availability. Some of the solar growth is also driven by behind-the-meter solar installations—which subscribers on-the-ground in Korea are relatively more bullish about (74 GW of grid-scale solar PV + 15 GW of BTM solar by 2050). Onshore wind growth remains more limited as onshore plants are generally difficult to permit and connect, and individual projects tend to be smaller in size and higher cost given terrain (15 GW by 2050). We forecast material growth in offshore (fixed and floating) driven largely by a combination of government auctions and RECs (22 GW fixed and 15 GW floating by 2050). We see most of this offshore capacity in the Honam and Yeongham regions (where there are already material offshore wind pipelines).

Offshore, in particular, also faces challenges around permitting. The government is pushing forward with a ‘One-Stop Shop Act’ to streamline interactions across ministries, but the existing process remains both complex and time-consuming.

Lastly, we forecast growth in fast-ramping and dispatchable flexible capacity to help manage the intermittency of this renewable generation. This flexible capacity is forecast to be a mix of battery storage of various durations (30 GW by 2050) and hydrogen peaking assets (12 GW by 2050)—including the fuel cells which are already operational and the additional capacity currently being auctioned. These fuel cells are expected to generate a more baseload profile over the life of the CFDs provided to them.

We would note that dispatchable capacity increases approximately linearly with peak demand, given Korea’s relative lack of diversity of renewable generation.

In terms of how that capacity converts into generation, we would highlight that, despite the significant renewable and nuclear capacity growth outlined above, our Central scenario is slightly more conservative on decarbonization than the 11th Basic Plan. For example, the 11th Basic Plan targets 70% carbon-free generation by 2038 while our Central scenario forecasts 63% by 2040. More specifically, the 11th Basic Plan targets 33% generation from renewables by 2038 versus our Central scenario at 29% renewable generation by 2040.

Often, we see forecasts where projected growth rates of capacity are fundamentally inconsistent with what regions have achieved to date, and have the potential to achieve moving forward. We generally try to ensure we are accounting both for tailwinds but also headwinds, especially those challenges that get harder as renewable penetration increases (e.g., optimal sites saturation, social license gets harder due to poor experiences/consultation fatigue, etc).

In the exhibit below, we map out the growth of all capacity and then renewable capacity, and compare that to the growth rates required to hit our Central and Net Zero scenarios. The key insight is that, somewhat obviously, Net Zero scenarios are challenging—they basically require a doubling of current build rates for renewables in Korea.

To bring some of this analysis to life, we have mapped out below two sample weeks in 2050: the first with high renewable output in summer; and the second with low renewable output in winter. This illustrates some of the key challenges in deep decarbonization systems, for example, required flexible asset ramp rates as solar output declines in the evening; the role of gas in ramping up and down around wind output; the risk of excess renewable generation and subsequent curtailment and the role of storage in minimizing curtailment; and the inflexibility of nuclear.

2) Wholesale pricing dynamics

In our Central scenario, we forecast the Korean SMP to stabilize between ₩100–110/kWh over the long-term to meet growing demand. These long-term averages disguise rising price volatility on an intra-day and inter-seasonal basis; this is a function of both variable and shifting demand, and different levels of renewable output across days and seasons.

It is worth noting that we also run alternative scenarios as well to provide plausible ranges of outcomes, particularly for the project finance community. For example, our Low scenario (lower commodity prices, CAPEX, and demand) forecasts prices of around ₩60–70/kWh. Conversely our High scenario (higher commodity prices, CAPEX, and demand) forecasts prices around ₩160–70/kWh.

We run two other scenarios as part of the Korean Power & Rewewables Market Forecast package: a Messy Transition scenario (reflects potential ‘messiness’ or ‘lumpiness’ of the energy transition across regions/markets) and a Net Zero scenario (assumes Korean Government fully delivers on stated decarbonization targets, grid buildout, renewable and nuclear buildouts, potentially via out-of-market support; and also assumes long-term demand grows in line with MOTIE forecasts and carbon pricing starts to be reflected in the power sector).

There are a range of other outputs in our Korean Power & Renewable Market Forecast—for example, technology-specific economic curtailment rates; REC prices (both assuming continuation of multipliers and more fundamental region- and technology-specific missing money calculations); fair value PPA benchmarks; capacity payments; intra-day spreads; KEPCO Industrial Tariff levels; amongst others. We won’t cover these here for the sake of brevity.

3) Emissions

Coal and gas accounted for approximately 65% of electricity generated in Korea’s electricity market last year, and while this share is lower than the Asian average (of 68%), it sits above that of other OECD (the Organisation for Economic Co-operation and Development) countries who have an average of 52%.

In the near term, current levels of emissions are expected to persist as some additional coal and gas capacity continues to come online. However, from the 2030s onwards, emissions are forecasted to fall steadily, reaching ~72% overall reduction by 2060.

These reductions are primarily driven by the retirement of ageing coal plants, as well as the conversion of some coal plants into lower- or zero-emission fuel sources (e.g., LNG, ammonia, hydrogen).

Under our Central scenario, we still see some carbon in the electricity system—as ever, it does remain challenging to drive the last fossil fuel generation out of an electricity system.

We trust this has been a helpful summary of some of the key themes and challenges in modelling the Korean electricity system and grid. Again, we thank +50 clients and friends who have provided detailed feedback on policy settings, inputs, and methodologies. Korea is among the most complicated markets we have modeled to date and the analysis in our Korean Power & Renewable Market Forecast has been significantly improved by their input.

If you do have any questions regarding the Korean electricity market and grid, reach out to the authors, visit the website, or email Jessie Seo.