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South Korea: 7 energy policy briefs

The energy policies moving South Korea’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Renewable procurement reset · from RPS certificates to a contract market, from 1 January 2027

South Korea · National Assembly (Renewable Energy Development, Use and Deployment Promotion Act, Act No. 21462 of 17 March 2026, renaming and amending Act No. 21943) · statute · 2026

Where it stands: Act No. 21462 in force from 18 September 2026; the procurement articles commence 1 January 2027

Korea is retiring the renewable portfolio standard that has driven its solar and wind build since 2012 and replacing it with government-run auctions and contracts: the renewable statute was renamed and rewritten by Act No. 21462 of 17 March 2026, new Articles 12-10 to 12-14 including a contract market system for renewable facilities commence on 1 January 2027, and a transitional provision fixes a cut-off for issuing supply certificates.

The problem

The renewable portfolio standard obliged large generators to source a rising share of their output from renewables or buy renewable energy certificates, and it worked as a deployment tool while volumes were small. It became a poor instrument as the fleet grew. REC prices were volatile and untethered from project cost, so developers could not finance against them and obligated parties could not budget; the obligation fell on a handful of state-owned generators who simply passed the cost through; and the certificate market produced no locational or temporal signal, which is precisely what a system with growing curtailment in Jeju and Honam needs. Meanwhile corporate buyers wanted long-dated, physically settled renewable supply that the REC market could not deliver, and the direct corporate PPA route opened under the Electric Utility Act remained small because the regulated retail tariff was cheaper than a PPA for most of the period.

What it does

Act No. 21462, promulgated on 17 March 2026, renames the New and Renewable Energy Development, Use and Deployment Promotion Act as the Renewable Energy Development, Use and Deployment Promotion Act and restructures its support architecture; the consolidated text carries a commencement date of 1 January 2027 for the new provisions, with a further consequential amendment as Act No. 21943 of 15 September 2026. The new Articles 12-9 to 12-14 rebuild the supply-certificate and procurement framework: Article 12-9 sets out the functions of the supply certification body, Article 12-10 the grounds for revoking its designation, Articles 12-11 and 12-12 fuel quality standards and inspection for renewable fuels, Article 12-13 an obligation to install renewable equipment at public car parks, and Article 12-14 the operation of a contract market system for renewable energy facilities, under which the Minister of Climate, Energy and Environment may operate a separate contract market where the minister considers it necessary, on criteria published by notice. Supplementary Article 3 governs the transition for the issuance and trading of supply certificates and fixes a deadline for certificate issuance under the old regime. Alongside this, direct corporate power purchase agreements remain available under the Electric Utility Act framework, and the Korea Energy Agency's competitive tenders for fixed-price renewable supply continue as the practical procurement route while the new contract market is stood up.

Market effect

The move from certificates to contracts is the single most important change for anyone financing Korean renewables. A REC-based project is financed against a volatile commodity with no term; a contract-market project is financed against a long-dated, government-underwritten price, which lowers the cost of capital and is what makes offshore wind under the new zonal regime bankable at Korean cost levels. For obligated generators the change removes a compliance cost and a hedging headache, but it also removes the merchant demand that supported REC prices, so holders of legacy certificates face a wind-down whose terms are set by supplementary Article 3, and the certificate issuance deadline in that provision is the number every existing project owner needs. For corporate buyers the reset is mixed: a state-run contract market competes with direct PPAs for the same projects, and whether corporate demand is served depends on how the minister designs the contract market and whether renewable supply is ring-fenced for RE100 buyers. For the system, an auction with locational and delivery conditions can do what an undifferentiated certificate never could, which is steer new capacity toward places and profiles the grid can absorb, and that matters most in exactly the southern regions where curtailment is already routine.

Key numbers

Renaming and restructuring statute
Act No. 21462, promulgated 17 March 2026 — the Act is now the 재생에너지 개발·이용·보급 촉진법, the words "new energy" having been dropped from a title that carried them since 1987
Main commencement
18 September 2026 for Act No. 21462
Commencement of the procurement provisions
1 January 2027 for Articles 12-10 to 12-14
Contract market power
Article 12-14: the Minister of Climate, Energy and Environment may operate a separate contract market system by published notice
Latest amendment
Act No. 21943 of 15 September 2026, commencing in stages — 1 January 2027 and 16 March 2027
Where "new energy" went
Act No. 21467 of 17 March 2026, amending the Hydrogen Economy Promotion and Hydrogen Safety Management Act (수소경제 육성 및 수소 안전관리에 관한 법률) and also in force 18 September 2026, carries fuel cells and hydrogen energy equipment (its Article 2(6) and (12)); the Electric Utility Act and the Distributed Energy Act now cite that Act for them and the renamed Act for renewables

Who gains and who pays

  • Solar and wind developers (gains): Long-dated contracted prices replace volatile certificate revenue, lowering the cost of capital.
  • Holders of legacy renewable energy certificates (costs): Face a wind-down governed by the transitional provision and the certificate issuance deadline.
  • Obligated generators under the old portfolio standard (gains): Lose an unpredictable compliance cost as the obligation is replaced by state procurement.
  • Corporate buyers pursuing RE100 (mixed): A state contract market competes for the same projects as direct corporate PPAs.
  • Electricity consumers (costs): Contract costs move onto the public procurement side and ultimately into tariffs.

Implementation

The Act creates the power; the ministry's notice and the Enforcement Decree create the market. What matters commercially is the design choices still to be made: whether the contract market is a pay-as-bid or pay-as-cleared auction, what contract tenor is offered, whether contracts are indexed, whether they carry curtailment compensation, how offshore wind zones designated under the Offshore Wind Special Act are tendered into it, and whether a share is reserved for corporate offtake. The transitional provision governs how long certificates continue to be issued and traded, which sets the runway for existing projects and for the certificate exchange. Because the renewable statute, the offshore wind statute and the grid statute all commenced within eighteen months of each other and are all administered by a ministry created in October 2025, the sequencing risk is real: a contract market that opens before zones are designated or before connection dates are credible will price that uncertainty into bids.

Concerns

  • Legacy certificate holders face a wind-down whose terms depend on a transitional provision
  • Contract-market design is left to ministerial notice, so key commercial terms are not yet fixed
  • A state contract market may crowd out direct corporate PPAs needed for RE100 compliance
  • Sequencing risk between the contract market, offshore wind zone designation and grid delivery
  • Cost moves from obligated generators to the public purse and ultimately to tariffs

Dates to watch

  • 1 January 2027: Commencement of the new supply-certification and contract-market articles
  • 2027: First auction round under the contract market system and the certificate issuance cut-off under the transitional provision

Sources

Checked against sources on .

11th Basic Plan for Electricity Supply and Demand · confirmed February 2025 for 2024-2038

South Korea · Ministry of Trade, Industry and Energy (energy functions transferred to the Ministry of Climate, Energy and Environment on 1 October 2025 by Act No. 21065) · plan · 2025

Where it stands: Confirmed February 2025 and being delivered through licensing, tenders and the grid plan

The 11th Basic Plan, confirmed in February 2025 after a year of delay and parliamentary fighting, fixes the capacity mix Korea will procure to 2038: more nuclear, including new large units and a first small modular reactor, a large increase in solar and wind, coal retirements, and a demand forecast lifted by semiconductor fabs and data centres.

The problem

Korea's electricity system is a single-buyer market run by KPX in which KEPCO buys almost all generation and sells at regulated retail tariffs, so the capacity mix is decided administratively rather than by price. The Electric Utility Act requires a Basic Plan for Long-term Electricity Supply and Demand every two years, and it is the document every subsequent decision hangs from: the transmission plan, the nuclear construction programme, coal retirement dates and the renewable auction volumes all follow it. The 10th plan was overtaken by events. Demand forecasts had to be rebuilt around the Yongin semiconductor cluster and data-centre load, the previous administration's nuclear phase-out had been reversed, KEPCO was carrying an enormous deficit from selling below cost, and the 2030 and 2050 climate targets needed a generation mix that could actually be built. The draft was published in mid-2024 and the final plan was held up by the National Assembly's standing committee before being confirmed in February 2025.

What it does

The plan covers 2024 to 2038 and is drafted by a working group under the energy ministry, reported to the National Assembly's standing committee, and confirmed by the Electricity Policy Deliberation Council. It raises the 2038 demand and peak-load forecast to reflect industrial and data-centre growth, sets nuclear as the largest single source by 2038 at roughly a third of generation with additional large reactors and a first small modular reactor, expands renewables toward roughly 30 percent of generation, cuts coal's share sharply through scheduled retirements and conversions, and leaves LNG as the flexible balance. It is planning guidance rather than a rule: it does not by itself license a plant or commit KEPCO to a contract, but nothing gets built in Korea that is not in it. Because energy policy moved from the Ministry of Trade, Industry and Energy to the new Ministry of Climate, Energy and Environment under the Government Organisation Act amendment (Act No. 21065 of 1 October 2025), the 11th plan was adopted by one ministry and is being implemented by another, and the 12th plan will be produced by the Ministry of Climate, Energy and Environment. Delivery of the transmission the plan assumes runs through the National Backbone Power Grid Expansion Special Act (Act No. 20844, promulgated 25 March 2025, in force 26 September 2025).

Market effect

For anyone financing generation in Korea the Basic Plan is the demand curve. A capacity type that appears in it can expect a KPX market position, a grid connection queue slot and, for renewables, a procurement route; one that does not will not be built regardless of economics. The higher demand forecast is the single most consequential number, because it justifies both the nuclear programme and the grid build-out, and because it is driven by a small number of very large loads whose actual arrival dates are commercially uncertain. A nuclear share near a third of 2038 generation, combined with 30 percent renewables, implies a system with very little room for mid-merit coal and a rising need for flexibility, which is why storage mandates, the distributed energy framework and the day-ahead and real-time market reform matter more each year. It also implies chronic curtailment risk in the south-west and on Jeju unless transmission arrives on schedule. For LNG importers the plan points to lower baseload gas burn but higher peaking value; for coal owners it sets retirement and conversion dates that determine stranded-asset exposure; for offshore wind and solar developers it sets the auction volumes the Korea Energy Agency will tender.

Key numbers

Plan and announcement
Eleventh Basic Plan for Electricity Supply and Demand (2024-2038), confirmed and announced 21 February 2025 as MOTIE Notice No. 2025-169
2038 peak demand
129.3 GW, against 157.8 GW of supply capability — a 22.0% reserve margin
2038 installed capacity
268.1 GW in total
2038 capacity mix (nameplate)
Renewables 121.9 GW (45.5%), LNG 69.2 GW (25.8%), nuclear 35.2 GW (13.1%), coal 22.2 GW (8.3%), pumped storage 4.0 GW (1.5%)
2038 contribution to peak supply
LNG 69.2 GW (43.8%), nuclear 35.2 GW (22.2%), coal 21.8 GW (13.8%), renewables only 13.5 GW (8.5%) — renewables are 45.5% of plate but 8.5% of firm peak capability, and that gap is the whole planning problem
Coal trajectory
Coal capacity falls from 38.7 GW in 2023 to 21.8 GW of peak contribution by 2038, roughly halving
Statutory basis
Electric Utility Act (current consolidated version Act No. 21944, in force 15 September 2026)
Competent ministry
Transferred from MOTIE to the Ministry of Climate, Energy and Environment on 1 October 2025 (Act No. 21065); the trade ministry now sits at motir.go.kr
Enabling grid statute
National Backbone Power Grid Expansion Special Act, Act No. 20844 of 25 March 2025, in force 26 September 2025

Who gains and who pays

  • Korea Hydro and Nuclear Power and reactor suppliers (gains): New large units and a first SMR in the 2038 mix, with the plan as the licensing and financing basis.
  • Solar and wind developers (gains): Renewable share near 30 percent by 2038 sets the auction and connection volumes.
  • Coal generators (KOSPO, KOMIPO, KOEN, EWP, KOWEPO) (costs): Scheduled retirement and conversion of coal units inside the plan horizon.
  • Semiconductor fabs, data centres and industrial users (mixed): The demand forecast is built on their load; connection timing and tariffs follow from it.
  • KEPCO and KPX (obligation): Must deliver the transmission, connections and market arrangements the plan assumes.

Implementation

Under the Electric Utility Act the ministry drafts the plan with a working group, holds a public hearing, reports it to the National Assembly's standing committee and has it confirmed by the Electricity Policy Deliberation Council. Implementation then splits across several bodies: KEPCO and KPX turn the capacity numbers into a transmission and substation programme under the separate long-term transmission and substation plan, the Korea Energy Agency runs the renewable tenders whose volumes derive from the plan, the Nuclear Safety and Security Commission licenses the reactors, and site selection for transmission now runs through the National Backbone Power Grid Expansion Special Act, which creates a national committee and compressed approval procedures for designated backbone projects. Plans are produced on roughly a two-year cycle, so the 12th Basic Plan is the next decision point and will be the first written by the Ministry of Climate, Energy and Environment, which also holds the emissions-trading and climate-target mandate. Because the plan is guidance, the binding moments are the licensing, tender and tariff decisions that follow it.

Concerns

  • The demand forecast rests on a handful of very large industrial and data-centre loads whose timing can slip
  • Nuclear expansion depends on site consent and Nuclear Safety and Security Commission licensing that the plan cannot compel
  • Transmission has consistently lagged generation, producing curtailment in Jeju and the south-west
  • Energy policy moved ministries in October 2025 mid-implementation, creating institutional discontinuity
  • The plan is administrative guidance with no contractual commitment to any developer

Dates to watch

  • 2027: Expected draft and confirmation of the 12th Basic Plan for Electricity Supply and Demand
  • 2030: Interim checkpoint against Korea's 2030 nationally determined contribution that the mix is calibrated to

Sources

Checked against sources on .

K-ETS phase 4 · 2026-2030 allocation under the amended trading Act

South Korea · National Assembly and the Ministry of Climate, Energy and Environment (Act on the Allocation and Trading of Greenhouse-Gas Emission Permits, amended by Act No. 21071 of 28 October 2025) · regulation · 2025

Where it stands: Amended Act and Decree in force from 29 April 2026; phase 4 allocation running to 2030

Korea's emissions trading scheme entered its fourth phase in 2026 covering 2026 to 2030, with the governing Act amended by Act No. 21071 of 28 October 2025 and the Enforcement Decree by Presidential Decree No. 36285 of 28 April 2026, both in force from 29 April 2026, and with administration now split between the Ministry of Planning and Budget and the Ministry of Climate, Energy and Environment.

The problem

K-ETS has run since 2015 and covers a large majority of Korea's emissions, but through its first three phases it produced a carbon price too low and too illiquid to change investment decisions. The causes were structural: allocation was overwhelmingly free and grandfathered to historical emissions, the cap was set loosely enough that most participants held surpluses, banking and borrowing rules restricted trading, the investor base was almost entirely the covered entities themselves, and power generators could not pass carbon cost into a regulated retail tariff, so the price did not reach the merit order. A scheme that cannot move a coal plant ahead of a gas plant in dispatch is not doing the one job an ETS exists to do, and Korea needed it working before the 2030 nationally determined contribution and the 2050 net-zero target became binding constraints.

What it does

Phase 4 runs from 2026 to 2030 and is governed by the Act on the Allocation and Trading of Greenhouse-Gas Emission Permits as amended by Act No. 21071, promulgated on 28 October 2025 and in force on 29 April 2026, with the Enforcement Decree amended by Presidential Decree No. 36285 of 28 April 2026 in force on the same date. Administrative responsibility is shared, with the Act now listing the Ministry of Planning and Budget alongside the Ministry of Climate, Energy and Environment, a consequence of the October 2025 government reorganisation that created the climate and energy ministry and moved budget functions. The phase 4 allocation plan sets the cap for the period, the split between free and auctioned allowances, the sectors moved from grandfathered to benchmark-based allocation, the treatment of new entrants and closures, and the rules on banking, borrowing and the use of domestic and international offset credits. The direction of travel across phases has been a tightening cap, a rising auction share, wider benchmark coverage and broader market access for financial participants intended to add liquidity.

Market effect

The immediate commercial consequence for power is the interaction with the single-buyer market. Korean generators bid into KPX and are paid the system marginal price; if carbon cost is not reflected in that price, an allowance obligation is a balance-sheet item rather than a dispatch signal, and the ETS shifts cost without shifting megawatt-hours. Phase 4's credibility therefore rests on whether the carbon cost reaches the market price mechanism and whether KEPCO's tariff can absorb it, which is the same constraint that governs the fuel-cost adjustment. For industry the change is more direct: a higher auctioned share converts a free allocation into a cash cost with a market price attached, which is what makes fuel switching, electrification and efficiency projects clear an internal hurdle rate. Benchmark-based allocation rewards the most efficient plant in each sector and penalises laggards, so within steel, cement, petrochemicals and refining the scheme becomes a competitive as well as an environmental instrument. For traders, the market to watch is liquidity: if the phase 4 rules genuinely widen participation beyond covered entities, the Korean allowance becomes a tradeable asset with a forward curve rather than a compliance certificate, and the offset market, including domestic reduction credits and eligible international units, prices off it.

Key numbers

Phase 4 period
2026 to 2030
Governing amendment
Act No. 21071, promulgated 28 October 2025, in force 29 April 2026
Enforcement Decree
Presidential Decree No. 36285 of 28 April 2026, in force 29 April 2026
Competent authorities
Ministry of Planning and Budget and Ministry of Climate, Energy and Environment

Who gains and who pays

  • Covered industrial emitters (steel, cement, petrochemicals, refining, semiconductors) (obligation): Must hold allowances for phase 4 emissions, with a larger share bought rather than granted.
  • Power generators (costs): Carry the allowance obligation without a reliable route to pass carbon cost into the KPX price.
  • Low-carbon technology suppliers and offset project developers (gains): Regulated demand for abatement and for eligible reduction credits.
  • Financial participants and market makers (gains): Wider access is intended to bring liquidity and a forward curve to the Korean allowance.
  • KEPCO and electricity consumers (costs): Carbon cost ultimately lands in generation cost and therefore in tariffs or in KEPCO's deficit.

Implementation

The Act sets the architecture; the phase 4 allocation plan and the Enforcement Decree set the numbers. Allocation is made to each covered entity at the start of the phase, with annual surrender against verified emissions reported under the greenhouse gas target management framework; auctions are run for the paid portion; and the allocation committee handles new entrants, closures and additional allocation. Because the October 2025 reorganisation moved the climate mandate into a new ministry, the phase 4 rules are being administered by an institution that is itself new, and the trading Act now names two ministries, so participants should confirm which body issues any given decision. The Act's interaction with the Ministry of Climate, Energy and Environment's other instruments, notably the renewable procurement reset and the Basic Plan's coal retirement schedule, determines how much abatement is delivered by the ETS price and how much by direct regulation.

Concerns

  • Carbon cost still does not reach dispatch because generators cannot pass it into the regulated tariff
  • Historically thin liquidity and a participant base dominated by covered entities
  • Free allocation and benchmark scope decide whether the cap binds or is simply absorbed
  • Administration split between two ministries after the October 2025 reorganisation
  • Alignment between the ETS cap, the 2030 NDC and the Basic Plan's coal retirement dates is not automatic

Dates to watch

  • 2027-06: First compliance surrender covering phase 4 emissions
  • 2030: End of phase 4 and alignment checkpoint with Korea's 2030 nationally determined contribution

Sources

Checked against sources on .

National Backbone Power Grid Expansion Special Act · in force 26 September 2025

South Korea · National Assembly (Special Act on the Expansion of the National Backbone Power Grid, Act No. 20844 of 25 March 2025) · statute · 2025

Where it stands: In force since 26 September 2025; amended Decree effective 1 July 2026

Korea's backbone grid act, promulgated on 25 March 2025 and in force six months later on 26 September 2025, lifts nationally significant transmission projects out of the ordinary Electric Source Development Promotion Act process and gives them a state-led committee, compressed approvals and statutory community compensation, because transmission, not generation, is what is failing to arrive.

The problem

Korea's grid failures have been the binding constraint on its energy plans for more than a decade. The 765 kV lines from the east coast nuclear and coal fleet to the capital region took decades and produced the Miryang dispute; the west-coast solar build ran ahead of transfer capacity and produced curtailment; and the semiconductor clusters in Yongin and Pyeongtaek need gigawatts of new supply on timetables no conventional transmission process can meet. Under the Electric Source Development Promotion Act a transmission project needed an implementation plan approval and a long chain of local consents, each of which a provincial or municipal authority could stall. The 11th Basic Plan's nuclear and renewable mix cannot be delivered without a step change in how quickly lines are built, and the National Assembly concluded that the answer required primary legislation rather than better project management.

What it does

The Special Act on the Expansion of the National Backbone Power Grid (Act No. 20844, promulgated 25 March 2025) came into force six months after promulgation, on 26 September 2025. It creates a category of national backbone power grid projects designated by the state, establishes a high-level committee to drive and coordinate them, and provides a compressed and integrated approval route in place of the ordinary sequence of separate consents. Supplementary Article 2 handles the transition: electric power facilities that had already received implementation plan approval under Article 5 of the Electric Source Development Promotion Act when the Act commenced are carried across into the new regime. The Act also puts community compensation and benefit-sharing for line and substation hosts on a statutory footing, which is the political price of the accelerated procedure. A consequential amendment by Act No. 21447 of 5 March 2026, arising from changes to the Local Autonomy Act, takes effect on 1 July 2026, and the Enforcement Decree was amended by Presidential Decree No. 36424 of 23 June 2026, also in force on 1 July 2026. Competence sits with the Ministry of Climate, Energy and Environment following the October 2025 reorganisation.

Market effect

Transmission timing is the variable that decides whether Korean generation assets earn what their business cases assume. For renewable developers in South Jeolla, North Jeolla and on the west coast, the Act is the difference between a project that captures a full price and one that is curtailed on every sunny spring weekend; the value of a solar or offshore wind PPA in those regions should be discounted by curtailment risk until the backbone lines are dated. For the nuclear and coal fleet on the east coast the Act determines whether output can reach the capital region or is bottled behind constraints. For the semiconductor clusters and data centres, the connection date set under this Act is a gating item on multi-billion-dollar fab investment decisions, which is why the government treated it as industrial policy rather than utility regulation. For KEPCO the Act reduces schedule risk but not cost: the capital programme still has to be funded from a regulated tariff that is simultaneously being used to repair the balance sheet, so the grid build-out and the tariff path are the same question. The statutory compensation framework converts an unpredictable political cost into a budgeted line, which is what makes the programme financeable, but it also raises the unit cost of every kilometre built.

Key numbers

Act and promulgation
Act No. 20844, promulgated 25 March 2025
Commencement
26 September 2025, six months after promulgation
Transition
Supplementary Article 2 carries across facilities already approved under Article 5 of the Electric Source Development Promotion Act
Later amendments
Act No. 21447 of 5 March 2026 and Enforcement Decree Presidential Decree No. 36424 of 23 June 2026, both in force 1 July 2026
Consequential amendment, 18 September 2026
Act No. 21462 of 17 March 2026 (the Renewable Energy Act renaming): Articles 2(2)(b) and 7(2) now cite the 재생에너지 개발ㆍ이용ㆍ보급 촉진법 by its new name. Cross-references only

Who gains and who pays

  • KEPCO as transmission owner (mixed): Gains a faster approval route for designated projects but must fund the capital programme from regulated revenue.
  • Renewable generators in the south-west and on Jeju (gains): Backbone reinforcement is the direct remedy for curtailment and depressed capture prices.
  • Semiconductor clusters, data centres and large industrial loads (gains): Connection dates for very large new loads become deliverable within investment timetables.
  • Host communities and local governments (mixed): Lose some procedural leverage but gain statutory compensation and benefit-sharing.
  • Electricity consumers (costs): The transmission capital programme and the compensation framework are recovered through tariffs.

Implementation

The machinery is the designation of national backbone projects and the committee that drives them. Once a project is designated, the integrated approval route replaces the separate consent chain and the statutory compensation provisions apply to affected landowners and host communities. The Enforcement Decree sets the designation criteria, the committee's composition and procedure, and the compensation mechanics; it was amended in June 2026 alongside the Local Autonomy Act consequential changes. Delivery is measured in energisation dates rather than approvals, so the tests to watch are whether the east-coast to capital-region corridors, the west-coast renewable evacuation lines and the connections into the Yongin and Pyeongtaek clusters actually move. Because the Act accelerates procedure without removing the underlying land and community negotiation, litigation and local resistance remain possible; the difference is that the state, not KEPCO alone, now owns the political problem.

Concerns

  • Compressed approvals do not remove land acquisition and community negotiation, only reorder them
  • Statutory compensation raises the unit cost of every line built
  • Funding still comes from a regulated tariff already stretched by KEPCO's deficit
  • Designation is discretionary, so projects outside the backbone category keep the old timetable
  • Local governments may litigate the displacement of their consent powers

Dates to watch

  • 2027: First integrated approvals and construction starts for designated backbone projects
  • 2028: Energisation checkpoints for the corridors the 11th Basic Plan depends on

Sources

Checked against sources on .

Offshore Wind Special Act · Act No. 20845, in force 26 March 2026

South Korea · National Assembly (Special Act on the Promotion of Offshore Wind Power Deployment and Industry Development, Act No. 20845 of 25 March 2025) · statute · 2025

Where it stands: In force since 26 March 2026 with Enforcement Decree and Rule made

Korea's Offshore Wind Special Act, promulgated on 25 March 2025 and in force a year later on 26 March 2026, replaces developer-led permit-hunting with government-led zoning: the state surveys and designates offshore wind promotion zones, runs a single integrated consent process, and tenders the zones, with transitional protection for projects already holding permits.

The problem

Korea has one of the best offshore wind resources in north-east Asia and almost none of it built, because until 2026 a developer had to assemble roughly thirty separate permits from ten or more agencies covering maritime spatial use, fisheries, military radar, environmental impact, port access and grid connection, each with its own timetable and veto. That produced a landscape of speculative electricity business licences covering large sea areas held by parties with no capacity to build, fishing-community opposition negotiated project by project, and lead times long enough that turbine pricing and financing assumptions expired before consent was granted. The 11th Basic Plan's renewables trajectory is not deliverable on that basis, and the government also wanted a domestic supply chain rather than a pure import programme.

What it does

The Special Act on the Promotion of Offshore Wind Power Deployment and Industry Development (Act No. 20845, promulgated 25 March 2025) came into force one year after promulgation, on 26 March 2026, with two exceptions written into its supplementary provisions: Article 33(2) took effect on the day of promulgation, and Article 33(1) takes effect three years after promulgation, in March 2028. The Act establishes a government-led framework in which the state conducts preliminary surveys of wind, seabed, environmental and fisheries conditions, designates offshore wind power deployment promotion zones, and selects developers for those zones through a competitive process, replacing the first-come permit race. It creates a committee-based integrated consent procedure so that the separate authorisations are deemed granted or are processed together, provides for compensation and benefit-sharing with fishing communities and coastal residents, and adds industrial-development measures aimed at building a Korean supply chain in turbines, foundations, cables and installation vessels. Supplementary Article 2 provides transitional treatment for operators already holding permits when the Act commenced, which is the provision that decides the fate of the existing speculative licence stock. The Enforcement Decree was made as Presidential Decree No. 36216 on 24 March 2026 and the Enforcement Rule as Ministerial Rule No. 32 on 25 March 2026, both in force on 26 March 2026. Competence sits with the Ministry of Climate, Energy and Environment; a consequential amendment by Act No. 21585 of 28 April 2026 took effect on 17 May 2026.

Market effect

The Act converts Korean offshore wind from a permitting lottery into a zonal auction market of the kind developers already price in Japan, Taiwan and Europe, and that is what unlocks institutional capital. For a developer the economics change in three ways: the state carries the survey and consent risk that previously consumed three to five years and tens of millions of dollars of at-risk spend; the competitive selection means the winning bid, not the permit queue, sets who builds; and the fisheries compensation framework converts an open-ended negotiation into a defined cost line. For holders of legacy electricity business licences over sea areas, supplementary Article 2 is the single most valuable or destructive provision in the statute, because it determines whether an existing permit survives into a designated zone or is superseded by the tender. For the supply chain, the industrial-development provisions create a domestic-content pull that favours Korean foundation fabricators, cable makers and port infrastructure, and that will sit uneasily with trade partners if it hardens into a formal local-content score. Grid connection remains the binding constraint: the zones are mostly off the south and west coasts, the load is in the north-west, and delivery depends on the backbone transmission programme.

Key numbers

Act and promulgation
Act No. 20845, promulgated 25 March 2025
Commencement
26 March 2026 (one year after promulgation); Article 33(2) from promulgation; Article 33(1) from March 2028
Subordinate legislation
Enforcement Decree Presidential Decree No. 36216 of 24 March 2026 and Enforcement Rule No. 32 of 25 March 2026, both in force 26 March 2026
Later amendment
Act No. 21585 of 28 April 2026, in force 17 May 2026
Consequential amendment, 18 September 2026
Act No. 21462 of 17 March 2026 (the Renewable Energy Act renaming): Articles 2(1), 5(2) and 18(1) and Supplementary Article 2(2) now cite the 재생에너지 개발ㆍ이용ㆍ보급 촉진법 by its new name. Cross-references only

Who gains and who pays

  • Offshore wind developers and their investors (gains): State-led surveys and integrated consent remove the largest source of pre-construction risk.
  • Holders of legacy electricity business licences over sea areas (mixed): Supplementary Article 2 transitional treatment decides whether existing permits survive the zonal regime.
  • Fishing communities and coastal residents (mixed): Gain a statutory compensation and benefit-sharing framework in exchange for losing project-by-project veto leverage.
  • Korean turbine, foundation, cable and installation-vessel suppliers (gains): Industrial-development measures channel demand into the domestic supply chain.
  • KEPCO and the transmission system (obligation): Must deliver connection and transfer capacity from southern and western zones to the load centres.

Implementation

Everything now depends on the zone pipeline. The ministry must commission and publish the preliminary surveys, designate promotion zones, publish the selection criteria and run the tenders, with the integrated consent committee standing up alongside. The Enforcement Decree and Rule set the survey scope, zone-designation procedure, developer qualification and the compensation mechanics. Article 33(1), deferred to March 2028, is the provision to watch because deferred commencement usually signals an obligation the industry needed time to prepare for. Legacy permit holders will test supplementary Article 2 in administrative litigation if their licences are displaced. Transmission is being delivered under a separate statute, the National Backbone Power Grid Expansion Special Act, so a zone can be designated and tendered well before the connection exists, and the gap between the two programmes is where delivery risk concentrates.

Concerns

  • Zone designation and the first tenders have to move quickly or the one-year commencement gap is wasted
  • Transitional treatment of legacy sea-area permits is likely to be litigated
  • Grid connection from southern and western zones to north-western load is not guaranteed on the same timetable
  • Domestic supply-chain measures risk trade friction if they operate as local-content requirements
  • Fisheries compensation is now statutory but the level is set administratively and can be contested

Dates to watch

  • 2027: First promotion zone designations and developer selection rounds under the Act
  • 2028-03: Commencement of Article 33(1), deferred three years from promulgation

Sources

Checked against sources on .

Special Act on Distributed Energy · in force 14 June 2024, curtailment in Jeju and Honam

South Korea · National Assembly (Special Act on the Promotion of Distributed Energy, Act No. 19437 of 13 June 2023) · statute · 2023

Where it stands: In force since 14 June 2024; amended again by Act No. 21941, in force 16 December 2026

Korea's Distributed Energy Act came into force on 14 June 2024 to break the pattern of building generation far from load and then curtailing it: it creates distributed energy special zones where local supply can be sold directly, an installation obligation on large new loads, and a framework for regional pricing, against a background of persistent renewable curtailment on Jeju and in the Honam region.

The problem

Korea built its renewables where land is cheap, in South Jeolla, North Jeolla and on Jeju, and its new load where industry is, around Seoul and in the semiconductor clusters, then connected the two with a transmission system whose reinforcement is repeatedly blocked by local opposition. The result since 2021 has been routine output curtailment of solar and wind on Jeju on mild, sunny, low-demand days, and curtailment spreading to the Honam region as solar capacity there outran transfer capacity to the capital area. At the same time the single national tariff gives a data centre no price reason to locate near surplus generation and a solar developer no reason to site near load. The Act's premise is that some of the transmission problem should be solved by moving demand and by letting supply be consumed locally rather than by building ever more lines.

What it does

The Special Act on the Promotion of Distributed Energy (Act No. 19437, promulgated 13 June 2023) came into force one year after promulgation, on 14 June 2024. It defines distributed energy to include renewables, fuel cells, combined heat and power, energy storage and small and medium nuclear reactors, for which a supplementary provision carves out special treatment under the nuclear safety legislation. It empowers the minister to designate distributed energy special zones in which a distributed energy business may sell directly to consumers inside the zone, bypassing the KEPCO single-buyer structure that the Electric Utility Act otherwise requires; it imposes an obligation on new developments and large new electricity users above thresholds set by decree to install distributed generation or storage; it provides for regionally differentiated electricity pricing so that areas with surplus generation can be charged differently from areas that import; and it requires a basic plan and implementation plans for distributed energy. The Act was amended by Act No. 21161 of 2 December 2025, in force 2 March 2026, with the revised Article 21(2) and (3) penalty-surcharge provisions taking effect on 2 June 2026; the Enforcement Decree was amended by Presidential Decree No. 36348 of 26 May 2026, in force 3 June 2026, and the Enforcement Rule by Ministerial Rule No. 24 of 3 March 2026. Competence sits with the Ministry of Climate, Energy and Environment following the October 2025 reorganisation.

Market effect

The Act is the first legal crack in Korea's single-buyer model outside the direct-PPA exemption. Inside a designated special zone a generator can contract with a local consumer at a negotiated price rather than selling into KPX at the system marginal price and watching KEPCO capture the retail margin, which changes the economics of industrial-site solar, fuel cells and behind-the-meter storage in exactly the regions where curtailment is worst. Regional pricing, once implemented, is a much larger lever: it would give a data centre operator a tariff reason to build in South Jeolla rather than Gyeonggi, and give a Honam solar developer a capture price that reflects local surplus instead of a national average. For existing renewable owners in Jeju and Honam the immediate value is different: curtailment risk is now a recognised policy problem with a statutory response, which matters when lenders price a project's P50 output. The installation obligation on large new loads shifts cost onto developers of logistics centres, fabs and data centres, who must now budget rooftop solar, fuel cells or storage into new sites. The counterweight is that special zones and regional pricing both erode KEPCO's revenue base at a time when it is still repairing its balance sheet, which is why implementation has been cautious.

Key numbers

Act and promulgation
Act No. 19437, promulgated 13 June 2023
Commencement
14 June 2024, one year after promulgation
2025 amendment
Act No. 21161 of 2 December 2025, in force 2 March 2026; Article 21(2)-(3) from 2 June 2026
Current text
Act No. 21941, promulgated 15 September 2026 as a partial amendment, in force 16 December 2026 — this supersedes the 2025 amendment as the operative version
Subordinate legislation
Enforcement Decree Presidential Decree No. 36348 of 26 May 2026 (in force 3 June 2026); Enforcement Rule No. 24 of 3 March 2026
Consequential amendment, 18 September 2026
Act No. 21467 of 17 March 2026 (the Hydrogen Economy Promotion and Hydrogen Safety Management Act (수소경제 육성 및 수소 안전관리에 관한 법률)): Article 2(2)(e) now defines a renewable energy business by reference to the renamed Renewable Energy Act, Article 2(2)(f) extends "fuel cells" to "fuel cells etc." under the Hydrogen Economy Act, and Article 4 cites both Acts. Definitions only; the 16 December 2026 amendment above remains the next substantive change

Who gains and who pays

  • Renewable generators in Jeju and the Honam region (gains): A statutory route to local offtake and a policy response to chronic curtailment.
  • Developers of large new loads (data centres, fabs, logistics) (obligation): Must install distributed generation or storage above the decree thresholds.
  • KEPCO (costs): Special zones and regional pricing erode the single-buyer margin and the uniform national tariff.
  • Fuel cell, storage and combined heat and power suppliers (gains): Explicitly within the statutory definition of distributed energy and eligible for zone participation.
  • Local governments hosting special zones (mixed): Gain investment and pricing powers but take responsibility for siting and local acceptance.

Implementation

The operative content arrives through the Enforcement Decree and Enforcement Rule, which set the thresholds for the installation obligation, the criteria and procedure for designating special zones, and the conditions under which a distributed energy business may supply directly. The minister designates zones on application, typically from a metropolitan or provincial government, with a business plan showing local supply, demand and grid effect; the zone then operates under a separate set of supply rules while KPX and KEPCO adjust settlement at the boundary. Regional pricing is the slowest element because it requires changes to the Electricity Market Operation Rules approved by the ministry after deliberation by the Electricity Regulatory Commission, and because any regionally differentiated tariff is politically contested. The 2025 amendment tightened enforcement, adding and reshaping penalty surcharges with a deferred commencement for those provisions. Watch the zone designations and the decree thresholds: they determine whether the Act is a structural change or a pilot.

Concerns

  • Curtailment in Jeju and Honam continues while special zones and regional pricing are phased in
  • Direct supply inside zones sits awkwardly against the Electric Utility Act single-buyer structure
  • Regional pricing is politically difficult because it breaks the uniform national tariff
  • The installation obligation raises capital cost for exactly the large loads Korea is trying to attract
  • Small and medium nuclear reactors are inside the statutory definition, which stretches the meaning of distributed energy

Dates to watch

  • 2027: Next distributed energy basic plan and any decision on regionally differentiated electricity pricing
  • 2026-12: First full compliance cycle under the amended penalty-surcharge provisions

Sources

Checked against sources on .

KEPCO tariffs and fuel-cost pass-through · industrial rates carry the repair of the balance sheet

South Korea · Korea Electric Power Corporation, with ministry approval after deliberation by the Electricity Regulatory Commission · decision · 2022

Where it stands: Regulated tariffs in force with quarterly fuel-cost adjustment subject to ministerial approval

Korea reintroduced a quarterly fuel-cost adjustment in 2021 and then suppressed it through the price shock, leaving KEPCO selling below cost and accumulating an enormous deficit; the repair since 2022 has come through repeated tariff increases loaded disproportionately onto industrial customers, with residential rates now at 120.0 to 307.3 won per kWh by tier.

The problem

KEPCO buys almost all of Korea's electricity from generators at a system marginal price driven by imported LNG and coal, and sells it at a regulated retail tariff set by the government. When the fuel-cost adjustment mechanism introduced for 2021 was suspended to protect consumers during the 2021-2022 price spike, the gap between purchase cost and sales price became a fiscal problem: KEPCO borrowed to fund the difference, its bond issuance crowded the domestic corporate bond market, and its credit standing became a sovereign-adjacent question. The political constraint was that residential tariffs are electorally sensitive while industrial tariffs are not, and the structural constraint was that any tariff that does not recover cost destroys the signal that would make efficiency, demand response and distributed energy worth anything.

What it does

The fuel-cost linked adjustment reintroduced for 2021 allows a quarterly change to the energy charge within caps, announced at quarter end, with the ministry able to freeze it on grounds of consumer-price stability. From 2022 the government approved a sequence of increases to the base energy charge and the climate and environment charge, concentrated on high-voltage industrial and general tariffs, with residential increases smaller and the low-usage tiers protected. Tariff changes are applied for by KEPCO, consulted with the Ministry of Economy and Finance, deliberated by the Electricity Regulatory Commission and approved by the energy ministry, which publishes a notice; since the October 2025 reorganisation that ministry is the Ministry of Climate, Energy and Environment. The current residential low-voltage schedule charges 120.0 won per kWh for the first tier, 214.6 won for the second and 307.3 won for the third, with monthly demand charges of 910, 1,600 and 7,300 won; the tier boundaries widen in summer to 300 and 450 kWh from 200 and 400 kWh in other seasons, and high-voltage residential customers pay 105.0, 174.0 and 242.3 won per kWh. Industrial (A) low-voltage customers with contract demand from 4 kW to under 300 kW pay a 5,550 won per kW demand charge and 107.7 won per kWh in summer, 85.9 in spring and autumn and 106.0 in winter; high-voltage industrial customers pay time-of-use energy charges that reach 146.5 won per kWh on summer on-peak under Industrial (A) II Option I.

Market effect

Tariffs are where Korean energy policy actually bites, because in a single-buyer market the retail price is the only signal most consumers see. Loading the repair onto industrial and high-voltage customers has three effects a trader or lender should model. First, it widens the gap between the regulated retail price and the price a large customer could obtain under a direct corporate PPA or inside a distributed energy special zone, which is the main commercial driver behind corporate renewable procurement in Korea. Second, it changes the value of demand response and storage: with summer on-peak industrial energy charges near 146.5 won per kWh against off-peak near 87.2, peak shaving has a clear payback where it barely did a few years ago. Third, it determines how fast KEPCO can fund the transmission build-out the 11th Basic Plan assumes, because network investment is recovered through the same tariff. On the generation side the fuel-cost adjustment matters less than it looks, since generators are paid the system marginal price by KPX regardless of what KEPCO recovers; the mismatch is absorbed entirely by KEPCO's balance sheet, which is why the utility's deficit is the standing systemic risk in Korean power and why any renewed freeze on tariffs is a credit event in slow motion.

Key numbers

Residential low-voltage energy charge
120.0 / 214.6 / 307.3 won per kWh by tier, with demand charges of 910 / 1,600 / 7,300 won a month — the schedule in force from 1 January 2025
Residential tier boundaries
300 and 450 kWh in summer (1 July to 31 August); 200 and 400 kWh in other seasons
Super-user rate
736.2 won per kWh on low-voltage consumption above 1,000 kWh a month in summer and winter — roughly 2.4 times the top ordinary tier
Industrial (A) I low voltage
5,550 won per kW demand charge; 107.7 (summer), 85.9 (spring and autumn), 106.0 (winter) won per kWh
Industrial peak spread
Industrial (A) II high-voltage A Option I: 146.5 won per kWh at summer peak against 87.2 off-peak, a spread of 59.3 won that is the signal behind industrial load shifting
Fuel-cost adjustment caps
Capped at ±5 won per kWh in total and ±3 won per kWh against the previous quarter; a computed movement within ±1 won is not applied at all, which is what keeps the quarterly mechanism mostly dormant
What the published rates exclude
These are energy and demand charges only. A bill also carries the climate-environment charge and the quarterly fuel-cost adjustment, so headline comparisons that omit them understate the delivered price by several won per kWh

Who gains and who pays

  • Industrial and high-voltage commercial customers (costs): Carried most of the increases; summer on-peak energy charges reach about 146.5 won per kWh.
  • KEPCO (mixed): Tariff increases repair the deficit but the fuel-cost mechanism can still be frozen by the ministry.
  • Generators selling into KPX (gains): Paid the system marginal price irrespective of KEPCO's retail recovery.
  • Demand response aggregators and storage developers (gains): Wide peak to off-peak spreads make load shifting economic.
  • Residential consumers (mixed): Protected low-usage tiers at 120.0 won per kWh but exposed to a steep third tier at 307.3 won.

Implementation

KEPCO applies, the Ministry of Economy and Finance is consulted, the Electricity Regulatory Commission deliberates and the energy ministry approves and publishes a notice; the quarterly fuel-cost adjustment is announced at the end of each quarter and applies from the first day of the next. In practice the decision is political and arrives without notice, which is why industrial buyers hedge by contracting outside the regulated tariff where they can. Cost recovery for the transmission programme under the National Backbone Power Grid Expansion Special Act and for the renewable obligation flows through the same bill, so each new policy cost eventually shows up as a tariff component. The medium-term question is whether the government restores the fuel-cost mechanism to something close to automatic, which would transfer commodity risk from KEPCO to consumers, or keeps discretionary control and therefore keeps the deficit risk on the utility.

Concerns

  • The fuel-cost adjustment can be frozen at ministerial discretion, so the mechanism does not reliably transfer commodity risk
  • KEPCO's accumulated deficit remains a systemic credit exposure for the Korean bond market
  • Industrial customers are carrying a disproportionate share of cost recovery
  • Below-cost pricing during the shock suppressed the efficiency and demand-response signals
  • Every new policy cost, from grid build-out to renewable obligations, lands on the same regulated tariff

Dates to watch

  • 2026-12: Quarter-end fuel-cost adjustment announcement for the following quarter
  • 2027: Expected review of cost recovery for the backbone grid programme within the retail tariff

Sources

Checked against sources on .