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Japan: 6 energy policy briefs

The energy policies moving Japan’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.

7th Strategic Energy Plan · FY2040 mix of 40-50% renewables, about 20% nuclear, 30-40% thermal

Japan · Cabinet of Japan (decision of 18 February 2025) on the recommendation of METI's Advisory Committee for Natural Resources and Energy · plan · 2025

Where it stands: Cabinet-decided and being delivered through auctions, grid plans and reactor reviews

The Cabinet adopted the 7th Strategic Energy Plan on 18 February 2025 alongside the GX2040 Vision and the Plan for Global Warming Countermeasures, targeting a 73 percent greenhouse-gas cut by FY2040 against FY2013 and a FY2040 power mix of roughly 40 to 50 percent renewables, 20 percent nuclear and 30 to 40 percent thermal, with electricity generation rising to 1.1 to 1.2 trillion kWh.

The problem

The 6th plan of October 2021 was written before the energy price shock, before generative AI and semiconductor fabs began to reverse two decades of falling Japanese electricity demand, and before the 2023 legislation that moved nuclear operating-period decisions from the Nuclear Regulation Authority to METI. Japan's energy self-sufficiency was 12.6 percent in FY2022 against 6.5 percent in FY2013, still among the lowest in the OECD, and the FY2022 mix was 21.8 percent renewables, 5.6 percent nuclear and 72.6 percent thermal. Meanwhile the government had to set a FY2040 emissions target under the Paris framework and give investors a capacity-mix number that the capacity and long-term decarbonisation auctions, the grid plan and the GX bond programme could all be calibrated against.

What it does

The plan, a Cabinet decision under the Basic Act on Energy Policy, drops the previous language about reducing dependence on nuclear power and instead treats nuclear and renewables together as decarbonised sources to be maximised. Its FY2040 outlook puts renewables at approximately 40 to 50 percent of generation (solar 23 to 29 percent, wind 4 to 8 percent, hydro 8 to 10 percent, geothermal 1 to 2 percent, biomass 5 to 6 percent), nuclear at approximately 20 percent and thermal at approximately 30 to 40 percent, against FY2022 actuals of 21.8, 5.6 and 72.6 percent. Electricity generated rises from 1.00 trillion kWh in FY2022 to approximately 1.1 to 1.2 trillion kWh in FY2040, with transport electricity demand quadrupling from 0.02 to 0.04-0.10 trillion kWh, while primary energy supply falls from 470 to about 420-440 million kilolitres oil equivalent. Energy-related CO2 falls from 960 MtCO2 in FY2022 to about 360-370 MtCO2, roughly 70 percent below FY2013, consistent with the 73 percent whole-economy target. On nuclear, the plan builds on the GX decarbonisation power source package of 2023 (Act No. 44 of 7 June 2023), which moved the operating-period rules into the Electricity Business Act under METI, allows periods when a reactor was suspended for regulatory or judicial reasons to be excluded from the sixty-year count, and preserves the Nuclear Regulation Authority's independent safety veto through a new long-term facility management review. The plan supports restarting the idled fleet, replacing reactors at sites where units are being decommissioned, and developing next-generation light-water and advanced reactors.

Market effect

The plan is not binding, but every binding instrument is calibrated to it. OCCTO's demand and supply scenarios, the interconnector master plan, the capacity market demand curve and the long-term decarbonisation auction solicitation volumes all trace back to the FY2040 numbers, which is why a 1,381 MW twenty-year contract for new nuclear at Ohma could clear in the FY2025 long-term auction: the plan gives a nuclear project a policy basis that the wholesale market alone does not. A 20 percent nuclear share in FY2040 implies roughly 220 to 240 TWh of nuclear output, which cannot be met by restarts alone and therefore implies both life extension beyond sixty years and new build, each with a decade-long lead time; that is the single largest uncertainty in Japanese long-dated power curves. On the renewables side, 40 to 50 percent with solar at 23 to 29 percent of generation means far more curtailment and far more value for storage, flexible demand and inter-regional transfer than today, which is what the FIP design, the battery share of long-term auction awards and the HVDC plan are meant to absorb. For thermal, a 30 to 40 percent share in FY2040 with GX carbon pricing arriving in FY2028 and FY2033 defines a narrow window in which new LNG is financeable, and explains the decarbonisation conditions attached to the LNG tranche of the long-term auction.

Key numbers

FY2040 power mix
Renewables approx. 40-50%, nuclear approx. 20%, thermal approx. 30-40%
FY2040 electricity generated
Approx. 1.1-1.2 trillion kWh (FY2022 actual 1.00 trillion kWh)
FY2040 energy-related CO2
Approx. 360-370 MtCO2, about 70% below FY2013; whole-economy target -73%
Cabinet decision
18 February 2025, with the GX2040 Vision and the Plan for Global Warming Countermeasures
Energy self-sufficiency
12.6% in FY2022, up from 6.5% in FY2013
GX package commencement
The GX decarbonisation power source act and the amended Reactor Regulation Act both came into force on 6 June 2025; advance applications had been possible since 1 October 2023
How the operating period actually works
The 40-year term and the 60-year maximum both survive. What changed is the counting: periods when a reactor was shut for reasons outside the operator’s control are excluded from the 60 years, so calendar age can pass 60 while regulated operating years do not. Extension needs the METI Minister’s approval on supply-security and GX grounds
Long-term facility management plan
Operating past 30 years requires a technical degradation assessment and a management plan approved by the Nuclear Regulation Authority, renewed at intervals of no more than 10 years
NRA approval test
The degradation prediction method must be sound, the plant must be able to meet regulatory standards for the coming period of up to 10 years with degradation allowed for, and the mitigation measures must not impede disaster prevention

Who gains and who pays

  • Nuclear operators (Kansai, Kyushu, TEPCO, J-Power and others) (gains): Policy backing for restarts, life extension beyond sixty years and replacement units; safety investment is eligible for twenty-year auction contracts.
  • Solar, wind and storage developers (gains): A 40 to 50 percent renewable share in FY2040 anchors procurement volumes and grid planning.
  • Coal and oil generators (costs): Thermal falls to 30 to 40 percent and unabated coal is squeezed by the GX carbon price timetable.
  • Large electricity consumers, data centres and semiconductor fabs (mixed): The plan assumes demand growth back above 1.1 trillion kWh and directs siting toward decarbonised supply.
  • Host communities and prefectural governors (obligation): Restart and replacement still require local consent, which remains the binding constraint on the nuclear number.

Implementation

The plan is guidance; it becomes binding through METI ordinances, OCCTO rules, auction volumes and budget. The Advisory Committee for Natural Resources and Energy began work in May 2024, published a draft on 17 December 2024, ran the public comment procedure and the Cabinet decided on 18 February 2025; the English text followed later on the Agency for Natural Resources and Energy site. Delivery now depends on three separate machines: the Nuclear Regulation Authority's safety reviews and the long-term facility management approvals under the 2023 package, which control how many reactors actually run; OCCTO's grid plan and the capacity and long-term auctions, which control how much decarbonised capacity is contracted; and prefectural consent, which has repeatedly been the gate that slips. Plans are reviewed roughly every three years, so the 8th plan is expected around 2027-2028 and will reveal whether the nuclear and renewable trajectories are holding.

Concerns

  • A 20 percent nuclear share in FY2040 requires restarts, life extension and new build at once
  • Local and gubernatorial consent remains the practical veto on restarts regardless of national policy
  • Solar at 23 to 29 percent of generation implies curtailment levels that need storage and HVDC to be built on time
  • Demand growth from data centres and fabs is assumed rather than contracted
  • The plan is a Cabinet decision, not a statute, and can be revised by a later government

Dates to watch

  • 2027: Expected start of deliberations on the 8th Strategic Energy Plan
  • 2030: Checkpoint against the FY2030 46 percent emissions reduction commitment that the FY2040 path builds on

Sources

Checked against sources on .

GX Promotion Act · mandatory emissions trading from FY2026, fossil-fuel levy from FY2028, power-sector auctioning from FY2033

Japan · National Diet (Act No. 32 of 19 May 2023, as amended by Act No. 52 of 4 June 2025) · statute · 2023

Where it stands: In force; mandatory emissions trading applies from the fiscal year beginning 1 April 2026

The GX Promotion Act finances Japan's transition with ¥20 trillion of GX transition bonds and repays them with carbon pricing on a legislated timetable: a mandatory emissions trading scheme for companies emitting 100,000 tonnes of CO2 a year or more from FY2026, a levy on fossil-fuel importers and producers from FY2028, and paid allocation to power generators from FY2033.

The problem

Japan committed to a 46 percent emissions cut by FY2030 and net zero by 2050 without an economy-wide carbon price, relying instead on the fossil-fuel tax for climate change mitigation at about ¥289 per tonne, voluntary industry action plans and subsidies. Industry argued that a carbon price imposed before the technologies existed would export production rather than cut emissions; the Treasury argued that no credible transition could be financed by subsidy alone. The GX Promotion Act resolved this with a sequencing deal: the state borrows first and prices carbon later, with each step written into primary legislation so that investors can plan against it. The voluntary GX League, which ran the first, non-binding phase of GX-ETS from FY2023, produced pledges but no enforceable cap, and ceased operations at the end of FY2025.

What it does

Act No. 32 of 19 May 2023 established the GX transition strategy, authorised the issue of GX economy transition bonds (about ¥20 trillion over ten years), created the GX Promotion Organization to administer support and carbon pricing, and set two revenue streams. Chapter 4 Section 1, Article 11, directs the Minister of Economy, Trade and Industry to collect a fossil-fuel levy from crude oil, petroleum product and gaseous hydrocarbon extractors and importers from FY2028, charged per tonne of CO2 embodied, using coefficients fixed by Cabinet Order. Chapter 4 Section 2, Article 27, provides that from FY2033 the Minister shall allocate emission allowances to specified operators, defined in Article 2(5) as the larger-emitting power generation businesses designated by Cabinet Order, for consideration or free, with the paid element collected as a specified operator contribution. The amendment made by Act No. 52 of 4 June 2025, in force on 1 April 2026, inserted Chapter 5 creating the GX growth investment operator allowance, the legal architecture of a mandatory emissions trading scheme: implementation guidelines set by the Minister, emission targets and verified actual emissions, an allowance registry, an allowance trading market with a reference ceiling price and an escape valve, registered verification bodies, and criminal penalties. Article 2 of the Enforcement Order (Cabinet Order No. 379 of 27 December 2023) sets the notification threshold at an annual average of 100,000 tonnes of CO2.

Market effect

For power generators the timetable, not the current price, is what matters. Free allocation until FY2033 means coal and gas plant keep their present cost stack through the late 2020s, but the 2033 auction date is close enough to sit inside the financing life of any new thermal asset, which is why the long-term decarbonisation auction requires LNG-only winners to commit to decarbonising by 2050 and why ammonia and hydrogen co-firing retrofits cleared at 100 percent in the FY2025 round. From FY2026 the mandatory scheme covers companies whose three-year average emissions reach 100,000 tonnes, which captures the large steel, cement, chemicals, paper, refining and power emitters and roughly half of Japan's industrial emissions; those companies now need verified monitoring, an allowance position and a trading strategy rather than a voluntary pledge. The FY2028 levy lands upstream on importers and will pass into gas, coal and oil prices, adding a visible fuel cost to marginal generation and therefore to JEPX clearing prices. Allowance liquidity is the open question: the Act provides for a trading market with a reference ceiling price and lets the Cabinet Order relieve compliance when the average traded price exceeds that ceiling for a defined period, or when sell-side volume is very thin, which caps but does not floor the carbon cost. Corporate buyers of Japanese carbon credits, J-Credits and eligible international credits gain a regulated demand source for the first time.

Key numbers

Mandatory ETS threshold
Annual average emissions of 100,000 tonnes CO2 (Enforcement Order Art. 2, Cabinet Order No. 379 of 2023)
Mandatory ETS start
FY2026; Chapter 5 in force 1 April 2026 under Act No. 52 of 4 June 2025
Fossil-fuel levy
Collected from FY2028 (Reiwa 10) under Article 11
Power-sector paid allocation
From FY2033 (Reiwa 15) under Article 27
Transition finance
About ¥20 trillion of GX economy transition bonds over ten years

Who gains and who pays

  • Companies emitting 100,000 tonnes CO2 a year or more (obligation): Must notify METI, set targets, report verified emissions and surrender allowances from FY2026.
  • Fossil-fuel importers, refiners and gas producers (obligation): Pay the levy per tonne of embodied CO2 from FY2028 and pass it into fuel prices.
  • Large power generators (specified operators) (costs): Paid allocation of allowances from FY2033 under Article 27, collected as the specified operator contribution.
  • Low-carbon technology developers, verifiers and credit suppliers (gains): GX transition bond support of about ¥20 trillion plus regulated demand for allowances and credits.
  • Electricity and industrial consumers (costs): Levy and allowance costs pass into fuel, power and product prices from the late 2020s.

Implementation

METI issues the implementation guidelines that fix how emission targets are set and how actual emissions are calculated, together with ministerial ordinances on verification, the registry and the trading market; the joint ministerial order of 30 March 2026 designates the priority investment sectors referred to in Article 32(2)(4). The GX Promotion Organization administers the levy, the registry and the support programmes and is supervised by METI, with fee schedules in the Enforcement Order that scale by emitter size. Verification is performed by registered confirmation bodies licensed under the December 2025 ministerial ordinance, with a five-year registration term. The first mandatory compliance year runs from April 2026, so the first verified reports and surrender obligations fall due in the following fiscal year, and the Cabinet Order coefficients for the FY2028 levy and the FY2033 allocation rules remain to be set. Watch the implementation guidelines and the allowance market rules for the reference ceiling price, which determines how much carbon cost actually reaches Japanese industry.

Concerns

  • The FY2033 start for power-sector auctioning leaves generation effectively unpriced for another seven years
  • The reference ceiling price and escape valve could cap the carbon signal well below abatement cost
  • Allowance market liquidity is untested after a voluntary phase that produced little trading
  • Carbon leakage and competitiveness for steel, chemicals and cement without a border measure
  • The ¥20 trillion bond programme must be repaid from levy and auction revenue whose level is not yet fixed

Dates to watch

  • 2027: First verified emissions reports and allowance surrender for the FY2026 compliance year
  • 2028-04: Fossil-fuel levy begins on importers, refiners and gas producers
  • 2033-04: Paid allocation of allowances to large power generators begins

Sources

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OCCTO wide-area grid master plan · about ¥7 trillion and the Hokkaido-Honshu HVDC

Japan · Organization for Cross-regional Coordination of Transmission Operators (OCCTO), Long-term Policy for the Wide-Area Grid · plan · 2023

Where it stands: Master plan adopted 2023; the Hokkaido-Honshu HVDC is in OCCTO's planning and evaluation process

OCCTO published Japan's first wide-area grid master plan on 29 March 2023, finding that about ¥7 trillion of network investment toward 2050 would still deliver net benefits, and identifying a new HVDC route from Hokkaido through Tohoku to Tokyo, reinforcement of the Kanmon link and more frequency-converter capacity; the 2 GW Hokkaido-Honshu Sea of Japan HVDC is now in the OCCTO planning process.

The problem

Japan's grid was built as ten regional systems joined by thin interconnectors and split between 50 Hz and 60 Hz, with only a few gigawatts of frequency-converter capacity between east and west. The renewable resource is in the wrong places: the best onshore and offshore wind is in Hokkaido and northern Tohoku, while demand is in Tokyo, Nagoya and Osaka. Without new transfer capacity, the FY2040 target of 40 to 50 percent renewables would be met by building solar and wind that is then curtailed, or not built at all, and the January 2021 and March 2022 supply alerts showed that thin interconnection is also a reliability problem. Project-by-project reinforcement driven by individual connection applications could not deliver a coherent answer, so the 2020 Electricity Business Act amendment gave OCCTO the duty to write a long-term wide-area policy and a cost-recovery route for it.

What it does

The master plan sets out the target shape of the wide-area grid under three demand-siting scenarios to 2050, all assuming about 1.2 trillion kWh of demand, roughly 260 GW of solar, 41 GW of onshore wind and 45 GW of offshore wind, and existing or under-construction nuclear running for sixty years. Cost-benefit analysis across the scenarios found that about ¥7 trillion of network investment could still be exceeded by the benefits, measured as avoided fuel and capital cost and reduced renewable curtailment. The reinforcements common to every scenario are a new HVDC route in the eastern region linking Hokkaido, Tohoku and Tokyo, reinforcement of the Kanmon interconnector between Chugoku and Kyushu, reinforcement within the central region and more east-west frequency-converter capacity; HVDC was selected over additional AC circuits on economic grounds, and the plan flags that a 2 GW HVDC injection into Hokkaido's internal grid itself requires internal reinforcement and measures against HVDC trip risk. OCCTO opened planning processes in July 2022 for the eastern region and the central-western region. For the Hokkaido-Honshu Sea of Japan route, OCCTO decided the basic requirements and the scope of beneficiaries on 3 April 2024, consulted on the solicitation guidelines through 2024, opened the call for implementation plans and a project entity, received expressions of interest from two parties by December 2024, and has been working through implementation-plan review and a confidential preliminary evaluation in the Planning Evaluation and Verification Subcommittee, most recently on 15 September 2026.

Market effect

The master plan converts curtailment risk into a dated investment programme, and it is the reason an offshore wind or storage project in Hokkaido can be underwritten at all. Until the HVDC is built, northern renewable output is trapped: Hokkaido and Tohoku already curtail on light-load spring days, and every additional gigawatt of wind there without transfer capacity lowers the capture price for the whole regional fleet. That is also why the FY2029 capacity auction cleared at ¥14,972/kW in Hokkaido and ¥15,111/kW in Tohoku and Tokyo against ¥12,388/kW in the central and western areas: the capacity price is separating along exactly the constraint the plan is meant to relieve. On the cost side, roughly ¥7 trillion has to be recovered from network users, which runs through the wheeling revenue caps that the Electricity and Gas Market Surveillance Commission reviews on five-year periods from FY2023, and through the generator-side grid charge introduced under the 2020 Electricity Business Act amendment, which for the first time makes generators as well as consumers pay for the network. For developers the practical consequence is that connection economics now depend on the master plan's sequencing: a project inside a planned reinforcement corridor can be financed against a dated in-service assumption, while one outside it faces Japanese-style connect-and-manage curtailment with no end date.

Key numbers

Master plan investment
About ¥7 trillion of wide-area network investment toward 2050, with benefits assessed as exceeding it
Publication date
29 March 2023
Hokkaido-Honshu HVDC
2 GW Sea of Japan route; basic requirements and beneficiary scope decided 3 April 2024
2050 scenario assumptions
About 1.2 trillion kWh demand, 260 GW solar, 41 GW onshore wind, 45 GW offshore wind
Capacity price gap driven by the constraint
FY2029 auction: ¥15,111/kW Tohoku and Tokyo versus ¥12,388/kW central and western areas
Generator-side grid charge start
In force from April 2024, so generators now pay toward the network they inject into rather than the cost falling entirely on demand
Charge structure
A fixed kW charge and a volumetric kWh charge, weighted 1:1 for the time being
First regulatory period
FY2024 to FY2027, the same window as the revenue-cap period; unit rates are in principle held constant across it and reviewed every five years thereafter
Two locational discounts
Discount A reflects a plant’s effect on the backbone grid and Discount B applies to distribution-connected plant by its effect on the extra-high-voltage system; both reduce the kW charge, which is what makes the charge locational rather than flat
How much the discounts matter
In the regulator’s own worked example the kW charge falls from ¥87.01/kW gross to ¥7.16/kW after Discount A of ¥30.86 and Discount B of ¥48.99 — the discounts are the charge, not a rounding adjustment. The same example uses ¥0.28/kWh for the volumetric part

Who gains and who pays

  • Offshore and onshore wind developers in Hokkaido and Tohoku (gains): HVDC transfer capacity is the difference between a bankable capture price and chronic curtailment.
  • The ten general transmission and distribution utilities (mixed): Build and operate the reinforcement, recovering cost through revenue caps reviewed by the EGC.
  • Generators connected to the grid (costs): Now pay a generator-side grid charge alongside consumer-funded wheeling revenue.
  • Electricity consumers (costs): The bulk of an investment programme of roughly ¥7 trillion is recovered through network charges.
  • HVDC, subsea cable and converter suppliers (gains): Multi-gigawatt converter and long-distance subsea cable orders with no domestic precedent at this scale.

Implementation

The master plan is a policy document; each reinforcement becomes real through OCCTO's wide-area grid development plan process, which fixes the basic requirements, the range of beneficiaries and the cost allocation, then runs a solicitation for the implementation plan and the entity that will build it, then a preliminary evaluation before the plan is settled and METI approves. For the Hokkaido-Honshu Sea of Japan route that process has been running since 2022: the Wide-Area Grid Development Committee took the route, cable-protection and converter decisions through 2023 and 2024, the beneficiary scope was decided in April 2024, two parties responded to the call for a project entity by December 2024, and the Planning Evaluation and Verification Subcommittee has been conducting the preliminary evaluation in closed session through 2026, with the committee reviewing the implementation plan in June 2026. Financing comes partly from the wide-area grid development cost pool funded through network charges and partly from GX transition bond support. Watch the OCCTO committee calendar: the decision that fixes the implementation plan and the project entity is the gate that turns the 2 GW link into a construction schedule.

Concerns

  • No Japanese precedent for a subsea HVDC link of this scale, so cost and schedule risk are high
  • A 2 GW HVDC injection into Hokkaido requires internal reinforcement and protection against converter trips
  • About ¥7 trillion must be recovered from network users without breaking affordability
  • Preliminary evaluation and project-entity selection have been conducted largely in closed session
  • Renewable build in the north is racing ahead of the transfer capacity that would make it valuable

Dates to watch

  • 2027: Expected conclusion of the preliminary evaluation and settlement of the Hokkaido-Honshu HVDC development plan
  • 2028: Next five-year wheeling revenue-cap reset, which sets how the reinforcement programme is funded

Sources

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FIT to FIP transition · feed-in premium live from 1 April 2022

Japan · METI Agency for Natural Resources and Energy under the Act on Special Measures Concerning Procurement of Electricity from Renewable Energy Sources (Act No. 108 of 2011, amended by Act No. 49 of 12 June 2020) · regulation · 2022

Where it stands: Feed-in premium operating since 1 April 2022, with annual base-price decisions

From 1 April 2022 Japan replaced the fixed feed-in tariff with a feed-in premium for larger renewable projects: generators sell into JEPX or to an offtaker and receive a supply-promotion subsidy equal to the gap between a base price and a reference market price, which moves merchant price risk, balancing responsibility and shape risk onto developers for the first time.

The problem

The 2012 feed-in tariff worked too well in one direction and not at all in another. It installed tens of gigawatts of solar at prices that started at ¥40/kWh, loaded the cost onto a surcharge every consumer pays, and produced a fleet with no incentive to respond to price or to system need, because a fixed tariff pays the same at noon in May in Kyushu, when the system is curtailing, as at 6pm in January. Meanwhile the levy became one of the largest single items on a Japanese electricity bill. METI concluded that mature technologies had to be exposed to wholesale prices so that storage, shifted output and corporate offtake became rational, while genuinely immature technologies, small rooftop solar and community projects kept a simpler support route.

What it does

Act No. 49 of 12 June 2020 amended the 2011 renewable special-measures act to create the feed-in premium: instead of a fixed purchase price, a certified FIP project sells its output on the market and receives a supply-promotion grant (kyokyu sokushin kofukin) calculated as the base price (kijun kakaku) minus a reference price derived from actual market prices over a set period, multiplied by the metered output, with a balancing-cost allowance. The base price is decided by the Minister each March for the following fiscal year on the recommendation of the Procurement Price Calculation Committee, on the same annual cycle as the remaining FIT categories. FIP went live on 1 April 2022. Eligibility was phased by size and technology so that the largest solar and wind projects moved first and smaller ones followed in later fiscal years, with rooftop and small self-consumption projects kept on FIT; offshore wind awarded through the 2018 marine renewable energy act runs its own auction with a FIT or FIP contract attached. The same 2020 amendment created the decommissioning reserve for solar, tightened certification against long-dormant projects, and gave OCCTO a role in the grid-reinforcement cost pool for renewables. A further amendment by Act No. 44 of 7 June 2023, part of the GX decarbonisation package, added measures on project discipline and local consent.

Market effect

FIP turns a renewable project from a bond into a merchant asset with a floor. Because revenue now depends on when output lands, a Kyushu solar farm that produces into a curtailed, near-zero-price spring afternoon earns the premium but little market revenue, which is precisely the signal that makes co-located batteries, load shifting and long-dated corporate PPAs bankable. It also created a new intermediation business: aggregators that take balancing responsibility, forecast output and route power into JEPX, bilateral offtake or the non-fossil value trading market, where the certificate is sold separately from the energy. Lenders responded by shortening tenors, demanding hedges and pricing basis risk, so the cost of capital for a FIP project sits above the old FIT equivalent; the offset is that a FIP asset can capture upside when spot prices spike, as they did in the winters of 2021 and 2022. For the system, the transition is the precondition for the 7th Strategic Energy Plan's target of renewables at roughly 40 to 50 percent of generation by FY2040, because a fleet that responds to price is far cheaper to integrate than one that does not. For consumers, the renewable levy remains, but the premium is smaller than the old tariff gap whenever market prices are high, which is why the surcharge fell in high-price years.

Key numbers

FIP start
1 April 2022
Enabling statute
Act No. 108 of 2011 as amended by Act No. 49 of 12 June 2020
Premium formula
Base price minus reference market price, plus a balancing-cost allowance, paid per kWh delivered
Price-setting cycle
The Minister sets prices before each fiscal year on the Procurement Price Calculation Committee’s opinion; the FY2026 set was announced 19 March 2026
Auction threshold
FY2026 auctions cover FIP-eligible solar of 250 kW and above, with rooftop exempt; four rounds, ceiling ¥9.6/kWh in every round
FY2026 solar prices
Ground-mounted 10-50 kW ¥9.9/kWh; ground-mounted 50 kW and above outside the auction ¥9.6/kWh
Rooftop and residential instead get front-loaded support
An initial-investment scheme rather than a flat price: residential ¥24/kWh for years 1-4 then ¥8.3 for years 5-10; commercial rooftop ¥19/kWh for years 1-5 then ¥8.3 for years 6-20
Ground-mounted solar leaves the scheme
From FY2027 commercial ground-mounted solar is outside FIT and FIP altogether, auction category included. Projects certified by FY2026, and FY2026 auction winners, may still move to FIP
FY2026 wind
Onshore under 50 kW ¥14/kWh (¥13.7 in FY2027); onshore 50 kW and above by auction, one round, ceiling ¥14/kWh, with an extra round if bids exceed 1.1 GW; onshore replacement ¥13/kWh; floating offshore ¥36/kWh; bottom-fixed offshore by auction with the ceiling withheld in advance
FY2026 renewable surcharge
¥4.18/kWh, applied from the May 2026 meter reading to the April 2027 reading — ¥1,672 a month, ¥20,064 a year, for METI’s 400 kWh model household
What the surcharge funds
FY2026 assumptions: ¥4.8507 trillion of purchase cost against ¥1.6495 trillion of avoidable cost, spread over 766.5 billion kWh of billed sales

Who gains and who pays

  • Utility-scale solar and wind developers (mixed): Keep a base-price floor but take market, shape and balancing risk; need hedges or PPAs to finance.
  • Aggregators and power traders (gains): New business taking balancing responsibility and routing FIP output into JEPX and corporate offtake.
  • Storage developers (gains): Price exposure makes co-located and standalone batteries economic where a fixed tariff did not.
  • Small rooftop and community projects (gains): Retained the simpler FIT route below the size thresholds.
  • Electricity consumers (costs): Continue to pay the renewable levy, although the premium shrinks when market prices are high.

Implementation

Each March METI publishes the coming fiscal year's FIT purchase prices, FIP base prices, reference-price method and the capacity thresholds that decide which projects must take FIP rather than FIT, after a public comment round on e-Gov. Certification and the grant flow through the cost-allocation body established under the act, and the renewable surcharge that funds it is announced annually with the new prices. Projects that certified under FIT before the transition generally keep their original terms for the remainder of the twenty-year procurement period, so the FIT and FIP fleets will run in parallel into the 2030s, and the expiry of the first FIT cohorts is already producing post-FIT volumes that flow into retail and corporate PPA markets. Offshore wind rounds under the 2018 marine renewable energy act and the long-term decarbonisation auction are the two alternative routes a large renewable project can take instead of FIP, and developers must choose one.

Concerns

  • Financing costs rose once projects had to absorb shape and balancing risk
  • Curtailment in Kyushu, Tohoku and Hokkaido erodes market revenue exactly when output is highest
  • The reference-price method rewards projects that can shift output, which disadvantages fixed-tilt solar
  • Annual base prices are reset each March, so the long-run revenue path is not contractually fixed
  • The parallel FIT and FIP fleets complicate portfolio management and post-FIT offtake for retailers

Dates to watch

  • 2027-03: METI decision on FY2027 FIT purchase prices, FIP base prices and the renewable surcharge
  • 2027-04: Start of the FY2027 support year and any new capacity thresholds for compulsory FIP

Sources

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Capacity market and long-term decarbonisation auction · ¥14,137/kW in 2020, 20-year contracts since 2024

Japan · Organization for Cross-regional Coordination of Transmission Operators (OCCTO) business rules, approved by METI · rule · 2020

Where it stands: Operating: capacity delivered since FY2024, long-term contracts awarded in four rounds

OCCTO's capacity market held its first main auction in July 2020 for delivery in FY2024, clearing 167.7 GW at the ¥14,137/kW cap; the FY2029 auction cleared 166.1 GW for ¥2.21 trillion at area prices of ¥12,388 to ¥15,112/kW. The long-term decarbonisation auction bolted on 20-year fixed-cost contracts for new low-carbon plant, batteries and LNG.

The problem

After liberalisation, Japanese generators earned only energy and non-fossil value, both of which are volatile and neither of which pays for keeping mothballed thermal units available or for financing new capital. Reserve margins tightened after 2011, the January 2021 supply crunch pushed JEPX spot prices to the cap for weeks, and retailers had no hedged way to meet the supply-capability obligation the Electricity Business Act places on them. At the same time Japan needed to build decarbonised capacity whose revenue would come mostly from a wholesale market that the same decarbonisation was making less remunerative. One instrument could not do both jobs, so OCCTO built two: a four-year-ahead capacity auction for availability, and a long-term auction for investment.

What it does

The main auction procures nationwide capacity four years ahead of the delivery year, with a national demand curve, area prices where interconnection binds, and a net cost of new entry that produced a ¥14,137/kW cap in the first round. The first main auction was held in July 2020 for delivery year FY2024 and cleared 167,691,648 kW at ¥14,137/kW in every area, for ¥1,598.7 billion after transitional deductions. The FY2029 auction, bid in October 2025 with results published on 20 January 2026 and corrected on 23 January, cleared 166,079,863 kW for ¥2,209.4 billion, with area prices of ¥14,972/kW in Hokkaido, ¥15,111/kW in Tohoku and Tokyo, ¥15,112/kW in Kyushu and ¥12,388/kW across the central and western areas. The long-term decarbonisation power source auction, a multi-price tender inside the same market, awards roughly twenty years of fixed-cost capacity revenue to new or repowered non-emitting plant, batteries, pumped storage, long-duration storage, nuclear safety investment, decarbonisation retrofits of existing thermal, and new LNG-only plant committed to decarbonise by 2050, with about 90 percent of other-market revenue clawed back. The first round (bid year FY2023, results 26 April 2024) cleared 4,010 MW of decarbonised capacity for ¥233.6 billion a year against a 4,000 MW target and 5,756 MW of LNG for ¥176.6 billion. The FY2025 round, published on 13 May 2026, cleared 4,261 MW of decarbonised capacity for ¥474.8 billion a year against a 5,000 MW target, plus 3,038 MW of LNG for ¥144.4 billion, and included 1,381,275 kW of new nuclear at J-Power's Ohma station and 557,848 kW of safety investment at existing reactors.

Market effect

The capacity payment is now a large, predictable revenue line for every thermal, hydro and nuclear unit in Japan and a large, predictable cost line for every retailer, collected as the capacity contribution (yoryo kyoshutsukin) alongside wheeling charges. Between the FY2024 and FY2029 auctions the national bill rose by about 38 percent, from ¥1.60 trillion to ¥2.21 trillion, on essentially the same cleared volume, which is a straight transfer from retail margins to generators and a reason retail switching offers narrowed. Area prices have separated: the FY2029 result put Hokkaido, Tohoku, Tokyo and Kyushu ¥2,600 to ¥2,700/kW above the central and western areas, a locational signal that now sits alongside the interconnector plan. The long-term auction is the more consequential instrument for developers, because a twenty-year fixed-cost contract is what lets a battery, a pumped-storage refurbishment or a new reactor reach financial close in a market where spot prices are expected to fall as renewables grow. Clearing rates tell the story of competition: in the FY2025 round pumped storage cleared 55 percent of what it bid and batteries 46 percent, while ammonia co-firing retrofits, hydrogen-only plant, biomass and nuclear cleared 100 percent, and about 97 percent of awarded capacity was new-build or replacement rather than retrofit.

Key numbers

First main auction (delivery FY2024)
167,691,648 kW cleared at ¥14,137/kW; ¥1,598.7 billion
FY2029 main auction
166,079,863 kW; ¥2,209.4 billion; area prices ¥12,388 to ¥15,112/kW
Long-term auction, bid year FY2025
4,261 MW decarbonised (¥474.8 billion/year) and 3,038 MW LNG (¥144.4 billion/year)
Contract length and clawback
20 years of fixed-cost capacity revenue; about 90 percent of other-market revenue refunded
New nuclear awarded
1,381,275 kW at Ohma (J-Power) in the FY2025 long-term round

Who gains and who pays

  • Thermal, hydro and nuclear generators (gains): Capacity revenue four years ahead plus, for qualifying projects, twenty years of fixed-cost income.
  • Retail electricity suppliers (costs): Pay the capacity contribution; the FY2029 bill is ¥2.21 trillion nationally.
  • Battery, pumped-storage and long-duration storage developers (mixed): Eligible for twenty-year contracts but cleared only 46 to 55 percent of bids in the FY2025 round.
  • New nuclear and hydrogen or ammonia projects (gains): Ohma took 1,381 MW of twenty-year cover in the FY2025 round; hydrogen-only and ammonia retrofits cleared in full.
  • Electricity consumers (costs): The contribution is passed through in retail tariffs and industrial contracts.

Implementation

OCCTO publishes a募集要綱 (solicitation notice) and business manual for each delivery year, runs participant registration, then the auction, then settlement of capacity contracts and the capacity contribution charged to retailers and network companies. The Electricity and Gas Trading Surveillance Commission monitors bids and can require price corrections before results are finalised, which it did in both long-term rounds. Long-term auction winners sign a capacity-securing contract with a decarbonisation roadmap and must start supplying capacity on the committed date; LNG-only winners must begin decarbonisation work within ten years of first supply and be decarbonised by 2050. CCS-equipped thermal, biomass-to-CCS conversion, ammonia co-firing new-build and synthetic-methane plant remain formally eligible but were excluded from the FY2025 round because no credible ceiling price could be set. Results for the FY2030 delivery year and the FY2026 long-term bid round are the next data points.

Concerns

  • Capacity costs rose about 38 percent between the FY2024 and FY2029 auctions with no increase in cleared volume
  • Area price separation raises costs most in the areas already short of interconnection
  • Batteries and pumped storage face solicitation caps that limited clearing to under 55 percent of bids
  • Twenty-year contracts for LNG-only plant risk locking in gas unless the decarbonisation conditions bite
  • The revenue clawback formula depends on estimated spot and non-fossil prices that have proved highly volatile

Dates to watch

  • 2027-01: Expected publication of the main auction result for delivery year FY2030
  • 2027-05: Expected publication of the long-term decarbonisation auction result for bid year FY2026

Sources

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