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Taiwan: 6 energy policy briefs

The energy policies moving Taiwan’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.

Nuclear exit and the restart question · Maanshan 2 shut 17 May 2025, licence renewal under review

Taiwan · Legislative Yuan and the Nuclear Safety Commission (Maanshan Unit 2 operating licence expired 17 May 2025) · statute · 2025

Where it stands: Licence renewal applications under staged review by the Nuclear Safety Commission

Taiwan became nuclear-free on 17 May 2025 when the Maanshan Unit 2 operating licence expired, four decades after the unit started up. A 2025 amendment to the nuclear regulation law reopened the possibility of licence renewal, a national referendum on restarting Maanshan failed to clear the statutory approval threshold, and the Nuclear Safety Commission is now running a four-part licence renewal review.

The problem

Taiwan legislated a nuclear-free homeland and let its reactor licences run out one by one: Chinshan, then Kuosheng, whose Unit 1 licence expired on 27 December 2021, then Maanshan, whose Unit 1 licence expired on 27 July 2024 and Unit 2 on 17 May 2025. The policy was set when Taiwan expected flat demand and cheap LNG. It collided with three later facts: electricity demand rose sharply with semiconductor investment and data centres, the 2050 net-zero target made replacing 8 to 10 percent of generation with gas awkward, and the island's reserve margin and LNG storage cover left it exposed to supply interruption with no interconnection to fall back on. The original licensing law also made the question difficult to reopen, because it did not contemplate renewing a licence that had already expired and required decommissioning to begin.

What it does

The Legislative Yuan amended the nuclear reactor facility regulation legislation in 2025 to allow operators of reactors whose licences had expired, or were about to, to apply for renewal and to permit extended operating periods, removing the automatic path to decommissioning that the earlier law implied. A national referendum on restarting the Maanshan plant was then held in 2025; affirmative votes outnumbered negative ones, but the result did not pass because the affirmative vote fell short of the statutory threshold of one quarter of the electorate required under the Referendum Act, so it created political momentum without legal effect. Taipower has since filed for operating licence renewal and the Nuclear Safety Commission has established a dedicated restart review programme. That review runs in four parallel workstreams, each fed by staged submissions from Taipower: a restart plan review, a review of the report on the execution results of that plan, a safety technical report review, and a review of the technical and management capability and financial basis report. The Commission publishes regulatory dynamics, a chronology, monthly regulatory information and the record of its regulatory meetings for each plant under review, and maintains separate pages for Maanshan and Kuosheng; the programme pages were last updated on 26 August 2026. Both Maanshan units are formally recorded as in decommissioning status while the renewal review proceeds.

Market effect

Removing the nuclear fleet moved Taiwan's marginal generation decisively toward imported LNG and, on tight days, coal, which raised both the average cost of electricity and the carbon intensity of every corporate renewable buyer's residual grid supply. It also tightened the reserve margin in a system with no interconnection and limited LNG storage, so the value of demand response, reserve contracts and new gas-fired capacity rose, as did the risk premium in long-dated industrial supply negotiations. The restart question is now the largest single uncertainty in Taiwanese power fundamentals. If licence renewal succeeds at Maanshan and later at Kuosheng, several gigawatts of low-marginal-cost baseload return, LNG import volumes fall and the merit order shifts down, which would reduce Taipower's fuel bill and ease the tariff pressure. If it fails, the 2030s depend on offshore wind, solar, gas and the demand-side. For gas infrastructure investors the asymmetry matters: terminal and pipeline capacity sized for a nuclear-free system becomes surplus if reactors return. Regulatory risk runs both ways, since the Nuclear Safety Commission is independent and a restart requires it to be satisfied on safety, technical and management capability and financial basis, none of which a referendum or a statute can compel.

Key numbers

Maanshan Unit 1 licence
27 July 1984 to 27 July 2024
Maanshan Unit 2 licence
18 May 1985 to 17 May 2025; Taiwan nuclear-free from that date
Kuosheng Unit 1 licence
28 December 1981 to 27 December 2021
2025 statutory change
Nuclear Reactor Facilities Regulation Act Article 6 amended — passed by the Legislative Yuan 13 May 2025, promulgated 23 May 2025, six days after Maanshan 2 shut
What the amendment did
Removed the bar on renewing an already-expired licence: an operator may now apply after expiry, subject to the regulator confirming no safety concern; original licences run a maximum of 40 years and a renewed licence a maximum of 20 years from its effective date
Referendum case 21, 23 August 2025
Agree 4,341,432 (74.17% of valid votes) against disagree 1,511,693 (25.83%) — a 3-to-1 majority in favour of restart
Why it failed anyway
Agree votes were 21.70% of the 20,002,091-strong electorate, short of the one-quarter threshold of 5,000,523; turnout was 29.53%
Restart review structure
Four reviews: restart plan, restart plan execution results, safety technical report, and technical, management and financial capability

Who gains and who pays

  • Taiwan Power Company (mixed): Carries the decommissioning cost and the restart application; a successful renewal would cut its fuel bill materially.
  • LNG importers and terminal developers (costs): Infrastructure sized for a nuclear-free system becomes surplus if reactors return.
  • Industrial and semiconductor customers (gains): Restart would ease reserve-margin risk and slow tariff increases in a system with no interconnection.
  • Renewable developers (mixed): Returning baseload lowers residual demand but also lowers the grid carbon factor and the urgency of procurement.
  • Nuclear Safety Commission (obligation): Must complete four separate reviews before any restart, independent of political direction.

Implementation

Nothing restarts without the Nuclear Safety Commission. Taipower submits documents in stages against a published review plan; the Commission reviews each workstream, holds regulatory meetings, publishes monthly regulatory information and a chronology for each plant, and can require further analysis, plant modification or ageing-management measures before it will issue a renewed licence. Because the units are formally in decommissioning status, some equipment has been laid up or defuelled and restoration is itself a project with cost and schedule risk that Taipower must fund from a balance sheet already under strain. Fuel procurement, spent-fuel storage capacity on site and the low-level waste question at Lanyu, which the Electricity Act itself addresses in Article 95, are all live constraints. Politically the referendum result gives the restart case momentum without a mandate, so the decisive events are regulatory rather than electoral: the completion of the four reviews and any licence renewal decision, followed by the same question at Kuosheng.

Concerns

  • Units are formally in decommissioning status, so restoration is itself a costly and uncertain project
  • The referendum created political pressure but no legal obligation to restart
  • Spent fuel storage capacity and the low-level waste question remain unresolved
  • Taipower must fund restoration from a balance sheet already strained by fuel costs
  • Regulatory independence means the Nuclear Safety Commission can refuse renewal regardless of policy

Dates to watch

  • 2027: Expected completion of the Nuclear Safety Commission's Maanshan licence renewal reviews
  • 2027: Progress of the parallel Kuosheng restart review programme

Sources

Checked against sources on .

Taipower tariff reviews and the state subsidy · April 2024 increase and the loss overhang

Taiwan · Ministry of Economic Affairs Electricity Tariff Examination Council under Article 49 of the Electricity Act · decision · 2024

Where it stands: Approved tariffs in force; reviewed twice a year with 1 April and 1 October effective dates

Taiwan's electricity tariffs are set twice a year by an MOEA-convened Electricity Tariff Examination Council, with changes effective on 1 April and 1 October. Successive reviews since 2022 have raised rates, most visibly in April 2024, while the Executive Yuan has covered part of Taipower's losses with budget injections that the Legislative Yuan has repeatedly contested.

The problem

Taipower buys or generates almost all of Taiwan's electricity and sells it at a regulated tariff, so when imported LNG and coal prices tripled in 2021 and 2022 the entire shock landed on one state-owned balance sheet. The government chose to protect households and small businesses and hold tariffs well below cost, and Taipower accumulated very large losses. Two structural factors made it worse than in comparable systems: the nuclear phase-out raised the share of generation set by imported fuel just as fuel prices spiked, and Taiwan's tariff is uniform and heavily weighted toward low-price residential blocks, so the customers whose consumption grew fastest paid the least relative to cost. Article 49 of the Electricity Act requires the central competent authority to set a tariff calculation formula and requires public hearings, but it does not prevent the government from deciding that the formula's output is politically unacceptable.

What it does

Under Article 49 the central competent authority establishes the formulae for calculating the rates charged by the public electricity retailing utility and by the transmission and distribution enterprise; Taipower determines rates using those formulae, reports them to the authority for approval and announces them once approved, and the authority must hold public hearings before deciding. In practice MOEA convenes the Electricity Tariff Examination Council twice a year, in roughly March and September, with changes taking effect on 1 April and 1 October, and the Executive Yuan has intervened both to moderate increases and to fund the gap. The April 2024 review produced the largest single increase of the period, with the burden weighted toward high-consumption industrial and commercial users and the lowest residential blocks left broadly protected; subsequent reviews have adjusted or frozen rates. Alongside the tariff, the Executive Yuan has proposed special budget injections into Taipower to absorb accumulated losses, and those appropriations have been cut or blocked by the Legislative Yuan, which has made the subsidy itself a recurring fiscal and political event rather than a settled backstop. Articles 9 and 10 put the ancillary service fee and the wheeling and dispatch fees through the same council, and both may be set by reference to the electricity carbon emission factor, with Article 10 allowing a discount on that basis under rules made by the central competent authority.

Market effect

The tariff decision is the single most important recurring event in the Taiwanese power market because it determines three separate things at once. It sets the price industrial and commercial consumers pay, and therefore the threshold above which a corporate renewable power purchase agreement becomes cheaper than grid supply: every increase widens the gap in favour of PPAs and strengthens the demand that Round 3 offshore wind and large solar depend on. It sets Taipower's revenue, and therefore the capital it can commit to the distribution reinforcement that rooftop solar and electrification require, and to the west-coast onshore grid that offshore wind needs. And through Articles 9 and 10 it sets the wheeling, dispatch and ancillary service fees that renewable projects pay, so a council decision can change a wind project's net revenue without touching its PPA price. Because the subsidy route is contested in the Legislature, the tariff is the only reliable instrument, which biases the system toward larger tariff increases concentrated on industrial users. For lenders the practical exposure is that Taipower is the counterparty for wheeling, connection and, for legacy feed-in tariff projects, offtake, so its financial condition is a credit consideration even for projects that never sell it a kilowatt-hour.

Key numbers

Statutory basis
Electricity Act Article 49: MOEA sets the calculation formulae, approves rates and must hold public hearings
Review cycle
Electricity Tariff Review Council convened twice a year, with 1 April and 1 October effective dates — but an extraordinary session can be called, as on 27 June 2022
June 2022 (extraordinary)
Residential up to 1,000 kWh a month unchanged; above 1,000 kWh +9%; high and extra-high-voltage industrial +15%, with six industries and schools exempt
April 2023
Average +11%; residential up to 700 kWh unchanged, 701-1,000 kWh +3%, above 1,000 kWh +10%; industrial +5% to +17%
April 2024 — the largest of the period
Average rate NT$3.4518 per kWh; residential up to 330 kWh +3%, 701-1,000 kWh +7%, above 1,000 kWh +10%; large industrial users +15% to +25%
September 2024
Residential frozen; industrial alone adjusted, by 14%
Current schedule
Unit prices for every usage class approved 26 September 2025 and in force from 1 October 2025; as of September 2026 the MOEA approved-price page still shows that schedule, the most recent council meeting having been held 27 March 2026
Accumulated loss
NT$382.6 billion through 2022, rising to NT$422.9 billion by the end of 2024
State support
NT$150 billion capital injection in 2022, then NT$100 billion in the 2024 supplementary budget and NT$100 billion in the 2025 general budget
Network and ancillary fees
Set by the same council and differentiated by generation fuel: in 2026 a non-emitting renewable generator pays 0.0364 NT$/kWh for ancillary services against 0.1014 for coal, with transmission wheeling 0.0778 against 0.2738

Who gains and who pays

  • Industrial and commercial consumers (costs): Carried the weight of the increases, which is what makes corporate PPAs competitive.
  • Taiwan Power Company (mixed): Tariff increases repair revenue but the fiscal backstop depends on contested appropriations.
  • Renewable developers and corporate offtakers (gains): Higher grid tariffs widen the commercial case for wheeled PPAs.
  • Renewable projects paying wheeling and ancillary fees (costs): The same council sets network and ancillary charges under Articles 9 and 10.
  • Households on low-consumption blocks (gains): Protected from most of the increases by the tiered residential structure.

Implementation

Taipower prepares a rate proposal against the MOEA formula, MOEA convenes the council, public hearings are held, the council decides and the rate is announced in the MOEA gazette with an effective date of 1 April or 1 October. The Executive Yuan can and does influence the outcome, including by directing freezes for particular customer classes, and separately proposes budget support for Taipower, which the Legislative Yuan votes on. Wheeling, dispatch and ancillary service fee schedules follow the same approval route and are then implemented through Taipower's published procedures, which is where a renewable project's actual charges are fixed. The medium-term issue is whether Taiwan moves to a more formulaic, pass-through tariff that would transfer commodity risk to consumers and take the decision out of the political cycle, or keeps discretionary review and therefore keeps the risk on the state.

Concerns

  • Tariff decisions remain discretionary despite a statutory calculation formula
  • Budget support for Taipower depends on appropriations the Legislative Yuan has cut
  • Industrial users carry a disproportionate share of cost recovery
  • Network reinforcement for renewables competes with loss recovery for the same revenue
  • Taipower's financial condition is a counterparty risk even for projects that do not sell to it

Dates to watch

  • 2027-03: Electricity Tariff Examination Council review for rates effective 1 April 2027
  • 2027-09: Second review of the year for rates effective 1 October 2027

Sources

Checked against sources on .

Climate Change Response Act · carbon fee under Article 28 and the import carbon measure

Taiwan · Legislative Yuan and the Ministry of Environment (Climate Change Response Act, promulgated 15 February 2023 by Presidential Order Hua-Tsung-Yi-Yi-Tzu No. 11200010681) · statute · 2023

Where it stands: In force; carbon fee being collected in phases with the first liabilities assessed on prior-year emissions

Taiwan's Climate Change Response Act, a 63-article rewrite promulgated on 15 February 2023, legislated net zero by 2050 and created a carbon fee on large direct and indirect emitters under Article 28, preferential rates for approved voluntary reduction plans under Article 29, offsetting under Article 30, and an import carbon declaration and credit obligation under Article 31.

The problem

Taiwan's earlier Greenhouse Gas Reduction and Management Act of 2015 set targets but gave the regulator no price instrument, relying on sectoral management plans and voluntary action. That was untenable once Taiwan's largest export markets began pricing embedded carbon: the European Union's border adjustment mechanism, in particular, meant that carbon not priced in Taiwan would be priced at the border by someone else, with the revenue leaving the country. Taiwan is also not a party to the UNFCCC, so it cannot use international mechanisms and must build a domestic system that trading partners will nonetheless recognise. The 2023 rewrite therefore had three jobs: put net zero by 2050 in statute, create a domestic carbon price whose revenue stays in Taiwan and funds abatement, and build a symmetrical import measure so that domestic industry is not disadvantaged.

What it does

The Act was promulgated in full on 15 February 2023 with 63 articles, replacing the 2015 statute; competence moved to the newly created Ministry of Environment in August 2023. Article 28 empowers the central competent authority to collect a carbon fee in phases from direct emission sources, charged to the owner or, if different, the actual user or manager, and from indirect emission sources on the emissions embodied in their electricity use; a generator that supplies electricity to others may apply to deduct the corresponding emissions so that the same tonne is not charged twice. The fee rate is set by a rate review committee established by the central competent authority, which weighs the state of national emissions reduction, the type of emission source, the greenhouse gases involved, the scale of emissions, voluntary reduction effort and effectiveness, and is then approved and announced by the authority and reviewed periodically. Article 29 allows a fee payer that adopts reduction measures such as fuel switching, negative-emission technology, efficiency improvement, renewable energy or process change, and meets a designated target, to submit a voluntary reduction plan and apply for a preferential rate. Article 30 lets a fee payer apply to deduct emissions using reduction credits. Article 31 is the import measure: importers of products announced by the authority must declare the product's carbon emissions and obtain reduction credits on the Article 25 platform equal to the assessed carbon differential, with relief where the export country already operates emissions trading or a carbon tax or fee that was not refunded on export, and a payment in lieu where sufficient credits are not obtained. The detailed rules on who pays, how emissions are calculated, reporting, payment deadlines, exemptions and the credit mechanisms are all made by ministerial regulation.

Market effect

For electricity the design is unusual and consequential: because Article 28 charges indirect emission sources on the carbon embodied in their electricity, with a corresponding deduction available to generators, the fee reaches large consumers directly rather than only through the generator's cost stack. That matters in a market where Taipower's tariff is politically set and cannot reliably pass a carbon cost through, so charging the consumer side is the only way to make the price visible to the entity that can act on it. The immediate commercial effect is to raise the value of a corporate renewable power purchase agreement and of Taiwan renewable energy certificates, because contracted renewable supply reduces a covered user's indirect emissions and therefore its fee, stacking on top of the Renewable Energy Development Act's large-user obligation. Article 29's preferential rate is the lever that actually determines industrial cost: a plant with an approved voluntary reduction plan pays materially less than the headline rate, so the negotiation over designated targets is where the real carbon price is set. Article 31 gives Taiwan a border measure of its own, which raises compliance cost for importers of covered products and creates demand for the domestic credit platform. The T-REC market sits alongside all of this: certificates issued by the national certification centre are what a manufacturer uses to evidence renewable consumption for its own customers, for the Article 12 obligation and, indirectly, for its carbon position.

Key numbers

Statute
Climate Change Response Act, 63 articles, promulgated 15 February 2023 by Presidential Order No. 11200010681
General fee rate
NT$300 per tonne CO2e, announced 21 October 2024, in force 1 January 2025
Preferential rate A
NT$50 per tonne CO2e for an approved self-determined reduction plan meeting the industry-specific reduction rate derived from SBTi
Preferential rate B
NT$100 per tonne CO2e for an approved plan meeting the technology benchmark rate, set against best available technology and Taiwan's 2030 NDC
Covered entities
Power and manufacturing entities emitting more than 25,000 tonnes CO2e a year
Threshold deduction
The same 25,000 tonnes is deductible from chargeable emissions — but NOT for entities assessed at high carbon leakage risk, which instead receive an emission adjustment coefficient and must hold an approved reduction plan
First liability and payment
Assessed on full-year 2025 emissions and payable by the end of May 2026; thereafter by end of May each year on the previous calendar year
Offset credit limits
Domestic voluntary and offset credits count at a ratio of 1.2, capped at 10% of chargeable emissions; pre-implementation credits at 0.3 for the first two years and international credits up to 5%, both only for industries not at high leakage risk
Three supporting regulations
Collection of Carbon Fees, Designated GHG Reduction Goals, and Administration of Self-Determined Reduction Plans — all announced 29 August 2024 (drafts 29 April 2024)
Import measure
Article 31: carbon declaration plus reduction credits for the assessed carbon differential, or a payment in lieu

Who gains and who pays

  • Large direct emitters (steel, cement, petrochemicals, semiconductors) (obligation): Pay the carbon fee under Article 28 unless they secure a preferential rate under Article 29.
  • Large electricity consumers as indirect emission sources (obligation): Charged on the emissions embodied in their electricity use, which is why contracted renewable supply has direct fee value.
  • Renewable generators and T-REC sellers (gains): Contracted renewable supply and certificates reduce a covered user's indirect emissions and fee liability.
  • Importers of announced products (costs): Article 31 requires a carbon declaration and reduction credits for the assessed differential, or a payment in lieu.
  • Taiwan Power Company (mixed): May deduct emissions attributable to electricity supplied to others, but carries the carbon cost of its own generation.

Implementation

The Act delegates almost every operative number to ministerial regulation. The Ministry of Environment makes the regulations on fee collection targets, calculation methods, reporting and payment, the regulations on preferential rates and voluntary reduction plans, the regulations on offset credit ratios and ceilings, and the regulations implementing the Article 31 import measure; the rate review committee sets the fee levels, which the Ministry approves and announces and must review periodically. The Article 25 platform administers reduction credits, which are also the instrument importers must obtain. Fee liability is assessed on the previous year's verified emissions, so the first payments fall due in the year after the first charging year. Recognition by trading partners, particularly whether the European Union treats the Taiwanese fee as an effective carbon price for border adjustment purposes, is the test that matters most to Taiwanese exporters and is the reason the preferential-rate design is scrutinised abroad as well as at home.

Concerns

  • Preferential rates under Article 29 could reduce the effective carbon price well below the headline rate
  • Whether trading partners recognise the fee as an effective carbon price for border adjustment
  • Charging indirect emitters on electricity use is unusual and complicates the interaction with the regulated tariff
  • The Article 31 import measure requires a functioning domestic credit platform with adequate supply
  • Almost every operative parameter is set by ministerial regulation rather than statute

Dates to watch

  • 2027: Next periodic review of the carbon fee rates by the rate review committee
  • 2027: Phase-in of the Article 31 import carbon declaration and credit obligation for announced products

Sources

Checked against sources on .

Offshore wind Round 3 zonal development · 3 GW blocks, corporate PPAs and localisation

Taiwan · Energy Administration, Ministry of Economic Affairs (offshore wind zonal development rules under the Electricity Act and the Renewable Energy Development Act) · rule · 2022

Where it stands: Phase 3 rules amended 27 March 2026; phase 1 and 2 contracts and grid allocations being executed

Taiwan's third offshore wind round replaced feed-in tariffs with zonal development, allocating 15 GW from 2026 to 2035. The rules governing phase 3, amended 27 March 2026, changed the model: bidders are scored on capability rather than price, the localisation scoring that drew an EU trade complaint is now ESG and energy-resilience investment, and phase 3 projects hold a guaranteed floor price of NT$2.29 per kWh — a revenue backstop under what had been a merchant model.

The problem

Rounds 1 and 2 built Taiwan's first offshore wind capacity on a feed-in tariff and a grid-allocation mechanism, which worked but was expensive and put the cost on Taipower and consumers. With a nuclear phase-out under way, a 2050 net-zero commitment and manufacturers demanding clean power, MOEA needed far larger volumes at lower public cost and with a domestic supply chain attached. The answer was to move the offtake risk onto corporate buyers, who were already obliged by the Renewable Energy Development Act to procure renewable electricity and certificates and who, in the semiconductor and electronics sectors, had customer commitments of their own. That solved the cost problem and created a new one: a project financed on corporate PPAs must find creditworthy counterparties willing to sign twenty-year contracts, in a market where a handful of buyers hold most of the demand.

What it does

The framework allocates capacity by completion-and-connection year under the Directions for Capacity Allocation of Offshore Wind Zonal Development Sites, promulgated 19 August 2021 and amended for each phase, most recently on 27 March 2026. Point 4 sets 3,000 MW for phase 1 (connection in 2026 and 2027, 1,500 MW a year), 3,000 MW for phase 2 (2028 and 2029, 1,500 MW a year), 3,600 MW in principle for phase 3 (2030 and 2031), and a further 6,000 MW for 2032 to 2035 whose schedule is to be planned later; capacity left unallocated in a phase may be carried forward. Each applicant may file one application, for no less than 300 MW and no more than 1,000 MW, at a density of at least 7,000 kW per square kilometre and at least 1,200 metres from any existing consented site. Applications are scored out of 100 under Point 8 — developer track record 35, developer financial capacity 30, and project execution capacity 35, the last split into execution progress 15, ESG planning 15 and energy resilience 5 — and must reach 70 to qualify. Qualified applications are then ranked by score and allocated capacity in rank order against Taipower's published annual connection capacity and points; there is no separate price-competition stage in the phase 3 rules. A single developer group is capped at 1,000 MW across all phases. Winners sign an administrative contract, post a performance bond of NT$2 million per MW, and may be allocated expansion capacity of up to half their award if it is connected by 31 December 2031.

Market effect

Round 3 moved Taiwanese offshore wind from regulated revenue toward contracted revenue, but the phase 3 rules stop short of the fully merchant model the earlier phases implied. Point 15 requires a phase 3 winner's purchase agreement with the public retailer under Article 9 of the Renewable Energy Development Act to be struck at the floor price of NT$2.29 per kWh, so a project that cannot place its output with corporate buyers has a defined fallback rather than nothing. That floor is what makes the round financeable on terms closer to the earlier rounds: lenders still prefer investment-grade corporate offtakers and still demand availability guarantees, but the downside case is bounded by a published number instead of by the PPA market's depth. Price discovery accordingly runs between the floor and whatever the small group of semiconductor, electronics and materials buyers will pay, with the Renewable Energy Development Act's monetary substitution payment still setting a soft ceiling on compliance-driven demand. The localisation question has been resolved not by abolition but by reclassification: what was scored industrial relevance is now ESG local-industry and economic-benefit investment worth 15 points and energy resilience worth 5, enforced as committed investment amounts in the administrative contract and rewarded through licence extension rather than imposed as content requirements. Grid connection remains the hard constraint, since capacity is allocated against Taipower's published annual connection capacity and points, and an application whose chosen connection points all have less than 100 MW remaining is simply not allocated. For Taipower the round is now not quite cost-neutral on offtake, because the floor price is an obligation it may have to honour, and it remains costly on network.

Key numbers

Governing instrument
Directions for Capacity Allocation of Offshore Wind Zonal Development Sites, promulgated 19 August 2021; phase 3 governed by the amendment of 27 March 2026 (經能字第11558000800號)
Total programme
15 GW allocated across 2026 to 2035 (民國115年至124年)
Phase 1 and 2
3,000 MW each — phase 1 connecting in 2026 and 2027, phase 2 in 2028 and 2029, both at 1,500 MW a year
Phase 3
3,600 MW in principle, connecting in 2030 and 2031; applications governed by the 27 March 2026 rules
Remaining tranche
6,000 MW for connection 2032 to 2035, schedule to be set later; unallocated capacity may be carried forward between phases
Bid size limits
One application per applicant, minimum 300 MW and maximum 1,000 MW, at least 7,000 kW per square kilometre and 1,200 m from any existing consented site
Scoring and pass mark
Developer track record 35, financial capacity 30, project execution 35 (execution progress 15, ESG planning 15, energy resilience 5); 70 of 100 required to qualify, then ranked by score — no separate price competition
Floor price
NT$2.29 per kWh — phase 3 winners' purchase agreements with the public retailer under Renewable Energy Development Act Article 9 are struck at this guaranteed floor
Developer cap and bond
1,000 MW maximum per developer group across all phases; performance bond NT$2 million per MW
Expansion capacity
Up to half the allocated capacity, conditional on connection by 31 December 2031 and on proportionate ESG and resilience investment
Delivery incentive
Licence extension up to five years: day-for-day for early connection, 12 months at NT$30 billion of local-industry investment plus one month per further NT$1 billion, and one month each at NT$2.5 billion and NT$3 billion of energy-resilience investment

Who gains and who pays

  • Offshore wind developers and their lenders (mixed): Larger volumes but merchant offtake risk; bankability depends on corporate PPA credit and grid allocation year.
  • Semiconductor, electronics and materials manufacturers (gains): Access to large, long-dated renewable supply that satisfies their own procurement obligations and customer commitments.
  • Taiwanese supply chain (foundations, cables, vessels, towers) (mixed): Guaranteed demand under localisation scoring, weakened as the requirements were relaxed after the trade complaint.
  • Taipower (costs): Must build west-coast onshore reinforcement and administer wheeling for projects it does not buy from.
  • Fishing communities on the west coast (costs): Fishery coordination and compensation are scored commitments rather than statutory entitlements.

Implementation

Each phase runs under the version of the Directions in force for it — phase 1 under the 2021 text, phase 2 under the 23 November 2023 text and phase 3 under the 27 March 2026 text — with the application window announced separately by MOEA. An applicant must already hold site-planning acknowledgement, a first-stage environmental impact assessment recommendation that covers the site and capacity applied for, and a Taipower grid-connection review opinion; the application cannot exceed any of them. A review panel of 13 to 23 government, technical, industry, financial and legal members scores the applications, with recusal rules and a quorum requirement that at least a third of those present be academics or outside experts. After allocation MOEA publishes the ranking and results, winners apply to sign the administrative contract with at least half the performance bond paid up front and the rest within a year of signing or a month after financial close, and MOEA then issues the offshore installation consent. Delivery is enforced through the contract and rewarded through Point 18: up to five years of licence extension, earned day-for-day for early connection, twelve months for local industry and economic-benefit investment reaching NT$30 billion and a further month for each NT$1 billion above it, and a month each at NT$2.5 billion and NT$3 billion of energy-resilience investment, with the local-industry items checked after connection and the resilience items five years after.

Concerns

  • Merchant offtake risk concentrated on a small number of corporate buyers
  • Localisation requirements raised cost and drew a WTO complaint from the European Union in 2024
  • Annual grid-capacity caps, not developer appetite, set the effective build rate
  • Milestone slippage across the industry puts awarded capacity and connection slots at risk
  • Fisheries and environmental coordination are contractual commitments rather than statutory entitlements

Dates to watch

  • 2027: Next zonal development phase selection rules and grid capacity allocation
  • 2027: Commercial operation milestones for earlier Round 3 blocks under their administrative contracts

Sources

Checked against sources on .

Renewable Energy Development Act · 2019 large-user obligation and the 2023 rooftop solar mandate

Taiwan · Legislative Yuan (Renewable Energy Development Act, promulgated 8 July 2009, amended 1 May 2019, 21 June 2023 and 11 June 2025) · statute · 2019

Where it stands: In force; large-user obligation operating and the rooftop mandate phased in by Executive Yuan order

The 2019 amendment to Taiwan's Renewable Energy Development Act created the large electricity user obligation in Article 12: consumers above a contracted-capacity threshold must install renewable generation and storage, buy renewable electricity and certificates, or pay a monetary substitute. The 2023 amendment added Article 12-1, obliging new and substantially rebuilt buildings to install rooftop solar.

The problem

Taiwan set a target of 20 percent renewable generation and legislated a nuclear-free homeland, but its feed-in tariff alone could not deliver the volumes on an island with very little cheap land and intense competition for rooftops, farmland and fish ponds. Two structural problems stood in the way. First, demand for renewable electricity was concentrated in exporters who needed certificates for their own supply chains, while the FIT channelled almost all output to Taipower, so the certificates that manufacturers needed did not exist. Second, solar siting on the ground had become socially contested, with disputes over agricultural land, salt flats and wetlands, while the enormous rooftop area on new industrial and commercial buildings went unused. The 2019 and 2023 amendments attack both: create demand by obligation, and create supply by mandating installation where the roof already exists.

What it does

Article 12, as amended in 2019, provides that where the chartered capacity on a consumer's electricity supply agreement exceeds a certain capacity, the user must either install renewable generation and storage equipment of a certain installed capacity, provide space for someone else to install it, or purchase a certain amount of renewable electricity together with certificates; if the user does none of these, it must pay a monetary substitution to the competent authority for the development of renewable energy. The contracted capacity threshold, the required installed capacity and purchase amount, the eligible generation and storage categories, the substitution payment and the compliance schedule are all set by regulation made by the central competent authority, and local governments may impose stricter autonomous rules within their jurisdiction. Article 12 also requires government agencies, public schools and state-run enterprises to install renewable generation on qualifying new, expanded or reconstructed public buildings and works. Article 12-1, added by the amendment promulgated on 21 June 2023, requires new buildings and additions or reconstructions of existing buildings to install solar photovoltaic equipment above a certain installed capacity unless light-receiving conditions are insufficient or an exemption applies, with the building scope, set scale, installed capacity and calculation method, light conditions and exemptions determined by the central construction authority together with the central energy authority; the commencement date for the revision was left to the Executive Yuan. Article 9 remains the feed-in tariff power under which MOEA announces annual purchase rates with twenty-year contracts, and Article 4 sets approval thresholds, with installations of 2,000 kW and above approved centrally and smaller ones by the municipal or county authority. The Act was further amended on 11 June 2025.

Market effect

The large-user obligation manufactured a domestic market for Taiwan renewable energy certificates where none existed. Because a covered user can comply by buying electricity and certificates, the obligation sets a floor under T-REC demand and, through the monetary substitution, an implicit ceiling on what compliance should cost: no rational buyer pays more for a certificate than the substitution payment. That relationship, not the feed-in tariff, is what determines the marginal value of a corporate renewable PPA for a mid-sized Taiwanese manufacturer, while the very largest buyers contract directly with offshore wind and utility solar under the Electricity Act's wheeling provisions. The rooftop mandate in Article 12-1 changes the supply side: every new factory, warehouse and commercial building becomes a solar site by default, which shifts volume away from contested ground-mounted projects toward distribution-connected rooftop capacity. That is better for land politics and worse for the distribution network, because it concentrates injection on feeders that were built for load, and it raises the value of behind-the-meter storage and of Taipower's distribution reinforcement programme. For developers, the practical consequence is that the growth segment has moved from large ground-mounted arrays to aggregating thousands of rooftops, a business with different financing, different counterparty risk and much higher transaction cost per megawatt.

Key numbers

Act and key amendments
Promulgated 8 July 2009; amended 1 May 2019, 21 June 2023 and 11 June 2025
Large-user threshold
Contract capacity of 5,000 kW or more — reviewed by MOEA and deliberately retained on 3 January 2025
Obligated capacity
10% of the user's prior-year average contract capacity (Regulation Article 4)
Compliance window
Five years from 1 January of the year the authority notifies the obligated capacity
Compliance routes
Install renewable generation, buy renewable electricity and certificates, or install storage — singly or mixed
Substitution payment
Unfulfilled obligated capacity × 2,500 kWh/kW × a substitution rate announced by MOEA
How users actually comply
495.0 MW met by purchasing electricity and certificates, 196.3 MW by self-installation and 5.2 MW by storage — purchasing dominates, which is what gives the corporate PPA and T-REC market its floor
Rooftop mandate not yet in force
Article 12-1, added in 2023, requires solar on new, extended or renovated buildings above a set scale, but Article 23 leaves its commencement to the Executive Yuan and no date has been fixed
Approval threshold
Renewable generation equipment of 2,000 kW or more is approved by the central competent authority

Who gains and who pays

  • Large electricity users above the contracted-capacity threshold (obligation): Must install, provide space, buy renewable electricity and certificates, or pay the monetary substitution.
  • Rooftop solar developers and aggregators (gains): Article 12-1 turns every qualifying new or rebuilt building into a site.
  • Property developers and construction firms (costs): Solar installation becomes a building-permit condition with capacity set by regulation.
  • T-REC sellers and certificate intermediaries (gains): The obligation creates regulated domestic demand with the substitution payment as a reference price.
  • Taipower distribution (costs): Distributed injection concentrates on feeders designed for load, requiring reinforcement and protection changes.

Implementation

Everything operative is in regulations. The central competent authority sets the contracted-capacity threshold, the required installed capacity, the purchase amount, the substitution payment and the compliance schedule for Article 12, and may allow local governments to go further, which several municipalities have done. For Article 12-1 the standards are made jointly by the construction and energy authorities and apply through the building permit process, which is why the commencement date was left to the Executive Yuan: the construction industry needed lead time and the standards had to be written into building codes. Feed-in tariff rates under Article 9 are drafted each autumn by the Energy Administration, reviewed by the FIT Rate Review Committee with public hearings and announced for the following year, with a twenty-year purchase term; the announcements are published as MOEA orders in the ministry's regulations database. Certificates are issued by the National Renewable Energy Certification Centre. Compliance for covered users is reported to the Energy Administration, which assesses the substitution payment where obligations are unmet.

Concerns

  • The threshold, required capacity and substitution payment are all set by regulation and can be changed administratively
  • The monetary substitution acts as a price cap that can suppress the certificate market
  • Rooftop mandates concentrate injection on distribution feeders not designed for it
  • Local governments may impose stricter rules, creating a patchwork for multi-site manufacturers
  • Ground-mounted solar siting on farmland, fish ponds and wetlands remains politically contested

Dates to watch

  • 2027-01: Announcement of the following year's renewable feed-in tariff rates by MOEA
  • 2027: Review of the large-user obligation compliance schedule and substitution payment level

Sources

Checked against sources on .

Electricity Act rewrite · 26 January 2017, green power wheeling and open grid access

Taiwan · Legislative Yuan (Electricity Act, amended 11 January 2017 and promulgated 26 January 2017) · statute · 2017

Where it stands: In force since 2017 and amended repeatedly, most recently on 5 January 2026

Taiwan's 2017 Electricity Act rewrite opened the market from the renewable end first: it made the transmission and distribution business a single state-owned enterprise with ring-fenced accounts and a duty of non-discriminatory access, let renewable generators wheel power to users or supply them directly, created an Electricity Industry Regulatory Agency, and put tariffs under an Electricity Tariff Examination Council.

The problem

Until 2017 Taiwan Power Company was a statutory monopoly across generation, transmission, distribution and retail, buying from a handful of independent power producers under long-term contracts and selling at a politically set tariff. Corporate buyers had no way to procure renewable electricity, which became an acute commercial problem as export manufacturers, above all the semiconductor supply chain, came under customer pressure to source clean power. Meanwhile Taiwan is an isolated island system with no interconnection, a reserve margin that had repeatedly fallen to uncomfortable levels, and a policy commitment to phase out nuclear power. Full retail competition on the European model was politically impossible; the Legislative Yuan instead chose a sequenced opening that began with renewables and left the conventional market intact.

What it does

The amendment passed on 11 January 2017 and was promulgated on 26 January 2017, restructuring the Act around separate classes of electricity enterprise. Article 5 provides that the electricity transmission and distribution enterprise shall be a state-owned corporation and that no more than one shall exist, covering the whole country, and that generation enterprises using nuclear or hydroelectric capacity above 20,000 kW must be public corporations. Article 6 requires the transmission and distribution enterprise to keep separate profit-and-loss accounts by business category and prohibits cross-subsidisation, with any other business it conducts needing regulatory approval and a finding that it will not impair fair competition. Article 8 makes the transmission and distribution enterprise responsible for dispatch and requires priority grid connection and dispatch for renewable energy, subject to system security. Article 10 lets a renewable energy generating enterprise or a retailing enterprise request dispatch and pay a dispatch fee, and requires the network company to charge wheeling fees by volume on published rates, with both fees able to be set by reference to the electricity carbon emission factor and subject to approval by the Electricity Tariff Examination Council. Article 45 keeps conventional generators tied to selling only to the public retailing utility or to the network company for ancillary services, but exempts renewable energy generating enterprises, which may wheel power to users across the grid or, with regulatory approval, build a dedicated line and supply a user directly; those paragraphs were to commence within one year of the 2017 amendment on a date set by the Executive Yuan, with at most two postponements of one year and six months. Article 46 requires the network company to plan, build and maintain the national grid, forbids it to refuse a user's connection request without justified cause and regulatory approval, and requires it to offer the grid to generators and retailers on fair and open principles without undue discrimination. Article 49 requires the central competent authority to set the tariff calculation formulae, the utility to report rates for approval and announce them, and public hearings before decisions. The Act has since been amended in 2019, 2023, 2024, 2025 and most recently on 5 January 2026.

Market effect

The 2017 Act is the legal basis for every corporate renewable power purchase agreement signed in Taiwan, and therefore for the offshore wind industry's financing model. Because Article 45 exempts renewable generators from the must-sell-to-Taipower rule and Article 10 obliges the network company to wheel their output at published fees, a wind or solar project can contract at a negotiated price with a semiconductor fabricator or an electronics manufacturer for twenty years rather than accept the administratively set feed-in tariff. That single provision is what allowed Round 3 offshore wind to be built on corporate PPAs instead of state offtake, and it is why Taiwanese renewable pricing is driven by what a handful of very large industrial buyers will pay. The reform is deliberately asymmetric: conventional generation is still locked into the Taipower single-buyer channel, there is no wholesale spot market, and Taipower remains the sole public retailer, so competition exists only in the renewable segment. Accounting separation under Article 6 rather than ownership unbundling means the network business has no independent balance sheet, so when Taipower's retail arm loses money the network's investment programme is exposed to the same political constraint. The Electricity Tariff Examination Council under Article 49 is where that constraint becomes visible, because it must approve both consumer tariffs and the wheeling and ancillary service fees renewable projects depend on.

Key numbers

Amendment and promulgation
Passed 11 January 2017, promulgated 26 January 2017
Network structure
Article 5: one state-owned transmission and distribution enterprise for the whole country
Wheeling commencement
Article 45: within one year of the 2017 amendment, date set by the Executive Yuan, at most two postponements (one year, then six months)
Public corporation threshold
Nuclear or hydroelectric generation above 20,000 kW must be a public corporation (Article 5)
Later amendments
2019, 2023 (Articles 71-1 and 71-2), 2024, 2025 and 5 January 2026

Who gains and who pays

  • Renewable generators and corporate offtakers (gains): Article 45 wheeling and direct supply made twenty-year corporate PPAs possible.
  • Taiwan Power Company (obligation): Must keep separate network accounts, offer fair and open grid access, and cannot refuse connection without approval.
  • Semiconductor and electronics manufacturers (gains): A legal route to contracted renewable supply that customers and investors demand.
  • Conventional independent power producers (costs): Still restricted by Article 45 to selling to the public retailing utility or providing ancillary services.
  • The Electricity Industry Regulatory Agency and the Electricity Tariff Examination Council (mixed): Took on licensing, dispatch supervision, dispute mediation and approval of tariffs, wheeling and ancillary service fees.

Implementation

The Act works through MOEA regulations and Taipower procedures. The Energy Administration, upgraded from the Bureau of Energy in 2023, writes the rules on licensing, direct supply qualification, wheeling and dispatch; Taipower publishes the wheeling, connection and settlement procedures that make a corporate PPA operable, and the wheeling and ancillary service fees go to the Electricity Tariff Examination Council for approval. Article 9 and Article 10 both allow fees to be set by reference to the electricity carbon emission factor, and Article 10 allows a discount on that basis under rules made by the central competent authority, which is the hook for preferential treatment of low-carbon supply. Renewable enterprises seeking a dedicated direct-supply line need the regulator's approval under criteria it publishes. Transitional Articles 92 to 96 required existing licensees to replace their licences within six months of commencement and disapplied the old Privately Owned Public Utilities Supervisory Act regime. The structural question the Act left unresolved is whether Taipower's generation and network businesses are ever separated by ownership rather than accounts; successive amendments have not delivered that.

Concerns

  • Accounting separation only: the network has no independent balance sheet from Taipower's loss-making retail arm
  • No wholesale spot market, so conventional generation still has no price signal
  • Wheeling and ancillary service fees are approved by a politically appointed council
  • Corporate PPA demand is concentrated in a few very large manufacturers, so pricing power is one-sided
  • The island has no interconnection, so all reliability risk is internal

Dates to watch

  • 2027-04: Electricity Tariff Examination Council review cycle covering tariffs and network fees
  • 2027: Any further Electricity Act amendment following the 5 January 2026 revision

Sources

Checked against sources on .