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Singapore: 4 energy policy briefs

The energy policies moving Singapore’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.

Energy Transition Measures and Other Amendments Act 2024 (No. 27 of 2024) · Future Energy Fund and EMA transition powers

Singapore · Parliament of Singapore · statute · 2024

Where it stands: Fully in force since 1 September 2025 (four commencement notifications); prescribed generation entity regulations issued

Passed on 9 September 2024 and fully in force since 1 September 2025, the act gives EMA the legal basis to fund and direct energy-transition infrastructure (a Future Energy Fund seeded with S$5 billion and topped up by a further S$5 billion in Budget 2025, powers to recover costs through market charges and to require participation in centralised gas and capacity arrangements), turning Singapore's market from purely merchant to a hybrid with state-directed investment.

The problem

Singapore's liberalised wholesale market rewarded short-run efficiency but did not deliver the long-lived, low-return infrastructure the transition needs (hydrogen-ready plants, import cables, storage, a central gas buyer), and the 2021-22 gas price crisis showed the market could not manage supply security on its own. The government needed explicit statutory powers to invest, to direct market participants and to socialise costs.

What it does

The act (Bill No. 27/2024, first read 6 August 2024, passed 9 September 2024, assented to on 30 September 2024 and gazetted 25 October 2024) amends the Energy Market Authority of Singapore Act 2001, the Electricity Act 2001 and the Gas Act 2001. It establishes the Future Energy Fund as a statutory fund under the EMA Act (new section 19), seeded with S$5 billion in Budget 2024 and topped up by S$5 billion in Budget 2025, to co-fund critical energy infrastructure such as import interconnectors, hydrogen-ready generation and storage. It empowers EMA to recover the costs of transition measures from market participants through charges, to direct licensees to participate in centralised arrangements (including central gas procurement: Singapore GasCo was established in May 2025, and the Electricity (Prescribed Generation Entities) Regulations 2025, in force 1 September 2025, set the minimum share of forecast gas that generators must contract from it over a ten-year horizon from 2028), and to require licensees to take actions for security of supply. It also provides for EMA to own or procure assets where the market will not, and updates enforcement and licensing provisions. Provisions commenced in four tranches by notification: 8 November 2024, 31 March 2025, 1 July 2025 (including the section 19B cost-recovery power) and 1 September 2025 (the central gas import regime), so the whole act is now in force.

Market effect

The act formalises a shift from a merchant market to one where EMA is buyer, planner and funder of key assets. Centralised gas procurement through Gasco means generators increasingly receive gas at a common price, which narrows fuel-cost differences between gencos and reduces the fuel component of the wholesale price spread; combined with the temporary price cap in the wholesale market, it dampens scarcity pricing. The Future Energy Fund lowers the cost of capital for imports and hydrogen-ready capacity, which accelerates the displacement of merchant gas generation. Cost-recovery charges appear as new line items in retailer and consumer bills. For investors the act reduces revenue volatility but also reduces the upside from tight markets; new capacity is now more likely to come through EMA-run tenders (such as the centralised process for new combined-cycle units) than merchant entry.

Key numbers

Future Energy Fund
S$5 billion initial (Budget 2024) plus S$5 billion (Budget 2025); further S$5 billion estimated for FY2026; no disbursements to date
Acts amended
EMA Act 2001, Electricity Act 2001, Gas Act 2001
Passage
Passed 9 September 2024; assented 30 September 2024; fully in force 1 September 2025
Central gas procurement
Singapore GasCo established May 2025; prescribed generation entity regulations in force 1 September 2025

Who gains and who pays

  • Generation companies (mixed): Common gas price and central direction reduce risk and upside; participation obligations.
  • Importers and infrastructure developers (gains): Access to Future Energy Fund co-funding.
  • Retailers and consumers (mixed): More stable prices; new cost-recovery charges.
  • Singapore Gasco (obligation): Central gas buyer with statutory backing.
  • EMA (obligation): New powers and responsibilities for investment and security of supply.

Implementation

All provisions are in force as of 1 September 2025 and EMA has issued the Electricity (Prescribed Generation Entities) Regulations 2025 under the act; GasCo was reported fully operational in early 2026. No section 19B cost-recovery rate determination and no Future Energy Fund disbursement had been published as of the FY2026 budget estimates, which budget a further S$5 billion top-up. Check EMA and Singapore Statutes Online for subsidiary legislation on charges and for fund commitments.

Concerns

  • Reduced competitive discipline as EMA becomes a central buyer and investor
  • Cost-recovery charges raising consumer prices
  • Transparency of fund allocation and centralised procurement outcomes
  • Crowding out of private investment in generation
  • Concentration of supply-security risk in state entities

Dates to watch

  • 2026: First Future Energy Fund commitments and cost-recovery charge determinations
  • 1 January 2028: Start of the ten-year window for minimum gas contracting with GasCo

Sources

Checked against sources on .

Low-carbon electricity imports · 6 GW by 2035 and conditional approvals

Singapore · Energy Market Authority · decision · 2024

Where it stands: Conditional approvals for 13 projects (9.25 GW) and six conditional licences granted; projects moving to financial close and construction

Singapore plans to import about a third of its electricity by 2035 from Indonesia, Vietnam, Cambodia, Malaysia and Australia; EMA has granted conditional approvals for 13 projects totalling 9.25 GW (six of them with conditional licences), but subsea cables, source-country export politics and financing decide which reach commercial operation.

The problem

Singapore's land constraints cap domestic solar at about 2 GW-peak and its grid is 95 percent gas-fired, so decarbonisation and price diversification depend on importing low-carbon power over new subsea and cross-border links. The government first set a 4 GW-by-2035 target in 2021 and raised it to 6 GW in 2024 as project proposals and the ASEAN Power Grid gained momentum.

What it does

EMA runs a request-for-proposal process and grants conditional approval, then conditional licences, to import projects that meet requirements on price, reliability and carbon intensity, with importers taking on supply obligations under a contracts-for-difference-style structure with retailers. Conditional approvals to date cover 13 projects and 9.25 GW: about 3.4 GW from Indonesian solar-plus-storage projects (of which 3 GW hold conditional licences, the first granted on 5 September 2024), 1.2 GW from Vietnamese offshore wind (Sembcorp), 1 GW from Cambodia (Keppel, solar, hydro and wind), 1.75 GW from Australia via the Sun Cable Australia-Asia Power Link (conditional approval 22 October 2024, operation expected after 2035), and 1.9 GW from Malaysia (1 GW from Sarawak, approved 17 October 2025, and 0.9 GW of trade with Peninsular Malaysia, approved 7 August 2026). The Lao PDR-Thailand-Malaysia-Singapore Power Integration Project has delivered up to 100 MW of hydro since June 2022, with a second phase to double it to 200 MW, and a 50 MW Malaysian import pilot began in December 2024. Singapore Energy Interconnections, set up in April 2025, will develop and own the cable infrastructure. Singapore also joined a regional grid-financing initiative and is studying a Singapore-Vietnam and Singapore-Indonesia cable corridor. Each project must still secure export approvals in the source country, cable routes, financing and a Singapore licence with conditions precedent.

Market effect

Imports at scale change Singapore's merit order: contracted low-carbon supply displaces the marginal gas plant in many periods, lowering the Uniform Singapore Energy Price and its exposure to LNG spot and the carbon tax, and shifting domestic gas plants toward mid-merit and peaking. Contracts with retailers transfer price risk to importers, who need firming (storage or hydro) to meet reliability conditions, so battery and pumped-storage demand rises in Indonesia and Malaysia. For the wholesale market the timing is the issue: the first large tranches (Indonesian solar, Vietnamese wind) target 2028 to 2030, SunCable the early 2030s, so through 2027 the domestic gas fleet plus EMA's centralised new-capacity procurement remain the price setters. Source-country policy (Indonesia's export rules, Vietnam's power development plan and offshore wind framework, Malaysia's energy exchange) is the main external risk.

Key numbers

Import target
About 6 GW of low-carbon electricity by 2035 (about a third of supply)
Conditional approvals granted
9.25 GW across 13 projects (Indonesia, Vietnam, Cambodia, Australia, Malaysia); six conditional licences (3 GW, all Indonesian)
Sun Cable conditional approval
1.75 GW, 22 October 2024; operation expected after 2035
LTMS-PIP hydro imports
Up to 100 MW since June 2022; second phase to double to 200 MW

Who gains and who pays

  • Import project developers (Sembcorp, Keppel, Sun Cable, Indonesian consortia) (gains): Long-term offtake into a high-price market conditional on delivery.
  • Domestic gas generators (costs): Lower load factors and prices once imports flow.
  • Retailers and consumers (gains): Diversified, lower-carbon supply with less LNG exposure over time.
  • Source-country governments and grids (mixed): Export revenue versus domestic supply and grid-priority concerns.
  • Subsea cable and storage suppliers (gains): Multi-gigawatt HVDC and firming demand.

Implementation

EMA converts conditional approvals into conditional licences as projects meet milestones; six Indonesian projects (3 GW) hold conditional licences. Financial close and cable-laying are the 2026 to 2028 milestones: EMA expects several projects to secure financing and reach final investment decision during 2026, and first commercial imports are targeted from 2028 for the Indonesian projects and around 2029 for Peninsular Malaysia. The ASEAN Power Grid and bilateral export frameworks are being negotiated in parallel. Watch EMA's import announcements and source-country export decisions.

Concerns

  • Source-country export approvals and political risk
  • Subsea cable supply chain, permitting through Indonesian and Malaysian waters, and cost
  • Reliability and firming requirements raising delivered prices
  • Stranding of domestic gas capacity and its effect on system security
  • Timeline slippage pushing the 2035 target

Dates to watch

  • 2026: Financing and final investment decisions for the first large import projects
  • 2028: Targeted first commercial imports from the Indonesian conditional-licence projects
  • 2035: 6 GW import target year

Sources

Checked against sources on .

Wholesale market interventions · temporary price cap and centralised procurement of new gas capacity

Singapore · Energy Market Authority · decision · 2023

Where it stands: Price cap operating since July 2023; centralised capacity process operating with three awards made and a 2032 tender open

Since July 2023 EMA has capped the Uniform Singapore Energy Price when it spikes above a cost-based threshold, and it now procures new combined-cycle capacity centrally (three hydrogen-ready units awarded so far: YTL PowerSeraya for 2027, PacificLight Power for 2029 and Tuas Power for 2031, with 2032 units under tender), moving new-build risk from merchant gencos to a state-run process.

The problem

In 2021 and 2022 the wholesale price spiked repeatedly to the S$4,500/MWh ceiling as LNG shortages and gas supply disruptions hit a system with thin reserve margins, several retailers collapsed, and consumers on wholesale-linked contracts faced extreme bills. EMA judged that the energy-only market was producing volatility without delivering investment, since no genco had committed to new capacity, and intervened on both price and quantity.

What it does

EMA introduced a Temporary Price Cap in the wholesale market from 1 July 2023: when the moving average of the USEP over 48 trading periods exceeds a trigger level set as a multiple (1.5 to 3 times, depending on the gas-price spread) of a combined-cycle plant's long-run marginal cost, the price is capped at that level for at least 48 periods; EMA publishes the parameters fortnightly and the mechanism was still operating in September 2026. Earlier measures included a standby LNG facility that EMA procures so gencos can draw gas at regulated terms during disruptions, and the Temporary Electricity Contracting Support Scheme to help retailers hedge. On capacity, EMA moved in 2023 to a Centralised Process for new generation in which it tenders for new combined-cycle units and provides a revenue support arrangement; the first award went to YTL PowerSeraya in January 2024 for a 600 MW-plus hydrogen-ready CCGT by end-2027, the second to PacificLight Power in January 2025 for 600 MW-plus by 2029, and the third to Tuas Power in August 2026 for a 670 MW unit by December 2031; a further tender for up to two units for 2032 closes on 30 September 2026 with award by 31 December 2026, against EMA's demand-growth forecast of 2.4 to 4.8 percent a year (peak demand of 9.6 to 11.4 GW by 2031), including data centres. Gencos remain merchant for existing plants.

Market effect

The price cap truncates the right tail of the USEP distribution: scarcity rents above the cap are removed, which lowers the value of peaking capacity and of wholesale-exposed retail contracts, and reduces the incentive for demand response in extreme hours. Combined with the centralised gas price through Gasco, most of the remaining USEP variation comes from fuel cost and outages rather than scarcity. Centralised capacity procurement means new entry is decided by EMA's forecasts rather than price signals, and the revenue support for tendered plants is recovered through market charges, adding a regulated cost element. For existing gencos the result is lower expected margins in tight years and a smaller share of future capacity; for consumers, fewer extreme bills but a structural charge. Electricity imports from 2027 onward will interact with both mechanisms, likely lowering the frequency of cap events.

Key numbers

Temporary Price Cap in force since
1 July 2023
Wholesale market price ceiling
S$4,500/MWh (market rule cap)
Centrally procured units
YTL PowerSeraya (600 MW-plus, 2027), PacificLight Power (600 MW-plus, 2029), Tuas Power (670 MW, December 2031)
Next tender
Up to two units for 2032; proposals close 30 September 2026, award by 31 December 2026
Demand growth assumption
2.4 to 4.8 percent a year; peak 9.6 to 11.4 GW by 2031

Who gains and who pays

  • Existing generation companies (costs): Scarcity rents capped; new capacity built through EMA tenders rather than merchant entry.
  • Electricity retailers (gains): Reduced exposure to extreme wholesale prices; hedging support.
  • Consumers on wholesale-linked or spot contracts (gains): Protection from price spikes; pay recovery charges.
  • Winners of centralised capacity tenders (gains): Revenue support for hydrogen-ready CCGT investment.
  • Demand-response and storage providers (costs): Lower value of responding to extreme prices.

Implementation

The price cap operates through EMC settlement rules and remains in force; EMA committed to review its parameters by the third quarter of 2025 and has not published a permanent replacement. The Centralised Process was adjusted on 7 April 2026 (supply planning horizon and entry management under the replanting framework, with a 27 percent reserve-margin trigger), and the cost-recovery framework under the Energy Transition Measures Act supports the revenue arrangements. Watch the award of the 2032 units by 31 December 2026 and any EMA determination on the price cap.

Concerns

  • Muted price signals reducing merchant investment and demand response
  • Forecast risk in centrally planned capacity (over- or under-build)
  • Recovery charges adding to consumer bills
  • Gas dependence extended by new CCGT build before hydrogen is available
  • Interaction with imports and the eventual design of a capacity mechanism

Dates to watch

  • 30 September 2026: Proposals close for the 2032 centrally procured units
  • 31 December 2026: Award of the 2032 units
  • 2027: YTL PowerSeraya unit target operation
  • 2029: PacificLight Power unit target operation

Sources

Checked against sources on .

Singapore carbon tax trajectory · S$25 (2024-25), S$45 (2026-27), S$50-80 by 2030

Singapore · Parliament of Singapore (Carbon Pricing (Amendment) Act 2022) · statute · 2022

Where it stands: Enacted; S$45 rate in force from 2026; 2030 rate to be set

Singapore's carbon tax, paid by power generators and large industrial emitters, rose from S$5 to S$25 per tonne in 2024 and to S$45 from 1 January 2026, with a 2030 range of S$50 to S$80; because the tax passes straight into the wholesale electricity price, it is the single largest policy driver of Singapore's power price after fuel.

The problem

Singapore generates about 95 percent of its electricity from imported LNG and pipeline gas and has almost no domestic renewable resource. To meet its net-zero-by-2050 target and 2030 NDC it needed a price signal strong enough to justify electricity imports, hydrogen-ready plants and efficiency, but the original S$5 per tonne rate from 2019 did nothing. The government chose a steep, pre-announced escalation with transition relief for trade-exposed industry.

What it does

The Carbon Pricing (Amendment) Act 2022, passed in November 2022, sets the tax on facilities emitting 25,000 tonnes CO2e or more a year at S$25 per tonne for 2024 and 2025, S$45 per tonne for 2026 and 2027, and a target of S$50 to S$80 per tonne by 2030. From 2024 taxable facilities may use eligible international carbon credits (Article 6-compliant, from countries with bilateral implementation agreements) to offset up to 5 percent of taxable emissions. A transition framework gives emissions-intensive trade-exposed facilities (refining, petrochemicals, semiconductors) allowances that reduce their effective tax for a period, subject to decarbonisation plans. Power generators receive no allowance and pass the tax through the wholesale market. The National Environment Agency administers the tax.

Market effect

A combined-cycle gas plant emits about 0.4 tonnes per MWh, so the tax adds roughly S$10 per MWh at S$25 and S$18 per MWh at S$45 to the marginal generator's cost, which the Uniform Singapore Energy Price reflects almost one-for-one because gas sets the price in nearly every period. That widens the gap that electricity imports from Malaysia, Indonesia, Vietnam and Australia must beat and improves the case for the 6 GW import target and for storage. Retailers pass the cost into contracts, so the 2026 step-up is visible in retail tariff resets. International credits at up to 5 percent cap the tax's bite for large emitters and create Singapore-specific demand for Article 6 credits from Ghana, Papua New Guinea and other partner countries. The 2030 range, to be set in a future budget, is the key uncertainty for long-dated power hedges.

Key numbers

2024-2025 rate
S$25 per tonne CO2e
2026-2027 rate
S$45 per tonne CO2e
2030 target range
S$50 to S$80 per tonne
Credit offset allowance
Up to 5 percent of taxable emissions with eligible international credits

Who gains and who pays

  • Power generation companies (Senoko, YTL PowerSeraya, Keppel, Sembcorp, Tuas Power) (obligation): Pay the tax on gas combustion; pass through in the wholesale market.
  • Electricity retailers and consumers (costs): Higher wholesale and retail prices as the tax steps up.
  • Electricity importers and storage developers (gains): Higher domestic gas-fired price improves import and arbitrage economics.
  • Refineries, petrochemical and semiconductor plants (mixed): Transition allowances soften the tax; still exposed to the 2030 range.
  • Article 6 credit suppliers (gains): Up to 5 percent of Singapore's taxable emissions can be met with eligible credits.

Implementation

The S$45 rate applies to 2026 emissions, assessed and paid in 2027. The 2030 rate will be set by a further amendment or announcement after a review, likely in a Budget statement around 2027 or 2028. Bilateral agreements for eligible international credits have been signed with several countries and the eligibility list is maintained by the National Environment Agency. Transition-framework allowances are reviewed periodically.

Concerns

  • Competitiveness of trade-exposed industry despite allowances
  • Electricity affordability as the tax steps up ahead of import supply
  • Integrity and supply of eligible Article 6 credits
  • Uncertainty over where in the S$50 to S$80 range 2030 will land
  • Limited domestic abatement options for gas-fired generation

Dates to watch

  • 2027: Expected announcement of the 2028-2030 carbon tax path
  • 1 January 2028: First year of post-2027 rate

Sources

Checked against sources on .