Australia weighs direct carbon costs for coal-fired power generators
Australia’s 2026–27 Safeguard Mechanism review could consider ending the electricity sector’s exemption from facility-level emissions rules. The change would raise costs for coal-fired generators and could affect wholesale power prices, carbon-credit demand and plant retirement schedules.
Electricity exemption faces scrutiny
Australia’s remaining coal-fired power stations could face direct carbon costs if the federal government removes electricity generation’s exemption from the Safeguard Mechanism. The issue is expected to form part of the mechanism’s 2026–27 review, as climate-policy advocates, renewable-energy investors and market analysts press for facility-level emissions limits.
The Safeguard Mechanism applies to large industrial facilities, with a default requirement for emissions baselines to decline by 4.9% annually. Electricity generation has instead operated under a collective sectoral baseline, a framework intended to avoid overlap with renewable-energy and other power-sector policies. Supporters of reform argue that this treatment leaves coal generators without the direct carbon liability imposed on major industrial emitters.
The debate comes as Australia targets a 60% to 70% reduction in economy-wide greenhouse-gas emissions from 2005 levels by 2035. International Business Times Australia reports that possible reforms would cover grid-connected fossil-fuel generators emitting more than 100,000 tonnes of carbon dioxide equivalent a year.
Facility limits would change generation costs
Under the proposal described by International Business Times Australia, individual plants would receive declining emissions baselines. Facilities exceeding those limits would have to surrender Australian Carbon Credit Units, known as ACCUs, or Safeguard Mechanism Credits. Plants potentially affected include AGL Energy’s Loy Yang A, EnergyAustralia’s Yallourn and Mt Piper, and Stanwell Corporation’s Stanwell power station.
ACCUs are reported to be trading at around A$37 to A$40 per tonne. Applying that cost to plant emissions could add A$30 to A$40 per megawatt-hour to the operating costs of black-coal generation and as much as A$50 per megawatt-hour for more emissions-intensive brown-coal plants. Coal bids in the National Electricity Market currently reflect fuel, operating and maintenance expenses without an equivalent facility-level carbon obligation.
The impact on electricity prices would vary with market conditions. When renewable output is low and coal plants set the marginal price, higher compliance costs could lift wholesale prices. During solar-heavy periods, coal units needing higher bids to recover carbon expenses could lose dispatch priority or continue operating at a financial loss.
Credit demand and closure schedules
Bringing power stations into the mechanism could also create substantial new demand for carbon credits because grid-connected coal plants collectively emit tens of millions of tonnes of carbon dioxide annually. The source reports that additional demand could consume available credit reserves, push ACCU prices higher and intensify pressure on carbon-intensive generators and other companies that need offsets.
The policy remains a proposal rather than an adopted rule. The Department of Climate Change, Energy, the Environment and Water is expected to publish consultation options, while formal legislative debate is scheduled for late 2026. A phased model could introduce plant-level baselines after 2027. For power companies, the review could influence decisions on coal-plant closure dates, renewable investment and the firming capacity needed to maintain supply as thermal generation retires.
