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Australia: 6 energy policy briefs

The energy policies moving Australia’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.

2026 Integrated System Plan · $16 billion of transmission on the optimal path, published 25 June 2026

Australia · Australian Energy Market Operator · plan · 2026

Where it stands: 2026 ISP published 25 June 2026 and operative; three newly actionable projects in non-network options consultation

AEMO's 2026 ISP, published on 25 June 2026, sets the optimal development path for the NEM to 2050: about $106 billion of annualised capital, $16 billion of upfront transmission capital, a 14 per cent (6,000 km) expansion of the 44,000 km grid and $30 billion of avoided cost for consumers. Actionable status in the ISP is what unlocks regulated revenue for HumeLink, VNI West, Marinus and three newly actionable Queensland and Tasmanian projects.

The problem

Australia's transmission network was built to move power from coal basins to capital cities. The resource that replaces coal sits elsewhere: wind in western Victoria, Tasmania, New England and central Queensland, solar in the Murray and central-west New South Wales, offshore wind in Gippsland. Without new lines the cheapest generation cannot reach load, renewable energy zones fill up and curtail, and interconnectors cannot share firming capacity between regions. Transmission is also the slowest element of the transition: a major line takes the better part of a decade from identified need to energisation, faces the hardest social licence problems of any energy infrastructure, and cannot be built speculatively because network revenue is regulated. The ISP exists to solve that coordination problem, giving transmission businesses a regulatory basis to spend ahead of generation that has not yet committed.

What it does

Prepared every two years under the National Electricity Rules, the ISP identifies an optimal development path and confers actionable status on specific projects, which lets a transmission network service provider run the regulatory investment test for transmission and seek an AER contingent project determination. AEMO published the 2026 ISP on 25 June 2026 after testing around 1,000 combinations of generation, storage, network and consumer investment across three scenarios, engaging close to 2,000 stakeholders and considering more than 300 submissions. Under the Step Change scenario the path involves about $106 billion in annualised capital costs to 2050 across generation, storage, transmission, distribution and system security; the upfront capital cost of the path's transmission projects is $16 billion in today's dollars, of which $6 billion is recognised to 2050. The current 44,000 km grid expands by about 14 per cent, or 6,000 km, with more than half the new lines already under way. Committed and actionable projects include HumeLink, VNI West, Project Marinus Stages 1 and 2, Project EnergyConnect, CopperString, Sydney Ring North and South, QNI Connect and the Central-West Orana, New England and Hunter-Central Coast renewable energy zone network infrastructure projects. Three projects are newly actionable in the 2026 ISP: the Brisbane Area 275 kV Reinforcement, Central to North Queensland Reinforcement Stage 1 and the Tasmania REZ Expansion, with AEMO calling for non-network options to meet their identified need by Thursday 17 September 2026. By 2050 the path delivers about 66 per cent of capacity from wind and solar supplying 96 per cent of annual generation, rising to about 98 per cent renewable with hydro, with flexible gas providing a small share of energy but critical backup.

Market effect

Actionable status is the single most valuable regulatory event in Australian transmission, because it converts a line from a study into a fundable asset with a path to a regulated revenue determination; conversely, projects dropped from the path lose their case, and several have been removed in the 2026 plan. The build reshapes locational value: AEMO estimates transmission saves consumers $30 billion under Step Change in avoided capital, operating and fuel costs compared with a path without these investments, and every megawatt of new interconnection narrows the interregional price spread that traders and battery owners monetise. Marinus and VNI West in particular move Tasmanian hydro and Victorian wind against mainland scarcity, compressing Tasmania-Victoria and Victoria-New South Wales spreads. For developers the signal is where to site: the ISP's indicative renewable energy zone boundaries and sub-regional traces tell you which connection points will have headroom, and with 67 GW of grid-scale renewables and storage in development against 34 GW operating, access is the binding constraint. For consumers the counterpart is bills, since the $16 billion is recovered through regulated network charges, which is why AER contingent project determinations for the large projects have been contested on cost. The non-network options consultation closing 17 September 2026 is a genuine opening for storage and demand response to displace part of the Queensland and Tasmanian network spend.

Key numbers

Annualised capital cost of the optimal development path to 2050
About $106 billion under Step Change, in today's dollars
Upfront transmission capital on the path
$16 billion, of which $6 billion is recognised to 2050
Modelled consumer saving from transmission
$30 billion in avoided capital, operating and fuel costs
Network expansion
About 6,000 km added to a 44,000 km grid, a 14 per cent increase
System mix by 2050
About 66 per cent of capacity from wind and solar, delivering 96 per cent of annual generation

Who gains and who pays

  • Transmission network service providers (gains): Actionable status underpins the RIT-T and AER contingent project revenue for HumeLink, VNI West, Marinus and the new projects.
  • Renewable developers in renewable energy zones (gains): New network capacity determines which connection points can host the 67 GW in development.
  • Electricity consumers (costs): Pay the $16 billion of transmission capital through regulated network charges against $30 billion of modelled avoided cost.
  • Interconnector-exposed traders and storage operators (mixed): New interconnection narrows the interregional spreads that support arbitrage.
  • Landholders and host communities (costs): Bear easement, amenity and land-use impacts of about 6,000 km of new lines.
  • Non-network providers of storage and demand response (gains): Can bid to meet the identified need for the three newly actionable projects by 17 September 2026.

Implementation

Actionable projects proceed through the regulatory investment test for transmission, an AER contingent project determination and then construction, with cost recovery through the network service provider's revenue determination; changed circumstances between plans are handled through ISP feedback loop notices. AEMO is consulting on non-network options for the Brisbane Area 275 kV Reinforcement, Central to North Queensland Reinforcement Stage 1 and the Tasmania REZ Expansion, with submissions due 17 September 2026. Inputs come from the 2025 Inputs, Assumptions and Scenarios Report published on 31 July 2025 and its addendum of 10 December 2025, and from the Demand Side Factors Information Guidelines developed between August and December 2025 in response to a December 2024 AEMC rule change requiring better treatment of demand-side factors in the ISP. State schemes, notably the New South Wales renewable energy zone network infrastructure projects and Victoria's transmission arrangements, deliver much of the actual construction, and a ministerial letter on the New England REZ network infrastructure project is published alongside the 2026 plan. The next plan is the 2028 ISP, whose consumer panel is already established.

Concerns

  • Delivery risk and cost escalation on HumeLink, VNI West and Marinus against the ISP's cost assumptions
  • Social licence and landholder opposition delaying easements and approvals
  • Recovery of $16 billion of transmission capital through consumer network charges
  • Generation committing ahead of, or behind, the network build, producing curtailment or underused lines
  • Scenario sensitivity: the path depends on Step Change demand and coal retirement assumptions
  • Workforce and supply chain constraints across simultaneous multi-billion-dollar projects

Dates to watch

  • 17 September 2026: Non-network options consultation closes for Brisbane Area 275 kV, Central to North Queensland Stage 1 and Tasmania REZ Expansion
  • 2027: Inputs, assumptions and scenarios consultation for the 2028 Integrated System Plan
  • 2028: Publication of the 2028 Integrated System Plan

Sources

Checked against sources on .

NEM Review (Nelson review) · final report 16 December 2025, draft NEL package open to 13 October 2026

Australia · Australian Government expert panel and the Energy and Climate Change Ministerial Council · consultation · 2025

Where it stands: Draft National Electricity Law bill and draft National Electricity Rules released for consultation on 14 September 2026 ahead of ministers' December 2026 decision

The independent review of NEM wholesale market settings reported on 16 December 2025; energy ministers other than Queensland agreed in principle that month and on an implementation approach in March 2026. A draft bill amending the National Electricity Law and draft National Electricity Rules are in consultation from 14 September to 13 October 2026, creating an Electricity Services Entry Mechanism, a Market Making Obligation and new visibility of price-responsive resources.

The problem

The NEM was designed as an energy-only market in which scarcity prices pay for capacity. With coal retiring, renewables setting the price at zero or below for long stretches and the Capacity Investment Scheme underwriting most new entry, the spot price no longer finances the plant the system needs, and the CIS itself is a contractual programme with an end date rather than a market design. The contract market has thinned: independent retailers and large customers struggle to buy firm hedges in some regions, which raises barriers to entry and concentrates risk with the large gentailers. At the same time a fast-growing mass of price-responsive resources, batteries behind the meter, flexible loads, virtual power plants and data centres, is largely invisible to AEMO's dispatch and forecasting. The Commonwealth announced the review in November 2024 to answer what replaces the CIS after 2027 without simply legislating a capacity market.

What it does

An independent expert panel supported by the Department of Climate Change, Energy, the Environment and Water ran the review, taking submissions on an initial consultation in early 2025 and on a draft report later that year, with the AEMC lodging submissions on 14 February 2025 and 17 September 2025 and publishing a working paper on supporting investment in the NEM. The final report was released on 16 December 2025. In December 2025 energy ministers apart from Queensland agreed in principle to the core recommendations, and in March 2026 all NEM jurisdictions except Queensland agreed on how to address them, recorded through the Energy and Climate Change Ministerial Council. The department established an implementation taskforce, an Industry Reference Group that has met monthly since 16 March 2026 and publishes its presentations, and, with AusEnergy Services Limited, a working group of eleven industry experts to co-design standardised electricity contracts. On 14 September 2026 the department released a draft regulatory reforms package for consultation until 11:59 pm AEDT on 13 October 2026, comprising a draft bill to amend the National Electricity Law and draft rules to amend the National Electricity Rules. The package implements three key recommendations: an Electricity Services Entry Mechanism to procure new generation and storage through standardised long-term contracts, a Market Making Obligation requiring firms to quote two-way prices in the contract market, and measures to increase the visibility of price-responsive resources. Three public webinars are scheduled for 24 September, 1 October and 6 October 2026, and the feedback will shape the National Electricity Law changes that ministers consider in December 2026.

Market effect

The entry mechanism would institutionalise what the CIS does contractually: instead of periodic Commonwealth tenders, a standing mechanism would procure firmed electricity services under standardised contracts, giving developers a repeatable revenue path and lenders a single credit assessment rather than a fresh agreement each round. That lowers the cost of capital for new entry but further displaces merchant investment, and the design of the standard contract, which the eleven-member working group is writing, will decide how much shape, firming and curtailment risk the seller retains. A Market Making Obligation targets the thinnest part of the market: forcing continuous two-way quotes in regional futures narrows bid-offer spreads, gives independent retailers and large customers a price at which they can actually hedge, and reduces the incumbency advantage of vertically integrated gentailers, at the cost of obligated parties carrying inventory risk. Price-responsive resource visibility changes AEMO's forecasting and, over time, dispatch: several gigawatts of behind-the-meter and flexible load currently appear as demand noise, and making them visible tightens reserve forecasts and reduces both over-procurement of reserves and surprise minimum-demand events. The live risk for participants is jurisdictional: Queensland has not joined, and because the National Electricity Law is a South Australian act applied by each jurisdiction, a Queensland carve-out would fragment a market that has run on one rulebook since 1998.

Key numbers

Final report released
16 December 2025, from a review announced in November 2024
Consultation window on the draft law and rules
14 September to 13 October 2026
Jurisdictions agreed
All NEM jurisdictions except Queensland, in principle December 2025 and on implementation March 2026
Core reforms in the draft package
Electricity Services Entry Mechanism, Market Making Obligation, price-responsive resource visibility
Contract co-design working group
11 industry experts convened with AusEnergy Services Limited

Who gains and who pays

  • New generation and storage developers (gains): A standing Electricity Services Entry Mechanism with standardised contracts would replace round-by-round CIS tendering.
  • Independent retailers and large energy users (gains): A Market Making Obligation should make firm hedges available at quotable prices in thin regions.
  • Large vertically integrated gentailers (obligation): Would carry market-making duties and lose part of their contract-market incumbency advantage.
  • Aggregators and owners of price-responsive resources (costs): New visibility and information obligations to AEMO for behind-the-meter and flexible load.
  • Queensland market participants (mixed): Queensland has not agreed to the package, raising the prospect of divergent rules in one NEM region.

Implementation

The National Electricity Law is a schedule to the National Electricity (South Australia) Act 1996 and is picked up by application acts in each participating jurisdiction, so the amending bill must pass the South Australian Parliament before it binds Queensland, New South Wales, Victoria, Tasmania and the ACT. The sequence is: consultation closes 13 October 2026; the department and the taskforce revise the bill and rules; energy ministers consider the package in December 2026; South Australian drafting, introduction and passage follow, with commencement by proclamation; ministers may make initial National Electricity Rules directly, after which the AEMC, AER and AEMO write the guidelines, procedures and systems that make the entry mechanism, market-making obligation and price-responsive resource obligations operational. On that timetable the earliest realistic date for a functioning entry mechanism is 2028, which matters because the Capacity Investment Scheme's dispatchable tenders are expected to end with Tender 10 in December 2026 and its generation tenders with Tender 12 in 2027.

Concerns

  • Queensland's non-participation fragmenting a single national rulebook
  • A gap between the last CIS tender and a working Electricity Services Entry Mechanism
  • Design risk in the standardised contract over who carries shape, firming and curtailment risk
  • Market-making obligations imposing inventory and balance-sheet cost on a small number of firms
  • Further displacement of merchant investment signals by centrally procured contracts
  • Legislative slippage, since the package must pass the South Australian Parliament before it binds the NEM

Dates to watch

  • 13 October 2026: Submissions close on the draft NEM Review regulatory reforms package
  • 2026-12: Energy Ministers consider the National Electricity Law changes
  • 2027: Introduction and passage of the amending bill in the South Australian Parliament, then commencement by proclamation

Sources

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Capacity Investment Scheme · 40 GW by 2030 after the 29 July 2025 uplift

Australia · Australian Government, Department of Climate Change, Energy, the Environment and Water · plan · 2023

Where it stands: Programme operating; eight national tenders plus two pilots awarded, with five further rounds scheduled through 2027

The Capacity Investment Scheme underwrites revenue for new renewable generation and clean dispatchable capacity through national tenders. Expanded to 32 GW on 23 November 2023 and uplifted to 40 GW on 29 July 2025 (26 GW generation, 14 GW dispatchable), it has already awarded about 22.7 GW of generation and about 11.5 GW of dispatchable capacity and is now the single largest determinant of what gets built in Australia.

The problem

Australia targets 82 per cent renewable electricity by 2030 and faces the retirement of most of its coal fleet within a decade, but the NEM's energy-only market was not producing new firm capacity fast enough. Merchant developers could not finance wind and solar against a spot price increasingly depressed by midday solar and increasingly volatile at the shoulders, while lenders would not underwrite four- and eight-hour batteries on arbitrage revenue alone. Power purchase agreement demand from corporates and state schemes was lumpy and regionally uneven, and the 2022 east-coast energy crisis showed how thin the reserve margin had become. The Commonwealth has no constitutional power over the National Electricity Rules, which belong to the states through the National Electricity Law, so it reached for the tool it does control: a contractual, competitively tendered revenue underwrite.

What it does

The scheme underwrites a project's revenue through a Capacity Investment Scheme Agreement, a long-term floor-and-ceiling arrangement that leaves the project merchant in the market but caps its downside and shares its upside with the Commonwealth. Launched as a pilot with New South Wales in 2023, it was expanded on 23 November 2023 to a national target of 32 GW (23 GW variable renewable generation, 9 GW clean dispatchable) and uplifted on 29 July 2025 to 40 GW (26 GW generation, 14 GW dispatchable), supporting about $73 billion of electricity-sector investment and rolling out from 2024 to 2027. AEMO and AusEnergy Services Limited administer the tenders; on 18 June 2025 the government moved from a two-stage to a single-stage tender process, and from Tender 9 a First Nations equity and revenue sharing set-aside reserves capacity for projects committing 5 per cent or more equity or revenue sharing. Results so far: NSW pilot 1,075 MW (22 November 2023); South Australia-Victoria pilot 995 MW and 3,626 MWh (4 September 2024); Tender 1 NEM generation, 19 projects, 6.4 GW (11 December 2024); Tender 2 WEM dispatchable, 654 MW and 2,595 MWh (20 March 2025); Tender 3 NEM dispatchable, 16 projects, 4.13 GW and 15.37 GWh (16 September 2025); Tender 4 NEM generation, 20 projects, 6.6 GW plus 11.4 GWh of hybrid batteries (9 October 2025); Tenders 5 and 6 in the WEM, 1.9 GW of generation and 482 MW and 3,683 MWh of dispatchable capacity (2 May 2026); Tender 7 NEM generation, 19 projects, 7.8 GW plus 7.9 GWh of hybrid batteries (23 May 2026); Tender 8 NEM dispatchable, 15 projects, 4.2 GW and 16.1 GWh (24 June 2026). Bilateral Renewable Energy Transformation Agreements guarantee each state and territory a minimum allocation.

Market effect

The scheme has effectively replaced the merchant investment case in Australia. Winning a CISA is now the practical precondition for financial close on utility-scale wind, solar and storage, so the auction outcome rather than the forward curve sets the build rate; unsuccessful bidders generally wait for the next round rather than proceed merchant. Because the underwrite is a floor and ceiling rather than a fixed price, projects remain exposed to dispatch decisions and negative prices, which keeps the five-minute price signal alive while removing the tail risk lenders would not take. The volume is large enough to move supply chains: Tender 7 alone cleared 7.8 GW of generation plus 7.9 GWh of associated hybrid batteries, and Tender 8 cleared 16.1 GWh of standalone storage, concentrating turbine, module and cell orders into a narrow window. For incumbents the effect is compression: roughly 22.7 GW of new generation and 11.5 GW of new dispatchable capacity entering by 2030 will deepen midday price troughs, flatten evening peaks and shorten the economic life of the remaining coal fleet. Tender 10, opening June 2026 with results due December 2026, is signalled as likely the final dispatchable tender, so the storage pipeline beyond it must stand on market revenue or on the successor mechanism proposed by the NEM Review.

Key numbers

Target after the 29 July 2025 uplift
40 GW by 2030: 26 GW renewable generation and 14 GW clean dispatchable
Original expansion target
32 GW announced 23 November 2023 (23 GW generation, 9 GW dispatchable)
Investment supported
About $73 billion across the 2024 to 2027 tender rounds
Generation awarded to date
About 22.7 GW across Tenders 1, 4, 5 and 7
Dispatchable awarded to date
About 11.5 GW, including 4.2 GW and 16.1 GWh in Tender 8 alone

Who gains and who pays

  • Renewable and storage developers with CIS agreements (gains): A revenue floor makes projects bankable; about 34 GW awarded across tenders and pilots to date.
  • Existing coal and gas generators (costs): Underwritten new entry depresses spot and cap prices and shortens remaining asset life.
  • Commonwealth taxpayers (obligation): Carry the downside of the underwrite and receive a share of upside revenue under each agreement.
  • First Nations communities (gains): From Tender 9 a set-aside reserves capacity for projects with 5 per cent or greater equity or revenue sharing.
  • Unsuccessful bidders and merchant developers (costs): Effectively locked out of financing until a later round; bid costs are sunk.

Implementation

Each successful bid is conditional on signing a Capacity Investment Scheme Agreement with the Commonwealth; AusEnergy Services Limited administers the tender, conducts due diligence and recommends bids on merit, with weighting on community and First Nations engagement, social licence, deliverability and reliability benefit. The department has confirmed that revenue underwriting for curtailment has never been included in an executed agreement, after consultation on the draft Tender 1 agreement removed a deemed-generation clause. Indicative 2026 rounds are Tender 9 (NEM generation, open May 2026, results November 2026), Tender 10 (NEM dispatchable, open June 2026, results December 2026 and likely the last dispatchable round), Tender 11 (WEM generation, open August 2026, results March 2027), Tender 12 (NEM generation, open November 2026, results June 2027) and a contingent Tender 13 that will not be needed if the dispatchable target is met in Tender 10. Awarded projects must still clear planning, connection and renewable energy zone access processes, which is where the delivery risk now sits.

Concerns

  • Concentration of the national build pipeline in a single Commonwealth counterparty and tender calendar
  • Connection, planning and transmission delays turning awarded capacity into late capacity
  • Contingent liability on the Commonwealth balance sheet if spot prices fall below the underwrite floors
  • Crowding out of merchant investment and weaker price-based entry signals
  • No confirmed successor mechanism once the dispatchable programme closes after Tender 10
  • Supply chain and labour cost escalation as multi-gigawatt rounds land close together

Dates to watch

  • 2026-11: Tender 9 results, the first round carrying the First Nations equity and revenue sharing set-aside
  • 2026-12: Tender 10 results, likely the final dispatchable tender under the scheme
  • 2027-03: Tender 11 (WEM generation) results
  • 2027-06: Tender 12 (NEM generation) results

Sources

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Safeguard Mechanism reform · baselines falling 4.9 per cent a year, review submissions close 18 September 2026

Australia · Parliament of Australia and the Minister for Climate Change and Energy (NGER Act and Safeguard Rules) · statute · 2023

Where it stands: Reformed mechanism binding since 1 July 2023; statutory 2026-27 review open with submissions closing 18 September 2026

The 2023 reform turned a dormant emissions cap into Australia's only binding industrial carbon constraint: baselines at facilities emitting over 100,000 tonnes CO2-e fall about 4.9 per cent a year to 2030, tradeable Safeguard Mechanism Credits reward over-performance, and grid-connected generators sit under a single sectoral baseline. The statutory 2026-27 review is open, with submissions closing 18 September 2026, against a new 2035 target of 62 to 70 per cent below 2005 levels.

The problem

The Safeguard Mechanism commenced in 2016 with baselines set so loosely that covered emissions rose rather than fell; it capped nothing and priced nothing. After the Climate Change Act 2022 legislated a 43 per cent reduction below 2005 levels by 2030 and net zero by 2050, the government needed the industrial sector, roughly a third of national emissions, to contribute without a broad carbon price it could not pass through Parliament. Electricity posed a separate design problem: putting facility baselines on individual power stations would have collided with the National Electricity Market's merit order and with state renewable schemes, so generation needed different treatment. Trade-exposed producers of aluminium, steel, cement, ammonia and LNG argued that a unilateral constraint would move production offshore rather than reduce global emissions, so the reform had to carry a leakage safety valve.

What it does

The Safeguard Mechanism (Crediting) Amendment Act 2023 amended the National Greenhouse and Energy Reporting Act 2007, and the amended National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule 2015 carries the detail, with the Minister required under sections 22XS(1A) and (1B) to publish a statement of reasons that the rules deliver the legislated safeguard outcomes. From 1 July 2023 baselines at facilities emitting more than 100,000 tonnes CO2-e a year decline in general by 4.9 per cent annually to 2030, applying to existing and new facilities alike. Baselines are production-adjusted: facility production is multiplied by an emissions-intensity value set, for existing facilities, at the average of Australian industry performance with transitional arrangements to 2030, and for new facilities and new products at international best-practice benchmarks published in Schedule 1 of the Safeguard Rules. Facilities that beat their baseline earn tradeable Safeguard Mechanism Credits; those that exceed it must surrender credits or Australian Carbon Credit Units. Trade-exposed facilities are listed in Schedule 2, and a subset facing elevated carbon-leakage risk can apply to the Clean Energy Regulator for trade-exposed baseline-adjusted status, giving a reduced decline rate for three years based on a prescribed scheme impact metric calculated using the published EBIT guidelines and the department's default prescribed unit price, set at $36.99 for 2025-26 after $36.05 in 2024-25 and $33.19 in 2023-24. Electricity is treated differently: a single sectoral baseline covers all generators connected to the main grids, and individual grid-connected generators are not covered unless total sector emissions exceed that baseline. The Powering the Regions Fund supports industrial decarbonisation, with round 2 opening on 27 January 2026.

Market effect

The mechanism creates a compliance carbon market and an implicit industrial carbon cost that the department itself benchmarks at $36.99 a tonne for 2025-26. That price sits well below European levels, so the reform has not reordered the industrial merit order, but it changes project economics at the margin for new LNG trains, ammonia plants and mines, which must meet international best-practice benchmarks from day one rather than the softer Australian average. Demand for ACCUs is now anchored by Safeguard compliance rather than voluntary buyers, which supports the ACCU spot price and has pulled forward method development in savanna burning, soil carbon and landfill gas. For power traders the important design choice is the sectoral electricity baseline: a coal plant faces no facility-level carbon cost, so NEM dispatch order is still set by fuel and by the Capacity Investment Scheme, not by the Safeguard Mechanism. That could change if the 2026-27 review recasts electricity coverage, and the 2035 target of 62 to 70 per cent below 2005 levels, adopted on the Climate Change Authority's advice and submitted in Australia's September 2025 Nationally Determined Contribution, implies a steeper post-2030 decline rate than 4.9 per cent. Any such change would show up first in ACCU forward prices and in the hurdle rates applied to new gas-fired generation with material fugitive or combustion emissions.

Key numbers

Coverage threshold
Facilities emitting more than 100,000 tonnes CO2-e a year
Baseline decline rate
About 4.9 per cent a year to 2030
Default prescribed unit price 2025-26
$36.99 per tonne (2024-25: $36.05; 2023-24: $33.19)
National targets
43 per cent below 2005 by 2030, 62 to 70 per cent by 2035, net zero by 2050

Who gains and who pays

  • Covered industrial facilities in mining, oil and gas, manufacturing and waste (obligation): Must keep net emissions at or below a declining baseline or surrender Safeguard Mechanism Credits and ACCUs.
  • Trade-exposed baseline-adjusted facilities (mixed): Can obtain a reduced decline rate for three years but must document EBIT or revenue impact to the Clean Energy Regulator.
  • ACCU project developers and carbon traders (gains): Compliance demand underpins the ACCU market and credit trading.
  • Grid-connected electricity generators (gains): Covered only through a single sectoral baseline, so no facility-level carbon cost enters NEM dispatch.
  • New entrants with emissions-intensive projects (costs): Baselines set at international best practice rather than the Australian industry average.

Implementation

The Clean Energy Regulator administers the scheme under the NGER framework, determines each facility's baseline annually, issues Safeguard Mechanism Credits and publishes facility-level baselines, covered emissions, net emissions, credits earned and units surrendered by method. Production variables and international best-practice benchmarks have been updated by legislative instrument in 2023 and 2024, each accompanied by a ministerial statement of reasons. The department must publish the default prescribed unit price by 30 June each year and issues quarterly year-to-date interim estimates. The statutory 2026-27 review is now under way: stakeholder consultation has opened and written submissions close at 11:59 pm AEST on Friday 18 September 2026. That review is the vehicle for deciding the post-2030 decline rate, whether the trade-exposed arrangements continue, and how the electricity sectoral baseline interacts with the 2035 target. Legislative instruments made under the NGER Act remain subject to disallowance by either house within 15 sitting days, so the detail can be reopened politically even after it is made.

Concerns

  • Carbon leakage and competitiveness for trade-exposed producers as decline rates continue past 2030
  • Reliance on ACCU integrity, since surrendered offsets substitute for on-site abatement
  • The electricity sectoral baseline leaves NEM dispatch untouched by any carbon cost
  • Uncertainty over the post-2030 decline rate until the 2026-27 review reports
  • Disallowance risk for the rules and benchmark instruments that carry most of the detail
  • Interaction with new LNG and critical minerals projects seeking best-practice baselines

Dates to watch

  • 18 September 2026: Written submissions close for the 2026-27 Safeguard Mechanism Review
  • 2027: Government response to the review and any amendment of the Safeguard Rules
  • 2030: End of the legislated 4.9 per cent decline trajectory and of transitional emissions-intensity arrangements

Sources

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NSW Electricity Infrastructure Roadmap · 12 GW generation, 2 GW long-duration storage, Eraring to April 2029

Australia · Parliament of New South Wales (Electricity Infrastructure Investment Act 2020 No 44) · statute · 2020

Where it stands: Act No 44 of 2020 operating; five renewable energy zones declared, 10.71 GW of access rights awarded and Eraring extended to April 2029

New South Wales legislated its own procurement machine in 2020: the Electricity Infrastructure Investment Act creates renewable energy zones and long-term energy service agreements to deliver at least 12 GW of renewable generation and 2 GW of long-duration storage, mobilising more than $77 billion of private investment by 2035. With 10.71 GW of REZ access rights awarded and Eraring now running to April 2029, it is the largest single state intervention in the NEM.

The problem

New South Wales is the NEM's largest load centre and its most exposed to coal retirement: Liddell closed in 2023, Eraring is the largest single generator in the market, and Bayswater and Vales Point follow. The state's best wind and solar resources sit in the central west, the New England tablelands and the south west, far from the transmission built for the Hunter and Lake Macquarie coal fleet, and the national market was never going to fund that network ahead of the generation. The 2019 NSW Electricity Strategy concluded that without state coordination the replacement capacity would arrive late, in the wrong places and at a price consumers would pay through scarcity. The design problem was to give developers bankable long-dated revenue and to give the network a reason to build first, without the state simply owning the assets.

What it does

The Electricity Infrastructure Investment Act 2020 No 44, in force since December 2020, implements the Roadmap released in November 2020. It creates a Consumer Trustee (AEMO Services) that runs competitive tenders for long-term energy service agreements covering generation, long-duration storage and firming, an Infrastructure Planner to declare and coordinate renewable energy zones, a Regulator and a Scheme Financial Vehicle funded through a contribution order on NSW customers. The statutory minimum objectives are at least 12 GW of new renewable electricity generation and 2 GW of long-duration storage such as pumped hydro and long-duration batteries, underpinning more than $77 billion of private-sector investment in the NSW economy by 2035. Five renewable energy zones were declared, and the government has awarded 10.71 GW of access rights across the Central-West Orana and South West zones alone. On coal, after AEMO's May 2024 update to the 2023 Electricity Statement of Opportunities found a forecast reliability gap in NSW from 2025-26 if Eraring closed in August 2025, the government announced on 23 May 2024 that Origin had agreed to operate Eraring until August 2027 in return for a government underwrite against a share of potential loss, with a profit share back to government if the underwrite is taken up; the agreement was tabled in Parliament on 4 June 2024 and an evaluation summary with commercial advice and modelling on 6 August 2024. On 20 January 2026 Origin advised AEMO it will operate Eraring until April 2029 and must cease operation of all units and deregister the power station by no later than 30 April 2029. Origin has not opted in to the underwriting arrangement in either 2025-26 or 2026-27 and no payments have been made. The Act is now being extended to large loads: the Electricity Infrastructure Investment Amendment Bill 2026, a Government Bill introduced in the Legislative Assembly on 5 August 2026 and passed there with amendments on 15 September 2026, lets the Minister declare a large load infrastructure access scheme over all or part of the State, authorising or prohibiting access by large load infrastructure to specified network infrastructure. It directs the Consumer Trustee, when setting access-scheme fees, to make proponents of large load infrastructure responsible for the network infrastructure needed to supply them so that other NSW customers do not pay for it, and lets regulations modify or disapply the National Electricity (NSW) Law and Rules to impose connection requirements on those proponents and to make network service providers manage the reliability and security impacts of connecting them. The Bill went to the Legislative Council for concurrence on 16 September 2026 and commences on assent. A separate non-government bill, the Energy and Other Legislation Amendment (Renewable Energy Infrastructure) Bill 2026 (No 2) introduced by Mr J H Griffin MP on 14 May 2026, would make the efficient decommissioning of solar and wind infrastructure and the remediation of its land objects of the Act and require the NSW renewable energy sector board to plan for them; it would also require environment protection licences for certain solar generating works, Ministerial consent (on a fit and proper person test) to transfer a wind or solar licence, and development consent conditions requiring decommissioning, remediation and security. It has not advanced beyond introduction.

Market effect

The long-term energy service agreement is a long-dated option on revenue rather than a fixed-price contract, so NSW projects can be financed without surrendering all upside, and the tender outcomes have become a second reference price alongside the Commonwealth's Capacity Investment Scheme, with several projects pursuing both. Awarding 10.71 GW of access rights in Central-West Orana and the South West converts zone capacity into a scarce, allocated right, pricing congestion explicitly rather than leaving developers to discover it after connection, and it determines which projects can bid credibly into future tenders. On the demand side the contribution order puts the scheme's cost on NSW customers, so the state is trading a near-term bill impact against avoided scarcity later. The Eraring decisions are the most consequential single fact for east-coast forward prices: a large baseload plant running to April 2029 rather than exiting in August 2025 has kept NSW cap and swap prices for 2026 to 2029 materially below what an early exit implied, and the fact that Origin has declined the underwrite in both eligible years signals the plant is running profitably on its own account, at no cost to the state so far. Traders should treat 30 April 2029 as a hard deregistration date and price the 2029-30 NSW summer against the storage and zone capacity contracted to replace it. The large load amendment matters for data-centre siting: once a scheme is declared, network access for large loads becomes an allocated, priced right like REZ access, with the cost of supplying the connection placed on the proponent rather than socialised through NSW network tariffs.

Key numbers

Statutory minimum objectives
At least 12 GW of new renewable generation and 2 GW of long-duration storage
Private investment mobilised
More than $77 billion into the NSW economy by 2035
REZ access rights awarded
10.71 GW across the Central-West Orana and South West renewable energy zones
Eraring deregistration deadline
All units to cease operating and deregister by no later than 30 April 2029
Progress against the generation objective
More than 75 per cent of the minimum 12 GW signed up for 2030
Pending amendment
Electricity Infrastructure Investment Amendment Bill 2026: introduced 5 August 2026, passed the Legislative Assembly with amendments 15 September 2026, in the Legislative Council since 16 September 2026; commences on assent
Retrospective regulations
As amended in the Assembly, regulations made under the new or amended provisions may commence on or after 3 March 2026, including before the day they are published
Non-government decommissioning bill
Energy and Other Legislation Amendment (Renewable Energy Infrastructure) Bill 2026 (No 2), introduced in the Legislative Assembly 14 May 2026 by Mr J H Griffin MP; no further stage recorded as of 23 September 2026; would commence on assent

Who gains and who pays

  • Renewable and long-duration storage developers in NSW (gains): Long-term energy service agreements and REZ access rights provide long-dated revenue and firm network capacity.
  • NSW electricity consumers (costs): Fund the scheme through a contribution order and carry the contingent Eraring underwrite exposure.
  • Origin Energy and other coal generators (mixed): Eraring gained a state backstop and a longer run to April 2029 but faces a hard deregistration date.
  • Transgrid and network businesses (gains): REZ network infrastructure projects plus $8.4 million in grants to Transgrid and AEMO for engineering capacity.
  • Merchant peakers and storage relying on scarcity (costs): Extended coal operation and contracted new entry suppress NSW cap and spot volatility until 2029.
  • Data-centre and other large-load proponents in NSW (costs): Under the pending amendment, access to specified network infrastructure can be allocated through a large load access scheme and proponents bear the cost of the network needed to supply them.

Implementation

AEMO Services as Consumer Trustee runs tender rounds against an infrastructure investment objectives report, awarding long-term energy service agreements for generation, long-duration storage and firming; the state has contracted enough projects to meet both the 2030 and 2034 minimum objectives for long-duration storage and more than 75 per cent of the 12 GW generation objective for 2030. Renewable energy zone declarations, access schemes and network infrastructure projects run in parallel, with the Central-West Orana and New England network infrastructure projects also carried as actionable projects in AEMO's 2026 Integrated System Plan. Supporting measures include $8.4 million in grants to Transgrid and AEMO to hire engineers and accelerate storage connections, Peak Demand Reduction Scheme incentives and regular Energy Security Target Monitor reporting. The Eraring agreement remains live: Origin may opt in to the underwrite in a future year and the profit-share obligation attaches only if it does. The binding constraints now are connection queue throughput, planning approvals and workforce rather than capital.

Concerns

  • Concentration of NSW replacement capacity behind a small number of renewable energy zone network projects
  • Cost recovery from NSW consumers through the contribution order and any underwrite drawdown
  • A hard deregistration date of 30 April 2029 for Eraring with limited slack if new capacity slips
  • Connection and commissioning queues limiting how fast contracted projects actually energise
  • Overlap between NSW long-term energy service agreements and Commonwealth CIS contracts
  • Social licence and landholder resistance in the Central-West Orana and New England zones
  • Regulations under the large load amendment may operate retrospectively from 3 March 2026, and the size threshold that makes a connection "large load infrastructure" is left to regulations rather than set in the Act
  • End-of-life decommissioning and land remediation for solar and wind projects is not an object of the Act; a non-government bill to add it, with licensing and security requirements, has not advanced since its introduction on 14 May 2026

Dates to watch

  • 2026: Legislative Council vote on the Electricity Infrastructure Investment Amendment Bill 2026 (large load access schemes); the Act commences on assent
  • 2027: Origin's annual decision on whether to opt in to the Eraring underwrite for 2027-28
  • 30 April 2029: Latest date for Eraring to cease operation of all units and deregister
  • 2030: Deadline for the minimum 12 GW renewable generation objective

Sources

Checked against sources on .

Five-minute settlement and storage participation · AEMC rule 2017 No. 15, live 1 October 2021

Australia · Australian Energy Market Commission · rule · 2017

Where it stands: Five-minute settlement operating since October 2021 and the storage rule since June 2024; Reliability Panel settings review completed April 2026

The AEMC's 2017 five-minute settlement rule aligned NEM financial settlement with five-minute dispatch from 1 October 2021, and its 2021 storage rule created the Integrated Resource Provider category from 3 June 2024. Together they are the price architecture behind Australia's grid-battery build, and the Reliability Panel's April 2026 review has now set the price caps and reliability standard that follow from 2028.

The problem

From market start the NEM dispatched generators every five minutes but settled them on the thirty-minute average of six dispatch prices. A plant that could respond in seconds was paid the same as one that took half an hour, so the settlement price rewarded slow, inflexible plant and invited rebidding games in the last dispatch interval of each trading period. Batteries, demand response and fast gas peakers captured only a fraction of the value they actually delivered, and the disconnect grew as coal retired and variable renewables made the within-hour price shape steeper. A second, narrower problem was registration: the National Electricity Rules had no category for a device that both consumes and injects, so grid-scale batteries and solar-plus-storage hybrids had to register twice, once as a generator and once as a market customer, with duplicated standards, forecasting duties and non-energy cost allocations.

What it does

On 28 November 2017 the AEMC made a more preferable final rule, the National Electricity Amendment (Five Minute Settlement) Rule 2017 No. 15, on a rule change request from Sun Metals, a zinc refinery. Schedules 1 to 6 were to start on 1 July 2021; the National Electricity Amendment (Delayed implementation of five minute and global settlement) Rule 2020 No. 10 moved commencement to 1 October 2021, when the spot price settlement interval fell from 30 minutes to five. On 2 December 2021 the Commission made the Integrating Energy Storage Systems into the NEM final rule, on an AEMO request lodged 23 August 2019; Schedules 1 to 6 commenced on 3 June 2024, creating the Integrated Resource Provider registration category, allowing DC-coupled hybrids to choose whether they are scheduled or semi-scheduled, letting aggregators of small generating and storage units provide market ancillary services from both generation and load, and moving non-energy cost recovery onto consumed and sent-out energy regardless of registration category. Existing grid-scale storage transferred to the new category at no charge, with connection agreements and performance standards untouched. On 23 April 2026 the Reliability Panel published the final report of the 2026 Reliability Standard and Settings Review, recommending for 1 July 2028 to 30 June 2032 a reliability standard of 0.003 per cent unserved energy (99.997 per cent, loosened from 99.998 per cent), retention of the market price cap at $22,800/MWh and the cumulative price threshold at $2,325,600 (both in 2022 dollars), retention of the market floor price at -$1,000/MWh with automatic clearing at the floor during Minimum System Load level 3 conditions, and retention of the administered price cap and floor at $600/MWh and -$600/MWh.

Market effect

Five-minute settlement moved revenue from slow plant to fast plant without moving a single subsidy dollar. Because a battery can capture the full $22,800/MWh cap in a single five-minute interval rather than seeing it diluted across a thirty-minute average, arbitrage and contingency FCAS revenue per megawatt rose sharply, and grid-scale storage went from a curiosity to the default new-build peaker; AEMO's 2026 Integrated System Plan records 34 GW of grid-scale renewables and storage already operating in the NEM with a further 67 GW in development. The same change compressed the value of thirty-minute-shaped hedges and forced retailers and traders to re-cut their contract books and risk models around five-minute exposure. The Integrated Resource Provider category then cut registration cost and duplication for hybrids, which is part of why almost every Capacity Investment Scheme generation award since 2024 has been a solar-or-wind-plus-battery hybrid rather than a bare renewable. The Panel's April 2026 decision to hold the cap at $22,800 rather than raise it, and to loosen the reliability standard from an average of about 10 minutes to about 16 minutes of unserved energy a year, caps the scarcity rent available to merchant peakers and storage for the 2028 to 2032 period and pushes investors toward contracted revenue under the CIS and the proposed Electricity Services Entry Mechanism instead.

Key numbers

Settlement interval
5 minutes, from 1 October 2021 (final rule made 28 November 2017)
Storage registration category live
Integrated Resource Provider, 3 June 2024
Market price cap recommended for 2028-2032
$22,800/MWh in 2022 dollars, with a cumulative price threshold of $2,325,600
Recommended reliability standard
0.003 per cent unserved energy, about 16 minutes a year, down from 0.002 per cent
NEM grid-scale renewables and storage
34 GW operating, 67 GW in development (2026 ISP)

Who gains and who pays

  • Grid-scale battery and hybrid developers (gains): Five-minute prices and the Integrated Resource Provider category convert fast response into settled revenue.
  • Aggregators and demand response providers (gains): Can register once and offer market ancillary services from generation and load.
  • Coal and slow mid-merit generators (costs): Lose the averaging benefit that paid them for ramping they could not deliver.
  • Retailers and hedge counterparties (mixed): Had to rebuild contract, metering and settlement systems around five-minute exposure.
  • Merchant peaking investors (costs): The 2026 Panel review holds the market price cap flat and loosens the reliability standard, capping scarcity rent to 2032.

Implementation

AEMO rebuilt dispatch, settlement and metering systems for the 2021 go-live and ran a multi-year participant readiness programme; metering data now flows at five-minute granularity, which is also the basis of global settlement. The storage rule required AEMO procedure changes, a transfer process for existing batteries into the Integrated Resource Provider category and new performance standard templates, completed for the 3 June 2024 commencement. The Reliability Panel's recommendations are advice, not rules: the AEMC must now give effect to the reliability standard and market price settings for the period beginning 1 July 2028, and any change flows into AEMO's dispatch engine, the Retailer Reliability Obligation trigger and every cap contract written for that period. Watch also the interaction with the NEM Review package, which would add a Market Making Obligation and greater visibility of price-responsive resources on top of this architecture, and the unresolved question of how network charges should be recovered from storage and other large responsive loads, which the Commission deliberately left to a future rule change.

Concerns

  • Holding the market price cap flat in nominal 2022 dollars erodes the real scarcity signal for merchant storage
  • A looser reliability standard shifts more of the reliability job onto out-of-market and jurisdictional interventions
  • Five-minute exposure concentrates risk on retailers with thin hedge books
  • Non-energy cost allocation and network charging for storage remain unresolved and are handled case by case
  • Increasing reliance on contracted revenue under the CIS weakens the investment signal five-minute pricing was meant to sharpen

Dates to watch

  • 2027: AEMC gives effect to the Reliability Panel's reliability standard and market price settings recommendations
  • 1 July 2028: New reliability standard of 0.003 per cent unserved energy and market price settings take effect
  • 30 June 2032: End of the settings period recommended by the 2026 review

Sources

Checked against sources on .