How The Grid Works — And What Is Closing The Coal Plants

Electricity cannot be stored at scale in the grid, so supply must equal demand every five minutes. That single constraint explains why coal plants are closing, why no carbon rule is doing it, and why the government decarbonised electricity by building rather than by capping. It is an explainer: it describes the system and does not propose changes to it. The credit scheme applied to the rest of the economy is covered in Memo 32.

1. The physical constraint

Electricity is not like other commodities. It cannot be produced now and sold later. At every instant, generation across the grid must equal consumption across the grid, or frequency drifts and equipment trips off. The market operator, AEMO, matches the two every five minutes, all day, every day.

That single constraint explains most of what follows.

• Output is set by demand, not by the generator. A power station does not decide how much to produce. It offers a price, and AEMO takes what it needs, cheapest first, until demand is met. Everything above that point is not dispatched and earns nothing.
• The last generator taken sets the price for all of them. If gas is needed to meet the final increment of demand, gas sets the price and every generator dispatched that interval receives it — including the solar farm that bid zero.
• Wind and solar bid at or near zero, because their fuel is free. They are taken first whenever they are producing.
• Coal cannot get out of the way. A coal unit takes hours to ramp down and hours to bring back, with cost and wear each time. When demand is met without it, it often keeps running through the middle of the day at negative prices — paying to generate rather than shutting down and restarting.

So the effect of adding solar is not that coal is out-competed hour by hour on fuel cost. It is that coal loses the middle of the day entirely, and has to recover the same fixed costs across far fewer running hours. That is what makes a paid-off coal plant unprofitable while nothing about the coal has changed.

2. Where electricity sits in carbon policy

Electricity is the largest emitting sector in the country, and it is not inside the Safeguard Mechanism. That is not a gap in the accounts. Electricity emissions are counted in full in the national inventory and count against Australia’s targets. What differs is the instrument used to bring them down.

Australia runs two tracks.

3. Where generators are captured

In four places, none of them the Safeguard Mechanism.

• They report. Every generator reports emissions under National Greenhouse and Energy Reporting, and the Clean Energy Regulator publishes electricity sector emissions and generation data each year. Nothing is hidden.
• They count. Those emissions are in the national inventory and count against the 43 per cent by 2030 and net zero by 2050 targets.
• They are pushed by a certificate market. The Renewable Energy Target obliges electricity retailers to surrender large-scale generation certificates, which pays new renewable generation to enter the market and displace fossil generation.
• They are pushed harder by direct funding. The Capacity Investment Scheme underwrites 32 GW of new capacity by 2030, Rewiring the Nation provides $20 billion of transmission finance, and the states run their own renewable energy zones and roadmaps. The target is 82 per cent renewables by 2030.

The sectoral cap of 198 million tonnes sits behind all of that as a backstop. It is set from the sector’s 2009–10 to 2013–14 emissions, it does not decline, and the department states it “is not expected to be exceeded”. If the sector ever went over it, the sectoral cap would fall away and every generator would receive an individual cap. The sector is around 148 million tonnes and falling, so in practice no grid-connected power station faces a compliance obligation.

Two things at a power station are inside the Safeguard Mechanism: an off-grid generator, such as one serving a mine, gets a facility cap and the full obligation; and non-generation emissions, such as fugitive methane from an attached coal mine, are covered above 100,000 tonnes. Anti-avoidance rules also stop a facility attaching itself to a power station to escape its own cap.

4. Why electricity was kept out of cap-and-credit

The reason generators were left out is an engineering one, and it holds. Generation is dispatched centrally by AEMO to meet demand in real time. A generator holding back output to stay inside its own cap would simply be replaced by another, possibly dirtier, generator. Electricity cannot be supplied below demand to satisfy an accounting limit.

So the government concluded that the largest emitting sector in the country could not usefully be decarbonised by capping and trading, and decarbonised it by building instead. That decision is the reason electricity emissions have fallen faster than any other sector’s.

Electricity emissions have fallen faster than any other sector’s since. Whether the same approach suits sectors currently inside the credit scheme is a separate question, and the credit scheme is set out in Memo 32.

5. What is closing the coal plants

Nothing in the scheme requires a coal plant to close. The sectoral cap has never bound, no generator has ever surrendered a credit, and there is no legislated closure date. The question is worth asking directly: if the cap is not doing it, what is?

Price is doing it. Coal plants are increasingly forced to switch off during daylight hours when solar undercuts them, which strands their fixed costs across fewer running hours. Eraring was closed early because market analysis identified it as the plant most exposed to renewable growth and likely to lose significant money. Around three quarters of Australia’s coal fleet is expected to close by 2035 on that basis.

And where government has intervened, it has intervened to keep plants open, not to shut them.

• Eraring — 2,880 MW, up to a quarter of NSW electricity — was due to close in 2025. AEMO identified a reliability gap without it. NSW underwrote it for up to $450 million over two years, covering up to $225 million of losses a year in return for a share of profits. Closure moved to August 2027, and must occur before April 2029. Origin has not opted into the underwriting and no public money has been paid.
• NSW also placed a cap on the coal price generators pay, to protect their profitability.
• Victoria has made two undisclosed agreements with coal generator owners to keep plants online. Yallourn’s closure was brought forward to 2028 alongside a confidential state subsidy arrangement.
• Western Australia has continued supporting a bankrupted coal mine, having already spent more than $300 million.

What AEMO says about NSW after Eraring

The reliability case for delaying Eraring rests on AEMO’s forecasts, and those forecasts do not agree with each other.

• AEMO’s Electricity Statement of Opportunities of August 2025 found that NSW reliability had improved, with no breaches forecast after Eraring closes.
• AEMO’s Medium Term Projected Assessment of System Adequacy, a weekly simulation, shows NSW from August 2027 — immediately after the scheduled closure — with up to 0.6 per cent of energy unserved in a month.

On the Centre for Independent Studies’ reading, that second figure is almost 300 times the Reliability Standard and around 1,000 times the Interim Reliability Measure that is actually in force. The two publications are months apart, from the same operator, and point in opposite directions. The discrepancy was reported by The Australian in 2026.

This memo takes no position on which forecast is correct. The observation is that the public case for paying to delay a coal closure depends on reliability modelling that the operator’s own outputs do not agree on, and that the modelling is not presented in a form that allows the two to be reconciled from outside.

So the position is the reverse of how it is usually described. The carbon scheme is not closing coal plants. Economics is closing them, faster than the replacement capacity is arriving, and governments are paying to slow that down for reliability reasons.

This memo takes no issue with those interventions. Keeping the lights on while replacement capacity is built is a legitimate reason to delay a closure. The observation is narrower: the mechanism that is actually retiring coal generation in Australia is the price of the alternative, and the constraint on going faster is how quickly the replacement gets built. Neither of those is a function of the Safeguard Mechanism.

6. How the build is going

• Transmission costs are 25 to 55 per cent higher in real terms than 2022, and the hold-up is building it rather than inventing it.
• HumeLink has run 190 per cent over, from $1.1bn to $3.3bn. Marinus Link 250 per cent, from $1.1bn to $3.8bn. Project EnergyConnect 84 per cent, from $2.23bn to $4.1bn.
• The household battery programme has moved from an original estimate of $2.3 billion to about $7.2 billion over four years.
• And grid decarbonisation does not reach transport. A vehicle burning imported diesel is unaffected by the fuel mix of the grid it drives past.

The plan the build is based on is contested

The build follows AEMO’s Integrated System Plan, published every two years, which sets the “optimal development path” for generation, storage and transmission to 2050. The 2026 ISP was released this year after 18 months of consultation, 1,400 stakeholders and 241 written submissions.

It is under external challenge on two specific modelling points, raised by the Centre for Independent Studies and answered by AEMO in its own 2026 ISP webinar.

• Coal retirement timing. Whether it is realistic to expect close to 5 GW of coal to retire in 2029.
• Battery revenue. How the plan models battery earnings, given that batteries need a price spread between cheap and expensive periods to earn revenue, and that adding batteries compresses that spread.

The CIS position, following those answers, is that the ISP is “merely an exercise in fitting new transmission projects to the government’s arbitrary renewables targets” rather than a least-cost plan. AEMO’s position is that the 2026 ISP reaffirms renewables firmed with storage and backed by gas as the least-cost path.

Separately, the Australian Energy Market Commission is reviewing the ISP framework itself — the rules and regulations that govern how the plan is made. The Centre for Independent Studies lodged a submission to that review on 3 March 2026.

This memo does not adjudicate the modelling. The relevant point for what follows is narrower: the transmission build is the mechanism actually decarbonising Australian electricity, it is running 84 to 250 per cent over budget, and the plan directing it is simultaneously under review by the market commission and under public challenge on its cost assumptions. That is an argument for building better, not for building less.

7. Price, and the fleet

At 30c/kWh an electric vehicle is about three times cheaper to run than petrol. At 10c/kWh it is 8.9 times cheaper — about $270 a year against $2,400 for the same driving. At three times cheaper, early adopters switch. At nearly nine times, fleets do.

The emissions arithmetic holds even on the current generation mix. An electric vehicle charged on a coal-heavy grid emits about 144 grams of CO₂ a kilometre against the Australian petrol fleet average of 191 grams — a quarter better on coal, because an electric drivetrain converts energy to motion above 90 per cent efficiency against 25 to 30 per cent for combustion. On the current grid it is 76 grams, and it improves every year the grid improves, with no new purchase.

China’s new-vehicle share passed 60 per cent in 2026 while purchase subsidies were being withdrawn, which indicates buyers were responding to running cost rather than to the subsidy. No credit was issued for any of it.

8. The build

The MMA programme builds capacity rather than producing credits. At maturity it comprises approximately 1,000 GW of desert solar firmed by 40 GW of pumped hydro, connected by an HVDC backbone carried inside the same corridor that carries freight rail, water, gas and fibre — so the cables are an added cost on a structure being built anyway, rather than a separate line needing its own route and its own land access.

Generation is sited in the interior, where the resource runs at 2,400 to 2,800 kWh per square metre a year against 1,600 to 1,800 in the coastal zones now being developed, on Crown land, with no competing agricultural use. No farmland is converted, and no credit is claimed for any of it.

Freight moves to electric rail, which is three to four times more efficient per tonne-kilometre than diesel rail and roughly ten times more efficient than road. Surplus generation is exported by subsea cable into Asia-Pacific grids, so coal plants there run fewer hours.

9. The ledger

At programme maturity: approximately 275 to 325 Mt a year retired domestically — about 140 from the grid, 80 to 100 from transport, 20 to 30 each from industrial process heat and from mining and agricultural diesel, and 15 to 25 from a billion trees planted on aqueduct water rather than on farmland. A further 455 to 585 Mt a year is displaced overseas, because cheap Australian electricity arriving in a regional grid is used ahead of that grid’s own coal, so those coal plants run fewer hours.

The residual is named rather than offset: 145 to 195 Mt remains at 2050 — gas leaking from old wells and mines, agricultural emissions outside the programme, and hard-to-abate industrial chemistry. That is about 60 per cent of the legislated path delivered by things that get built, with the remaining 40 per cent stated as an engineering problem still to be solved.

10. What the market does not price

The National Electricity Market is an energy-only market: a generator is paid for the megawatt hours it produces and nothing for standing ready. That design is what strands a coal plant when solar takes the middle of the day — the plant still holds the system up at 6pm and in July, and earns nothing for that availability.

Western Australia already handles this differently. The South-West Interconnected System runs a Reserve Capacity Mechanism, which pays plant for being available separately from what it generates. The National Electricity Market has debated a capacity mechanism for years without adopting one.

The state underwriting agreements described at section 5 are, in effect, capacity payments — negotiated one at a time, outside any published mechanism, and in two cases undisclosed.

11. Summary

Electricity cannot be stored at scale in the grid. Supply must equal demand every five minutes, AEMO takes the cheapest offers first, and the last generator dispatched sets the price for all of them. Wind and solar bid near zero because their fuel is free, so they are taken first whenever they are producing.

Grid-connected generators are not inside the Safeguard Mechanism. They sit under a single sectoral cap of 198 million tonnes, fixed, set from 2009–14 emissions, against actual emissions of about 148 million tonnes. No power station in Australia has ever surrendered a credit. Electricity is instead decarbonised by the Renewable Energy Target, the Capacity Investment Scheme and transmission finance — and its emissions have fallen faster than any other sector’s.

What is retiring coal is the loss of daylight running hours to solar, which strands fixed costs across fewer megawatt hours. Around three quarters of the fleet is expected to close by 2035 on that basis. Where governments have intervened they have paid to delay closures for reliability, not to accelerate them — and the reliability forecasts underpinning those decisions do not agree with each other.

The build doing that work is running 84 to 250 per cent over budget, under a plan now being reviewed by the market commission and challenged on its cost assumptions.

This memo sets out how the system works. It does not propose changes to it. The credit scheme applied to the rest of the economy is set out in Memo 32.

12. Sources

1. DCCEEW, Safeguard Mechanism overview — coverage above 100,000 t CO₂-e; 219 facilities in 2023–24 representing about 31 per cent of national emissions; reformed scheme commencing 1 July 2023; baselines as production multiplied by an emissions-intensity value; the 4.9 per cent default annual decline rate to 2030; trade-exposed baseline-adjusted determinations. Cited in sections 1, 4 and 5.
2. DCCEEW, Safeguard Mechanism overview and reforms factsheet; Clean Energy Regulator, Safeguard baselines and Electricity sector emissions and generation data — a single sectoral baseline of 198 million tonnes CO₂-e applying collectively to all grid-connected electricity generators across the National Electricity Market, the South-West and North-West interconnected systems, the Darwin to Katherine network and the Mount Isa–Cloncurry supply network; the baseline set from the sector’s 2009–10 to 2013–14 emissions and stated as not expected to be exceeded; individual grid-connected generators not being covered while the sector stays below it, and the sectoral baseline being replaced by individual facility baselines if it is exceeded; coverage of the electricity sector being unchanged by the 2023 reforms; non-grid-connected generators holding facility-level baselines and the same obligations as other covered facilities; non-generation emissions at a power station, such as coal mine fugitives, being covered above the 100,000-tonne threshold; anti-avoidance rules preventing a facility from attaching itself to a grid-connected power station; and shale gas facilities, including in the Beetaloo Basin, having a baseline set to zero. Australian Energy Council — the sectoral baseline sitting well above the sector’s current emissions of about 148 Mt CO₂-e, and the engineering objection to individual generator baselines in a centrally dispatched market, including the risk of a lower-intensity generator reducing dispatch and being replaced by a higher-emitting one. International Carbon Action Partnership — grid-connected power sector facilities facing no compliance obligation; covered emissions falling from 138.7 Mt in FY2023 to 135.9 Mt in FY2024, a reduction of about 1.9 per cent; and a compliance rate of 98 per cent. Cited in sections 1, 3 and 16.
3. King & Wood Mallesons and PwC Australia, Safeguard Mechanism guidance — the post-2030 proposed decline rate of 3.285 per cent; TEBA minimum decline rates of 1 per cent for manufacturing and 2 per cent for other sectors, available once the scheme cost exceeds 3 per cent of EBIT, for three years; the fixed ACCU purchase price for Safeguard facilities of $75 in 2023–24 rising CPI plus 2 per cent; banking and borrowing provisions; and the statement that the critical risk is carbon leakage, where facilities close and move offshore to jurisdictions with lower carbon prices and higher emissions intensity, resulting in higher global emissions as an unintended consequence of the Safeguard Mechanism. Cited in sections 1, 4, 5 and 12.
4. International Carbon Action Partnership, Australian Safeguard Mechanism — Safeguard Mechanism Credits, banking to 2030, borrowing up to 10 per cent of baseline, and the 2026–27 scheme review. Carbon Market Institute — the decline rate exceeding 20 per cent cumulatively within five years, and the estimate of 205 Mt CO₂-e of reductions to 2030 relative to a no-reform projection. Cited in sections 1 and 4.
5. Clean Energy Regulator, 2024–25 Safeguard Mechanism data insights and Quarterly Carbon Market Report, December quarter 2024 — 139 facilities surrendering 10.8 million ACCUs and 2.6 million SMCs, 13.4 million units in total, for the 2024–25 compliance period; 153 of 215 covered facilities above their baselines in 2023–24 by an aggregate 10.7 Mt before flexibility measures; 60 facilities below their baselines and eligible for approximately 9.2 million SMCs; over 8 million SMCs issued to 57 facilities as at 18 February 2025; holdings of just under 50 million ACCUs in the national registry at the end of 2024 with Safeguard and Safeguard-related entities holding around 60 per cent; the definition of an SMC and of a facility’s net emissions number; and deemed surrender of ACCUs purchased by government under a carbon abatement contract. S&P Global Platts — 142 facilities incurring a total liability of 9.2 Mt in 2023–24 and surrendering 7.1 million ACCUs and 1.4 million SMCs, with ACCUs 84.5 per cent of units surrendered and a 479 per cent increase on the 1.2 million surrendered the previous year; generic ACCUs assessed at A$33.75 a tonne on 15 April 2025; and SMCs last traded on 21 March 2025 at A$31.25, a A$1.80 discount to generic ACCUs. International Carbon Action Partnership — the maximum civil penalty of one penalty unit per tonne of excess emissions a year, a penalty unit being A$330 as at November 2024, with infringement notices charged at one third of the maximum. Cited in sections 1 and 5.
6. Institute of Public Affairs, The $165.5 million carbon tax on our last two refineries (April 2026) — the Ampol Lytton and Viva Energy Geelong refineries as the last two in Australia and both Safeguard-covered; the IPA’s calculated Safeguard cost of up to $79.9 million for Lytton, $85.6 million for Geelong and $165.5 million combined to 2029–30; and its estimate of $7.1 to $11.7 billion across all covered facilities. Stated as the IPA’s calculation. Cited in section 5.
7. Santos and Beach Energy, Moomba CCS — joint venture interests of approximately 67 and 33 per cent; capture of reservoir CO₂ from the Moomba gas plant, dehydration, compression, approximately 50 km of pipeline and injection into depleted fields; Phase 1 design capacity up to 1.7 Mt a year; lifecycle cost under US$30 a tonne; first injection 30 September 2024; approximately 2.3 million tonnes stored by mid-2026; more than 1.19 million ACCUs issued for injections to 30 September 2025, including the first issuance under the CCS method; and monitoring and verification under a plan approved by South Australian authorities. business.gov.au — the A$15 million grant from the Carbon Capture Use and Storage Development Fund against a project of approximately A$210 million. Clean Energy Regulator — the 25-year crediting period and the add-back of ACCUs to a Safeguard facility’s net emissions to prevent double counting. Cited in sections 6 and 16.
8. IEEFA, Gorgon CCS underperformance hits new low in 2023-24 — approval on condition of capturing 80 per cent of CO₂ removed from the reservoir on a five-year rolling average from July 2016; injection beginning August 2019, three years late; 44 per cent captured between FY2019–20 and FY2023–24; 33 per cent in FY2021–22, 34 per cent in FY2022–23 and 30 per cent in FY2023–24; design capacity of 4 Mt a year; more than A$3.2 billion spent by Chevron, ExxonMobil and Shell; operation at about one third of design capacity; the 7 km injection pipeline into the Dupuy formation; and the finding that of 13 CCS projects reviewed worldwide, three achieved their targets. Geoengineering Monitor — the five-year target missed by approximately 7.4 Mt and penalties in carbon credits worth approximately A$180 million; the injection system found clogged with sand in January 2021; and A$250 million made available for CCS and CCUS projects in September 2021. The Australia Institute, quoted in The Guardian — the $60 million provided to Chevron for CCS with no penalties attached for failure. Cited in section 6.
9. IEEFA, Bayu-Undan: A test bed for carbon trading or a distraction? — capture at Darwin LNG with transport of 500 to 800 km for injection at the Bayu-Undan field in Timor-Leste waters, across a maritime boundary; intended scale more than twice that of Gorgon CCS with more complex engineering; project economics not published; and unresolved liability arrangements between Australia and Timor-Leste. Cited in section 6.
10. Clean Energy Regulator, ACCU Scheme methods and project register; DCCEEW method determinations — approximately 185 million ACCUs issued since 2012 under the Carbon Farming Initiative Act 2011; the method set comprising avoided deforestation, human-induced regeneration, environmental plantings, plantation forestry, soil carbon, savanna fire management, landfill gas, alternative waste treatment, carbon capture and storage, mining oil and gas fugitives, and tidal restoration of blue carbon; the new Reducing Methane Emissions from Landfill Gas method implementing Recommendation 10 of the Independent Review of Australian Carbon Credit Units; and the two 2026 savanna fire management methods made 10 April 2026, expected to credit more abatement on average because living biomass and standing dead wood are now counted and the crediting period is longer. Independent Review of Australian Carbon Credit Units (the Chubb Review, January 2023) — the finding that the scheme was essentially sound, the abolition of the Emissions Reduction Assurance Committee in favour of the Carbon Abatement Integrity Committee, the suspension of the avoided deforestation method for new projects, and human-induced regeneration placed under review. Argus Media — 5.57 million ACCUs issued under the alternative waste treatment method, 3 per cent of the 180.78 million issued at that date, the method expiring to new registrations on 31 March 2025, only 11 projects ever earning credits under it with Veolia, Cleanaway and Corporate Carbon Group among the largest; and the five largest sources of ACCUs surrendered under the Safeguard Mechanism for the 2023–24 compliance year being avoided deforestation, landfill gas, human-induced regeneration, savanna fire management and alternative waste treatment. Australian National University College of Law — approximately 115 real landfill gas projects, with the ten largest accounting for more than half and the twenty largest for almost 70 per cent of ACCUs issued to landfill projects, all of the largest being generation projects earning electricity, renewable energy certificate and ACCU revenue. Clima market commentary — human-induced regeneration closed to new registration yet supplying 60 per cent of a record vegetation quarter in the first quarter of 2026, with environmental plantings at 29 per cent. Cited in sections 1, 6 and 16.
11. Reporting on the Rushy Lagoon sale — The Examiner, The Land, Tasmanian Country, Wood Central, Pulse Tasmania and Farm Weekly: Rushy Lagoon and East Wyambi totalling 21,744 hectares near Cape Portland, Tasmania’s largest farm, sold to the Tasmania Natural Asset Trust managed by Gresham House with Aviva Investors; $69 million from the Clean Energy Finance Corporation and $73 million from the shareholders in a $142 million project; an additional $8.8 million Support Plantation Establishment Program grant received in May, before the sale was approved; approval by the Treasurer on Foreign Investment Review Board advice; forecast output of 3.2 million ACCUs, 5 million tonnes of timber, 12 million pine trees and 190 jobs across the project life; biodiversity certificates under the Nature Repair Market; the $73 million Support Plantation Establishment Program closing in May at approximately 40,000 hectares nationally, with this single estate covering more than half that area; the plantation estate falling from 1.973 million hectares in 2014–15 to 1.709 million in 2024–25, a 20-year low; and the removal of the water rule which had excluded high-rainfall plantation projects from the ACCU scheme. Cited in sections 6, 8 and 16.
12. ARENA, Record funding for ARENA; DCCEEW, Powering Australia; Clean Energy Finance Corporation, Rewiring the Nation Fund; Centre for Independent Studies, Counting the Cost; Norton Rose Fulbright, Roll on the throttle; and pv-tech reporting on the 2026–27 Budget — approximately $22 billion earmarked for renewable energy in the 2024–25 Budget; the $7.1 billion ARENA package and $1.5 billion baseline over seven years; $2 billion per round for Hydrogen Headstart; the $6.7 billion hydrogen production tax incentive at $2 per kilogram from 2027–28; $1.7 billion for the Future Made in Australia Innovation Fund; $1 billion for Solar Sunshot; $400 million for the Powering the Regions Industrial Transformation Stream; $20 billion of Rewiring the Nation finance and the $19 billion CEFC Rewiring the Nation Fund; $13.7 billion of CEFC commitments over the decade to 2022–23; the Capacity Investment Scheme underwriting 32 GW by 2030; the CEFC’s $3.8 billion commitment to Marinus Link stage 1 as its largest ever investment; and the return of $1.3 billion in uncommitted funding in the 2026–27 Budget, comprising $1 billion from Hydrogen Headstart and $300 million from Solar Sunshot and Battery Breakthrough, within $63.8 billion of savings and reprioritisations. Cited in sections 1, 3, 7 and 8.
13. Climate Change Authority, Transport Sector Pathways Review (September 2024) — transport emissions of 90 Mt CO₂-e in 2022, 21 per cent of Australia’s total, with on-road vehicles at 85 per cent of the sector; light vehicles 60 per cent of transport emissions; heavy vehicles 24 per cent, comprising articulated trucks 11.7 Mt, rigid trucks 8.7 Mt and buses 1.6 Mt; domestic aviation and shipping 9 per cent; approximately 19 million cars in the light vehicle fleet with electric vehicles under 1 per cent of it; and no direct abatement options identified for domestic aviation and shipping. Bureau of Infrastructure and Transport Research Economics, Australian Infrastructure and Transport Statistics Yearbook — road vehicles at 84 per cent of full fuel cycle transport emissions in 2022–23 and aviation at 9 per cent; domestic road vehicle full fuel cycle emissions reaching a record 106,000 Gg CO₂-e in 2022–23; domestic aviation falling from 11,116 Gg in 2018–19 to 5,955 Gg in 2020–21. National Greenhouse Gas Inventory, via The Conversation — railways at approximately 1.5 Mt; 41 grams CO₂ per passenger kilometre for domestic rail against 171 grams for a passenger car; and road freight dependence raising emissions by a factor of three against rail or sea. DCCEEW, Safeguard Mechanism overview — covered facilities spanning mining, manufacturing, transport, oil, gas and waste. Cited in sections 1, 10 and 16.
14. Australian Energy Market Operator, 2026 Integrated System Plan and Draft 2026 ISP — the optimal development path to 2050; 18 months of consultation with over 1,400 stakeholders and 241 written submissions; three scenarios; and the finding that renewable energy firmed with storage, backed by gas and connected by upgraded networks is the least-cost way to supply secure and reliable electricity. AEMO, Electricity Statement of Opportunities (August 2025) — NSW reliability improved with no breaches forecast following the Eraring closure. AEMO, Medium Term Projected Assessment of System Adequacy — NSW unserved energy from August 2027. Centre for Independent Studies (Aidan Morrison, Director of Energy Research) — the assessment that the Medium Term PASA figure represents almost 300 times the Reliability Standard and approximately 1,000 times the Interim Reliability Measure; the two questions put to AEMO in its 2026 ISP webinar concerning the realism of approximately 5 GW of coal retiring in 2029 and the treatment of battery revenue where storage both requires and compresses price spread; and the conclusion that the ISP fits transmission projects to government renewables targets. Hilton, Z., Morrison, A., Bainton, A. and Wu, M., The Six Fundamental Flaws Underpinning the Energy Transition (Centre for Independent Studies, 2024). Centre for Independent Studies submission to the Australian Energy Market Commission review of the Integrated System Plan, 3 March 2026. Matthew Cranston, The Australian (2026) — reporting of the NSW unserved energy forecasts. NSW Department of Climate Change, Energy, the Environment and Water, Submission to the Draft 2026 Integrated System Plan — the household battery programme moving from an original estimate of $2.3 billion to approximately $7.2 billion over four years. Cited in sections 5, 6 and 11.
15. NSW Government, Department of Climate Change, Energy, the Environment and Water media statements on Eraring Power Station; RenewEconomy; and reporting on coal closure dates — the 2024 agreement between the NSW Government and Origin Energy to operate Eraring until August 2027, underwriting up to $450 million over two years and covering up to $225 million of losses a year in return for a share of profits; the requirement that closure occur no later than April 2029; AEMO’s finding of a NSW reliability gap from 2025-26 without Eraring; Origin not having opted into the underwriting and no public money having been paid to date; Eraring at 2,880 MW supplying up to a quarter of NSW electricity; the NSW cap on coal prices paid by generators to protect profitability; two undisclosed Victorian agreements with coal generator owners and the confidential arrangement accompanying Yallourn’s 2028 closure date; Western Australian support for a bankrupted coal mine exceeding $300 million; the expectation that around three quarters of Australia’s coal plants will close by 2035; coal plants increasingly switching off during daylight hours as solar undercuts them on price; and market analysis identifying Eraring as the coal plant most exposed to renewable growth and likely to lose significant money. Cited in sections 1, 3 and 16.
16. Modern Movement Australia, Three Plans, One Grid — interior solar resource of 2,400 to 2,800 kWh per square metre a year against 1,600 to 1,800 in the coastal renewable energy zones; transmission costs 25 to 55 per cent higher in real terms than 2022 with delivery the binding constraint; and the 82 per cent renewables by 2030 target. Modern Movement Australia, The Coal Paradox and the EV Transition — 144 grams CO₂ per kilometre for an electric vehicle on a coal-heavy grid against an Australian petrol fleet average of 191 grams and 76 grams on the current grid; drivetrain efficiency above 90 per cent against 25 to 30 per cent for combustion; light and heavy vehicle emissions on the basis used in that memo; the running-cost ladder from three times at 30c/kWh to 8.9 times at 10c/kWh, being approximately $270 a year against $2,400; and electric rail three to four times more efficient than diesel rail and roughly ten times more efficient than road freight. Cited in sections 1, 3, 10, 13 and 14.
17. Climate Analytics, Australia’s global fossil fuel carbon footprint (August 2024), commissioned by the Australian Human Rights Institute, calculated from the Australian Energy Update, Resources and Energy Quarterly and Australia’s National Greenhouse Accounts — 1.15 billion tonnes of CO₂ from Australian fossil fuel exports in 2023, comprising 443 Mt thermal coal, 430 Mt metallurgical coal, 231 Mt LNG and 48 Mt oil; a further 46 Mt emitted domestically extracting, processing and distributing exports, for approximately 1.2 Gt attributable in total; 1.7 billion tonnes CO₂-e counting all greenhouse gases; cumulative export CO₂ of 30 billion tonnes 1961 to 2023, rising by approximately 15 billion tonnes to 2035; Australia at approximately 4.5 per cent of global fossil CO₂ with about 80 per cent from exports; third largest fossil fuel exporter by energy and second by greenhouse gas footprint; 52 per cent of world metallurgical coal exports and 17 per cent of thermal coal exports; LNG export capacity rising from 25.5 to 62 million tonnes a year between 2012 and 2022; 78 per cent of LNG, metallurgical and thermal coal bought by Japan, China, South Korea and India; and exports consuming approximately 7.5 per cent of the remaining 200 Gt carbon budget between 2024 and 2035, or 9.1 per cent including domestic emissions. The Conversation, ‘Australia could become the world’s first net-zero exporter of fossil fuels’ (2026) — approximately 900 million tonnes of iron ore exported annually, processed overseas into about 560 million tonnes of iron. Cited in sections 1, 2 and 16.
18. Modern Movement Australia, The Net Zero Path to 2050 Target — Department of Climate Change projections missing the legislated 2030 target by 25 to 68 Mt and the 2035 target by 86 to 200 Mt; approximately 1,000 GW of desert solar and 40 GW of Alice Hub pumped hydro; the domestic ledger of approximately 275 to 325 Mt a year and its components; international displacement of approximately 455 to 585 Mt a year by merit-order dispatch; the residual of approximately 145 to 195 Mt at 2050 stated rather than offset; and the HumeLink, Marinus Link and Project EnergyConnect cost overruns of 190, 250 and 84 per cent. Cited in sections 1, 2, 3, 8 and 15.
19. IEEFA and Michael West Media — Moomba reducing its adjacent gas plant’s emissions by more than 50 per cent, and the 55 km Moomba pipeline against Gorgon’s 7 km. Core Markets — ACCU spot price of approximately A$38 a tonne in late July 2026. Cited in sections 1 and 6.