AEMO’s 2026 Electricity Statement of Opportunities shows an improved reliability outlook with gaps not emerging until 2030-31 in NSW and Victoria under the official standard; WattClarity questions whether that improvement is partly an artefact of a contested 2023 methodology change adding 6-12 month buffers before new projects count toward the forecast.
Chris Bowen has launched Capacity Investment Scheme Tender 11, seeking 1.8GW of wind and solar in WA to help replace coal plants closing by 2029. In spite of this, recent analysis from the ABC shows that only 4 of 31 Capacity Investment Scheme-backed wind projects reaching financial close as construction costs have risen 30-50% since bids were submitted.
The AER has released its Strategic Plan 2026-2030 with concrete commitments including implementing an effective domestic gas reservation scheme and driving more efficient utilisation of electricity distribution networks.
Victoria has opened its first offshore wind auction, seeking 2GW of capacity across Gippsland and Warrnambool zones (enough for 1.5 million homes), with bids closing August 2027, contracts awarded in 2028, and first power expected in 2035.
The Australian Renewable Energy Hub has shrunk from a planned 26GW to 15GW, with proponents InterContinental Energy and CWP Global dropping the hydrogen and ammonia export components entirely.
Oxford Economics forecasts Australian data centre electricity demand will more than triple from 5.1TWh in FY26 to 33.7TWh by FY36 under its central scenario, with NSW and Victoria accounting for over 85% of that load and data centres consuming up to 19% of those states’ grid-supplied electricity by then.
News from Japan
Paywalled: Kirin has begun producing green hydrogen on-site at one of its beer factories using a 280kW solar array, targeting 70-80 tonnes of hydrogen annually to cover up to 23% of the plant’s heating needs.
Paywalled: Japan’s grid operator OCCTO has proposed a new “Complementary Auction” within its Capacity Market, run alongside the existing Reserve Power auction, both effectively paying older thermal plants to stay online amid concerns that supply will remain tight through FY2030.
Podcast of the week
Catalyst with Shayle Kann talks to Voya Energy’s Richard Wang about replacing diesel backup generators with an electrochemical generator that produces electricity from aluminium pellets and air.
What cancelling VNI-West means for the energy market and the future power system
VNI-West sits in the forward plan for the NEM, but its future is now uncertain. It has been the subject of a long and difficult public debate about cost, route and land use, and there is a live possibility that the project does not proceed. Most of the analysis published on the project to date has been directed at the explicit cost of the project. Comparatively little has been directed at what the world looks like with and without the project, and in particular the key question: what does the power system look like without VNI-West and what must happen in its place?
Against this backdrop, in this article we consider a range of projections to improve our understanding about the consequences of the project not proceeding. We do not seek to express views on the non-quantitative merits of the project, on whether its costs are reasonable, on the land use and social licence questions along the route. Those are matters to which a model has nothing useful to contribute. What a model can do is trace the consequences for the power system, the electricity market, and the broader energy system.
We take our reference case for the NEM, remove VNI-West, and consider what happens when we do nothing, or when we allow the model to re-optimise the generation and storage build in response. We consider three questions:
What happens to prices, in Victoria and elsewhere?
What does the system build instead?
What does that build do to gas consumption?
The short answer is that the price effect is large and it persists, the system does not really replace the interconnector so much as run a more expensive version of itself without it, and the difference is accounted for by increased consumption of gas for power generation.
Where the project stands
VNI-West entered the 2022 ISP as a staged actionable project. AEMO Victoria Planning and Transgrid published the PACR in May 2023, identifying a 500 kV double-circuit line from Bulgana on the Western Renewables Link to Dinawan on Project EnergyConnect as the preferred option. AEMO ran the feedback loop against the 2023 IASR and the Draft 2024 ISP in December 2023 and confirmed the project remained on the optimal development path, and the AER approved the Stage 1 early works contingent project application in May 2024.
The project has been retained as actionable in the 2024 and 2026 ISPs. Over that period the Victorian route has moved, the delivery vehicle has changed, and the cost estimate has risen from a little under $4.0 billion at the time of the Stage 1 application to $7.6 billion in the 2026 ISP, carried with an accuracy range of minus 30 to plus 50 per cent.
Our method
We start from our headwinds reference case for the NEM and construct three cases for comparison.
The first is the base case, with VNI-West delivered on its current timing in our reference case. Importantly, our reference case already assumes delays to VNI-West.
The second is the naive removal case. We take VNI-West out of the forward plan and change nothing else – the same generation and storage build, in the same places, at the same times. This is deliberately artificial.
The third is the re-optimised case. We take VNI-West out and let the model rebuild: generation, storage and firming are all free to respond, subject to the same build limits and connection constraints as the base case.
We report outcomes on our standard weather reference year, but also for some charts on a 2011 weather reference year. The 2011 reference year combines a harsh summer with a winter that sees sustained wind droughts across the southern states. Chart 2 explains why the choice of reference year does a great deal of the work in this analysis.
Chart 1 – The naïve price effect in Victoria, and how long it lasts
Chart 1 shows average annual spot prices in Victoria for the reference case and the naïve case without VNI-West. The two cases are indistinguishable to FY2033. They separate in FY2034, and by FY2036 the case without VNI-West is at $194 per MWh against $126 in the reference case. From that point the gap averages around $56 per MWh and never closes. It is at its widest in FY2036 and again in FY2044, at close to $70 per MWh, and at its narrowest in the mid-2040s, at around $40. In the last year of the outlook it is still $38.
Chart 1 – Removing VNI-West lifts Victorian prices by around $56 per MWh from FY2036
Average annual spot price in Victoria, reference case versus reference case excluding VNI-West
Chart 2 – Outcomes under a 2011 weather reference year
Chart 2 adds a 2011 weather reference year to both cases, giving four lines: the reference case and the case without VNI-West, each run on standard weather and on the 2011 trace. The price level rises sharply. Without VNI-West, a 2011 trace produces Victorian prices above $210 per MWh in six years of the outlook and a peak of $236 per MWh in FY2045, against $124 in the reference case on standard weather in the same year.
Chart 2 – Under a 2011 reference year the removal effect is markedly greater
Average annual spot price in Victoria, standard weather and 2011 weather reference year
An interconnector earns its keep on a small number of days a decade, under exactly the conditions the 2011 trace reproduces, because that is when the diversity between regions is doing the heaviest lifting. Averaging across reference years does to an interconnector what averaging across a year does to a peaker: it produces a number that is arithmetically correct and analytically useless.
We made a version of this point in our November 2021 Chart of the Month on Vic-NSW. Interconnectors derive a large part of their value from the uncertainty of future outcomes, because they increase the diversity of supply options, and yet the models used to value them are typically deterministic and assume perfect foresight. If we know the future, there is no value in a hedge against uncertainty. Five years on, the models have improved at the margin, but the point still stands.
Chart 3 – This is not just a Victorian question
Chart 3 shows the same comparison across four regions. South Australia is affected almost as heavily as Victoria. Prices without VNI-West run around $50 per MWh above the reference case from FY2036 through to the mid-2040s, peaking near $168 per MWh in FY2036 against $114. Tasmania is $30 to $45 per MWh higher over the same period. New South Wales moves the other way: from the early 2040s, prices there sit some $5 to $12 per MWh below the reference case, because energy that would have moved south stays in the region.
Chart 3 – South Australia and Tasmania bear price increases nearly as large as Victoria
Average annual spot price by region, reference case versus reference case excluding VNI-West
The mechanism is not complicated, but it is routinely missed. Interconnectors also affect prices in neighbouring regions, sometimes for the better and sometimes for the worse. The practical consequence is that the effects of the decision are not restricted to Victoria, and they are not symmetric. A change of $50 per MWh in South Australia is not a rounding error.
Chart 4 – What the system builds instead
We now turn to the re-optimised case. Chart 4 shows the difference in new capacity between the base case and the re-optimised case by technology and year. Bars above the line are capacity the reference case builds but the removal case does not; bars below the line are capacity built only in the case without VNI-West.
The first thing to say is that this is not a replacement. Without the network, the renewables cannot be delivered, so the model does not build them. It builds a smaller, more gas dependent fleet and runs it harder.
Chart 4 – The system does not replace VNI-West. It substitutes gas peaking and deep storage for VRE
Difference in new capacity by technology and financial year, reference case less case excluding VNI-West
Underneath the total there is a clear substitution. Through FY2036 to FY2038 the reference case builds around 1.5 GW a year more solar and wind, while the removal case brings forward roughly 1.2 to 1.5 GW a year of gas peaking. The pattern continues with more gas and deep storage replacing more wind and solar. Interestingly the No VNI-West case builds materially more pumped hydro as it tries to firm a system that no longer has a second path to New South Wales.
The replacement is not like-for-like in either technology or location: it is gas peaking and deep storage in place of solar, wind and network, sited to reach load on the existing system rather than to reach the resource.
Chart 5 – The consequences for prices under the re-optimised case
So what does this mean for prices. Chart 5 shows the same analysis as Chart 3 but now includes prices for the re-optimised case. The important point here is that the price increases associated with the new build case persist. The reason for this is the increased use of gas for power generation in the Southern states.
Chart 5 – Even with re-optimisation the price increases persist in Victoria and Tasmania
Average annual spot prices, reference case versus re-optimised and reference case excluding VNI-West
Chart 6 – The consequence for gas under the re-optimised case
Chart 6 shows gas consumption for electricity generation in the Southern States across all four cases: reference and re-optimised, each on standard weather and on the 2011 trace. Gas burn rises by roughly 20 to 28 PJ a year from the mid-2030s onwards, an increase of between a third and a half on the reference case. The divergence opens in FY2035 and, like the price effect, does not close. The extreme weather year is when the system most needs gas, and removing the interconnector also raises the requirement.
Chart 6 – Southern states’ gas consumption rises by 25 PJ a year, more under a 2011 reference year
Gas consumption for GPG in Southern States, 2015 and 2011 weather reference years
The southern gas market is already tight. Southern supply has been declining faster than southern demand for some years, the balance is met by northern gas moved south through pipeline capacity that is fully subscribed on peak days, and it is peak-day capability rather than annual quantity that binds.
We cannot be certain whether that gas can be delivered, because much can happen in the domestic market between now and the 2030s. But we can say that it is one of the questions on which the removal case turns.
Our two cents
The system does not replace VNI-West, it substitutes for it, and the substitution is worse. We expected the model to build its way back to something close to the reference case outcome and it does not. It leans on gas peaking and deep storage, and leaves Victorian prices around $20 per MWh higher for the rest of the outlook. Removing an asset like this from the forward plan is not a decision to avoid a capital cost. It is a decision to accept a permanently more expensive system unless something cheaper is put in its place.
The price effect does not fade, which is unusual and which changes how the decision should be framed. In most of the work we do, a shock to the system produces a transitional price effect that closes once the build catches up. Here the build has fifteen years to catch up and does not. We are removing a key piece of strategic infrastructure from the grid. A decision framed as a saving of $7.6 billion in capital is, on these results, a decision to add tens of dollars per megawatt hour to southern prices indefinitely.
The value of a line like VNI-West is the value of an option, but we keep measuring it as though it were a pipe. Chart 2 is revealing – the value under the 2011 weather year is markedly higher than under a median year. The value is concentrated in the tail events, and a framework that prices interconnectors on median outcomes across a scenario weighting will underprice it in a way that is superficially rigorous. This is a general problem with how we (as an industry) value network assets – not a feature of VNI-West.
The effects are national and they are not symmetric. South Australia carries an increase of up to $30 per MWh and Tasmania up to $20 per MWh, while New South Wales is slightly better off. This shows that this is not just an issue for Victoria, but rather a consideration for all the Southern states.
The benefit of planning certainty is itself an input to cost, and it does not appear anywhere in a RIT-T. A developer looking at any future transmission project has to price the probability that the project is unwound before it is delivered, and that probability is now visibly non-zero. A forward plan that is revisited whenever costs move or circumstances change raises the risk premium on every project that it comprises, and that premium is paid by consumers.
Applied consistently across all future transmission projects, the RIT-T and ISP framework that has been applied to VNI-West would ultimately dispose of most of the forward transmission plan. Every major line has the same profile: costs that escalate between the PACR and the final estimate, and benefits concentrated in tail years that the central case dilutes. If that combination is sufficient to remove a project from the plan, the same logic reaches into every other major transmission project. A counterfactual worth modelling is one in which the sector builds very little new transmission at all, and each region solves its problem locally with gas. That is a coherent system with an estimable cost, and we should estimate it rather than arrive at it by accident, one project at a time.
About Endgame
Endgame Analytics is an economic and mathematical consultancy that specialises in energy. We bring expertise in optimisation, quantitative analysis, and critical thinking to solve complex problems.
The Victorian Coalition promised to scrap the VNI West transmission project if it wins November’s election, citing a $7.6–11.4bn cost and proposing gas reserves and urban solar parks instead.
The AER found that batteries — now 6.1 GW across the NEM, up from 261 MW five years ago — are splitting “one market into many”, easing wholesale price pressure but leaving evening and overnight prices well above pre-2022 levels.
Itochu (major Japanese trading firm) will be entering the data centre business and aims to develop up to 10 data centres by 2030: 伊藤忠がデータセンター参入 数千億円投じ10棟開発、JR東と協業視野Each site will be ~50 MW in size, and the investment capital for the 10 data centres to be developed is estimated to be several-hundred billion yen (several billion AUD). As data centres require large plots of land, Itochu is planning on partnering w/ JR East (major train company) which holds strategic lots of land across the Greater Tokyo and Eastern Japan.
JAPEX (major Japanese petroleum exploration firm) is now driving a 2nd pile underground to conduct geological survey for potential CO2 sequestration in Tomakomai City, Hokkaido: 石油資源開発、CO2地下貯留に向け試掘2坑目 北海道苫小牧で
Tomakomai has Japan’s largest industrial area aptly called Tomatoh (“eastern Tomakomai”), where various trials are being conducted such as CCS / CO2 sequestration and hydrogen/ammonia co-firing, alongside existing thermal power plants: 日本最大の産業地域「苫東」：TOMATOH―苫小牧東部地域 産業用地―
Kansai EPCO says that at its Oi nuclear plant Unit 3 (1.18 GW), which has been shut down since last week due to the loss of magnetic field generation for the turbine, a part called a “diode module” broke apart, most likely due to wear-and-tear: 停止中の大飯原発3号機、部品に損傷 異常警報で関西電力が調査 The diode module was installed in 1991 and hasn’t been replaced since then (so it was over 35 years old).
Japan’s Ministry of Agriculture, Forestry and Fisheries (“MAFF”) is proposing new legislation for agrivoltaics to have a max shading rate of 30%: Japan’s proposed shading rate for agrivoltaics is unreasonable, says think tank Public comments are to be submitted by 22nd Aug, w/ the proposed legislation to be implemented from Sep-end onward. Developers as well as think tanks such as the Renewable Energy Institute (“REI”; for some reason in the English article they call it the Renewable Energy Foundation) have voiced concerns that implementing a “non-scientific” arbitrary threshold of 30% for the shading rate would be detrimental for the agrivoltaics industry.
Podcast of the week
In the debut episode of Zugzwang, Oliver and Jack tackle the perception that market modelling is an impenetrable black box and start pulling it apart.
Paywalled: Kansai Electric’s 1.18 GW Oi Unit 3 tripped automatically on Saturday 8 August after a loss-of-field alarm on the generator and remains offline with no restart date.
Paywalled: Japan’s supplementary T-1 capacity auction for FY2027 cleared every bid yet still missed its target for the first time, securing 4.58 GW at ¥10,361/kW and leaving Hokkaido short with no new entrants able to close the gap.
Podcast of the week
Zugzwang: The Market Modelling Podcast. The energy sector has been asking for this. Zugzwang is Endgame Analytics’ new podcast digging into market modelling, from Oliver Nunn and Jack Simpson.
The name comes from chess, a position where any move you make leaves you worse off. It’s hard to pronounce and a little pretentious, and that’s exactly the point.
Energy ministers agreed to legislate national standards requiring large data centres to underwrite new renewable supply, but Queensland and the Northern Territory opposed the package with the NT instead backing a $40 billion gas-fired data centre industry drawing on Beetaloo gas.
The Balance Sheet’s Issue No. 13 audit of Australia’s energy economy finds the country exports about three times the energy it consumes and will earn $405 billion doing it this year; yet, household electricity prices have drifted from among the world’s cheapest two decades ago to around the OECD average today.
The Albanese and Cook governments have put $4 million into a pre-feasibility study for the first large-scale petrol refinery since the 1960s, but experts have called it “dinosaur technology” given the clean energy transition and structurally falling petrol demand.
News from Japan
The M7.1 Kumamoto earthquake on 28 July cut power to about 32,000 households in Kumamoto Prefecture at its peak, with around 14,000 still off supply two days later; gas supply remains suspended in parts of the prefecture, mobile generator vehicles have been deployed to run air conditioning at evacuation centres in 35°C heat, and the Sendai nuclear plant about 100 km from the epicentre reported no abnormalities.
Paywalled: Invenergy has shelved its planned 47.3 MW onshore wind project near Hakodate in Hokkaido three months after announcing it, after residents objected over soil erosion, water contamination and low-frequency noise. An online petition drew more than 30,000 signatures ending an 11-turbine project that was to begin construction in 2031 and reach commercial operation by 2035.
Podcast of the week: Catalyst’s Shayle Kann on the commercial battery comeback – why C&I storage has been the missing middle, and what’s finally shifting the economics.
Australia connected a record 9.1GW of new solar, wind and battery capacity to full output in FY26 – more than double FY25 – per AEMO’s latest connections scorecard, with battery projects accounting for 52% of total capacity.
Origin Energy has confirmed unauthorised access to customer data potentially affecting millions of its accounts, with the hacker reportedly obtaining names, addresses, emails, dates of birth and bill history.
Podcast of the week: Bloomberg’s Switched On discusses data centre developers turning to on-site gas turbines to bring AI data centres online faster than grid connections allow.
The AEMC has made a final rule to improve visibility and planning of the local electricity grid, requiring network businesses to publish more consistent distribution data and a new 20-year Distribution Network Development Plan as rooftop solar, EVs and nearly half a million newly-installed home batteries reshape the low-voltage grid.
Paywalled: Tesla and several NSW councils have warned the AEMC that letting network companies such as Ausgrid, Endeavour Energy and Essential Energy own pole-mounted EV chargers under the government’s $40 million charger rollout program could backfire, deterring competition and private investment in faster charging.
Some news from Japan:
Japan Nuclear Fuel Limited’s Rokkasho-mura reprocessing plant in Aomori Prefecture looks set for a 28th delay, after the Nuclear Regulation Authority ordered that nuclear waste material currently on-site be processed and removed before completion, rather than afterward as originally planned.
AEMO has released the 2026 Integrated System Plan, reaffirming renewables firmed by storage and backed by gas as the least-cost path as coal retires, with NEM consumption forecast to nearly double and a 35 GW home battery fleet expected by 2050.
AEMO has published the 2026 WEM Electricity Statement of Opportunities, finding that coordinated home batteries are already flattening WA’s evening peak and are expected to reduce grid-scale investment needs by 2028-29, with data centres appearing as a separate demand category for the first time.
The Australian Government has announced CIS Tender 8 results: 15 BESS projects totalling 4.2 GW/16.1 GWh were awarded, marking the second consecutive technology-neutral dispatchable tender where every winning bid was a battery.
The Queensland 2026-27 Budget confirms the government will continue progressing Borumba Pumped Hydro and conduct further investigations into the Capricornia pumped hydro project in Central Queensland.
The AEMC has commenced its Electricity Network Regulation Review, including consideration of a rule change request from Energy Networks Australia to allow distribution networks to install and operate kerbside EV charging infrastructure as a regulated service.
The AEMC’s final pricing review recommends shifting tariff complexity off household bills and onto retailers — pricing electricity “like milk” — while flagging up to $6 billion in network savings by 2040 and forcing retailers to disclose loyalty penalties.
Singapore-based Firmus is on track to become Tasmania’s single largest electricity user, with AI factories proposed across Launceston, Bell Bay and Wesley Vale targeting up to 400 MW — as much as 15% of state supply.
The AER has granted five-year trial waivers letting VIOTAS and Enel X enrol large multi-site industrial loads in the Wholesale Demand Response Mechanism, testing whether flexible demand can ease peaks and defer grid investment.
The Bureau of Meteorology has confirmed El Niño is underway, with the Niño3.4 index at +0.92°C — above its +0.80°C threshold — bringing the BoM into line with NOAA and the WMO and signalling a drier, hotter winter–spring for eastern Australia.
Endgame’s own piece, republished on WattClarity, argues the NEM’s deterministic planning hides tail risk and that the ESOO is no longer fit as a resilience instrument — making the case for stochastic modelling, stress-testing and wargaming.
INPEX is launching a commercial trial of blue hydrogen power generation in Niigata, with first electricity sales due mid-June from a 1 MW turbine made by Germany’s 2G — hydrogen made from domestic natural gas, with the CO₂ sequestered in a depleted nearby gas field.
Podcast of the week: Let Me Sum Up chat about the Domestic Gas Reservation Scheme draft Design Framework, which is out for consultation.
