Energy Transition
One big contributor to CO2 is the fossil fuel-based electricity supply system around the world. In Australia, this sector’s emission reaches over 30% of total national emission. Reducing the supply chain emission of Australia’s power system is claimed to be a priority in tackling emissions nationwide. But Australia and much of the West have seen net decreases in emissions over the last decade. China is the largest net contributor to CO2 emissions and India is next as the second largest by virtue of its surging coal fired power production. If we think CO2 emission is a risk worth managing, we should come up with a new plan where the 3 largest emitters, China, India and the U.S., are active participants in it. But this scenario is nowhere to be seen, a testament to the fact that there is no such risk.
The energy strategy for Australia should be horses for courses when it comes to using what technology for what purpose. Let the free market decide how to provide us with the lowest cost (value of emission reduction included if need be) and avoid spending $ billions on crowbarring any technology into the system by cash or mandated regulatory favour. No matter which way we cut it, International Energy Agency data shows that China’s emissions have been almost the sole driver of world emissions, with India coming up behind. What is the strategy that the West should use to incentivise China and India to take account of their emissions seriously?
Australia is headed in the wrong direction by overreacting to the CO2 risk when none of the largest world emitters really care about. This overreaction has led to us locking ourselves into an increasingly expensive power supply system that does not make sense socially, economically or strategically from an emission reduction or national security perspective.
Given the strategic environment, it is reckless for Australia to double-down on wasting vast amounts of taxpayer money to subsidise mass installation of solar, wind and battery (SWB) systems indiscriminately. There are clear instances where SWB should be used, such as in remote regions or mine sites where diesel powered generation is the only option. SWB could represent a lower cost alternative than pure diesel. But on large grids where coal, gas, nuclear and a variety of other natural or synthetic fuels can be used for power generation without significant new network infrastructure investment being required, there is no net national gain to be had in this pursuit. At the end of the day, all energy fuels are free as they already exist. The cost of power supply is in turning those free fuels into on-call electricity for the consumers.
State of Play
Despite fierce debate in the scientific world over the idea of global warming being caused by industrialisation, the government is pushing for Australia to adopt lower CO2 emission fuels and power generation technology in the energy supply system. The most commercially popular renewable energy (RE) technologies are solar and wind, both having received significant government support and subsidies over the last 20 years. But as intermittent generation, these require back-up supply, which has come from fast response power plant at grid system level. Gas and diesel (peaking) generators have historically been used for this purpose, together with hydropower wherever geology permits. Coal fired generation is great for baseload generation but not very suitable for back-up supply due to its slow ramp speed. Recently, modern utility scale and small on-site batteries have begun to be used for network stability support. But the issue of back-up supply remains the domain of peaking plant.
Capacity Factor
A peaking plant’s availability factor is greater than 95% and a power supply system based on fossil fuels can reach 100% reliability due to individual plant’s dispatchability (ability to control fuel intake and thus power output). A solar farm’s availability is at 10-25% and only runs daytime under clear skies. A wind farm’s availability is 20-40% but can lose almost its entire capacity in a brief time due to wind shifts. This means, overall, we may be able to rely on 10-40% of a RE plant’s nameplate capacity over an extended period, but at any point in time such plant could lose most of its capacity without warning. We can raise the anytime availability of a renewable based system by overbuilding RE capacity and having plant in diverse locations on the grid. This can avoid all renewable plant suffering from cloud cover or wind receding at the same time. Wind is more useful as it provides power at all times of day when it is blowing. Solar is useful in providing energy during daytime, the traditional high-demand period, although the midday summer peak in Australia has collapsed – pushing the peak to early morning and late afternoon – due to growing energy spill from residential rooftop solar systems. Existing coal fired power plant is being retired to make room for a renewable based generation portfolio. This might be possible if there is enough solar/wind + peaking plant to provide anytime and long endurance back-up supply to form baseload power. What needs to be worked out is the direct and opportunity costs of such a system – the extent of renewable and peaking capacity overbuild that will be required to achieve this transition.
In theory, renewable capacity can be overbuilt by five or six times the nameplate capacity of fossil fuel plant to provide a similarly reliable amount of energy. This is to cover the low average availability level of renewable plants. But even with that quantum of overbuilding, the risk of renewable capacity in the system not being available at any point in time remains. Eg, if system demand is 1,000 megawatts (MW), we can build 1,200 MW of gas-diesel plant (ie, including 200 MW contingency capacity) and have 100% guaranteed supply (using plant of 100-300 MW each). To provide an equally reliable amount of annual energy, at least 5,000 MW of renewable capacity would need to be built. Even so, the risk of single solar or wind farms repeatedly losing almost all of their capacity remains, so the renewable based system must still have some gas-diesel fired back-up supply. Building 5,000 MW of RE plant may raise the average energy production over a period to equivalent to 1,200 MW fossil fuel generation, but it will not raise the anytime energy production to that level. Estimates vary but maintenance of supply quality and reliability to that of a fossil-fuel based system would require peaking plant back-up equivalent to at least 15% of total renewable capacity or up to the largest single renewable plant on the system, whichever is greater. In this example, about 750 MW fast response gas-diesel plant will be needed. If battery stations are to be used instead of peaking plant for back-up supply, we will need even more back-up capacity to ensure all-time electricity supply. This is because a battery station can last only several hours at full discharge while a peaking plant can go on for as long as is needed with adequate fuel supply arrangement. Estimates of battery capacity requirement point to half the total renewable capacity, or 2,500 MW in this case with long duration batteries.
Back-Up Supply
The key difference is the availability factor of a fossil fuel plant is impacted by technical failure only. That of a solar / wind farm is affected by technical failure and weather variation at any point in time. This requires a renewable system to be backed up by gas-diesel peaking plant or an oversized battery portfolio or both. Otherwise, renewable generation capacity overbuild will be prohibitively costly. Installing batteries instead of peaking generators will be expensive as battery stations cost up to three times that of same size gas-diesel plant. The comparative cost per useable megawatt-hour (MWh) for the system is higher with batteries also because these can only run a few hours per charge and last only up to 10 years while a gas-diesel plant’s life is 30 years or more. Thus, while a battery does not require fuel, its levelled cost (ie, inclusive of capital and operating costs) of back-up energy still work out more expensive than that of peaking plant, the extent of which depends on cost of capital and cost of fuel.
Supply Rearrangement
Changes to power supply market regulations have in the last 10 years been implemented to aid renewable entry. Eg, Western Australia proposes to allow batteries to obtain capacity payment based on 6-hour continuous supply (a recent increase from 2-4-hour previously). This compares to the traditional gas-diesel plant requirement of minimum 14-hour continuous fuel supply obligation. If the system’s main generators are down for longer than 2-4 hours, a battery back-up system would suffer brownout or blackout. WA currently has no batteries that could back up the system for more than 2-4 hours due to the cost of installing them. The 6-hour versions are being brought in, with significant cost impact to electricity retail pricing.
The Australian power supply portfolio has been re-arranged with more renewable capacity entry, requiring more back-up supply. This pressure will become prominent with coal plant retiring from the system, opening gaps in baseload capacity. The Australian Energy Market Operator (AEMO) claims that it no longer talks about “baseload capacity,” preferring to use “firming capacity” instead. This is pure semantics as both terms define the same anytime-secure capacity for the system to use. The second term clarifies that renewable is not secure and it requires other types of capacity to firm it, like batteries or peaking plant.
Gas can be used for the baseload transition, such as in combined cycle gas turbine (CCGT) mode in which waste heat is captured for secondary electricity generation without additional fuel consumption. This lower emission, high efficiency generation method has been in use for decades. Gas turbine technology has improved significantly, with open cycle (OCGT) mode being able to reach fuel efficiency closer to 50%. This is making CCGT less beneficial in terms of fuel savings for the same energy output. OCGT is one-third cheaper than CCGT plant to build. If gas is not used, intermittent wind and solar will have to fill the gap, which will require major investment in new renewable capacity, plus batteries and gas-diesel peaking plant.
Baseload Change-Over
Due to Net-Zero, ageing coal plant is being retired from the market without planned new coal plant replacement. Shutting down the 1-gigawatt (GW, or 1,000 MW) Yallourn plant requires 5 GW of solar / wind and another 0.8 GW back-up peaking plant. In WA, the 800 MW Muja CD plant is being retired in 2027 with no baseload plant earmarked for replacement. Currently, coal and CCGT plant provide low-cost baseload and mid-merit generation. But they are being displaced at any time by solar / wind farms based on dispatch rules that have been rewritten to favour intermittent generators. Coal and gas plant must respond to renewable plant output on the grid. Usually, the more flexible gas-diesel plants are adjusted first and, if required, the coal plant ramped up or down accordingly. This causes fossil fuel plant to vary output constantly, drastically reducing their efficiency and raising their operating costs. In the case of coal plant, such operation severely impacts their viability as coal plant is designed specifically for stable baseload supply.
When the media reports that renewable is taking more of a share in total electricity supply, it is because of this preferential treatment that forces coal and gas energy off the grid. It decimates coal fired generator efficiency. In an otherwise non-discriminatory system of merit order of dispatch, no intermittent generators would be able to be used since they are not dispatchable. They are at the mercy of minute-by-minute weather.
Batteries
Lithium batteries are being installed to provide energy balancing and back-up supply to the grid. Note that these two jobs are distinct from each other. Energy balancing or load following ancillary services (LFAS) is a real time balancing requirement to maintain grid stability. Back-up supply is additional energy sent to the grid on short notice to cover a sudden supply shortage, which could be short or long in duration. While batteries can do the LFAS and short duration back-up jobs well – the latter in taking advantage of supply-demand variations within the 5-minute trading intervals – they are of limited use as long-duration back-up suppliers. Batteries are being ushered into the market through government subsidies, financial and regulatory, as it is believed they could replace peaking generators. Comparison tends to ignore lithium batteries’ life being less than 10 years compared to gas turbine plant’s life of 30 years, or that lithium batteries are highly flammable, and all batteries are energy storage. The critical difference is that batteries need charging before discharging. They are not additive energy providers like peaking generators. For batteries to be useful there needs to be substantial generation capacity overbuild and extended battery life. One form of battery that has promise to deliver these characteristics is the vanadium flow battery, which not only carries a long 30-year life but escapes the spontaneous combustion issue of lithium. Nevertheless, the overbuild is not just for intermittency coverage but also for charging the batteries while supplying the system in full. Using batteries instead of gas-diesel plant, which generates its own power that is additional to system supply, requires this extra overbuild.
The overbuild is needed even in cases of arbitrage where batteries could be charged daytime while the system is oversupplied with excess solar power. This arbitrage would work for a single self-supply customer with an outsized battery on site and who were paying a flat retail price for power, with the penalty for missing a discharge being the retail price (cap on cost). It does not work for the system since the system penalises any discharge failure by a battery station and there is no way of knowing how much discharge the system could obtain from private batteries. In WA, the penalty to private suppliers is sweetened by the reserve capacity payment. In the NEM, such penalty could turn out to be severe in times of emergency.
Strategic Competition
Due to deliberate regulatory intervention in the market, coal plant attrition is scheduled for the next 5 years as it is not economic to keep them operating. Grid stability will come to be more at risk as a result. If the goal is to have 100% RE supply, over-investment should have been made over the last 15-20 years, to take the system to at least five times its demand capacity, with substantial gas-diesel back-up plant. The peaking / renewable capacity trade-off is important in that the more gas-diesel plant we use the less renewable overbuild is required. If batteries are used, over-investment would have to be greater and at higher cost.
Total Australian power generation capacity amounts to 65 GW. Coal makes up 55% (36 GW) of that total. Fossil fuels contributed 65% of total electricity generation in 2023, including coal (46%), gas (17%) and oil (2%). Coal’s share of electricity generation continued its long-term decline while the share of gas-fired generation was lower due to artificially high gas prices caused by government blocking of gas resources deployment in the NEM. Renewables contributed 35% of total electricity generation in 2023. The discrepancy in the share of energy generation and nameplate capacity – eg, 46% for coal generated energy versus 55% for nameplate capacity – is due to the stated reasons of active government intervention through regulatory suppression of fossil fuel generation and financial incentives for renewable generation. Electricity supply, however, is a nameplate capacity game and not energy generation one. Any unreliable wind turbine or solar panel could produce energy. A power system, however, relies on anytime capacity availability for which a wind turbine or solar panel would have limited value, unless it is fully and instantaneously backed up by batteries and peaking plant.
With solar, wind and battery plant and equipment being made mainly in China, where electricity production is three-quarters fossil fuel based, the more the West installs SWB the higher the world CO2 emissions. The estimated bill for Australia to install 100% SWB can be up to $1 trillion over 10-15 years according to various calculations by industry and government bodies. This estimate does not include the impact of AI-related demand for power. This additional demand from AI will double or triple the cost of power supply infrastructure. Countries with the most SWB entry are the ones facing the highest electricity price for their citizens as witnessed in Europe. Renewables are not generally cheaper than fossil fuels in powering economies. Energy and Net-Zero policy in Australia, and most of the West, has been irrational from a strategic competition viewpoint, playing into the hand of the CCP that wants to see the climate change game drag down the West’s economic growth.
Pursuing Net-Zero in Australia will be equivalent to stripping the entire $40-odd billion national defence budget down to zero every year for the next 15 years, transferring this money to the power supply sector that it doesn’t need, in order to build a far more expensive system and raise its dependence on the China supply chain, with the hope of reducing emissions the extent of which is guaranteed to be wiped out by China’s increase in emissions as allowed under the Paris Agreement.
Power Generation Mix
As ageing fossil fuel plant are closing, new high-efficiency gas plant will be built to provide energy balancing and back-up supply to the SWB system. The likely trend now is more gas fired power plant will need to be built. This is giving time for nuclear energy to make its way into the market. To replace Australian coal capacity with RE, there would need to be 180 GW of solar and wind capacity installed. With cost per MW of solar, wind, CCGT, high-efficiency OCGT and coal plant at roughly $2 million, this calls for $360 billion worth of Capex. In addition, the cost of back-up capacity (at $1.5m per MW for the lower-cost regular OCGT mode) would amount to $41 billion if gas-diesel is used, or $248 billion if batteries are used ($2.5-3m per MW). The total capital cost of transiting Australia’s 36 GW of coal generation to all solar and wind with peaking plant would be $401 billion, or $608 billion with batteries on a direct cost basis. This does not include the impact of higher power price on industrial production and other sectors of the Australian economy. In return, Australian power consumers would save $9 billion per year in fuel cost over 10 years, the life of inverters and batteries. These savings would be overwhelmed by the cost of transmission and distribution network augmentation to accommodate the accumulating intermittent generation.
Network Costs
Further driving up the cost of a SWB power system is the limitation of transmission and distribution networks to handle the entry of RE capacity, even with the exit of coal plant that will free up some. The cost of network augmentation is yet to be sorted in policy formulation. In Western Australia (WA), there have been proposals to develop renewable in the south-west corridor and north country region to Oakajee. Western Power, the network utility, is not planning new transmission lines in either region. There is no prospect of a renewable generation hub in WA the way that Collie / Muja has been for baseload coal. Utility scale renewable needs to be spread across the network for locational diversity. As Western Power is not planning for transmission network expansion on its own, it will be up to the private sector to develop the network incrementally. Network connection costs could increase rapidly in future. For the north country region, to accommodate any mining load growth, private network investment will need to be enticed using any new capital contribution regime. It could result in investors adding to the network and allocating new capacity chunks to new users to recoup the cost and make a return over time. It is unknown how this would work with intermittent generators, which face uncertain returns due to reliance on uncommercial regulatory assistance.
Such grid connection costs might encourage mining loads to stay off-grid, where renewable plus gas-diesel back-up or vanadium batteries may provide lower cost supply than just using diesel. How much lower will depend on the uncertain cost of batteries and oil and gas price. For mining projects, the cost of power can be absorbed easily in the mine’s economics so miners might be more inclined to buy public relations kudos by installing an off grid “green” power system. On the other hand, reliability of supply is critical for mines, hence it is not clear which way mine owners will go in choosing between “green” and gas fired power, using piped or shipped-in compressed natural gas for the plant. For cottage industry or semi-isolated townships and loads at the edges of the grid, it could be viable at the margin to turn them into micro-grids like stand-alone mine sites. This refers to decoupling a load or bunch of loads at locations where it is uneconomic to extend or strengthen the main grid. Such micro-grids would face the same RE / battery cost issues except they might be able to net out some transmission / distribution network extension cost from the total expense. For general grid supply, which industry, manufacturing, agriculture, service industries and households rely on, there will be much less tolerance for sharply higher costs associated with a SWB supply system. More intense economic competition worldwide requires much more intensive power supply systems than distributed technologies could muster at present. This means that transmission networks will need to be substantially augmented to safeguard industrial grade power supply. There has been a notable slowdown in regulatory and environmental approval for installation of further large scale solar and wind farms in the NEM due to much higher network support costs than previously thought.
The AEMO has released a key document – the Draft 2025 Electricity Network Options Report – as part of a two-yearly consultation on network inputs for its Integrated System Plan (ISP). The cost of new transmission line projects has surged by 50% per cent over the past two years, putting a significant damper on the SWB combination. The report also raises the issues of 1) social licence for massive transmission projects, and 2) the role that local networks could play in hosting renewable and storage projects at a lower cost and with less disruption. The ISP presents a path for Australia’s main grid to reach 82% renewables by 2030, replacing coal with a mix of SWB, which requires significant investments in transmission upgrades. Without a major review and breakthrough of some sort, the costs will impact consumer electricity bills drastically, or the government will have to front up with bigger subsidies.
Surging Electricity Prices
There is a severe conflict between a competitive power cost structure and an SWB-only supply system. The cost of electricity in Australia has gone up significantly in real terms over the last 15 years due to the impact of the change in the supply portfolio, where intermittent generation has been crowbarred into the system at the expense of supply efficiency. This trend will continue, if not accelerated, with replacement of coal plant in the next decade. Cost increases may be tempered by higher technical efficiency in solar / wind generator and battery design, as seen with regard solar panels and inverters and wind turbine blades in the last two decades. Vanadium and other long-life battery technologies should be more suitable for stationary purposes such as utility plant. Pressured by this high-cost combination, the federal government has introduced a subsidy program for new batteries of up to $3,000 for households with income up to $210,000, about $300 million in total. This is separate to state subsidies such as WA’s $5,000-7,500 per shot. In short, taxpayers are funding almost in full the cost of a battery for those eligible. The term “permanent reduction in power bill” used in this program is untrue since batteries last up to 10 years, making the average capitalised cost of $15,000 per battery rather high for either consumers or taxpayers.
Meanwhile, the price of natural gas has continued to trend up due to penetration of solar and wind generation capacity, which necessitates more construction of gas plant for the purposes of firming capacity on the grid. Battery capacity alone is not sufficient to back up intermittent renewable power.
AI and Electricity Demand
AI and associated infrastructure such as data centres are coming fast. They have a rapacious demand for electricity. Data centres are searching for lowest cost electricity to keep them humming 24/7. Big Tech companies are looking at installing their own modular nuclear plant to ensure 100% reliable supply. The estimated cost of Australia’s Net-Zero driven energy transition is well behind the time. Rather than half-a-trillion dollars earmarked for just switching existing coal to RE, energy transition for the future will likely be more like double that amount if Australia stays with just SWB. What’s more, this is based on the initial stage of RE entry, while the entire power supply system already has gas plants to cover for new intermittency with heavily discounted pricing. For new intermittent generation entry, and closure of fossil fuel power plant, new private investment will need to come into the picture. The back-up cost will sky-rocket and this will drive retail electricity price accordingly. Germany had been increasing demand for gas supplied from Russia until the Ukraine invasion in 2022. Loss of this gas source has wreaked havoc on the E.U. economy except for France, which relies on nuclear power for two-thirds of its total need. China is relentlessly pursuing coal, gas and nuclear power expansion. Oil and gas prices went up across the globe on the back of the then U.S. government’s cancellation of the Keystone XL gas pipeline project and moves to curtail oil and gas exploration in 2022-24. These developments point to the absence of alternative fuels or technologies that could in the foreseeable future replace the current fossil fuel uses in industry and society.
The AI race will shove Net-Zero aside. It will be decided by default with nuclear energy and any other available power source on a horses-for-courses basis. Lower cost is the driver and the market will be the final arbiter. Either join the AI race with least cost, most reliable power supply or be relegated to the rank of “dumb economies” with relative falls in living standards. China and India are gunning for lowest-cost electricity supply simply for survival. This follows the long-standing strategy of excess production for exports as a means for maintaining employment growth.
Nuclear Energy
Nuclear power remains a clear option for Australia although public reservation towards it has been conditioned by Chernobyl and the more recent Fukushima Daiichi accident. However, modern nuclear fission is a totally different matter to those 1950-60s technologies. France is today’s nuclear energy superpower, with two-thirds of its power supply from nuclear fuel while it exports a net 60 million MWh to surrounding countries including the U.K., Netherlands, Germany, Switzerland, Italy and Spain. Uranium based nuclear power is a true and tested technology that can be packed into containers with a 20-30-year life span and placed on ships, with no re-fuelling or maintenance required, hence deployable safely in confined or open space, near or far from urban areas. Energy transition from natural gas to nuclear in this regard would be a much lower cost adventure than using SWB + backup power + network expansion + hydrogen.
The moratorium on nuclear energy must be lifted as soon as possible so that this zero-emission technology could be evaluated and included in the mix by the market. There is no need for rushing any high-cost tech in the power supply industry. Australia has at least a couple of hundred years of abundant low-emission, low-cost gas supply to use as power generation fuel.
A recent study by Frontier Economics (FE) puts paid to the misperception that nuclear energy is a higher cost alternative than the SWB portfolio option. FE emulated the AEMO’s model to conform with Government emission reduction targets and target of having a minimum amount of electricity demand from renewable energy. Those two Government conditions are irrelevant to the costing comparison, however, for the sake of comparing apple to apple, FE did just that and found that including nuclear into the mix of NEM generation portfolio would save consumers between $100 and $270 billion (25-44%), depending on the main scenarios used by AEMO, over the AEMO’s Integrated System Planning horizon. If the emission reduction and minimum renewable consumptions conditions are excluded, the use of nuclear power would outcompete all other forms of generation within 10 years on Australia’s main grid. And these results are based on maintaining the capex cost of nuclear at $10.0M/MW, a current project cost that would fall away quickly with accelerated commercialisation of nuclear energy at greater scale.
Around the world, nuclear energy is making a comeback, particularly since the start of the Ukraine war and subsequent termination of Russian gas supply to the E.U. There are 436 nuclear power stations in 32 countries with 60 under construction and 110 in planning. Pressure will be mounting on countries that refuse to come to the table to take advantage of nuclear energy. The U.S. has 93 active reactors, 26 scheduled to be decommissioned and 2 under construction. The age of the fleet and AI requirement points to an imminent renaissance for new reactor technologies.
To maintain a sovereign and competitive energy supply industry, France developed its nuclear power industry in the 1960s. By 2023, the country had 56 nuclear reactors in commercial operation, the second largest number in the world after the U.S. (93 reactors). Electricity generation derived from nuclear power reached 320 terawatt-hours (TWh), 63% of France’s total electricity generation. In Aug 2015, the French Government promulgated the Energy Transition for Green Growth Act and announced planned reduction in nuclear power dependency to 63.2 GW (50%) of total generation capacity by 2025 and promotion of renewable energy to 32% by 2030. No explicit reactor closures were mandated, but it implied phasing out older units. Implementation relies on the Multi-Year Energy Programme (PPE) planning the decommissioning of 14 nuclear reactors by 2035. However, the 2019 Energy-Climate Law delayed the 50% target to 2035 and planned closures of 14 reactors. While France closed the oldest Fessenheim plant (two 900 MW reactors) as a symbolic step towards diversification, Macron’s 2022 Belfort speech marked a “nuclear renaissance,” reversing prior cuts amid energy crises triggered by the Ukraine war. The policy integrates nuclear into the France 2030 plan (€54 billion investment) and the 2021-2030 Integrated National Energy and Climate Plan (INECP), aiming for 40% GHG reduction by 2030.
Having reaffirmed the importance of nuclear energy, the Macron government reversed course and announced a policy of building 6 to 14 new nuclear reactors and extending the operating life of all nuclear reactors to more than 50 years. Key elements of the new plan:
2022-25: Share and Capacity Targets: Maintain 70% nuclear in the mix short-term; no firm 50% cap until 2035; Multi-Year Energy Programme PPE3 (2025-35 draft) proposes extending operations beyond 50-60 years and building 6-14 new reactors to add 25 GW by 2050.
Reactor Extensions (Grand Carénage Program): €49.4 billion investment to extend most reactors from 40 to 50 years by 2025, and potentially to 60+ years (feasibility study approved in 2023); in July 2025, regulator ASN approved extensions for 1,300 MW reactors (Civaux, Chooz) beyond 40 years; inspections of all reactors prioritised for completion by 2025.
New Builds: 6 EPR2 reactors (1,650 MW each, simplified from EPR design) by 2035-40, with options for 8 more. First pair at Penly (applied 2023); others at Gravelines and Bugey/Tricastin. Construction start: 2027; first online: 2035.
Small Modular Reactors
Small modular nuclear reactors (SMR) have spilled over from military to civilian use. One of the proponents is X-Energy, supplier of the Xe-100 and Xe-Mobile reactors. This is based on High-Temperature Gas-cooled Reactor (HTGR) technology while the Xe-Mobile is a ground, sea and air transportable container power generation system that can be delivered to a user site with no construction or site preparation requirement.
The Xe-100 is a 80 MW reactor that can be scaled into a four-pack 320 MW power plant or even larger scale as required. The Xe-Mobile is designed to operate at full power for 3 years without refuelling at a 100% duty cycle, utilising fuel that is designed not to melt. It can produce 1-5 MW of electric power at 4.2 kV. The genset can be shipped to remote locations or urban infrastructure or construction sites. The company completed its most recent review of design processes and related costs on 31 March 2023, with updated cost estimates for the full ARDP scope to a total of $4.8 billion to $5.8 billion. This cost is for the total design, licensing and construction of the proprietary TRISO-X commercial fuel facilities and a 4 x E-100 pack power plant. With more orders and economies of scale, this total cost could be halved within 10 years.
As nuclear energy is catching up quickly with the advent of AI and its voracious demand for power, speculations of China having placed kill-switches in inverters and transformers exported with solar equipment places further momentum on the move to a sovereign nuclear power industry. The accompanying electricity generation by fuel source chart bodes well for nuclear energy. It corroborates other data sources. Given the decades-long head start that solar and wind have over nuclear power, the fact that nuclear makes up a substantial portion of total energy generation shows its critical importance. There are 436 nuclear power stations in 32 countries with 60 under construction and 110 in planning. Pressure will be mounting on countries that refuse to come to the table to take advantage of nuclear energy.
Timing
The main concern about nuclear energy is that Australia may have missed the window of opportunity to use it for AI development. This may be true for the initial wave of data centre establishment in which Australia has not been a contender anyway considering our rising electricity cost in the last decade. This stage is seen to be happening now until 2029. The next wave will be more in follow-up markets including Australia. Work can start now with any promise to lift the moratorium on nuclear energy in the next few years. Strategically and practically, we have no choice. The world will be moving to nuclear more and we’ll become a laggard in emission reduction (if this remains relevant) and electricity supply cost. We should aim for a 10-year program to place us in a reasonable position to contest in the global market. Otherwise, our productivity will continue to bump along the bottom of the OECD stack. A high-cost energy system will condemn our industrial base to remain unsustainable.
In the near term, there is no reason for Australia to lock itself into an unsustainable position of a combined power supply system. We can let the market build its own solar-wind-battery solutions wherever commercial and appropriate. Existing coal-fired power stations can also be extended to run an extra 5-10 years without much capital investment. In WA, their closure date has been pushed back a few times, currently until 2029. Another few years after that would make little difference in the scheme of things. Meanwhile, more high-efficiency gas turbines can be brought on stream quickly, to avoid the massive transmission and distribution network augmentation costs.
The U.S. Big-Tech seven are all installing or preparing their own nuclear power supply schemes, connected or unconnected to the main grids. From NVIDIA’s semiconductor plants in Arizona that are now mass producing 4-nanometer chips and heading to 2-nanometer chips by 2027, to Samsung’s Taylor, Texas plant that has inked a USD17 billion deal to produce AI6 chips for Tesla’s full-self-driving mode by 2028, to Musk’s Colossus-2 data-centre in Southaven, Mississippi, each plant requires gigawatt-size power supply system with absolutely reliable power that cannot be interfered with. Amazon, Microsoft, open AI, Meta, are pouring billions into AI factories because they need 10x to 20x more compute power than just some years ago when they were running smart models. These AI hyper-scalers are no longer running data centres but are becoming energy companies, having to install power plants to fuel AI faster and cheaper without encumbrances to the grid. They are defending the cloud and push the frontier of technology to survive. Microsoft is restarting the Three-Mile-Island nuclear power plant to secure about 850 MW of clean energy for AI, and Google is funding 3 new nuclear power plants for the very same reason. 10 years ago, the biggest data centres ran on tens of megawatts and today AI demands gigawatts of power supply capacity. Hyper-scalers are on track to own more nuclear power capacity than some nuclear energy nations. The country that can lock down the most energy at lowest cost will shape the balance of power not just at the individual company or industry level but the level of nations.
It is gross negligence on the part of Australian government to continue to keep the ban on nuclear energy, the highest density, most reliable and cleanest energy source that is fundamental to allowing Australia to keep pace with AI development worldwide.
