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The Future of our Power Grid Humanity has used fossil fuels as our dominant source of energy since the Industrial Revolution. We are now in the throes of change as we transition to other energy sources. Electrification is increasing, but how will we generate all this power? A ustralia generates the majority of its electricity from coal, as explained in my article in the August 2023 issue on the Australian electrical grid and its generation mix (siliconchip. au/Article/15900). Coal has been a cheap and reliable source of power for a century, but many coal-fired power stations are approaching the end of their designed life and will be decommissioned in the coming years (see the panel). These coal-fired power stations will need to be replaced with new generators. Additional capacity will also need to be built to meet increasing demand from population growth, transport electrification, industry and domestic consumption. Fortunately, Australia can take a pick of the best technologies, as we have some of the world’s most plentiful fuels. This article will consider ‘best’ to be the cheapest generation that meets the Australian Energy Market Operator’s (AEMO) reliability standard: 99.998% or better uptime, or less than 11 minutes per year of blackout on average per person. These costs must include not just the generator itself, but also any required network augmentation, storage, waste disposal, etc. Deliberately excluded are any discussions of indirect costs of generation, such as ecological impacts, population health issues, noise pollution and so on as while they are real, they are difficult to quantify. Coal power stations The most obvious solution to replacing our existing coal power stations is simply to build new ones. In many ways, this makes sense; Australia has some of the world’s largest coal reserves. We also have established mines to extract it, transmission infrastructure already built to carry this power to where it is needed, and an experienced workforce well versed at running this type of plant. It is an approach that has served us well thus far, so why change now? The problem is that coal is an increasingly uncompetitive way to Part 1 by Brandon Speedie generate electricity, driven largely by two factors. Firstly, cheaper variable sources of generation are entering the market. As coal power stations are designed to run all the time with only gradual changes to their output power, it’s challenging to match them to an increasingly dynamic grid. Second, the price of coal is rising. In a little over two years from August 2020 to September 2022, prices increased from $50 per tonne to $430 a tonne (see Fig.1). Prices have since fallen to around $150 per tonne, but that is still high by historical standards. It is for these financial reasons that many coal power stations are facing an early closure, despite still having usable life left. Nuclear power stations At first glance, nuclear fission looks promising as a drop-in replacement for coal. Nuclear power stations operate similarly to coal plants, with large turbines spinning all the time and only slow changes to output power. The Fig.1: the Australian coal price in USD ($) per metric tonne over the last five years. Source: https://ycharts.com/indicators/ australia_coal_price 40 Silicon Chip Australia's electronics magazine siliconchip.com.au power stations could be built nearby or in place of the existing coal fleet, reusing the transmission infrastructure and (with some training) redeploying the skilled workforce. The grid would hardly notice a difference. Australia is also well-suited geologically to nuclear fission-based power. This country has by far the biggest uranium reserves in the world, much of which is served by established mines. Also, the landmass sits in the centre of a tectonic plate, mitigating the risk of a meltdown from a natural disaster. The main problem is inflexibility. Fission power stations typically operate above 90% capacity factor, meaning that they run close to the full rated output power at all times. Much like coal, they are slow to ramp their power up and down, and very slow to restart if stopped completely. This makes them increasingly difficult to match to the grid. Nuclear power is also expensive; assuming a high-capacity factor, it is the most costly generation type of the established technologies. If required to run flexibly (that is, at a lower capacity factor), costs increase further. irradiance of any country, which makes photovoltaics our cheapest way to generate electricity. But solar is highly variable, so it needs to be combined with more expensive technologies to provide stability to the grid. Rooftop solar is being built rapidly, with over 3.4 million homes, businesses and industrial facilities now boasting a solar system. This represents over 20GW of capacity across the eastern states. Grid-scale solar is even cheaper than rooftop due to economies of scale, and also its more favourable yield and generation profile. Grid-scale farms are designed to avoid shading between panels and from nearby structures, which is often not possible on rooftop systems. Most grid-scale farms also have motorised pivots to track the sun. This results in superior energy production per panel, but also a more favourable generation profile (see Figs.2 & 3). The grid is typically shorter on supply at dawn and dusk than during the middle of the day, so grid-scale solar earns better financial returns by tracking the sun and maximising output at these times. Natural gas Wind power Given the trends in fossil fuel prices, natural gas is an increasingly expensive way to generate electricity. However, gas has an advantage over many other generation types, which will likely see it remain part of our energy mix well into the future. That advantage is speed; gas ‘peakers’ can ramp their output power up and down rapidly. This makes them good for ‘firming’: shoring up supply when there is a critical shortfall, or when other generation types can’t respond fast enough. Australia has the world’s 13th largest natural gas reserves, and is the world’s largest exporter, so it is a well-­supplied industry. While natural gas is currently the dominant fuel in this segment, it is possible other types will enter the market. Waste methane from industrial processes, such as waste water treatment and agricultural processing, is increasingly being captured and combusted for generation. Alternative fuels such as hydrogen may also have a future role to play. Australia’s southern states have some of the best wind resources in the world given their proximity to the “Roaring Forties”. Onshore wind has a higher capital cost than solar, but due to its more favourable generation shape and capacity factor, it is able to earn higher revenues. Thus, its overall energy cost levels out to only slightly higher than solar. It is our second-cheapest source of electricity. While wind is less variable than solar, it will also need to be combined with more expensive technologies to ensure grid stability. The economics of offshore wind are much more uncertain. Globally, there are some offshore projects in construction or operation, but they compare poorly to onshore developments due to their high capital cost and maintenance difficulties. Solar power Australia has the highest solar siliconchip.com.au Hydroelectricity Hydroelectricity has a long history in this country; projects like the Snowy Mountains Hydroelectric Scheme are a source of great national pride. Unfortunately, rain is one of the few natural resources Australia doesn’t have much of, being the driest inhabited continent Australia's electronics magazine Coal power plants in Aus. A list of coal power plants in Australia that are either still operating or have been decommissioned recently. Victoria Hazelwood (1600MW): built in 1964, decommissioned in 2017 Yallourn W (1480MW): built in 1975, due for closure in 2028 Loy Yang A (2200MW): built in 1984, due for closure in 2035 Loy Yang B (1050MW): built in 1993, due for closure in 2047 New South Wales Liddell (2051MW): built in 1971, decommissioned in 2023 Eraring (2880MW): built in 1982, due for closure in 2027 Vales Point B (1320MW): built in 1978, due for closure in 2029 Bayswater (2640MW): built in 1982, due for closure in 2033 Mt Piper (1400MW): built in 1993, due for closure in 2040 Queensland Callide B (700MW): built in 1988, due for closure in 2028 Gladstone (1680MW): built in 1976, due for closure in 2035 Tarong (1400MW): built in 1984, due for closure in 2037 Stanwell (1445MW): built in 1993, due for closure in 2046 Kogan Creek (744MW): built in 2007, no scheduled closure date Callide C (810MW): built in 2001, no scheduled closure date but hasn’t operated since 2021 Millmerran (852MW): built in 2002, no scheduled closure date South Australia Northern (520MW): decommissioned in 2016 Playford B (240MW): decommissioned in 2016 Western Australia Collie (340MW): built in 1999, due for closure in 2027 Muja (854MW): built in 1981, staged for decommissioning in 2022, 2024 & 2029 Bluewaters (416MW): built in 2009, no scheduled closure date March 2025  41 Fig.2: the power output (red) of a real-world solar farm with fixed tilt panels. Irradiance is shown in pink. Fig.3: similar to Fig.2 but the solar farm has panels that track the sun. Horizontal irradiance is shown in purple, with panel irradiance shown in pink. Note the increased output at the start and end of the day compared to the fixed system. on Earth. Of the rain that we do get, much is already captured in existing hydro systems. The opportunities that exist are not cost-competitive from the perspective of electricity generation. In fact, many of Australia’s existing hydro projects serve the main purpose of irrigation for agriculture, with electricity as a secondary benefit. For this reason, Hydro is unlikely to see any meaningful expansion in this country. There are several Pumped Hydro projects in construction and development and that sector is expected to continue strong growth. See the later section on storage. The generation mix Looking at generation types in isolation is useful to understand the relative merits and drawbacks of each technology, but the optimum fleet will feature a diverse mix. By combining different fuels, the limitations of some types can be compensated for by others. A good example of this is our historical fossil fuel system, which used coal as the workhorse and gas for load matching. It would be difficult to run 42 Silicon Chip a grid on just coal, and expensive on just gas; a combination of the two gives a more optimal solution. Fig.4 shows a forecast of how the eastern seaboard grid (the NEM) is likely to change from now until 2050. Three scenarios are modelled: “step change”, which forecasts changes to the industry at current rates; “progressive change”, which is a more conservative view of the speed of the energy transition; and “green energy exports”, which is a bullish view that considers Australia becoming an exporter of energy to other nations (mainly through derivatives such as hydrogen or metals smelting). This modelling has some interesting takeaways. Most striking is the sheer increase in capacity. The entire fleet expands six-fold, from the current level of 50GW to just under 300GW. This is driven by increased electricity demand and a shift away from high-capacity factor generation (coal, mid-merit gas) towards low capacity factor generators: wind, solar, flexible gas and storage. Unsurprisingly, rooftop solar is projected to continue its rapid expansion. Australia's electronics magazine From now until 2050, capacity is expected to increase from 20GW to a monumental 100GW. A similar but slightly smaller growth is seen in gridscale solar and onshore wind. Interestingly, this modelling shows a small amount of offshore wind, which is the direct result of a taxpayer funded scheme to build a farm off the Gippsland coast and/or in Bass Strait. If the Victorian government changes their policy in future, this capacity will disappear in the modelling, as the private sector deems it uneconomic. The combination of wind and solar makes up a mammoth 220GW of capacity and will be the workhorse of the future power grid. These two generation types work favourably together because their supply is driven by opposing weather patterns; high pressure is generally good for solar, while low pressure accompanies increased wind. Despite this correlation, there are times when both solar and wind output is low. During these periods, other generation will need to be called upon, so-called ‘dispatchable capacity’, which can be run on demand. The black line in the modelling shows the required dispatchable capacity increasing from the current 40GW to around 75GW by 2050. While the amount of this capacity only increases modestly, its composition changes quite dramatically. Currently, dispatchable capacity is predominantly coal, with smaller contributions from hydro and mid-merit gas (otherwise known as load following gas; not as versatile as flexible gas, but faster than coal). Hydro aside, this composition is projected to entirely change by 2050. Firstly, coal and mid-merit gas reach their end of life and are not replaced by new power stations. Instead, utility storage takes its place, mostly made up of pumped hydro and batteries. There is also a modest increase in flexible gas that can start up rapidly. From around 2030 onwards, an interesting trend emerges. The modelling shows a large increase in ‘coordinated CER storage’. CER stands for consumer energy resources, which are small-scale storage assets like home batteries or electric vehicles with V2G capability (see the July 2023 article for a detailed look at EV charging, including Vehicle to Grid – siliconchip.au/ Article/15857). siliconchip.com.au These assets would be directly controlled to respond to the needs of the grid, typically as a member of a ‘virtual power plant’ (VPP). Most remarkably, AEMO is projecting CER storage will overtake grid-scale storage in overall capacity by around 2045. A smaller amount of ‘passive CER’ is also modelled. These are home batteries and EVs that aren’t directly orchestrated in a VPP, but are still incentivised to respond to grid demands through indirect means like a price signal. While the AEMO doesn’t consider this ‘dispatchable’ by their definitions, it will still support the grid in the same way. Remaining dispatchable capacity is made up of a very small amount of biomass (combustible organics), and ‘demand side participation’, which will be covered in the later section on Demand Response. I believe AEMO is being conservative with their estimates of demand-side participation, and actual dispatchable capacity will be higher. the Electric Grid from August 2023 – siliconchip.au/Article/15900). They are increasingly also being deployed in network support roles, easing transmission constraints (Fig.5) and deferring costly line upgrades. Batteries are also used in voltage control applications, which will be discussed in the later section on reactive power. Given their flexibility to perform in multiple applications and their freedom to be installed basically anywhere, lithium-ion batteries are currently being constructed at a rapid rate. They have recently overtaken pumped hydro as the largest storage in the NEM. Fig.6 shows how one of the major inputs for building lithium-ion batteries has become a lot cheaper over time. There are also some less mature technologies that are worth mentioning. Some early generation ‘flow batteries’ such as vanadium and zinc bromine types are currently operating in the grid. They don’t degrade through charge and discharge cycles like a Energy storage The largest change in dispatchable capacity is a trend away from fossil fuels towards utility and CER storage. While it could be argued that fossil fuels are a form of storage (chemical energy held in carbon bonds, and released when burnt), the phrase ‘storage’ is reserved for technologies that consume electricity and later release it. Historically, this has mainly been pumped hydro, but more recently lithium-­ion batteries have shown enormous growth. In the same way as the generation mix, storage technologies work best when used together. The main advantage of Pumped Hydro is its long duration. While this capacity is often constrained by competing factors such as environmental limits or water supply security, it is cheaper than lithium-ion batteries in this role. By contrast, lithium-ion batteries are cheaper than pumped hydro for short duration storage, and also offer a higher round trip efficiency (90% batteries vs 75% for pumped hydro). Lithium-ion batteries have other benefits that are making them increasingly popular. As they are extremely fast responding, they are being employed in grid stability services such as FCAS (Frequency Control Ancillary Services; see my article on siliconchip.com.au Fig.4: generation mix changes from now until 2050. Three scenarios are modelled, the most bullish being “green energy exports”, the most conservative “progressive change” and the central scenario shown as “step change”. Dispatchable capacity is indicated by the black line. Source: AEMO ISP 2024, p48 Fig.5: using a battery for ‘peak shaving’. As the transmission line reaches its thermal limit, the battery discharges to prevent an overload. Overall throughput is improved, as the line can be operated closer to its rating for longer periods. Source: www.mdpi.com/1996-1073/15/6/2278 Australia's electronics magazine March 2025  43 Fig.6: the mined lithium carbonate price in the last year. Lithium-ion batteries have subsequently shown a sharp reduction in cost over the last few months. Source: https://tradingeconomics.com/commodity/lithium lithium-ion battery does, but they have much lower energy density and poor round-trip efficiency. Mechanical energy storage methods, such as compressed air or gravity storage, are also used in very niche scenarios. One notable example is using decommissioned mine shafts to suspend weights. It has poor economics from an electricity storage perspective, but there are other benefits in mine shaft upkeep and rehabilitation. See the April 2020 article on GridScale Energy Storage for a more detailed look at grid storage, including gravity systems (siliconchip.au/ Article/13801). Demand Response While dispatchable capacity is largely thought of from a supply perspective, it can also be created from demand side solutions. Demand Response (DR) refers to deliberately switching off a load to meet a generation shortfall, network constraint or grid stability requirement. While this is not technically storage, it helps the grid in the same way. At its crudest, this can be the deliberate load shedding network operators employ in an emergency scenario. Historically, this has been during summer heatwaves when the grid exceeds its rated capacity, and substation feeders are deliberately switched off on a scheduled rotation. This type of DR is extremely unpopular in Australia, as electricity customers have no control over when the outage occurs. Fortunately, there are less impactful ways to shed load that can have the same positive outcomes. Any process that has some flexibility in when it needs to run is a good target for DR. An example might be a cool room used for frozen food storage. Given the vast size of the fridge, it might take three days to defrost, but only needs compressors to run eight hours a day to maintain temperature. By automating the pumps to turn on during periods of high supply and turn off when the grid is supply constrained, the thermal mass of the refrigerator is effectively used as storage. Diesel backup generators are another example gaining popularity. Many commercial or industrial facilities already have diesel backup for blackouts, or for operation/maintenance reasons. While most of these generators are not allowed to export energy into the grid, they do effectively work as demand response by removing a grid connected load. It is common for these assets to run for a minimum of 20 hours per year for preventative maintenance reasons. Simply aligning those mandatory hours with periods of high electricity demand increases dispatchable capacity. Cost comparisons It is common in industry to compare generators by their LCOE (Levelised Cost Of Energy/Electricity), which considers revenues and costs over the Fig.7: Levelised Cost of Electricity (LCOE) estimates for 2023 marked in cyan. Projected costs for 2050 are shown in red and are based on current trends. VRE is a combination of wind and solar, with storage and transmission costs included. Source: Gencost 2023/24, p72 & p75 44 Silicon Chip Australia's electronics magazine siliconchip.com.au entire life of the asset. Simply put, the LCOE of a generator is how much revenue it would need to earn per MWh of energy generated to pay for its construction and operating expenses. While this metric isn’t without its flaws, it does give a reasonable indication of how cheaply different generation types can be built. Still, there can be large variation in returns over different timescales, regions, and economic conditions, so we are listing an upper and lower range for a given fuel type. Fig.7 shows the current range of prices for 2023 in cyan, while in red shows a projection of the same costs at 2050, using current trends. The cheapest generator is solar, currently being built for between $47 and $79 per MWh, followed by onshore wind for $66 to $109 per MWh. This is the price for the individual generators, but given their variability, they will need to be combined with other technologies. This modelling considers a separate generator, VRE (variable renewable energy), which is a combination of solar and wind along with firming via storage and associated transmission upgrades. The price for a 90% VRE share is currently assumed at between $100 and $143 per MWh, projected to reduce to between $89 and $128 in 2030 (see Figs.8 & 9). The next cheapest are the fossil fuel generators; black coal at between $107 and $211 per MWh, followed by brown coal at $118 to $199. Midmerit gas is broadly similar at $124 to $183 per MWh. Gas peakers are classified separately; they operate at a low capacity factor, so are more expensive per unit of energy. Depending on the technology, they can currently be built for between $204 and $296 per MWh. Nuclear is estimated at between $155 and $252 per MWh, reducing to $133 to $221 by 2050. Without firming, offshore wind is estimated at between $146 to $190. Figs.8 & 9: the VRE cost breakdown for 2023 (top) and 2030 (bottom). Spillage is curtailed energy, a deliberate reduction in generation to ease an oversupply problem. It is cheaper to overbuild wind and solar generation and spill energy, rather than investing in additional storage. Source: Gencost 2023/24, p70 Grid stability The operation of a grid is not just about meeting supply with demand, but also ensuring the system is robust. Historically, this has been achieved mainly through ‘spinning reserve’; large rotating turbines. The energy transition is seeing a trend away from these alternators towards Inverter Based Resources (IBR), which replace these electromechanical systems with electronics. siliconchip.com.au Fig.10: global trends in LCOE from 2009 to 2023. Source: https://w.wiki/BnN IBRs have different strengths and weaknesses to spinning reserve, and will need to be operated differently to achieve the same stability outcomes. In the follow-up article next month, we will look at how the different types of Australia's electronics magazine IBRs work, and how they are used to provide grid stability. That article will also include plenty of detail on the electronics used in modern electrical generators and the electricity distribution grid. SC March 2025  45