Price matters more than volume to coal generators

Coal generators will certainly lose volume over the next few years as a group. Perhaps this will hurt the brown coal generators more because of their high level of fixed costs. But as far as I can see its price that matters a lot more than volume. Indeed its a sure sign of age that I have work out again what I already knew 30 years ago.

The other message of this piece is that it pays to announce you are going to close. Its a wonder the owners of LYB, Vales Point, Mt Piper and Bayswater haven’t already announced their closure. It seems to be the sure way to Govt funded capacity payment. Perhaps they are waiting to see what Eraring gets before quickly following suit. Might be a case of first in best dresse though.

Coal generation sensitivity to falling price and volume

Coal generators in Australia are expected to mostly all close over the next 11 years. That’s a short time frame and may or may not be achieved.

State Governments particularly in Victoria and NSW have become concerned that coal generators may close before there is enough new supply to replace them.

The coal generators will close because revenues will fall as lower variable cost supply from wind and solar comes on line, and becaause of increased competing supply, from batteries, at peak price times.

A coal generator has both fixed and variable costs and is an almost text book example to show the impact of the contribution margin on profitability. We can compare Eraring and Loy Yang A as follows:

I’ve shown the estimtimated market coal price in US$/t. Using the legistated coal cap adds over $100 m to profit at currrent price and volume. That’s quite a bit more difference than I anticipated. Eraring is in effect heavily subsisided already, as likely is Vales Point. Even at market price for coal the numbers show Eraring to be a better proposition than LYA, it breaks even at lower volumes and has more cashflow, but the cash flow depends on both the price and volume.

For instance Eraring cash flow after capex is quite sensitive to both price and volume but its clearly more sensitivity to price. At $80 MWh, entirely within the range of possibities and if coal prices are at current spot rates then Eraring has negative cash flow at any volume. At $100/MWh it can wash its face even if it loses 1/3 of volumes. Still 5TWh is less than the output of 2 GW of wind and that in due course is a certain outcome.

The good news for consumers, if therre is any, is that there will be more need for a Govt funded capacity payment in the event of lower prices than lower volumes. In the case of Eraring that using the subsidised coal cost of A$125/t improves ORG cash flow by as much as $100 m.

Its much the same at LYA despite the lower fuel cost and the higher fixed costs. Its still price that is more important than volume.

Renewables are subsidised but the subsidy amount is generally known

At least the REC price is public. Even in the case of PPAs there is generally some information about the price.

So far though, at least in Victoria, the capacity arrangements with Energy Australia in regard to Yallourn and with AGL in regard to LYA are completely unknown.

It may be that LYB enjoys a similar pro rata agreement to LYA, who knows? Nothing has been announced. However what if LYA is getting paid for capacity but still free to sell its output and LYB is not getting paid for capacity. Clearly LYB will need a higher price than LYA to stay open.

Its likely that ORG will also get a capacity payment.

Politicians who make a difference

Four politicians in Australia over the past 15 years stand out as having made a real difference in energy policy in a way that will benefit most Australians. They are:

• Lily D’Ambrosio
• Matt Kean
• Mick Di Brenni
• Chris Bowen

Notwithstanding the mark of all good policiticans, and that is the courage of their convictions, D’Ambrosio and Di Brenni enjoy a dominant position in their parliament. Both are distinguished.

Matt Kean stands out for being the leader of a Parliament that collectively agreed on a policy designed to move NSW forward. However his achievement was only possible because he lead and the ALP and the NSW National party followed. His achievement was consensus. Consensus was possible because the policy was likely to succeed and be effective and served the interests of NSW. It had something for everyone including voters.

Chris Bowen stands out as having achieved more than any other Federal Energy Minister in the past 15 years without actually making too many waves. It is easy to criticise Federal policy as not going far enough but the achievements include:

• Restoring Federalism and genuine consultation in energy policy after Angus Taylor in particular had created animosity with everything he touched. The importance of this goes to how Federal and State policy can be coordinated ie NSW LTESA with Federal CIS. More than that if the “word” is kick the Planning Depts into action then maybe it will happen.
• An improved, if still imperfect, “Safeguard mechanism”
• Capacity Investment Scheme;
• A genuine fuel efficiency standard (yet to be legislated)
  
• Funding for transmission that one way and and another has enabled early works on say Hume Link.
• I would add that it seems to me Bowen does his homework, consults widely and listens. John Howard was the same.

By contrast the Federal opposition opposes wind and solar and supports nuclear

Imagine you were AEMO. You have spent $millions with a significant team of people developing over 4 years what is now the second comprehensive version of the ISP. You have had basically the enitre set of industry stakeholders formally input via the “Delphi” method their consensus opinion of the way forward.

Then you observe the dominant faction in the Federal Opposition encouraging and speaking at an anti wind and solar forum, . The leader of the Nationals, David Littleproud, not at the rally, nevertheless leaned in to the anti renewables push as the SMH reported.

New renewable energy projects in regional Australia must be stopped now, Nationals leader David Littleproud has declared as he claims the nation should downgrade its commitment under the Paris Agreement, signalling a major escalation in the political brawl over climate policy.

Regional communities and farmland cannot cope with more wind and solar farms, as well as transmission lines, Littleproud said.

This of course factually garbage. Its complete and utter tripe. How can Australia progress when leaders make statements like this? Imagine General Monash telling the Australian troops that the Germans don’t have any guns. That’s the level Littleproud is at. Just depressing to me as there so many interesting and real problems to solve.

Look at the politicians that were reported in the above article to have attended the Canberra rally!

The Nationals could make a real difference but as it stands they will try to make electricity expensive and unreliable

If they wanted to the National Party could actually make a big difference to lowering prices of electricity by helping to smooth the way for renewable energy to be built in regional Australia. Not only would this benefit the vast majority of Australia but it brings the many $billions of investment. It also brings costs. But instead of helping to bridge the gap, instead of adopting the mainstream view of the electricity industry the Federal Opposition make it as hard as it possibly can to get the job done. They subscribe to net zero and then talk about the “ute tax”. Peter Dutton could basically tell his team to back AEMO. He could show some real leadership like Gladys Berijiklian did in appointing Matt Kean. His failure to grasp the nettle is not going to stop anything longer term because climate change and economics will inevitably win the battle longer term. All he does is paint his party into a smaller and smaller corner.

Liberals are presently in reality the smaller group from one perspective in the Federal Opposition

QLD Nationals/Lib and the Nationals are presently the largest force in the Federal Opposition. Most will say this classification is wrong because the Queensland LNP sit in the Liberal partyroom where they notionally could be outvoted. However to an amateur like me it seems that the Nationals and LNP make policy which they then impose on the Liberal Party Room. To the best of my knowledge Dutton is not differentiated from the National Party on any substanial policy issue.

As is well known low Liberal number are partly because a number of Liberal seats were lost to Teals and partly because of perhaps one off events in West Australia. Liberal seats were lost to Teals because their moderate members, lets call them the Keans, a were unable to stand up to the dominant QLD/National faction and had zero influence on policy. Their constitutents wanted members that represented their values.

Having lost so many seats the Liberals seem now to be even less influential, even inconsequential. Other than Angus Taylor who is a de facto member of the LNP, its hard to think of a single Liberal with anything important to say or any real influence on Opposition policy

From a perspective of a Matt Kean supporter the problem was the merging of the National and Liberals in QLD. As things stand it now seems that has made the Nationals more powerful and the Liberals weaker.

None of this is news. How it will work out I don’t know. It could work out by a strong Liberal moving the LNP back into middle Australia. Something Turnbull was unable to do and Morrison had no need of or interest in doing.

What I do know is that no matter who is in power, decarbonsiation will proceed. It would seem more sensible to swim with the tide than pretend it doesn’t exist and make the job harder and harder

Batteries are becoming significant.

Over the past couple of years one technology, initially the butt of jokes, has come to be taken very seriously and captured a big share of the incremental investment dollars. And that’s batteries, or for engineers, never satisfied unless there is an acronym, its BESS. Its become clear that the role of batteries, evident to me for close on a decade, is moving from the fringes to the mainstream. In the case of the NEM we can think of the fringe as FCAS or ancillary services, to firming wind and solar, [VRE]. Even on the fringes its now I think, accepted by the industry that batteries are the ideal technology for frequency control, capable of virtual inertia as well as very fast frequency control. Cost reductions driven by learning rates seen the use of batteries in EVs are now seeing developers start to choose batteries over pumped hydro projects even in the 8-10 hour duration task. Development times are so much faster, environmental and more broadly social license issues are so much easier even if the useful life is much shorter.

Battery revenue by source

The GSD is indexed by alphabetic DUID. Unfotunately there is no “fuel type” index. I was interested to find out where batteries get their revenue from and how this is changing. The GSD does a great job of presenting this information. For instance if I look up the battery that got the ball rolling in Australia, that is the Hornsdale Power Reserve [HPR] (page 684) in the digest can see the following figure.

Figure 1 Hornsdale Power Reserve, monthly revenue by segment. Source: GSD

From this I can see that HPR’s revenue is lumpy and that much of its revenue is derived from lowering frequency. In general its eaerned negative revenue from selling, and buying energy. Using the excellent Global-Roam NEM Review product which does allow selection by fuel I was able to identify the 16 utilty batteries that were in operation at one time or another in the NEM in the past year. I used these with the GSD to produce an analysis of batteries by revenue source for all of 2023.

/Figure 2 NEM batteries revenue 2023. Source: GSD

Readers should note that battery analysts are really interested in the “spread” revenue rather than just “sales” as the battery energy has to be bought as well as sold. Still based solely on the chart it seems that the sale of “energy” is a big share of category revenue.

Looking at only the FCAS revenue its interesting to see that although “raise contingency” is the main sector driver a couple of batteries had lower contingency as the main source.

/Figure 3 NEM battery FCAS revenue 2023. Source: GSD

In terms of forecasts I expect both energy and FCAS revenues to grow over time. As the coal generators close batteries will provide all the frequency control in an inverter based grid. To the best of my knowledge based on discussions with the technical people this is not something to be feared but rather embraced. Batteries can be widely distributed in the grid providing resilience at many points to frequency shocks.

Coal units dominate the top revenue DUIDs

Figure 4 Top revenue earning units in the NEM 2023. Source: GSD

Demand response achieves highest volume weighted price but…

Demand Response volumes are tiny as yet and I don’t focus on them. For both producers and consumers what really matters is average day peak prices. For instance the following figure shows the average time of day price over the past year for selected States.

Figure 5 Major state average time of day prices, last 12 months. Source: NEM Review

Its clear that that the average time weighted priced is impacted by peak prices. For instance for NSW last year keeping the average maximum halfhourly price to $130/MWh (above the fuel cost of gas) drops NSW prices by over $10/MWh.

Figure 6 NSW actual prices and impact of lowering only evening peak prices. Source: NEM Review, ITK

Batteries are already choosing to price above gas in some instance, but as more batteries are built there will essentially be more competition to be dispatched and peak prices will come under pressure. Or at least that is my expectation.

Figure 7 Highest average price earners in NEM. Source: GSD

Finally at this glance through the GSD what about the lowest price receivers?

Certainly there were, as you would expect, some solar farms near the bottom of the list. Kiama Solar Farm 1 average price was $12/MWh, GLENSF1 (Glen Rowan) did worse averaging -9.71/MWh. Essentially it was generating to earn RECs, not really a happy place should its PPA expire and conditions not have changed.

However it was interesting to see, given that AGL received just $22/MWh for Macarthur wind farm, one of the largest in the NEM.

Key Takeaways

• Industry lore of 75% wind / 25% solar holds (almost) true in our VRE portfolio optimization exercise. We incentivised a model to generate a solar/wind portfolio from AEMO’s Renewable Energy Zones (REZ’s) that maximizes its return relative to risk (Sharpe ratio), and no constraints were placed on the proportion of wind and solar, nor the geographical distribution of the generation. The generated portfolio came to 77% wind, 23% solar. Indeed, in subsequent sensitivity analyses, varying the wind to solar ratio either side of this optimum increased the long-term costs of the system (capital + fuel + firming dispatch). Increasing solar % of the portfolio decreases the upfront costs, but significantly increases firming capacity requirements and expenditure on fuel for firming gas generation over time.

• Generation in this Sharpe-ratio optimized portfolio is very heavily weighted to Far North Queensland. This portfolio sees Qld, SA, and Tas being net exporters, NSW and Vic net importers of energy. Given the location of the demand centres, it is highly likely that an optimized system which accounts for transmission costs will shift generation further South.

• The optimized VRE + Firming Capacity system modelled in this analysis requires:

  • 56 GW of Variable Renewable Energy capacity supplying 160 TWh of energy in 2025,

  • 15 GW / 4 hours of storage capacity supplying 3 TWh of energy in 2025,

  • 7.5 GW / 14TWh of (existing) Hydro, and

  • 8 GW of open cycle gas supplying 4 TWh of energy in 2025.

The total capital (excluding Hydro) is $169 billion. The VRE cost is $123 billion, and gas firming capacity cost $46 billion.

• The amount of battery storage required is dependent on the order in which firming resources are used. If Batteries are dispatched first the seasonal nature of VRE production means that there will be large surpluses at times but also very large deficits. If dispatched last the batteries spend too much time at full capacity with surplus VRE wasted. Realistically there is a large incentive to discharge full batteries when sunlight is abundant. By dispatching batteries first in Summer but last in winter, an additional 2.6 TWh of additional energy can be supplied by batteries instead of gas. Refining the dispatch algorithm seems to offer the promise of further reducing the overall theoretical cost.

2022 ISP vs. 2024 ISP

The 2024 ISP generally forecasts higher rooftop PV compared with the 2022 ISP. This gap starts relatively small (around 2023-2025) and significantly widens over time. According to the AEMO 2024 Draft ISP “Consumer Energy Sources are forecasted to be taken up even faster than before, with 18GW more rooftop solar by 2050 under Step Change compared to the 2022 ISP”. Increased EV uptake also significantly bumps daytime total demand, as consumers leverage increased rooftop solar to charge their cars.

Figure 1 – 2024 ISP demand forecast compared to 2022 forecast by time of day in 2050 (Source: AEMO 2022 ISP and 2024 Draft ISP)

Sharpe-Ratio-Optimized VRE Portfolio

State Demand vs. Generation

Queensland, SA, and Tasmania will be net exporters and Victoria and New South Wales net importers of energy based on our VRE portfolio and 2025 operational demand. The net importers happen to be the states with densest population, by a significant margin, see Figure 3. Logically, this net import/export status is partially explained by having less land available for high quality renewable energy generation per (energy-consuming)-capita in the densely populated states.

Figure 3 – Net Energy Balance and Population Density by State 2025 (Source: AEMO 2022 ISP)

Figure 4 – Demand and Generation by State 2025 (Source: AEMO 2022 ISP)

It is also explained by the quality of renewable energy in each of the states. Vic and NSW’s REZ’s have the lowest mean capacity factors, highest CFs are in Tasmania and Queensland. Figure 5.

Figure 5 – State average Renewable Energy Capacity Factors (Source: AEMO 2022 ISP)

Sub-Regional Demand

Figure 6 shows how heavily NEM demand is weighted towards the NEM’s lower latitudes (Sydney-Newcastle-Wollongong and Victoria subregions alone make up > 50% of NEM demand in 2025).

Figure 6 – 2025 OPSO Demand by NEM Subregion (Source: AEMO 2024 Draft ISP)

To contextualize the distance between our VRE portfolio generation and demand centres, Figure 7 illustrates demand by sub-region alongside VRE portfolio generation on an Australian map. The significant distance between the highest generating REZ's and the highest-demand sub-regions underscores the need to incorporate associated transmission costs in future iterations of portfolio optimization. Given the considerable distance of the Far North Queensland REZ from major demand centres, transmission costs are likely to redirect a lot of this energy generation further South.

Figure 7 – Sharpe-Optimized Portfolio Generation (Source: AEMO 2022 ISP) and AMEO Sub-Regional Demand (Source: AEMO 2024 Draft ISP)

Method

A system was then designed to meet the NEM operational (OPSO) demand for every half-hour period of the 2025 calendar year. ISP 2022 half hourly demand traces for CY 2025 were used, 17520 datapoints. We have assumed that energy flows freely from the REZ’s through to the demand centres as required and assumed no transmission losses. A transmission network will be modelled, and the cost of this transmission incorporated in future iterations of this analysis. We then firm renewable energy generation with storage capacity, pumped hydro, and open cycle gas, per the following dispatch order.

• Solar/wind energy is dispatched first. Where combined solar/wind generation exceeds NEM demand, the energy is used to charge up storage, or spilt when storage capacity is exceeded. For simplicity, we have assumed a round trip efficiency of 100%.

• For any half-hour period where NEM demand cannot be met by solar/wind:

1. In the months September through February, draw energy from storage if state of charge (SOC) greater than 80% capacity. Discharge as required until capacity < 10%. Figure 8 shows the impact of dispatching battery first in the summer months.

2. Dispatch Hydro. We’ve assumed 7.5 GW and capacity of 14 TWh that can be drawn down at a cost of $5 / MWh.

3. Dispatch open cycle gas. We increase modelled gas capacity to ensure that demand is met in every period.

4. Dispatch storage, if not already dispatched in step 1, above. March through August we save storage until last in the dispatch order to firm hydro/gas in the case of renewable energy “droughts”. This ensures that battery capacity isn’t low when the NEM experiences long “negative runs” where demand exceeds VRE generation. Storage capacity is set to 4 hours at 15.4 GW¹. Further optimization of storage capacity is planned in future analysis work.

Figure 8 – Effect of Firming Dispatch Order on Storage Supply and Gas Fuel Costs

Sensitivity Analysis

After modelling the above system, we conducted a sensitivity analysis to examine the impact of varying the VRE portfolio capacity and the percentage of solar in the portfolio on both the capital cost and the combined (capital + fuel) costs over 5, 10, 15, and 30 years. Note, as this is a sensitivity analysis rather than a detailed costing exercise, 2025 fuel costs were simply extrapolated out over the specified time periods rather than adjusting annual fuel costs in line with demand. Future iterations of this work will model more accurate combined costs.

We assumed the following prices when calculating the capital and long-term costs of our system.

Figure 9 – Assumed Capital and Consumption Costs

VRE Portfolio Capacity

NEM OPSO demand in the 2025 calendar year was 181 TWh. The VRE portfolio was scaled such that generation would meet a certain percentage of this demand (i.e., 100% indicates that the VRE portfolio generates 181 TWh during the 2025 calendar year). In the case of the Sharpe-ratio optimized portfolio, VRE capacity of 56 GW was required to generate 181 TWh (20.7 GW average) over the 2025 calendar year. Generally, as the VRE portfolio capacity increases, less firming capacity is required, reducing fuel costs but increasing capital costs (1GW of wind farms cost more than 1GW of gas plants). See Figure 10. However, the ratio appears optimized when VRE is set to generate around 100% - 110% of NEM OPSO demand, i.e., at a certain point the additional fuel costs become negligible compared to the increased capital cost of more VRE. See Figure 11.

A contributor is hydro capacity. With lower VRE capacity, the hydro capacity (14TWh) is exhausted at some point during the reference year; the lower the VRE capacity, the earlier hydro runs out. At 100% VRE : NEM, hydro runs out on the 5^th of December, after we’ve ridden out the high-demand/low-solar of winter; gas and storage pick up the slack for the remainder of December. See Figure 16. At 110% VER : NEM we end the year with some hydro capacity remaining (3.4TWh). Further increasing the VRE portfolio beyond the 110% ratio essentially “wastes” the cheap hydro capacity in the eyes of the model/system.

Figure 10 – VRE Portfolio Capacity: Sensitivity Analysis

Figure 11 – 5-year Cost of Hydro and Fuel for Gas Gen (Billions)

Wind to Solar Ratio

The total output of each modelled portfolio was set to NEM OPSO demand + 10% for the wind to solar ratio sensitivity analysis. The system was modelled with 0%, 23.3%, 50%, 75%, and 100% solar. This was done by scaling the solar and wind portions of the Sharpe-ratio optimized portfolio accordingly. Notably, the Sharpe-Optimized portfolio (i.e., 23.3% solar) exhibited the lowest cost over any period greater than 5 years. The effects of increasing solar were:

1. Slightly reduced capital. Capital reduction tempered by the fact that solar has lower capacity factors, so the required portfolio capacity to meet demand increases with increasing solar % of portfolio.

2. Increased reliance on hydro/gas/storage to supply power during significant shortfall overnight and decreased daylight hours in winter, and therefore:

3. Significantly higher gas demand and long-term fuel costs.

Figure 12 – Solar % of VRE Portfolio: Sensitivity Analysis

Figure 13 – Open Cycle Gas Capacity Required with Increasing Solar % of VRE Portfolio

Optimized System

Based on the sensitivity analysis, a system with VRE portfolio scaled to meet 100% NEM OPSO demand over the 2025 calendar year was selected for further analysis. Due to Hydro running out in December in this scenario, the December dispatch order was varied, leaving storage until last (same as March-August). This ensured sufficient capacity for handling longer negative runs in December, minimizing the gas power requirements in those instances.

Figure 14 summarizes the properties and performance of the optimized system over the 2025 calendar year. We have a 56 GW capacity VRE portfolio with a capital cost of $123 billion. Capital cost of firming capacity required to support this VRE portfolio is $46 billion (hydro excluded). As discussed in the sensitivity analysis, there were systems available with lower upfront cost, but once fuel costs were incorporated over 10+ years, this system was the cheapest.

Figure 14 – Summary of Optimized System (Costs, Capacities, Energy Supplied)

Figure 15 illustrates the energy supply for a 2025 average day, with firming capacity generally kicking in for the evening peak demand period and then (mostly hydro) continuing to supply overnight while solar is at zero. All pretty stock standard. Figure 16 and Figure 17 illustrate the supply seasonality. Hydro supply is highest March through August, when hydro is first (and storage last) in the firming dispatch order. Storage is highest in the months where it is at the front of the firming dispatch order.

Figure 15 – "Optimized" System, Average Day Supply by Source - 2025

Figure 16 – "Optimized" System, Total Monthly Supply by Source - 2025

Figure 17 – "Optimized" System, Average Day Supply for Calendar Year 2025 by Quarter

Key Assumptions / Limitations

• 2022 ISP demand, solar, wind trace data is used. Future iterations of this work will update all underlying data to reflect changes in the 2024 Draft ISP.

• Transmission costs and losses need to be incorporated in a future iteration of this work. We understand that this will prove a pivotal piece in portfolio optimization, particularly given the (potentially unrealistic) geographical distribution of our hypothetical VRE generation network in relation to the demand centres.

• Recommend further optimization of firming capacity dispatch order, which is currently relatively static, aside from moving storage up the order during months of increased sunlight. Once a more realistic firming capacity dispatch order algorithm is in place, storage capacity needs to be further optimized.

• Storage round trip efficiency needs to be incorporated.

Consensus earnings

AGL is forecast to earn $1.04 per share in the year to 30 Jun 24 and the same in the year to Jun 25. Although the market likely has no real idea ,EPS for the year to Jun ’26 are forecast to be similar again.

AGL’s most basic valuation metric, the humble but long lived PE ratio stands at about 8.5. Even with interest rates having risen companies that the market likes are on PE ratios of 20. The forward PE for the ASX 200 is something like 16 give or take.

The dividend yield at around 3.5% not that attractive for a value stock.

The argument I have made is that AGL’s customer services business is hard, if not impossible to replicate. Almost no small electricity retailers turn into large retailers. I have argued that a gentailer’s job is to buy long and sell short. For a large retailer this is a low risk strategy because the large number of customers means that there will always be demand even though the individual customer can cancel contracts within 12 months at consumer level and 3 years at industrial level. Because of this guaranteed load AGL, ORG and EA are well placed to take a longer term approach to building the generation portfolio. The can afford to write long term PPAs, to build generation and to manage a portfolio of projects in different stages of development.

All the above remains true but from an investor perspective it is also true that (1) retail profits are the smaller piece of the pie and (2) a significant part of retail profits come from gas retailing and that is not a good business, (3) the retail business has faced the major headwind of behind the meter generation. No Gentailer has so far found the key to making major money out of behind the meter. Indeed ORG reported that its industry leading VPP remains loss making for the moment. Finally on the negative side of things was EA writing down its retail good will.

AGL’s investible cash flow is hampered by Tomago and maintenance

AGL appears to be going through one of its quiet phases. Historically the company has attempted many changes of direction, but ultimately nothing of substance has changed since ex CEO Michael Fraser (now Chair of APA) and Jerry Maycock (now Chair of Transgrid) locked AGL into coal generation via LYA and Macquarie generation investments.

As the EPS chart shows those decisions were successful in the short term but ultimately they condemned the company to failure.

Not only have the cash flows from LYA and Macgen not been reinvested in replacement capacity, the cash flows are likely a lot less than initially contemplated due to the $400 m or more that has to be invested each year to keep the plants running. Indeed forced outages at LYA continue to be an issue.

AGL’s investible cash flow is hampered by Tomago and maintenance

AGL’s free cash flow depends on:

• Price received by LYA and Bayswater, but this sensitivity is lowered due to half Bayswater output sold at fixed price to Tomago smelter. Essentially there is around 22 TWh of coal generation exposed to market prices such that a $1/MWh price change is say a $22 m change in ebitda. The sensitivity to currently low Victorian prices is about double the sensitivity to NSW prices.

• Volumes: AGL makes close to $50/MWh from every MWh at Bayswater in NSW sold at spot and maybe $40/MWh from every MWh at LYA in Victoria. But actually the sensitivity to hot weather might be doube or treble that because prices at dinner time are so much higher but costs don’t change. Another 1 TWh at dinner time might add as much as $200/MWh or more and that’s $200 m of ebitda. For the six months ended Dec ’23 Bayswater volumes were, surprisingly, down 4% over PCP, but LYA did manage a 10% increase but that just represented a catch up on the poor performance of the Dec ’22 half.

• Coal cost change in NSW. Bayswater costs are around A$2/GJ or as little as $20/MWh using AEMO data (9.5 GJ/MWh). However this estimate must be based on old existing contracts and my sense is that over A$100/t implying closer to $4.50/GJ and over $40/MWh is a better number.

Over the past year coal gen has averaged $110/MWh in NSW and $62/MWh in Victoria. My expectation remains for prices this year to be a bit less.

Figure 1 Fuel weighted prices. Source: NEM Review

The following table shows an estimate of AGL coal generation financials using spot prices (and spot is a bit below futures in NSW and Victoria) but adjusted for the Tomago price.

I used $2/gj per AEMO for the Bayswater fuel costs and AEMO estimates of other variable and fixed costs.

Figure 2 AGL coal generation cash flow from 2026, Source: ITK

In FY2024 and FY2025 its likely that AGL coal generation cash flow will be about $500-$600 m higher than shown in Fig 2, as a result of contracts written during 2022 and 2023 which will flow into profits in FY24 and FY25. The Winter 2022 price spike can be seen in the following graph that compares spot prices to futures.

Figure 3 Spot and futures prices in NSW and Victoria. Source: NEM Review

Its worth recalling that in NSW significant output is tied up in the Tomago smelter contract which runs until 2028 and in Victoria where pool prices are in any event much lower, some output is tied up with Portland smelter. Those contracts although at much lower than futures prices, nevertheless are stable. In any event barring an always possible system shock such as a major outage, flat load prices will likely remain low in Victoria until Humelink is complete and Yallourn closes. Humelink will, in my opinion, raise prices in Victoria by shifting some South Australian load into NSW, but it’s true that the reverse can happen.

In NSW there is also the obvious possibility of an outage but more supply from QLD should ease pressure even over 2024. Then in 2025 Eraring is still due to close putting pressure back on. Also in NSW it’s unclear whether thermal coal prices will continue to be controlled. Once Eraring closes there is less need for control at least around volume. Equally a slowish China and very strong Chinese domestic coal production point to a stable market. At this stage. Things change quickly.

AGL likely has $0.6 bn to invest after dividends in each of the next two years.

Consensus EBITDA is about $2 bn for each of FY24 and FY25. That is higher than my medium term forecast. It does mean that AGL will have perhaps $600 m per year for at least this year and next to invest in replacing coal generation.

Figure 4 Near term AGL cash flow. Source: ITK, Factset

Actually a good part of that, say $400-$500 m is going to the Torrens Island battery.

Conclusion. OK for the next two years but medium term cloudy

At the moment I don’t see there is enough medium term cash flow for AGL to retain its current generation leading position in the market. Nor is it clear that there is a good earnings growth path once contract prices fall back to the futures level and volumes come under more pressure. There will be earnings from the Torrens Island battery but not that much else right now.

NEM coal volumes keep dropping leading to generation closures

Volumes in NSW and QLD are down 25% from 2018 and 12% in Victorica

Figure 5 NSW coal generation. Source: NEM Review

Figure 6 Victorian coal generation. Source: NEM Review

Figure 7 QLD coal generation. Source: NEM Review

What stands out is the overall consistency of the volume decline. This is obviously because NEM demand has been flat and renewable supply has been increasing.

So for AGL the two great hopes in the next five years are the closures of Yallourn in Victoria and Eraring in NSW. The closure of Yallourn is more or less certain but Eraring much less so.

In fact I’d argue that Origin has basically created a situation where Eraring can’t be closed, and that’s because Origin has done

AGL and Tilt

Tilt has a new Chief Executive, with expirence and knowledge of AGL. Its possible that Tilt may therefore have some change of policy or emphasis. Nevertheless it’s expected that as Tilt develops new projects, project output will or must be offered first to 20% shareholder AGL. The 1 GW Liverpool Range project is likely the first of these to be announced. The project falls in the Orana REZ from which transmission is now secured or at leas the price for connection can be agreed. Liverpool Range capital cost is likely closer to $3 bn than $2 bn once construction interest and pre FID costs are accounted for.

Even so AGL’s share of the equity is likely to be well within its annual free cash flow capability.

From its role as Liverpool Range’s off taker a 1 GW wind farm with a capacity factor of 34% is going to produce about 3 TWh of energy, and at $70/MWh that’s $210 m of commitment per year and over 15 years thats a $3 bn gross liability, maybe half that in present value terms.

Liverpool Range, even if committed in FY24, as is possible, won’t be in operation until FY27

AGL needs 18-24 TWh representing around 8-10 GW of wind and solar to replace LYA and Bayswater. Likely there will be some loss of generation market share along the way. It’s hard to see AGL continuing to be the sole supplier to Tomago. It’s not an arrangement that seems to suit either party particularly and has become more problematic for AGL post the closure of Liddell as Tomago notionally represents more than 50% of Bayswater output.

AGL and and the Capacity Investment Scheme

It’s no secret that lots of new wind and solar is and will be built. The question is what does that mean for AGL.

In the first instance it likely means that Bayswater and LYA revenue will fall and unit costs will rise. That’s because the new supply will see volumes falling to the minimum viable level during solar hours and prices also very low. Competitors with higher costs, Yallourn and Eraring will close sooner and may relieve the volume but not the midday price pressure.

In any event my conclusion is that the CIS provides a pathway for the Gentailers to get out of the mess they have made for themselves, and they should, but probably won’t, be grateful to Chris Bowen.

The CIS will put downwards pressure on electricity prices

The most fundamental feature of the CIS is that the Commonwealth and State Goverments will bear more of the risk of building new generation. Because they will guarantee a minimum floor price, developers will not low or negative price risk. That means that the cost of capital for the project can be lower because the risk is lower. Because the cost of capital is lower the required price to earn the cost of capital is also lower. In this way the Commonwealth will both be taking on risk on behalf of producers and consumers but acting to put downward pressure on electricity prices. Likely this will take some time to become clear.

Taking some risk off the table will tend to increase supply and this will be evident in responses to the CIS tenders the first of which is due mid calendar 2024.

The new supply will be sold to the Gentailers including AGL, ORG and EA and that in turn will enable them to close their coal stations with more certainty. In AGL’s case it will also likely mean some loss of relative profitability as its cost base is unlikely to be any better than that of its competitors.

Eraring cant close in 2025 (fiscal 2026) because ORG hasn’t replaced its energy

ORG recently invested $530 m increasing its stake in Octopus to 23%. This may or may not be a good move for the shareholders but its $530 m that won’t be invested in its Australian energy markets business.

Eraring provides around 14 TWh of energy and as yet ORG management have made no formal statement of how the energy from Eraring is going to be replaced. It’s very clear that it cant be replaced by new build in NSW if the station is to be closed in September 2025. Equally it’s not clear whether the energy in NSW can be bought from other parties. It is possible that ORG management have already bought over the counter contracts with other generators. However there is not much visibility around this and I regard it as unlikely.

The NSW Govt is possibly negotiation some capacity payment with Eraring but in my opinion its of insurance value only. Market forces will ensure that Origin management keep Eraring open long enough to ensure that most of its energy can be replaced. Origin is not a fly by night operator and has strong obligations to its residential and commercial customers. Since it has done nothing to buy or build replacement supply it therefore wont close Eraring.

From AGL’s perspective if Eraring closure is delayed then the extra supply will intensify the pressure on all players and average prices in NSW will be lower.

Similarly in Victoria EA has done little to replace Yallourn’s energy. In common with AGL and ORG its strategy appears to be based around buying energy and providing the firming required. In Victoria though there is more visibility on new supply and prices are low. Its presently a buyers market.

Nuclear in Australia is just an example of the LNP’s ability to sell anything to their base provided it doesn’t look “left”

I personally compare the LNP’s ability to sell nuclear to a religious view preaching that there is “life after death”. There is zero evidence of life after death and it is contrary to everything we know from centuries of medical and scientific research but millions profess to believe in the idea.

Similarly once the LNP agreed that climate change was indeed real and that decarbonization targets were bipartisan policy then it became necessary to invent an alternative vision to using wind and solar. That’s because wind and solar are “green” and left. The LNP had traditionally supported coal but if coal was a problem then whatever the answer was it certainly couldn’t be “wind and solar”. So a solution had to be found and that was nuclear. The practical issues with nuclear don’t matter at all. It was a fuel that the base would not only accept but rally round. Conveniently Ted O’Brien had long advocated nuclear and so away he went. In the sharemarket I saw many times over 30 years how ssmall speculative stocks could exist for 10-20 years on an idea. This idea might be some new medical technology, a new form of car engine, a potential gold mine, a hydro plant in New Guinea delivering power to Sydney. The worst thing the company management could ever do was put the idea into practice, because then the problems would start. But if you only talk about it, put an expert in front of the shareholders with a report and some facts and figures then you could raise enough money to keep going for years and do it a few times over. Nuclear in Australia is just like that but with political ideology added in. People a gullible and will mostly fall for a good story well told that they want to believe in. We used to say we would start a company “The Golden Shaft”, we get the gold, you get the shaft. But anyway not only do I digress but equally its worth acknowledging that the fact that Australia doen’t need nuclear and can’t afford to wait for nuclear doesn’t mean that at some future time there may not be a role for it. In the meantime the task in Australia is clear, build the wind and solar, ensure the transmission and firming are there and then use the decarbonized electricity system to decarbonize industry and transport. It’s a clear achievable plan and we have been set on the course for a decade already. The problems are known and the solutions are easy..

Global and regional trends

So lets look at the global and regional trends, bearing in mind that the trends can’t show policy shifts, won’t show the impacts of new plants under construction or old ones that will shortly be decommissioned. Trends are interesting but no substitute for informed analysis.

Globally or at least that part of the world within the IEA database, gas is now the largest fuel source for electricity, largely because of the USA. Wind and solar have overtaken nuclear and in my view will over take coal with the next 12-18 months. There are some new nuclear generators to come in China but equally the new wind and solar being built in China far exceeds even on a capacity factor adjusted basis, the new nuclear.

Figure 3 IEA all covered countries electricity production. Source: IEA

In OECD Europe VRE is now easily the largest fuel source with the coal share having more or less halved and nuclear down by 22% from its 2011 peak.

Figure 4 Electricity generation by fuel OECD Europe. Source: IEA 9 months to Sep 23

In the USA gas is dominant and growing. Due to shale gas and the lack of bipartisan consensus on climate change I expect gas to retain its dominant position for years. Renewables will soon overtake coal.

Figure 5 Electricity generation by fuel USA. Source: IEA 9 months to Sep 23

China and India have a long way to go. Many times do I read how much solar capacity is added each year in China. And then I look at the generation shares and feel sorry for the future generations.

Figure 6 Electricity generation by fuel China. Source: IEA 9 months to Sep 23

As for India there is not much positive to say so I will say nothing except to note that although the population of China and India is roughly equal China consumes 4-5X the amount of electricity that India does.

Figure 7 Electricity generation by fuel India. Source: IEA 9 months to Sep 23

Two big events left this year

Results from AEMO services tender 2 for renewable energy in NSW are expected to be released in the next couple of weeks. That should cover around 1 GW of projects, a drop in the ocean but still very welcome news. Hopefully at least some new wind.

Energyco (AEMO Services partner in NSW) will also release a year end update Monday 11 December. It would not surprise me to find that the Orana transmission contract is also announced then.

Then, of course, the first draft of the 2024 ISP will also be released in the next couple of weeks. Although ostensibly a transmission planning exercise, the reality is that the 2022 ISP was the document that convinced stakeholders that we all in reality expected a decarbonised NEM and sooner rather than later. Not so much price discovery as belief discovery.

In any event the ISP 2024 will embody State Govt policies such as Victoria’s offshore wind target, misguided as it may be, the Queensland plan, misguided though Borumba may be and changes to the NSW outlook including delays to Snowy 2. Personally I could not give a rats about the delay to Snowy 2 or its cost. For me the world has moved on. Still lets leave ISP 2024 until its released. Speculation is pointless.

Transmission outlook is improving

For years commentators have focussed on transmission as the key enabler of a strong renewable electricity system. The earliest article I wrote about this here at Reneweconomy was on July 5 2017 "Transmission we need to start building now". That was only a year after I left UBS. At that time the then AEMC Chair John Peirce oversaw a rigid approach embodied in the logical and seemingly rational but ultimately utterly misguided view of new transmission embedded in the RIT-T test.

It was clear even then, using the best practice Texas example, it would take seven years to build new transmission, just as it was clear even then that the existing transmission network in the NEM would likely be in the wrong place for wind and solar. However at that time it wasn’t clear just how congested the existing network actually was.

Despite the blackout in South Australia by 2023 the only new transmission actually being built other than some minor augmentations in the QLD-NSW link is the SA-NSW link and that not due for completion until 2026. Indeed building new transmission has taken every bit as long as feared back in 2017.

During this period, stoked by rabble rousers, fear and doubt (FUD) about the ability of Australia to build something as simple as some wires and poles has grown and grown. Transmission and wind farms are now portrayed as ruining the Australian way of life, a source of endless depression and creating environmental destruction.

My view of reality is that renewable energy and the associated transmission will preserve the Australian way of life, bring more prosperity to regional Australia, is the best thing that can be done to preserve the environment and will lead to lower and more certain electricity prices. Color me a hippy.

Today a wide range of “experts” and advisors contend that the lack of access to transmission is the No 1 problem preventing new renewable energy projects from starting.

Personally I not fully convinced that transmission is necessarily holding back projects right now. I think wind and solar developers lack a willingness to commit, perhaps hoping to move the dial in their favour. For instance the 400 MW Uunguala wind farm in Northern NSW could have started construction 12 months ago but Twiggy Forrest seems too busy posturing on the world stage to sign the contract.

$40 bn of transmission under development $12 bn ready by 2028

There is over $40 bn of transmission under development.

Figure 1 Transmission development in the NEM.

But if I focus on NSW as the State with the highest forward prices and the largest consumer of electricity and look at when significant new transmission will be available I see:

Figure 2 Transmission development in NSW by 2028. Source: AEMO, TSPs, EnergyCo

Humelink, Orana will make a difference in NSW

In my opinion Humelink is roughly on target to be built by December 2026. That’s despite ongoing opposition to building it above ground, despite not all easements agreed, despite a recent 22 km route length increase, despite not one but two upper house enquiries and despite the fact it has yet to get final approval from the AER or a final investment decision.

My confidence comes from the up to $600 m of pre commitment spending that has already and will continue to take place ahead of the AER decision next year and because the above ground line is lower cost and faster to build than competing underground proposals.

Secondly My guess is that the independent consortium developing the Orana REZ transmission link will be able to confirm that link in the near future. Confirmation of that should enable the pricing to be available to projects in that general area such as Liverpool Ranges Wind farm and Valley of the Winds wind farm.

Between those two projects alone and with the 800 MW capacity of Project Interconnect now well underway NSW will have removed one of the many excuses developers from Origin Energy to Tilt provide as to why they aren’t building projects.

Aluminum is 10% of NEM electricity consumption

Aluminum is still about the largest single consumer of electricity in Australia. Its responsible for 10% roughly of consumption in each of NSW, QLD and Victoria and probably more in Tasmania.

For some years many of us having been thinking about how to replace coal fuelled electricity with renewable electricity for aluminum smelting. However the difficulty (thanks Matt Howell ) is that aluminum smelting is basically a non interruptible process. Although you can cut power to a smelter for a couple of hours every now and then, doing so impacts the “pot” life and its really not what the process wants to do. So aluminum production is much better suited to something like hydro than to wind and solar. So in the absence of any intervention you would basically expect global production of aluminum to shift from coal intensive areas like China to hydro intensive areas like Russia and Canada as decarbonisation becomes a bigger and bigger deal.

This means that Australian smelters are at risk of closing. They face environmental costs which their Chinese competitors do not and they are not as easy to repower as it might seem. Even though smelter owners are notorious for wanting government handouts the basic reality is that they sell the product in a global market and it has to be one way or another globally competitive. This can be on cost where electricity is normally the sole differentiator of costs or it could be on value if there was say a “green” premium. But basically its cost.

Even though Australian wind and solar costs are likely very competitive with hydro it’s the firming component that’s difficult. So what looked like the obvious way to go about things was maybe not so obvious. Recently though I’ve been thinking a lot about the intermediate step in the aluminum process and that’s alumina.

Australia currently produces 14% of the world’s alumina

Australia has the largest, but not necessarily most economic, reserves of bauxite and Australia is a significant global producer for alumina. However, at least in Queenland the alumina refineries are old.

Figure 2 Global aluminium production. Source: International aluminium institute

Alumina is behind only LNG and power generation as a gas consumer in Australia

The next thing to appreciate is that alumina is the largest single consumer of gas in Australia outside of electricity generation and LNG production with total consumption in excess of 220 PJ. The overall flow of gas in Australia is shown below and I tip my hat to an excellent Sankey diagram:

Figure 3 Australian gas production and uses. Source: Dept of Climate change

Eliminating gas in alumina would have a bigger impact than eliminating gas from all residential consumption let alone new consumption.

Alumina refineries are well suited to solar power, they can offer very large scale demand response.

The most important point to understand in this note is that alumina refineries and particular the digestors are flexible. Like a pot on the stove they can be turned up and down with no damage other than a loss of production. This potentially makes them incredibly useful when coupled with solar energy. It also may be possible, ah say MAY be possible, to store excess process heat from the digestor and release it over night.

So the ultimate idea is to run the flexible alumina refinery and the aluminum smelter next door on solar and wind energy. The refinery is run mainly on solar during the day with the excess heat stored. Over night the refinery cuts its wind solar input right down and supplements it with stored heat. The wind that the refinery consumes during the day then becomes available to the inflexible aluminium smelter next door to replace essentially lost solar production.

In addition any time the wind and solar input has a drought it’s the flexible refinery that takes the hit and the smelter largely keeps on going.

External firming may still be required but much less often freeing up the firming capacity, eg Borumba, for other uses. Indeed for those rare occasions where State wide there is such a drought that the refinery and Borumba cant handle it then backup generation (eg gas) is called into action.

Focus on QLD as no aluminum in WA

Using alumina refineries as demand response/batteries doesn’t require a coupled aluminum smelter but if they are coupled as in Gladstone it fits in very nicely with the coordinated industrial region approach that is increasingly regarded as the lowest cost and most efficient way to approach industrial decarbonisation see Climate works report. Indeed the use of alumina refineries as storage/demand response is exactly the sort of thing that emerges from a broader look.

A quick estimate is that the digestors use around 12-13 TWh of energy in QLd

Figure 5 Alumina digestor energy. Source: Derived from ARENA report

So the alumina refineries in QLD use more energy even in the boilers, and before considering “double digestors” than the aluminum smelter.

Figure 6 Australian aluminium smelter capacity. Source: ITK

So the combined QLD position is a requirement for about 22 TWh of renewable energy of which 60% is flexible demand:

Figure 7 Gladstone aluminium complex. Source: ITK estimates

However since the idea in this note is to store digestor heat from solar energy we need more solar and more GW.

The first thing to note is that QLD total operational consumption was about 54 TWh last year so adding in the alumina refinery adds about 25% to consumption. Equally it frees up gas for other uses but that is of no concern to this note. 13 TWh is broadly equivalent to 1.4 GW of flat load and if we consider it to be a battery its about 70% the proposed size of the power that Borumba can provide. I won’t bore anyone with social license issues but unless I am even more clueless than I think I am then providing a clear future for the refineries is likely to be a social license winner.

What it would require is 12 rather than 8 GW of wind and solar, the more solar the more GW. But in fact its more than that, because enough power has to be produced in the middle of the day to fill the refinery storage for overnight operation. I compiled the portfolio to ensure that on average there was enough renewable average to cover demand for every half hour of the average day.

Figure 8 VRE portfolio to run Gladstone

It really works (in the spreadsheet)

The smelter load is 960 MW and the underlying alumina digestor load is 1800 MW. The digestor is run in two modes, peak and offpeak. Peak is when its sunny. During this mode the digestor uses excess daytime solar to charge its storage. This storage is assumed to be “cheap” storage of process heat. In this case the stored heat is just used to partly run the digestor at night. This is more than twice as efficient as using the stored heat to run a turbine that makes electricity. In this system the energy losses are very low. In the turbine case more than half the heat is wasted.

The digestor was modelled to run using an input power of 900 MW in non solar hours supplemented by storage. Again this is a guess. The process heat storage was enough to provide the missing 900 MW during non solar hours. In this model about 15 GWh of process heat storage is required (providing about 900 MW for roughly 16 hours a day) . To charge the storage and also run the refinery and smelter during the day required 4.5 GW of input power. However only 1800 MW of input power is required over night.

The most important point is that the smelter itself only needs 960 MW. Since the system has been sized to provide at least 1800 MW on average over night, it takes a severe wind drought for the smelter to need outside power.

The following chart shows how it works on average day over 508,000 modelled half hours using adjusted AEMO provided wind and solar REZ traces for the period 2024-2050.

Figure 9 Alumium smelter and alumin digestor run on wind and solar, average day. Source: ITK

This graph is of course just an average. If wind and solar output falls away then initially the burden falls on the refinery and some refinery output is lost. But the refinery can easily cope. Our main concern is keeping the power up to the smelter.

It turns out that for this model there are about 4200 half hours out of 508,000 modelled, that is less than 1% of the time, where there is not enough wind and solar to run the smelter. The following figure shows the distribution of those half hours by the shortfall.

Figure 10 Need for aluminum smelter firming. Source: ITK

You can see that for 500 hours (0.1%) of the time 300-500 MW of external firming is required. A gas generator or a battery could do that easily. It’s a trivial problem.

Problems - what problems?

If it was this easy it would have been done already.

Imaginary economics

In this section I make up some price assumptions and fiddle with the numbers until I get the result I want. Uh hang on that’s what I used to do in the research dept. This is the real deal. Just kidding. In fact you can make up any numbers you want for the input prices. These numbers are overnight costs ignoring transmission. The “green” price is assumed to be a constant. Somehow you can purchase wind and solar for $60/MWh and get an REC with a value of $30 thrown in. Then you can turn around and sell the surplus output for $50/MWh but without the certificate.

On the other hand who knows what coal generation will cost in QLD going forward. Its kind of a moot point because its all supposed to go away.

However the biggest point maybe that you only need a normal as opposed to do gooder, super greenie level of optimism to make the numbers seem possible.

I suspect that there are a few lines missing in these sums but no doubt the many eagle eyed readers will be quickly alert me to the many errors.

Figure 13 Decarbonising Gladstone aluminum production. Source: ITK dept of imagination

Using QLD and NSW wind together with QLD solar

In ITK’s opinion any large QLD renewable project that doesn’t take advantage of the portfolio benefit of including some NSW wind is nuts.

The following figure shows the correlation of wind output between the various Queensland and NSW REZs. Basically the deeper the brown colour the less correlated the two zones are and therefore the lower variability of a wind portfolio that combines them. Some zones actually are negatively correlated. Negative correlation is wonderful if you can get. It means that when one zone isn’t blowing the other one is likely to be blowing. Careful perusal of the “map” will show that combining Q3 and Q4 wind with N7 and N8 wind would be a good idea. It might be that in reality that can only be done financially.

Figure 14 NSW and QLD REZ wind correlations. Source AEMO 2022 ISP, ITK calculations

The map below shows the zone locations. Plausible portfolios that don’t require too much transmission imagination might be N1 through N3 with say Q3- through Q7. Q8 and Q9 are too close to the northern NSW zones including Orana and don’t give the same portfolio benefit.

Figure 15 Modelled NSW and QLD REZs. Source: AEMO

Equally large scale solar can be built faster and possibly has a lower cost of energy than wind. Notionally such a large project could also manage the risk with access the spot market given the predictable surplus of midday power coming from behind the meter. That is you might undersize your contracted portfolio. That too is ignored here.

For most renewable systems in Australia, the general finding is that the ideal mix is about 70% wind and 30% solar. Because of the large solar resource in QLD and because we are viewing the refinery(s) as a pseudo battery lets push up the solar ratio to 50% with say 35% of power coming from QLD wind and 15% from NSW wind. I don’t worry about the solar side of things except to note that spreading the solar out within QLD will likely improve results.

These numbers are just guesss.

All real world issues like transmission are completely ignored.

QLD is cracking on with the job

QLD Govt owned entities have committed PPA support to over 3.5 GW of QLD wind in the past 12 – 18 months.

Figure 1 Source: Company

Notwithstanding the problems at Clarke Creek where the new owners are still a bit wet behind the ears construction is cracking on. In particular Acciona is demonstrating how to develop large scale wind at the Macintyre site. Dulacca wind farm was built without too many issues..

In general over my career Queensland has always been the place to go if you want to get something done. If you want to spend most of your life managing social license, planning and dealing with labour issues then by all means do development in Victoria. You might end up famous and will certainly get lots of media attention. These days NSW is nearly as tough as Victoria.

QLD is the future of the NEM

Its obvious that QLD has fantastic solar resources, but no matter how often I say it, it bears repeating that QLD has excellent wind resources. By that I don’t just mean that QLD wind has good capacity factors, it does, or often has transmission access, it does in the CSG areas where the transmission network was rebuilt without any drama whatsoever, about 10 years ago.

No the real value of QLD wind is its ability to be paired with NSW wind to reduce the need for firming. Unfortunately this is one of the areas where I’m not sure the QLD Govt, always parochial, actually gets it. Not invented here, or in this case, not built here, can be damaging just as no development can be damaging.

And the great advantage of coupling QLD and NSW wind (and the solar resource of both) is it reduces the need for firming. Why should Queenslanders care about that?

Queensland can’t afford giant pumped hydro projects

For the renewable energy transition to be successful it has to achieve two goals as well as decarbonisation. They are to keep the lights on and to keep the price reasonable. And of course it would be helpful to turn it into a winning political strategy

From what I can see of the Qld opposition at the moment energy is not the focus but the question is can “Jobs and Energy” be a positive. Unfortunately to stand any chance of being a winner no changes of course can be permitted. So in essence even in the unlikely case that every word I write in this note is completely accurate it doesn’t matter. The die is cast.

In the early romantic, frontier years of the transition we all focussed on the LCOE (price that would accept) of wind and solar. That price was (1) coming down every year and (2) clearly lower than the cost of new thermal supply.

Now however as we move from 30% wind and solar across the NEM to 60% and then 90% its become even more obvious that we also have to focus in the cost of transmission and the cost of firming.

I don’t want to speak about transmission here other than to say, really its been demonised. In what world do you find Barnaby Joyce and Bob Brown of one mind,? It’s the world where above ground transmission is demonised as an environmental disaster. Bob Brown may do it out of genuine belief and lifelong commitment and Barnaby Joyce does it out of near term, cynical I’ll do anything for a vote but the result is the same. A transmission line does not mean the end of the Australian way of life. Anyhow rant over.

No what needs to be discussed is the cost of long duration pumped hydro.

Jobs and Energy plan – resulting electricity price

One way to think about electricity prices is to do an NPV calculation on the system. That is add up the capital cost of the assets, estimate the operating cost, forecast the volume and then find a price that makes the whole thing acceptable to a capital provider.
In the case of the QLD Energy and Jobs plan, and wrongly putting to one side, the contribution of behind the meter, what we have is, 25 GW of wind and solar, 7 GW/24 hour pumped hydro and some transmission to string it together.

Looking at those assets:

Figure 2 QLD plan, bulk energy. Source: Govt, ITK

Figure 3 QLD plan, transmission: Source: Govt

Even if that transmission is a significant underestimate it doesn’t change the overall picture but the pumped hydro does.

Figure 4 Govt pumped hydro. Source: Govt, company, ITK

AEMO has vastly increased its estimate of pumped hydro costs over the past few years and even so estimates just 4 $m/MW or just 57% of the pre starting estimated Borumba cost. The biggest item in a list of big items is the Pioneer/Burdekin projects. I have just read the cost through from Borumba. In all honesty it’s a complete unknown as to whether Pioneer will be built or what it would actually cost, it’s a decade away from being built even in the “plan”. Nevertheless it is in the plan and therefore its modelled here.

The historic model for “firming” plant is the gas open cycle “peaker”. It has a capital cost of around $1 m/MW plus an operating cost of maybe $100/MWh more or less. The idea was that the high operating cost could be tolerate due to low capacity factors. The peaker would cover its cost of capital by selling “caps” to retailers and would earn roughly $15/MW x hours in year = $131 k in revenue less the cost of actually operating when the cap price ($300/MWh) was exceeded. In addition the peaker could operate between its operating cost and the cap price for its own benefit.

Clearly that is not the main model of a 24 hour pumped hydro project. Were it to sell $15 caps on 2000 MW revenue is $262 m per year or a yield of less than 2%

Adding up the capex on an “overnight” basis:

Figure 5 Jobs & Energy capex: Source: ITK

This total does not include anything for the existing gas assets which will also need to earn a return and contribute a small amount of output.

Also the approach of big long duration pumped hydro is at odds with how the ISP modelled outcomes across the NEM and in QLD.

Nevertheless putting the numbers into a very simple NPV spread sheet and assuming that reinvestment = depreciation I get around $120/MWh for a 7% IRR.

Figure 6 QLD plan, IRR. Source: ITK

I don’t show the IRR (Internal rate of return) working but 69 TWh at $120/MWh is $8.3 bn and knock off say $1bn of opex so $7 bn of ebitda compared $94 bn of capital cost = Ebitda multiple of say 13 which is in my professional opinion a typical back of the envelope outcomel.

You could argue that you don’t need 69 TWh once you include rooftop outpu but on AEMO’s demand growth forecasts you will in fact need more energy post 2035 than the system will provide.

Its only the firming part where savings can be made. You need roughly 25 GW of wind and solar and nothing the QLD Govt does will change that cost or the associated transmission by much.

QLD modelling – with and without NSW. TL;DR

As stated above NSW and QLD wind are poorly and in some cases negatively correlated. This means that when wind is not blowing in a QLD zone it is more likely to be blowing in a NSW zone and vice versa. In short by combing NSW and QLD wind you get a higher average output for any given number of MW. You can see this in the following correlation heat map.

Figure 7 NSW and QLD wind make a great pairing. Source: ISP data

The brown areas show the correlation of NSW and QLD wind zones, the green are QLD compared to other QLD or NSW compared to other NSW.

However some QLD and NSW zones have other issues, like being in sensitive areas, or far away from demand so the correlation can’t be considered as anything more than a starting point.

In any case taking the Qld Jobs and Energy program with 13 GW of wind, 12 GW of utility solar, plus AEMO’s forecast of behind the meter solar, AEMO’s forecast of demand, and using the 2030-2035 window (when forecast output is just a bit higher than forecast demand (inlduding a 1 GW of hydrogen demand)) I get the following average time of day graph.

Figure 8 QLD in the 30s under the QLD jobs and energy plan. Source: Govt, AEMO, ITK

You can see the need for storage because there isn’t enough wind run the show over night. In reailty there would be gas as well as storage not to mention the possibility of imports. In short to me this portfolio looks far from optimised even without considering the variation. And yet building 13 GW of wind is not without its own challenges, even in a State as big as QLD.

In what I consider to be a more optimised version 5 GW of utility solar in QLD are replaced with 5 GW of NSW wind, this confers both a higher capacity factor and a diversity benefit.

Figure 9 QLD in the 30s with NSW wind instead of some QLD solar. Source: AEMO, ITK

The advantage is obvious, at least on an average day basis.

The average daily firming, which doesn’t account for wind and or solar droughts, of the two strategies are shown below:

Figure 10 Average daily firming showing the advantage of merging QLD/NSW. Source: ITK

6 GW dominates 2 GW

The recently released information that QLD’s Borumba pumped hydro station will cost $14 bn for 2 GW of 24 hour storage = 48 GWh is in my opinion a good reason for the QLD Govt to re examine its options.

Batteries have a higher capital cost than pumped hydro although the difference based on Borumba is so much less than we are used to thinking. (see table at end of document)

Also Pumped Hydro once built could be expected to last for 50 years or more. A battery or as its called a BESS [Battery energy storage system] typically has a life of 20 years based on a rated number of cycles per year.

That’s the end of the advantages of pumped hydro. The disadvantages include massive social license issues, long build times, a very low learning rate, cost blow out exposure, limited ability (compared to BESS) to provide system services (virtual inertia, black start) and typically lots of transmission.

However the epiphany I had was that Pumped hydro maximum power and configuration flexibility is non existent. If you build a 2 GW /24 hour pumped hydro station at best you can provide 2 GW of power for 24 hours.

By contrast a BESS with the same storage capacity as Borumba can be configured however you like. Specifically you could configure your 48 GWh as 2 GW by 24 hours , 4 GW of 12 hours, 8 GW of 6 hours and so on.

Lets say your BESS was configured as 6 GW of 8 hour storage. That’s the same energy (48 GWh) as Borumba. You can run that as 6 GW operating as 8 hours or you can run 2 GW for 8 hours then the next 2 GW then the final 2 GW. You get 2 GW /24 hour just the same as the pumped hydro. But now you can take advantage of all the opportunities when you need more than 2 GW but only for a few hours.

Confirming the obvious with a model

Due to previous work it was easy enough to setup in my very humble ITK model (not to be compared with space rockets like PLEXOS) a 2 GW 24 hour pumped hydro asset and also for comparison a 6 GW 8 hour BESS.

The way these models work is purely mechanical I start the storage asset at 80% full. For every half hour if demand exceeds VRE then the storage asset trys to fill the gap subject to its maximum power and also how much energy it has. If it doesn’t have enough energy then it supplys until it is empty. The reverse is true if VRE supply exceeds demand. In that case the storage asset trys to store the excess subject to its power and its state of charge. Any excess supply left over is spilled and is recorded as a negative net firming demand. Results show that the assets are regularly either empty or full because the QLD needs more than 48 GWh of storage and more than 6 GW of firming power once it gets to 100% VRE supply around 2040 on the ISP view.

In this case both assets were assumed to have 75% round trip efficiency (even though BESS can achieve 85%)

In this exercise I only compared their peforrmance for the hypothetical FY 2045 in QLD. But the results could very easily be extended. Frankly I just got lazy. Note my model uses ISP data, if QLD builds its VRE at the Energy and Jobs plan forecast pace it will get to 100% VRE around 2035. So while this note focusses on a notional FY45 it might as well by FY35 on the QLD Govt timetable.

First of all I show the average day in FY45 for QLD. The source data is basically from that provided by AEMO as part of the ISP 2022 documentation. All calculations and adjustments are of course my own.

Figure 1 QLD FY45 (100% renwable) average day. Source: ITK

As stated in the prior note by 2045 some hydrogen demand is included and AEMO has carefully estimated electrification and EVs and changed the demand shape accordingly.

Its important to understand that storage has to cope with wind and solar droughts as well as copinng with the average day. Nevertheless its interesting to look at the most common situation.

Basically I compared the performance of Borumba with a 6 GW/8 hour BESS by looking at the residual need for firming after operating whichever storage asset I am modelling. Neither I nor anyone else is suggesting that Borumba alone can provide all the firming needed in a decarbonised QLD electricity supply.

The following chart shows the residual demand for firming for both systems using median data. Medians don’t capture extremes (edge cases) but they still provide a useful view in my opinion.

Figure 2 Median day FY45 QLD firming net of either Borumba or a 6GW BESS. Source:ITK

On this measure we can see that the 6 GW BESS comprehensively outperforms the 2 GW pumped hydro asset. Using medians. 6 GW of 8 hour storage means that no firming demand is needed in the evenings but using Borumba would still require another 3 GW of firming power in the evening.

The BESS doesn’t perform quite as well in the morning, probably because its empty on lots of days but even so because it can recharge at 6GW instead of 2 GW it still does a better job than Borumba.

Consumers big and small don’t care about spilled energy, they only care about having enough power to run as they want to. So for this next graph I only show results for when demand exceeded VRE. In this modelled year (FY45) that happened on 9867/17520 = 56% of half hours. The average demand over those half hours was 11.6 GW and average VRE production 7.4 GW.

The following chart shows a rolling 30 day sum (in GWh) of positive firming demand after operating our storage assets. That is we ran the system with Borumba and then ran the system with the BESS. They assets operated over all half hours (ie recharged when supply exceeded demand) but the graph just shows how they performed when demand exceeds VRE supply.

Again the result clearly favours the BESS. Typically the system with the 6 GW BESS requires about 0.8 TWh less additional firming per month relative to the system with the 2 GW Borumba pumped hydro asset. “net” means the difference between the Borumba and the BES results

Figure 3 QLD FY45 net firming energy rolling 30 days Borumba v BESS. Source: ITK

In FY45 in QLD February is the worst month

All of this analysis considers QLD as an island. That is a bad way to do things. NSW and QLD have very complementary wind systems and strong inter connects between the two States will greatly benefit both. In another note I’ll show that result again. Nevertheless considering QLD as an island the greatest need for firming comes in February.

Figure 4 QLD FY45 rolling 30 day Demand, VRE. Source: ITK

So looking at February 2045 half hour by half hour the following figure shows the state of charge, in MWh, (maximum is 48,000 when the storage is full for both systems). The chart shows that both systems are regularly at zero state of charge but that the extra power of the battery means it can recharge much more easily than the lower power Borumba asset and this is what enables it to easily outperform Borumba.

Figure 5 QLD FY45 SOC Borumba compared to BESS. Source: ITK

And to further illustrate, the following chart shows model output for Feb 21, 2045.

The day starts with the BESS or Borumba empty due to having been run flat the evening before. Neither asset was able to do anything until solar output went up. After that, because there was enough Sun the BESS was able to achieve a much higher state of charge [SOC] and therefore could contribute more to evening demand. Note that the SOC lines are in MWh but other lines are MW. (footnote I can’t find a way to make the chart simpler)

Figure 6 Comparing systems on a low VRE day. Source: ITK

Finally I show some of the actual numbers that were used in compiling Figure 6. Again note that when the storage asset is charging it loses some of the energy to running the pumps or in the BESS case to other losses.

In table form a subset of the numbers shows:

Figure 7 half hourly model output 21 Feb 2045 QLD. Source: ITK

Economics

As discussed the BESS will have a shorter life than pumped hydro and also likely higher maintenance cost but can be built far more quickly. The BESS can also provide additional revenues by managing the grid frequency. The BESS can be located all along the existing grid likely providing additional grid capacity but specifically it should avoid most of if not all the transmission that Borumba requires.

In my last note I took a generous view of the $14 bn announced Borumba cost and assumed it included the associated transmission. Some more reading makes me now inclined to believe that Borumba is currently costed at $14 bn plus transmission.

If that’s the case the BESS gets within striking difference of Borumba

Figure 8 2 48 GWh storage system costs. Source: QLD Gov, ITK

When you have chosen Borumba you will need at least another 2000 MW of firming and probably another 4000 to catch up with what the 6 GW/8 hour BESS can do. So all of a sudden I’m asking why so keen on Borumba? Its true my BESS numbers are a bit of a stretch, lots of assumed cost down, no transmission costs. Yet I still think if it was me, I’d look again.

Summary

This note borrows from the “theory of finance”, to build a maximum Sharpe ratio portfolio of wind and solar farms in the NEM. The average daily output of the portfolio and its variability can be compared with the average daily output of utility VRE (that is excluding rooftop) in the NEM over the past 12 months. I set the “optimised” portfolio to have the same total output per day as the existing NEM portfolio of wind and solar farms.

Figure 1 Daily average output optimised portfolio and NEM existing portfolio.Source: ITK, NEM Review

You can see that the “best” portfolio has a much more constant output through the day (and is much less seasonal) and for every half hour has a much lower volatility as compared to the existing, installed wind and solar farms. Put another way the mean is more stationary with respect to time of day and season of year and the variance is lower. The Sharpe ratio (mean/standard deviation) is nearly twice as good as the existing NEM wide portfolio of wind and solar farms.

I might add that although I have yet to prove it I think it would have a better capacity factor and likely be lower capital cost. Obviously this “best” or optimised portfolio would require much less firming.

The optimised portfolio would be heavily concentrated in Queensland (see fig 3) but the function maximisation algorithm didn’t result in much VRE in Victoria overall by State where O = offshore and numbers are in %

Figure 2 Optimised portfolio, weighting by State, O = offshore. Source: ITK

and would have about 77% wind and 23% solar.

I realise the following colour scheme is worse than tasteless but it shows as a percentage of the total portfolio how much would be allocated to each zone that the “optimiser” chooses. Most of the results are generally what I would have expected but I was truly astonished to see that the algorithm results in a little bit of Tasmanian solar going into the portfolio. Its interesting that the results have more offshore wind off the Illawarra than in Gippsland, probably because of the Tasmanian wind included. These results would likely change quite a bit if levelized cost of the energy was included, an extension I plan to do for next time.

Figure 3 Optimised portfolio percentage held by fuel and REZ. Source: ITK

The portfolio built by the optimisation algorithm only takes account of the forecast capacity factors for each half hour for each fuel for each REZ. It doesn’t account for cost, correlation with demand, transmission, social license, rooftop solar. Some of these things (rooftop solar and capital cost) can easily be accommodated and I may do so in a future note. Others are more difficult. Also we aren’t dealing in the real world with a fresh sheet of paper.

However what I personally take from this analysis is that Queensland should have a huge role to play in the NEM, it should be getting lots of $ for transmission both within the State and for connections South. Equally Marinuslink is likely to be just as useful as building offshore wind.

These conclusions may change as other factors are thrown into the optimisation algo.

The following map taken from the ISP shows where the REZs are located with the notation first letter = State and then the number is the zone within the State.

Figure 4 REZ locations, source: AEMO

Wind and solar farms as a portfolio – the lessons from finance

I wrote about the idea of seeing wind and solar farms through the lens of finance theory ’s “efficient frontier” last June. In this note I continue that journey by employing the Sharpe Ratio to build an “optimal” portfolio of wind and solar in the NEM.

The Sharpe ratio in finance is the ratio of the expected return on a security divided by its standard deviation. It’s a measure of the return you get relative to the risk of getting that return.

The idea is that by building a portfolio of securities you can improve your overall Sharpe ratio, that is a portfolio will give you a higher return for a given level of risk than you can get from owning individual securities. This happens mainly because the standard deviation of a portfolio is less than the standard deviation of the individual securities. They don’t all go up the same amount at the same time and vice versa.

To demonstrate that, you need to calculate the mean expected return of the portfolio and its standard deviation. I want to avoid the maths as far as possible, mainly because I’m not very good at it, but its important to appreciate that the variability of the portfolio return depends not only on the variability of each stock considered on its own but also their “covariance” or the extent to which stock returns tend to move together.

The other important thing that the portfolio return and standard deviation depend on, is how much you put into each stock. That is the relative weight of the stock in the portfolio. Its finding those weights that is the point of this note.

40 REZs, two fuels, 40 million data points

Translating these ideas into the world of Australian renewable energy our portfolio consists of the 40 REZs that AEMO provided data for in the 2022 ISP. In each REZ AEMO provided the expected half hourly output between July 2022 and June 2052 of a 1 MW wind farm, and a 1 MW solar farm. In fact for wind they provided a high and low series. So that is basically 120 series of roughly 0.5 million half hourly forecasts each or roughly 60 million data points.

For the wind data I took a simple average of the high and low series for each zone.

In renewable energy we care about (1) the capacity factor = actual output per year/(24/7 output) (2) the variability of the output or how likely it is to be running at any given time, like dinner time and (3) other factors like cost and location.

Solar is more predictable in output than wind but nevertheless has a higher variability because it doesn’t run at night.

The following chart attempsts to illustrate the concept of the Sharpe ratio. It shows the best 15 wind zones sorted in order of Sharpe ratio best to worst. The chart shows the capacity factors and the volatility. You can see that Queensland in general and North Queensland in particular has both a good capacity factor and a relatively low volatility of output.

Figure 5 Best wind farm locations. Source: ITK,AEMO ISP

The offshore wind zones (in blue) have good capacity factors but are, like the Tasmanian ones typically more volatile than the Queensland ones. The six best zones as measured by the Sharpe ratio are all in Queensland and Tasmania. No NSW wind farm makes the “best” Sharpe ratio list and only one in South Australia. Again this list doesn’t pay any attention to cost, or demand correlation or access to transmission, or social license.

Repeating the same exercise for solar shows that the capacity factors, and the not shown here Sharpe ratios are much closer together and that Queensland, NSW and South Australia are the best regions for solar.

Also if you compare the scales for the wind and solar charts you will see, as expected, that wind capacity factors are higher than solar and the standard deviation of wind is lower. The latter result is because the wind does blow at night.

Figure 6 Best solar farms.Source: ITK, AEMO ISP

For some colour relief and a more pleasing to the eye but generally abstract figure shows the correlation of each of the 80 wind and solar zones with each other. Perhaps as someone suggested it would make a good corporate symbol

Figure 7 Renewable energy correlation. Source: ITK , AEMO ISP

The optimisation process

The problem is to find the weights for each zone in the portfolio of wind and solar zones that maximises the sharpe ratio of the portfolio. There are at least two ways of doing this that I know of. The first way is just to run a loop that throws random weights at the portfolio and then choose the one with the best Sharpe ratio. There is nothing inherently wrong with this method. The second way and what I did is to use some kind of “solver” engine. I used a solver available as part of the scipi python package . It took 20 minutes and 3000 iterations to find its “best” set of weights which were constrained to be between 0 and 1 and to sum to 1.

The following figure shows the Sharpe ratio for every REZ wind/solar combo as well as for the existing utility wind and solar farms and finally the “Optimised” portfolio. You can see that the Optimised portfolio performs about twice as well as the exising NEM portfolio and the existing NEM portfolio beats any existing individual REZ. As it turns out the yellow bars are the solar farms and the blue bars the wind farms. Again you can see the uniformity of the solar farms on this scale.

Figure 8 Sharpe ratios for REZs and for existing NEM portfolio and Optimised. Source: ITK, AEMO ISP

Transmission, social license and easements

This note started out as a narrow piece on landholder access value. However its grown to comment on the value of transmission, the relative value of individual projects and the in my opinion, improper use of inherently inaccurate RIT NPV models to drive decisions instead of using them to facilitate decisions and improve understanding.

The ISP is at its heart more than a transmission planning tool, it is a synthesis of policies adopted by Australian Goverments, Federal (zero added value) and State to show how those policies can be brought together to decarbonise the NEM and hold electricity prices steady. Even so although the ISP recognises the need for social license, it isn’t modelled. Nor does it explicitly model electricity prices and therefore competition impacts that an integrated NEM provides. Nevertheless it rises above being “just an NPV model” because of the vision it presents. And because of the seemingly simply but actually highly democratic “Delphi” process its clear its been able to sell that vision to a majority of stakeholders. The sale of that vision is the “capstone” of the social license required and the consequences.

If we are going to reconfigure the NEM some transmission will need to be built. Arguments over the merits or demerits of individual transmission projects cannot escape this central point. Some old transmission may lose value. The key evidence today that more transmission between NSW and Victoria is needed is a forecast $40-$50/MWh price difference out to June 2025 at least.

Figure 1 Baseload futures. Source: NEM Review

ITK doesn’t expect that difference to be alleviated until project EnergyConnect [PEC] is completed or until there is more supply from within NSW. As I understand it other than the Waratah battery there is no prospect of alleviating the Vic to NSW bottleneck until VNI West is built around 2030 or just after.

Indeed as modelled in the draft 2020 ISP, Vic-NSW alleviation is seen as relatively low benefit compared to other actionable projects. From a current price and conditions perspective its tempting to argue that VNI West is actually the most important project, but that is probably a short term view.

Figure 2 Actionable ISP projects ranked by net benefit. Source: AEMO

And so to social license

Social license starts at the top, at Government selling the plan but the social costs are paid by the communities and environments that are impacted.

There is good evidence that even today far too much bargaining power for transmission lies with the transmission provider and not enough with the impacted community as compared to fully negotiated bargains between land owners and wind and solar providers. All consumers benefit from transmission in the form of lower electricity prices, and greater security and it’s the value of the land in its highest value use as enabling transmission that should be compared with the visual and other costs of facilitating transmission to the selling land owner. Equally the reduction of the value of surrounding land also needs to be factored in.

And in the case of energy there is a strong case that for historic reasons land owners in different projects are treated unequally.

In ITK’s estimates, the value of “land access” paid to Humelink land owners or ex owners will be about 1/6 of those paid to windfarm land owners.

Figure 3 Land use cost. Source: Humelink PACR, ITKe

For Humelink the current estimated easement costs are 2.75% of the total project cost, but will likely rise when the easements are actually negotiated. My point here is that easement costs are not a major decision driver. Still up to a point social license is, but only to a transmission developer, only up to a point.

NSW and Victorian price differences seem entrenched for years

Futures prices in NSW and QLD continue to rise.

Figure 4 Futures. Source: Global Roam

However it’s the difference between Victoria and NSW that’s of interest here, given that these are the two States that nominally are the most linked by transmission.

Figure 5 Source: Global Roam

During calendar 2021 average net Vic to NSW flow was 385 MW and didn’t rise above 500 MW even when the peak evening price differential averaged over $120/MWh.

If NSW pool price in 2023 was the same as in Victoria the NSW pool revenue would be $4 bn lower, or over 3 years that’s $12 bn. And even a little more flow might lower prices in NSW.

Figure 6 Pool revenue FY23. Source: Nem Review

AEMO’s Transmission cost report 2021 puts the blame squarely in Victoria’s side of things where transfer capacity from Victoria to Southern NSW is limited to 870 MW at peak at best. The problem with this is, unless I’ve missed something, its not due to be fixed until VNI West is built, if its built. NSW gets no relief until transmission from South Australia arrives or more local supply is commissioned. Transmission from South Australi will run into a bottleneck at Wagga which is where Humelink comes in.

Victoria and NSW existing limits and a ugmentation options
Zone	Existing limit MW	Aug mentation	Map
Central NSW to Sydney, Newcastle Wollongong	6125	Northern 500 kv loop cost $1 bn	{wi dth=“1.2013188976377953in” heig ht=“0.9869422572178478in”}
Southern to Central NSW	2700	Humelink $3.3 bn Or HVDC wagga to “bannaby” $2 bn	{wi dth=“2.5622430008748904in” heig ht=“1.0706310148731408in”}
Vic to Southern NSW	870	VNI west in some form cost $3.0 bn	{wi dth=“2.5554451006124235in” heig ht=“1.2731889763779527in”}

Figure 7 Transmission capacity by stage Vic to Sydney. Source: AEMO

Eraring sharpens the NSW net importer focus

One thing the closure of Eraring does is to heighten NSW’s historic status as a net electricity importer, that is demand is higher than production with energy being imported from Queensland and NSW.

The NSW Electricity roadmap will, if fully executed, likely make demand and supply more in balance but in 2022, 2030 is still a long way off.

The NSW transmission augmentation schedule looks as follows:

Figure 8 NSW network augmentation, Source: AEMO Services

And the broader context is shown in the map below.

Figure 9 Transmission development in NSW, VIC, QLD. Source: draft ISP 2022

RIT tests are nonsense, they obscure the basic questions behind complex unverifiable scenarios.

The traditional regulatory test for consumer paid transmission called the RIT-T is theoretically perfect enough to satisfy even John Pierce. In practice though it’s a load of old cobblers. In reality by the time the RIT is undertaken the decision to build the transmission capacity has already been taken. It is just a discussion of the appropriate route and the electrical characteristics of the link. And that is more a technical than economic discussion. In the case of Humelink a 5% difference in NPVs is regarded as sufficiently material to justify one route choice over another. This is frankly humorous.. HVDC was dismissed as 50%-100% more expensive in the PADR. 50% to 100%? In AEMO’s transmission cost database, HVDC for Humelink looks quite good on a cost basis, although the “benefits” aren’t modelled.

Complex NPV models used to justify one transmission route over another that attempt to predict over 20 or 30 or 40 years what generation mix will be built if one transmission link is built or not built completely hide the forest for the trees. Costs and benefits and costs to consumers are important but financial models aren’t meant to be used deterministically. NPV models generally have wide margins of error at the best of times and are a decision input not the be all and end all.

Its good judgement that drives good decisions, not easily manipulated, difficult to verify NPV models about future fuel mixes that are out of date before they are even published. How does one know what a good judgement is? Well there’s the rub of it.

The ISP is the primary decision input into what transmission is needed and the order in which it should be built. It is a fair point to be made, as Bruce Mountain and Ted Woodley make at every opportunity that the ISP takes a set of State and Federal policies as inputs and then works out a solution. Certainly Snowy 2 should have been modelled simultaneously with the ISP, but that is now irrelevant. Similarly if Queensland Govt eventually decides that actions matter more than words and stops trying to pretend it can simultaneously decarbonise , meet its renewable energy targets and keep coal generation open then it may build new transmission and the ISP will adapt to include that external decision.

Transmission provides diversity, insurance and competition

A strong transmission backbone in the NEM increases the resilience of the NEM by reducing dependence on local sources of power and energy. It also makes the NEM fairer by increasing inter regional competition. The history of the NEM shows that when the NSW and Victorian markets were brought together in the original Hilmer/Coag reforms of the early 1990s that NSW and Victorian coal generators competed strongly against each other to the benefit of consumers and the detriment of generators.

In a different world NSW could build lots of batteries and pumped hydro and have less interstate transmission capability. ITK believes that such an outcome would likely eventually lead to a few big players running the NSW market to consumers detriment. Of course that can happen NEM wide but the bigger the market the harder it is for an oligopoly to emerge.

Transmission provides both capacity and energy. In that sense its dispatchable power.

Social license, requires a license fee

Australia has a fundamentally divisive regime that divides property, mineral resources and access rights between the State, the land owner and the utility.

Broadly: Mineral rights below ground belong to the crown. People wishing to extract mineral rights obtain licensees from the crown and then have a right of access to the land subject to paying access costs. But look at the coal seam gas [CSG] experience to notice how this doesn’t always make landowners happy and the industry evolved so that landowners get significant additional payments and in some cases the CSG developer bought the underlying property. Note that the QLD CSG industry is fully electrified and this requires gas and power lines laid in trenches right across the impacted area. Its actually a text book example of how to do it with minimal environmental impact but lets not go there. In fact from a visual perspective, and I speak from personal experience, it’s the electricity transmission that is the most visually intrusive element.

By contrast wind and solar farm developers have no natural rights to the land on which they seek to locate their wind turbines and or solar panels and so they must negotiate land rental fees. Over time and in order to improve social license additional fees have often come to be paid to land owners that feel they are impacted even if the wind turbine is not located on their property. In addition there are community funds and similar.

Finally electricity transmission access is granted by way of easement:

“An easement is the right to enter or use a section of land for a particular purpose by someone who is not the land owner. 

Transmission line easements can generally be defined as the lots of land on which transmission overhead and underground lines are built and include a buffer area to ensure the safe and secure operation of the lines.”

The extent of transmission easement width wise is shown below although the left most tower doesn’t make much intuitive sense to me.:

Figure 16 Transmission easements. Source: Transgrid

The easement process is either a negotiated outcome based on the value of the land or if that fails it can be compulsorily acquired under the terms of the “Just Terms Act” with the valuation determined by the valuer general in NSW or ultimately by the Land and Environment Court. In the case of Humelink we are talking about 500 kv double circuit.

Safeguards scheme – Do new coal and gas projects make it completely pointless, or merely blunten the impact

As we previously opined just after the election, the centre piece of the ALP emissions policy, as opposed to legislate able but fairly useless target is to tighten the safeguards scheme to require a fall of about 5 mt per year from a starting point of 143 mt. So in ten years after the scheme starts those emissions are supposed to fall by 50 mt reducing overall total Australian emissions from all sources relative to today by about 10%.

To be frank ITK has doubts about the policy. Its tackling the hardest to abate sectors first instead of the easiest to abate sectors. Still as we will say several times, we must like Oliver Twist be grateful for what we are offered because the alternative is worse. And tightening the safeguards scheme is sound policy, its just the difficult part rather than the easy pickings available in electricity and transport.

Never mind that 5 mt is less than 1% of emissions that’s what’s on offer and because any policy is better than what the Liberal National party were offering so we should, and to an extent are, grateful.

But not so grateful that we can overlook pointing out what a farce it is to allow new coal and gas projects at the same time as the existing ones are required to reduce emissions. Note this is not a statement about whether new coal or gas projects should go ahead. It’s a statement that requiring existing projects to reduce emissions but at the same time allowing new projects is fairly pointless and also seemingly unfair to existing projects. That is unless the new projects pay and pay heavily for the privilege.

Contrary to what I last wrote coal and gas are not responsible for 25% of Australia’s scope 1 emissions, even though exports of goods and services , which includes agriculture are about 40% of scope 1 emissions. A little checking shows that coal and gas production, excluding say coal transport to port, are about 67 mt or 14% of emissions. And as we show later we could add another 50 mt maybe for the ocean transport of these products.

Figure 4 Emission by industry. Source: CER

Its still a big number and other sources point to even higher emissions from gas production.

It takes on even more significance when we look at the safeguards scheme. The following graph shows a summary by industry of the 53 largest covered emitters, remembering that electricity emitters are excluded.. Emissions from those 53 facilities total 100 mt out the 143 covered by the scheme and which are subject to the potential 5 mt per year reduction. I allocated each facility to an industry and I included Bass Strait in gas.

Figure 5 53 largest emitters summed by industry. Source: CER

I note that the 41.7 mt of gas is almost double what the CER analysis shows and this may be due to some double counting. The graph only covers coal mines that made the top 53 largest emitters from all sources. So most medium and small coal mines are not shown.

Digging into the weeds here is a sorted list of the top 29 emitting facilities. It’s a list dominated by gas.

Figure 6 Top 29 "safeguards" emitters. Source: CER

Another difficulty is that the Govt has stated that all the “export” industries covered under the safeguard scheme will have “tailored” treatment. Well guess what. They are pretty well all export oriented. So if they are all tailored then it seems like we’ll have to kiss bye bye to the 5 mt. And yet there is always a different way to cut the numbers, particularly given a bunch of bright bureaucrats.

Shipping coal, gas and oil nearly doubles the emissions from production

Globally shipping of all kinds results in about 1 bt of carbon emissions a year (ie two Australias) and represents about 2.5% of global emissions. See Transport and Environment

It turns out that shipping coal gas and oil is around 40% of the total.

Yes you read that right, shipping of coal, gas and oil is over 40% by weight of all global shipping trade. The numbers come from United Nations Conference on Trade and Development. To get the emissions from oil tankers its just their share of global shipping as a share of 1 bn tonnes of global shipping emissions and so on.

Figure 7 Global shipping, emissions and implied australian contribution. Source: United Nations Conference, Transport and Environment, BP, ITK derived

The Australian derived contribution to global carbon emissions from the shipping of fossil fuels produced in Australia is a bit of a stretch. The method was to work out Australia’s share of global trade in each commodity using the BP data and then to apply that share to the global emissions from the global sea transport of that product.

The data used to derive the shares is in exajoules

Figure 8 World energy trade. Source BP stats review 2020, ITK calculations

Based on the above data it appears that in addition to the over 60 mt of emissions from the domestic production of coal, gas and oil there is another 50 mt of emissions involved in shipping the product and no doubt still more emissions in transporting it to the port of export and from the port of import to where ever its finally consumed.

Yes Minister

Your analyst has always appreciated humour, and even if satire is the lowest form of wit and irony be far superior nevertheless “Yes Minister” was generally a good jolly.

As an avid student of irony it causes no more than a smile to note that we have policies like in Victoria where the aluminum smelter (the consumer) is subsidised and both a fossil fuel part supplier (Yallourn) and the renewable energy suppliers are also subsidised.

I have gone off reservation bringing in Portland and Victoria only becauseto demonstrate that the Federal Govt, and no doubt most voters, are unlikely to see any problem in forcing existing gas producers and coal producers to reduce emissions by 5 mt per year out of 143 mt total or say 3% and yet at the same time allowing new coal mines and gas facilities to start up.

And new gas projects are largely in West Australia. And as far as the ALP goes what ever West Australia wants in the way of new gas projects it can have.

Give us an A, Give us an L but don’t take the P

And hurrah, hurrah however timid and contradictory ALP policy is its better than the Coalition and we will always be grateful. And if I were in Albanese’s place I doubt if I would have the stomach to ban new coal and gas projects. But what I would do is make them pay heavily for the cost they are going to impose on the future of the world. I would frankly tax the guts out of them. And I’d tax the existing projects a whole lot harder.

Were I advising the ALP my policy prescription would have included:

• In regard to electricity. Increase the LRET target to say 65% by 2030 and allow RECs to be used as well as ACCUs to discharge “safeguards obligations”. Increasing the target to 65% is a way of forcing the existing large gentailers to finance more wind and solar and takes the burden away from the States.

• Mark Butler’s residential battery program could be revived. It dovetails well with AEMO’s ISP modelling and would be politically popular as well as really useful. I’d also charge the ESB to work on a revision of the current NEM functional design that is the separation of retail, generation, distribution and transmission. A place may need to be found for the large scale deployment of community batteries in the way WA is doing it without having to go through endless regulatory jumps. In any event some kind of storage scheme analogous to the LRET is likely a goer. This would provide opportunities for pumped hydro and batteries to compete. Despite the ESB analysis I am intuitively drawn to the Californian 4 hour capacity credit model as it targets diurnal storage. Diurnal storage is clearly the emerging market need once we build the bulk wind and solar farms.

• Legislate vehicle tailpipe emission standards just about the same as Europe, maybe with a two year adjustment phase. In my opinion this is an easy win for the Govt. Future research will look at how much this could save a year in emissions compared to the safeguards proposal

• Put some weight behind 7 star residential building. The built environment is a major consumer of energy and carbon emitter. There is a ton of work done in this sector already its true and yet the perception remains that the overall results are not that flash

• Raise taxes on coal, gas and oil production. We can do it for tobacco we can do it for fossil fuels.