Know your NEM: Why a business customer might buy a battery

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Fascinating insight into electricity bills for business, and why they should, or shouldn’t buy a battery. Meanwhile, futures price fell across the board.

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What’s interesting at the moment

We focus on the commercial market and the outlook for pool electricity prices in the next three years.

ERM presentation to investors

ERM released a presentation last week as part of an investor day. Companies generally hold investor days when there is some positive news or there is a new strategy or they just want investors to remember they exist.

Although there was not much info directly share price sensitive – e.g. changes to estimates or new investments – the presentation nevertheless had some interesting slides.

For me, the most interesting was their presentation of a sample monthly bill for a medium/large customer.

Figure 1: QLD industrial customer monthly bill. Source: ERM

This customer pays $60.59/MWh in this month for energy representing 49 per cent of costs, RECs (large scale certificates) cost 9 per cent or 11 per cent if we include SREC (small scale renewable scheme). This component of cost will drop away sharply post 2020.

In contrast to household customers, networks are just 39 per cent of the bill for business customers and, of that, demand charges are by far the most important.

The demand charge is based on the maximum kVA (kilovolt/amp) used in the month. I read that the kVA is the Kw+ reactive power.

There is a thing called a power factor that has to be allowed for in measuring the demand charge. The power factor for this company is 0.9, meaning that the maximum monthly kW of  441 is only 90 per cent of the kVA charge.

Looking at this company, it becomes apparent that batteries could not be profitably used to “peak shave” the network demand charge at present prices. If the battery was reconfigured to give less energy but more power then it would be closer.

For instance, if the battery’s max power was 100kW for an hour, it would be just about there.

The network peak demand shave in the table below comes from reducing the max monthly kVA charge by 50. ERM stated that the load factor for this business was 66.9 per cent.

Figure 2: Battery modelling for commercial use. Source: ITKe

The profile and maximum daily demand for this customer were shown by ERM.

Figure 3: QLD commercial customer, monthly pro forma profile. Source: ERM

ERM also showed its estimate of market share in the 86TWh commercial and industrial market. Margins in this market are low, about $4.50/MWh so volumes are high, but profits insignificant for ORG and AGL compared to the retail market.

As a result, market shares are volatile. Should EnergyAustralia and or AGL wish to win back market share based on lower price, they could do so.

ERM has consistently shown, though, that customers prefer its offering in the commercial and industrial space. That’s what specialisation and focus and really putting the customer first will do for you.

Figure 4: C&I market share. Source: ERM

The outlook for electricity prices

There are at least three mainstream, extremely expensive packages for modelling the NEM and the outlook for electricity prices.

  1. Plexos is used by the AEMO. Of course generally AEMO don’t model price but they do use it to model supply and demand. This is mainly a linear and integer planning model with “solvers” see this  plexos brochure for more.
  2. Strategist as used by Jacobs. Jacobs described this as a “multi-area probabilistic dispatch algorithm. The timing of “new thermal generation pant and interconnection upgrades is determined by dynamic programming that seeks to minimize system production and new capital costs”
  3. Frontier Economics has the whirlygig (least cost mix), spark (least cost engine with game theory add ons) and strike (efficient mix of purchasing instruments suite of modelling tools. See frontier electricity models for a description.

There are other models out there, but these three are the most commonly employed in Australia for major studies. Those studies typically cost $0.5 m and up and are used to support, I say this advisedly, to support policy choices made in the market.

Despite the existence of these extremely expensive models, electricity prices go up and down just as they have always done. Many electricity price forecasts turn out to be wrong, and the modelling outcomes tend to support policy choices that the client wants.

This is no different to consulting reports or expert advice which on average tends to support the position of the person paying the bill.

This is in no way to denigrate these models, each of which no doubt have a massive amount of sophistication and capability.

It’s simply to point out that the output depends, as ever, on the inputs and that markets, even the vertically integrated oligopolistic Australian electricity and gas markets are complex beasts that defeat most attempts to beat or forecast them.

We conclude that electricity price forecasts retains a high element of judgement skill, a high likelihood of error and that frequent revision of forecasts is a reasonable approach. Without claiming skill but working our way through the qualifying rounds our helicopter view is:

New supply is going to impact the pool prices, maybe drive up consumption

What we know is that there is about 15-17TWh of new energy, maybe 5 per cent less after line losses, being built to come on line before Liddell goes away. This excludes two new AGL gas plants and the 100MW Bayswater upgrade.

Figure 5: New zero marginal cost supply. Source:ITK

In this table we have added in 175MW from the Susan River and Childers PV farms in Queensland, previously overlooked but definitely under construction, and also added in 650MW from the VRET scheme, where outcomes are due in July.

We have adjusted output down by 5 per cent for line losses, but given the potential 13 per cent increase in South Australian supply, more curtailment seems likely.

We see no way for Queensland to export an additional 4-5TWh of power, so some existing generation will have to give way in that state. In Victoria, where there is a 15 per cent increase in supply, we see gas going away in the short term. But when Liddell closes, more exports coming back to NSW.

In general we expect prices to soften across the region, but the question remains how much?

In the middle of the day, Queensland generators will push energy to NSW as hard as they can. When the wind blows, Victoria and South Australia will push energy to Tasmania and NSW.

NSW coal generators, which are the highest marginal cost coal generators in the NEM, will cut back on output and try to make their existing coal contracts go as far as possible.

New coal contracts are at much higher levels than the old ones in NSW. For instance, last year Centennial repriced upwards a 1.4 mt contract by 74 per cent.

As shown below (Fig 9), the A$ export price of coal is around $147 /t. So even allowing for lower spec, that is NSW uses bad coal at say 0.4 t coal MWh, you are looking at maybe $48/MWh for fuel cost alone, if you pay export parity.

That is the future for NSW coal generation and why we retain confidence that it will go away over time. NSW generators are not really that important to the NSW coal mines, other than the nearest market is always the best market.

Figure 6: NSW coal sales FY17. Source: NSW Govt

Conclusion: Price weakness in say 2021 and more volatility

In short, electricity prices may drop further than implied by the futures market, we expect a reduction in gas generation in Victoria and Queensland, and reduction in output from NSW coal generators.

Volatility will likely increase, particularly in South Australia and Victoria. None of the pumped hydro projects will be online to take advantage of this volatility. Gas peakers can therefore maybe get some returns.

Prices will probably rise again post the closure of Liddell and there will be some squeeze in NSW.

Given the slow speed of transmission development it would be a good effort to get the NSW/QLD interconnector upgraded in that time. It’s physically possible, but not in the world where the RIT-T has to be satisfied. Even more so for a SA-NSW interconnector.

The best opportunity for new renewable development, in my opinion, remains NSW despite the fact that futures prices in that state are the second-lowest in the NEM.

The market action –  futures drop, gas rises

The main feature of the past week was indeed a drop in futures prices across the board.

If we use Victoria as an example of the underlying market, not impacted by Queensland government command control, we see that after hitting a peak of $88/MWh in April 2017, the 2020 average contract is down to $65 MWh.

That’s a pretty good recovery, considering that both Portland smelter is back on line (maybe just for a few years) and Hazelwood has gone away.

The chart shows the recent weakness. Electricity prices are still 50-65 per cent higher than they were back in 2016 but then so are gas prices.

Figure 7: Vic 2020 futures contract. Source: ASX

Elsewhere, Queensland gas prices rose, feasibly already starting to reflect the higher LNG spot prices on offer. Consumption was typical for this time of year, and spot prices were identical to last week but down on last year.

Figure 8: Summary

USA bond rates fell again – very good news for renewable financing if sustained – and are now little changed on a year ago. Coal prices rose but oil prices fell.

Figure 9: Commodity prices. Source: Factset

We already note the 19 per cent lift in US$ oil prices over the year, but the USA 10 year bond continues to slowly rise.

Share prices

Most utilities have done poorly this year, but Windlab had a good week. Genex has announced it hopes to get to FID for its pumped hydro project in Queensland in H2 of this calendar year. At this point we simply note that the project cost is large relative to its market capitalisation.

Figure 10: Selected utility share prices

Figure 11: Weekly and monthly share price performance

Volumes

Figure 12: Electricity volumes

 

Baseload futures, $MWh

Figure 13, NSW. Figure 14: Victoria

Figure 15: Queensland. Figure 16: South Australia

Figure 17: Baseload futures financial year time weighted average

REC Prices

Figure 18 Source: Mercari

Gas Prices

Figure 19: STTM gas prices

Figure 20: 30-day moving average of Adelaide, Brisbane, Sydney STTM price. Source: AEMO

David Leitch is principal of ITK. He was formerly a Utility Analyst for leading investment banks over the past 30 years. The views expressed are his own. Please note our new section, Energy Markets, which will include analysis from Leitch on the energy markets and broader energy issues. And also note our live generation widget, and the APVI solar contribution.

David Leitch

David Leitch is a regular contributor to RenewEconomy.com.au. He is principal at ITK, specialising in analysis of electricity, gas and decarbonisation drawn from 33 years experience in stockbroking research & analysis for UBS, JPMorgan and predecessor firms.

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5 Comments
  1. Jonathan Prendergast 6 months ago

    Yes, seeing unbundled electricity bills can be very revealing. I would suggest in this case a bill has been selected with a very high % of network charges being fixed charges. Possibly a customer in Ergon. Generally the wholesale/futures prices are lower in QLD, and Ergon has much higher fixed/capacity tariffs, compared to say NSW/Vic in Ausgrid/Citipower network areas. Certainly commercial battery proponents should be concentrating in Ergon!

  2. Andy Saunders 6 months ago

    That commercial customers max demand seems to be about 440kW (fuzzy graph…), if it corresponds to the bill network demand of 489 kVA then the power factor is 0.9 – not unusual.

    Does anyone know if a Tesla Powerwall can do power factor correction? If so (I know SMA inverters can), then there might be an extra few dollars in the economics and it may tip the balance to make it affordable…

  3. Peter F 6 months ago

    That capacity factor is very flat. A more normal demand from a company that works 5 or 6 days 1-2 shits would see a much lower Capacity factor and therefore more use for peak shaving

  4. Genevo 6 months ago

    The issue with Tesla’s Powerpack in an Australian NSP setting is that they are designed to satisfy Californian NSP (PG&E, SCE) demand response incentives which reward 2 & 4 hour demand reductions. Hence the Powerpack being a 4 hour system. In AU this equates to an expensive energy (kWh) redundancy. A 1 hour system (100kW/120kWh) with the commensurate (lesser) price tag, arbitraging a network charge of $17.47 would yield far better paybacks.

  5. bruce mountain 6 months ago

    David, excellent note as always. thanks.

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