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Know your NEM: AGL’s cheap wind deal, and falling cost of storage

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Volumes: For the week ended Jan 20, were it not for Portland smelter being 2/3 closed NEM wide volumes would be well up. As it is despite NSW volumes 4% up on last year and QLD volumes up 13%, the 14% decline in Victoria has left NEM wide volumes flat.

The increase in volumes is due to warm weather and QLD LNG. Qld daily volumes on hot days in QLD are within touching distance of total volumes in NSW. Qld is becoming ever more important as an electricity market but transmission links to and from QLD have been neglected.

In our view QLD’s electricity industry is sharply anticompetitive with too much Government ownership of generation and networks. QLD generators regularly exploit the market and the rules in QLD. Their primary victim is QLD retailers particularly ORG, but in the end all QLD business and consumers pays excess price for electricity. QLD’s renewables plans are fantastic but slow to be implemented. Meanwhile over reliance on gas to provide peaking and shoulder power is going to be costly now that gas prices have doubled.

Future prices:

Victorian Premier Daniel Andrews was apparently quoted as saying that the subsidies to keep Portland open wouldn’t have any impact on the electricity price. A schoolkid could tell him that if you increase demand price will increase.  Victorian futures prices were up 8% during the week. NSW and QLD futures prices were up 5%.

Welcome to the real world. The Victorian FY18 price was up $8 MWh and FY19 $5 MWh. Over about 40 TWh of Victorian demand that’s $200 m a year. But it’s worse because of the flow on impacts to NSW where prices are up $7 MWh in two weeks! Portland may be a beautiful town and aluminium export dollars welcome but the timing of this subsidy could not have been worse. As the stock market adage goes, “the cure for high prices is high prices”. High prices will encourage energy efficiency and provide an incentive for new investment.

However, with Federal Govt locked in its “gordian knot” over energy policy and generation, developers are going to be especially cautious. We think the blame for high electricity prices and falling energy security can be more reasonably laid at the feet of those forces trying to get the present RET repealed. That is what is killing new investment.

A call reported in “The Australian” today for the CEFC to provide money for “clean coal” in Victoria is perhaps the ultimate exemplar. Clean coal in Victoria is frankly genuinely amusing as an example of what I believe is “cognitive dissonance”. As for using the CEFC for coal investment the mind truly boggles but it does point to the fact that the CEFC (i) needs a strong chief executive appointment ASAP and (ii) if you don’t spend your budget someone else will nickel and dime it away from you.

Figure 1 Victorian Base Load Futures. Source NEM ASX

Figure 1: Victorian Baseload Futures. Sour

Figure 2: NSW baseload futures

Figure 2: NSW Baseload futures

Figure 3: QLD Baseload futures

Figure 3: QLD Baseload futures

Spot electricity Prices were high this week averaging $124 MWh in Qld and $70 MWh in Victoria despite the decline in demand. This is becoming very much a supplier driven market. Over the past 5-7 years competition within the NEM has been reducing and we believe the big players are getting a tighter grip.

The biggest winner from keeping Portland open will probably be CLP. Its Yallourn power station – virtually as bad in terms of emissions as Hazelwood – has traditionally been a major supplier to the Victorian industrial market. That plant has been written down to very little by CLP but will now see a doubling of revenue and a bigger percentage increase in profits over the next few years.

REC prices were unchanged

  • Gas prices : These continued to increase. Basically you were paying $9 GJ- to $12 GJ for gas in the spot market last week. These prices undoubtedly make new gas fired generation more expensive than new wind plants, but it remains true to say that the gas plants would achieve a significantly higher electricity price than an a wind or PV plant.
  • Utility share prices: Were mostly stronger and most utilities beat the broader index. We have replaced Duet with Tilt as Duet is in the process of being taken over. Tilt is a windfarm owner and developer with a largely safe revenue stream 1/3 sourced from New Zealand and 2/3 sourced from Australia. We expect it to grow in Australia although it seems to have a very much safety first attitude. Safety first doesn’t get you too far in the Australian market. Elsewhere we expect the Alinta IPO to be back “on the go”.
  • Industry news..

Outside of the Portland subsidy the main news last week was:

  • The $65 MWh contract for the Silverton wind farm. This is a very low price. Unfortunately its always difficult to be confident in the arms length nature of a price struck between related parties. What is for sure is that AGL is going to get some cheap power from that wind farm. What’s in it for QIC, AGL’s 80% partner in the Powering Australia Fund [PAF], is much less clear. We can understand low prices for long term contracts but this one is only for 10 years (5 years plus 5 year option). Still it does show that when it’s the QIC involved the banks are willing to help.
  • Equally the construction costs quoted for PV plants are now well below wind. The Clare PV farm at $1.78 watt compares with the $2.50 watt AGL quoted for Silverton. PV farms are also very fast to build.
  • Over the Xmas period the Kauai Island Electric Coop and AES announced a 28 MW solar plant with a 20 MW, 100 MWh battery for US$0.11 KWh or US$110 MWh. That’s down from a 2015 price quoted by SolarCity (Tesla) for US$145 Wh for a smaller system. US$110 MWh is still not as cheap as combined cycle gas in Australia (which is at maybe US$65 MWh) but its getting closer. Also the gas price is still more likely to go up than down in Australia in the next year or two as the oil price will probably increase a bit.

    Figure 4: Summary

    Figure 4: Summary

Figure 5 Selected utility share prices.

Figure 5 Selected utility share prices

 

Figure 6: Weekly and monthly share price performance

Figure 6: Weekly and monthly share price performance

VOLUMES

Figure 7: electricity volumes

Figure 7: electricity volumes

BASELOAD FUTURES

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DL10

Figure 12: Baseload futures financial year time weighted average

GAS PRICES

Figure 13: STTM gas prices

Figure 13: STTM gas prices

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.  

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  • Jonathan Prendergast

    So much to go through!

    I think Daniel Andrews is right, in the long term. Electricity is about supply and demand, and scale. The SA grid goes from 1 GW to 2GW. Meanwhile, Victoria goes from 4GW to 6 GW. (not exact but trying to illustrate). Sure in the short term, losing such a large demand/consumer will reduce prices. But in the long term, loss of such industry will reduce scale and base load on the market, seeing lower utilisation of plant, increasing costs.

    (yes, I want more renewables, but even at 50% in say 10 years, the above applies. a 100% renewable scenario would be different)

  • alexander austin

    Is the $65/MWH price for gas an operating cost only estimate or does it include an allowance for the cost of capital?

    • David leitch

      That is US$65 MWh and is what is called in the industry LCOE (levelised cost of electricity) or what an economist would call LRMC (long run marginal cost). Its the electricity price required for the investment to earn its cost of capital, including capital costs, operating costs, tax and finance costs. It can be used to compare different generation types.

      • alexander austin

        thanks. I missed the exchange rate …. and thought it seemed very low compared to gas prices. What gas price do you assume to get a US$65 long run cost?

        • David leitch

          I used A$7.50 GJ. The numbers are all a bit theoretical. In each case you have to think about gas transmission/storage costs. Gas prices tend to vary enormously over a 20 year period but modellers invariably just pick a number around their estimate of long term gas cost.

          • alexander austin

            thanks for the clarrification

      • Peter F

        David
        What did you use as your capacity factor for CC gas and the WCC. By my calculations a new combined cycle plant would be nearer to A$110.
        CC gas plants don’t load follow very well because the exhaust temperature of the gas plant has to be kept just so for the steam section to work and the steam section has a 1-2 hour ramp time. Some of the existing CC plants in Australia are now running just as OC plants and therefore have higher cost per MWhr because the available peaks are too short to fire up the steam generator.

        The Hawaiian plant is more like an OC peaker and at peak gas prices $25/MJ an OC plant is more like $300/MWhr

        • David leitch

          Peter you’ve changed the $90 to $110 :-). A$100 = US$75 if you want to split the difference.

          I agree with your comments about CC plants and Pelican Point is an example of that. I think they will work better balancing the solar duck curve than balancing wind.

          Of course operating gas generation in open cycle mode is little better than modern coal generation in terms of emissions and more expensive.

          By definition the Hawaii plant is the lowest cost solution to the problem Hawaii has else a different solution would have been chosen. I am not close enough to know whether it is an “energy” = combined cycle or “power” = open cycle problem.

          What I do know is that we need some dispatchable renewable energy.

          • Peter F

            The coal vs gas emissions problem is much more complicated than people realise but we won’t go there now.

            The problem here is cost.
            I was unclear and you are correct US$110 is more expansive than gas @A$7.50. I recalculated that and it comes out at around A$100/MWhr if it can run at 60% CC duty cycle.

            This is unlikely to be achieved over the life of the plant and certainly not during high gas prices. The problem for gas generators is that they tend to see highest demand when their fuel prices are highest. Of course gas prices can be hedged but hedging is not free.

            Currently gas prices are between 8 and $11 and range up to $25 at peak so if we take 50% CC duty cycle and say weighted average gas price of $12 the price gets to around US$105 still with fuel price and utilisation risk.

            The solar/battery system has a price risk also but even if the price drops to $35 per MWhr it can still supply because it can recharge at zero marginal cost the next day. At $35 or even $55/MWhr it costs actual cash to turn the gas turbine on.

            Given that the gas plant is a 25-30 year payback period and solar, wind and batteries are getting cheaper all the time, do you think it is a safe investment.

  • David Pethick

    Another significant piece of news this week was the AGL purchase of $7-$8/GJ gas from the Gippsland Basin, from FY19 to FY29. All the cheap gas is gone.

    Cheers.

    Dave P.

    Sources:

    http://www.asx.com.au/asxpdf/20170118/pdf/43fcswcy05y1ps.pdf

    http://www.afr.com/business/energy/gas/southeast-gas-on-track-after-agl-energy-doubles-buy-contract-20170117-gttfy4

    • David leitch

      David they are small volumes. There is still more gas in Bass Strait. Cost and price are another matter.

      • David Pethick

        Certainly small volumes, but the list of buyers is interesting. EA, AGL and a decent sized C&I customer (O-I) all know where the market is. They chose to lock in some supply at what seems to be the new market price (ex shipping).

        I’m not an upstream gas guy, but I don’t see a credible path back to lower gas prices in the next decade. My perspective is on the power markets – it’s hard to see new OCGT or CCGT being built to replace existing coal fleet with the current spark-spread.

        Cheers.

        Dave P.

        • David leitch

          Agree 100%