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Dumb and dumber energy choices in the wild West

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The Western Australia energy system can proudly lay claim to some notable firsts for Australia. In 1986, it opened the nation’s first commercial wind energy plant near Esperance. Just last month, the state government formally opened the nation’s first utility-scale solar farm near Geraldton.

Now it may have a new but less admired “first” – a power plant that is built, but doesn’t operate, and is paid for by a state-sponsored tariff imposed on consumers. The Perth-based company Merredin Energy is in the throes of completing an 82MW peaking plant near the wheat-belt town of the same name. It is being built at an estimated cost of $95 million and proposes to use expensive and highly polluting diesel fuel, but it may never be switched on.

And if it isn’t, its owners might not care – under WA’s capacity payments system, they’ll likely make enough money simply for being there – around $15 million in its first year. In fact, they might prefer if the plant wasn’t used. Some analysts suggest it would be difficult to run the diesel plant at a profit – even during critical peak periods – given the sky-high cost of diesel and the fact that WA power prices rarely jump to more than $300/MWh.

A couple of hundred kilometers away, WA state-owned generator Verve Energy is about to take a leap into the past with the reopening of the highly polluting Muja A and B coal-fired generators near Collie. Is being criticized as a knee-jerk reaction to the disruption to gas supplies at Varanus in 2008. The company says it is an interim measure that is cheaper – and less long lasting – than building a new coal-fired power station. But critics say it is a another example of overkill – again encouraged by the state’s capacity market system.

The Muja A and B coal-fired power station

“We have a long history of strange decisions,” says Peter Newman, professor of sustainability at Curtin University, citing the decision to power the Kwinana power plant with oil in the early 1970s, just as the global oil crisis erupted, and Premier Sir Charles Court’s impulsive decision to declare later that decade that the state would soon be powered by 25 nuclear plants.

In the end, the state government went for gas. Excited by the prospect of tapping into its huge natural gas resources, the government signed a large take-it-or-leave-it supply contract based on bullish demand forecasts. Then it found itself with excess supplies that it decided to pass on to households. But it had an immediate adverse impact, and effectively brought another pioneering effort, the introduction of solar hot water systems to the mass market, to an end.

The company SolarHart began in WA in the late 1950s when a bunch of plumbers, frustrated with the expensive and dirty coal fired generation based in the south west of the state, decided  that heating water with the sun was a lot more efficient, and cheaper than with coal.

By the late 1970s nearly one third of new houses were installed with solar hot water heaters. That figure plunged to less than 1 per cent once the government started to flog subsidized gas. Now that gas supplies have reached international parity price, that is a millstone around the government’s neck – one apparently, that the Newman government is keen to repeat in Queensland.

“We don’t have a good record about making sensible choices about power,” Newman notes. “In those days you could not get anything on renewables going. It was virtually impossible.”

But even when renewable energy development has occurred, there is an air of tokenism. After the construction of the first Esperance wind farm, little was built in following decades. And on the same day that Energy Minister Peter Collier travelled to Geraldton to open the 10MW Greenough River solar farm built by First Solar, GE and Verve Energy, he and premier Colin Barnett said they wanted the federal government to get rid of the renewable energy target – a move that would surely mean that no more solar plants of that type would be built for the foreseeable future.

The irony is that WA is home to the best wind and solar resources. Across town from the Merredin diesel peaking plant is the 200MW Collgar wind farm, the largest in the country when it was built. When it opened last year, it stunned even its operators by producing energy at a capacity factor of nearly 50 per cent. (Just for comparison, black coal generators in Queensland operated at a capacity factor of 55 per cent in the last year). Collgar is believed to be still operating in the mid to high 40s, and much of the  wind comes during the day.

WA’s Collgar Wind Farm

Newman says WA should now return to wind and especially solar, and use its natural resources to advantage. (Even the Saudis have figured this out, reasoning that its cheaper to build solar and then reallocate subsidised fossil fuels for the more lucrative international market).

Numerous solar farms, including an expansion of Greenough River, are also on the drawing board, particularly in the mid-west region near Geraldton. Some of these could be brought into production once the transmission line to the area is upgraded. Developers think it could be the first solar plants to be built in the country without the need for any support beyond renewable energy certificates, simply because they make more financial sense, and deliver a more predictable financial outcome, than gas-fired generation.

Back at the Merr

edin peaking plant, there are questions about whether a capacity market is really the answer to the energy industry’s problems. This was introduced in WA because of its “peaky” market, and is designed to encourage more peaking plants to be produced rather than baseload, so that they can respond to rapid changes in demand caused by hot weather and other extreme events.

The Merredin Energy web site makes mention of the Collgar wind farm, saying that wind needs backup from peaking generators on a 60:100 basis.( Ie. 60MW of backup for every 100MW of installed renewable capacity). But the experience of South Australia shows that no new peak load capacity has been needed to support wind – now accounting for between 22 and 30 per cent of the state’s generation.

And further down in Merredin’s explanation, it concedes that its plant’s purpose is really only for use for around 100 hours a year  ”mainly during periods of extremely hot weather in the Perth metropolitan area.” But as explained above, many doubt it will be used at all and estimate that WA customers are paying around $200 million a year in payments for capacity (this and other plants) that is not needed.

While capacity markets exist only in WA in Australia, the decisions being made in that state are important to the eastern seaboard, because as renewable energy continues to be deployed, forcing down the price of wholesale energy because its fuel cost is zero, attention will one day need to turn to how enough fossil fuel capacity can be encouraged to stay on line to fill the gaps.

This is what is occurring now in Germany, where it is admitted by the biggest generators that the future of coal and gas generators, and the government has implemented a “please don’t go anywhere until we sort out the market” hiatus to its plans. The challenge is how to design a market that supports a system whose focus is no longer on meeting the peaks. Capacity markets are cited as one solution, but research suggests that they will not be flexible enough to deal with the new “paradigm” of increased wind and solar, and the push to decarbonise energy system.

What is now emerging is a proposed system called a “capabilities” markets, that reflects not just a plant’s ability to respond, but also it’s environmental and other credentials. It’s a complex system, that breaks down the market requirements, but its proponents, such as Regulatory Assistance Project, say it will help energy market regulators design wholesale markets to ensure supply security without undermining competitive markets, without locking in all the wrong resources, without creating excessive windfall profits for existing generators, and without prohibitively high renewables integration costs. But more on that another day.

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  • Pete Moran

    Sorry, to be picky, but that picture isn’t Muja.

    That’s Collie Power Station (completed recently – unfortunately).

    Muja is two new units (tall stacks) and two old units (smaller) which appears like four stacks in a row.

    • Sophie Vorrath

      Thanks Pete. Picky is good. Error fixed, hopefully!

  • Ian

    In an electricity market with high renewable energy penetrance incentives should be geared to creating an adaptable load from the end user base and energy storage facilities . There are many examples of this. Ice storage refrigeration, smart domestic and industrial hot water heaters where the heating elements are switched on and off remotely. Intermittant industrial processes that use electrical power during daylight hours when solar generators will be operational. Water pumping for city and town water supply, header tanks can store water until it is needed. Water reticulation tanks atop high rise buildings can be sized large enough to enable water pumping during peak power supply and water use at other times. Desalination plants over sized to allow intermittant operation. Pumped storage schemes of various kinds such as salt water pumped storage, pumped storage integrated with farm irrigation and town water supplies.

    • Mart

      ..smart load shifting in refrigerated warehouses, HVDC link between NEM and SWIS, remote cycling of air conditioner compressors, renewable methane in gas grid, smart charging of electric cars, etc., etc.

      But who in this country actually wants a high proportion of renewables?

    • Tim

      I agree Ian. What are the limitations then? For example, does the pumping station need to be hooked into the electricity market, so that it only starts pumping when prices are below a certain level?

  • Pete Moran

    The need for fossil generators as “backup” or “top-up” could be eliminated with some well placed concentrating solar thermal plant.

    CSP with storage can load shift, and if necessary can be gas boosted at higher efficiency than OCGT, and even approaching CCGT.

    Further; we need networks of wind, pv, CSP, industrial CHP demand agreements to buy/operate such fossil backup plant.

    Of course, the idea is that the fossil plant need never operate.

  • http://ronaldbrak.blogspot.com.au/ Ronald Brak

    It seems a little odd. It doesn’t seem that long ago that Western Australia seemed okay with just not meeting demand during peak periods and did things like ban escalator use instead. But now we have low cost rooftop solar that helps meet peak demand they go and build a peaking plant that may never be used. They probably could have avoided the need for the plant altogether with a small rebate to people who install their rooftop solar systems at an appropriate angle to meet demand.

  • Sean

    Whats the comparive cost for a 1MW HVDC connection to the NEM?

    • Pete Moran

      There actually isn’t one that long yet.

      The Chinese have just finished one that is 2000km long, but is 6400MW (!!!).

      It will require some visionary leaders to get that sort of infrastructure in place.

    • http://ronaldbrak.blogspot.com.au/ Ronald Brak

      A one megawatt cable is too small to be practical. A one gigawatt HVDC line is something like $2 million a kilometer according to this AEMO report:

      http://www.climatechange.gov.au/en/government/initiatives/aemo-100-per-cent-renewables/~/media/government/initiatives/aemo/APPENDIX2-AEMO-transmission-cost-assumptions.pdf

      So it would cost something like seven billion dollars, or about $300 per Australian or $3,000 for every West Australian. At $3 an installed watt, that could buy about 2.3 gigawatts of rooftop solar capacity. Given that solar is continuing to decline in price, my guess is it would be cheaper to use correctly orientated solar PV to deal with superpeaks, which are generally confined to the day, than to try to connect eastern and western Australia. Note this is just a guess. Maybe there’s enough money to be made sending electicity back and forth across the continent to make it worthwhile.

      • Concerned

        “Given that solar is continuing to decline in price, my guess is it would be cheaper to use correctly orientated solar PV to deal with superpeaks, which are generally confined to the day”
        What?
        What time does the sun go down?
        Here are a few facts. Check the figures.
        http://www.aemo.com.au/Electricity/Data/Price-and-Demand/Price-and-Demand-Graphs/Current-Dispatch-Interval-Price-and-Demand-Graph-QLD

        • Giles Parkinson

          In WA, the super peaks are in the afternoon while the sun is still up – blame the fremantle doctor. See here

        • http://ronaldbrak.blogspot.com.au/ Ronald Brak

          Concerned, a few points:

          1. Super peaks or critical peaks, or whatever one wants to call them, generally occur on hot, sunny, summer afternoons. This is the case everywhere in Australia. If you’re not aware, super peaks occur when our generating capacity is close to being maxed out. Today it’s not close to being maxed out.

          2. Australian solar power shows up as reduced grid demand as it is point of use and not grid only. As a result it can reduce or eliminate the daytime peak and result in a demand for grid electricity of the sort you provided a link to.

          3. Under the right conditions, Australian solar power can currently produce over 1.5 gigawatts in the middle of the day. Not only is this more than enough to send a DeLorean through time, it’s also enough to reduce the incidence of super peaks.

          • Concerned

            Ron,glad to see that facts never get in thje way,but what could we expect.

    • Sean

      Sorry Ronald, I meant 1GW
      6400MW would power Victoria or QLD.
      its about 2500 from perth to the middle of NSW.
      i wonder how much it cost the chinese to go 2000km?

      • http://www.outbackenergy.com.au Jim

        Sean, It is a lot more than 2500 km from Perth to NSW, that far would get you just into South Australia, a little bit further would be needed to go to reach the NEM which extends into SA,
        An upgrade of the existing Collie to Kalgoorlie line, and then run from Kalgoorlie across to SA, this is already covered in the BZE report.
        With that line in place across a high insolation and high wind region of Australia would allow bolt on of renewable plants all the way across, add a pipe line for good measure and desalination plants

      • Zvyozdochka

        That’s what is different about China; they see that as a long term investment, whereas we just seem to sit around complaining about the cost.

        Energy analysts/economists that I work with say that the Snowy project could not be built today.