ESB’s capacity payments for coal and gas may cost $3.2 billion a year. Guess who pays

The Energy Security Board’s recommended capacity payments for electricity generators will benefit polluting fossil fuel-based electricity generation over renewables.
  1. The Energy Security Board’s recommended capacity payments for electricity generators will benefit polluting fossil fuel-based electricity generation over renewables.

    And energy consumers will wear this expensive and unnecessary cost.

    The Physical Retailer Reliability Obligation (PRRO), which will provide a new revenue stream to generators in the form of capacity payments, has been proposed by the ESB as part of its mandate to reform the National Electricity Market (NEM).

    In effect, electricity retailers will have to pay generators for simply being available to generate energy in peak demand periods such as dinner time – but not for actually turning on their plants and generating electricity.

    Retailers will enter into contracts to buy “capacity certificates” from generators to make up the retailer’s share of a 1 in 2 year peak in power demand.

    These certificates will be allocated to generators based on some kind of assessment of their potential to generate electricity during peak demand periods, although how this might work is yet to be detailed by the ESB.

    A similar capacity payment is used in Western Australia.

    There, conventional generators (like coal and gas-fired power plants, but not solar or wind) receive “capacity credits” in line with a power plant’s generating capacity.

    What will this cost, and who’s footing the bill?

    Curiously, the ESB hasn’t provided costings on the energy bill rise consumers will face from capacity payments.

    The Western Australian example however does provide a guide. Forecasts suggest Western Australia will face a capacity price of $85,294/megawatt (MW) in 2022-23.

    If this cost were applied in the NEM, consumers could expect to pay almost $3.2 billion in 2023 alone based on AEMO’s forecast for a 1 in 2 year peak in demand of 37,161MW[1].

    Why? Because capacity costs will inevitably be passed through from retailers to end consumers.

    Residential households across the NEM account for approximately 45% of peak demand so they will shoulder close to 45% of the cost. This means, across the 6.4 million residential households in the NEM, every household would have to pay about $220 per year.

    Assuming the remaining cost is allocated between small to medium enterprises versus large industrial loads in proportion to their energy consumption, then small to medium enterprises would face an average new bill item of $1,550 per year, and large industrial loads $11,600.[2]

    Admittedly these are simplistic estimations, but in the absence of modelling from the ESB, it is as good a guide as any. And what it shows is the new costs that could face consumers are significant.

    An extra household capacity payment cost of $220 per year is 72% higher than the extra cost NSW households paid on their electricity bills from the carbon price. It is also 98% higher than what Victorian households faced from the carbon price, and 48% higher for Queensland households.

    Why is the ESB recommending consumers pay this additional fee to generators?

    Theoretically the additional cost consumers pay for capacity – just in case it might be needed – could be offset by reductions in electricity generation prices.

    This occurs in Western Australia, where capacity costs are offset by a market price cap for electricity generation set below $600/MWh.

    Despite the NEM wholesale electricity market spot price cap of $15,000/MWh being substantially higher than most electricity markets in the world, the ESB has not recommended a reduction.

    This means NEM retailers – and therefore consumers – will remain exposed to astronomically high energy prices during periods of short supply or generator market power, even though they’ve already paid these generators an extra capacity payment insuring against such shortages.

    The PRRO is unsupported, except by owners of coal plants

    The ESB’s Post 2025 Market Design Options suggests the PRRO is aimed at incentivising new dispatchable (“on demand”) generation to be installed in the NEM, to fill the energy supply gap left by ageing, exiting coal generators.

    Coal generators are increasingly uneconomic due to competition from low-cost renewables and are likely to exit sooner than expected.

    However, we don’t know which plants will exit, nor when.

    ESB Chair Kerry Schott predicts coal plants “will go broke” and close 4-5 years earlier than expected.

    Furthermore Schott has acknowledged there is a risk of unexpected outages of large coal generators which could reduce reliability, stating if we had a “major unexpected outage at a big coal plant [then] we’ve got a real resource adequacy issue right on top of us.”

    Reflecting this reality, the ESB appears to be trying to provide more investment certainty to encourage the entry of new dispatchable (“on demand”) capacity to replacing the exiting coal generators.

    However, the PRRO payment would apply to all electricity generators, not just new ones.

    Therefore, the PRRO will be propping up increasingly uneconomic coal generators, keeping them online well past their use-by date, and extending coal closure uncertainty even further into the future.

    Consequently, the energy industry still will not know how much replacement capacity needs to be built, where, and when, to fill the gaps left by exiting coal.

    Many key stakeholders do not believe the PRRO will incentivise investment in new capacity, with Origin Energy stating in the September consultation round that “decentralised capacity markets like the RRO are too indirect (with the obligation on retailers) and are unproven as a means of delivering timely new investment.”

    The ESB Chair acknowledged that “whether or not it actually works that way to bring new firm dispatchable into the system is arguable I think, because contract markets… goes out about three years at most.”

    Stakeholders also believe the PRRO is complex, unproven, lacking in transparency and costly to implement.

    The PRRO will not do the job it is meant to do.

    The only supportive stakeholders appear to be Delta Electricity and EnergyAustralia – owners of coal plants.

    What’s the alternative to the PRRO?

    As coal generators exit the system, we must ensure we have enough supply at all times.

    Mechanisms like the proposed operating reserve, or existing state government arrangements to incentivise new replacement capacity like NSW’s Electricity Infrastructure Roadmap, could be employed.

    Another option would be to build on the Market Liquidity Obligation – requiring owners of large generators to provide offers to the market to sell market hedges five to seven years into the future.

    This would then force them to be far more transparent about how much longer they think their power plant can reliably generate power, because if they can’t honour these contracts they face large financial penalties.

    Transparent coal closure schedules are necessary, making it clear how much replacement capacity is needed, in which locations, at which times. This could be done through mechanisms like those recommended by Professor Frank Jotzo or the Blueprint Institute.

    Rather than mandating consumers pay costly capacity payments to uneconomic outdated technologies, the focus should be on building instruments which attract investment in new low emissions generation capacity and install transmission capacity to support it.

    The Tesla battery that helped strengthen reliability cost $90 million but saved South Australian consumers over $150 million in its first two years of operation – a huge financial success.

    The PRRO could cost $3.2 billion a year, a recurring cost bourn by consumers.

    It will also keep coal generators online for longer.

    The coal exit uncertainty problem needs to be addressed directly, not tiptoed around.

    Consumers should not bear the cost of energy market confusion.

    Author: Johanna Bowyer, electricity analyst with Institute for Energy Economics and Financial Analysis (IEEFA)

    [1] This is AEMO’s forecast for 2023 P50 maximum demand (operational generation) in the ESOO2020 central scenario

    [2] Note no growth in customer numbers assumed. Customer numbers source AER

    Source: RenewEconomy