The world’s electricity business models are broken. What’s next?

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After decades of dull, regulated returns, the international electricity sector is in a state turmoil. Their business model is effectively broken – a series of dramatic “game changing” technologies has seen to that. And the pace of that change is expected to quicken. The growing use of energy storage and the dramatic changes in energy consumption will make sure of that. The question being posed is, what should go in its place?

In its recently published annual World Energy Outlook, the International Energy Agency highlighted the problem, saying that the market-based systems favoured in recent decades by most countries no longer served their purpose because they were being threatened by the impact of renewables and falling demand. It was so serious, the IEA said, that “the future adequacy of the power system may be at risk.”

It is has gotten to the point where fossil fuel generators in Europe – having railed against subsidies for renewable energy – are now calling for subsidies of their own. They know that their plants will still be needed in the transition to low-carbon grids because they can produce on demand, but they need a different model to justify and maintain those investments. Some of these are expressed in a form of “capacity market” – but the IEA and the European Commission are both resisting. The energy consulting firm Fortum says it will simply add “yet another subsidy layer that will further deteriorate the market functioning.”

Australia is not quite as far down the track as Europe, but it is already feeling the effects. And the tone of the submissions to the review into the Renewable Energy Target, and the threat of the break-down in the market by some generators, underlines their fears. Rather than seeking to find a solution, the response has been to simply try to stop the growth in renewables in its tracks. But that is simply not an option.

Australia, like many other countries, runs on a system that rewards and gives priority to the lowest-cost suppliers of energy. Historically, this has been the dirty brown coal generators in Victoria, followed by black coal generators. But even though they are low cost, their business models have been structured so that they rely –for the repayment of debt on overly inflated purchases, as much as profits – on windfall gains from peaking power generators.

The coal generators are good at providing “baseload” power, but useless when they need to respond to sudden jumps in demand, such as when people want to turn on their air conditioners on very hot days. So the system relies on fast response gas-fired turbines, which cost little to build but are very expensive to run. Some of these plants are not switched on until wholesale electricity prices reach $150/MWh or more. But when they are switched on, all generators receive that market price – even if it rises to $10,000/MWh. The generators rely on it so much that, according to the Energy White Paper, 30 per cent of the revenues from Australia’s generation fleet comes from just 30 hours a year. And that is then passed on to consumers, who pay an estimated 25 per cent of their bill to meet the “critical” peak that last just 40 hours a year.

Renewables such as wind and solar have a zero marginal cost of generation, so they got priority in the electricity “bidding stack”. But the problem is not so much that they are shunting the cheapest forms of fossil fuel generation a few rungs up the ladder, they are closing the door on the super-expensive peaking generators that are no longer required, removing much of the profit cream for the whole industry.

That is why in Australia – and elsewhere – it is not the dirtiest generators getting closed down or not being built, but those marginal plants who rely on peak rates to pay their interest bills. In Australia, the proliferation of rooftop solar PV and falling demand is adding to the stress on conventional supply. In the past year, some 3,000MW of fossil fuel generation has been closed or put on ice because of the impact of lower demand and renewables. Many projects have been put on hold.

So, if a market-based system can no longer operate because it is turned on its head by renewables, what should go in its place?

The “capacity” market is favoured by some because it provides a more consistent return to generators – but some get money simply for being there, not for doing anything. The extent to which this can be distorted is highlighted in this story: Western Australia has a capacity market but it has encouraged the construction of plants such as a 92MW diesel-fired peaking power station that may never get switched on. The state is now reviewing its rules.

The European Commission has been urging its members states such as Germany and the UK not to introduce capacity market, saying a broader integrated market would address such issues.

The IEA also expressed concern about the capacity market. It noted that they had been costly to implement and involved “heavy-handed regulatory intervention” that can favour specific technologies. Some analysts take that to mean it will lock in fossil fuels for longer than needed. “The way decisions on required capacity levels are reached can lack transparency. While some countries may adopt capacity mechanisms, other innovations in market design may offer ways to maintain adequate capacity in the presence of a high share of renewables.”

It seems certain that the solution will come from thinking differently about the energy system. Until now, it has been based exclusively on a baseload/peakload scenario, where large generators provide the bulk of energy, and a whole bunch of flexible generators are added to meet “peak demand.” But as we have seen in Australia, this has led to massive over-building of networks.

The new system dominated by renewables will be different. It will be characterised by inflexible generation – where energy is produced when the sun shines and/or the wind blows – and flexible sources, which can deliver the balance needed when required. This could come in the form of flexible fossil fuel generation, or storage, either through current sources such as hydro, or other forms of storage enabled by batteries or solar thermal, for instance. Even recently installed coal-fired generation in Germany is designed specifically to cater for flexible demand response and fill the gaps left by wind and solar.

The problem lies in the transition – in many markets, such as California, Denmark, Germany, and in South Australia, existing fleets of flexible generation has been sufficient. But as the rate of renewables continues to grow, what is the financial incentive for these to be built?

“The more flexible options will require higher initial investment,” says the Regulatory Assistance Project, a US-based think tank. “Yet there is now concern that current energy and capacity market designs will not provide the forward-looking information investors and suppliers will need to evaluate properly the trade-offs between higher initial cost and life cycle consumer benefits.”

The RAP says capacity markets can distort in the same way as energy markets. It suggests that future  operational needs are best revealed by forecasts of net demand (which is gross demand minus demand served by variable resources). This will help quantify the gaps and the requirements for flexible generation over investment timescales, which can then deliver least-cost reliability.  But it says there is no long-term market mechanisms for flexible resource capabilities.

It proposes something called a “capabilities market”, to ensure against the overbuilding of flexible generation. “Additional flexibility is not desirable at any cost, it is only desirable if the cost to obtain it is less than the cost of the alternative.” It offers two alternatives – things it calls “enhanced Services Market Mechanisms” and “Apportioned Forward Capacity Mechanisms”. Both seek to provide greater value to flexible generation, without the need for creating too much capacity, or inflate electricity costs. Both require highly sophisticated approaches to the market.

Here is an example.

“Envision a system with gross demand on a winter day ramping from 15,000 MW to 30,000 MW between 05:00 and 08:00. Add a large share of wind generation on the system, with wind production on the day ramping down to near zero in the morning. The ramp in net demand could be 2,000 MW to 30,000 MW during that same time period. This calls for much more and much steeper ramping capability than was previously needed.

“Now imagine the same system with gross demand on a summer day ramping from 10,000 MW at 05:00 to 40,000 MW at 18:00 and then ramping down over the rest of the day. Add a large share of PV generation, with PV ramping up from 07:00 but at a slower pace than the ramp in gross demand, peaking at 14:00 and then ramping down to zero by 19:00.

“Net demand would therefore peak once in mid-morning, subside dramatically during mid- day, then peak again in late afternoon/early evening. This creates a need for a significant share of the non-renewable resource portfolio being capable of starting up quickly, shutting down and starting up again within the space of only about nine hours. Operating a power system reliably and cost-effectively under these conditions is entirely feasible with commercially available supply- and demand-side resources, but it requires a different mix of such resources than in the past. Wholesale power markets will need to project and value these emerging investment needs more clearly than they do today.”

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  • Warwick

    How can international electricity markets have both “decades of dull, regulated returns” and “… the market-based systems favoured in recent decades by most countries no longer served their purpose because they were being threatened by the impact of renewables and falling demand.”?

    Also if the “closing the door on the super-expensive peaking generators that are no longer required” is happening, why do we still get prices in excess of $12,000/MWh such as we had in early July?

    Given peaking generators in the NEM often sell caps in lieu of capacity payments, why would we need a capacity market in eastern Australia?

    • Giles Parkinson

      I believe i said closing, not shut. Didn’t suggest that they were never used at this price, just not quite so often. As you well know Warwick, much of the electricity industry in Australia works off regulated returns, networks being one of them.

  • Benj

    Is there really any chance of a capabilities market developing here with a paltry 20% RET?

    Wouldn’t we be making live easier by biting the bullet and setting a much more ambitious target?

    • Giles Parkinson

      Agree we need more ambitious target. The RAP suggests the tipping point begins around 15 per cent penetration. I should provide a link, because they explain this much better than i ever could. Go to and look for link to “beyond capacity markets” report.

  • I wonder how much of that demand-ramp modelling takes into account additional demand peaks generated by the transition to EV based vehicle fleets? It’s one of the areas of investigation being undertaken within the Hunter area as part of their SmartGrid-SmartCity project, exploring energy-demand modelling based on different EV utilisation patterns (see

  • J

    Electricity markets in Australia have always been ‘failed markets’. Adding a layer of private retailers and generators did nothing to change this except privatise monopoly rents in the name of efficient ‘free’ markets.

    It is clear that our electricity market will transition to a tense mix of re-nationalised generation and infrastructure providers with private distributed generators/storage plants (read PV, wind etc) that will range from large-scale to micro-scale.

    The opportunity to take your business or home off grid is not too far away and this will accelerate the need to re-nationalise to get through the transition.

    Ultimately self-sufficiency is where we are headed and it will be hard for anyone but a government to maintain underutilised infrastructure during this change.

  • CZ

    Solar PV, energy efficiency and the impacts of the GFC have all contributed to reduced demand – definitely agree with that. The RET has also had a dampening effects on wholesale prices. All of these factors have probably weakened the case for investment in fossil fuel generation, both peaking and baseload, at least in the short to medium term.

    However, are you suggesting that this effect will necessarily last? If so, I’d have to disagree.

    Assume that demand remains low, prices are low and therefore investment signals under the energy only, gross market remains weak. Also assume that summer weather patterns return to what we saw through most of the 2000’s, with higer average temperatures, drought etc (which is consistent with climte change). Despite the effect of solar PV, EE, etc, there is also large scale penetration of air conditioning units, so high temperatures result in massive demand spikes.

    However as there has been a shortfall in investmet (due to the lower demand and prices we are currently experiencing), the demand suppply balance becomes increasingly tight again and…voila, a return to more super peak price periods and a sharp increase in the average wholesale price. Which would in turn incentivise investment in peaking units, at least in the MR.

    So the existing mechanisms may not actually be broken. However, there is a lot of potential pain out there to be had by those parties who haven’t adequately managed their exposure to a spot price which is increasingly volatile due to earlier weakening of investment signals.

    • CZ

      sorry, meant to say


      However, also assume that after some period of this low demand/price scenario, summer weather patterns return to what we saw through most of the 2000′s, with higer average temperatures, drought etc (which is consistent with climte change). Despite the effect of solar PV, EE, etc, there is also large scale penetration of air conditioning units, so high temperatures result in massive demand spikes.

  • Giles,

    As you know, I am an occasional reader of what you write, and that which a few others write, on RenewEconomy.

    It seems to me that most of the debate (in the comments) on this site, and other sites, arises because of differing priorities through which different people view the choices confronting the energy supply industry. These might be consciously formed, or subconsciously held.

    My sense is that the Electricity Supply Industry (on average) has traditionally viewed its priorities as follows:
    Priority 1 = The lights must stay on
    Priority 2 = So long as it does not impact on the above, the costs of energy supply should be stable, and as low as possible
    Priority 3 = Within the bounds of the above, carbon emissions should be low.
    Priority 4 = Renewable generation would be nice to have, where it can fit with the criteria above.

    My sense, from reading what you have written, is that you have a different ordering of priorities, putting increased renewable penetration at the top of the list in something like this order:
    Priority 1 = We need to keep increasing the penetration of renewable generation
    Priority 2 = Emissions will fall as a result of increased penetration of renewables, hence probably does not need as much of its own explicit focus
    Priority 3 = If it needs to happen, then the infrastructure supporting the ESI (and the market supporting the use of this infrastructure) needs to change to ensure that the lights stay on whilst the renewable penetration is increasing.
    Priority 4 = As much as possible within the bounds of the above, the cost of supply should be low.

    If I look at the second priority ordering (above) I can certainly understand why you write what you do.

    If I look at the first priority ordering (above), I can also understand why some changes underway – like the debate about whether 20% is really 25% – are seriously concerning for others (and not just from the perspective of “my business is threatened”.

    Am I missing something, or is much of the debate akin to people shouting at each other when each is seeing part of the elephant, but none is seeing the whole?


    Full Disclosure:
    Our company will work within whatever market structure exists at a time and, through the provision of information that helps to make complex data more understandable, strive to make that market operate as efficiently as possible. As such, we supply our products to a wide range of clients including:
    1) generators, no matter what colour (black, brown, green and blue); and
    2) fuel suppliers, no matter what the source.

    • Giles Parkinson

      I think that is a fair summation. My take is that we need to do this stuff because the science says it needs to be done, and not only is it possible, but it can be probably be done at little extra cost to business as usual, and certainly cheaper than dealing with those consequences. We just got to get our heads around changing markets, and models, which is the point i was trying to make here. The RAP is a very sensible solution that finds a middle road for the two sides shouting at each other (though i would say that one side is shouting louder and more often because they have more to lose, and ample outlets in the mainstream and reactionary media).

      • Thanks Giles

        Knowing this makes it easier to read comments in context.



    • Benj

      And different views on cost. Too often price is confused with cost. With so many externalities, the actual cost of energy is not reflected in the price. The price is whatever the regulators set it at, irrespective of actual cost.

      My priorities:

      Priority 1 = There is a global yearly CO2-emissions budget. The individual budget seems to be 2.7 tonnes. It is my responsibility to stay within that budget.

      Priority 2 = I haven’t yet found a way to calculate the overall CO2 emissions that I’m responsible for. So for now I wil concentrate on direct energy use emissions. My goal is to bring these direct emissions down to zero, leaving some allowance for the unknown indirect emissions.

      Priority 3 = To achieve this goal, I employ energy efficiency first and renewables second.

      Priority 4 = Everyone should be able to afford a minimally required amount of energy and stay within their CO2 budget. At the moment, many in the lower income groups encounter energy hardship while still relying on dirty energy. Governments will have to create the conditions and spend the money to alleviate this situation.

  • PS Giles,

    The challenge you allude to above can, I believe, be summed up as follows:

    On the assumption that the penetration of renewables is going to increase significantly (leaving aside questions about whether it should, and at what cost) then the Electricity Supply Industry is faced with significant challenge – which, I believe, stem from two main related factors:

    1) Lower capacity factors for energy supply.
    With wind (30-40% CF) and solar PV (20-30% CF) being the two most talked about, this means that there will need to be a 3-4 times greater installation of capacity for the same energy output than would have traditionally been the case. This has cost implications not only for the installed capacity itself, but also in terms of how the capacity connects into the energy supply infrastructure such as:
    (a) Transmission, the case of remote wind (e.g. Hydro’s proposed King Island wind farm); and
    (b) Distribution enhancements (including metering) for embedded PV, fuel cells or other technology.

    2) Increased uncertainty of output.
    With the increased uncertainty comes increased cost, in terms of the provision of reserves required to keep the lights on under credible contingency events (which would start to include sudden cessation of wind, or cloud cover), and also in the development of smarter technology to help the market operators forecast an envelope of probability.

    One of the approaches that has the potential to help mitigate the effects (and cost) of this increased uncertainty is Demand Side Response. There are a couple different permutations of this operational in the NEM already, to some extent:

    1) The outsourced model
    A couple weeks Tim Buckley posted this article ( ) speaking about the success our clients EnerNOC had had in the DS. There are other similar operators in markets overseas that have not found their way into the Australian market (yet?)

    2) The retailer model
    Retailers have traditionally operated their own DSR resource, where there might be something like a 50:50 benefit sharing with the energy user providing the response – however there is anecdotal evidence to suggest that some retailers (those long on peaking generation) might not call their DSR as often as the energy users might want to be called.
    In more recent times we have seen ERM heavily promoting their DSR capabilities (such as here ) and we know of a couple other smaller start-up retailers working to establish business models that heavily utilise DSR in various forms.

    3) The self-managed model
    For those energy users who can do it (we’ve found it’s not as hard as they might first think), there is also the option for them to manage the DSR themselves. To give some indication of the scale of what’s possible, we have a significant number of clients (whose peak demands somewhere between 1000MW and 2000MW) that operate in this way.
    Here’s a synopsis of what the benefits might be:

    4) The distributor model
    There have been trials (e.g. Essential Energy, SA Power Networks and others) where distributors have used technology to do a variety of things – like cycle air-conditioning compressors.
    I don’t know of any distributors that are using approaches like these on an ongoing basis. Maybe one of your other readers does?


    Renewables “threatened” established sources when governments, driven by citizens or politics, heavily subsidized renewables with their citizens’ tax dollars. Many countries’ governments have pulled back from THAT position because it was way more expensive than letting the “conventional sources” continue to serve the markets.

    I believe that recent and ongoing developments in energy storage (battery technologies), photovoltaic collector efficiencies and maybe even distributed thorium reactors will pave the way for the future, but with the massive new discoveries of oil and natural gas reserves, to think that those sources won’t power our way into the future for scores of years at least is, I believe irrational.

    • suthnsun

      We won’t have scores of years to use any ‘massive new discoveries’ alan, if we try to use them the damage to the global economy will be far higher than the additional cost of renewables. The situation is even worse than the headlines. Also the net energy return from these ‘massive new discoveries’ is very small, renewables will be far better in that regard on any timescale except the very short term.

  • Arjan

    It seems to me the owners need high returns because they paid too much for the assets when they bought them. Happens all the time. Caveat Emptor. What should happen now is they will go broke, and the assets will be sold to a new operator for a fraction of the book value. The new operator will run them profitably in the new cost environment. The lights stay on.
    Renewables continue to disrupt the market, and eventually we can retire these assets from the system when the renewables have sufficient market share, distributed energy production becomes the norm and storage delivers on all its promise. Its actually not a bad scenario for all of us collectively, and exposes the current owners to the downside of their risk assessment re their original purchase. They are grown ups and they should have seen this possibility and judged the risk/return accordingly. Its actually a necessary step to decarbonisation of the energy supply and the sooner, the better.

  • CZ

    Another issue which is not dealt with in terms of the transition to renewables is are the likely increases in the cost of maintaining system stability.

    At the moment, reactive power and inertia are provided, largely at very low cost, by big fossil fuel generators with large “spinning mass” turbines. Similarly, large volumes of surplus flexible capacity with the ability to ramp up and down can provide frequency, voltage and stability control, which allows the system to respond to disturbances.

    As far as I am aware, wind turbines, solar PV and solar CST have a reduced ability to provide these services. It follows that as we transition towards more and more of these types of renewables in the mix, the remaining providers of these services (fossil fuel generators) will have greater market power, increasing the cost of these services.

    Anyway, something to think about, which often gets overlooked in the general enthusiasm for 100% renewables.

  • Dave Smith


    It is hard to see how the Australian NEM is broken or even stressed. Yes, increased supply (from renewables) and falling demand growth are reducing wholesale prices and putting pressure on older, higher-cost generation which may be forced to close. But that is how the market (indeed, any market) is supposed to operate. If this WASN’T happening then THAT would suggest market failure.

    If peaking generation is being required less often, that suggests that supply reliability is improving not worsening. So, again, the market seems to be working fine.

    As Paul McArdle notes, the biggest risk of future market failure is the lack of demand side response. That needs to be fixed. But changes on the supply-side – such as a “capacity market” – are unnecessary and more likely to cause market failure than prevent it.

    • Warwick

      Dave, Spot on, good to see a voice of reason. Too many people look at spot prices and read them like tea leaves as a guide to the future rather than examining them in the context of contract prices for electricity to understand what is really happening. The conventional fossil fuelled generators have withdrawn capacity and prices have gone up. This has happened in the NEM a number of times before.

      Increased intermittent renewables will at times make spot prices lower than they might otherwise be but invariably we’ll get additional volatility. (It looks like it might happen later today in SA with predispatch above $3,000/MWh). This simply reflects lower utilisation by fossil fuelled generators that will attempt to maximise spot prices at high net demand times to recover revenues through spot and higher contract prices. Again, sounds like the market is working.

      Anyone who seriously argues that the NEM needs a capacity market must not appreciate that generators contract and receive payments when prices are low regardless of whether or not they actually generate. Also, changing to a capacity + energy market like WA requires a not insignificant burden on retailers to establish their contribution to the 12 or so maxima per year as well as penalising/rewarding generators for their performance in meeting their contracted capacity.

        • Warwick

          Hopefully it will lead people to understand that the so called “merit-order” effect is only transient and perhaps they might take the time to examine the contract market as well. It still staggers me that so many analyse the market by spot prices alone and conveniently ignore contracts, never mind that Australian electricity futures had a face value turnover of $20bn last year.

        • Looking at the AEMO demand and price graph it seems nothing too unusual happened in South Australia. Prices shot up for a while in the afternoon while demand was actually dropping, but that’s perfectly normal as various generators perform their juggling act. What is interesting about South Australia is the wholesale price was zero cents for hours in the early morning and averaged about a cent or less for the majority of the day time. This is due to South Australia haveing the most wind and solar capacity. If it’s not too hot but sunny, over 15% of our total electricity use can come from solar in the middle of the day. As a result of wind and solar pushing electricity prices down I’m getting an 8.1% cut in what I pay per kilowatt-hour for grid electricity on the first of January.

  • Can anyone explain what bad thing might happen to Australians if we don’t pay for capacity? Because I really don’t understand the problem at all. The NEM is currently chock full of fossil fuel capacity that will continue to produce electricity as long as the price is above its marginal cost. And for coal that marginal cost is about two and a half cents which is less than half the average wholesale price. Are we expecting the wholesale price of electricity drop by more than half anytime soon? What could cause that to happen? Point of use solar plus cheap energy storage?

    • Warwick

      Yes, peaking plant shut down or retire because they can’t cover their fixed costs each year. i.e. they need to make enough gross profit from spot and contract revenues in excess of fuel, maintenance etc to cover their capital costs. Don’t worry just yet as although the NEM does not have a capacity market, these generators sell financial contracts in lieu of receiving capacity payments. Events like last week’s hot weather caused prices to go into the thousands of dollars per MWh which keeps up the price of cap contracts that are usually sold by peakers.

      • Thanks for the reply. Assuming all else to be equal, wouldn’t only one peaking plant shut down as that would increase profits for the remaining peak capacity? I was going to suggest that it would be simpler to increase the cap instead, but then I realised that would increase the incentive for generators to withold supply to jack up prices, so maybe paying for capacity would be better if we had a situation where we were actually running low on peak capacity.

        • Warwick

          It’s not certain how many peaking plant will choose to shut down, if any. It’s not unlike a baseload generator choosing to stay on rather than shut down to avoid restart costs but the timescale may be on years rather than hours. Eventually, demand will again go up with increasing population and increasing levels of intermittent renewable generation will increase volatility, which suits peaking plants. What few usually understand is that even peaking generators such as gas turbines and hydro power stations don’t necessarily make their money through the price spikes rather that these spikes encourage market participants to buy caps. What’s most important is whether the cap cost per MWh is sufficient to cover the annual fixed costs, then you’re not concerned how often the price spikes above the $300/MWh level as you usually can produce electricity well below that level. If you want to look at market prices see the dcyphatrade page (

          • Given that retail electricity prices are currently quite high in Australia and Germany is now installing solar PV for about $2 a watt, I suspect that we’ll see increasing amounts of solar installed which will push down daytime electricity prices and I imagine pretty much eliminate critical peaks while the sun is up. If this happens then Australia’s existing pumped storage capacity could focus on meeting evening demand, as it would generally no longer be needed during the day, and so reduce the need for peak plant capacity. Also, if it becomes economical to build new storage capacity of whatever sort, then that would presumably also reduce our need for peak generating capacity. So while I could be overlooking something, I think there’s a good chance our existing peak plants might be all we need for quite some time.

  • The solution needed here is to follow the internet model of cloud computing.
    In the energy sphere, deeper interconnection between regional and national markets coupled with an ‘open-access, common carrier’ transmission network (example: Australia’s National Broadband Network’) can enable both flexible matching of aggregate supply and demand from spare capacity in the system (like Akamai does on the web), but also provide better price signals for aggregate long-term capacity investment.
    The logical end result of all this thinking is a Pan-Asian Energy Infrastructure of bundled fiber optic cables, natural gas pipelines and HVDC that can enable ‘fuel switching’ across a market of 2 billion people stretching from Australia, through ASEAN and up to China, Japan and South Korea.
    See and