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

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.”