This is the third in a series of three posts on what I see as the most important issues for the electricity market for the 2020s and beyond.  The first issue was woeful lack of disclosure in the gas market, and the second issue was the ineffectiveness of the electricity hedge market.  This third and final issue is on the challenge of moving toward extremely high levels of renewables in our electricity supply.

By Greg Sise, 18 July 2019

I’ve held off posting on this topic because of our involvement in the work undertaken by the Interim Climate Change Committee (ICCC) on the Labour-Green target of “100% renewables in a normal hydrological year by 2035”.  But the ICCC’s two reports, one on Accelerated Electrification and one on Action on Agricultural Emissions, were released this week, so I now feel free to cover this issue.  For avoidance of doubt, nothing in the following is intended to be at odds with the recommendations in the ICCC’s electricity report – they make lots of sense.

This post is informed by work that we started in 2016 in our “High Renewables” project, by work undertaken subsequently in modelling well beyond 2035, and by the work undertaken with the ICCC.

Our High Renewables project aimed to answer questions such as:  will the energy-only market survive intact in the long run if and when renewables exceed 90% of annual generation?  Can the market support renewables at close to 100%?  If so, when might this happen and what would be the impact on prices? Do we need some form of capacity market to ensure that thermal peaking capacity can be kept available?

One thing we do know, is that moving to “extreme renewables”, by which I mean moving beyond 97% toward 100%, and particularly the last 1%, will be a tremendous challenge.  It is an open question as to when this might happen, and we must await the announcement of government policy before we will know for sure about the Labour-Green target, but it will happen eventually.

Now, it is possible that there will be some ‘silver bullet’ that will make the challenges go away, but based on current knowledge and trends, getting rid of all thermal plant will be very difficult to achieve in a way that is both technically and economically feasible.

So what have we discovered so far?

Firstly, there is a question about the viability of the spot the market in its current form.  As I have posted before, the price of wholesale gas used for thermal generation is a key driver of electricity prices (see The three most important issues for the 2020s - #1, Gas Disclosure for a simplified explanation).  Renewable generation, wind, solar and geothermal, for example, tend to offer into the spot market at very low prices, so as the penetration of renewables approaches 100% the gas-fired peaking plant that remains, which spends less and less time running, must offer to generate at higher and higher prices to cover costs.  Higher offers also help to support prices on average so that all generators might earn enough to keep them in the market. 

But, the influence of gas-fired peakers’ on the offers of large hydro generators (see link above) falls off rapidly and eventually, at 100%, the large hydros have no thermal price to “shadow”.

So how would prices be set dynamically in the competitive spot market?  It can be argued that the large hydro generators between them have enough market power (influence over prices) to offer competitive prices that support the market as a whole, but how would this be achieved without the benchmark set by thermal generators?  Suppose one large hydro generator decided to undercut the others to gain market share:  the others would have to follow or risk sub-optimal use of their storage and perverse outcomes.

Or maybe generators will all be well hedged at prices that allow them to stay in business?  That might work for a while, but if spot prices are much lower than hedge prices for a prolonged period, which could be years, spot purchasers will simply not hedge, and they will instead take the risk on the spot market.  So much for being well hedged.

It may be that the prices for non-supply, known as “scarcity prices”, currently set under the Electricity Code at between $10,000/MWh and $20,000/MWh ($10 – $20 per kWh) could be the proxy for thermal generation, and these prices could be raised if required.  But there are doubts, for technical reasons, as to whether the large hydro generators would use these as their shadow prices when calculating the prices they offer into the market. 

Furthermore, if scarcity prices are to have real influence on the market, then the threat of them actually setting spot prices needs to be real, and when that happens, consumers and politicians will have something to say if it happens too often!

Changes to the way the electricity market operates may be required, perhaps including some form of payment for providing generating capacity regardless of how much it is used (known as a capacity market), or additional market services which would pay battery owners and consumers to make reductions in demand during periods of shortage.  Capacity markets are in operation overseas, but they have their own problems.

Secondly, the market needs to deliver sufficient capacity to back-up hydro generation during prolonged dry periods, and also to meet peak demand on winter mornings and evenings.  Geothermal helps in both cases by providing a constant baseload output of generation.  Solar can do the former but not the latter because it is mostly dark during the winter peaks. 

Wind appears to be the cheapest, proven way to support hydro during dry periods, but only if the market builds more wind farm capacity than is needed on average, i.e. as thermal generation falls, over-build wind to make up the difference during dry periods.  But the evidence so far is that wind cannot reliably make up the difference during winter morning and evening demand peaks because there are a significant number of peak periods when it is relatively calm across the country, resulting in a shortfall if wind is the only remaining option.

Having to over-build windfarms (or solar, for that matter) also leads to the inevitable conclusion that prices would need to rise significantly to support the over-build.

Batteries will have an increasing role to play.  Grid-scale batteries have come a long way in terms of cost per kWh of storage, but they are still relatively expensive to deploy directly into the energy market and currently need additional revenue or value streams to make them economic.  Even optimistic assumptions about falling battery costs mean that simply adding batteries to cover peak periods would also require prices to rise significantly to support the scale of investment that would be required.

There is much work being done around the world on the “smart grid” and how consumers can become more flexible and more responsive to price signals.  For the most part, this has only been for that small proportion of consumers that have high electricity costs and that are also motivated to invest in becoming more responsive.  The rest of us should just be able to turn on the lights, or whatever, whenever, and be assured of supply.

But I am reluctantly coming around to the view that demand response on a larger scale will be required, albeit done automatically based on a combination of technology systems and pricing signals working together to produce good outcomes for consumers.  The rise of EVs and the growing use of home batteries could be the enablers that make this work.

Other options are possible including pumped storage and hydrogen-based generation, for example, and ultimately we might have nuclear fusion or some cost-effective way of permanently capturing emissions from gas-fired generators.  But currently these technologies are either too expensive, or have too many unknowns, to place firm bets on.

These are big challenges and intellectually very stimulating, although I do find that if I think about them for more than a couple of hours at a time my head hurts!  But one thing is for sure, despite the incredible energy density and flexibility of fossil fuels, the world must transition away from their use.  For what it’s worth, my view is that ingenuity, technology and investment got us into this, and ingenuity, technology and investment must get us out.

So now I have laid out my three big issues for the 2020s, and well beyond in the case of this post.  Having been in and around the electricity market now for almost 30 years I could be getting bored.  But that is far from the case – the challenges on the horizon are large and important so boredom is the least of my worries!