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Ronan, much of your expertise lies in the history of energy markets in the UK and Europe. You've recently published an article on the subject and authored a book on the origins of electricity market liberalisation in Europe. In what ways is the current transition towards net zero similar to the market transformations of the 1970s and the 1980s, and what inspired your work in the field?

It’s similar in the sense that it’s a fundamental rethink of how society organises electricity systems.  But how we do that – what types of institutions we use and what the role of markets and governments is – that’s different. I originally got interested in this topic through reading about the history of electricity systems, especially Thomas Hughes, a famous historian who wrote a book called Networks of Power. What I liked about him was the way he looked at the energy system as a whole: how it was created, and how it developed and expanded over time. Thanks to Thomas Hughes, we have a very good historical narrative of how electricity systems were initially developed by people like Thomas Edison in the 1870s and 1880s. These were small-scale, local systems. But over the next decades – and particularly in the interwar period – they became large, centralised systems spanning regions, nations and even reaching across borders. I was inspired by Hughes’s book and the field of Large Technological Systems, which followed his work. A fundamental question in this field is how to organise these systems so that technological innovations – such as electricity generation or transmission technologies – benefit society and enable end use. This and similar questions are about technical systems but are fundamentally social and political. So, I was keen to build on the work done by people like Thomas Hughes about the early history and expansion of these systems, and to examine a later period, from the 1980s to the mid-1990s, when electricity systems underwent another fundamental reorganisation. This time, it was based around principles of competition and saw the introduction of new types of market mechanisms and regulatory structures.

At the time, privatisation and increasing competition were among the main issues, and the roles of governments and markets transformed. Many countries are now considering re-nationalising the industries they privatised back then. France, relatively recently, nationalised its major energy company, EDF, and Scandinavian countries also remain heavily state-owned. In your recent paper, you contrast Britain's liberalised model from the late 20th century with the broader European experience. Do you think decisions about how and whether net zero is achieved will ultimately be political and societal rather than market-led?

I think there is a rebalancing happening, with a greater role and more direct influence of the state. During the liberalisation period, it wasn’t that the state was uninvolved or had washed its hands of the electricity system. Rather, it changed its role and relationship vis-à-vis private and market actors. The markets were initially underpinned by very strong legislation and regulatory frameworks, which hadn’t existed during the period of public or state control. So, in some ways, it was just a reconfiguration of what the state does, enabled because these energy systems were already in place. It made sense that states then used their market powers to make the systems efficient. Right now, we’re going back in history – to a system building phase involving expansion, reinvestment, large capital programmes, and growth inelectricity demand and investment between generation and networks. That wasn’t the case in the 1990s, when electricity demand was quite static and predictable. Now, electricity use is expected to expand quite dramatically. The key question is: how do you make big, coordinated investments in these complex systems amid uncertainty? Markets are not going manage this on their own. You need a guiding hand from the state, which will act differently in different places. In some places, the state may take a direct role, with public-sector electricity companies making the investments themselves – like in France. Elsewhere, there could be a new relationship between the state and private market actors, where risks are shared between the public and the private.

‘In the fossil fuel model, it was about linking markets together, having forward trading, and thinking in commodity market terms. But in the current world, we need to think decades ahead and figure out how to spread those costs and risks over a long period of time.’

What does “risk” mean in this context? And who is most likely to bear it on the road to net zero? Will it be consumers through higher prices, or will risk be distributed elsewhere?

There’s been a qualitative change in how we think about risk and electricity systems around low carbon and net zero. In the largely thermal-based systems, most of the risk was linked to the cost of fuel inputs, which accounted for the majority of costs. In countries like the UK and much of Western Europe, which had become increasingly reliant on energy imports and global commodity markets, the main risks lay in the fuel costs and the operation of the electricity system. The markets were then designed to manage that risk. Because the countries dealt with commodity price risks for natural gas and coal, they structured their electricity systems similarly to commodity markets. There was a natural synergy in managing risks: when the cost of fuel input went up, so did the cost of electricity. Low-carbon systems are different. It’s now about upfront investment, and that’s where most of the risk is. Once you’ve made the investment, the costs are much lower. So the question moves from how to manage and allocate risk around fossil fuel price volatility, to how to manage and allocate the risk of big upfront investments.  And that links to your previous question. In the fossil fuel model, it was about linking markets together, having forward trading, and thinking in commodity market terms. But in the current world, we need to think decades ahead and figure out how to spread those costs and risks over a long period of time.

Speaking about decades ahead, the plan is to reach net zero. The UK’s emissions from electricity generation have dropped by over 20% in the last three decades. Other areas of energy use, such as heating, remain quite emissions-heavy. You’ve co-authored an article on seasonal thermal storage, which remains marginal here – unlike in countries like Denmark and Sweden. Why is that the case and what is the role of heat pumps and similar technologies in the wider energy transition?

When we look at the energy transition, there are three main challenges. We’ve already talked about the first one: capital expenditure and big upfront investments. The aim is to keep the cost of capital as low as possible, which involves managing risk through state and market governance.  The second challenge is coordinating the development of the system networks in line with the expansion of low-carbon sources. The specifics vary depending on whether you’re in Scotland, the North Sea, or in sunnier areas or more remote regions where the grid wasn’t historically in place. You also need to consider the distribution of demand. Then the third big challenge, which is especially important in places like Northern Europe, is the seasonal question. The system needs to be able to cope with the winter period – when it’s cold, dark, and there’s not much wind. This kind of seasonal flexibility is currently provided mostly through gas. There are alternatives. Pumped hydro, for example, provides a huge amount of non-fossil-fuel-based flexibility in electricity systems around the world. Finding new locations for pumped hydro stations should be the main priority – and that’s something that could happen in Scotland. Green molecules like hydrogen are another solution. Storing hydrogen underground, in the way we currently store gas, could be part of the answer. Then there are also solutions like interconnectors that span different time zones and weather systems, as well as demand-side flexibility. And finally, there’s also the option to store heat underground, using various mediums. The reason that hasn’t happened in the UK is because there hasn’t been a strong need. Heat storage is widespread in parts of continental Europe – like Denmark and the Netherlands – because they have district heating systems and local heat supply. The geology in those areas is favourable, and they’ve pursued that path. But here, there simply hasn’t been a need for it.

Ronan, your background – alongside science and technology studies – is in mechanical engineering and STEM. How does that help you assess the different technological solutions and how they fit into the wider system?

A lot of colleagues working in my area often have an engineering or STEM background. When you’re doing this kind of work, you have to get into the detailed technical aspects – not only of the technologies themselves but also of the markets, which have a technical core, especially when it comes to balancing the system. These are quite technical constructs, but they also have an economic aspect. When you study the role of regulators – how they oversee markets and deal with the monopoly aspects of networks – you combine the economic, technical and political. A conventional social scientist might strip out the technical and focus just on the political and economic dimensions. But things are configured around the technical features of the systems and the markets. Traditional social science thinking might not fully capture what’s happening.

‘It’s the most critical system we have, it has to be balanced in real time, second by second. It's also a system that’s transitioning. The energy transition happening now is, I think, the most consequential global industrial transformation in history.’

What drew you to energy as a field? Were you interested in it since the start of your studies?

I quite like the systemic character of it. It’s the most critical system we have – it has to be balanced in real time, second by second. It’s also a system that’s transitioning. The energy transition happening now is, I think, the most consequential global industrial transformation in history. So, you know, it’s just important. The systemic character of electricity supply has a social element, too – it’s something we use every day. Government decisions about regulation and investment decisions are filtered through the system and impact everyone. That natural interconnectedness between the social and the technical is what drew me to it.

Let’s turn to the specifics of the current situation. Many of the topics we’ve discussed reflect the importance of political decisions and negotiated outcomes in shaping energy transitions. One such process is the ongoing REMA reform of the electricity markets. Could you outline the main design decisions or policy questions currently at stake?  

The cost of capital is an absolutely essential outcome of any market reform and regulatory structure, and it’s a huge driver of REMA. The cost of achieving net zero is extremely sensitive to the cost of capital. You need to find a fair and reasonable balance of risk between investors and consumers – one that also pushes down the cost of capital. People often discuss contracts for difference as a way to achieve this balance, including how risk can be spread over time. This isn’t a one-off issue that REMA will solve; it’s something that needs to evolve and adapt progressively. Another key aspect of REMA concerns capacity mechanisms – how do we ensure that we keep the lights on? Part of the REMA discussions focus on updating the existing capacity mechanism to bring in more diversity in flexible sources. This is important both in the balancing timeframe and for addressing seasonal challenges, though the seasonal flexibility issue itself isn’t really part of REMA. Finally, there’s the very contentious question of locational pricing, even if it might not be the most important one. How do we manage a system and the network to get the most out of our expanding low-carbon, renewables-based system?

We are expecting a decision on whether locational pricing will be introduced or  whether the current national wholesale market will prevail in a reformed shape. How did the debate on a national versus zonal market become so polarised?

Generally speaking, it’s a natural consequence of expanding the renewables capacity and the fact that the high load factors for wind and offshore wind are in remote, windy places where the grid hasn’t been historically developed. So, this problem was always going to arise in some way. To a large extent, I think the government and the regulator had their heads in the sand about it. Around 10 or 15 years ago, they were projecting that curtailment and congestion costs on the grid wouldn’t be significant. I think they got that wrong. It’s a major issue, largely driven by the unexpectedly rapid expansion of offshore wind as an industry. This problem isn’t unique to the UK – it’s also present in Germany and other places. There are competing perspectives on how to address it. One perspective is that this is primarily a system issue and that the fundamental problem is a lack of transmission capacity. The solution, then, is to build out the transmission grid and smooth prices across the British market. The competing solution is a market-based approach, which acknowledges that you can’t ignore that capacity on the transmission grid is a scarce resource – you can’t just hide that scarcity under the carpet. It needs to be made transparent and reflected in the market prices, so generators and market players know the full cost of putting power onto the system at any given time. For wind plant, the critical factor is not just whether it’s windy, but whether there’s capacity to absorb that power. That's broadly the locational pricing, market-type solution.

Currently, we have a nationally set price of electricity from generators. When did that come about, and wasn’t the lack of transmission capacity between Scotland and the rest of the UK a problem back then?

Scotland used to have a separate system, while England and Wales operated a unified one. England and Wales had an electricity pool, in which Scottish generators sold electricity almost like foreign exporters. In 2005, BETTA – the British Electricity Trading and Transmission Arrangements – created a unified system and introduced a national market with a single national price was introduced. This was a reasonable move because the technology was settled, the system configuration was stable, and the supply and transmission network was a known entity. Although there were some ideas about locational pricing, given the lack of transmission capacity between Scotland and England, it wasn’t seen as a major issue or challenge that couldn’t be managed. Instead, they introduced what’s called the balancing mechanism, which provided flexibility to adjust market players’ positions to ensure the system stayed within technical parameters. So, while locational pricing wasn’t a priority, they did introduce a residual backstop to prevent overloading the system.

‘If the decision is zonal pricing, it could have big impacts on the prices for consumers and potentially on future investment in the Scottish sector. So, the Scottish government and others need to have an informed view and develop a position.’

You recently co-organised the First Scottish Forum on Future Electricity Markets, where public and private stakeholders came together to discuss the REMA reform and its specific implications for Scotland. What motivated you to organise the event? And did the discussions reveal anything new or particularly specific to Scotland?

The idea came from conversations about the REMA process with my colleagues Chris and Lars, and with Andrew from the School of Engineering. One issue that kept coming up was the complexity and difficulty of making sense of the evidence base. There’s obviously a lot at stake for different market players, whether they support locational pricing or oppose it. Many studies funded by proponents on both sides have been published – often by management consultants – and they often conflict each other. There’s no definitive, central study that people in the Scottish government or elsewhere can look at. So, we thought there was a good case for convening something that helps policy and other stakeholders start to grapple with this question in an environment that’s not so heated or biased, but which adheres to some fundamental academic principles of independent research and critically examines the evidence base. Electricity markets are a reserved matter under UK government powers. But obviously, the decisions have very important implications for Scotland with its build-out of renewables andits low-carbon economy. There’s also a good understanding of the topic here. If the decision is zonal pricing, it could have big impacts on the prices for consumers and potentially on future investment in the Scottish sector. So, the Scottish government and others need to have an informed view and develop a position.

So, do you think the price for consumers would likely reduce while the investments might also decrease because of the lower price of energy?

Yeah, well, going back to some of those high-level challenges I mentioned – getting capital investment in and managing system complexity – there’s a trade-off between the two. It’s not an straightforward policy decision, and that’s why it’s so contentious.

At the forum, we heard from speakers representing energy systems in the US, Germany and Norway. Why were these country examples relevant for the UK, and what can we learn from them?

Norway is relevant because they’ve had a zonal pricing system and different configurations since they introduced their market in 1991. Even before market trading was introduced, they had different hydro operators across regions trading with each other – partly due to geographical factors – which resembled a zonal market. The energy crisis in Europe made prices in Norway very volatile, particularly in the southern zones, which are more closely tied to the European market. That volatility, and how it's been passed through to consumers, created a big political storm in Norway. The debate in Germany, which was another example, is similar to that in Britain, as Germany is tackling a similar north-south grid congestion issue. And they are also debating how best to deal with it. Can you manage it through something called re-dispatch – by adjusting the market positions after they've been taken? This is a management strategy, but it’s expensive. Or do you wait for your transmission grid to be built out? There are also issues of fairness being raised, mainly by people from the south. Finally, the US has had some experience with zonal pricing in California and within the PJM market on the East Coast, but it wasn’t well implemented or designed. So, they dropped it and reverted to a different type of system, which is called nodal pricing, a more extreme form of locational pricing where every point on the network has its own individual price. The market is also much more centrally managed. The US model was considered in the  REMA process, but they thought it was too radical. Still, I think something that hasn’t been looked at in enough detail is the US experience with zonal pricing.

Recently, you published a report from the December forum, and, if I’m correct, there might be a follow-up event soon. What are your next plans for the discussions around electricity markets in Scotland, and what topics or questions do you think need to be addressed next? And what are you personally working on?

Yeah, I think we'd like to continue with that same philosophy of bringing in an academic perspective and independent, critical appraisal – and to do something similar after we know the REMA decision. If that’s introducing a zonal market, it may be more oriented around delivery and implementation, including how long that would take – again, looking at international experiences and the issue of risk management. If they decide to stick with the national price model, we’d like to look at what is practical near term and in the future, and how stable that solution is. And again, questions around implementation. The first forum was about two theoretical options in the air, whereas the next one will be more of a discussion of practical implementation and challenges – learning lessons from how other countries operate or have operated similar systems. I’m currently looking more into the Nordic experience with a zonal market, and the general story behind zonal pricing and how it’s evolved and developed. In many ways, before Brexit, Britain was also, in a sense, part of a zonal model at a higher European level. I also focus on how we can redesign the regulatory framework in a way which facilitates the transition of the networks – both transmission and distribution. That’s a related topic, which mixes economic, technical, and political elements.

Will there be a Second Scottish Forum on Future Electricity Markets? And when would that be?

Yeah, I think maybe towards the back end of the year. The government will likely publish a lot around their decision, which should be made sometime in June or July. As an organising group, we’ll probably sit down in August to plan ahead. Later in the year, we might re-engage with stakeholders and the debate, and move the discussion forward then.

Interviewer: Jan Žižka