As Europe’s energy industry prepares to convene for POWER-GEN Europe in Amsterdam in June, Power Engineering International invited a panel of experts to debate the future of the fossil fuel and nuclear sectors, the development of on-site power and distributed energy and the changing business models of utilities

Europe’s energy landscape is in a state of transition. The penetration of renewables is gaining pace, throwing doubt on the future role of fossil fuel and nuclear plants and opening the door for the adoption of flexible, on-site power solutions.

We asked four energy experts to discuss how they see Europe’s power sector developing. The four were: David Porter, Senior Advisor to the Global Energy team at consultancy Navigant; Simon Hobday, Energy Partner at international legal practice Osborne Clarke; Jacob Klimstra, Energy and Engine Consultant; and Ulla Pettersson, Managing Consultant and Founder of E for Energy Management.

Fossil fuel’s future


There is growing consensus that traditional coal- and gas-fired plant remains ‘uninvestable’. What are the best options for optimizing legacy plant operations for nations needing to maintain fossil fuel-fired plant to meet baseload requirements or ensure security of supply?


Simon Hobday: Gas is, in many respects, a low-carbon technology. It is much cleaner than coal, and it’s an excellent source for ensuring stability in generation whilst new smart technologies continue to develop – power is still required regardless of whether or not the wind is blowing.

However, deciding to commit to gas generation is currently a difficult decision. The market design and other support must give investors confidence they will be able to recover finance construction and operating costs and make a profit; otherwise they simply will not build. If the market model does not allow this then other approaches, such as the UK’s capacity market, will be needed.

David Porter: It is no longer financially viable to run existing power plants in the traditional way, and certainly not economical to build new power plants – the scope for them to run and earn an income has been reduced by the mandatory ‘must-run’ nature of renewables. But, we need plants that can provide electricity when customers want it. There’s currently a lot of discussion about how capacity mechanisms can pay for a plant to be available 24/7 and fill the gaps when intermittent renewables are not generating.

However, in Europe this is creating problems for the slowly emerging single market in electricity. Theoretically, one country ought to be able to take account of a neighbouring power station in another country if there is an interconnector between the two countries. But capacity mechanisms are being developed by individual countries, rather than centrally from Brussels, therefore they focus on particular countries’ requirements and this creates difficulties for countries that would like a proper market in electricity across Europe. It underlines where true political responsibility lies.

Jacob Klimstra: A recent conference in Brussels revealed that cogeneration in cities will play a major role in optimizing legacy plant operations. The demand for heat in Europe is two or three times more than the demand for electricity, therefore only integrated power, such as combined heat and electricity generation, will be flexible enough to thrive in the new energy landscape. Remotely located large power plants are not the answer due a lack of flexibility and high costs.

There is much debate over the future of fossil fuel power plants

Credit: Alstom

Ulla Pettersson: I think that each country must have an ISO (Independent System Operator) whose responsibility is to put up auctioning capacity if needed, but this offering is stronger and weaker in different countries. However, this approach is more applicable to kick load; it is very unlikely to use capacity contribution for baseload and mid-merit.


Is there a future for new-build large plants if they were to include technologies such as those based on co-firing, cogeneration or CCS technology?


David Porter: I believe there is a future for new-build large plants, but they’ve gone through such a period of trauma, companies will need to see stability and have much more confidence in the politics of the market before anything happens. Gas which, like coal, can be run flexibly is widely accepted as a ‘bridging’ fuel in the lower-carbon transition, so it will remain part of the mix. In fact, coal- and gas-fired plants will be part of the market for a while to come, but the market arrangements must inspire developers and investors with more confidence than they currently do. Power companies will face huge challenges in optimizing the running of their plant and making a portfolio profitable.

Ulla Pettersson: There is definitely a future for big plants because if we don’t build them we will never get out of this recession. The manufacturing industry in Europe isn’t operating at maximum capacity, therefore we cannot base supply on this lower demand; otherwise we’ll face difficulties when we try to increase capacity in manufacturing industries. If we replace old plants with many small ones, the costs for staff and environmental protection – for example, filters – will increase. If we don’t replace old plants, we will never be able to catch up and manufacturing will move to other parts of the world. That would be a catastrophe for Europe.

Simon Hobday: I believe there is a future in large plant, but while support is being given renewables to encourage high capital cost, low marginal operating cost plant mechanisms need to be looked at to encourage the construction of large efficient plant. In the UK, the new capacity mechanism auction has secured some additional capacity but it’s still new, and it remains to be seen whether it will in fact serve to provide cost-efficient new balancing plant. Other approaches used historically in the UK include the supplemental payment in the Pool Price prior to NETA (PIP or Pool Input Price and POP, Pool Output Price).

Jacob Klimstra: For CCS to be implemented, the price of CO2 has to be about €80 per tonne, but this doubles the electricity production costs of coal-fired power plants. Biomass co-firing is an option to keep the CO2 production of power plants low. However, in order to optimize energy use in Europe, power plants have to be very flexible and offer CHP facilities. However, I believe that smaller-scale local power plants are the best option for the future. They can offer the required flexibility, especially if they are of a modular design.


Should national and EU policy be adjusted to ensure that coal- and gas-fired plants can operate alongside more intermittent forms of power generation?


Simon Hobday: If a country makes the policy decision to intervene in the power markets to promote (intermittent) renewable generation, then once the intermittent generation reaches a certain level where it affects the economic health of other plant required to balance the power system the country must, I believe, look at methods to support non-intermittent generation. Otherwise energy technologies such as storage, which has additional cost for the consumer, otherwise the lights will go out. I believe a number of countries are currently in this position.

David Porter: I think policy will have to change because of the imperative of keeping the lights on. Part of the answer is the ‘smart’ agenda which should help us manage better the mix of plant, which was forced on to the system by public policy before we had the means of properly managing it. That’s exciting, but however smart we are, we still need plants that can respond to demand. Policy will have to allow for that.

The integration of renewables has changed the energy landscape

Credit: London Array

Jacob Klimstra: This situation would mean further leaving the free market for energy. Energy is one of the most important driving factors in our economy. Purely commercial operation procedures and quarterly profit goals do not fit with the long-term planning required for the power sector. Maybe we have to go back to a fully government-controlled energy supply sector, as is practically already the case with renewables.

On-site power


Who have been the early adopters of distributed generation technologies, and in what scenarios does it prove an attractive option?


Simon Hobday: Generally speaking, across Europe power has been generated through large, centralized plants and distributed through a national or regional grid. This system worked very well where generation was pretty stable, controllable and predictable. As there has been more focus on the environmental effect of carbon, and growing support for renewable energy from solar and wind which is inherently intermittent, the way that the power networks physically behave and the economics of plant generation have radically altered. The impact of this is that in places like Germany, many fossil fuel plants have been mothballed – even new CCGT – because their operation is no longer economically viable. In contrast, smaller localized plants have grown significantly, driven by renewable subsidy, such as combining the use of heat and power, or greater use of resources, such as waste for energy plants.

Ulla Pettersson: Distributed energy generation is most attractive in places where it is expensive to connect to a grid.

David Porter: This sector is expected to expand significantly in coming years. Its recent growth is due to public policy support and renewable energy investment, notably in photovoltaics and wind power.

Jacob Klimstra: Denmark was an early adopter of these new technologies, and the country has a great strategy for integrating heat and electricity usage through distributed generation. It is generally recognized now that cogeneration substantially reduces fuel consumption and that it is an ideal backup instrument for the fluctuating output of wind- and solar-based generation. Moreover, if wind and solar sources produce more electrical energy than required by the grid, heat pumps in combination with the heat supply system of cogeneration can easily take the surplus. Small-scale generators can be very clean thanks to sophisticated catalyst technology.

Simon Hobday: Approximately two thirds of the inherent energy in fuel is being lost as heat to the atmosphere. If that can be captured, energy conversion efficiency will increase exponentially. This means the overall energy cost is lower, less fossil fuel is used and the plant’s carbon footprint is massively reduced. Distributed energy technologies are one solution to the large amount of energy lost through transmission.

David Porter: Smaller distributed projects are generally less capital-intensive, and this can make them more attractive as investments. They are usually easier to set up and can take pressure off centralized production and distribution plants. However, one of the problems with subsidized, small-scale renewable technologies is that they also take demand and revenue from the established utilities and inevitably damage traditional profitability.

Ulla Pettersson: It’s also worth noting that for plants involving combustion technology, it is better for the environment to operate a few centralized plants than lots of small localized stations, as large-scale plants can afford to install environmental protection. Additionally, there’s no environmental damage caused by transporting electricity over cables. Lots of small plants without the necessary equipment and processes can be even more harmful than a single large plant, because delivery is not cost-effective to them.


On-site power is a prominent form of distributed energy. In what contexts is it most common today, and where might we see it used in the future?


David Porter: Europe is making a conscious effort to reduce carbon emissions, as is seen with the 2020 targets, meaning smaller renewable energy enterprises are here to stay. Established utilities, therefore, must figure out how to accommodate them whilst maintaining profitable traditional plants that are vital for meeting energy demands when the sun doesn’t shine or the wind doesn’t blow.

Will nuclear have a European revival?

Credit: Vattenfall

Simon Hobday: While the traditional generator model has suffered from the subsidy for renewable generation, a new economic model is emerging – and this points towards what we might see in the future. Over the last five to eight years we have seen significant deployment of solar and wind generation. As part of this deployment, smaller developers have taken advantage of economic incentives to construct low-carbon plants with long-term operation and power sale contracts, and then recycling the capital by selling the generation assets – or economic interest in the assets – to financial investors. While much of this generation has been standalone, wind farms being an excellent example, an increasing amount is being linked to commercial and industrial sites, as well as institutional buildings such as schools, hospitals and universities. As the European sector reacts to the Commission’s drive to increase overall energy efficiency, we are likely to see more of these initiatives.


Will cogeneration and trigeneration technologies be largely privately-funded, or do you expect public-private partnerships (PPPs) and subsidies to play a role in driving further adoption?


Simon Hobday: It’s a little of both. Consider district heating. Currently, systems in many parts of Europe are sparse and fragmented. A good example of this is London where there are various new and older developments in, for example, King’s Cross, Islington, Greenwich, Pimlico and soon to be in Battersea. However, the projects have been designed and built as isolated systems with either private finance or public funding. The challenge, then, is how to connect these isolated areas. The pipe work is extremely expensive – approximately £1.5 million/km. While the economic case for heat in each development can, and is, made, the economics of longer transmission pipes ahead of future connections is more difficult. However, without this infrastructure, wider deployment of heat will be held back. It is in respect of this interconnecting pipework that public support could make a significant impact.

David Porter: Smaller-scale cogeneration is probably less likely to require public funding. There is a big difference between a cogeneration scheme for a factory or an apartment block and a district heating scheme for a large area of city – that’s the kind of infrastructure where public sector involvement seems almost inevitable.

Ulla Pettersson: Also consider, though, that cogeneration is a long-term investment, and the demand for heat in most European locations is not a competitive market. As such, consumers rely on regulators to govern pricing, and this makes risk assessment difficult for private capital investment. Consequently, public funding is a more natural solution.

Currently most of the cogeneration in Europe is heat distribution to households; it’s considered part of the responsibilities of the public service, and it’s a typical principality matter. For this type of cogeneration public funding makes the most sense. Heat in the industrial distribution sector, however, is much more likely to have private funding, as it presents a business case that’s easier for an investor to understand.

Jacob Klimstra: Citizens generally do not like to be controlled by large anonymous companies so this could present an opportunity for people to actively participate in investment in local generation through crowdfunding. However, there is a risk that government-controlled subsidies could undermine these efforts. Renewable energy enterprises need reliable financial backup. Insecure subsidies due to volatile policies of governments will only distort the market.

Utility business models


What have been the most pressing challenges driving change in the way that utilities operate and the business models they follow?


Ulla Pettersson: Over the last 10 years utilities have struggled to understand the role of renewables in the generation market, and how investment would affect business models and merit order. Today all utilities have adapted, but a future challenge will be understanding consumer behaviour in relation to the smart grid.

David Porter: Utilities have often found themselves being driven by political requirements. But their focus on what the politicians want may have distracted some of them from what their customers want. Customers want reliability and the lowest possible prices but politicians have caused some utilities to become disconnected from that, resulting in a strain in the relationship with customers.

The challenge is to achieve sufficient stability in energy politics to enable companies to plan their future. This will involve greater energy efficiency, customers producing some of their own power and, most probably, new players in the business. It is a big challenge for utilities that are used to traditional ways of working. New business models will develop to take advantage of new opportunities – for example, adapting to the ‘Energy Cloud’ where there will be not only microgrids, but a two-way flow of power across networks. It’s not just a threat to utilities; it is also very exciting.

Jacob Klimstra: Utilities have to learn how to cooperate with their customers and expand their offerings to include services, not just energy.


Which utilities have been the most successful in transforming their portfolios, and what aspects of the local market have ensured their success?


Ulla Pettersson: When Sweden began to build wind farms on a bigger scale there were a lot of problems organizing permits. The government appointed four coordinators, one for each part of the country, to ensure that all the different authorities were working together. Without them the development process would have been much slower. Lots of components must come together first before progress can happen. In the UK there are examples where it’s difficult to get all the necessary permissions; for example, permission to use land, to run cables over land, and to actually commence generating wind power. This is also seen in China where there are lots of wind farms that are not online because they don’t have a grid connection.


Is business model innovation more of a defensive play given the challenges utilities face in Europe’s energy transition, or are there tangible opportunities emerging and, if so, how can utilities best harness them?


Simon Hobday: I don’t think business model innovation is a defensive play. I think we’re going to see some challenging, innovative business models that will radically alter the industry landscape.

Jacob Klimstra: Business model innovation is the only option.

David Porter: Utilities and other energy businesses can only firmly reconnect with customers if the politics is stable. Innovation will emerge as newcomers force the pace; existing companies may either pull out or reshape their business. I don’t think a company should ever underestimate the importance of a large, happy customer base, but established utilities have lost a lot of confidence and trust, and they haven’t been as vigorous as they could have been in thinking how to strengthen and develop their relationship with customers.



What role do you see nuclear playing in Europe’s energy decarbonization?


Simon Hobday: I believe nuclear will play a role in decarbonization because, despite the public association with danger, nuclear is a stable form of generation and the technology is, in fact, relatively safe. The most pressing issue is how to safely dispose of nuclear waste. Whilst low-level waste is relatively easy to deal with, the high-level waste (mainly spent fuel) must be subject to a careful and long-term solution, and governments around the world have not, to date, implemented this. If Europe is to use nuclear power plants as a way to reduce carbon emissions, there must be a clear plan for long-term storage of highly radioactive nuclear material, and potentially a reappraisal of the ‘you deal with your own waste’ concept to help small countries with unsuitable geology, and to help share the cost of expensive facilities.

Jacob Klimstra: I believe that nuclear power has a future only in countries with a substantial baseload. Finland’s climate, for example, is unsuitable for solar and wind generation to constitute a major portion of the baseload, therefore nuclear is a possibility as long as the public doesn’t protest. Opportunities in the UK, however, are limited due to plans for large wind capacity.

David Porter: Nuclear power, whilst having massive potential, has never been able to distance itself from the perception that it is a ‘political’ technology. But construction costs and timescales mean that it cannot be financed without a level of stability in policy that the EU and member states find hard to deliver. It remains, however, a technology that offers more than most to meet the challenge of the energy policy ‘trilemma’. Nuclear power will remain on the agenda and if we get a breakthrough in cold fusion, it will be even more important.

Ulla Pettersson: Nuclear and hydro are the only large-scale types of power generation with low-carbon technology and carbon-free emissions. As firms incorporate more renewables into power generation, they must also consider how to handle renewables’ intermittent nature. I believe that companies will use carbon-emitting fuels such as coal and gas to balance renewables, and nuclear will constitute the baseload.

Nuclear is a relatively safe and stable form of generation but, from a global perspective, it’s more likely to be accepted in countries with a high standard of education and a stable political system. If more countries incorporate nuclear then the price of coal and gas will decrease as demand goes down. This will make it more acceptable for countries with a lower standard of education and a less stable political system to continue using fossil fuels.

There are a few markets where hydro is enough for a baseload but you need a natural source for it, as they have in Norway, Sweden, Finland, Austria and Switzerland for example. France and England do not have enough hydro not to use nuclear.


Aside from France and the UK, are there any other European nations where new nuclear generation appears likely, and what factors would drive investment in nuclear?


Simon Hobday: Nuclear is a particularly long term investment with a high initial cost. Even if a plant has a 40-year lifecycle, the decommissioning process takes many years; it could be 150 years (or longer) before a site is fully available for other usage. However, it also requires long-term political support and stability, and an independent nuclear regulator ensuring that the highest possible safety standards are complied with. If a country has this in place, nuclear has major advantages as a flat, stable, baseline output with a comparatively low carbon footprint.

Jacob Klimstra: Nuclear generation is a possibility in Bulgaria and Romania but investment costs may be prohibitive.

Ulla Pettersson: The development of nuclear programmes depends on the political situation of each country. For example, there is enough hydro technology in Norway and political feeling against nuclear in Denmark, and these things will hinder its development in these regions. However, Sweden and Finland will probably continue to develop nuclear plans. I will also be surprised if Eastern Europe doesn’t invest in nuclear, instead of thermal, as a way to meet climate requirements.


In the longer term, do you anticipate any change in European Commission policy with regards to nuclear power plants? If so, what could be the potential impact not just on major producers, but on the importers reliant on them?


Simon Hobday: There have been moves to harmonize some elements of approval processes around reactor technology to assist in reducing the costs of deployment across Europe and promote trans-European nuclear trade. However, localized safety concerns and standards will always need to be addressed and met, which increases the cost of deployment compared to other forms of generation.

Utilities have been forced to find new business models

Credit: RWE

With a new Commission it remains to be seen whether they will address other issues around nuclear power, such as the patchwork of nuclear liability regimes across Europe. Meanwhile, nuclear can be part of Europe’s decarbonization equation on a cost-effective basis, but to do so it is likely to require an equivalent level of support to that received by other low-carbon forms of generation.

Ulla Pettersson: It is very expensive to build brand new nuclear plants today. One way to reduce costs and shorten approval time would be to have the same system of approval for design and construction across Europe, instead of the current fractured system of different authorities in different countries with different requirements. This would be particularly useful for companies that wanted to build plants in different countries. However, Europe is not yet ready for industry centralization; it is still very country-oriented.

David Porter: Since the Fukushima disaster, the European Commission has addressed safety issues so I don’t anticipate any future changes to policy. But, there will still be tensions if an anti-nuclear member state finds that its neighbour wants to build a new nuclear power plant.

Jacob Klimstra: I believe the free market will decide the future of nuclear and not the European Commission.