Nuclear industry weighs short-term pain for long-term gains

With increased use of nuclear energy currently the EU’s most likely route to ensuing both security of supply and low carbon emissions, Alex Davis examines the impact such a policy could have for energy risk managers

The European Union's dual policies – of guaranteeing the security of energy supply throughout its member states and of ensuring that the energy produced is sufficiently low in carbon emissions – seem to be heading on a collision course unless there is more nuclear power in the energy mix.

The EU has stated that it wants a 20% to 30% reduction in carbon emissions from 1990 levels by 2020 and a 50% reduction by 2050, while energy companies have promised to try and deliver carbon-neutral electricity supply by 2050.

At the same time, the EU is furiously working through directives, agreements and incentives to make sure that the European energy infrastructure and markets are fully integrated and transparent to avoid repeating events such as the Russia-Ukraine gas supply disputes that raged between 2005 and 2009, which affected a number of surrounding states.

As such, nuclear power seems to be the ideal solution. The technology is well established and nowhere near the gamble presented by some newer renewable technologies, while the production borders on carbon-free. In fact, according to the International Energy Agency and the Nuclear Energy Agency, the most cost-effective scenario that envisages a 50% cut in global energy-related CO₂ emissions from 2005 levels by 2050 means that nuclear energy will have to supply almost one quarter of the world's electricity. This increase from its current market share of around 14% would make it the single-largest power source in the world.

Although there remain very serious obstacles to overcome – in particular the financing and public acceptance for new nuclear power station builds – in the likelihood that projects such as the UK's planned new sites in Anglesey and Oldbury get the go-ahead and come online in the early part of the next decade, there are going to be a raft of new challenges facing energy risk managers.

No natural hedge

Wholesale gas prices have a large influence on wholesale electricity prices, giving combined cycle gas turbine (CCGT) power plants an inherent market hedging strategy to counter the cost of the fuel. The same market hedging options apply to coal-fired plants and plants that occasionally run on oil. Nuclear power stations do not have these options and, thus lacking CCGT's flexibility and price-setting link to gas, they are slaves to the power market.

Although the margin impact from the cost of widely sourced, easily stored uranium is a fraction of that of fossil fuel-fired power plants, the comparative fuel cost savings are dwarfed by the intensive capital costs.

The cost of the first-of-a-kind new generation European Pressurised Reactor (EPR) station being built in Finland currently stands at around €6.5 billion. Even after lessons from Finland have been learned, the common assumption is that new units will cost around €5 billion.

Nuclear energy is squeezed on both sides. As KPMG summarised in a recent report: "nuclear generation does not have any hedge against variation in its costs and is exposed to a variation in revenues".

Thus energy risk managers face the daunting prospect of finding a way to protect nuclear generation from energy market fluctuations while having to find a way of easing the capital drain from an asset that, according to KPMG, can take over 30 years before paying back its investment.

US-based utilities firm Southern Company currently operates two nuclear power plants in Georgia and one in Alabama and is currently building the first new units in the country for 30 years at its Vogtle, Georgia site. Risk manager Chris Schlegel is thus dealing with both of these problems right now.

"In terms of managing the risk, I can't call up my top financial counterparties and say, ‘give me a structured product that takes my risk off the table.' Nuclear is a very different animal – it's a marathon, not a sprint," Schlegel says.

From a market risk perspective, Schlegel actually sees nuclear energy's role as an inflexible base-load generator as a positive characteristic for risk managing power trading.

"For a risk manager looking at the trading side, a large nuclear plant, as long as it is running, is not adding to your risk. It's actually a great thing to have, humming along in the background, lowering your marginal cost."

The danger from Schlegel's perspective comes from an unexpected shutdown and if nuclear power does indeed gain a greater share of the energy mix in the future, this could have a stark effect on managing supply.

"Where it becomes a problem is if it is not running – if there was some kind of forced outage, and you have a good portion of nuclear energy in your portfolio," he says. "Imagine you have 2,000MW disappearing overnight from your portfolio of low-cost stable generation. If that goes, and you haven't managed your reserve margin well, you could potentially be struggling to fill that supply."

The key is clearly diversification in the energy portfolio, of getting the right balance and ensuring the producer is not overly reliant on any one source. As such, although the decision to increase capacity in the short-term appears to make CCGT plants the better option with a lesser capital risk, Didier Beutier, deputy vice-president for marketing at Areva, and chair of the European Commission's sub-working group on competitiveness for nuclear energy, believes that firms cannot afford to leave out nuclear.

"The big companies have policies of balancing the energy mix, exactly aiming at mitigating the specific risk of each technology and so that's why for big utilities, nuclear is a component," he says. "I would say the optimum mix for a utility in Europe right now would be a combination of gas plants and nuclear plants because gas is driving the price and the margin of electricity and then they can reap the margin with their nuclear power plants."

Managing the capital costs

Being able to leverage nuclear generation in order to make better margins in the energy portfolio is undeniably useful, but there still remains the extremely delicate matter of easing the huge burden of debt arising from the long-term capital costs.

Utility firms can thus find themselves in something of a catch-22 situation, whereby the off-putting construction costs keep away financiers who in future years would not consider a company without sufficient nuclear energy in the portfolio.

"With nuclear, basically you need to find investors that take the long-term view," says Fabien Roques, director, European power with consultancy IHS Cera. "There are not that many investors around happy to take a view for 40 years."

David Simpson, energy partner at KPMG, outlines the risks of then lacking such investment.

"Provided other people are doing it, most power companies want to stay somewhere not a million miles away from the generating mix that other companies have got," he says. "So if you are completely underweight on one key portion of everybody else's portfolio, this might not be a good thing for investors over time."

To shoulder the burden, IHS Cera's Roques thinks that there are in fact numerous options facing Europe's utilities companies, not least of which is adopting the joint-venture approach, as seen in E.ON and RWE's 'Horizon' partnership that plans to build sites in the UK.

"The big issue is simply the sheer magnitude of risk so it does make sense for utilities to partner up to share the risks and liabilities. In the UK, partnerships will be the name of the game - probably only EDF has the ability to go it alone," he says (see details on risks below).

"It does depend on the markets – in some markets, you've got some utilities ready to go it alone. France is a very specific case, obviously, but we've seen the example in Finland, where it was actually some local energy users joining forces and asking one utility to build the site and helping to finance it."

Indeed, the variance in the member states' market potential is a result of public acceptability. With the Chernobyl disaster still casting a 24-year shadow, the question of having more nuclear power in the energy mix is a hugely political one. While central and eastern European countries such as Slovakia and Slovenia, currently overly-dependent on one power source, are highly supportive of nuclear energy, countries like Austria have ruled out nuclear energy generation altogether.

With its recent decision to extend the life-spans of its nuclear plants, but at the same time demanding a larger share of the profits, the German government has a highly ambivalent attitude towards nuclear power. Even in a relatively supportive country like the UK, public opposition meant the government has ruled out providing subsidies to build new nuclear units on the grounds it is a ‘mature' technology.

The European Union did not include nuclear energy either in its €4 billion European energy programme for recovery subsidy package and as a policy it has ruled that the decision to build new nuclear units is a sovereign issue.

"The EU has clear legal competence in energy policy as one of the new articles of the Lisbon Treaty but it's clear that each EU member state is free, in principle, to decide on their energy mix," says Philip Lowe, director-general for energy at the European Commission. "The role of the EU here is to provide the most advanced legal framework for nuclear energy to meet the highest standards of security and non-proliferation of any other use other than civil use. That's the limit of our role – we can't express our view of how important nuclear can be. It's obviously a technology where we can facilitate things where there is some desire among member states to deploy nuclear energy."

Companies such as EDF Energy have been on record as saying they are happy to try and build new plants without subsidies but what they all need are market conditions that will guarantee the investment.

Southern Company's Schlegel believes that regulated long-term agreements provide the stability needed to sell the electricity and service the debt.

"In terms of risk management, it does look like the merchant nuclear model for new-build is running into trouble. If you're going to manage the overall risk, the regulated model looks like the better way to go," he says.

In the words of one risk management source: "you're supposed to build something that doesn't come online until at least 2018 and then you have to run it for 20, 30 years. To try and sell that in the spot market is kind of a suicide mission." It is a sentiment with which Xavier De Rollat, director of power origination at Société Générale Corporate and Investment Bank, agrees.

"There is absolutely no incentive to sign long-term contracts in the EU. The growth of spot markets does not help, because it puts a lot of emphasis on very short-term electricity sales arrangements – day-ahead or hours-ahead, which is a far cry from the 60-year operational life of a nuclear power plant," he says. "So either you have long-term contracts or you own distribution assets so you have a fair degree of certainty that you can put the electricity through your network. If you don't have those to a degree of comfort, you're probably struggling."

However, regulation is not a direction Europe's utilities especially want to take, while signing up to long-term wholesale power agreements is by no means straightforward.

"Well, yes, we haven't got a long-term power market and clearly you can't lock in prices in a way that would enable you to support those major capital investments. That said, the time period for returns from nuclear will be 20-years-plus and we don't have a history of 20-years-plus power purchase agreements anyway," says KPMG's Simpson. "In fact, big power companies will say that they like, under appropriate circumstances, to be exposed to market risk because actually if they manage market risk appropriately, they can make better than average returns. They don't necessarily want to be regulated utilities. There are some benefits to a liberalised power market as well as some drawbacks."

For risk managers, this presents a tricky strategic balancing act and one in which the ultimate outcome lies out of their hands, in the realms of regulatory risk. They do not want incentives that would damage the spot market and remove the cashing-in opportunities that nuclear generation provides an energy portfolio. Neither can they afford to leave nuclear generation completely exposed to gas and electricity price movements. What they need is market reform.

"I think there are two types of changes that need to be made. One is linked to power markets and the other is linked to carbon markets," says IHS Cera's Roques. "The UK reform is first tackling the carbon market by venturing a price floor."

Such a price floor, if sufficiently high, would thus ensure that the carbon-neutral nuclear generation off-take would have to be part of the daily spot market in-flow. Roques also believes that there need to be measures taken in the EU's power markets.

"With regard reforming power markets arrangements, I think we need to de-risk some of these power markets. You need to move to some type of market arrangement that will provide more stable revenues and that will contribute to de-risking the markets," Roques says. "There are many examples – one could be the capacity payments, which is being put in place in France at the moment and talked about in the UK. The idea is not only to re-numerate not only output of the plant but also availability, meaning that even if you don't produce, you are available to produce."

The question is – with such potentially crippling costs and with currently no guarantees that market reforms will be enacted in nuclear generation's favour, why should the utilities be willing to commit themselves to something so unwieldy and awkward to risk-manage?

"We have had a seminal move, politically, socially and economically to low-carbon electricity and security of supply. Nuclear power is the cheapest bulk method of generating low-carbon electricity – absolutely the cheapest," says KPMG's Simpson. "Over time, it's expected that the process of fossil fuels, probably aided and abetted by the carbon price, will be more expensive than the levelised costs of nuclear power, therefore putting them in a good position."

Indeed, the difficulty of managing the short-term market and capital risks of nuclear energy is an effort that will be richly rewarded for a company when it outlasts gas as the market-setter for power.

The main five risks affecting nuclear power

1. Construction risk: the challenge of having a unit built on-time and on-budget.

2. Market risk: nuclear generation’s lack of hedging ability in the power market.

3. Capital risk: the need to manage the long-running capital costs for an asset that might not recoup its investment for 30 years.

4. Regulatory risk: the variations in safety standards and licensing agreements across EU member states; although the European Commission is shortly issuing a directive on safe nuclear waste disposal.

5. Political risk: with public acceptability such a major factor, the danger arises, for instance, from a change in policy that halts a project that has been started, such as the Zwentendorf nuclear power plant in Austria, finished in 1978 but never switched on.