The West’s nuclear renaissance faces a slow birth as fragile economies and sluggish growth make it a difficult time to raise cost-effective financing for greenfield projects. The United States Department of Energy’s loan guarantee programme underwent some tough scrutiny after Constellation Energy abandoned the Calvert Cliffs 3 nuclear project. The other sponsor of Calvert Cliffs 3, Electricite de France (EdF) is under pressure to be one of the winners, not the losers, in an increasingly global nuclear arena.

Problems for Calvert Cliffs

Constellation’s abandonment of the 1,600MW Calvert Cliffs 3, which would be located in Maryland, highlights the difficulty of developing nuclear projects under current market conditions. Constellation and EdF were 50/50 shareholders in Unistar, which plans to build four new nuclear plants in the US, starting with Calvert Cliffs. EdF brought experience working with newer generations of nuclear reactors, and a desire to export French technology, while Constellation brought some development sites and US nuclear experience.

But Constellation said the $880 million fee for a loan guarantee from the DoE, at roughly 11.6%, was too high for the $10 billion project. The White House’s Office of Management and Budget works with the Department of Energy on the loan guarantee applications, largely to ensure that the fee adequately covers a project’s risk profile. The department was reportedly about to offer modified terms to Unistar, when it heard of Constellation’s withdrawal. “We were surprised to receive the notice from Constellation since DoE has been working closely with the company on this complex transaction, and have laboured on this matter diligently for weeks,” says Stephanie Mueller, spokeswoman for the DoE.

The Baltimore-based utility, generator and gas and electricity distributor and trader has since agreed to sell its stake in Unistar to EdF. But EdF is obliged to have a US partner in Unistar, to conform with the country’s regulations on nuclear build. EdF said the Unistar consortium was close to agreeing terms on the loan guarantee application, and many reports linked Constellation’s change of plan to an ongoing dispute with EdF over a put option to sell to EdF up to $2 billion of fossil fuel assets, agreed in 2008.

As part of the settlement between EdF and Constellation, EdF takes over the project and hands 3.5 million shares of Constellation, worth roughly $110 million, back to Constellation. The two sides keep their respective stakes in the existing portfolio, while EdF takes over the Calvert Cliffs 3 site and two sites in New York where it wants to build new plants. EdF will need to find a new co-sponsor that can absorb the risk of cost overruns and power price volatility associated with nuclear, either on its own balance sheet or by passing them onto customers with the help of a supportive regulator.

Whatever the real reason for Constellation’s change of heart on Calvert Cliffs, the government’s loan guarantee program has been thrown into the spotlight. The loan guarantee plan was authorised in the 2005 energy policy act, and the section of the act under which nuclear developers apply stipulates borrowers must pay their own credit subsidy costs.

The only greenfield nuclear project to have thus far secured a conditional DoE guarantee is Southern Company’s Vogtle expansion. Southern, through its regulated Georgia Power utility subsidiary, plans to build two 1.1GW Westinghouse AP1000 reactors on its existing nuclear site in Georgia. The department has committed to loan guarantees for approximately $8.3 billion of the estimated $14.5 billion project cost.

The fees for the Vogtle loan guarantee are thought to be around 1 or 2%, largely on the back of a corporate guarantee from Southern. The regulated market structure in Georgia allows Southern to make this commitment, because regulators allow costs of the plant to be passed on to consumers.

With Constellation operating in the more deregulated PJM market, the initial proposal for Calvert Cliffs 3 was for it to be a merchant plant. The DoE and OMB looked at this offtake structure, together with the sponsors’ ability to cope with cost overruns, and applied a much higher credit subsidy cost. In a letter to the government dated October 8, Constellation said such a fee “would clearly destroy the project economics, or the economics of any nuclear project for that matter.”

Power market prices face downwards pressure from the prospect of sustained low gas prices, the level of which will depend somewhat on the development of shale gas. Nuclear power plants have also not been given support from new regulation on carbon markets that some in the nuclear sector had hoped for.

In negotiations over the loan guarantee fee, the department requested the project sign up around 75% of the plant’s capacity to offtake contracts, rather than operate on a merchant basis. The concept of having an offtaker in the structure is being considered by Unistar, with the idea that this may bring the fee down to nearer that for the Vogtle project. But a failure to secure a guarantee could make other nuclear developers gunning for a loan guarantee reevaluate their stance. “If the government wants to be wholly market-based in its fee, I can understand the logic, but at the end of the day they won’t be seeing a lot of nuclear plants built other than those built on the balance sheets of companies,” says one banker.

East is beat

The stumbling of the Calvert Cliffs-3 project comes at a time when EdF, and Areva, its long-standing French partner, are trying to reassert their positions as world-leading nuclear firms.

Following recommendations in a government-commissioned report by Francois Roussely, an ex-CEO of EdF, it is expected that EdF will take more of a lead in French nuclear projects, leaving Areva, its loyal partner, to play more of a supply role. The government owns 85% of EdF and 87% of Areva, and wants EdF to increase its 2.4% stake in Areva. There have also been reports that EdF has considered using other suppliers, giving it a choice of reactors to offer.

The pressure on EdF to perform on a global scale was heightened by the failure late last year of a French consortium, including EdF, GDF Suez, Areva and Total, to win a tender to build four reactors in Abu Dhabi, in United Arab Emirates. The tender was won by a South Korean consortium, led by Korea Electric Power Co. Included in KEPCO’s grouping are Samsung, Hyundai, Doosan, Westinghouse and Toshiba.

The Emirates Nuclear Energy Corporation, a body created by the UAE, plans to develop the project with the Korean group. It has appointed Credit Suisse and HSBC as financial advisers. The consortium’s contract to build the plant is valued at around $20 billion. Under the build-operate-transfer contract, four APR-1400 reactors will be used, and the plants are to be brought online between 2017 and 2020.

The financing structure is still being worked on, but it is likely that Korea’s export credit institutions, the Export-Import Bank of Korea (KEXIM) and Korea Trade Insurance Corporation (K-Sure, formerly KEIC) will directly provide much of the funding, perhaps around $10 billion, and by extending guarantees to commercial lenders could cover the entire remaining costs.

South Korean companies have been aggressively exporting their business overseas, in particular to Middle Eastern countries, and any third-party lenders for this greenfield nuclear project would have to be comfortable with the sovereign credit risk. “South Korea is definitely a good sovereign risk, but there’s so much South Korean paper out there right now,” says one banker. “Pricing that risk is the real issue,” he says. Still, in the KEPCO grouping’s favour is the track record of the UAE, and Abu Dhabi in particular, in running power procurements and developing creditworthy offtake structures.

But the KEPCO consortium will have to build its first nuclear plants in the Middle East on time, and on budget. In the US, new licensing procedures will need to run smoothly for projects there to hit targets. Southern Company’s Vogtle reactors are scheduled to start commercial operations in 2016 and 2017, around the time of the first Abu Dhabi plant.

The US project will not have its combined construction and operating licence awarded until after September 2011, the deadline for the final approval of its Westinghouse reactor design. Seven other combined licence applications in the US have referenced the same reactor design, under what one NRC official describes as an “aggressive” licensing schedule.

After delays of third-generation plants in Europe, in both Finland and France, timely completion of newer projects would help boost investors’ confidence in nuclear, and influence which developers and suppliers gain market share, as more countries look towards nuclear power. Those markets with the most heavily regulated power sectors could be the best-placed to attract new nuclear generation investment

Domestic power

In France offtaker credits drive nuclear investment. The Exeltium deal, which closed in April of this year, was a unique structure which, if not incorporating full project risk, saw many of France’s largest industrial users investing in nuclear output. The Exeltium SPV was created in 2006 by a group of electricity-intensive companies based in France. The companies said high wholesale power prices were reducing their competitiveness in global markets. Exeltium, founded by Air Liquide, Arcelor Mittal, Arkema, Rhodia, Rio Tinto Alcan and Solvay, wanted long-term access to power at a price below market rates and based upon the cost of nuclear output. The consortium swelled to 26 members.

The French government was heavily involved in putting together the deal, and since EdF, with 58 reactors in its home market, is the dominant power supplier and operator, the structure was at the mercy of prolonged negotiations with the European Commission. These resulted in changes to the project structure, including opt out clauses for offtakers after 10 years, and the ability for companies to resell unused power on the open market.

The EU authorities gave their final approval in August 2008, but the financial crisis in late 2008 meant the project was unable to raise sufficient debt – roughly Eu4 billion ($5.6 billion) – to complete the initial deal. The project was halved in size, and this first portion reached financial close in April this year. Some 150TWh of power is contracted under the agreement.

The transaction was arranged, subscribed and syndicated by four French banks, BNP Paribas, Credit Agricole, Natixis and Société Générale. Natixis was financial adviser to Exeltium.

The final syndicate consisted of 10 banks including the four initial arrangers, plus Banca IMI, Banco Santander and BTMU as mandated lead arrangers, Dexia as lead arranger, and Banesto and ING as arrangers. Caisse des Dépôts et Consignations provided a separate Eu233 million junior debt facility, and the equity contribution was Eu174 million.

The equity contributed by each Exeltium shareholder correlates to the amount of power taken. The maturity of the debt is 9.5 years. Debt margins rise from 250bp up to 400bp. Cash sweeps increase in time and reach 100% after year six and a bullet payment is due at the end of 9.5 years.

Sharing the load

Exeltium supplies roughly one hundred industrial sites, in sectors such as aluminium, chemicals, environment, industrial gases, paper, metal processing and glass.

Lenders had to scrutinise the credit of each of the 26 counterparties, though the offtakers were treated as a portfolio, so that that the debt service coverage ratio would only be heavily affected if there were lots of defaults within the group. The offtakers are required to provide cash collateral in case of default, with a larger amount required from lower-rated entities.

In the event of a counterparty default, the project would try to replace the offtaker, or sell the power into the wholesale market, says Paul Lund, credit analyst for Standard & Poor’s, which rated the transaction at BBB-. “If a buyer is found in the day-ahead or week-ahead markets, then some revenues come from there, but they may be more volatile,” Lund says. “Given where the deal is sitting in terms of overall cost for participants versus the long-term average for baseload power in France, we think it’s reasonably competitively priced,” he adds.

Under the upstream contract, EdF supplies power to the project for 24 years, and treats the contract as a corporate obligation. There is some risk sharing between EdF and Exeltium on the cost overruns for its third-generation Flamanville-3 EPR plant, currently under construction, as well as the availability of EdF’s 58 operational reactors. This has an impact on the price to offtakers, but not on the volume supplied to the project. The offtake price for the shareholders is around Eu41 per MWh, with a capped price adjustment related to any increased costs. One source describes these potential adjustments as “moderate,” but it increases the price by euros, rather than cents.

Not all offtakers are signed up for the full 24 year period, but they are all contracted for over 15 years. To conform with EC demands, there are opt out clauses every five years starting from the 10th year, which gives the offtakers the right to not take the power for a period of five years. To mitigate this market risk, Exeltium shareholder Arcelor Mittal sold a put option to the project company for around half of any opt out volume, and, for the remaining half, the SPV pays EdF an adjusted price.

EdF initially said the Flamanville plant would cost around Eu4 billion, but the cost has reportedly risen to Eu5 billion and the commercial start-up date has slipped from its initial target of 2012. The company has kept the official costs and progress of the project close to its chest.

Exeltium repeated

Talks are under way for the second phase of Exeltium, which is expected to use a similar structure to the first. With the economic climate much changed in the last few years, it is doubtful all 26 shareholders will remain in the project structure for phase 2.

It is also unlikely CDC will supply junior debt this time, and the project is looking for other mezzanine providers. Financial close is expected next year, by which time France’s NOME law, currently being read by Parliament, may have been implemented.

The NOME law reforms France’s power markets in favour of new suppliers, giving them access to EdF’s nuclear output at competitive prices. The move follows recommendations in the Champsaur report, commissioned by the French government and published in April 2009.

While the NOME law is hugely important for the development of the French power market, it is not likely to prompt many changes for the Exeltium 2 financing. “Many aspects of French regulatory reform were considered in the Exeltium 1 deal, in the context of the Champsaur commission findings. The regulatory environment was obviously a sensitivity from a funding perspective, but one on which a sufficient degree of comfort was ultimately found,” says Simon Ratledge, partner at Linklaters, which advised the lenders on the deal. “The economic and industrial imperative for the Exeltium offtakers was to get clarity on a long-term basis on their electricity costs ... they were not analysing the deal on a short-term basis,” he says.

Exeltium is seen as a rather special transaction, with industrial lobbying and political impetus combining with a state-owned generator that operates the world’s largest nuclear fleet. While those involved in the transaction may look to repeat some of the project structure in other countries, it would likely need significant adjustments to sit comfortably in other power markets.