The €3.9bn debt for the €5.5bn phase one of the Nord Stream gas pipeline project reached financial close in April after 18 months in the market.
The debt financing was the last pre-construction stage of the project that took its current form in late 2006 as the culmination of ideas for a north-European scheme that has been mooted since the start of the century.
The principle of the project is provide an export route for Russian gas to the European Union that bypasses Eastern European transit countries. The pipe will run from Russia’s Baltic coastline at Vyborg, through the Baltic sea to Germany at Greifswald. The Nord Stream project company is led by Gazprom, which holds 51 per cent, and also comprises BASF’s Wintershall (20 per cent), E.ON Ruhrgas (20 per cent), and Gasunie (9 per cent). GDF Suez is in the process of acquiring a 9 per cent stake, bringing the two German firms’ stakes down to 15.5 per cent each.
The entire two-phase project envisages 1,220km of two parallel pipes transporting a combined 55bcm of gas. The project has a total capex of €7.4bn, and a total project cost of nearly €9bn. It is scheduled to be completed in 2012.
Connections at each end are provided by Gazprom building a 917km onshore connection to the Russian transmission system, and Wintershall/Gazprom subsidiary WINGAS and E.ON Ruhrgas building two onshore connections in Germany totalling 850km. The first pipe carrying half the gas is scheduled to be completed in 2011, and is the portion financed by the 2010 loan package.
The €3.9bn of loans covering 70 per cent of the phase one total cost was split 80:20 between ECA-covered and uncovered commercial tranches. The ECA tranches, all for 16 years, were €1.6bn, 95 per cent covered by Hermes, priced at 160bp; €1bn, 90 per cent covered by UFK, priced at 180bp; and €500m, 100 per cent covered by Sace, priced at 165bp. Fees were 65bp–75bp on all tranches. The uncovered tranche was €800m for 10 years, priced at 275bp pre-completion, then at 430bp, rising to 450bp at seven years. Fees were 110bp. The sponsors are providing construction completion guarantees.
The commercial banks on the uncovered tranche were BBVA, Bank of Tokyo-Mitsubishi UFJ, BayernLB, BNP Paribas, Caja Madrid, Commerzbank (financial adviser and Hermes agent), Credit Agricole (documentation bank), Credit Suisse, Deutsche, Dexia, DZ Bank, Espirito Santo, Fortis, ING, Intesa Sanpaolo, KfW Ipex, Mediobanca, Natixis, Nordea, Raiffeisen Zentralbank Oesterreich, Royal Bank of Scotland (financial adviser), Société Générale (financial adviser, Sace and intercreditor bank), Standard Bank, SMBC (technical and environmental bank), UniCredit (UFK agent) and WestLB.
The sponsor company wanted a minimum 50 per cent of the €3.9bn deal swapped, and hoped for 80 per cent. Banks were asked to bid on the basis of a set spread, between 10bp and 15bp, and once this position was covered banks that bid higher were allowed to bid again at the established price. The full 80 per cent swap target was allocated. The swaps do not benefit from the export credit cover.
The project’s revenues are set out in the gas transportation agreement with Gazprom export. Gazprom export has complete responsibility for putting the gas through the pipeline, with the project company required solely to make the pipe available. The project company is subject to no volume risk or price risk on the gas.
The availability payment comprises a debt service allocation, an operating cost allocation, and a fixed return. The debt service and operating cost allocations are recalculated annually. Coverage ratios for the loans are quite low at ×1.25– ×1.3, but are robust due to protection of revenues built into the gas transportation agreement’s availability payments. This also avoided any suggestion of the sponsors guaranteeing the ratios themselves.
A critical issue throughout the financing process was the country risk, and whether an offshore account structure could be used to mitigate this. The potential for banks hitting Russian exposure limits was avoided by the ECAs covering 80 per cent of the debt, but when the deal was presented to banks many were still keen for an offshore structure to protect against the reliance on Gazprom.
Swiss-based project company Nord Stream has solely European accounts, but with the payments coming directly from Gazprom export this makes little difference from a lender protection perspective. A truly offshore structure would have seen buyers of the gas paying Gazprom export separate payments for the fuel itself and for transportation, with a percentage of proceeds hived off to a separate offshore entity to pay the project company. This proved difficult, however, with strict Russian restrictions against revenues from gas sales being channelled out of the country.
With the offshore structure ruled out, lenders had to content themselves with the protection offered by 80 per cent multilateral cover, and sought a higher pricing to account for the Gazprom risk that remained. Banks had first been approached with pricing in the 250bp–300bp range on the uncovered tranche, and 150bp–200bp on the ECA tranches.
Inevitably for a project put together in late 2008 and 2009, the credit crisis stamped its mark on the financing. Whilst an early 2008 deal for a project with strong revenues would probably have seen a handful of mandated lead arrangers and quick progress towards financial close, times of high liquidity were gone by the time the project was ready, meaning a huge club deal and accordingly slow-moving process.
Financial advisers Royal Bank of Scotland, Dresdner Kleinwort (pre-Commerzbank rebranding), and Société Générale started sounding banks in January 2009 on a 14-year deal. ECA involvement of some level was already expected, as ECAs had been approached much earlier. When feedback from banks came in in February, the long-term exposure to Gazprom was raised as an issue, with talk of an offshore account structure to avoid it allowing a bank group to be together by May.
As the middle of the year approached with no resolution, a July launch to market was targeted, with suggestions that the tenor could be as high as 17 years. Gazprom was keen to extend the tenor as much as possible, as a longer tenor would lower the amount of the availability payment Gazprom export would need to pay the project company.
The debt was launched to banks in August, with the final structure regarding ECA levels, tenor and onshore accounts emerging for the first time. The ECA-covered portion was set at 80 per cent to protect banks against Russian exposure limits and Gazprom risk, and these tranches had the tenor upped to 16 years to satisfy Gazprom, whilst allowing the 20 per cent of uncovered commercial loan to drop to 10 years to reassure lenders.
Banks were asked to bid on pricing and fees, and given a bid deadline of October 9. Bank meetings in September saw banks disappointed with the onshore account structure, but happy with an indicative model pricing of 175bp and 400bp–450bp on the sweet and sour portions respectively.
The adjusted tenor also compared favourably with other oil and gas mega projects that many desks were looking at at the same time – the Oil Search/ExxonMobil/Santos LNG project in Papua New Guinea that was looking for US$1bn–$3bn of 15-year commercial debt, and the Saudi Jubail refinery that was looking for US$1.4bn of 16-year commercial debt.
With the October 9 commitment date set, sponsors were looking to close by the end of November. Whilst most lenders considered this ambitious, the strong political will behind the project was expected to see the deal done by the end of the year.
The sheer number of banks involved delayed commitments slightly, with €6bn worth of bids coming in. A final term sheet with pricing details was sent to banks in early November, and within a fortnight a 26-strong bank group was in place with the sponsors still hoping for a 2009 close, setting December 15 as signing day.
Final documentation work did not progress sufficiently quickly, however, and the date for final documents to be sent out was revised once to December 23, and then again to mid-February, with an early March close hoped for. The deal eventually was signed in March, before swaps were placed and a full financial close the following month.
The €3.9bn total finances only the first phase of the project, with banks to be asked for a further €2.5bn for the second pipe. Phase two is cheaper, thanks to phase one encompassing both work preparing the route, including landfall in Germany and Russia, and laying of the first pipe, whereas the second phase is just laying the second pipe along the already prepared route.
With phase two an integral part of the project, rather than merely a potential add-on, the phase one financing is structured with the phase two financing in mind. Given that the sponsors are providing completion guarantees, and construction of the two pipes is staggered, Nord Stream needs to be able to source additional financing from lenders that will remain recourse to the sponsors as guarantees fall away on the phase on the financing.
Technical analysis puts the risk of phase two construction work interfering with phase one as minimal. Although parallel, the two pipes are a few hundred metres apart. The major contracts on the project have been let to Saipem (pipe-laying), Europipe (75 per cent of the pipes), OMK (25 per cent of the pipes) and Eupec (concrete weighting on the pipes).