The pace of activity in Europe’s offshore wind market is ex­pect­ed to step up another gear when the UK’s Office for Gas and Electricity (Ofgem) announces a preferred bidder for the Greater Gabbard offshore transmission link. The announce­ment, which follows a long period of delays, will mark the completion of the first phase of a £15 billion ($24.3 billion), three-part programme aimed at bolstering offshore wind generation in the UK by as much as 33GW by 2020.

The award will clear the way for Round 2, with the regu­lator announcing a shortlist of poten­tial bidders, possibly as soon as the end of April, and bolster confi­dence in a pipeline that has at times threatened to dry up amid regulatory uncertainties, shifting poli­ti­cal priorities and tortuous negotiations between bankers and sponsors.

Greater Gabbard sets the tone

Greater Gabbard, the first UK wind farm to be located outside of the coun­try’s territorial waters, was dogged by problems linked to the welding of its monopile foundations, though it is unclear whether this had any bearing on Ofgem’s decision late in 2010 to re-run the tender. Under the terms of the OFTO process, the 504MW farm must be connected to the grid before the 25km transmission cable can be transferred to a buyer. More than half of Greater Gabbard’s 140 turbines are now in place and the plant began generating electricity in January.

Four bidders are in the running to win the deal, including Macquarie Capital Group, which has already successfully bid for three of the nine transmission links available in the current auction round and Transmission Capital Partners, which has won four tenders worth £244 million and which has emerged as a frontrunner to scoop the mandate.

Once a preferred bidder has been announced for Greater Gabbard, attention will shift to three larger transmission projects in the £250-£500 million range which form part of the second phase of Ofgem’s offshore development pro­gramme, scheduled to reach financial close during the first half of next year: Gwynt y Mor (576MW), Lincs (250MW) and London Array Phase 1 (630MW).

A further clutch of projects will also be announced as part of the second round in early 2012 with financial close ear­marked for mid-2013. The third round of the pro­gramme, the biggest with an initial value of up to £17 billion, is known as the “enduring regime” and is seen by many devel­opers as the ultimate prize, involving the design and build of a new generation of offshore wind farms sited in deep water.

Robin Rigg – close on first OFTO

Transmission Capital Partners, a con­sor­tium including Inter­national Public Partnerships Limited, a listed infra­structure fund and Amber Infrastructure, manager of the fund, closed the £78.5 million financing of Robin Rigg, the first OFTO to come to the bank market, on March 1.

Critics claim that delays in closing Robin Rigg lie in part with the fact that bidders did not fully appreciate some of the inherent technology risks until very late in the process. Accord­ing to one banker with knowledge of the early-stage bidding process, some lenders were trying to benchmark the cost of funding to a typical PFI accom­modation deal where there is only a modicum of construction risk and no tech­nology risk. Several banks backed away when the sponsors started target­ing the debt pricing at around 150bp over Libor. That level was seen as overly ag­gres­sive for a path­finder deal and few lenders were surpris­ed when the financ­ing eventually came in at around 200bp over.

However Amber, which manages more than 50 PFI and PPP assets on behalf of INPP, points out that it is comfortable with its risk analysis of OFTOs, noting that the asset class has a potential lifespan beyond the initial 20-year revenue period. INPP adds that it effectively reached com­mercial close last December, but was required to put the terms of the deal out to license under a Section 8A market consultation, thereby delaying news of the deal by around eight weeks. No other deal has yet reached this consultative stage, which effectively addresses any changes to the project’s structure since the initial tender first took place.

That Robin Rigg emerged as the pathfinder deal under the first round of OFTOs is not surprising in itself. The cable, which runs for 12km off the Cumbrian coast, is half the size of that connecting Greater Gabbard to the shore and the link is the only first-round project not to include an offshore substation, thereby limiting operational risks asso­ciated with integrating differ­ent control systems between the wind farm itself and the national grid. Trans­mission Capital further minimised operational difficulties by retain­ing a maintenance team from the cable’s former owner E.ON.

Negotiations at the documentation stage were seen as being relatively simple given Transmission Capital’s decision to appoint a small banking group comprising just Barclays, BNP Paribas and Lloyds.

As more first round OFTO financings reach close the margins are likely to contract – there is no shortage of lend­ers looking to establish relationships in the burgeoning sector, and the predict­able cash flows and lack of construction risk make them a simple proposition to finance.

Further tweaks to financial struc­tures might come if pricing in debt capital markets eases dramatically. As the debt requirements become larger, the potential to use a securitisation will increase, although cautious bond investors are likely to want to see concrete evidence of a project moving all the way through from financing to commission­ing before they participate. It also remains unclear whether the regulatory and compliance costs of bringing a bond to the market would undermine the financing rationale – or indeed whether an offering could be flexible enough to offer the borrower any recourse in the event of an unforeseen interruption to supply. That said, bankers predict that finan­c­ing through a bond will eventually prove anything from 50-100bp cheaper than current rates available through vanilla project financing.

One aspect of the current financial model that might prove controversial, however, is the gearing: at 84% senior debt, INPP will have been required to put considerably more equity into the deal than it might be used to in many of its other ventures, especially given the lack of construction risk. However, going forward, lenders will view the debt to equity ratio as aggressive, considering the tech­nology and interface risks associated with some projects that were clearly not designed with the current OFTO regime in mind. In Europe, where several projects with construction risk have already reached financial close, the split comes in at around 60:40 to 65:35 and as developers in the UK start to eye the big-ticket deals on offer under the enduring regime, the pressure to provide significant contingent equity is likely to prove great.

Regulatory regimes

Although the UK leads the rest of Europe in the development of offshore power, its regulatory framework is very much unique, both in terms of developing the OFTO regime and by way of the Renewable Obligation Certificates (ROCs) that incentivise power generators to develop offshore assets. But just as OFTOs were devised to help lower the weighted average cost of capital by ring-fencing the low risk, low return operation of transmission cables, so too the propos­ed move to switch from volatile ROCs to a feed-in tariff system should also cut funding costs by ensur­ing more stable returns for investors.

Under proposals issued by the De­part­ment of Energy and Climate Change (DECC) in March, regulators would set a feed-in tariff linked to a contracts for difference structure: if power rev­enues fall short, sponsors would re­ceive a subsidy making up the difference to the reference tariff, but if revenues exceed the reference, the regu­lator would claw cash back. By help­ing developers forecast with greater certainty their future revenues, the DECC hopes to make offshore farms more attractive to smaller independent operators and possibly even infrastructure funds.

However, uncertainties over the way the new tariff will be introduced – and in particular, how existing commitments under the ROC system will be honoured, has de­layed the project financ­ing of Masdar’s 20% stake in the 650MW London Array scheme as well as progress on the 270MW Lincs scheme.

Proponents of the feed-in tariff system point to Europe, where various tariffs have been in operation for many years. In Denmark, for example, a reference tariff is set by tender; in Belgium, suppliers receive Eu90/MWh for 10 years and in Germany, operators receive Eu91/MWh for the first 12 years and Eu61.9 for the next 8 years. Meanwhile in the Netherlands, generators receive a top-up payment from an energy agency, which makes up the difference between the price they raise on the wholesale markets for their energy and the tariff level.

In revamping the incentives structure, there is a feeling among some lenders that UK regulators are trying to do too much too soon and bankers are looking for some clarity as to whether there will be a second phase of consultation after DECC officials have had an opportunity to absorb industry submissions ahead of the 10 March deadline.

While many bankers will already be comfortable with the notion of a feed-in tariff regime from their involvement in projects elsewhere in Europe, there is some concern that cur­rent proposals are light on detail. There is little discussion, for example, of how the tariff would change should a future government view the incentive as too costly. It also remains unclear whether a mechanism will be put into place to fix the value of existing ROCs in the years running up to the switch to a feed-in tariff regime in 2017.

Lincs – too optimistic?

The uncertainties appear to be particularly pertinent to banks thrashing out the £1.045 billion financing of Lincs. The project’s sponsors, Centrica, Siemens and Dong, have been holding last-minute bilateral talks with several of the larger lenders involved in the project to come up with a more bankable proposition. The sponsors have been seek­ing aggressive terms from the outset and negotiations have in part been driven by the need to temper their optimism.

As well as concern over the ROC overhaul, the difficulties also centre on a £600 million funding gap left by the departure of the European Investment Bank and the level of construction risk that the sponsors are looking to lay onto lenders. The tensions are understood to focus on 11 separ­ate construction packages and how they interact with each other and are heightened by the collapse into administration of a subcontractor last year. While it is not un­com­mon for European offshore wind projects to carry significant con­struc­tion risk, they typically come with support from devel­opment banks and the apparent departure of the EIB from Lincs, though not yet publicly confirmed, is causing some unease among many of the 15-strong bank club still in the process. In particular, the level of contingencies, which in the original term sheet was set at £130 million, is not thought to be adequate given the complicated timeline for construction and the impact that even a small period of bad weather could have on the project.

A further source of discomfort is the fact that the current level of contingencies does not adequately reflect the lack of an engineering, procurement and construction contractor, which might typically oversee construction on a big-ticket project such as this.

It is debatable, though, whether there is an entity with sufficient experience in the offshore construction sector to even step forward as a credible risk counterparty, regardless of the premium it would need to charge to provide sufficient cover. In established PFI sectors, an EPC contractor may charge anything up to 15% of the total project cost to take on the risk of managing a host of smaller contracts– in an untested market such as offshore wind, that premium would rocket to somewhere north of 25%, even though the number of subcontractors might be as few as half a dozen.

Moreover, there is some reticence among contractors to lose direct contact with their customers as well as a deeply entrenched conviction among developers that they are best placed to manage the construction process.

Sponsors argue that the offshore sector offers phenomenal growth, with an estimated funding requirement in excess of £200 billion over the next decade and that shouldering some construction risk now is a small price to pay for gain­ing a strategic foothold. But while it is true that each new project that comes to the market involves banks with previous offshore experience, it still remains the case that lenders need considerable support from sponsors including undertakings to provide management teams and technical assistance. More­over, the notion that the market will even­tually succumb to a degree of commoditisation does not allow for the constant drive to site bigger and bigger farms in deeper water and further away from the shore. Under the remit of the enduring regime, for example, developers will be asked to consider building clusters of wind farms in large parcels which will require back-up investment in the supply chain all the way back to the shore.

Nevertheless, banks remain uncomfortable with the multi-contractor model and while Lincs looks set to break the mould, the UK market has yet to see an offshore wind project with construction risk get to financial close.

Included in the £1 billion financing for Lincs is a £250 million facility that will be set aside to pay for a transmission link to the shore. The remainder will comprise a 17-year loan of £575 million, a £25 million standby, a £150 million letter of credit, a £20 million working capital facility and a £25 million VAT cover. The debt to equity split is targeted at just under 70:30, which some lenders still view as tight given the limitations on recourse built into the struc­ture. Bankers still involved in negotiations expect the debt to be priced at around 300bp over Libor.

European offshore growth

Elsewhere in Europe, the deal flow is also picking up: in February President Nicholas Sarkozy injected fresh vigour into France’s Eu10 billion ($14 billion) offshore wind power programme by launching a tender for five proposed wind farms in the Loire, Brittany and Normandy regions.

Meanwhile, in Germany, the second largest market for offshore wind in Europe after the UK, the pipeline is encouraging.

Last month, wpd mandated UniCredit, KfW-IPEX and Bremer Landesbank to arrange debt financing for the Eu1 billion Butendiek wind farm just west of Sylt, in the North German Sea. The deal arrangers are now looking for addi­tional support from state banks and multilaterals as well as a guarantee from Danish export credit agency EKF to help finance the 80-turbine 288MW facility.

Unicredit and KfW also worked as lead arrangers on the Eu860 million financing of Borkum West ll in December 2010 – the first offshore wind project in Germany to be delivered through project financing and the first venture to be led by a group of municipal utilities – although the EIB and the State Bank of North Rhine-Westphalia (NRW Bank) provided the bulk of the funding. Borkum West is perhaps most not­able for the speed at which documentation passed through the EIB: in all, it took just nine weeks to sign off the term sheet, though that is testament to the amount of due dili­gence that went into the deal’s predecessor, C-Power’s Eu1 billion Thornton Bank project, as it is to the attractiveness of the deal.

Meanwhile, it is understood that banks involved in the Eu1.3 billion funding of the 400MW Global Tech 1 wind farm are advancing quickly through the final documentation stages and financial close is thought to be very near. The deal is being arranged by Nord/LB, KfW, Societe Generale and Dexia. The 80-turbine park is located 60km north-west of Cuxhaven in the German North Sea and is expected to produce 1.6 billion kWh per year.

Both France and Germany’s offshore programmes are re­defining the template as to what lenders see as being acceptable construction risk and as new projects trickle their way through the pipeline a broad consensus is emerging. Relation­ship banks clearly want to carve a presence in the sector, but they are not willing to buy their way into a deal at any price. The right deal with the right structure will get oversubscribed, but developers are unlikely to be able to squeeze more than 10-20bp out of a hotly contested mandate. Ultimately, the level of debt continues to dictate how strong the structure needs to be and it remains the case that the larger projects now coming to the market will need a broad term sheet to clear credit committees, leaving no room for aggressive financing.

Happy times, nervous lenders

Although the pace of financings might be on the slow side, the outlook for offshore wind development is en­couraging. According to the Global Wind Energy Council, 308 new wind turbines producing a total of 883MW were connected to the grid in 2010 – a near 50% increase on 2009 and a record in its own right. Nine wind farms were completed, with all but one fully connected to the grid, and construction work on a further ten offshore projects is under way. When these are finally connected, Europe’s off­shore capacity will more than double to 6,133MW.

Meanwhile, European policymakers are looking to build on an intergovernmental initiative between Belgium, France, Germany, Ireland, Luxembourg, the Netherlands, Norway, Sweden and the UK aimed at establishing a transnational offshore supergrid. The project will be part-funded by a new financial instrument, which is expected to help plug a Eu100 billion gap between total financing requirements and the market’s capacity to provide funds. European commissioners are looking at range of alternatives, including equity participation certificates, credit guarantees, public-private partnership loans and project bonds and expect to finalise proposals by June.

 Changes to UK wind: Between ROCs and a bad place. By Paul Smith

The period for industry submissions on the Consultation on Electricity Market Reform closed on 10 March. The consultation, run by the UK’s Department of Energy and Climate Change (DECC) is a primer to legislation that will be brought in late 2011 to retire the Renewable Obligation Certificates (ROCs) incentive regime.

The consultation seems a done deal: a feed-in tariff, most likely a contracts for difference model, will almost certainly be brought in. On the face of it, a feed-in tariff should be a good thing. The volatility in the price of ROCs increases the weighted average cost of capital because leverage is limited, especially without a long-term offtake contract. However, the near- to medium-term impact of the uncertainty is a delay to the financing of offshore wind projects. Indications are that the new regime could harm future wind development and there is speculation that the change could also trigger change in law clauses on some existing wind farm financings.

Offshore not well with FiT

While the retirement of ROCs will affect all UK renewable projects, offshore wind is likely to be hardest hit by the changes because ROCs provided sponsors sufficient potential upside for the risks they were taking. Under a contracts for difference regime, technological innovation and calculated risk taking could be stymied.

Uncertainty surrounding the future regime and the government’s plans for grandfathering the ROC regime are causing sponsors to reassess their investment decisions and perhaps renegotiate power purchase agreements.

The retirement of ROCs is thought to be delaying both the project financing of Masdar’s 20% stake in London Array and progress on the Centrica/Dong/Siemens Lincs deal. Credit committee approvals for banks on the London Array deal have lapsed, but providing terms remain the same all the banks are expected to reapprove the commitments. The key question for these projects is how the government will phase out ROCs when the supply-side of the market will be completely removed after 2017. Sponsors on Lincs are also considering on-balance sheet financing if they cannot extract sufficiently good terms from banks.

The DECC proposes giving developers a choice of proceeding with a feed-in tariff or ROCs from 2013 before closing Renewable Obligations (RO) to new accreditation from 1 April 2017. All projects accredited under the RO would receive their full 20 years’ support. Therefore, the entire RO system would be ‘vintaged’ from 1 April 2017. The RO would continue to operate, but support levels in terms of number of ROCs will not change. The closure of the RO to new investment will create a closed pool of capacity, which will decrease over time as it approaches the end date for the RO of 31 March 2037. According to one financier, as an obsolete regime, the long-term price of ROCs is unlikely to be favourable to sponsors.

The DECC is also speeding up the review of the banding of the Renewable Obligation so that the market has more notice of the banding levels in 2013 and beyond. The DECC will announce to the market in the middle of the year the banding for consultation, and the government will give a definitive response in Autumn and the new bands brought into force April 2013.

The rationale for FiT

The UK government is scrapping ROCs to bring down the weighted cost of capital and to open up the market to independent generators and foreign investors. ROCs favour utility-scale investors and while there is a rising demand for capital for renewable generation, it will be met in the context of a shrinking supply of capital from the incumbent energy utilities. According to the DECC: “there seems to be a broad consensus that the existing, vertically-integrated “Big 6” utilities (Centrica, EdF, Eon, SSE, Iberdrola and RWE) may struggle to invest in low-carbon generation at the scale and pace required to meet the UK’s targets between them.” A third of on-shore and offshore wind projects in the pipeline at the moment are being developed by companies outside the Big 6, such as DONG Energy, Vattenfall and Statoil.

The bargaining position of the incumbent UK wind sponsors is weak as they can easily be accused of defending their own interests by protecting the status quo as one of the principal aims of the legislation is to bring new sponsors to UK wind.

The DECC’s proposed new regime is a tariff regime based on a contracts for difference because long-term feed-in tariffs would provide more certainty on the revenues. A reference tariff would be set whereupon sponsors would receive additional payment up to the reference tariff if their revenues fall short, or revenue would be clawed back if they exceed the reference. This model, according to the DECC, should control costs for consumers, provide stable returns for investors, and maintain the market incentives to generate when electricity demand is high.

This last point is important, otherwise generators are not incentivised to generate electricity according to demand. This contracts for difference model of feed-in tariff is used in the Netherlands for all renewables, not just offshore, and in Denmark for offshore wind. It provides a similar level of revenue certainty to a fixed FiT but by setting the level of support according to the average price preserves the efficiencies of the price signal, that is, generators will have an incentive to sell their output above the average price as they will keep any upside.

The DECC adds: “The rationale for choosing the FiT with CfD as a lead option is that it gives the best balance between the Government’s objectives of decarbonisation (including renewables), security of supply and affordability.”

Because feed-in tariffs result in a lower risk profile, they should be more attractive to a wider group of investors – in particular, smaller independent generators and institutional investors. The logic seems compelling: FiTs provide greater certainty on future revenues to investors than the current Renewables Obligation. ROC prices have a floor (the buy-out price), which guarantees a certain level of stability for investors. However, due to the way the Obligation is set at a higher level than expected generation, the value of a ROC is typically higher than the floor price, and this level can vary. Due to this variability, not all of this additional value is included in a project financing base case. Thus the additional value does not necessarily result in higher levels of renewable investment. A different instrument with a fixed level of payment (a premium FiT) could deliver the same level of deployment more cost effectively.

An aim of this policy is to introduce new market entrants. However, offshore wind development is inherently risky and perhaps only utility-scale sponsors or those with the financial clout and project know-how of Mubadala can stomach offshore construction risk. Institutional investors such as pension funds will not touch construction risk. So while the CfD may bring in other large foreign investors, and unintended consequence could be to actually reduce the pool of vaible investors if utilities deem the new system incapable of providing enough upside for the risks. And while this new regime will partially insulate sponsors from electricity price fluctuations a further unintended consequence may be to limit innovation and technology, again, as sponsors are using upside in ROCs as extra equity risk premia.

The evidence for FiT offshore

The overarching issue is that the rewards under the new system are unlikely to match the risks. An example of rewards matching the risk profile of projects is the OFTO (offshore transmission line) programme, where the low risk and low return projects were carved out from the offshore wind projects to lower the weighted cost of capital.

Since 2008, the Netherlands has used a FiT very similar to a FiT with CfD to incentivise renewable technologies (called a “sliding premium” because the size of the premium is related to the wholesale price). Generators have to sell their electricity (either into the wholesale market or under bilateral contracts) and then an energy agency pays them a top-up payment (differentiated by technology) up to the tariff level.

The tariff is decided by the government. Contracts are signed by the energy agency for 15 years. The reference price is the average annual spot market price. The top-up is paid out monthly to facilitate cash flow for smaller generators. It is in effect a one-way CfD, in that if the electricity price goes above the tariff then the generator keeps all the upside.

Denmark has since 2005 operated a feed-in tariff for offshore wind which is also very similar to a CfD model. For major offshore wind farms the required support is set by means of a tender procedure.

There is still a great deal of uncertainty surrounding the new UK renewable incentive regime. It is not clear whether the tariff will be set by a competitive bid or by government. It seems unlikely that competitive bids will be used, as there has been a trend in other jurisdictions to resort to tried and tested technology and a lack of innovation. The reference tariff is likely to be indexed to inflation and could be banded in similar way to the Renewable Obligation to take into account changes in technology, costs and the depth of water for offshore wind plants. Besides how the reference tariff will be set, there are other uncertainties such as who will be the payer/payee of the tariff, how the system will account for variable output (the imbalance risk of what a generator nominates it will generate and what it actually generates) and how grandfathering the ROCs would work. And it will be impossible for wind generators to time their dispatch over the average wholesale price to achieve a higher return.

Sponsors and banks on existing wind financings are also consulting lawyers as the changes to the incentive regime could trigger change in law clauses on some deals, which in a worst case scenario could see banks attempt to renegotiate terms.

Nuclear benefits – does anyone else?

The retirement of the Renewable Obligation seems designed to help develop baseload nuclear capacity, but the consequences of a one-size-fits-all approach could be severe for the UK wind industry. A cleaner more transparent solution would be to offer a fixed feed-in tariff, as in the German and French regimes. This would cost the consumer more but it may be better than the unintended consequences of a CfD regime: reduced wind developer activity and a reduction in the use of new technology.

The Department of Energy and Climate Change proposals

– Key points

• Introduce a feed-in tariff based on the contract for difference model from 1 April 2013

• Provide developers with a choice between the CfD and ROCs until 1 April 2017, when new accreditation of ROCs will end

• Publish the new RO banding for post-2013 by the end of 2011

• Grandfather the RO until 31 March 2037