Centrica, Dong and Siemens are out to the bank market with the Lincs offshore deal, as is C-Power with its 295MW second phase of the Thornton Bank project, and Masdar is close to signing a £330 million ($519 million) loan for its share of the 650MW London Array scheme. The first OFTOs have also been awarded, and in January The Crown Estate issued its Round 3 offshore licenses, in effect creating a pipeline of upcoming projects for the debt market.

But the growth of offshore wind is not a given. Wind levels experienced this year have been consistently lower than forecast. Furthermore, the technology risk, slow moving supply chain, insurance and bank liquidity concerns are all potential hurdles; and although the sector has political impetus behind it at the moment, that political backing could yet dissipate if consumers are unwilling to pay the higher price of offshore generated power whilst it develops the technology to become competitive with other forms of generation.

Offshore is expensive – the UK Energy Research Centre (UKERC) claims offshore capital costs have doubled since 2003 and are now around £3 million/MW. It is an increase already recognised in the offshore ROC subsidy, which was increased in 2009 to 2x until 2014. To get back down to the previous level of 1.5x the UKERC estimates capital costs will have to drop by 18%.

On the upside the UKERC is optimistic about “meaningful cost reductions” by the 2020s with the possibility of a 40% drop by 2025. And developers, lenders and politicians are agreed that offshore capital costs will come down, that the UK market is an exceptional wind resource, is the scaleable renewable market and has the stable support mechanisms in place to attract long term debt and the large-scale utilities with which banks are keen to service relationships. But there the consensus ends.

In the lending market banks are being challenged by the first deals without construction guarantees – projects with construction guarantees are on-balance sheet for the developer and hence eat into the capacity for future project development. Initial lender reaction has been positive tinged with caution, for both the Lincs and C-Power deals. The risk is very real – the Greater Gabbard scheme has been hit by faulty monopiles manufactured in China, and Siemens is making repairs to early versions of its reliable 3.6MW offshore turbine at the Burbo Bank farm.

Both C-Power and Lincs proffer slightly different challenges to banks. C-Power claims phase 2 of the 31 billion-plus Thornton Bank project is an expansion and, given that phase 1 is already operating, it has a construction track record with the same contractors on phase 2 as phase 1. However, the expansion is from an existing 30MW to a further 295MW and C-Power is putting up limited sponsor support in the form of contingencies to cover construction risk up to £180 million.

The £1.045 billion 270MW Lincs financing is a greenfield project and includes £250 million to fund the OFTO part of the scheme, which will be sold and the debt repaid early. The debt facilities include a £70 million base case contingency and a £60 million risk contingency and a £50 million combined debt and equity standby facility.

Some lenders have expressed concern that although Siemens is providing tried and tested turbines for the project, there is no single EPC. Centrica argues it is best placed to manage the contractors and has offset concerns over construction risk with a project financing designed to attract lenders – a 1.5x debt service coverage ratio and 90% of the project’s income from PPAs and ROCs with Centrica and Dong.

The coming year will not only be a test of bank appetite and willingness to take risk – it will also be a test of the practicality of the new OFTO regime – for both offshore wind farm developers and lenders – the willingness of the supply chain to take the investment decision on new offshore wind designs and manufacturing facilities, and the ability of sponsors to meet the challenge of raising off-balance sheet financing.

Meeting the targets

Sean Keating (Project Finance): What is the biggest threat to meeting the UK’s renewable targets – economics, ROCs versus feed-in tariffs, supply chain, corporate finance, bank liquidity?

Daniel Nanson (Centrica): In the short-term bank liquidity is possibly a problem – but it is fixing itself. The supply chain is reacting a little slower than we would have expected, but given the level of definite projects around the industry, we view that it is reacting.

The primary issue is the economics of offshore – the cumulative impact on the economy of these costs. The increased costs going to the consumer who will eventually pay for all this investment. We see that as potentially one of the biggest threats to what is a very new industry.

Whether there’s enough sponsor balance sheet for fast-paced offshore development is also a big issue. If you look at the amount of spend that has to happen and the headroom that the large corporates have, there’s a disconnect. It is something we’re reacting to and we are looking to diversify funding solutions.

Andrew Doyle (RBS): That’s a common theme across a lot of the utilities in the UK market. Centrica is using project finance on Boreas and now the Lincs deal. SSE is looking to divest certain wind farms that they deem non-core. RWE is looking for partners in some of its projects, and EDF is also divesting its wires business. Rather than just relying on balance sheet funding, these large utilities are looking at alternative sources of finance to deliver the projects.

James Whittall (EIB): It is not just an issue of funding. The UK market together with Germany is going to account for 70% of the offshore wind market. But as other local markets grow there is going to be pressure for the UK to compete not just for capital but the rest of the supply chain.

Matthew Knight (Siemens): Do you think most of the large utilities are taking a pan-European strategy towards renewable energy, and particularly to offshore wind? All the signs I’ve seen recently point towards a pan European view. That means developers will have several projects in the pipeline and can flex between countries depending on which has the best subsidy.

Daniel Nanson (Centrica): It will depend on the strategy of the developer. Centrica looks mainly to have the offtake, the PPAs and the assets as part of its vertical hedge. The more we can vertically integrate, the less risky our business and we’re looking to have some of that integration come from renewables and low carbon sources. So for us, we were probably motivated to do offshore in the UK where our existing consumers can plug into that power.

Sean Keating (Project Finance): Is that pan European approach hampered by banks who have a national centric view at the moment?

Daniel Nanson (Centrica): No. I don’t think there’s any project finance bank that would only lend in the UK – the capital as well as some of the developers appear to be international or pan-European in their approach.

Andrew Buglass (RBS): That’s largely right. There is a degree to which many banks, RBS included, are focusing more on their home markets, because in an environment where you have limited balance sheet you will naturally go where you’re most comfortable with the regulatory regime, where you have the highest proportion of customers and existing corporate relationships.

Daniel Nanson (Centrica): In addition, whilst we are seeing foreign funding coming in, it might be tied to some of the sponsors.

Matthew Knight (Siemens): Do you think that trend poses a bit of a threat to the countries that are coming to offshore a bit later? For example, if you’re Poland or Estonia and you’re trying to do your first project, just when the rest of Europe is really busy, supply chains and finance may be constrained. They will look first at countries where there is a proven model.

Andrew Buglass (RBS): True – but it could be mitigated as offshore wind projects become mainstream and standardised. The cookie cutter approach helps banks get over their fear of the unknown.

James Whittall (EIB): As the sector grows you will see more commercial banks getting comfortable with the types of risks they’re facing, and there will be new entrants coming into the market. I’m sure a capital market solution is a possibility at some point in the future, although we’re still waiting to see that, even in some of the more traditional project sectors.

Alastair Dutton (The Crown Estate): What are people’s views on capital market solutions? There is an element of flexibility with bank debt that is lost on a capital market solution – can those solutions fit with utilities?

Daniel Nanson (Centrica): In the short to medium term we view banks’ concentration risk as a potential obstacle to raising capital, and we see a need for fresh equity and alternative debt sources. The more those alternatives are used, the more sponsors will be able to adapt to the loss of flexibility. Of course there’s not yet a lot of project flow to create a new debt market, project or secured bond or otherwise.

Supply chain issues

Sean Keating (Project Finance): The discussion up to now has been all about the financing challenges. But the supply chain has also been identified as a big risk in meeting targets – will it be a determining factor?

Alastair Dutton (The Crown Estate): We commissioned a supply chain gap analysis at the beginning of 2009 and the answer came back, “if the economics are there the supply chain will be there. This is an industry that could become the size of oil and gas.

Sean Keating (Project Finance): But can the costs come down in the future?

Alastair Dutton (The Crown Estate): Yes, although a lot of work is needed. Studies talk about a 10% per annum learning curve. But you need to break it down into the components and drive the vectors of cost – and we’re starting to see that come through now.

Lack of skilled personnel is also an issue. We don’t have an offshore wind industry with a dedicated training programme because it isn’t big enough yet. It’s also not clear who should be leading on it. You need one body, and you will probably see that appear in the next six months.

Chris Veal (Transmission Capital): There’s a design challenge as well. At the moment offshore technology is very similar to technology onshore. But in theory you should be able to design things specifically for offshore that require much lower maintenance and hence, cost.

Andrew Buglass (RBS): And as we develop clusters of projects, centralised supports and services that can supply multiple projects will emerge. There’ll be some challenges from a financing perspective over how we, as lenders, get comfortable with that, but it’s been done before and is not insurmountable.

Alastair Dutton (The Crown Estate): What we’re now seeing is technology starting to be developed for the industry, rather than borrowed from other industries, which should up reliability. There’s also the construction side and the interface between companies where you’ll see much more skilled applications developed. Confidence is rising. Just two years ago offshore was a great story. Now people talk about how they’re going to do it, not if they’re going to do it.

Matthew Knight (Siemens): But there is still a caveat to development; the strength of the supply chain from the middle of the decade will be based on investment decisions that suppliers make this year. Those decisions could be disproportionately influenced by trading conditions now, rather than expectations for tomorrow.

That said, in the run up to Christmas 2009 a lot of supply chain investment decisions could have gone either way. Since then most have opted to go with offshore investment. But people are still taking cautious investment decisions – if they’re building a factory they’re doing it in phases with the opportunity to expand later.

Development is also very sensitive to the short-term politics and short-term weather in the industry – a year of wind levels below forecast can influence an investment decision.

Sean Keating (Project Finance): Is there anything that could be improved immediately to boost deliverability in the supply chain?

Alastair Dutton (The Crown Estate): Port development is a major issue. The competition for £60 million of DECC funding for offshore wind port upgrades is a start. But getting the supply chain to shape itself around the big ports is going to be the next big step.

Regime change?

Sean Keating (Project Finance): There is a concern over changes to the UK ROC regime. How much stability is needed in terms of regime and the length of that stability – 10 years, 15 years – to get these offshore projects done?

Andrew Buglass (RBS): Stability is critical to banks because we’re entering a long-term commitment and we need the long-term cash flows to ensure repayment. We must be able to convince ourselves and our management that whatever regime changes there may be, they will be done in such a way that is not discriminatory, that they grandfather what’s gone before, they don’t fundamentally change the economics of the existing projects and they form the basis for a solid, sustainable business going forward.

There’s a lot of debate about whether feed-in tariffs would be better than ROCs? It doesn’t really make a big difference from our perspective because we have, over the years, financed around 8.5 GW of renewable capacity in a variety of different regulatory regimes. We can work with pretty much any sensible programme.

My concerns, if we were to go down a path solely towards feed-in tariffs, are twofold: First, fixed costs to government – where governments can look down a budget, see a high line item of cost and say, “we are in economic constraint, that looks expensive, let’s cut it,”. That exposes the projects to more political risk than a more market based system such as ROCs,

Second, if we are to change systems midstream it could take a year-plus of consultation; a year to put the law in place and implement it, and another year for investors and lenders to digest the changes – in effect three years of stasis that no-one can afford.

Although ROCs are not perfect, they have a lot of benefits and we understand them and know how to finance on that basis.

Daniel Nanson (Centrica): The government support and the stability of that support is absolutely critical over the long term. We are quite happy with the Renewables Obligation consultation given they’re showing continued support for the ROC, at least on a grandfathering basis, while they look at other alternatives.

Regime change, whilst it might net out to be indifferent [to financial investors?], would be very difficult to implement because it trickles down and affects things like PPA pricing. And anything that can be done to reduce investor uncertainty is a must at this critical point in the offshore market’s development. Therefore continued government support for the ROC regime, or something that works as well, is absolutely mandatory for the long term.

Chris Veal (Transmission Capital): Independent developers would prefer to have feed-in tariffs for offshore wind because they don’t have supply business and often need to present banks with a very secure PPA to get finance. But they’re a small group, and getting smaller.

Sean Keating (Project Finance): How much do The Crown Estate get involved in the tariff debate?

Alastair Dutton (The Crown Estate): Being a public body we have a slightly different conversation with government than lobbyists – we help government understand all the issues proposed changes generate. While governments recognise the fundamental needs and hurdles to meeting UK targets, they are not always aware of the unpublished cost vectors – water depth and distance from shore for example, which are both recognised in the German scheme but are not recognised in the UK one.

The risk reward equation

Sean Keating (Project Finance): Given the risks involved in offshore wind do the bank margins on offer – 200-300bp for example – adequately reflect that risk – particularly those with construction risk like Lincs?

Daniel Nanson (Centrica): I’m still struggling to see how 200-300bp is cheap given offshore wind is a huge growth sector. The banks that get involved and get competitive now are going to have a very good position going forward – there is an estimated £200 billion-plus of offshore wind to get financed.

Martin Benatar (JLT): We talk as if there is lots of funding going into offshore wind and yet there’s not been a single UK offshore wind project with construction risk project financed to date. Offshore wind is a very new industry where people who aren’t directly involved in it think that the technology hasn’t developed enough to attract decent funding levels. So when people talk about banks taking construction risk and pushing it off to the bond market, there’s still quite a way to go.

As to how the active construction risk is going to be taken, it’s ironic that the EIB, who didn’t used to take construction risk, might be the key factor in getting construction risk taken.

The construction area, in terms of supply chain, still looks very problematic. You’ve got a lot of people sitting on the sidelines waiting to learn from others mistakes before they invest. So, rather than the people who are in now getting all the benefit, they’ll come in, be able to offer cheaper terms and get lower debt pricing.

Daniel Nanson (Centrica): Possibly, but if you’re involved at the beginning it gives you a better competitive position – it doesn’t put you behind the others who come in late, it puts you ahead of them in terms of depth of understanding of the risks.

Alastair Dutton (The Crown Estate): Companies are now investing in equipment specifically for this sector, that equipment allows you to construct all the year round thus cutting construction risk.

Andrew Buglass (RBS): It will be some time before accepted lender practice is to take unmitigated construction risk. It took time in onshore wind and with the new generation of gas turbines in the early 1990s.

The only way to build lender comfort is to have the earlier projects provide a little bit more in terms of support and a little bit less in terms of aggressiveness. Once projects become commoditised, more bank competition will come in – there’s a limited number of banks at the moment that are prepared, or able, to take that risk allocation.

There is a further caveat. Because the offshore projects are big and there are relatively few of them, and because projects will go a little bit further offshore as the market develops, banks will not only have to get comfortable with generic offshore risk but the concept of funding deals in 20m of water, or 40m or 65m, with a different type of technology and a different set of challenges. It’s quite a big ask to expect both developers and lenders to get comfortable with risk on a project in 65m water based on experience of a project in 20m water for example.

Alastair Dutton (The Crown Estate): In recognition of that, the design of Round 3 development agreements are to have large zones that allow developers to think through a portfolio – to move from single projects to a sequence. That means that you’ll get investment in ports and in the supply chain as well.

Martin Benatar (JLT): But initially wouldn’t it have been better to start with some smaller projects? From a funding point of view it’s much harder to get one billion on the table. Maybe if it was a little more restrained initially it would enable for a quicker development long term.

Daniel Nanson (Centrica): You’re right except for one thing – we do have other funding alternatives. At the moment we can absorb the size of tickets required internally, so there is still competitive pressure on the banks to give the right level of offer, the right participation. But as the market expands that internal funding becomes more difficult. Hopefully, as the volume of large ticket deals increases, that will move in step with bank appetite. If they get out of synch some developers could be in a very tight position.

Martin Benatar (JLT): Can contractors cope with that – with building 400 MW of brand new turbines that have never really been tested before?

Matthew Knight (Siemens): A wind farm is made up of multiple wind turbines and multiple loops of cable, so provided you’re not putting them out there with a type fault, doing more is just about volume and time.

Block size is limited by finance as much as it is by electrical engineering – by how much can you put in in one season or a couple of seasons and how big a grid connection you’re going to build. Up to about 500MW, one utility, or maybe a couple of utilities acting in consortium, have been able to finance the early construction stage, and in the future the banks will get more comfortable and will come into that.

Personally I wish we had the chance to do Round 2? before we got to Round 3. But the benefit of Round 3 in terms of repeatability and opportunities of scale is clear.

Chris Veal (Transmission Capital): But as you get bigger and bigger wind farms, so the number of contractors that have big enough balance sheets to stand behind their contracts and the warranties of those contracts, shrinks as well.

Matthew Knight (Siemens): Yes, but the standardisation and commoditisation of technology and will bring greater numbers of competitors in as we go forward.

Sean Keating (Project Finance): There are three deals in the market at the moment. Two of them – Lincs and Thornton Bank – have no construction guarantees while Masdar’s share of London Array has got guarantees. Are there any alternative means of handling construction risk so that it isn’t necessarily passed on to the commercial lenders?

Daniel Nanson (Centrica): One of the limitations on offering construction guarantees is ratings headroom – if you can’t get the project completely off balance sheet there’s very little motivation to go out and spend the higher margins for a hybrid project finance solution, or higher than your corporate debt margin at least.

We’ll see a natural evolution towards different financing solutions that take projects truly off balance sheet. But getting that off balance sheet treatment with an all-encompassing construction guarantee is impossible.

Paul Smith (Project Finance): So effectively banks will be taking unlimited construction risk? Is that the aim?

James Whittall (EIB): Until the industry has demonstrated a consistent ability to deliver projects to budget, on time, banks will always be hesitant to take unlimited construction risk. There is going to have to be some support, at least initially, to bring in a sufficiently large number of banks to fund some these big projects.

Daniel Nanson (Centrica): It will depend on the project as well. If you’re dealing with a project where you’re effectively carbon copying a previous project in roughly the same geographical area with the same contractors, it’s probably the right time to test the market. If you’re going into a completely new physical area and a completely new technology, a completely new contract interface strategy with completely different contractors, then it would be a harder sell.

Andrew Buglass (RBS): There’s a world of difference between the phrase ‘unlimited construction risk’ being accepted by banks and the other extreme of that risk being taken totally by the project developer. Reality lies in the middle somewhere and will move more to one end of the spectrum or another depending on the project.

Banks in these early projects will need some form of additional support because they will run the “what ifs” – if there’s a delay of X months, if there’s an overspend of Y% – and will need to know those contingencies are covered. I don’t think they will expect hell or high water cover, but I do think they want more than just saying the contingency is X and then it stops.

Chris Veal (Transmission Capital): The traditional way of doing this is to use a construction contractor that will provide a wrap. Is that something Centrica thinks is not going to be cost effective?

Daniel Nanson (Centrica): We view ourselves as the best people to manage all the sub-contractors. By managing the construction ourselves we’re able to identify issues and mitigate them very early on. Under EPC contracts, in our experience, that doesn’t always happen.

James Whittall (EIB): EPC contracts just shift the risk from a sponsor with an A- rating to a contractor that often doesn’t have as strong a rating as the developer. So EPC contracts are not necessarily the solution to the construction problem.

Andrew Buglass RBS: And it comes at such a huge price premium that it makes the project much less economic. An EPC contractor can add 10-20% to the project cost to take that risk.

Matthew Knight (Siemens): As a large contractor we like to deal directly with our customer, and it’s in our interest to offer as big a package as we can and to encourage the complementary parts of that package to be offered by as few other single parties as possible and reduce interface risk. In traditional project sectors, one big EPC managing a hundred little contracts adds a lot of value. But offshore wind is about a handful of large contracts put together in a competent way. We’re getting more flexible about where we draw the boundaries of our scope so that it makes it easy to create an interface between us and say a foundation supplier.

The OFTO system

Sean Keating (Project Finance): With the first four OFTOs awarded, what will be the impact of wind farms and transmission lines being owned and operated by different parties?

Chris Veal (Transmission Capital): Obviously we think it’s a great transmission regime and has been structured well to make it a very low risk investment opportunity for banks.

In the operational phase the incentives on the OFTO are really quite strong. The OFTO does get hit reasonably quickly from an equity perspective if there’s a drop in the availability of the OFTO assets – it only takes a few months outage, say for a cable fault, for it to lose 10% revenue which could affect the equity return fairly quickly. So there is a strong incentive on the OFTOs to make sure that they’re available and to use mitigation such as insurance against uncontrollable events.

Some of the first round OFTOs are going to be maintained by the wind farm owners anyway. So I don’t think the offshore wind farm generators should have a lot of concerns about the operational assets – they will be operated and maintained to a good standard, and the incentives are right.

However, the issue of whether the incentives are right for new build is more complex. We’ve been involved in the discussions that have led up to Ofgem’s recent consultation on the generator-build option and it seems that they will probably have that option.

Our view in the longer term is that it is probably not the right thing for the generator to design and build the assets, but we can understand why, at the moment, it’s the thing that will enable generators to get comfortable with the regime and allow their projects to proceed.

The OFTO should be involved in the design and build of the assets in the longer term and there should be significant benefits from OFTOs doing that given that – the OFTOs are transmission specialists and can bring in a lot of innovation and new competition into that area.

Andrew Doyle (RBS): Do you see generators managing the transmission construction but bringing in people like Transmission Capital in to help build the things ahead of an asset transfer?

Chris Veal (Transmission Capital): That adds another layer of management into a project. We provide advisory services to generators on the design and development of the project as well, but it is less likely we’d provide that for the construction. There needs to be some incentive on generators to move away from the generator build option, and the most obvious way of giving them that incentive is to provide them with some financial compensation if the OFTO is late in delivering. We would advise Ofgem and DECC that they need to build into the regime some compensation for the generator if the OFTO is late in delivering.

Andrew Buglass (RBS): From a financing perspective the risk allocation between OFTO and generator is one-way. If the OFTO is built but the wind farm is not ready, the OFTO gets paid; the converse is not true and in that situation the wind farm won’t get financed.

The generator build option does address that issue. Although some form of compensation for the generator is a good idea, in my experience having two projects linked to each other and yet separate, is hugely complex. It costs more and takes longer.

Matthew Knight (Siemens): Generator build is definitely the least worst option for the generators. It’s not something they particularly seek to do because they’ve got to raise that extra chunk of finance and manage that process.

And there are several things that, in the long term, if we get the regime right, will allow for OFTOs to build. The key thing is the trigger to start the consenting and building process needs to be sufficiently early that consenting and building is ready on time: At the moment the regime is founded upon the idea that nothing will happen until the users have committed, and the users can’t make that level of commitment until they are certain. The lead time for the grid connection is that much longer than it is for the rest of the wind farm, and the grid connection’s got to be there first, which is what causes problems.

National Grid has changed the game again in the last couple of months by producing its concept of a coordinated network design. It has put together a strong argument: if you design the whole offshore network in a coordinated way you will save 24% of the capital cost.

That obviously chimes well with the government at the moment, but it’s only the right answer if it doesn’t delay or damage offshore wind.

The OFTO regime needs to be able to cope with the fact that there will be one developer who is ready and needs a grid connection for project number 1 in 2015, and the economic way to connect that is to build something that’s also big enough for project number 2 that’s not coming until 2017 and whose sponsors can’t possibly give you 100% commitment that it’s going to happen. Somebody needs to be in a position to say, ” the balance of probability is that project 2 will come along, and if it doesn’t, 2A or 3 will, and they’ll use up that spare capacity.” That’s the emphasis Ofgem has had so far – timely building and getting the absolute cheapest price rather than avoiding the stranding of assets.

Paul Smith (Project Finance): It’ll be interesting to see what the government comes out with in terms of the carbon capture and storage competitions, because that has parallels. If you’re going to build one pipeline do you size it just to assure the demonstration projects or do you size it to allow for future developments?

Matthew Knight (Siemens): Sizing for future developments is only possible if somebody takes stranded asset risk, and in the final analysis that will be electricity consumers via the regulator. There are two ways for the regulator to take that risk on the consumers’ behalf: either the regulator says, “you build it, you get paid” or it gives someone the franchise for a whole area at an enhanced rate of return, so that they can take a commercial risk on building capacity for future projects.

I much prefer the first option because the rules are clear; the second option, otherwise known as a ‘give it all to National Grid option’, will be a commercial decision made by one company behind closed doors.

What should happen is that NETSO (the UK system operator) needs to decide on the balance of probability the size of an asset that is needed, with the first generator that needs the first element of that asset triggering that process. It is then for Ofgem to accept the rationale and appoint an OFTO to build the whole bigger asset or not.

Chris Veal (Transmission Capital): We do agree that there does need to be some sort of design authority that takes a wider picture of what needs to be built.

Sean Keating (Project Finance): Some banks had OFTO financing bids returned to them as being too expensive. What’s your take on the OFTO in terms of financing going forward?

James Whittall (EIB): Once the first round OFTO projects have closed, and the market becomes more familiar with the structure and risks associated with these deals I would expect margins to fall. Fundamentally banks believe in the investment case, it is just a question of their credit committees getting more comfortable with the risks.

Andrew Buglass (RBS): OFTOs are attractive assets, they’re very predictable cashflows, there is limited operational risk for the transitional regime, there’s no construction risk overall, it is a fairly simple proposition in terms of the cashflows attached to it.

What’s been interesting is that a number of different banks have chosen to either tag this as an infrastructure project or as a power project. As a result there have been some different approaches to risk taken by different banks.

Sean Keating (Project Finance): So are we saying that the general bank response at the time was wrong – that the risk wasn’t there to qualify for higher margins?

Andrew Buglass (RBS): These are availability based projects and benchmark quite well to some of the availability based PFI projects. Therefore you would think that there would an element of similarity in pricing. Actually there has been a bit of a difference in pricing, with the OFTOs bid more aggressively than a lot of the PFI projects that we are funding at the moment. It’s interesting to speculate on why – perhaps it’s because OFTOs form part of a wider market that we as lenders want to be heavily involved in, and therefore it’s more strategic to be involved in a significant way in an OFTO than it is perhaps to fund a PFI project.

James Whittall (EIB): A lot of banks will be looking to OFTOs to fill at least some of the expected drop-off in PPP volumes, which is why we will see further interest in the sector and competition between banks.

Sean Keating (Project Finance): Is the current interface risk, or the mitigants towards it, acceptable to lenders? Novation of warranties, the insurance issues, the legal risk – they all seems quite messy at the moment.

Andrew Doyle (RBS): The challenge with the whole OFTO process is that different developers structured the OFTO warranty packages in different ways. So you’re trying to get a degree of homogenisation where there are differences and where the technical due diligence on each project is slightly different.

Now that people are being awarded preferred bidder status it makes it a lot easier, because at least you know which deals you’re looking at and you can focus on the project specific issues; before that the process was badly designed because banks were being asked to support transactions without really knowing which assets they were going to end up supporting – that was a challenge for lots of credit committees.

Chris Veal (Transmission Capital): So you would prefer to come in after the preferred bidder has been appointed?

Andrew Doyle (RBS): It would have been simpler. I certainly had a challenge with my credit function of trying to say, “this is how much we’re looking to lend in total, but we’re pretty sure the sponsor won’t win all of these assets and we think that Ofgem and DECC want a bit more competition in the market”. But you had to go in with the bigger number in support of the bid because developers were looking to win all of them.

Andrew Buglass (RBS): And the bank has to allocate capital based on that commitment – so it’s an economic decision as much as anything else.

Chris Veal (Transmission Capital): Is there an issue for banks on valuing the assets on projects where the generator’s building out the transmission line and then selling the OFTO later?

Andrew Doyle (RBS): It’s something that we need to get comfortable with, that the transfer price does accurately reflect the cost to the developers and that assets are not being transferred at an inflated price. Ultimately the tariff is there to provide buyers with comfort.

Chris Veal (Transmission Capital): But as a buyer of what is effectively a 20 year revenue stream that is fixed and in the licence, the important thing to us is not just what the asset originally cost the seller to build but what it’s going to cost to keep it going for the next 20 years.

We have a pretty good idea of what these things cost because we’re in the market. And our view is that developers have done a reasonably good job on the valuation.

Andrew Doyle (RBS): The bigger risk for lenders is projects where you’re being asked to fund the wind farm and the OFTO element without knowing how much the OFTO asset will be sold for, or even when it will be sold.

Daniel Nanson (Centrica): From a funding standpoint it does bring an additional risk to the banks, many of which have very different views on it as well, which doesn’t help. We have to have construction contracts clearly delineated between the wind farm and OFTO elements, so that the costs for the OFTO are clear and at a fair and efficient price.

Delays become an issue, as you’re aware, but then there’s also the ability to put in the rolled up cost of capital into the RAV, the interest on that delay, so there is a motivation to get these done. If we end up having a very expensive OFTO and selling it, the Transmission Network Use of System (TNUoS) charge gets higher for the project as well. So there is a motivation for us to keep that cost down because obviously the TNUoS impacts the margins on the operating side.

Martin Benatar (JLT): From the insurance side, the OFTO regime costs wind farm developers because their policies have to have provision for potential revenue loss caused by a third party OFTO – it is phenomenally inefficient and the cost to the generator goes on to the consumer. The way the OFTO regime has been structured means that for wind projects to have the kind of protection they thought they would have, insurance costs for operations will be double what they expected. Although there is the opportunity for the wind farm owner and the OFTO to work together on placing their insurances, possibly place them with the same underwriters.

Insurance and Green Bank development

Sean Keating (Project Finance): What are the biggest hurdles to creating cheaper offshore wind project insurance?

Martin Benatar (JLT): At the moment there are very few offshore wind farms that have actually been built. Therefore you just don’t have critical mass of premium coming in to deal with the claims that are already being seen. Because there’s no critical mass it’s totally skewed, you only need relatively small losses to make it look unattractive and there have been a number of claims over the past two years.

Then there is the global insurance market context. There is phenomenal capacity at the moment, but if the global situation turns nasty for insurance companies, which it has to, and should have done about a year ago, the appetite for all sorts of risk is going to become more restrictive and more problematic.

Within that market context you’ve got insurers that are very keen to get into offshore wind. But what they don’t want is to put their capacity into projects that look problematic. So it depends on the experience of the first projects, and whether the anticipated surge of premium meets expectations.

In terms of policies – the insurance programmes you can get farm an offshore wind farm should in theory protect to the same extent as an onshore wind farm. Fortunately you don’t have things like defective worlds exclusions, although the underwriter will try and push those on, especially as you move to the jacket foundations because there the only real risk is defective welding.

Then there are quality assurance issues like those on Greater Gabbard for example. The big concern is the serious loss, the serious defect. But there are others like the delay risk due to the unavailability of a specialist vessel due to loss or damage – it is an insurable proposition, but no one’s prepared to offer it.

Brokers aren’t serving the offshore wind industry in the best possible way. There are only two teams that are dedicated to offshore wind and renewables. They are trying to get the market developed, but there are so many areas where insurance product for offshore does not yet exist.

For example why hasn’t an insurance solution started to be talked about in meaningful terms that deals with contingent business interruption risk for stranded assets? Specialist vessel protection, loss or damage away from the project, or on the project, could be tied in to the people who own the vessels, so that they can offer wind farm developers some sort of compensation if they can’t be available.

To sum up, the insurance industry is providing an extremely healthy extent of insurance apart from the areas that really matter.

Sean Keating (Project Finance): Will the Green Investment Bank idea for the UK become a reality and how would you like it to function?

Daniel Nanson (Centrica): The GIB could play a very important role in recycling capital and in supplying an alternative capital source. We hope that is what it will provide, so that we’re not totally reliant on the current funding providers and funding models.

Andrew Buglass (RBS): We’ve been asked by government to give our input to the process as well. Potentially it could be a very beneficial body, but at the current level of capitalisation that’s being talked about, I don’t believe it will be in a position to provide any material funding. It will function more as a catalyst and a conduit.

I hope banks will be able to look to that body to aggregate the loans that they have written, or will be writing, and distribute them to a different set of investors. It’s easier to do that on an industry-wide basis than it is for each individual bank, because if you’re talking to a large pension fund they may want 300-500 million of exposure in easy chunks, and the nature of these projects is that it will take some time to build that mass bank by bank. Using pension funds would also addresses any future balance sheet congestion point.

The Green Investment Bank can also, and should, play a valuable role in some of the newer technologies – a VC role, which is probably very ill served at the moment. Funding for things like tidal and marine power is not going to come from commercial banks for a very considerable period, principally because it’s unproven technology and we don’t finance that on a senior debt basis.