Financing offshore wind: Plain sailing?

According to WindEurope, a trade organisation for the wind industry, Europe's total installed offshore wind capacity increased by 23 per cent in 2017. Europe is now home to more than 4,000 offshore wind turbines across 11 countries. Thirteen new offshore wind farms were completed in 2017, with the UK and Germany leading the way. 

The offshore wind market is also developing rapidly in Asia too.  Taiwan held offshore wind bid rounds in April and June 2018, and in doing so it has met its goal of awarding 5.5 GW of offshore wind capacity to be developed by 2025.  Denmark's Orsted completed financial close on its first Taiwanese offshore wind project on 8 June 2018.  Other markets, such as Japan, are not far behind: in March 2018 Japan introduced a new law designed to facilitate the development of offshore wind projects. 

This surge in wind projects is being sustained by a change in the economics of offshore wind power generation.  As shown by figure 1, setting out the strike price for recent UK offshore wind auctions, the market has become much more competitive in a short space of time.

Figure 1 - UK CfD strike prices for offshore wind

 

This boom in offshore wind development has been underpinned by increasing interest in the sector from financial institutions.  Whereas many of the earlier projects were financed by major utilities on balance sheet (and indeed some developers still prefer to pursue an equity finance route), there has been an increasing use of limited recourse debt financing to fund these projects.

This article seeks to highlight some of the features of this recent financing boom, drawing on Ashurst's practical experience of advising sponsors and funders across the UK, France and Germany.

Legal due diligence matters

As with any project, potential funders will need to understand the key risks if they are being asked to fund a project's construction on a limited recourse basis.  Many of the risks are similar to those applicable to other forms of conventional or renewable power generation.

Land, planning and grid

As with any generation project, acquiring the necessary rights to land, connecting to the grid and obtaining the necessary permits is fundamental.  For the developers, undertaking these activities on an offshore wind project can be a time-consuming process.

In relation to land rights, acquiring land rights offshore will inevitably involve interaction with the national or regional competent authorities responsible for the ownership and management of a country's offshore domain, and some form of participation in a tender competition to acquire those rights.

In relation to grid connection, responsibility for constructing the necessary connection to link the wind farm with the national transmission grid varies.  For example, in the UK, it is (invariably) the developer of the offshore wind farm who assumes the obligation to construct the cables linking the wind farm to the onshore transmissions grid.  Irrespective of the contractual responsibility for the cables to grid, offshore wind farms are increasingly being built in remoter locations and so the timing and process for grid interconnection needs to be properly understood.

By the time potential funders become involved, land, planning and grid activities will normally be well advanced and funders' due diligence will normally be able to focus on the fundamentals:

• Land:What onshore and offshore land rights are needed to build the wind farm and connect it to the grid?  Have those rights all been obtained or are some still under negotiation?  If onshore rights are required, does the project company have the benefit of compulsory purchase powers to obtain the necessary land rights?
• Consents:Given that offshore wind project development takes place over such a long period of time it is not uncommon to find that land rights or consents are not in the project company's name and need to be transferred (often backed by appropriate credit support) or that the requisite consents need to be varied because the precise layout of the site has changed, or the turbine technology has moved on so that the capacity and number of turbines has changed.
• Appeals process: With regard to consents, have all necessary consents been obtained and have all statutory appeal periods expired?  For example, in the UK decisions of a competent authority in granting the necessary licences can be subject to a judicial review.  However, in all but limited circumstances judicial review proceedings must be brought within three months of the relevant decision.

Construction contract 

It is perhaps in the area of construction contract strategy that offshore wind practice diverges most from other forms of power generation.  Most comparable large-scale gas-fired independent power projects (IPPs) are developed on the basis of a single lump sum turnkey EPC contract.  

However, while such structures were seen on a number of the early offshore wind deals, such structures are now quite rare.  It is worth noting that while gas–fired CCGTs are quite complex integrated plants with a single high value gas turbine at their core, wind farms are much more modular, with different components.  It is therefore very difficult to ask, say, the turbine manufacturer, to "wrap" every element of an offshore wind farm's construction.

A bankable practice has developed whereby the construction is split into a number of packages with no overall EPC wrap.  These packages could be:

• turbine supply and installation;
• foundations;
• offshore platforms;
• inter-array cabling;
• main transmission cable; and
• onshore works.

While the project sponsors will try to align the contract terms as much as possible and will build in extensive cooperation and coordination obligations on each contractor, there is no overall EPC wrap.  In these circumstances, technical due diligence becomes key to bankability and the lenders' technical advisor will be asked to do a top down analysis, testing the degree of practical interface risk between the various contract packages and assessing the project's available contingency to cope with an agreed delay/cost overrun downside scenario.

Alternatively, some experienced developers still utilise a multiple contract strategy, breaking the project down into 20+ sub-contracts which they manage.  While this structure has not typically been capable of attracting limited recourse finance, some more experienced developers may be prepared to put an EPC "wrap" round the project, thereby elevating its credit profile to investment grade and marketing the debt accordingly.

Offtake arrangements

Offtake arrangements will vary from jurisdiction to jurisdiction, depending on the applicable regimes for renewables.  There are essentially three types of arrangement:

• feed-in tariffs, where the project company is paid a fixed price for the renewable power it generates;
• green certificates, where the project company is given a certain number of green certificates for the renewable power it generates to supplement the revenue from its commercial power purchase agreement (PPA); and
• contacts for difference (CfDs), where the project company is paid an agreed top-up payment up to an agreed strike price to supplement the revenue from its commercial PPA (which, for the purposes of the CfD, is deemed to be the relevant market price and referred to as the "reference price").

Irrespective of the relevant government's procurement strategy, the tendering authority will look to deliver some degree of competition into the process: with costs reducing so rapidly, tariffs rapidly become off-market: witness France's recent decision to cut the tariffs for offshore wind projects awarded tenders in 2012 and 2014.

From a financing perspective, feed-in tariffs and CfDs both deliver a stable revenue stream (provided that, in the case of CfDs, the generator can also secure a long-term PPA).  Green certificates, although used for many of the older UK offshore wind projects, are slightly more challenging because the project is still exposed to a fluctuating revenue stream under its PPA (which will typically pay the (variable) market price for power).

The key point about a PPA combined with green certificates or CfDs is that lenders will want an offtaker not only to purchase the power but also take the system imbalance risk that arises from a wind farm's variable generation: a single wind farm is unable to balance its position such that it always sells precisely the amount of power it generates.  Some of the key points in relation to the PPA will include:

• ensuring that the pricing mechanism is back-to-back with any CfD, such that there is no price leakage;
• negotiating the discount to the reference price that the offtaker pays (either on a fixed amount per MWh basis or on a percentage basis) for taking "imbalance risk" in relation to the wind farm's output;
• negotiating caps on liability for termination that provide the project with a sufficient buffer should the PPA be terminated for counterparty default while not unduly negatively influencing the discounts; and
• credit support should the offtaker not have an investment grade rating, and risk mitigation strategies such as placing multiple PPAs with different offtakers.

Operation and Maintenance Strategies

Lenders will also need to be happy with the project's proposed operation and maintenance strategy.  While the favoured option may be for a long-term maintenance contract for the wind turbines with the original equipment manufacturer, more experienced developers may prefer to take such a contract for perhaps five years and then take over the O&M themselves.  The project's ability to undertake the balance of plant O&M will also need to be assessed.

Financing matters

Facility structure

As offshore wind financings have increased in size and the cost pressures have become more intense, so the facility structures have become more complicated.  Set out in figure 2 is a typical facility structure for an offshore wind deal.

Figure 2 - Offshore wind: Typical UK finance structure 

1. Facility may be split if credit support is required.
2. Revolving facility used to provide credit support for transmission and/or OFTO sale obligations.
3. Contingency may be built into base facilities.
4. There may be multi-currency facilities.
5. For working capital or letters of credit.

The following are some key observations on facility structuring:

• UK financings will incorporate a separate tranche for the construction of the transmission facility.  This tranche will typically be financed on a higher leverage and will be prepaid out of the proceeds of the sale of the offshore transmission assets to the successful bidder who wins the competition to own and operate these assets.
• How each of the generation and transmission financing facilities will be split depends to some extent on whether there is just commercial debt or commercial debt plus direct or credit enhanced lending from export credit agencies or multilaterals such as EIB or EKF.  These facilities may also need to be split into a term facility and a revolving facility to enable them to be used to provide credit support for construction obligations.  The value added tax (VAT) element of any project costs will also be financed from a VAT facility which is structured as a revolving facility to be prepaid from refunds of VAT.
• In common with many other projects, offshore wind financings may also incorporate a standby facility to provide additional funding in the event of cost overruns or delays.
• The precise scope of the ancillary facilities will depend upon the specific project requirements, but it is not uncommon to see a working capital facility, a debt service reserve facility (DSRF) and one or more letter of credit (LC) facilities (depending on currencies required).
• The DSRF is becoming an increasingly common feature of major renewables financings, with sponsors seeking to avoid tying up money in a debt service reserve account (DSRA) or funding a sponsor-backed DSRA letter of credit.  The idea of a DSRF is to have a project-level loan facility that is available if required to meet unpaid debt service.  Whether or not all banks are participating in the DSRF will determine the precise availability conditions of the DSRF: if all banks participating in the term facilities are lenders in the DSRF, then this is less of an issue, but if there are (ECA or other) lenders who are not participating in the DSRF, then this can give rise to intercreditor issues, as those funders will want the DSRF to be a cash equivalent with extremely limited conditions precedent to drawing.
• The scope of a project's LC facilities will vary considerably depending on the specific requirements of the project and the extent to which credit support is coming from the sponsors.  Common credit support requirements for offshore wind projects can include:
     — credit support to contractors;
     — security to state or private landowners; and
     — security to civil or military air authorities to secure the building or upgrade of radar equipment.

Wind risk

Electricity production from an offshore wind project and the resulting revenue will ultimately depend on wind speeds over time at the wind farm site.  Lenders will therefore be keen to understand the forecast of wind energy resource at the project site and any uncertainty to which the expected electricity production from the wind farm is exposed.

The energy yield assessment (EYA) is therefore one of the fundamental pieces of technical due diligence.  The project sponsors will have carried out their own EYA during the development phase and the lenders' technical advisor (LTA) will need to validate that EYA.  The sponsors' EYA will be the subject of careful scrutiny: it may be that there will be some disagreement as to the data or methodologies used which will need to be resolved between the sponsors and the LTA.

Wind output will typically be assessed over three projections and for the following purposes:

• P50 probability – the wind yield estimate can be expected to be exceeded 50 per cent of the time.  Project sponsors will often base their own economics around the P50 analysis.  In connection with the financing, P50 is typically used to determine whether or not projected coverage ratios are met for distribution purposes.
• P90 probability – the wind yield estimate can be expected to be exceeded 90 per cent of the time.  Typically the lenders' debt sizing case is based around the more conservative P90 and any events that give rise to a recalculation of base case ratios will typically employ the P90 definition (see below).
• P99 probability – the wind yield estimate can be expected to be exceeded 99 per cent of the time.  P99 is typically used for certain downside sensitivity analyses (e.g. does the project meet a one-year P99 debt service cover ratio of 1.0) and it may also be used when calculating pre-completion revenues (PCRs) (see below).

Equity structure/Pre-completion revenues (PCRs)

A key part of the overall financing plan will be the equity structure. Like any project, sponsor equity can be contributed up-front, pro rata with senior debt and even after debt, subject to the provision of appropriate credit support.  Project sponsors may also choose to utilise an equity bridge loan to defer the funding of their actual equity commitment.   In particular PCRs can play a significant role in the funding structure for wind farms.

Large offshore wind farms can generate a significant amount of PCRs during the commissioning period and before the wind farm as a whole achieves its commercial operation date (COD).  Project sponsors will want to use the PCRs to reduce the funding burden on them and indeed will in most cases want to treat PCRs as equity.  

For example, a project might be structured such that project sponsors commit to contribute the required amount of equity net of the P50 projection of PCRs plus all PCRs actually generated up to the projected P50 figure. The lenders will contribute the senior debt and may be asked to assume that the P90 revenues will be generated (i.e. the project sponsor does not credit support the P90 revenues even though they are treated as equity and only credit supports the difference between the P50 and the P90 figure).

While treating some level of PCRs as equity is acceptable to most commercial banks, some other funders may have strict policy requirements that do not allow PCRs to be treated as equity but rather as both debt and equity, reducing project cost rateably.  In this case P99 revenues may be allowed to be taken into account in the financial model on an unsupported basis to reduce project costs.  However, the treatment of PCRs cannot be considered in isolation and needs to be reviewed in conjunction with the gearing ratio: from a sponsor's perspective a higher gearing ratio can offset the impact of a more conservative treatment of PCRs.

Equity cure and wind reforecasting

In more recent offshore wind deals, strong project sponsors have been able to introduce other features that are favourable to equity, namely the concepts of wind reforecasting and equity cure.  Equity cure, namely the right during operations to inject equity to cure a ratio breach and/or prepay debt, is not specific to offshore wind, but the prevalence of this feature is a good indicator of the strength of the sponsors and the banks' appetite for financing these projects.  Typically project lenders resist granting sponsors automatic cure rights like this.

More specific to offshore wind is the wind reforecasting concept.  It is worth remembering that P90 ratios are calculated on a ten-year basis and as such it is still possible that in the given calculation period for a ratio test the energy yield is so low that revenue generation drops and a default ratio is triggered.  Sponsors will argue that the project is still fundamentally sound notwithstanding the ratio breach.  Lenders will argue that this may be true, although they will want to know that the reduced energy yield is not a longer term issue.  Wind reforecasting is essentially an additional cure mechanism for a historic DSCR event of default whereby the project's revenues are recalculated assuming that the wind yield had corresponded with the P90 data.  If this recalculation demonstrates that the ratio would have been above the event of default level, then there is no event of default.  There will be negotiations around the number of times that this cure right can be used both consecutively and in the aggregate.

Deferral and mandatory resizing

Unlike a conventional power plant, where the plant is essentially a single integrated plant, a wind farm is a series of tens of individual wind turbines, all of which can generate revenue once common infrastructure is in place.  Many subsidy regimes cater for the uncertainty that flows from needing to commission multiple generating units and allows the COD to be achieved within a target window rather than by a single date, and gives the project company the option to decide not to commission all its turbines (provided a minimum number are commissioned).

Wind farm financings therefore ideally need to allow for shifts in the COD and/or reductions in project size.  This can be achieved through a deferral mechanism and associated mandatory resizing events.  The deferral mechanism allows an agreed number of repayments to be deferred and the debt reprofiled at COD such that the debt tenor matches the subsidy contract.  Any reprofiling or reduction in the number of the project's turbines gives rise to a mandatory resizing where the base case financial model is rerun applying the project ratios to the actual position at COD.  If this calculation shows that the sizing case ratios cannot be maintained, then this "excess debt" is repaid via an agreed cash sweep mechanism.

Security

In common with regular IPP financings the lenders to a wind farm project financing will look to take the maximum security possible over the project.  While there is nothing surprising in this, potential lenders will need to understand the security that is available to them offshore, particularly if the wind farm is located outside territorial waters.  For example, in the UK it is not possible to perfect security outside the 12 nautical mile limit, because there is no applicable land registry where the security can be registered.  Lenders may therefore have limited security over these assets, although depending on the lease terms they may be able to take an assignment of the project company's rights under the leases.  

Hedging

Like any heavily leveraged project, lenders will want to ensure that the project puts in place an appropriate hedging strategy to ensure the project's construction costs are properly protected against adverse movements in interest or currency rates.  Likewise during operations the project may need to protect itself against adverse currency movements if the major operation and maintenance agreement for the wind turbines with the original equipment manufacturer is denominated in a foreign currency.  There is nothing particularly novel about this, save that due to the long time periods from project award to financial closing we have seen sponsors extensively deploying pre-hedging strategies to mitigate interest and currency risk and indeed, rather than automatically novating any pre-hedges to lending banks at financial close, seeking optionality to break those hedges and take the profit and loss into account, either taking the profit for equity or using it to reduce project costs and including any negative hedging termination payment as a project cost.  Depending on what happens to any positive mark to market there may be some upside to sponsors, but the key attraction is building in a mechanism that allows sponsors flexibility not to have to novate a hedge with a perhaps large negative mark to market to incoming lending banks.

The second interesting feature is the growing use of CPI hedges in the UK.  The "strike price" which is used for the calculation of the difference payments payable under the UK CfD is indexed to the consumer price index (CPI).  As with any project, sponsors will have made an assumption at the outset as to future CPI (inflation), and the project can therefore hedge its CPI profile, paying or receiving the difference between the actual CPI payment received and the assumed CPI payment.

CPI hedges are therefore helpful in stabilising a project's cashflow and protecting coverage ratios, particularly in a low interest rate scenario.  However, CPI hedging is relatively new and there are a limited number of counterparties, meaning that there may be some intercreditor discussions around orphan swaps and ranking.

Sponsor support

Project sponsors will need to decide at the outset the degree of sponsor support that will be available for the project.  There are two key areas where sponsor support may be required.  The first is in relation to construction and operation activities.  The project's funders will be keen to see some involvement from the main sponsors in these areas.  Involvement during construction may simply take the form of various technical services and secondment arrangements.  Alternatively the sponsors may take on a more coordinating role and provide some form of construction management services.  Such a contract may be valuable where an experienced sponsor can provide these services during construction, although limited liability is likely to attach to their activities.  Similarly an experienced sponsor may take on a role during operations, providing balance of plant O&M services and even O&M services for the wind turbines after, say, five years.

Secondly sponsors may provide credit support for the project's obligations towards third parties such as landlords and contractors. Additionally, in the UK context, credit support may also be needed in relation to the sale arrangements for the offshore transmission cable or in relation to its maintenance.  While such credit support has historically been provided by the sponsors, it has become the norm to build these third party credit requirements into the project facilities.  Although this means the project and its founders have less recourse to the sponsors, it has the advantage of ensuring that all required credit support for the project can come from the project facilities and the project is therefore more insulated against events affecting individual sponsors.

Accommodating different financing strategies

Not all project sponsors want to use project financing to undertake offshore wind projects.  A number of the leading sponsors in this space are large-scale, well-rated utilities or multinational companies who typically fund project development on their own balance sheet.  This has led to a number of interesting structures in the market, where sponsors with different commercial approaches seek to combine different financing structures.

One approach is to use a "HoldCo" financing, where the sponsor who wishes to raise debt does so at a HoldCo level.  However under a normal HoldCo financing the HoldCo funders are structurally subordinated and reliant on dividends or other distributions to repay their debt.  They also have no security over the asset.  On some projects, a HoldCo financing has been structured such that the HoldCo and the project company enter into a PPA for the HoldCo's pro rata share of the power generated and the HoldCo then on-sells this power such that there is a revenue stream sitting within the HoldCo and not just a dividend flow.  This revenue stream may also include an element of the project's green certificate revenue.  This PPA can also be assigned to the HoldCo's lenders.

On other projects we have seen lenders willing to accept a sponsor co-lender structure, whereby project sponsors are allowed to participate in the financing as senior lenders and even hedge banks pari passu alongside the commercial senior lenders.  Clearly such structures can give rise to a degree of inter-creditor complexity as commercial banks will want to ensure that sponsor funders are disenfranchised with regard to lender decision-making.

Conclusion

There is no doubt that the offshore wind market is in a period of major growth: an increasing number of ever larger wind farms are seeking finance in a growing number of countries and existing wind farms are being refinanced.  Happily, for now funder appetite remains strong: funders have become more familiar with offshore wind farm construction risk and seem to like the combination of large ticket sizes backed by strong sponsors that are on offer for these renewable financings.