This is the seventh part of what will be a 10–part series of blog posts, which will ultimately be published in full as a single report. Two parts are published each week.
Offshore wind project finance presents 3 categories of risks:
- Those that are common to all infrastructure projects (regulatory, macro-economic)
- Those that are common with other wind projects
- Those that are specific to offshore, during construction and operations
Let’s take these in turn
The first category of risks apply to all sectors that use non-recourse financing and more generally attract infrastructure investors like specialized funds . That means that these risks are well known to financiers and thus well understood.
Political risk is, broadly speaking, the risk that regulators or legislators will change the rules that apply to a project once the investment has been made, or even during its development phase, with an adverse impact on its ability to repay its debts or turn a profit. That can include changes in taxation or regulations that apply to the sector or to the project specifically, and macro-economic policy decisions such as restrictions on currency exchange or cross-border capital movements.
In project finance, political risk is usually associated with oil & gas or mining projects in emerging markets, where big infrastructure projects can have a material impact on the overall economy of the country and are thus negotiated at the highest levels of power of the country, with the corresponding potential for arbitrary decisions. In these countries, investors like the big oil major typically bring in lenders to share that risk, and in particular they bring multilateral lenders and export credit agencies, which usually have deeper relationships with these countries, and specific tools to mitigate political risk. Commercial lenders usually take a relatively small portion of the risk alongside the public lenders, but they assess it carefully.
It may seem a bit strange to compare such emerging market projects to wind projects, but the reality is that renewable energy projects, like all infrastructure projects, heavily depend on the applicable regulatory framework, and any change to the rules can have an impact. And the projects have the same financial profile, which is to see most of the investment done upfront, with operations showing large gross operating profit before debt repayment. Such cash flows always constitute a tempting target for governments that are looking for new funding. In the case of renewables, and as opposed to oil & gas or mining projects which rely on exporting the production to the global market, the revenues are generated locally, creating additional macro–economic risks, like inflation or reduced demand, which can translate into lower revenues (if funds need to be converted from the local currency into dollars or euros)
The risk was specifically acute in the early days of the sector, when projects relied on tariffs that were clearly out of the market, and needed these subsidized tariffs to repay their debts. The question was whether such tariffs were sustainable both politically and economically for the country.
As it were, there have been a number of countries, in particular after the financial crisis of 2008, that took retroactive decisions with respect to renewable energy tariffs (to reduce them), forcing a number of projects into bankruptcy or at least serious financial stress. So the risk certainly exists.
The risk is also acute during the development phase, when investments are not fully committed but developers are making efforts (and spending money) to make their projects viable – by identifying suitable sites, running the relevant environmental studies and submitting permit applications. If the rules change during that period (to give a simple and real example: rules on the minimum distance between a turbine and a house, onshore, or between a turbine and navigations lanes, offshore), some sites may no longer be viable and earlier development efforts will have been lost.
Developers, investors and lenders understand these risks, and behave accordingly. That means, for instance, avoiding countries that have a history of decisions detrimental to existing assets and preferring those that have predictable and stable regulatory frameworks; it can mean avoiding projects that offer too high remunerations (because they are not economically justified nor politically sustainable, and have a higher chance of triggering a backlash and adverse decisions later on), and it also means that countries perceived as less predictable will suffer a discount in the form of higher interest rates or higher expected returns on capital invested.
It is important to note here that lenders in particular do not like tariff regimes that are too far out of the market, unless there is a really strong strategic justification for these, and subsidized projects are seen as inherently more risky than projects that have a price regime close to what market prices are.
Similarly, while lenders do not take development and permitting risk (they will only provide funding once all permits and licenses have been granted without risk of appeal), they are sensitive to the transparency and professionalism of the process – a permit that has been granted by an arbitrary decision of a minister can be revoked just as easily and would be seen as less valuable than a permit that has been granted following explicit or regular procedures that provide stakeholder involvement. This can be relevant in countries where offshore wind is a nascent industry and the overall vetting and permitting process has not been fully defined and may be subject to jockeying by various domestic bodies, such as those responsible for aviation, fisheries, navigation, the military, industry, and many others. A stabilized permitting and supervisory regime is essential for an investment that will take 20+years to be repaid.
Overall, this is a critical risk for investors and lenders, and one which is always closely assessed.
Commodity price (merchant) risk
“Merchant” is the term used to describe price risk on the sale of electricity on the wholesale market. For offshore wind projects, there is also an element of commodity price risk with respect to steel and copper as projects use substantial quantities of these, as well as, prior to FC/FID, risk on the interest rates that will apply.
Even when projects have power price regimes set by regulation, there is an element of merchant risk – at least for the period beyond the regulated tariff (which is relevant for investors and to a lesser extent for lenders when the tenor of debt is longer than the tariff) but also during the regulated period – if for instance it is possible for projects to sell their production on the spot market if prices are higher than the regulated tariff. It is obviously even more relevant for projects that are developed without a long term tariff regime.
Investors and lenders are familiar with merchant risk in that they have long taken price risk for gas‑fired projects, and as we have seen, there is a close link between power prices and gas prices (even as the difference between the two, known as the “sparkspread” is closely watched). The economics of these gas projects are very different: they don’t produce if they are not competitive, and their running costs are otherwise relatively low, but the requirement to have an opinion on future power prices is the same.
This is not a risk that either investors or lenders like much (power prices can be very volatile and stay away from expectations for long periods) so they try to be careful about how much of the risk they will take: this is typically done by taking fairly low price assumptions, or requiring high returns on capital to take more risk, or, whenever possible, by transferring the risk to a third party via long term power price agreements (PPAs) with price formulas that typically offer a minimum price and thus guarantee some minimum revenues.
The unavoidable consequence is that merchant risk translates into less debt (as lower revenues are considered to calculate the amount that can be safely repaid), more expensive equity (as it receives more volatile income) and overall more expensive capital. Even when a PPA can be procured, this is seen as riskier than a fixed price regime, as the contract creates counterparty risk (see next paragraph) and potentially mismatches between the profile of generation sold and what is actually produced. For capital-intensive projects like renewables, it means that the cost of electricity produced is higher. It is actually a sign of how far renewable energy production costs have fallen that projects can now be built on a merchant basis in some countries.
For offshore wind, the volumes they are generating (several TWh per year for a typical utility–scale project) means that it is difficult to find PPAs for their full production volumes and thus merchant projects remain a questionable proposition, and the industry is now lobbying hard to avoid these as much as possible, and have access to long term price regimes that afford price stability, even if the prices are very low.
This is one of the key risks for projects and is treated as such by financiers.
The final traditional risk is that borne on the third party stakeholders in the projects. Construction contractors, suppliers, electricity off‑takers all make industrial and financial commitments towards the project, and these can be endangered if the company fails – or the guarantees backing these commitments can become void if the relevant company is unable to back them. Any stakeholder going bankrupt is a risk for the project – at the very least a source of delays and potential new costs to solve the problem if it appears. Evaluating the financial strength of project parties is a core competence of banks and investors, and it is as relevant for renewable projects as it is in other sectors.
Indeed, it may even be more critical for several reasons:
- Certain project components are highly specialized, or manufactured specifically for the project (for instance, turbine foundations are each individually designed for their specific location) and may not be easily replaceable;
- Given the requirement to build turbines in a specific order, bringing very different supplier in a delicate dance, a failure to manufacture or install one of the components can have knock-on effects on the rest of the installation schedule and severely delay the project – and cause cost overruns as other suppliers need to have their own deliveries delayed;
- As a relatively new industry, it has tended to rely on suppliers that have often been smaller and less tested companies, without the strong balance sheet of contractors in other sectors. There have indeed been multiple failures of key suppliers over recent years, sometimes during the construction of projects, and these have led to serious complications for projects.
This is a risk that banks understand, and try to cater for as much as possible in the financial structuring of projects, and they can impose quite strict requirements on projects and on the contracts that are negotiated, for instance by including financial guarantees backed by the contractor’s banks, by asking the project to identify alternative suppliers (and, in the most critical cases, to procure options for such alternatives as back up plans).
This is a risk that is always carefully monitored by investors and lenders.
Exemple – the Senvion bankruptcy
Senvion, the German turbine manufacturer, went bankrupt in 2019. This had an impact on multiple wind projects across the globe, in particular for those that had reached FC/FID, made downpayments to the contractor, but had not seen the turbines built yet. For projects with operational turbines, it created mostly short term disruption as Senvion’s role as operator was taken over by SiemensGamesa and the existing long term maintenance contracts could be taken over.
In offshore wind, where Senvion was involved in a handful of projects, it generated massive headaches on several projects, and in particular on two that were project financed: C–Power (already in operations), and TWB II (under construction).
C–Power benefitted from a long term operations and maintenance contract, which suddenly became void, and had to build a new operations set up that made economic sense and could be accepted by the lenders. That meant contracting directly with a number of core subcontractors (more than 20) of Senvion to ensure continuity of supply and services, and build a team to take over the tasks and coordination previously done by Senvion – and get the banks to validate the new setup.
TWB II was in an even tougher situation, as the bankruptcy happened in the middle of construction, with some turbines delivered but not installed, and others not yet manufactured – but paid for to a significant extent. The only way forward was for the project to take over the installation of the turbines, and enter into direct relationships with suppliers for them to continue to provide components, while entering a new contract with the now–under–administration Senvion entity to perform the actual turbine assembly (but without the guarantees that were previously included in the contract and could no longer be provided by the bankrupt entity) using the components supplied under now–separate contracts.
This was made possible by “step–in” rights in the existing contracts (that precisely allow the project to enter into direct relations with key suppliers in such circumstances) and other contractual features, including the contingency budgets and buffers in the project financing that allow to survive the unavoidable chaos and delays that such an event can cause.
In both cases, the project successfully navigated the bankruptcy, with the support – and ultimate approval – of the banks during the negotiations, but this was time–consuming and complex to manage.
Wind sector related risks include the uncertainty on wind measurements and production estimates, and the risk on new technology as projects tend to want to use the most recent turbine models.
Electricity production estimates – as well as estimates of the likely seasonality and variability of such production – are obviously a critical aspect of the economics of a project, and these depend for the most part on the wind measurements made onsite or near the site. It turned out a few years ago that production estimates for onshore sites had been structurally over‑estimated by technical experts (to the tune of 8-10%) and banks and investors had to deal with projects that were generating quite a bit less electricity than expected, and have been even more sensitive to the topic since that.
The good news is that wind speeds at sea are a lot easier to measure than onshore, as the surrounding area is completely flat and does not have obstacles like hills, trees, etc., that complicate wind patterns, and estimates made to date on offshore projects have proven to be quite accurate. The further good news is that it is possible to use different methodologies such as “mesoscale models” using atmospheric data (as the US National Oceanographic and Atmospheric Administration (NOAA) provides) or interpolation from existing meteorological masts, even if they are some distance away, and combine them to reduce overall uncertainty. Investors and financiers are thus quite comfortable with estimates made by reputable experts.
One point of attention has been the “wake effect” and associated “blockage effect” i.e. the fact that turbines situated behind other turbines in the prevailing wind direction tend to have lower output. On a windfarm level, the impact on net production can reach 10-15% of the gross number, so it is a significant factor and projects rightfully spend a lot of effort to try to optimize site layout so as to minimize this effect. From the banks’ perspective, this effect is also correctly estimated by experts so it is not a source of uncertainty as long as it is taken into account from the start.
Overall, the estimate of the wind resource for offshore wind projects is seen as a low risk by financiers.
Wind turbine technology
Wind turbines are relatively mature technology – large mechanical and electrical equipment, with mostly incremental improvements (like cars, one could say) but putting them offshore has created new challenges as there is a specific additional requirement for reliability, as you cannot simply drive down to the turbine and replace a component in case of failure. The quest for size as a way to reduce costs has also meant that new industrial processes have become necessary to test and manufacture components at a scale never seen before (such as 100+ meter blades, or multi-hundred‑ton nacelles that need to be transported to site and installed at 100+ meter heights).
With projects keen to use the most recent and largest turbine models, it has also meant that offshore wind projects often use relatively untested products, without a long track record of use at sea.
Lenders have nevertheless been quite relaxed about that risk, thanks to a methodology that was applied on the early projects with independent experts to assess turbine design, testing procedures and expected performance. The fact that offshore wind turbines have been manufactured by a relatively small number of players (never more than 3-4 at any point in time, in fact) has helped by creating a relatively small universe of players that have shown their commitment to the sector and “stood by” their turbines when technical issues were identified.
Lenders understand that all turbines will experience teething problems, and know that these will be solved by the turbine manufacturers – and they trust those that have had problems and have been transparent about what happened and how they solved it. Financiers do expect strong contractual commitments by turbine manufacturers: warranties, availability guarantees over long period of operation (up to 20 years), and a commitment to repair their equipment. And as this is what has happened since the early projects in 2002-2005, the manufacturers have strong credibility on that front and are trusted for any new turbine they bring to production. Conversely this would not apply to newcomers and it seems unlikely that Chinese manufacturers will be seen as credible parties in the foreseeable future without first demonstrating the same commitment in a consistent and transparent (towards banks at least) manner.
Technology risk is thus considered low, provided that the right processes are followed.
In the next instalment we’ll look at the construction and operation risks.