A sea of risk – Offshore wind
Technological advancement is rendering offshore wind power an increasingly viable energy source worldwide. By some estimates, the market could grow at a 16% compound annual rate from 2017 to 2030, as falling manufacture and installation costs allow untapped potential for offshore wind farms to be exploited1. By Luisina Berberian, associate director,S&P Global Ratings.
Recent progress in cost and market penetration aside, there may be headwinds approaching. As project risks during both the construction and operations phases heighten, developers and investors must be cognisant of the credit-negative implications that can occur. And, though developers appear to have a grasp of how to mitigate construction risk, they should remain wary of the risks that can arise – the moving parts that come with intricate projects such as these.
Thankfully, the maturation of the offshore wind industry, particularly in Europe, has enabled greater transparency and understanding of the key risks during a project’s construction and operations phases. We receive many queries about how we evaluate the construction and operations risks present in offshore development – many of which we intend to address in this article.
Understanding the methodology
Starting with the financing risk, the concerns are similar to those found in all project financing transactions: risk may abound because offshore projects are typically financed on a non-recourse basis due to their large financing needs – meaning that in simple terms the lender is entitled only to repayment from the cashflow available for debt service of the specific project the loan or bond is financing and its specific reserves.
In practice, should the borrower default, the lender cannot seek from the borrower further compensation. This remains true even if the collateral does not cover the full value of the defaulted amount.
Compounding the issue is that such transactions, by nature, are investment-intensive: they require large debt values and must also offer to sponsors a favourable equity return – especially in a competitive environment. With vast sums at stake, ensuring that the financing risks are correctly mitigated for the long term of the transaction becomes ever more crucial. Add in the evolving risks that come during the construction and operations phases – what one might call the moving parts – and the risks can intensify.
Assessing construction risk
To demystify these risks, our credit rating methodology serves to assess the possible risks for offshore wind project finance transactions in a transparent and comparable way within a broad and diverse universe of power projects.
First, we establish a project’s overall stand-alone credit profile (SACP), which is an assessment of its intrinsic creditworthiness. The project SACP is the lower of our assessments of the project’s construction phase SACP and operations phase SACP.
To arrive at the final rating, we adjust the project’s SACP for other factors. These may include any considerations related to the transaction structure, extraordinary government support, the sovereign rating and any full credit guarantee.
We can break down the process of creating a SACP to its bare components, starting with assessing the construction profile. The risk profile of the construction phase, we believe, cannot be understated: in the absence of sufficient risk transfer and mitigation instruments, cost and schedule overruns can be a significant source of disputes and delays.
* Technology risk – A principal consideration that we assess under the construction profile is technology risk. Such technology typically includes turbines, structures, offshore substations and possibly cabling and onshore connections.
Our approach is to evaluate the technologies’ key features, including any innovations. But how do we distinguish between varying degrees, or types, of technology risk? Our construction methodology criteria differentiate technology risk in four categories of this type of risk: commercially-proven; proven; proven, but not in this application or arrangement; and, new or unproven.
Given the relative limited operational history of some newer turbines, most assessments might fall from the “proven” to “proven but not in this application” range.
That said, the assessment for certain turbine and foundation technologies can be supported by a satisfactory operational track record, leading to a reliable long-term forecast, which, in turn, can breed comfort around the long-term generation output forecast of such assets – so, too, can strong testing, verification and certification for new turbines.
Our technology assessment reflects residual risk to the project after mitigants, including warranties and operation and maintenance contracts that guarantee performance such as availability, which can also carry attendant benefits during the operations phase. The robustness of the risk transfer is assessed by evaluating the conditionality of the contracts, as well as the balance sheet strength of the party supporting the risk transfer.
To achieve lower installation costs, the drive towards efficiency savings during the manufacture of turbines and their foundations has led producers to one outcome: making the parts larger. This has also provided options to build offshore wind farms at further distances from shore – though this introduces other risks, too, namely harsher sea conditions and exposure to longer cable lengths connecting to shore.
* Construction complexity – With this in mind, another consideration as part of our methodology is construction complexity or difficulty. Naturally, the more complex construction tasks are, the more likely they are to lead to delays and cost overruns.
For this reason, we measure the effectiveness of construction contracts by assessing how the risks of cost and time overruns are effectively transferred to the construction counterparties, and how much risk the project retains.
Digging deeper, offshore wind and subsea transmission in benign sea conditions, according to our methodology, would typically be considered a “civil or heavy engineering task”. Those in harsher sea environments, on the other hand – in deeper waters and built further from the shore – would typically be assessed as a “heavy engineering-to-industrial task”.
Other considerations, in this respect, are neighbouring wind farms and nearby ports, water depth, as well as tidal range and soil composition, among others.
Accentuating these risks, are scenarios where a discrepancy exists between the construction plans at the bidding stage and executable plans once construction tasks begin. For example, the technologies proposed during the bidding stage might differ from the ones that are actually feasible at the time of construction.
Should water depths, turbine sizes, and distances-to-shore increase, we can expect additional risks to be introduced. That said, 2017 offered some respite on previous annual figures: the average water depth for wind farms completed or partially completed was 27.5m, down from 29.2m in 2016; the average distance-to-shore was 41km, down from 43.5km in 20162.
We expect these construction complexities to be properly managed, largely thanks to more robust design, standardisation, and increasing vessel and crane capacity. And, it appears that lessons have been learned.
Since the troubles with Greater Gabbard, projects developed in the North Sea have reached completion with less complications. The Westermost Rough project – a 210MW project built in 2015 – was delivered 15%-20% below the initially-announced final investment decision (FID) budget.
In January 2017, the 288MW Sandbank project, also in the North Sea, was commissioned three months ahead of schedule. In this respect, market participants are keeping in-check the possible risks of developing offshore – and, it seems, are also privy to a far more robust supply chain.
The value of contractor experience
The ability and experience of contractors, together with major subcontractors, to deliver the project on time – including sufficient time buffers – is a key part of the construction analysis. We base this on their relevant expertise with the project’s type, scale and location, experience of each contractor’s project director and team, among others.
When evaluating contractor experience, a key consideration is the ability and track-record of resolving issues between various prime or subcontractors, known as interface risk. The contractor’s liquidity, too, can be a factor in mitigating interface risk, along with clear delineation of contractor responsibilities across all involved parties. The assessment ranges from very experienced to inexperienced.
This factor is particularly significant within the offshore wind sector due to the limited pool of available contractors. Only a few market players, in our view, can deliver such projects on time and within budget, due to the logistical complexities and supply chain required. In most cases, therefore, contractor experiences – according to our project finance methodology – are expected to be assigned very experienced or experienced.
We nonetheless see a diverse blend of players entering the market. European specialists have, to-date, built most offshore projects worldwide, but we increasingly expect the industry to leverage expertise, and the supply chain, from the oil and gas majors. These players could increasingly complement the expertise of the European specialists, or even act as substitutes.
Mitigating counterparty risk
Yet this can, in some scenarios, present a double-edged sword. Although experienced contractors can augment a project’s credit profile, one limiting factor is counterparty risk.
The degree of the risk largely depends on how easily the counterparty can be replaced. For example, the pool of possible replacements for a lead construction contractor may be limited. For this reason, the costs to replace the contractors and the potential increase in engineering, procurement, and construction (EPC) costs may, in turn, be higher for an offshore project than for a more conventional project.
Difficult to replace are contractors operating under a turn-key construction contract (whereby the builder absorbs design and performance risks), or contractors providing highly specialist design or construction skills. This is because replacing the initial EPC contractor with another on similar terms can be challenging.
Then there’s interface risk. Offshore construction typically becomes more complex with increasing numbers of interfaces. A large proportion of projects maintain a portion of the construction risk by directly subcontracting works without the benefit of a main contractor. In these cases, the project is exposed to the greater interface risks associated with managing multiple contractors.
For some projects, multiple contracts may cover a broad range of building tasks – such as the installation of foundations, cables, and turbines. In this scenario, the overall counterparty dependency assessment (CDA) typically reflects the CDA of the weaker contract. We note, however, that the number of construction contracts across offshore wind projects is falling – which, in terms of project coordination and risk mitigation, can be beneficial.
For other financings, we’ve seen the use of credit substitution to completely transfer the risk of construction (and often operations) to counterparties. Perhaps the most notable example of this arrangement has been seen in another asset type: the Cameron LNG transaction – the limited purpose vehicle, building a large-scale natural gas liquefaction project in Louisiana, US.
In the case of Cameron LNG, the offtakers guaranteed the construction. Originally, the lowest-rated participating entity was Engie SA, which thereby reflected Cameron LNG’s rating. However, in July 2018, Engie SA exited the transaction, and was replaced by Total SA. This consequently meant that the new-lowest credit quality offtakers, Mitsui & Co Ltd (currently A/Stable) and Mitsubishi Corp (currently A/Stable), would govern the credit rating – thus leading to an upgrade.
Interface management for main building activities, such as foundation and cable installation, has improved in recent years. For earlier projects, cable installation would typically be completed once the substation foundations or topsides were installed – an occasional cause of construction delays. In more recent projects, high level construction programmes can decouple these two activities, allowing for installation to be scheduled during the most suitable periods of the year.
Operations phase risks
Next come operations phase risks, which we assess via an “asset class operation stability” assessment- the risk that a project’s cashflow will differ from expectations due to operational issues. These are ranked on a 10-point scale where 1 denotes the most stable and 10 the least stable.
On this scale, offshore wind projects typically have a score of 5; by comparison, onshore projects are typically assessed at 4. The difference between the two results from remoteness: because of the greater difficulty in maintaining projects offshore, we consider such projects to have a greater likelihood of operations and maintenance cost overruns than their onshore cousins do.
In terms of our assessment, first we analyse the adequacy of operating costs and maturity of the operations and maintenance (O&M) environment. One of our important observations from rating renewable projects is that, when markets open up, initial O&M expenses are usually estimated with limited comparable benchmarks.
As the industry sees rapid growth, higher demand for specialist labour and crane hire may propel O&M expenses. This was the case in the US wind industry, where O&M expenses increased by approximately 30%-to-40%. This led us to downgrade the two projects we once rated for US-based contractor FPL Energy.
However, as any regional market begins to see increasing numbers of operating assets – and capacity to service the projects – we also see that costs begin to stabilise. As a result, we will likely adjust our underlying operational forecast.
Similar to onshore projects, we consider the extent of variability in wind resources for offshore wind projects to determine if the resource will be available in the quantity and quality needed to meet production and performance expectations.
But perhaps as important as the wind data itself, is our understanding of the manner of collection, including the proximity, height and duration of the data. These result in classifications for resource risk ranging from minimal to high and, for most projects that we’ve rated thus far, we classify wind projects as either having modest or moderate resource exposure, depending on the level of confidence in the project’s resource estimates.
For contracted assets, resource availability is paramount. For that reason, we expect management to spend significantly more than budgeted under stressed conditions to ensure availability.
A story of moving parts
Evident from the discussion around the development of offshore projects is the significance of moving parts. At many turns, from the construction to the operations phase, we see a range of factors, be they risks or opportunities, interacting – and it’s these that developers must bear in mind.
As such, we update credit risks on at least an annual basis, forming a view levied on the expertise of technical advisers and sponsors. As the industry emerges from nascency, we can draw on an increasing wealth of historical data and scenarios that help inform our rounded view of the inherent risks with offshore development.
In practice, the understanding of these risks will help give greater certainty to the strengthening project pipeline that is emerging globally. The key message, however, is clear: by mitigating the technological, counterparty and interface risks that we see across the construction and operations phases of offshore development, we believe that the industry can move closer to maximising its untapped potential.