Market view: Subsidy-free UK solar and wind projects

With the UK's first subsidy-free solar project opening in September 2017, the industry is beginning to shift to a new era of "subsidy-free" renewables out of necessity. However, while subsidy-free energy projects reduce the overall cost to the consumer of delivering new clean energy capacity, they are not without their challenges. Overcoming the higher cost of financing subsidy-free schemes is one hurdle, while managing variable wholesale prices is another.

To understand the extent of the impact of these challenges on the development of wind and solar projects in the UK, Ashurst sought the views of solar and wind developers and commercial and institutional lenders, together with financial, legal and market advisers, at a forum hosted at our offices in Spring 2018. The forum was subject to the Chatham House Rule, but the attendees kindly agreed that we could share their responses, which we analyse in this article.

Withdrawal of subsidies for onshore wind and solar

Despite the UK Government's gradual withdrawal of various subsidy mechanisms, 57 per cent of those consulted disagreed with the Government's decision to abolish subsidies for onshore wind compared to 43 per cent who were in agreement. On the other hand, this is reversed when focusing on solar, with 57 per cent of respondents agreeing with the UK Government's decision to abolish solar subsidies. (See figure 1.) This reflects the view that solar is a more established technology with a lower construction cost, ready to compete with conventional generation on a subsidy-free basis. Nevertheless, it appears that the market view is that subsidies were removed too soon in the UK.

Figure 1: Do you agree with the UK Government's decision to abolish subsidies for onshore wind and solar?

Many in the industry are of the view that solar and onshore wind projects in the UK do still require some support, and market participants consider that the UK Government should have introduced a price stabilisation mechanism for both onshore wind and solar projects even if this was on a subsidy-free basis. In our research 86 per cent of respondents agreed that these generating technologies still require some level of price stabilisation, to allow risks to be fairly shared between energy firms and the Government, while helping to attract investment. (See figure 2.)

Figure 2:

The consensus is that subsidy-free renewables will happen later in the UK than elsewhere. Fifty per cent of respondents agreed that the UK renewables market will see material investment in subsidy-free onshore wind and solar projects over the next two to five years. (See figure 3.) This is in stark contrast to Southern Europe, where there has been a growing emergence of subsidy-free projects since late 2017. For solar in particular, this is due to the higher load factors in these jurisdictions, which increases output and in turn increases return on investment.

Figure 3: Within what time horizon will we see material investment in subsidy-free wind and solar projects in the UK?

Risks to subsidy-free deployment

Those operating in the energy sector perceive current regulatory risks in the UK energy sector to be one of the most significant barriers in the industry to driving development and investment.

Alongside concerns around the uncertainty Brexit brings to the energy market, participants identified a number of additional regulatory risks, including:

• cuts to so-called embedded benefits, one example of which being Ofgem's decision to cut the Triad avoidance payment for embedded generators by 95 per cent over three years;
• changes to the way the transmission loss adjustment is calculated, including Zonal Transmission Losses, as implemented on 1 April 2018; and
• recent amendments to the capacity market rules, including the de-rating of battery storage projects which cuts the derating factor in capacity market auctions by almost 80 per cent for 30 minute duration batteries. As a result, a majority of battery storage projects that had qualified for the capacity market auction in 2018 were unable to compete.

Despite these issues/changes, the vast majority of respondents do not currently view the UK energy sector as being heavily impacted by regulatory risk, with only 21 per cent of participants perceiving the UK to have high regulatory risk. (See figure 4.)

Figure 4: How concerned are you with regulatory risks in the UK energy sector?

While there is no evidence that the Government would seek to impose regulatory changes on a retrospective basis, the rebanding of support under the Renewables Obligation and changes to solar support under the Feed-in Tariff regime are well-remembered. Regulatory stability is paramount to promote investor confidence, and at a time when the Government is focused on reducing the cost of capital, investors may consider adding a risk premium to investments in the UK energy sector to reflect the regulatory uncertainty.

Financing renewable energy

The move to subsidy-free deployment brings into question whether or not classic project finance debt structures remain the most efficient way of financing projects. In particular, the higher exposure to less stable revenue streams could result in financiers demanding higher margins to match the risk.

When considering the debt amortisation period for a subsidy-free project, 40 per cent of respondents thought that the appropriate amortisation period was between 10 and 12 years, compared with 20 per cent who thought debt should be repaid over a term of 10 years or less. (See figure 5.) The preference for short-term debt reflects the banking community's perception that subsidy-free onshore wind and solar carries with it more risk than subsidy-backed schemes.

Figure 5: What debt amortisation period should be used for a subsidy-free wind/solar project?

Continuing the theme, there was recognition that the margins to be earned across the solar and wind space are relatively low at present, and 86 per cent of respondents believed that margins should be higher for subsidy-free projects. (See figure 6.)

Figure 6: Should margins be higher for a subsidy-free solar/wind project?

The majority of participants, 65 per cent, also considered that the debt to equity ratio should be lower, requiring sponsors to invest more of their own capital in the project and therefore helping to lower the risk for lenders. Thirteen per cent thought that there would be no change irrespective of subsidy. (See figure 7.)

Figure 7: Should debt to equity ratios be lower for a subsidy-free solar/wind project?

For the banks there was recognition that deal structures may need to be become more flexible. One possible solution discussed was to include a lower fixed repayment schedule, but with a cash sweep and immediate prepayment of the debt during periods of strong economic performance such as high winds/irradiation and/or higher than expected power prices.

Direct PPAs

Since the UK Government decided to abolish subsidies for some technologies, direct power purchase agreements (PPAs) have become more prominent in the market and are now seen as a key feature of subsidy-free wind, solar, biomass and energy from waste projects.

The concept of direct PPAs has been in existence for many years but, in practice, their use has been relatively limited with the majority of projects to date opting to enter into a long-term PPA with an established licensed supplier, and preferably with one of the large utility companies. 

There are three main types of direct PPA – a contract for difference, a sleeving PPA and a direct wire PPA¹.

In our research 40 per cent of respondents favoured a PPA with a licensed supplier with a floor price or ability to fix prices. Another 40 per cent favoured a long-term corporate sleeving PPA, and 20 per cent favoured a long-term corporate contract for difference. None of the respondents favoured a utility PPA on a purely merchant basis, a direct wire PPA or a short-term rolling PPA strategy. (See figure 8.)

Figure 8: What is your preferred PPA strategy?

 

Looking into this further, 60 per cent of the respondents thought that the PPA could be shorter than the term of the debt. Twenty-seven per cent thought that the PPA should be for the same term of the debt, and 13 per cent thought that the PPA should be longer than the term of the debt. (See figure 9.) Clearly, when considering a PPA that is shorter than the term of the debt, lenders will be keen to ensure that their loan documentation contains appropriate controls on the borrower's replacement PPA strategy.

Figure 9: Will a subsidy-free wind farm require a PPA in place for the term of the debt?

Utility PPAs with floor prices can be less appealing to sponsors because the utility will usually offer a low floor price, which may not even be contemplated in lender downside sensitivity testing for debt sizing purposes, and the utility will charge for this floor price by way of a higher deduction from the power price under the PPA. We note that PPAs with the built-in ability to forward fix prices are becoming increasingly popular.

Price cannibalisation

Investment in subsidy-free projects can also be affected by "price cannibalisation". This arises when there is a lot of solar or wind power connected to the grid. By definition, wind and solar projects have a near zero marginal cost of production and so will always generate when they can. This means that on sunny or windy days (or even more of an issue on sunny and windy days) supply goes up but demand for power in the UK is relatively fixed. Basic economics dictate that when supply is high and demand is low or level, price will reduce. This means that wind and solar generators are often generating at the time of the lowest power prices. Respondents believed this effect will have a bigger impact on wind generators, with 37 per cent agreeing, compared to 25 per cent who believed the decline in value will be steeper for solar generators. (See figure 10.)

Figure 10: Will price cannibalisation deter investment in merchant projects?

Battery storage has the potential to mitigate the impact of price cannibalisation as further discussed below.

Co-location of battery storage on renewables sites

There has also been an increasing focus on colocating battery storage alongside solar or wind energy projects as a means to mitigate the impact of price cannibalisation and in order to benefit from a shared grid connection, which in turn helps to reduce overall costs of development. At times of low prices, the electricity generated by the wind farm or solar park will be used to charge the batteries. When power prices increase, the generator will either export directly from the wind farm or solar park to the grid or discharge the battery. The ability to do both will depend on the size of the grid connection, but in all likelihood the generator will be able to use the battery to smooth the output of the wind farm or solar park.

Furthermore, having battery storage located onsite behind a meter negates the effect of bid-offer spread on pricing compared to a situation where the wind farm/solar park and battery storage project are located separately. This is reinforced with 50 per cent of respondents agreeing that colocation would make a material difference to the economics of a project for both wind and solar, compared with a quarter of respondents who thought colocation would have no impact. (See figure 11.)

Figure 11: Will battery storage colocated with wind or solar projects make a material difference to the economics of the project?

A developer does not necessarily need to colocate a battery storage project onsite in order to realise the benefits. Instead, a developer could use the battery as a tool to arbitrage the low price a wind farm/solar park might receive during periods of high supply and low prices by charging the battery from the grid at such time and then exporting from the battery to the grid when power prices are high. However, this exposes the developer to the bid-offer spread of power prices.

Repowering wind farms

A number of wind farm sites with the best wind resource, wind data and grid connection were developed when the industry was in its infancy and turbine technology embryonic. Repowering these sites and deploying the latest in turbine technology will see a significant increase in capacity and reduction in opex. Furthermore, since repowering often involves enhancing an existing site rather than building on a new site, there should be less public opposition which could facilitate a positive planning consent outcome. As such, there has been a steady increase in interest in repowering, with some secondary market acquisitions and financings now being concluded with repowering assumptions built into the base case. This is reflected in our research, with 47 per cent of respondents saying that they would consider repowering an existing asset before the end of its modelled life as a matter of course, while 47 per cent said that their decision to repower would depend on the specifics and economics of the site. (See figure 12.)

Figure 12: Would you look to repower an existing asset before the end of its modelled life?

Overriding themes

Supply chain pricing

One of the overriding themes emerging from the research was that the supply chain serving both solar and wind industries needs to be more flexible in its approach to pricing and more creative in its offering, to allow onshore wind and solar projects to become economically viable without the support of subsidies. Structures whereby the whole life cost of a particular asset is linked to the revenue generated by that asset were widely seen as having potential for development. While there is precedent for such structures within renewable energy deals (for example, it is often the case that the landlord's rent under a wind or solar lease is linked to the revenue earned by the project) consensus is that it would be a brave operator that took the first step to receive an O&M fee linked to project revenues.

Additional thoughts on offtake arrangements

Lenders do not like taking the balance sheet risk on corporate offtakers for longer than three to five years. The ratings of tech firms, in particular, are not seen as robust. Favourable credit ratings offer some comfort to lenders but even the credit default swap market is not liquid enough to cover longer term exposure to corporate offtakers. Lenders' preference would be for a regulated utility (such as a water company) to be the offtaker, but there are not enough of them. Therefore, the risk associated with corporate offtakers is a key risk which lenders are going to have to come to terms with in order for subsidy-free wind and solar projects to be developed. 

One potential way to structure around this is to give credit to the fixed price offered by a corporate offtaker for a period of up to (say) five years, but then to assume the medium or low price case provided by a market adviser for any subsequent period. One could also attach a higher risk weighting (with respect to the required debt service cover ratio) for the purposes of debt sizing. This issue is a good example of where sponsors and lenders are both going to have to compromise in order to establish a bankable structure for subsidy-free wind and solar projects.

1. For more information about these different types of direct PPAs, see our earlier article, "Direct PPAs: Connecting with corporates", published in issue 18 of EnergySource.