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Energy spotlight: Wind

17/09/2019

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United Kingdom

Onshore wind generation is a fuel-free and increasingly low-cost form of high-volume electricity generation.

This is now equally true for offshore wind, which was initially perceived as being expensive and excessively complex from an engineering installation point of view.

Unless you are an unfortunate bird, a radar operator, have unusually sensitive hearing, or consider turbines blemishes on land/seascapes, there are almost no significant downsides to wind-powered generation.

To the extent wind turbines are deemed visually unattractive, they have the advantage of being easily decommissioned (offshore projects are experimenting with floating and gravity-based foundations to make them easier to move).

They do not have the legacy waste issues associated with nuclear, or the environmental and greenhouse gas consequences of unabated coal and gas-fired generation.

Concerns about subsidies inflating customer bills have been allayed by the fact that government financial support for wind is now reasonably modest and largely confined to legacy schemes.

New subsidy support is expressly conditional on a significant reduction in legacy costs, under the government's Control for Low Carbon Levies.

It is now effectively government policy that onshore wind should proceed without policy support, and that offshore wind should operate with very modest levels of support (reflected in increasingly slim Contract for Difference (CfD) administrative strike prices).

 

 

From gust to gale

Unsurprisingly, wind is playing an increasingly important role in the global energy mix, particularly in the UK.

UK wind generation hit a record high of over 15 GW in February 2019, which at the time accounted for over a quarter of UK electricity demand, up from around one sixth of the UK generation mix normally.

Wind power output exceeded coal power output for the first time in 2016. There is now total installed capacity of 21.5 GW in the UK, which has more installed offshore wind capacity than any other country.  

Of that capacity, onshore wind accounts for far more projects by number, but with a smaller "per turbine" capacity (largely due to planning restrictions).

As of September 2019, there were 2,012 onshore projects in the UK containing 7,834 turbines, which account for 13 GW of installed capacity – broadly equivalent to 11 nuclear plants or six large coal stations.

Offshore wind accounts for fewer projects but has a higher "per turbine" capacity. As of September 2019, there were 37 offshore projects comprising a total 2,016 turbines accounting for 8.5 GW of potential capacity.

According to the Crown Estate, there is also a pipeline of almost 24 GW of offshore projects destined to be built in the UK, of which 17.7 GW are both pre-construction and pre-award of policy support (i.e., the pipeline is strong, but the new capacity is a long way off).

As with other forms of renewable generation offshore wind has seen significant growth over the last decade – from around 0.8% of the UK generation mix in 2010, to expectations of around 10% by 2020.

The UK government launched its Offshore wind: Sector Deal in March 2019, where it announced an ambition to generate a third of its electricity from offshore wind by 2030.

This goal has started to look modest in light of the government's amended Climate Change Act 2008, which commits the UK to "net zero" carbon emissions by 2050.

 

Blow the expense?

Onshore wind

With the exception of the 15 onshore wind projects that were awarded Round 1 CfD contracts (but together account for only 0.7 GW of capacity), the main support mechanism for onshore wind is the Renewables Obligation (RO).

The RO underpins around a quarter of current UK generating capacity, approximately 30 GW.

Onshore wind is by far the largest benefactor of this support, accounting for 12.5 GW of capacity.

However the RO regime for new onshore wind closed in April 2016.

Onshore wind has also been excluded from both the second and third rounds of the CfD auction and is not able to participate in the Capacity Market (CM) (although the UK Department for Business, Energy and Industrial Strategy (BEIS) published guidance in May 2019 on how to facilitate renewable technology participation in the postponed 2020 T-3 auction).

The main reason behind the withdrawal of policy support is that onshore wind is now thought to be the cheapest form of electricity generation in the UK.

It has the lowest levelised cost of energy of any UK generating technology, if carbon price support is applied to conventional thermal projects.

This lower cost is largely attributable to the significant cost reductions achieved by advances in the design of turbines – which are allowing increasingly bigger and more efficient turbines.

Offshore wind

Unlike onshore wind, offshore wind can still compete for policy support, as it is regarded as a "less established" technology in the CfD auction (the exception is island wind, which has been included in the third round CfD, albeit at a much higher price than offshore wind).

The third allocation round is currently underway, with auction strike price for offshore wind capped at £56 MW/h for 2023-24 projects and £53 MW/h for projects delivered in 2024-25.

By comparison, the second round (2017) Hornsea 2 and Moray Offshore projects (to be delivered in 2022-23) were awarded £57.50 MW/h strike prices and the Triton Knoll 2021/22 project was awarded a £74.75 contract.

Round three continues the significant price reduction from the first CfD round, where the two offshore projects averaged £117 MW/h clearing prices.

Offshore wind has benefited from the same design and engineering advances noted above, but arguably at a greater scale, as offshore turbines do not have to overcome such strenuous planning restrictions and are now specifically engineered for the offshore environment (rather than, as in the early days, adapted versions of onshore turbines).

That helps minimise maintenance costs and allows far more sophisticated monitoring of operating parameters (allowing a preventative operation and maintenance (O&M) regime).

Offshore wind benefits from looser limits on turbine height and array size, whereas the planning regime for onshore farms has to accommodate both alternative land uses and the interests of neighbours.

This difference is now very marked: Orsted's new Hornsea 1 wind farm (120 km off the Yorkshire coast) is using 174 7 MW turbines, each 190 metres high with a blade length of 75 metres.

It is expected that 10-15 MW models will come into circulation from mid-2020s.

 

 

Investing in wind

The wind sector is now mature from an investment perspective – its growth driven by its relative attractiveness to pension and infrastructure funds, which value the longer-term investment with lower and stable returns such projects typically enjoy.

However, express government support is fundamental to maintaining investment viability – particularly as CfD strike prices move closer to projected wholesale market prices for offshore projects.

Government contracts provide revenue stability over the tenor of a CfD contract – which is particularly important to investors.

Revenue stability de-risks offshore investment against volatile short-term and hard-to-forecast long-term market prices.

The net effect of de-risking the project from a revenue perspective (other project risks still require mitigation) is to lower the cost of capital, which is a significant part of the overall cost of a project.

A useful benchmark for the necessary level of future investment is set out in National Grid's "Two Degrees" case in its Future Energy Scenarios (2018).

This suggests around 160 GW of low-carbon capacity is required to deliver the ambition of limiting global temperature increases to two degrees over pre-industrial levels.

Achieving this requires a threefold increase in low-carbon capacity over the next 30 years.

160 GW is four times the capacity already delivered under the combined low-carbon support regimes (i.e. the RO, feed-in tariff (FiT) and CfD).

The existing 53 GW of low-carbon capacity will have exceeded its 25-year economic life by 2050 and will require repowering (or replacing).

National Grid anticipates that 35 GW of additional low-carbon capacity will come from offshore wind, supported through the CfD, and that 10 GW will come from onshore wind.

Yet even assuming the CfD continues to offer sufficient incentive to offshore development, there is now no attractive investment policy support for new onshore wind.

The same goes for existing onshore projects when their support runs out, as they will require repowering to maintain the viability of the "53 GW element" of the 160 GW target.

Even if projects proceed on the basis of wholesale market prices, the increasing proportion of non-dispatchable renewable generation on the system gives rise to an effect known as "price cannibalisation", which over the long term erodes wholesale market price.

Price cannibalisation arises where "must dispatch" technology (wind and solar, but also to a lesser extent nuclear) creates oversupply in the system, pushing down wholesale market power prices.

This was demonstrated on 26 May 2019, when UK power prices turned negative for nine consecutive hours due to a shortfall in demand (2 GW below forecasts), combined with high wind generation (which provided almost 40% of demand).

During this period, wholesale power prices falling to as low as -£71.26/MWh, requiring the National Grid Electricity System Operator (NG ESO) to pay over £6.6 million in balancing costs (compared to just £300,000 the day before).

This illustrated the volatility introduced by high-capacity, intermittent generation.

The investment proposition for wind therefore hinges on whether decreasing technology costs and improved efficiencies, perhaps together with co-located energy storage, can outweigh the combined challenges of wholesale market price cannibalisation and debt providers' limited appetite for exposure to short-term price volatility.

It is hard to see cost of capital continuing to fall if that challenge is not properly addressed (bearing in mind that debt accounts for around 74% of total funding for subsidised onshore wind in the UK).  

 

Propelling towards the carbon goals?

The UK's efforts to bring down carbon emissions tend to focus on closing the gap between installed low-carbon capacity and the capacity target over the next 30 years.

Of almost equal importance is the proportion of installed capacity that will reach the end of its economic life in this period, given that most early projects were designed to operate for 20-25 years.

There is a significant repowering challenge facing the industry – with one estimate pointing out over 8 GW of onshore wind capacity is set to be retired in the next 10 years (almost 20% of the UK's current renewable energy output).

 

CfD: Wind prospecting

Onshore wind projects have some significant issues to overcome before the capacity gap can be closed.

Despite performing well in the first allocation round of the CfD, they were subsequently excluded from rounds 2 and 3 in favour of immature technologies (with a very minor concession in round 3 for remote island wind).

FiT and RO support is now closed to new projects. The loss of revenue is a concern, but it is more likely to be the lack of revenue stabilisation that will significantly affect the bankability of grid-scale onshore wind.

Even if long-term wholesale power prices offer investable returns, bank provided debt finance and infrastructure investors still require protection around short-term volatility

There has been some interesting commentary about the traditional debt-finance model not sitting well with the "policy support-free" onshore projects.

This is primarily because three or six-monthly amortising loan repayments (capital and interest) is normally paid in accordance with the agreed repayment schedule, irrespective of any short-term project cash-flow challenge arising from a dip in power prices.

This means projects without CfD support will have very little tolerance to avoid a debt repayment default, and the associated collateral-related steps that would initiate for the lender.

Thin or negative margins around volatile market revenue could impact the debt service cover ratio as, when the power price dips, there would be insufficient revenue over the debt service requirement.

Such issues do not exist to the same extent with RO or CfD projects, as there will be a long-term guaranteed and stable revenue component in addition to wholesale market price (or in support of a strike price).

The market concern is that debt providers will either lend less, or at a higher cost.

Outside the CfD, challenges around setting a satisfactory de-rating factor (and the difficulties in applying the existing penalty regime to intermittent or non-dispatchable technology) for renewable participation in the CM has traditionally meant there are few other revenue mechanisms to bring comfortable levels of certainty to investors and developers.

BEIS' response to the question of participation by non-subsidised renewable generation in the CM is largely centred on the need to provide a satisfactory answer to the problem of intermittency, which means deciding an appropriate de-rating methodology for non-dispatchable technology.

BEIS have confirmed that the replacement T-3 auction in early 2020 (for delivery in 2022/23) will allow certain renewable technologies to participate.

This will be on the basis of the application of an equivalent firm capacity de-rating methodology, to reflect their intermittent nature.

In addressing this question of intermittency, BEIS commented that allowing the participation of (appropriately de-rated) renewable technology does not increase security of supply, it simply alters where and how their contribution to secure supply is accounted for.

It also noted that "remunerating this contribution is a key principle of the technology-neutral framework of the CM, and a de-rating methodology has been developed to accurately account for that contribution".

Therefore, it will now be possible for subsidy-free renewable forms of generation to participate in the rescheduled 2020 T-3 auction, although the de-rating methodology and increasingly low clearing prices means this opportunity will not come close to replacing lost subsidy regimes.

 

Hugo Lidbetter is a partner specialising in energy and natural resources at European law firm, Fieldfisher. For more information on our renewables and wider energy expertise, please visit the relevant pages of the Fieldfisher website.

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