SUBDIVISION DEL HORN

The principal successive policy instruments intended to deliver increasing renewables capacity, whilst not entailing excessive cost for consumers or the taxpayer, were the Non-Fossil Fuel Obligation, the Renewables Obligation and Contracts for Difference.

1.7.2.1 Non-Fossil Fuel Obligation

The Non-Fossil Fuel Obligation aimed to encourage “demonstration of renewable energy technologies that are approaching commercial competitiveness”. It was

“hoped that, once established, these technologies will be viable without further support” [53].

Under the NFFO Orders (the first of which was known as NFFO1), generators were awarded fixed price, index-linked contracts for their generation at a premium to conventional electricity prices; this premium was underwritten by the revenues of the Fossil Fuel Levy [53].

The first NFFO order, NFFO1, was successful in bringing on renewable capacity and was followed with four further orders in England and Wales (NFFO2-5), three orders in Scotland (Scottish Renewables Orders, SRO1-3) and two in Northern Ireland (Northern Irish Non-Fossil Fuel Orders, NI-NFFO1 and 2) [53].

Only one offshore windfarm, Blyth Offshore (capacity 4 MW) was commissioned under the NFFO regime (NFFO4) [53]. Although one wave project was awarded a SRO contract, no wave or tidal stream projects were delivered under the NFFO, SRO or NI-NFFO orders,

As delivery of capacity under the NFFO regime was insufficient in the context of the Kyoto Protocol – it reached 5% of UK electricity production – Government set an increased target of 10% of power from renewable sources by 2010 [53] and introduced the Renewables Obligation (“RO”) as the mechanism to drive this capacity.

1.7.2.2 Renewables Obligation

The RO, introduced in 2003, placed an obligation on Public Electricity Suppliers to source a defined and increasing percentage of their electricity from eligible renewable sources. If they failed, they were required to buy Renewable Obligation Certificates (“ROCs”) from renewable generators or from ROC traders or pay a

“buyout” price to Ofgem. A similar Obligation was introduced in Northern Ireland.

The total of buyout payments was recycled to those suppliers which had submitted certificates, providing an incentive to comply with the Obligation [54].

The percentage of electricity supply covered by the RO was set at 3% in 2003, rising to 15.4% in 2016 [55].

While the Non-Fossil Fuel Obligation offered different prices to different technology tranches, the Renewables Obligations did not initially differentiate between technology types. The most important change adopted in the Energy Act 2008, was the “banding” of the RO, increasing the level of support to those technologies which needed it most and limiting support to already-viable technologies [52], thereby minimising the overall costs of the scheme. ROC banding effectively doubled support to offshore wind, which received 2 ROCs/MWh, and increased support for wave and tidal to 5 ROCs/MWh.

In response to increasing cost of the RO – due in large part to the increase in offshore wind capacity - the Government announced reform of the UK Electricity Market to “deliver low carbon energy and reliable supplies, while minimising costs to consumers” (“EMR”) [56]. EMR included the replacement of the Renewables Obligation with a new Contracts for Difference (“CfD”) scheme.

As at August 2019, 6,570 MW of offshore wind were operating under the RO [57].

1.7.2.3 Contracts for Difference

CfDs were announced as part of EMR in 2015 [56]. In general terms, the contracts guarantee wind farm developers a defined unit price for electricity generated (called the “strike price”) which would increase in line with the Consumer Price Inflation (CPI) index. The mechanism is that the Government-owned Low Carbon Contracts Company (“LCCC”) pays an amount to the generator in a year in which the market price is less than the strike price, and if and when the market price exceeds the strike price, the developer pays the balancing amount to the LCCC.

Critically, wave and tidal stream were categorised with offshore wind in “Pot 2” of the CfD scheme, meaning that they had to compete directly on the basis of cost for contracts with offshore wind. This had the effect of rendering wave and tidal stream schemes unable to secure funding support.

Early projects were granted CfDs under the FIDeR (Final Investment Decision Enabling for Renewables) awards of contracts, at administratively-set (rather than competitively-bid) prices from £140-150/MWh comparable with the level of

support under the RO [58]. It was recognised that these prices might be “higher than needed” [59], but that it was nevertheless considered desirable to maintain a stream of offshore wind.

Round Strike price Projects

FIDeR awards £140-150/MWh

(administratively set) Beatrice, Burbo Bank Extension, Dudgeon, Hornsea 1, Walney Extension, amounting to 3.2GW

First allocation round £119.89/MWh

£113.97/ MWh East Anglia 1 (714 MW)

Third allocation round Maximum strike price

£53-56/MWh

Bids at £39.65/MWh

Maximum strike price announced for late 2019, bids announced late 2019 [193]

Table 1-1: CfD allocation rounds and strike prices (author's analysis)

As of August 2019, 1,913 MW of capacity were operating under the CfD regime with another 15 GW in the pipeline [57,62].

The actual cost of offshore wind has varied through time, as experience and learning curve effects are offset by technological challenges of larger turbines in deeper water, as shown by Aldersey-Williams et al. [63], but anticipated cost reduction trends demonstrated by CfD strike prices are clearly downwards. The competitive nature of the CfD bidding process is likely to have been a factor in driving down prices for the generated electricity from offshore wind. If delivered, these cost reductions are likely to to “strand” wave and tidal stream projects, which are unable to compete with prices at these levels.