Renewable Energy Foundation

Summary

On its website the Moray Offshore Windfarm (East), known as Moray East and comprising one-hundred 9.5 MW turbines located off the North East coast of Scotland, describes itself as a “highly competitive offshore wind project”.

It is certainly notable for its extremely high levels of income, over £1 billion since it began generating in June 2021 and up to July 2023, with a strikingly high average of £234 per megawatt hour generated, well in excess of the average price of £168/MWh, received by gas-fired generators in the same period.

This is all the more remarkable since Moray East was originally awarded Contracts for Difference (CfDs) in Allocation Round 2 in November 2017 with a guaranteed but capped price of £57.50/MWh in 2012 prices (the CfD administrator calculates that this would at present be equivalent to £74.49/MWh).

However, Moray East has not implemented its CfD, preferring to take the much higher market prices prevailing in the wake of the invasion of Ukraine. As a result of this decision Moray East offshore windfarm received £812 million in electricity sales since coming on line in summer 2021.

Moray East is also asking to be paid to reduce output (constraint payments), a behaviour that is arguably unjustified, adding a further £101 million, plus £195 million contracted wholesale income it receives for the constrained off electricity.

Had Moray East implemented its CfD and delivered electricity at the contracted price, the wind farm would have received £350 million with the consumer receiving the difference of about £460 million under the terms of the CfD. By refusing to take up the CfD contract, Moray East has more than doubled its income and prevented the consumer receiving a rebate of £460 million. Moray East was able to achieve this remarkable result because the CfD contract terms permitted deferral without penalty, in effect placing almost all the risk on the consumer, and very little on the generator.

When generation income and the income it receives when constrained are totalled, Moray East is found to have received over £1.1 billion in the period June 2021 to July 2023. We estimate that this means the consumer has overpaid by approximately £647 million. In that period, the actual volume of electricity generated was 4,740 GWh which means the price paid for wind energy generated by Moray East in this period is £234 per MWh, greatly exceeding the price of gas-fired Combined Cycle Gas Turbines over the same period, which was £168 per MWh. The claim that wind energy is invariably cheaper than fossil fuelled energy appears to be a fallacy.

Detailed Discussion

The UK government awarded Moray East a 15-year Feed-in tariff with Contract for Difference on 11 September 2017. This entitled the wind farm to a guaranteed price, referred to as the strike price, of £57.50 per MWh (2012 prices). Strike prices are (CPI) index-linked so the strike price had risen to £68.55 by the time the first of the three Moray East phases was commissioned in summer 2021.

Under the CfD scheme, the holder of the contract is assured of receiving the strike price regardless of the level of market prices. When market prices are less than the strike price, a levy is charged on the consumer to top up the price so that it matches the strike price. Alternatively, should market prices be higher than the strike price, the wind farm is obliged to return the difference to the contract administrator, with funds being notionally returned to the consumer.

The scheme was designed to give both parties to the contract price certainty. It would incentivise investment in renewable electricity generators by giving security and stability of revenue and avoiding exposure to volatile wholesale prices. At the same time the contract would protect consumers from paying needless subsidies on top of high electricity prices, a factor that has plagued the previous subsidy mechanism, the Renewables Obligation, and made it extremely expensive to consumers.

However, the terms of the CfD scheme as devised by the Government allowed developers to defer the start date of the contract, and Moray East has elected to do this. In the period up to the end of July 2023, they have received £812 million from selling electricity in the wholesale market.

Had they been obliged to take up the CfD promptly, they would have received only £350 million because the price would be capped at the level of the strike price. Thus, Moray East’s decision to exploit the legal loophole and defer implementing its contract, has cost the consumer £462 million. Assuming that the wind farm was profitable at the CfD strike price that Moray accepted, this additional income would have to be accounted as sheer profit and a clear breach of the spirit of the Contracts for Difference system, which was designed to give price security to both parties.

But that is not the whole story. The wind farm has tapped into a second very profitable source of income, namely constraint payments. Moray East is located off the far north-eastern coast of Scotland which is a highly constrained area of the GB electricity grid. 

Fig 1. Moray East windfarm consists of 100 turbines (900 MW) off the north east coast of Scotland (blue). Moray West windfarm (in green) which has consent for 60 turbines (882 MW) is not yet built. 

Constraint payments arise when wind farms are paid to reduce output at times when their electricity can neither be used locally nor, because of network congestion, transmitted to areas of the country where it can be used. Under the subsidy system that preceded the CfD arrangement, wind farms received a subsidy payment on top of the prevailing wholesale price, but they would lose this subsidy if constrained off the system. In the view of some analysts, including ourselves, this loss is a foreseeable market risk, and no compensation should be offered, but the Electricity System Operator (ESO), with the approval of the regulator, has in fact thus far paid the wind farms compensation to cover this lost subsidy.

It is important to note that the constraint payment is recompense for lost subsidy not compensation for the electricity which would have been generated because under the terms of its contract the wind farm is in fact paid for that electricity even though it has not generated the energy.

Moray East has charged £101million to reduce output. But no subsidy was forgone when it was constrained off because it is operating as a merchant generator and taking the wholesale price. Since it will have retained its wholesale income (which we estimate at £195 million at the high prevailing market prices) when constrained off, it has lost no income, and it can reasonably be argued that National Grid should not have paid to reduce output. As it is, Moray East actually earned more per MWh when not generating than when generating and selling normally. This appears to us to contravene the principle set out in the Transmission Constraints Licence Conditions (TCLC) that a generator should not profit from a grid constraint, and to require investigation by the regulator Ofgem.

To put this matter in the context of the CfD deferral: If Moray East had been operating under the CfD and received the strike price for the constrained electricity output, they would have received £112 million. In fact, by deferring their CfD, taking the higher wholesale prices and charging to reduce output during periods of constraint, Moray East made £296 million, some £184 million more than reasonably could have been charged under the CfD regime.

The total overpayment by the consumer arising from the three streams of revenue for Moray East comes to £647 million as summarised in Table 1 below.

The total electricity generated by Moray East in the period of this study is 4740 GWh which gives the cost of £234 per MWh. The comparable cost of gas-fired energy from CCGT generators for the same period is £168 per MWh.

Table 1: Summary of the revenue achieved by Moray East’s revenue by deferring implementation of its CfD and charging for constraints, compared with what would, reasonably, have been charged under the CfD, as estimated by REF for the period June 2021 to end of July 2023.

1 Generation income for Moray East whilst operating outside of its CfD is estimated from the windfarm’s actual generated electricity multiplied by the market index price for each half hour in the period studied.
2 Constraints income is the amount paid by the Electricity System Operator to Moray East for reducing output in the period.
3 Constrained volume proceeds is estimated from the volume of electricity in MWh constrained off the system (and supplied by another generator) multiplied by the market index price for each half hour period.
4 The generation income that Moray East would have received under the CfD is estimated by multiplying the actual generated electricity by the prevailing strike price for Moray East.
5 Constrained proceeds should be zero because there is, in our view, no justification for an extra payment when constrained off, since Moray will not lose income.
6 Constrained volume proceeds if the CfD had been taken up by Moray East is estimated by multiplying the constrained volume by the prevailing strike price.

Table 1 shows that a very significant portion of Moray East’s income, some 27%, arises from being constrained off the system. Indeed, Moray East was by far the biggest beneficiary of wind farm constraint payments of all GB wind farms in 2022: constraint payments to wind farms in 2022 to reduce output came to a total of £227 million with Moray East alone accounting for 30% of that sum.

Averaged over the year of 2022, 29% of Moray East’s output could not be used, and in the month of February 2022 an extraordinary 60% of Moray East’s potential output was constrained off.
Given that Moray East is located in a region where the grid network is notably weak, it is unsurprising that this very large wind farm has been heavily constrained, resulting in a significant cost burden on consumers. We note that permission has already been granted for Moray West which will effectively double the generation capacity in that area, almost certainly resulting in still higher constraint costs for consumers.

Conclusions

The UK’s approach to renewables has resulted in unjustifiably high costs to consumers, but the multitude and complexity of the revenue streams available to generators has concealed this fact. There are two issues that government needs to address immediately. Firstly, the failure to draft watertight CfD contracts has cost the consumer dearly, and it must not happen again. Although Government has recently made changes to CfD legislation requiring generators to take up CfDs promptly for future projects, it is difficult to see how this loophole has been definitively closed when some developments involve CfDs on subsets of their output. Secondly, constraint payments such as those obtained by Moray East have been an absurdly expensive scandal for more than a decade, and Ofgem should take firmer action to protect the consumer.

 

Renewable Energy Foundation has published two substantial studies of wind farm economics by Professor Hughes, the latest of which appeared in 2020. The present study applies the same principles to the analysis of large, utility-scale, solar generation in the United Kingdom and in the United States. Inquiries regarding the study can be made to This e-mail address is being protected from spambots. You need JavaScript enabled to view it .

1. Between 2011 and 2020, 13.4 GW of solar generation capacity was installed in the UK, two-thirds of it in the years 2014 to 2016 in response to what were seen as generous subsidies. This study uses data from company accounts to examine the actual capex and opex costs of building and operating solar plants. In addition, it examines the relationship between age and the performance of solar plants in both the UK and the US. The results are used to assess the economic viability of solar generation if subsidies are reduced or eliminated completely. The conclusions are strikingly different from the claims or assumptions made by official bodies and industry sources.

2. It is well-known that the cost of solar panels fell sharply during the 2010s. Many have assumed that the overall cost of building solar plants has fallen similarly and, even more important, will continue to fall in future. The data show that there was a 15% decline in the average capex cost per MW of capacity from 2011-13 to 2014-16 and a 10% decline from 2014-16 to 2017-20. The average capex cost per MW was £0.95 million at 2018 prices. The trend in capex costs is consistent with the fall in the costs of solar panels and inverters, but other costs have increased over the period and appear to be affected by a scarcity of equipment and skilled labour. Further falls in the cost of solar panels will only have a limited impact on total capex costs.

3. The average annual level of opex costs per MW of capacity for solar plants is 3 to 4 times the official assumptions at about £36,500 for a plant in the size category of 10-20 MW. Opex costs are highly variable over time and across plants because of equipment failures and other factors, but the pooled data suggests that they tend to increase with the age of the plant. The estimated rate of increase over time was about 5% per year in real terms. That rate of increase may fall as the industry matures but it would be prudent to assume that opex costs will increase by 2.5% to 3% per year in real terms.

4. There is extremely strong evidence from both the UK and the US that the output of solar plants falls at 1% to 2% per year after age 3 years, after controlling for the level of solar radiation. The rate of decline in output is higher in the US than in the UK which may reflect differences in maintenance practices or the greater length of experience in the US. If the US pattern prevails in the UK, solar plants reaching the end of their period of eligibility for ROCs will have an expected output for standard weather conditions which is 30% lower than in their early years of operation.

5. The combination of rising opex costs and declining performance means that existing solar plants are unlikely to cover their operating costs once their period of eligibility for ROCs comes to an end after 20 years and they move to operating as merchant generators. Recently, many of the SPVs which own and operate solar plants have changed their accounting assumptions to increase the economic life of their assets from 25 to 35 years. This modification is ill-judged and potentially damaging to investors as the evidence suggests that the economic life of solar assets is unlikely to be significantly greater than 20 years.

6. The breakeven price of electricity for new investment in solar plants is £108 per MWh over a 25-year life under the most optimistic assumptions about opex costs and performance and it is £123 per MWh under more realistic assumptions. These breakeven prices are significantly higher than for onshore wind but comparable with breakeven prices for offshore wind.

7. Solar plants in the UK are not financially or economically viable as pure merchant generators. They require either subsidies or non-commercial power purchase agreements which offer an average offtake price that is at least three times what they could expect to earn by selling at the average day-ahead price over the period 2015-19. Since solar plants must compete with wind generation for CfD contracts, new investment in solar plants is likely to rely primarily on the willingness of companies to pay much higher than market prices for the electricity that they produce or to make sites and other resources available at below market rates.

8. It should be emphasized that the UK has much poorer solar resources than some other countries in Europe and most states in the US, while both land and skilled labour are expensive in the parts of the UK where solar resources are best. The conclusions of this study about the relationships between operating costs, performance and age are relevant to solar generation in other locations. However, the fundamental determinant of the economic viability of solar plants is the quality of the solar resources. Spending public money to promote solar generation in the UK seems to be a very poor use of limited budgetary resources.

9. The UK Government’s Energy Security Strategy published in April 2022 claims that: “The cost of solar has fallen by around 85% over the past decade [...] We expect a five-fold increase in deployment by 2035.” The first statement is demonstrably false when applied to utility-scale solar plants which account for about 50% of total capacity. The goal of increasing solar capacity by 56 GW would destabilise the grid and impose a burden of up to £10 billion per year on either taxpayers or energy consumers for practically no benefit. It is, of course, a fantasy in practical terms but such fantasies cause enormous damage by diverting resources from addressing the real sources of high energy costs in the next five years.

Payments to wind farms to reduce output are an ongoing national scandal, with the cost to consumers now totalling well over £1 billion since the payments began in 2010.

We have repeatedly observed that the prices charged by wind farms to reduce output not only routinely exceeded the subsidy income lost when constrained but were hard to justify in any case. Grid congestion preventing dispatch is a foreseeable commercial risk and the windfarms should not be compensated at all for such an eventuality.

However, it has been accepted by government and the regulator that such compensation – for lost subsidy – should be paid.

However, in recent months Scottish wind farms that are not in receipt of income support subsidy, so called “subsidy-free”, wind farms have also been charging the electricity system operator to reduce output when generation in Scotland exceeds grid capacity and local demand.

These wind farms usually have a power purchase agreement (PPA) with commercial entities such as Tesco, who have a PPA with Halsary wind farm, and Amazon, with Beinn an Tuirc III windfarm. The commercial companies, who buy the electricity, almost certainly do so to comply with recently introduced pressure via the Streamlined Energy and Carbon Reporting framework, which is embedded in the Companies Act and thus backed by criminal sanctions, to demonstrate their commitment to carbon reduction and to renewable energy. It is the existence of this little understood legal pressure that raises questions about whether such wind farms are really “subsidy-free” but this is a separate question. The fact of the matter is that these wind farms are not in receipt of income support subsidy levied on the consumer, and they suffer no loss of subsidy when they are constrained.

Why, then, are these “subsidy free” wind farms charging for constraints, and, more pertinently still, why is the regulator, Ofgem, allowing them to burden the consumer with these charges?

It should be recalled that neither subsidised nor unsubsidised generators forego payment for the electricity which would have been supplied to the grid if the curtailment had not been necessary. This may seem strange but is reasonable in terms of current market structures; the generator has sold their electricity to a customer, either a supplier or an industrial consumer under a PPA; and it would be wrong for that bilateral contract to be jeopardised by grid management necessities. However, this is not efficient from the consumer’s point of view. While the curtailed wind farm is paid by their customer as usual, the energy shortfall on the other side of the grid bottleneck is supplied by the Electricity System Operator (ESO) from other generators (typically fossil fuelled generators) and usually at premium price because of the extremely short notice.

Electricity consumers ultimately foot the bill for this electricity balancing action: the PPA consumer honours its contract; and the general consumer (including the PPA consumer) then pays any constraint payments to the wind farm, and the cost of the replacement electricity from the, usually fossil fuelled, generator plus any other costs incurred by the ESO in carrying out the constraint balancing action.

We have argued, see above, that even subsidised generators should not be compensated for lost subsidy in this eventuality. We think they should simply take the hit as normal commercial risk which would have the benefit of removing the perverse incentive that currently encourages the building and extending of wind farms in the highly constrained areas of rural Scotland. But we accept that there are arguments in favour of compensation, though we think those to be very weak arguments.

But it is difficult to see any justification whatsoever for allowing wind farms that are not losing income when constrained to charge for this reduction in output. Their commercial position is not harmed, and the constraint payment represents additional income. We think that is wrong, and that Ofgem should step in to protect the consumer from what will seem to many to be ruthless opportunism.

The following table lists the unsubsidised wind farms and their constraint volumes and costs for 2022 to date.

Table 1: Unsubsidised wind farms constraints volume in GWh and cost of this in 2022 (as at 27 October 2022) plus the average price per MWh being charged by the wind farm to reduce output.

1 Generation proceeds in £000’s is estimated from the windfarm’s actual generated electricity for the first 9 months of 2022 multiplied by the system price for each half hour period

2 Constraint cost is the amount paid to the windfarm for the constrained off volume in the 9 month period

3 Constrained volume is the volume supplied by the ESO during the constraint period on behalf of the constrained wind farm and the proceeds are estimated from the windfarm’s constrained volume in MWh multiplied by the system price for the appropriate half hour period

4 Price per MWh actually generated is derived from the total income value divided by the actual volume generated by the wind farm.

It should be noted that the total income per MWh being achieved, which range from £192/MWh to £413/MWh is extremely high compared to previous years, for example in 2019 and 2020 such prices were around £30-£40 per MWh. However, the income is also high compared with that received by an unsubsidised wind farm sited where there are no grid constraints, which we estimate would be £178 per MWh for the equivalent period.

The Gordonbush wind farm extension stands out in the table above because it has been charging least (£8/MWh), and so has been called on relatively often by the ESO to reduce output. As a result, approximately 56% of the potential generation of the Gordonbush wind farm extension is being discarded (See Table 3). This increases the ultimate cost per MWh to the consumer who has to pay the constraint cost plus the cost of the replacement energy.

If one includes these costs, the electricity actually generated by Gordonbush extension has cost the consumer over £400 per MWh on average in 2022. This is 2.3 times what wind generated electricity would have cost in this period if it were unsubsidised and was sited where there were no constraints. Constraints on this scale also raise important questions about the balance of harm and benefit underlying the grant of planning permission. Did decision makers understand that Gordonbush was very likely to be heavily constrained, rendering its putative benefits much reduced and thus, at least arguably, vastly outweighed by its harms. (See REF’s earlier blog)

Table 3: Actual energy generated and constrained in GWh for the unsubsidised wind farms in receipt of constraint payments for the period 1 January 2022 to end of September, and the discarded proportion as a percentage of the potential total output.

Large volumes of wind energy are being discarded in Scotland in order to preserve grid stability, with a fleet average of over 13% of generation constrained off in the years 2015 to 2021, inclusive, with a high of 19% of generation in 2020. Some wind farms have been discarding between 20% and 50% of their output, while being rewarded with generous constraint payments from the electricity consumer for doing so. The reductions in environmental benefits are not given adequate weight in the planning system, where the low marginal benefit of additional wind capacity appears to be poorly understood. This blog offers detailed data on the volumes of wind energy constrained off at a fleet level in Scotland between 2010 and 2021, and for every individual wind farm in 2020 and 2021.

Figure 1: Part of the Monadhliath Mountains, with Creag Mhor overlooking Loch Gynack in the foreground.  By Spike - Own work, CC BY-SA 4.0, Link

Wind turbine generation has been weak in 2021 due to low wind conditions, with total (onshore and offshore) output reduced by about 14% in 2021 as compared to 2020 (61 TWh estimated in 2021 as compared to 72 TWh in 2020). Onshore wind output has been the most severely affected, with a reduction of 20% in 2021 (27 TWh estimated) as compared to 2020 (34 TWh).
This has had a significant effect on the volumes of wind energy constrained off the system, with a corresponding and welcome reduction in the total cost to consumers.

In 2020 constraint payments to onshore wind in Scotland amounted to 3,460 GWh (at a cost of £243m), whereas in 2021 this was 1,783 GWh (at a cost of £107m), a reduction of 48% by volume of energy.

While it would be reasonable to say that grid reinforcement and the somewhat improved reliability on the Western Link interconnector account for part of this reduction in constraint payments and volumes, the majority of the effect is the result of reduced wind power output, which reduces the need for wind to be constrained off the system. This reduction in output affects individual wind farms in a way that is highly significant from several perspectives.

Firstly, the average load factor of Scottish onshore wind farms has fallen from 26.7% in 2020 to 22.1% in 2021. This is the second lowest fleet load factor in 20 years, the lowest being 21.5% in 2010. A reduction of this magnitude has implications for the wind farm’s Internal Rate of Return (IRR), a shortfall that may be difficult for the investors to recover without exceptional output in the future, exceptional output that probably lies beyond the end of their economic lifetimes for older and even middle-aged installations. This will have implications for the way that investors view the future of these assets, particularly older sites where maintenance costs are rising.

Secondly, the reduction in output in 2021 is a substantial contributor to the current energy bills crisis, having caused the electricity system to draw heavily from gas fired generation at precisely the moment that many other systems in Europe were experiencing the same problems. This has combined with high international demand, particularly in Asia (which is reducing greenhouse gas emissions and local air pollution by switching from coal to gas) to drive particularly high prices of natural gas in the European region.

This effect may have come as a surprise to many renewables supporters, who expected that large wind fleets would buffer the United Kingdom against high gas prices. In fact, as is well-known to experienced analysts and has been long-predicted, a heavily renewables-based system becomes critically dependent on natural gas generation across all timescales, from seconds to years, in order to guarantee security of supply. The volume of gas consumed may fall, but, paradoxically, the exposure to gas and its price increases. The addition of more wind power will do little or nothing to mitigate this effect, and will all but certainly intensify the problem.

Thirdly, the reduction in constraint volumes brings into sharp focus the low marginal benefit of adding further wind capacity in Scotland. A reduction in wind power output, such as that in 2020, reduces constraint payments. Therefore, conversely, any new proposal for wind power in Scotland, which increases potential output, must be expected to increase constraints. Additional capacity therefore has a high probability of some part of its own output being constrained off, reducing the global environmental benefits it can claim to offset local environmental harms. This matter should obviously be given close scrutiny in the planning balance by decision makers. However, and as far as we are aware, the Scottish Government has not issued formal advice requiring Reporters to take the matter into account.

The constraints problem will persist until there is more than sufficient interconnection between Scotland and the centres of demand in England. Given the Scottish Government’s plans for wind, particularly offshore, it is not clear that the required level of interconnection is either feasible or economically viable. Constraints are therefore likely to persist for the foreseeable future, with wind capacity constantly outrunning the network’s ability to transport it to consumers at reasonable cost.

The tables below provide detailed figures on the degree to which Scottish wind farms are discarding potential generation, all the information being based on our own datasets as collected from official market sources. The first table provides our calculated estimate of Scotland’s wind generation output by year, the level of actual constraints in those years, and a calculation of the proportion of wind energy that has had to be discarded to preserve grid stability. The second table provides similar estimates of generation and discarded energy for each individual wind farm in both 2020 and 2021.

The headline findings from these tables are stark. On an annual basis since 2015, when the wind fleet reached substantial levels, Scotland has been discarding around 13% of all wind energy that it could have generated. This figure rose to a high of 19% in 2020, when demand fell due to lockdown and other public health measures, before falling back to 13% in 2021, a low wind year with recovering levels of consumer demand.

It follows that decision makers in the planning system should expect that if a wind farm currently applying for consent has not taken the potential for constraints into account, it is likely to have over-estimated its actual benefits of generation by between 10% and 20%, figures that could be crucial in determining the planning balance given the significant adverse local, and even regional environmental impact of many wind farms, on wildlife and the landscape and visual quality of unspoiled wildland areas.

However, the results on a site-by-site basis indicate that a general figure may not give an adequate insight into the scale of potential losses. Some wind farms in 2020 discarded extremely high fractions of their potential output. Corriegarth, for example, lost about 51% of its output to constraints, with other notable sites being Strathy North (48%), Blaraidh (47%), and Farr (39%). Even some of the largest, high-profile sites in lowland areas had to discard substantial proportions of their output, such as Whitelee (31%), and Fallago Rig (27%). Strikingly, these proportions remained very high even in 2021 and in spite of the facts of weaker winds and higher demand. In this year, Dorenell discarded 35% of its output, and Strathy North 28%, Bhlaraidh 24%, Farr 22%, Whitelee 17%, and Fallago Rig 15%.

It should be noted that many of the heavily constrained wind farms are located in areas with great ecological, environmental and wild land value. One such area is the Monadhliaths, Great Glen region adjacent to Loch Ness. This region is one of Scotland’s most remarkable wilderness areas, known for the unaltered antiquity of its landscape and its austere beauty (see Figure 1 above). Nine large wind farms have been built in this remarkable wild land area (see Figure 2 below). All of these received constraint payments in 2020/2021 with an average of 22% of potential output being discarded, averaged over the two years at a total cost to the consumer of £67 million. In spite of the clear economic evidence that the site is saturated, there are seven further wind farms in that location going through the planning system, which could increase the installed capacity by 66%. ;four already with permission to build and three awaiting a decision. It seems that the planning process is failing to consider the multiple harms to the public interest incurred by developments which sacrifice an irreplaceable natural landscape for consumer-subsided wind farms whose output is capped – at a further cost to the consumer – because the site is a wilderness remote from where power is required.

There can be no serious doubt that this is an important issue for the planning system and that it needs to be addressed to preserve public confidence in the rationality of decisions taken by reporters and the Scottish Government.

Figure 2: Wind farms are indicated by circles whose area is proportional to their installed capacity. The nine operational and constrained wind farms as of 2022 are labelled and coloured red.  The four wind farms with planning consent are the blue circles and numbered as follows :  Glen Kyllachy (1) 50 MW; Aberarder (2) 50 MW; Dell (4) 42 MW; Millennium South (3) 35MW. The three wind farms whose planning permission has not yet been determined are identified by yellow circles and are: Corriegarth II (5) 76 MW, and Cloiche (6) 150 MW and Glenshero (8) 168MW. Note that both Cloiche and Glenshero are each effectively split over two locations west and east of the centre of Stronelairg.  The areas of the pairs of circles numbered 6 and 8 are proportional to the relative sizes of the west and east parts of the proposed Cloiche and Glenshero wind farms.

 

Table 1: Annual electrical energy generated and constrained at all Scottish wind farms, 2010 to 2020. The generation data is derived from monthly Renewables Obligation (RO), Contracts for Difference (CfD) and Renewable Energy Guarantees of Origin ( REGO) data for Scottish wind farms as reported in the REF databases. As of the date of publication of this blog, the generation data for 2021 is not complete for all generators. However, for those wind farms where there is generation data for a month, the constraints volumes for that generator and month are also included in the totals below to ensure consistency in calculating the percent of output that is discarded in 2021.

It is frequently claimed that the subsidy cost of offshore wind farms has fallen over the past few years. The UK government itself is on record as recently as November 2020 claiming that:

Government support to unleash the potential of offshore wind generation has seen the cost of it fall by two thirds in the last 5 years.

Echoes of these claims are commonplace. The Times (08.07.21) reports the think tank Policy Exchange as remarking that “the cost of offshore wind power had fallen steeply in recent years”.

As work by Professor Gordon Hughes has shown, the capital and operating costs of offshore wind do not support these observations, and, as this blog will demonstrate, it is a matter of fact that the cost of consumer subsidies to offshore wind per unit of electrical energy generated (MWh) has risen and continues to rise year on year.

As of the end of 2020, there were 41 operational offshore wind farms which receive a subsidy levied on consumer electricity bills via either the Renewables Obligation (RO) or the Contract for Different (CfD) subsidy mechanisms. If one sums the subsidy paid to each offshore wind farm and divides this by the recorded generation it is possible to plot the average cost per MWh generated, as in Figure 1 below. It will be immediately apparent that far from falling, there has been a continued and substantial increase in average subsidy per MWh for offshore wind.

Figure 1. Subsidy in GB £ per MWh of Offshore Wind Generated. Source: Data: Ofgem; BMReports, Calculations by REF.

This trend will not be surprising to anyone who understands the (admittedly obscure) subsidy mechanisms for renewable generation in the UK, since it reflects the increasing levels of subsidy awarded by the UK Government to successive offshore wind farms as they have been built, and the fact that these subsidy rates are index linked and designed to persist for 15 or 20 years per site.

From 2002 until 2018 when the Renewables Obligation closed to new entrants, the number of Renewables Obligation Certificates (ROCs) issued to offshore wind per MWh changed several times for new entrants. The oldest offshore wind farms such as Scroby Sands, Kentish Flats, and Barrow, which were all built prior to 2006, received and continue to receive 1 ROC per MWh. Offshore wind farms built after 2006 receive (and continue to receive) either 2 ROCs per MWh, or 1.9 ROCS or 1.8 ROCs per MWh depending on when they were accredited by the regulator, Ofgem.

The value of a ROC increases year on year with the retail price index (RPI) and is further boosted if the total number of ROCs in any year is less than required by Government, such that in 2002 the value of a ROC was £46 whereas in 2020 it is approximately £55. Thus, the wind farms in the 1 ROC per MWh band, such as Scroby Sands, cost £55 in subsidy per MWh generated in 2020, whereas those in the 2 ROCs per MWh band, such as London Array, Thanet, and Gwynt y Mor, cost £110 in subsidy per MWh generated.

Generators will receive index linked subsidy in their allocated RO subsidy bands for 20 years from accreditation. This means, for example, that Humber Gateway which was accredited in 2015 will continue to be subsidised at 2 ROCs per MWh until 2035.

There are three special case offshore wind farms subsidised under the RO with extremely high levels of subsidy, namely the Aberdeen Offshore demonstration unit which receives 2.5 ROCs per MWh, and two floating offshore wind farms, Hywind and Kincardine, which receive 3.5 ROCs per MWh. The latter two wind farms are the most expensive for the subsidising consumer in that they cost £193 per MWh generated.

The subsidy cost per MWh for RO supported generators will not fall because the support mechanism is designed such that the subsidy increases. The total subsidy burden on the consumer will only fall as the 20 year support duration ends for individual sites and they cease to be subsidised.

There are six live offshore wind farm sites subsidised via Contracts for Difference as at the end of 2020. The CfD provides subsidy as a top up payment that the generator receives over and above a reference price (essentially the wholesale market price for electricity) to match a strike price, in essence a guaranteed price, that the wind farm owners were awarded in their contracts.

Strike prices increase annually in line with the consumer price index (CPI) and the contracts are for 15 years.

The following table gives a very simplified outline of the subsidy calculation. The strike prices are those for each wind farm as at the end of 2020. If one uses the average reference price in 2020 which was £35 per MWh, the subsidy paid by the consumer for the CfD supported offshore wind farms ranged from £104 per MWh to £139 per MWh. In fact, the hourly reference price in 2020 ranged from - £39 per MWh to £350 per MWh and the calculation of total subsidy which we have made for this blog uses the actual reference price for each hour of the year.

Unlike RO-supported generators, the subsidy cost per MWh for CfD supported generators can fall if the wholesale price of electricity, and thus the reference price, increases. For example, for a reference price of £70 per MWh which would arise if the wholesale price of electricity doubles, the subsidy per MWh in the table above would range from £104 per MWh to £69 per MWh. However, this is of no comfort to the electricity consumer because the component of their bills that covers wholesale electricity costs will have risen to cancel out any potential savings on CfD subsidy savings. 

It is important to recall that some of the highly subsidised offshore wind farms are large and consuming a substantial proportion of the total subsidy provided to the industry.

On the basis of official RO and CfD data we estimate the total subsidy in 2020 for offshore wind to be over £4.3 billion. Eight of the 41 offshore wind farms took more than 50% of that total, with Hornsea taking 11% or £480 million.

Statements from official sources, carelessly echoed in the press, may have given the impression that the unit subsidy cost in £/MWh, and thus the total cost to consumers of subsidy to offshore wind has been falling. As this basic survey of the facts shows, this is simply not the case.

 

There is ongoing interest in Professor Gordon Hughes’ empirical work on the economics of wind power, with occasional requests for talks and summaries, and updates and recent reflections. The attached paper was presented recently to a London-based financial organisation. It summarises afresh the work published by REF in 2020, and offers additional comments.

On the 10th of April this year Professor Gordon Hughes of the University of Edinburgh submitted a paper on the economics of small-scale wind generation in Northern Ireland as formal evidence to the "Inquiry into Generating Electricity from Renewable Energy” conducted by the Public Accounts Committee of the Northern Ireland Assembly.

Professor Hughes gave oral evidence to the Committee on the 22nd of April. A full recording of the whole session, including the evidence of other witnesses, is available here: Public Accounts Committee Meeting Thursday 22 April 2021. Professor Hughes' evidence begins at approximately 1hr 43 minutes into the session.

Professor Hughes' paper given in written evidence is now available for download from the REF website: Small Wind Generation in Northern Ireland.

The evidence provided to the Public Accounts Committee is an extended development of a subject first broached by Renewable Energy Foundation in a blog post published on the 24th of September – "Extreme Subsidies to Small Wind Farms in Northern Ireland: A Bureaucratic Oversight? – which was the subject of extensive media coverage.

Those interested in this subject may also wish to read the October 2020 study of the same general topic by the Northern Ireland Audit Office: Generating Electricity from Renewable Energy, and a study contradicting the Audit Office’s findings, commissioned by the trade body Renewables NI from KPMG, An economic review of small-scale wind in Northern Ireland.

Professor Hughes' study of Northern Ireland wind can also be read alongside his two volume book length study of the economics of wind power in the UK and in Denmark, published by REF in November 2020: Wind Power Economics: Rhetoric & Reality 

Professor Gordon Hughes has written the following blog describing his experience of sourcing reliable energy supplies to power a remote rural broadband network in Scotland.

I have written a number of papers on the costs and performance of wind power and other forms of renewable energy. Even serious empirical research provokes responses along the lines that any questioning of the merits of renewable energy amounts to original sin or blasphemy. There is little that I – or anyone – can do to convince those who treat the superiority of renewable energy as an article of faith. Still I wonder how much practical experience such commentators have of the reality of relying solely on renewable power in commercial applications. For this reason other readers may be interested in what I have learned as an economist faced with the practical issue of relying upon renewable energy.

The context is that about seven years ago I set up a small wireless broadband network serving my local community. This has grown into a social enterprise that provides high speed broadband service to about 600 properties in the South of Scotland. We are good at what we do and as a consequence we are expanding quite rapidly and cover a very rural area of about 1,500 square miles. We serve properties and settlements that BT/Openreach find too hard or expensive to deal with. To do this, we rely heavily on relays in locations that are far from the nearest source of power and operate off-grid. Since the South of Scotland from the Ayrshire coast to the North Sea has numerous wind farms a casual observer might think that off-grid operation is relatively straightforward. It would make our lives much easier if things were so simple!

Even though we serve isolated properties and settlements our customers are as concerned as urban residents about having a reliable broadband service. They or their children are equally unhappy about interruptions to their Zoom meetings or Netflix viewing sessions as any family living in the centre of Edinburgh. They understand that we have to cope with much worse weather conditions than most operators, so occasional outages due to extreme weather are unavoidable. We work to meet an overall target of 99.5% availability for our service. Since weather and other factors outside our control account for most outages, we design our network with sufficient backup to achieve at least 99.9% reliability for power supply at all of our relays –including the off-grid units. That is a difficult target when relying solely on renewable energy in Scotland. National Grid’s alarms this winter about meeting demand is merely a much bigger version of the same problem.

The problem for any off-grid site in Scotland is maintaining power supplies during the winter months from mid-November to end-February. Solar panels, which are our main source of off-grid power, yield little during this period – partly because the length of daylight is short and partly because the sun is very low in the sky which means that insolation levels are low even when the sky is clear. Almost all of our off-grid relays are sited in hilly areas at 350+ metres above sea level. You might think that these sites are all windy, but wind turbine yields are extremely variable. Extended periods (five or even ten days) of low wind combined with fog or mist and limited light occur three or four times every year. As an illustration we have just experienced a period of fifteen days (from December 26th 2020 to January 9th 2021) with minimal wind and solar output. Freezing conditions make such episodes worse because the performance of batteries degrades in sub-zero temperatures. Even with large amounts of battery backup we find ourselves having to transport replacement batteries all too often.

Let me give a sense of the numbers. We choose our equipment and design our off-grid relays to minimize power consumption. Most of our relays have a continuous power demand of 40-60W, little more than an old-fashioned incandescent light bulb. We use 12V AGM deep cycle batteries  which cope better with variations in temperature and state of charge than regular car batteries. Lithium-ion batteries are, at least for now, too expensive and have too short a life for this kind of application. A continuous demand of 60W translates to 120 Amp-hours (Ah) per day. Even deep cycle batteries cannot be discharged completely without drastically shortening their life, so a bank of eight 120Ah batteries will power a relay for up to six days.

To operate such an off-grid relay at 99.9% reliability (less than 96 hours of outages per year for a set of ten relays), a standard relay with a continuous consumption of 50W has 900W of solar panels, a 350W wind turbine and eight  to twelve batteries plus some occasional load shedding – i.e. switching off non-critical links. This translates to peak generation capacity that is more than twenty times the continuous demand plus enough battery capacity to meet six to eight days of consumption. Allowing for the ancillary equipment - charge controllers, voltage monitors, etc - plus installation, the cost of such a setup is about £6,500 excluding VAT. That amounts to a capital investment of more than £100,000 per kW of continuous demand. For us the breakeven point between on-grid and off-grid is where the power cable would run for about 1,200 metres because the power loss on longer cables is too high unless they are run on three phases which increases the total investment.

This is the engineering reality of using renewable power with no grid backup. There is no dogma about the choice: we choose the best solution that is consistent with what our landowners will accept and our requirements. The lesson is the high level of redundancy that is necessary to provide the level of reliability that is expected by customers in modern economies. Bear in mind that 99.9% reliability is nothing special: the power company that serves the central area of Hong Kong has a reliability standard of 99.99% (less than one hour of outages per year) mandated by the government.

Viewed in a different light, it would be much easier for us at our off-grid sites if we could switch off relays between, say, midnight and 6 am whenever both batteries are running low and wind generation is low. That is what load shedding, referred to in many plans to cope with variability in renewable generation, means in practice – but without backup generators or alternative sources of non-renewable generation. But what happens to our customers who work with clients in Asia or who have families in Australia or California? Or what, on a larger scale, about hospitals, hotels and businesses who rely upon 24/7 availability of broadband and network services?

Thirty odd years ago when the current wave of enthusiasm for renewable energy started, many of us involved saw the huge benefits from bringing electricity to rural areas in developing countries. It was similar to using hand pumps to provide clean water in villages with no access to piped water. Whether it was getting access to crop prices, pumping water for irrigation or watching TV in the evenings, even a limited and irregular supply of power provided by a few solar panels, some batteries and an inverter can transform lives for billions of people living off-grid.

However, that is not the world of rich or even middle income countries today. We have built our economies and lives on the assumption of plentiful and almost completely reliable power, broadband and other networks. At the less critical end of the spectrum I invite any reader to monitor our support lines if there is an outage in the middle of the Scotland vs England rugby match. Even occasional buffering of a Netflix or Zoom stream is a “disaster”. Or consider the threat to people’s health and transport chaos caused when there was a relatively brief power outage affecting London and South East England in August 2019.

Some argue that the problems of ensuring high levels of reliability in a power system entirely dependent on renewable generation can be largely mitigated by scale, in effect by pooling sources of generation over a large area. There are, indeed, some economies of scale but they are smaller than might appear at first glance. It is still necessary to have high levels of excess capacity – not at one location but spread across the system – and any reduction in total capacity per unit of continuous demand is offset by the need for heavy investment in transmission capacity. In addition, on a small scale it can be easier to rely upon diversification across types of renewable generation, something which may not be feasible at a regional or national scale.

The central lesson from this story is that the key issue for power systems which rely upon renewable generation is not energy but system stability and reliability of supply. With sufficient capital it is easy to generate electricity at a marginal cost that is close to zero, but guaranteeing high levels of reliability is much more difficult and expensive. Our small network is a microcosm of the trade-offs that face rich economies that wish to switch entirely to rely upon renewable sources of power. Such systems will always be highly capital-intensive: that is an inescapable consequence of using current resources in place of stored energy in the form of fossil fuels. The trade-off is between:

• accepting some combination of a moderate increase in system capital-intensity plus a substantial reduction in reliability relative to the level that people living in rich countries have learned to expect; or
• paying for a large increase in the overall capital-intensity of power networks so as to maintain something close to current levels of reliability.

Politicians and enthusiasts for a renewable transition are strongly inclined to fudge such trade-offs. The managers of existing power systems are rarely willing to deliver unwelcome messages and may expect to benefit from the large capital spending that is required by the transition. As a consequence, most public discussion of the necessary choices relies on vapid good intentions rather than a realistic appraisal of the costs and benefits of the alternative options.

There is a further issue, which is that the costs and difficulties of relying upon renewable power are not evenly spread. Much of the support for green solutions comes from people who live in cities and other urban areas. Advocates give the impression that they have no idea what it is like to live in thinly populated rural areas, where distances are large and public services are either minimal and/or unreliable. In my case the distance to our local shop is 10 km and to the nearest town with basic public services is 15 km. And we live barely 40 km from Edinburgh, not in a remote part of the Highlands! Rural Scotland has lots of wind farms but little in the way of public services or, indeed, benefit from those wind farms.

This matters because it is rural areas that are likely to experience the most serious costs of a reduction in system reliability. To extend the personal example, we experienced a series of power cuts on Christmas Eve 2020 which caused our primary heating system to fail due to a power surge. It was out of operation for 6 days during the coldest weather of the 2020-21 winter to date. Such episodes have occurred in the past and we have invested in alternative sources of heating. Hence, we coped, albeit at a significant cost. That is the point. Around the world, the costs of reducing system reliability are often high but they fall unevenly on customers, especially on those living in rural areas. All too often those who offer simplistic calculations of the costs of relying upon renewable power take no account of the consequences for system reliability and the costs that fall on those who have to cope with less reliable power supply.

To emphasize the general point: the central challenge of the transition to renewable power is not the generation of electricity. That is the easy part. Rather it is the difficulty and costs of ensuring system reliability that must be addressed. Up to now, all electricity systems depend upon a legacy of investment in storable energy resources, primarily in the form of fossil fuels but with some storage hydro. None of the operators has any real idea of how they will function without being able to call on such backup resources. While scale will permit options that are uneconomic for small operators, the lesson from experience is that the investment and operating costs required to maintain system reliability in electricity systems dependent on intermittent renewables are likely to be very large.

Finally, we should bear in mind that not all communities or countries will – or should - make the same choices, in large part because conditions around the world vary so much. It is simply absurd to assume that choices which make sense for urban populations in Europe are either feasible or sensible in the remoter areas of Eurasia – for example Siberia or the huge extent of arid or semi-arid land from the Pamir Mountains to Mongolia. The inclination by some to frame the renewable transition as a moral issue is not the most constructive approach to dealing with the different trade-offs that have to be made in different circumstances. In many circumstances this can appear either arrogant or tone deaf when directed to populations and governments who face different choices and may feel that they are being asked to sacrifice the benefit of economic growth that those living in rich countries take for granted.

Gordon Hughes

Renewable energy is often claimed to empower local communities as well as providing economic benefits. Part of the logic is that renewables seem to offer “energy independence”. The truth is less straightforward. In this article, co-authored with Professor Gordon Hughes of Edinburgh University, REF examines the case of the Viking Energy wind farm in the Shetlands and more broadly that of Scotland itself.

For 600 years from the mid-9th century to the mid-15th century, the Shetland Islands were the largest component of the semi-independent Viking Jarldom of Orkney and Shetland and as such affiliated with both Norway and Scotland. They were transferred to Scotland in 1470 in lieu of the dowry payable when Margaret of Norway married James III of Scotland. They became part of the United Kingdom with the Act of Union in 1707, and they have been associated with the United Kingdom for longer than they were part of an independent Kingdom of Scotland. That history is, perhaps, reflected in their somewhat ambivalent relationship with Edinburgh over the last fifty years.

Now, with the willing involvement of the Shetland Islands Council, the Scottish Government and the Ofgem (the UK’s energy regulator), the Shetland Islands are being converted into what will to many seem like a private colony operated by the power company SSE.

The role of the Scottish Government is no surprise: SSE is the largest company based in Scotland and has been consistently supported by the Scottish Government.

It is less clear why the Shetland Islands Council or Ofgem should facilitate this project, the key elements of which are:

(a) the construction of a large onshore wind farm, “Viking Energy”, with a capacity of 447 MW, and

(b) a 260 km largely undersea transmission cable with a capacity of 600 MW from Kergord in Shetland to Noss Head, Caithness in the north of mainland Scotland 

Since Scotland is awash with excess wind power, the electricity from Viking will be exported to the North of England – but only when there are no constraints on North-South transmission capacity. That is not a trivial qualification because wind generation capacity in Scotland already exceeds by a substantial amount the capacity of the cross border inter-connectors and the sub-sea Western Link. Thus, the reality is that for many hours in the year Viking Energy will simply add to the amount of wind capacity in Scotland that has to be constrained off the system, being paid (very generously) for that.

The role of Ofgem is particularly controversial. As the regulator it has a statutory duty to protect the interests of electricity and gas customers in the whole of the United Kingdom. More than 90% of the costs of the subsea transmission system and any constraint payments will be borne by electricity customers in England and Wales, who will see absolutely no benefit from them. This is taxation without any form of associated benefit or, indeed, representation in the decision. History suggests that taxation without either representation or offsetting benefits is a hard sell.

Ofgem also has a duty to promote renewable energy, but in a manner that is efficient and consistent with the long run interests of customers, so there can be no excuse for supporting a scheme that is unjustified in geographical and economic terms, and that justification, as we shall see, is doubtful.

The case of the Shetland Islands Council is more delicate still. The publicity material for Viking Energy claims large economic benefits for the Shetland Islands. Tracking down the real payments is more difficult. There is a commitment to pay £2.2 million in community benefit per year. Viking Energy suggests that it will have 35 employees in Shetland, amounting to about £1 million per year in take-home pay. Beyond that almost everything will be imported or arise outside Shetland.

On the most generous estimate the likely economic benefit in Shetland will be less than £5 million per year. That may sound generous, but cool reason suggests otherwise since that sum amounts to only £220/Shetlander per year.

The major beneficiary of the scheme seems likely to be SSE’s transmission business – SSEN Transmission (formerly SHET). Irrespective of the economics of the Viking wind farm itself, SSEN’s regulatory asset base – i.e. the permitted assets for which Ofgem, the regulator, allows the company to charge consumers – will increase by nearly 20% directly as a result of this project. Perhaps even more important, its investments in other transmission assets such as the subsea cable from Caithness to Moray and transmission lines down from the North of Scotland will be underwritten by adding additional power generation for transmission.

Stepping back from the issues of who gains and who pays, and also putting aside the extremely questionable wisdom of inflicting the environmental impacts of major industrial construction on such a unique wild land environment, we are left with the fundamental economics. Does a wind project of this nature make economic sense in Shetland?

Even though the wind turbines are located on land the project is conceptually identical to the development of any offshore wind farm. It is constructed in a remote marine location and the power generated has to be transported a long distance to the major mainland centre of power consumption in the North of England, a straight-line distance of about 720 km.

When operating, the wind power from Viking will displace marginal gas-fired generation. This will lower carbon dioxide emissions by between 0.35 and 0.40 tonnes per MWh. At a carbon price of £30/tonne of CO2 (tCO2) – well above the current level – the value of this saving is £11–£12/MWh. Based on the long run gas price, the saving in the variable operating costs for gas generation will be £25–£30/MWh. There will be no saving in the fixed costs for gas plants as these will be required for backup and to ensure system stability. Thus, the marginal value of wind power delivered to the North of England will be in the range £36–£42/MWh.

On the cost side there are two elements that must be considered. The first element is comprised of the costs of transmitting power from the North of Scotland to the North of England and then using it to meet English power demand. The transmission losses over multiple transmission zones will be at least 5%. On top of that there will be transmission costs of at least £15/MWh (from Caithness to the North of England) and balancing costs of at least £12/MWh (based on the lowest estimate). Hence, the net value of power from the Viking project supplied to the North of England will be no more than £15/MWh at Caithness, i.e. where the power is delivered to the existing UK transmission system. It may, of course, have cost a great deal more than that to generate and transmit.

The second element to consider, therefore, is the cost of building and operating the wind farm itself and the subsea transmission line to Caithness. Published estimates of the cost of the Viking wind farm stand at about £600 million, but this seems likely to be an optimistic understatement of the type familiar from many other large infrastructure projects as various as the Channel Tunnel and the Scottish Parliament.

Based on the analysis of the actual costs of onshore wind generating stations, and allowing for the premium incurred in building a wind farm in Shetland, it seems likely that the actual cost of building the wind farm will be nearer £750 million at 2018 prices. Actual operating costs are likely to start at £85,000 per MW at age 1 year and will increase to £125,000 per MW at age 15, both at 2018 prices. Using a cost of capital of 4% in real terms the actual cost of the wind output from Viking is likely to be about £58/MWh at 2018 prices. The capital cost of the transmission line is reported as about £600 million. With a cost of capital of 3% the cost of transmission from Shetland to Caithness will be about £24/MWh at 2018 prices.

As noted, the Viking project is in effect an offshore wind farm that happens to be located on land. Thus, it should cover transmission costs to the nearest point on the UK mainland on the same basis as other offshore wind projects. On this basis, the net value of power at Caithness is £15/MWh while the cost of producing and delivering power to Caithness is £82/MWh. Even allowing for some error in the cost estimates described above it is highly unlikely that this project is a cost-effective way of meeting power demand in the GB market.

Expressed in terms of the cost of reducing carbon dioxide emissions the calculations imply a minimum cost of over £310/tCO2 if we assume that all power from the Viking project displaces gas generation. However, that is improbable because Viking output will be highly correlated with onshore and offshore wind output in the rest of the UK. In many periods Viking output will simply displace other wind generation – either in Scotland or offshore – for reasons of transmission grid stability. As a consequence, the actual cost of reducing emissions using the Viking project is likely to be more than £550/tCO2. That is extremely high, much greater than even extreme estimates of the Social Cost of Carbon, and wildly in excess of mainstream values such as the $29/tCO2 assumed in the Stern Review. Abatement at the cost likely to be incurred at Viking is not an economically rational climate policy; the cure is worse than the disease. And this, as noted earlier, is without taking into account the local environmental impacts of the scheme.

There is another way of thinking about the Viking Energy project. SSE claims, when bidding for CfD contracts, that it can supply offshore wind to the mainland grid at £45–£48/MWh (2018 prices) from projects such as the Seagreen and Dogger Bank offshore wind farms, with delivery dates in 2023. If these bids are taken at face value, there can be no justification for supporting a project due for completion in 2024 that will have much higher costs when the electricity is delivered to the main demand centres in England. SSE can’t have it both ways. If the Seagreen and Dogger Bank bids are realistic, then Viking is poor value for money. If Viking is good value, then there is something wrong with the Seagreen and Dogger bids.

We can conclude, therefore that, when seen in the larger context, the Viking project is likely to be a very expensive way of reducing emissions or meeting national power demand. But what about meeting Shetland’s power needs? Currently the island relies primarily on an ageing set of diesel generators at Lerwick power station, plus power from gas generation at the Sullom Voe terminal. The Lerwick station is operated by SSE but the units are due to be retired by the mid-2020s. It is not possible to rely solely upon wind generation from the Viking project – and/or other wind farms in Shetland – because the supply is intermittent and requires either storage or backup generation capacity. The Shetland to Caithness transmission cable could import power from the mainland, but that will involve substantial market and operating risks. Hence, in 2013 SSE proposed a scheme involving a 90 MW replacement for the Lerwick power station which was rejected on grounds of cost.

There is a serious conflict of interests with respect to the role of SSE, a conflict that has significant implications for customers in both Shetland and the rest of Great Britain. It is extremely surprising, to say the least, that Ofgem, the Scottish Government and the UK Government have tolerated a situation in which the various parts of SSE – as wind farm developer, transmission operator, power distributor and plant operator – have been allowed to determine the design and assessment of projects whose costs will ultimately be borne by British electricity customers via a variety of what are, in effect, taxes.

Neither is this arrangement good for Shetland because the islands find themselves at the mercy of decisions that are driven by the complex internal finances of SSE’s various subsidiaries. The role of the Shetland Community Trust (SCT), which financed a significant part of the early development of the Viking project, is especially questionable. At the outset it seems to have thought that it could be an equal partner in the project, but both project economics and the accounts for the various limited liability partnerships suggest otherwise. There is a lesson here for all local development trusts. The imbalance of resources and expertise mean that all of the advantages lie with the commercial developer in almost all joint ventures between developers and community organisations. In the Viking case this imbalance was reinforced by SSE’s size and its control of both transmission and distribution in Shetland and the North of Scotland as well as its larger relationships with both regulators and the Scottish Government.

SSE may have sincerely thought that what it was proposing was good for the local economy, but it is of course true that arguments of that kind have frequently been used to defend the behaviour of colonial governments and dominant external investors in the past. We tend now to view such arrangements in a different light, whether in Africa or in Scotland. Certainly, SSE has done little to avoid either the appearance or the reality of conflicts of interests in its dealings with the Shetland community.

The situation in Shetland highlights similar issues in the rest of Scotland in which the multiple roles of Scottish Power and SSE, whether in generation, distribution and transmission, frequently give rise to conflicts of interest and incentives to transfer costs from power companies to English and Welsh electricity consumers. One irony is that the SNP administration in Edinburgh, which rests its case for independence on membership of the European Union, has resolutely failed to act on EU Directives that require the unbundling of generation, transmission and distribution to avoid precisely such conflicts of interest as can be observed in Scotland. Electricity accounts for a significant fraction of Scotland’s exports but the population of Scotland, like the population of the Shetland Islands, gains very little benefit from this activity. Bluntly, the electricity sector in Scotland is highly capital-intensive and generates limited added value for consumers. At present this reality is concealed by a distorted market, and distorted prices. If those distortions are removed, the truth would become painfully evident. If Scotland wishes to avoid becoming a text-book example of a dangerously unbalanced economy it must seek to avoid over-reliance on a very small number of companies in one industry.

The following is the text accompanying the talk given by Professor Gordon Hughes, School of Economics, University of Edinburgh on 4 November 2020 to launch his two new reports for REF on:

Wind Power Costs in the United Kingdom  and

The Performance of Wind Power in Denmark

For a recording of the event, please click here.

It is difficult to make predictions, especially about the future. [Attributed variously to Niels Bohr (Nobel Prize in Physics) and Sam Goldwyn (movie mogul)]

The theme of my talk is the disparity between predictions about the future costs and performance of wind power (especially offshore wind) - the Rhetoric - and the actual evidence that is available on what it costs to build and operate wind farms and the amount of power they produce over their lifetime – the Reality.
Read more...