Lord Callanan, Parliamentary Under Secretary of State (DESNZ), speaking in the House of Lords on 16th May 2024, said:

I will give the noble Lord the costs in the latest published analysis, which show that electricity from offshore wind is 60% cheaper to build and operate than gas-fired power. The levelised costs are £44 per megawatt hour for offshore wind, versus £114 per megawatt hour for closed-cycle gas turbines. The other key point is energy security. As the noble Lord is well aware, the amount of gas coming from the North Sea is declining year on year, and therefore we have to import increasing amounts of gas. It makes no sense to make us dependent on imported gas for the years to come. We can see the effects of the Russian invasion of Ukraine on gas prices. With the current turmoil in the Middle East, it makes even less sense.

Responding to this, Net Zero Watch director Andrew Montford said:

If wind power is as cheap as Lord Callanan claims, then no subsidies are necessary. He can’t have it both ways. It’s painfully obvious that he is trying to hide the truth from the public. This can’t go on.

During the subsequent discussion, Lord Callanan told Lord Howell that the levelised cost figures he was quoting “take account of other system costs”. This is incorrect.

The claim made by Lord Callanan is one that is widely believed by renewables enthusiasts. During a recent online discussion I was involved in elsewhere, I was told by one such enthusiast:

Lastly, a flat statement that gas is cheaper than offshore wind is at best misleading. Since most CCGTs are fully depreciated, then the prices reflect only the cost of the gas plus maintenance and operations. The UK Government LCOE figures show a massive difference between CCGTs and renewables. Even if we double the RE prices to allow for recent movements, they are still well below the LCOE of gas. I assume you will not label the UK Government as a renewable ‘activist’.

Read on, and perhaps you, like me, will conclude that the UK Government is indeed an activist on behalf of renewables, with the truth about costs being spun more than the average wind turbine blade.

Electricity Generation Costs 2023

This is the title given to a Government publication which purports to provide the levelised costs of different types of electricity generation in the UK. It tells us that:

Electricity generation costs are a fundamental part of energy market analysis, and a good understanding of these costs is important when analysing and designing policy to make progress towards net zero.

I find it impossible to argue with that, save that I would have said the understanding of costs should be used to decide whether rather than when to make progress towards net zero. By phrasing that paragraph in that way, the author of the report displays an immediate bias. We are told:

This report, produced by the Department for Energy Security and Net Zero presents estimates of the costs and technical specifications for different generation technologies based in Great Britain.

It represents an update since the last report (BEIS Electricity Generation Costs) from 2020. Having updated some assumptions, we are told:

In this report we consider the costs of planning, construction, operation, and carbon emissions, reflecting the cost of building, operating and decommissioning a generic plant for each technology. …Most costs in this report are presented as levelised costs, which is a measure of the average cost per MWh generated over the full lifetime of a plant. All estimates are in 2021 real values unless otherwise stated. Levelised costs provide a straightforward way of consistently comparing the costs of different generating technologies with different characteristics, focusing on the costs incurred by the generator over the lifetime of the plant. However, the simplicity of the measure means that there are factors which are not considered, including a technology’s impact on the wider system given the timing, location, and other characteristics of its generation. For example, a plant built a long distance from centres of high demand will increase transmission network costs, while a ‘dispatchable’ plant (one which can increase or decrease generation rapidly) will reduce the costs associated with grid balancing by providing extra power at times of peak demand. An analysis of the impact of these wider ‘enhanced levelised costs’ were presented in our 2020 report. Generation costs are used as inputs to the department’s analysis, including the setting of Administrative Strike Price setting for Contracts for Difference allocation rounds. These assumptions are reviewed at each allocation round. However, it is important to note that levelised costs are not the same as strike prices. Strike prices include additional considerations, such as market conditions, revenues for generators, and policy factors, which are not considered in levelised costs. To date, they have also typically been expressed in 2012 prices, whereas the levelised costs reported here are in 2021 prices.

Let’s get that straight. These levelised costs (much beloved of renewable energy enthusiasts, who regularly quote them to justify their claim that renewables are cheaper than gas) present a completely unrealistic picture. First, they put their thumb on the scales by adding a hypothetical carbon cost into the calculation. Second, they ignore the massive increased transmission costs associated with the dispersed nature of renewable energy sources sited a long distance from where the energy is needed (and the corresponding cost savings associated with dispatchable energy sources that can ramp up and down as needed). Third, they ignore “additional considerations, such as market conditions, revenues for generators, and policy factors”.

In order to have a clearer understanding, we need to look at the earlier report, to see exactly what costs have been excluded from the calculation.

Wider ‘Enhanced Levelised Costs’

The 2020 report which did take into account the “wider ‘enhanced levelised costs’” (but at 2018 prices), was disarmingly honest regarding the broad brush nature of the approach associated with levelised cost estimates:

The Levelised Cost of Electricity (LCOE) is the discounted lifetime cost of building and operating a generation asset, expressed as a cost per unit of electricity generated (£/MWh). It covers all relevant costs faced by the generator, including pre-development, capital, operating, fuel and financing costs. This is sometimes called a life-cycle cost, which emphasises the “cradle to grave” aspect of the definition.

The levelised cost of a generation technology is the ratio of the total costs of a generic plant to the total amount of electricity expected to be generated over the plant’s lifetime. Both are expressed in net present value terms. This means that future costs and outputs are discounted, when compared to costs and outputs today. Because the financing cost is applied as the discount rate, this means it is not possible to express it as a £/MWh component of the cost directly.

The main intention of a levelised cost metric is to provide a simple “rule of thumb” comparison between different types of generating technologies. However, the simplicity of this metric means some relevant issues are not considered.

At Page 9 of the 2020 report, we are told:

For onshore wind and large-scale solar PV, we have reviewed capital costs and developed an updated learning rate – the rate at which capital costs decrease as more plants are built, resulting from greater technical and construction experience – to reflect the projected decreases in capital costs over time…

At page 15 we are advised:

BEIS commissioned a report from Europe Economics (EE), updating the Department’s hurdle rate assumptions for projects starting development from 2018 in a range of technologies. The Europe Economics (EE) report is published alongside this document, along with a peer review by Cambridge Economic Policy Associates (CEPA). Europe Economics analysed developments in bond markets, the energy market and the electricity sector, as well as changing risk drivers, to understand how hurdle rates have changed since our 2015 update. They found the hurdle rates to have fallen across all technologies due to falls in market-wide parameters (the risk-free rate and the equity risk premium) and in debt premia, convergence in risks in the sector and falls in effective tax rates…

On page 16 we learn:

The hurdle rates applied are based on investor expectations at the time the work was undertaken. For investments to be made in future years, the hurdle rates may change. However, such changes are difficult to project and therefore we assume a flat trajectory for hurdle rates applied to investments to be made in future years in our modelling…

Which is rather unfortunate, because interest rates have risen substantially since then from the record low levels the renewables industry has enjoyed for many years now. The high up-front capital costs of renewables now cost much more to finance than the Government reports assume, and will continue to do so, even if interest rates start to ease down again over the next year or two, as widely expected. In short, the assumptions regarding financing costs which underpinned the 2020 report have rapidly proved to be over-generous.

The 2020 report also makes some fairly heroic assumptions about load factors for wind turbines, predicting a projected load factor (net of availability) improving from 47% in 2020 to 63% in 2040.

Decommissioning costs for offshore wind also appear to be rather optimistic (page 18):

For offshore wind, we have also made an allowance for decommissioning costs in line with the approach outlined in Arup (2018). This assumes that developers must provide a financial security to cover the costs of decommissioning the project. Developers incur a financing cost of providing that security as well as the final cost when the project is decommissioned. The effect on the LCOE of decommissioning costs is less than £1/MWh…

Page 19 enlightens us as to the thumb on the scale, loading imaginary “carbon costs” onto the hypothetical cost of fossil fuels:

For gas and coal plants, the total carbon price up until 2030/31 is given by the sum of the 2018 EU ETS carbon price projections and the rate of Carbon Price Support (CPS). At Budget 2018 it was announced that the CPS rate was capped at £18/tCO2 until the end of year 2020/21.

From 2021/22 onwards, we assume that the total carbon price for the electricity sector remains fixed in real terms at the 2021/22 level until the price of the EU ETS rises above this; after this the carbon price for the electricity sector coincides with the EU ETS price. Beyond 2030, the total carbon price increases linearly to reach the appraisal value of carbon in 2050…

The 2023 report has already given the game away regarding the fact that additional costs associated with renewable energy are simply ignored, but at page 21 of the 2020 report the position is made crystal clear:

As levelised costs relate only to those costs accruing to the owner/operator of the generation asset, the metric does not cover wider costs to the electricity system.

Starting on page 21 and running over on to page 22 of the 2020 report we also receive a candid admission regarding the nature of the LCOE assumptions:

Levelised cost estimates are highly sensitive to the underlying data and assumptions used. Within this, different technologies are sensitive to different input assumptions.

This report captures some of these uncertainties through ranges presented around key estimates. A range of costs is presented for capex and fuel, depending on the estimates, and the tornado graphs illustrate sensitivity to other assumptions. However, not all uncertainties are captured in these ranges and estimates should be viewed in this context. It is often more appropriate to consider a range of costs rather than point estimates. It should also be noted that levelised costs are generic, rather than site-specific. Land costs are not included and use of system charges are calculated on an average rather than a site specific basis.

And on page 22 it is again reiterated that the levelised cost prices may be very different from strike prices under the CfD process. Of course, the latest CfD round saw a massive increase in the strike price of all forms of renewable energy, the previous round having being a miserable failure. The assumption that costs would keep on falling wasn’t matched by reality, and when asked to enter into contracts at low prices, the renewables industry simply declined to do so.

As the 2020 report observed:

For all these reasons, the levelised costs presented here may be significantly different from the administrative strike prices that are set for CfDs and therefore should not be seen as a guide to potential future administrative strike prices.

Well that certainly proved to be true!

However, so far as the 2020 report is concerned, it’s section 7, commencing on page 41, that is of great interest, because this is the section that deals with “wider system impacts” that are ultimately excluded from the LCOE calculation. It starts very frankly:

The levelised cost estimates presented in this report do not take into account wider positive or negative impacts that an electricity generation plant may have on the electricity system due to timing of its generation, its location and other characteristics.

In assessing the qualitative framework, the 2020 report makes it clear just how much the ignoring of such factors tilts the scales against fossil fuels and in favour of renewables.

First:

Impacts in the wholesale market: This category considers how timely or valuable each MWh generated by a technology is. This will differ by technology type. For example, a CCGT plant is dispatchable and will be able to focus its generation on valuable/useful time periods, while renewable technologies’ generation is determined more by availability of resource.

Second:

Impacts in the capacity market: This category considers how firm or reliable each MW of capacity provided by a technology is at moments of peak demand. This will differ by technology type. For example, an OCGT plant is very reliable at moments of peak demand (e.g. on a winter’s evening), while other technologies’ available capacity in those moments is less reliable (e.g. solar).

Third:

Impacts in balancing and ancillary service markets: This category considers how helpful or unhelpful a technology’s generation is for the balancing and operability of the system. This will differ by technology type. For example, a technology whose output is more difficult to forecast is likely to increase the need for balancing in the system, while flexible, dispatchable technologies will potentially be able to solve balancing issues more cost-effectively. Regarding operability, technologies that, for example, provide additional inertia (which helps to slow a drop in frequency following a system loss, e.g. a large generator coming off the system unexpectedly) will help to reduce costs, while plants that currently cannot or are not incentivised to provide inertia will increase the system’s need to procure additional inertia from other plants. The model also considers technologies’ ability to provide reserve.

Fourth:

Impacts on networks: This category considers how conveniently located a technology is, i.e. its proximity to demand centres. This will differ by technology type and location. This category is highly subjective as it depends on where a technology is assumed to be located.

Every one of those points are a point in favour of fossil fuels and against renewables. Presumably that’s why the LCOE calculation ignores them. And even when assessing wider system impacts, the 2020 report still doesn’t add all the costs associated with renewables in to the mix. For example (page 43):

Subjective nature of plant location: The wider system impacts presented in this report include impacts on transmission networks by considering a range of possible locations for a generic plant; distribution network impacts are not included. However, results are still to a large extent driven by the subjective choice of the range of locations used and should be interpreted with caution. It is important to note that network costs and charges are likely to change going forward; this is not captured in the estimates presented.

Page 44 reads like an argument against widespread use of renewable technology and against increasing demand for electricity by forcing us to switch from gas central heating and from internal combustion engine vehicles to EVs:

While dispatchable technologies like CCGTs and CCUS generally help to reduce system costs, they run at less than maximum load factors and therefore their levelised costs increase. In these… scenarios, generally (but not always) the system savings outweigh the load factor impacts, resulting in an overall cost reduction. Intermittent technologies (e.g. wind and solar) generally impose a wider system cost, which is more severe in scenarios with lower flexibility or a less diverse generation mix…

…The value of additional CCGT capacity to the system is greater in scenarios where demand increases faster or there is a higher proportion of intermittent renewable capacity…

Three scenarios of enhanced levelised costs are offered up depending on the commissioning year. In each case they start with an assumed cost (which may well turn out to be wrong) per MWh of CCGT H Class; CCGT + CCUS; Onshore wind; Large scale solar; and offshore wind. Wider system impacts, other impacts and transmission impacts are then added or deducted as appropriate, to come up with a revised price of each per MWh, representing the enhanced levelised cost.

Scenario 1 is for plants commissioning in 2025. CCGT (without CCUS), starts as the most expensive (at £82 compared to £43 for onshore wind, £41 for large scale solar, and £54 for offshore wind) but is the cheapest option by the time the additional costs and benefits of each form of generation are taken into account. On that basis CCGT is said to cost £40 to £60, while onshore wind is £56 to £73; large scale solar is £53 to £66; and offshore wind is £69 to £85.

Scenario 2 (plants commissioning in 2030) sees an even starker difference. CCGT falls from £97 down to a range of £40 to £82) while all the renewable sources see their levelised costs rise – Onshore wind from £42 up to a range between £59 and £87; large scale solar rises from £37 up to a range between £48 and £66); while offshore wind goes from £45 to a range between £62 and £82.

Scenario 3 (plants commissioning in 2035) shows such a wide range of possible costs as to be almost meaningless. Despite that, one important point is clear – take into account all the costs and problems associated with renewables and all the benefits to the Grid associated with gas, and the analysis is to the significant detriment of renewables. CCGT costs fall from £112 to as low as £27 (or as high as £127). The hypothetical benefits of CCUS reduce the costs of CCGT with CCUS from £78 to between £38 and £61. Onshore wind meanwhile rises from £42 to somewhere between £60 and £87. Large scale solar rises from £33 to somewhere between £45 and £61. Finally, offshore wind rises from £41 to somewhere between £59 and £79.

The thumb on the scale can be found in Annex 1, which shows how the basic costs have been assessed. For CCGT H class projects commissioned in 2025, “carbon” costs are said to be £32 per MWh; by 2030 they rise to £45, by 2035 they are said to be £59 and by 2040 are deemed to be £70 (remember these are at 2018 prices).

Fast Forward to 2023

Tucked away on page 19 of the 2023 report is the sneaky sentence admitting that the thumb is pressing down on the scales ever more heavily against fossil fuels:

Carbon prices are significantly higher than assumed in the previous 2020 report, which has resulted in an increase in LCOE for fossil fuel plants.

Another sneaky change to the way costs are assessed spans two paragraphs at the foot of page 19 and the head of page 20:

In April 2022, Ofgem published their decision CMP30818, which moves BSUoS charges away from generation and demand to Final Demand only. This change is due to take effect from April 2023 onwards.

Therefore, these costs are no longer incurred by the generator and are no longer part of the levelised cost framework. They are no longer presented as part of the estimates in this report. Previously this cost fell under the variable operating costs.

BSUoS charges, of course, are Balancing Services Use of System charges. They are rising due to the increasing proportion of renewables in the system. Thanks to this piece of legerdemain, however, those costs don’t count against renewables when arriving at the final LCOE numbers. The point is made again on page 21:

Levelised costs do not cover wider costs to the electricity system as they only relate to those costs accruing to the owner/operator of the generation asset.

In case anyone is left in any doubt that the LCOE calculation has precious little to do with real world pricing, they should read pages 22 and 23:

The generation costs data used here may be different from that used as part of the administrative strike price-setting process. This is particularly true where information relevant to potential bidders in a particular allocation round is used to inform cost assumptions for pipeline projects. Further, ASPs are normally set so as to bring forward the most cost-effective projects, which may not be the same as the estimates of typical project costs estimated in this report.

For all these reasons, the levelised costs presented here may be significantly different from the administrative strike prices that are set for CfDs and therefore should not be seen as a guide to potential future administrative strike prices.

And what of those assumed carbon costs loaded on to fossil fuels? Remember that back in 2020, for CCGT H class projects commissioned in 2025, “carbon” costs were said to be £32 per MWh; by 2030 they were to rise to £45, by 2035 they were said to be £59 and by 2040 were deemed to be £70. By 2023 they have risen (albeit expressed in 2021, rather than in 2018, prices) to £60 (2025); £83 (2030); £108 (2035); and £123 (2040).

Conclusion

Et voila! Ignore all the wider system costs associated with renewable energy, assume lower interest rates than are prevailing today, assume constantly improving load factors and low decommissioning costs, ignore land costs and other uncertainties, ignore the higher strike prices achieved in the latest Contracts for Difference auction, add a load of hypothetical carbon costs on to fossil fuels, and the job is done. Proving that renewables are cheaper than gas isn’t difficult when you know how to go about it. The only problem is, the claims made by the LCOE calculation aren’t true in the real world, and we’re all paying the price.