1. The actual costs of onshore and offshore wind generation have not fallen significantly over the last two decades and there is little prospect that they will fall in the next five or even ten years.
2. While some of the components which feed into the calculation of costs have fallen, the overall costs have not. For example, the weighted return for investors and lenders has declined sharply, especially for offshore wind, because of a fall in perceived risk. In addition, the average output per MW of new capacity may have increased, particularly for offshore turbines. However, these gains have been offset by higher operating and maintenance costs (O&M).
3. Far from falling, the actual capital costs per MW of capacity to build new wind farms increased substantially from 2002 to about 2015 and have, at best, remained constant since then. Reports of the costs of building new offshore wind farms in the early 2020s imply that their costs may fall by 2025, but such reports are consistently unreliable as well as being incomplete. Final costs tend to be significantly higher, so little weight can be attached to forecasts of future costs.
4. Far from falling, the operating costs per MW of new capacity have increased significantly for both onshore and offshore wind farms over the last two decades. In addition, operating costs for existing wind farms tend to grow even more rapidly as they age. The increase for new capacity seems to be due to the shift to sites that are more remote or difficult to service. Much of the increase with age is due to the frequency of equipment failures and the need for preventative maintenance, both of which are strongly associated with the adoption of new generations of larger turbines -- both onshore and offshore.
5. Turbine manufacturers and wind operators appear to be relying on an increase in load factors (a measure of the generator's energy productivity) via (i) an increase in hub heights to take advantage of higher wind speeds, and (ii) changes in the engineering balance between blade area and generator capacity. However, the inferior reliability of new turbine generations leads to a more rapid decline in performance with age, so that the ultimate effect on average performance over the lifetime of new turbines is not clear.
6. The combination of increasing operating and maintenance costs with the decline in yields due to ageing means that at current market prices the expected revenues from electricity generation will be less than expected operating costs after the expiry of contracts guaranteeing above-market prices. The length of these contracts has been reduced, implying a need to recover capital costs over a shorter economic life which pushes up the effective capital charge.

On expanses

1. Capex costs. The BEIS assumptions imply total capex costs (including capitalized interest) in 2025 of £1.30 million per MW for onshore wind, £2.16 million per MW for offshore wind (or £1.82 million excluding transmission), and £0.55 million per MW for large scale solar. Comparison with the actual costs reported in audited accounts is stark. The average value of the actual capex costs reported for onshore wind farms completed in 2016-19 was £1.61 million per MW, for offshore wind it was £4.49 million per MW (including transmission) or £3.99 million if the very expensive Hywind project is excluded. For large scale solar the average of actual costs was £0.98 million per MW. Hence, the BEIS assumptions are only 50%-80% of the actual capex costs reported in audited accounts for recently commissioned projects. Since BEIS provides no evidence of any rapid reduction in capex costs per MW of peak capacity, their assumptions reflect little more than wishful thinking. The bias is particularly egregious in the case of offshore wind as most future projects will necessarily be at greater depths and distance from shore, thus incurring significantly higher capex costs for both turbines and transmission.
2. Opex costs for onshore wind. The BEIS assumptions imply opex costs for onshore wind of £47,000 per MW per year for a wind farm commissioned in 2025. Incredibly, these are assumed to be constant over an operating life of 25 years. Our study, based on audited accounts, shows that actual opex costs for a new onshore wind farm commissioned in 2016 were £77,000 per MW at age 1 and that this will increase to £114,000 at age 15, and £149,000 per MW at age 25 if it were to continue to operate that long (which is very unlikely). The analysis also shows that the initial opex cost for new wind farms has been increasing at 4.3% per year, so the expected opex cost for a wind farm commissioned in 2025 at age 1 would be £112,000 per MW, more than double the BEIS estimate. Overall, the BEIS estimates of opex costs are about one-third of the best estimate based on actual data for the last two decades.
3. Opex costs for offshore wind. The BEIS assumptions imply opex costs for offshore wind of £109,000 per MW for a wind farm commissioned in 2025, constant over an operating life of 30 years. It is hard to make sense of the BEIS numbers. Their table 2.4 gives a fixed O&M cost of £36,300 per MW per year for 2025. This is implausible if it is supposed to cover Offshore Transmission Operator (OFTO) costs. Indeed, there isn't a single reference to OFTO transmission costs in the whole document, yet the methodology requires that OFTO costs must be included. Again, our analysis of audited accounts shows that actual opex costs (including OFTO costs) for a new offshore wind farm commissioned in 2018 were £184,000 per MW per year at age one, with an expectation that this will rise to £426,000 per MW per year at age fifteen. Actual offshore opex costs have been increasing at an average of 5.9% per year in real terms for the last two decades, so the lifetime average for a new wind farm commissioned in 2025 would be at least £450,000 per MW per year, or about four times the figure assumed by BEIS.
4. Opex costs for large solar. The BEIS assumptions imply opex costs for large solar plants of £10,000 per MW per year, constant over an operating lifetime of 35 years. Since most large solar plants were built between 2012 and 2017 the data on lifetime opex costs is limited, but our analysis shows an average of actual operating costs of £19,000 per MW at age one rising to £33,000 per MW at age five. It is unclear whether these costs have been increasing with year of commissioning as well as age. Nonetheless, the pattern is clear. The BEIS assumptions about large solar opex costs are typically one-quarter to one-third of the actual costs incurred by real plants that are operating today.
5. Load factors for onshore wind. The BEIS estimates assume constant load factors of 34% over relatively long operating lives for new plants. This is implausible, and it would be surprising if even the most committed advocates of renewable generation believed it to be correct. Even the most optimistic academic analyses imply a decline of 1.5% to 2% per year in annual output of onshore wind farms, holding wind conditions constant. Our analysis of the extensive data for Denmark, published together with the present study, shows that while the rate of decline in performance was lower for early generation turbines in the 0.5 MW to 1 MW category, which are no longer installed, the current generation of onshore turbines of greater than 2MW exhibits a rate of decline of about 3% per year. The BEIS failure to recognise any decline in performance is a serious defect in the analysis. There can be no justification for this. BEIS's own figures show that the actual load factor for onshore wind farms has been constant at about 27% over the last decade after controlling for variations in wind conditions. In practice, what has happened is that the higher load factor for larger turbines at new wind farms, which lies behind their estimate of 34%, has been offset by the decline in performance for older wind farms.
6. Load factors for offshore wind. BEIS assumes a constant average lifetime load factor of 51% for conventional offshore turbines (i.e. not floating devices such as Hywind). However, for offshore turbines the rate of decline in performance is much worse than for onshore wind, a fact which underlies the rapid increase in opex costs per MW. The average load factor for offshore wind has increased, but this is purely a function of the skewed age distribution in the wind fleet. The BEIS assumption of a 51% load factor relies upon a belief that the future will be radically different from the past. That is unreasonable. The average load factors for offshore wind farms less than five years old in NW Europe mostly fall in the range 40-45%. That is the best they will achieve over their lifetimes and as they age their performance will decline. The advantages of turbine size and hub height referred to in the BEIS analysis are not remotely sufficient to account for the difference between the BEIS assumption of a constant 51%, and the reality of an initial 45% declining steadily over time.
7. Load factors for large solar. Proponents of large solar generation may be somewhat aggrieved by the BEIS assumption of average lifetime load factor of 11%, which is in fact typical of recent experience. Indeed, solar developers may have a stronger case for arguing that their relatively new technology may allow higher load factors in future. This is partly a matter of definition. Peak output is rarely achieved by most solar plants, whereas wind turbines are increasingly designed to achieve rated output at lower wind speeds, by adjusting the balance of swept area to generator capacity. Nonetheless, United States Energy Information Administration (US EIA) estimates of generation costs have assumed a significant increase in solar load factors for new plants commissioned in 2023-2024 relative to those commissioned in 2019-2020, holding location and solar conditions constant. That may prove to be wrong, but BEIS's failure to note this possibility, while exaggerating the prospects for wind, brings the peculiar bias of the overall BEIS analysis into sharp focus.
8. Operating lifetime. The operating lifetime of a new wind farm or solar plant is a complex economic issue and not simply a physical one, since the effect of age on operating costs and performance is critical. The BEIS assumption of an operating life of 25 years for onshore wind is optimistic but not completely outside the bounds of reason. Our analysis suggests that the upper bound with current contractual arrangements and market conditions will be no more than 20 years. On the other hand, assuming an operating life of 30 years for offshore wind -- note, with a constant load factor -- is completely at odds with any of the actual evidence. The same is true for the 35 year lifetime for large solar plants. After all, even mature and reliable technologies such as Combined Cycle Gas Turbines and super-critical coal plants require major refits after about 20 years.
9. Future market prices and lifetimes. A possible interpretation of the implausibly long economic lifetimes projected for wind and solar is that BEIS is tacitly assuming that market power prices in the late 2030s will be 3 to 4 times their current level in real terms. Indeed, it is hard to explain the lifetime assumptions on any other basis. If that is indeed BEIS's assumption, the failure to spell this out in the analysis illustrates the lack of transparency and arbitrary nature of the whole exercise.
10. Hurdle rates. The BEIS assumptions with regard to hurdle rates are based on a study by Europe Economics carried out in 2018, but only published on the 24th of August as part of the Electricity Generation Costs [2] Let us put aside the problem that even though the Capital Asset Pricing Model used in the study has been adopted by some economists and regulators it has, at best, only an accidental relationship to the way in which real investors determine the hurdle rate of return of investment in generation or other businesses. Still, it is surprising that BEIS appears not to have carried out any kind of sanity check on the numbers in the Europe Economics report. For example, if BEIS had examined a financial model for any of the offshore wind CfD projects in Allocation Round 2 (AR2) or Allocation Round 3 (AR3), they would have discovered that every project would be a financial disaster on the cost of capital assumptions made in the Europe Economics analysis. It would be impossible for Hornsea 2, Moray East or Triton Knoll -- all AR2 projects which we have examined in detail -- even to cover debt service costs on the BEIS assumptions, let alone produce a reasonable return on equity, if their CfD strike prices are taken at face value. The cost of capital for each project would have to be close to zero simply to cover the announced levels of debt that have been incurred for each project, and even that may not be possible.

From

https://briefingsforbritain.co.uk/the-costs-offshore-wind-power-blindness-and-insight/