Why the global energy crisis strengthens the case for wind

One of the advantages of wind energy is that once the plant is built, the energy cost is stable — unlike with fossil fuels, as has been demonstrated during the past year. 

In January 2022, UK wholesale gas prices were nearly seven times higher than a year ago, while US gas prices had risen by 45%. This, along with increasing pressure to decarbonise, has further strengthened the position of wind. 

No serious competition from any other energy source — renewable or fossil — has emerged during the past year, apart from solar. The costs of electricity from wind and solar are now almost identical, and future projections of the uptake are roughly evenly divided between those who favour either technology. 

The cost of wind energy is dependent on the site wind speed. A link between wind speed and productivity can be derived by scrutinising wind turbine performance characteristics, in particular the specific rating (see p5). The estimates of energy cost have been derived using appropriate specific ratings for onshore and offshore turbines.

Calculating the cost of wind energy

Three sets of installed costs have been used for wind power (see graphic, below). The cost of offshore wind is falling rapidly, and it must be stressed that these are estimates of prices for recently completed or soon to be commissioned projects. Bids for wind farms to be built in 2023 and beyond are likely to factor in price reductions expected to be achieved by that time. The latest tender reported by Windpower Monthly, for the 1GW Thor project in Danish waters, suggests the installed cost will be around $2,400/kW. 

Offshore cost projections have been derived for wind speeds from 7m/s to 10m/s as it is unlikely that any projects would be built at sites with a lower wind resource. The onshore cost projections cover the range of wind speeds from 6m/s to 9m/s; very few sites have wind speeds higher than this. 

At $1,450/kW, the cost of onshore wind energy varies from $46/MWh at 7m/s to $33/MWh at 9m/s. The cost of offshore wind at $3,400/kW varies from $125/MWh at 8m/s to $90/MWh at 10m/s. At the lower installed cost of $2,800/kW, the generation cost varies from $97/MWh at 8m/s, down to $70/MWh at 10m/s.

Comparisons with other renewables

PV and concentrating solar power (CSP)

Current generation costs for photovoltaics are very similar to those of wind but vary widely, depending on the location and financing. The range shown in the chart on page 5 varies from $35/MWh to $42/MWh, but there are installations with higher and lower costs.

The costs of concentrating solar power (CSP) have been falling for a number of years, but are not yet on a par with wind. The quoted range here is $90-$123/MWh. One advantage of CSP over wind and PV is that there is often a thermal store, which means that output is less variable. 

Geothermal

The geothermal resource and its associated cost varies considerably. The cheapest resources are found where steam comes to the surface; otherwise the cost of drilling means that capital costs increase. Although temperatures increase with depth, the advantages of these increased temperatures generally do not offset the increased drilling costs. The US Annual Technology Database (ATB) quotes a minimum generation cost of $58/MWh, while the International Renewable Energy Agency (Irena ) suggests most of the resources can be accessed for less than $71/MWh. 

Hydro, wave and ocean resources 

Since the density of water is 800 times that of air, the attraction of hydro, wave and tidal energy is that much smaller structures can be used. 

Like geothermal, hydropower generation costs also vary widely across the globe. Outside China and Russia, however, there are few locations where large reservoirs can be built to take advantage of the economies of scale achievable with large facilities. In some locations, such as Switzerland and other mountainous regions, high load factors can be realised. The cheapest cost quoted by Irena is around $50/MWh. Most of the estimates in the ATB are below $100/MWh, but some are significantly higher than this.

Wave energy research has been in progress for around 50 years, but few commercial devices have been produced. Some devices float, others are installed onshore. The Pelamis floating device resembles a string of sausages and the elements flex, relative to each other. This motion forces hydraulic fluid through a turbine linked to a generator. Another device, the Oscillating Water Column, is essentially a tube that is tethered to the seabed and the motion of the waves forces air through a turbine, generating electricity. The turbine is a special type that is able to generate whether the air is being forced out of the column or sucked in. The UK’s energy department spent £15 million on research during the 1970s (around $70 million in today’s money) before scaling back the programme as a detailed analysis of seven competing devices concluded that none was likely to produce electricity at less than twice the prevailing cost of coal-fired generation. 

Research continues in the US, Denmark, the UK, Portugal and elsewhere, but a recent report on Ocean Energy by consultants DNV concluded: “We do not, however, see costs coming down to make them competitive globally, and consequently it is unlikely that offshore floating solar PV, wave energy or tidal energy will reach significant output by 2050.”

Ocean Thermal Energy Conversion (OTEC) makes use of the temperature differences that exist between the ocean surface and deeper levels. These can reach 20C in equatorial regions — for which the technology is best suited. The first demonstration facility was commissioned near Okinawa, Japan, in 2013 and other facilities are planned for Malaysia and Hawaii. 

One of the technical difficulties is that the low temperatures needed to establish a worthwhile differential are only accessible at depths of around 1,000 metres. Although the resource is believed to be considerable, the high costs are likely to inhibit progress in the near future.

Tidal energy has been exploited for many years. A few schemes are operating and more are planned. It is predictable and uses proven technology, but the civil engineering costs of barrages are substantial and load factors are low (around 20%). Apart from hydro, it is perhaps the most promising of the water-based technologies  

Fusion

“Fusion could be the ultimate clean power solution” proclaimed the UK government in a recent consultation document. This sought views on the future regulatory framework needed if and when the goal of fusing hydrogen atoms together, releasing huge quantities of energy, is achieved. The fact that such a document should be issued indicates that the government takes it seriously, after decades of research. The document suggests prototype power plants will be ready in the 2030s or 2040s, after which the technology will need time to becomes fully established. 

However, the Journal of Plasma Physics, in September 2020, suggested a prototype might be built as soon as 2025. In an important step forward, the most powerful electromagnet in the world, based at the Massachusetts Institute of Technology, reached its design rating in September 2021. The MIT team confirmed it still has its sights on 2025 for commissioning the first prototype.

Comparisons with fossil fuels

In the light of the move towards low-carbon generation, considerable interest is focused on nuclear power. Currently, the lowest generation costs for large-scale nuclear, according to the International Energy Agency (IEA), come from China — at $65/MWh. There are very few large reactors being built in Europe or North America, but one benchmark price comes from the Hinkley Point C power station being built in the UK, which has a contract to generate for 35 years at £92/MWh (in 2012 prices — about $145/MWh in 2021 prices).

The UK station and a similar one in France are both running late and over budget. There is considerable interest in the prospects for “small modular reactors”. These would be based on designs used in submarines, and would have outputs in the range of hundreds of megawatts. Costs are uncertain. The US Energy Information Administration suggests capital costs (in $/kW) would be similar to those of the larger stations. However, the prospectus for US-based Nuscale suggests that the cost of energy from a “first of a kind” plant would be around $74/MWh and, once in production, that could fall to around $45/MWh. These costs are shown in the chart on page 5, but have yet to be validated. A Rolls-Royce Small Modular Reactor (SMR) business was established in the UK in November 2021 “to bring forward and deliver at scale the next generation of low-cost, low-carbon nuclear power technology”. 

Gas and coal

Although gas- and coal-fired power plants are still being built in some parts of the world, there is a lot of interest in “carbon capture and storage”. Extracting carbon dioxide from the flue gases is a daunting challenge — and costly. While there are a few demonstration plants, generation costs are uncertain. The IEA recognises that coal and gas plant are less likely to operate with high load factors because electricity system operators in the future are likely to prioritise renewables. This has been taken into account in the generation cost calculations. The turmoil in gas markets seems likely to continue well into 2022.

Integrating wind

Critics often argue that every megawatt of variable wind generation must be matched by an equivalent amount of standby plant, thus pushing up the cost of wind. However, all electricity system operators schedule “operational reserves” that are used to match supply and demand, because neither are totally predictable. Events such as power station faults can cause them to shut down suddenly. The electricity system in mainland Britain, for example, must be able to cope with the sudden loss of the largest single generating unit on the system – a 1.2GW nuclear power station. On the demand-side, there can be unexpected surges in demand or reductions if, for example, a large factory suddenly shuts down. 

The way in which wind power variations add to the uncertainty in matching supply and demand is not linear, but more complex. With wind supplying 10% of the electricity, estimates of the additional reserve capacity that are needed are in the range of 3-6% of the rated capacity of the wind plant. With 20% wind, the range is round 4-8%. The cost of the extra reserves can be estimated analytically, as a part-loaded plant is less efficient than a plant on full load, and some data is illustrated (see chart, below). Most of these suggest the additional cost is below $5/MWh, up to a wind energy penetration level of 45%.

Britain’s system operator, National Grid, is on record saying that there is no limit to the amount of wind that can be absorbed and managed. “Based on recent analysis of the incidence and variation of wind speed, the expected intermittency of the national wind portfolio would not appear to pose a technical ceiling on the amount of wind generation that may be accommodated and adequately managed,” it said.

This highlights the fact that system-wide wind power variations are smaller (in percentage terms) than individual wind farm variations. Moreover, the behaviour of wind is not a totally unknown quantity and uncertainties can be further reduced by forecasting. WindEurope quotes a study that shows wind farm output can be predicted one hour ahead with an accuracy of around 7% of its capacity. 

Other integration costs depend on the specific characteristics of particular power systems. 

To deal with periods when there is very low wind, for example, “backup”, is needed. The costs depend on how much spare capacity is available and whether the system operator can call on power from other systems — “interconnectors”. Conversely, in strong winds, it may not be possible to absorb all the wind energy in the network (or export it via interconnectors), in which case wind turbines or wind farms need to be “constrained off” and compensated. 

The Australian System Operator has estimated all the additional costs for each of its four transmission zones and suggests they add $AS5-10/MWh ($US3.5-7) to the cost of wind, when it supplies 50% of demand.

How Denmark manages 50% wind share 

Denmark has been at the forefront of wind energy development for many years. In 2020, wind energy contributed more than 46% of the country’s electricity supply, and this is set to increase further (see chart above). However, the system operator for Western Denmark is able to draw on power from Norway, Sweden, Germany and the Netherlands, as well as from the eastern part of the Danish network.

In November 2021, wind generated 55% of the electricity needed in Western Denmark and the pattern of generation — compared with total demand — is shown on the chart on page 17. The average demand was 2,750MW and the average wind generation 1,492MW. There were net imports of just over 1,000MW in total from Norway and Sweden and net exports to the other interconnectors were slightly less than this. 

Interconnectors play a key role in keeping the Danish system balanced, but there are other ways in which electricity systems are evolving to meet low-carbon aspirations – in Denmark and elsewhere. These advances include demand-side management (DSM), smart metering, electric vehicles (EVs) and energy storage.  

DSM allows system operators to restrict supplies to consumers when necessary, usually in return for a reduced tariff. Smart meters may eventually take this concept a stage further, but at present most rely on “smart consumers” to manage their demand. 

Electric cars are being developed as a means of reducing greenhouse gas emissions — not explicitly to aid the assimilation of wind. However, it may to possible to encourage EV owners to charge them when there is a surplus of electricity or to draw energy from the batteries of parked vehicles when the system
is stressed. This last option needs to be carefully managed — drivers do not want to be stranded if their battery has been drained while they are visiting the supermarket. 

Storage

Energy storage is often seen as a way to “level the output” of variable renewables, thus increasing its value. However, “dedicated storage” — linked to a specific wind farm — adds to the cost of the variable renewable. This additional cost needs to be less than the additional value of “firm” over variable power. Moreover, the store would need to be very large if it was to ensure that “levelling” continues during long periods of low wind.

An early integration study by authors at the National Renewable Energy Laboratory in the US concluded: “Storage may increase the value of intermittent generation. However, studies generally show that dedicated storage systems for renewables are not viable options for utilities because of added capital costs of current storage technologies. Storage can add flexibility and value to utility operations, but it should generally be a system-wide consideration, based on the merit of the storage system.”

As the costs of storage are falling rapidly, viability may now be easier to achieve, but it is generally easier to extract value from system-wide storage than from “dedicated” storage. Numerous storage facilities are under construction or planned, but most are fairly small-scale (tens of megawatts). Apart from pumped hydro, none have the capacity to supply thousands of megawatts for several hours — which would be needed in
the absence of renewable energy in California or Great Britain, for example. It may be noted that Denmark has negligible storage.