BVG Associates is the latest consulting business to raise concerns about merchant risk for offshore wind projects as more and more wind generation is built. Dr Kate Freeman, a managing consultant at the firm, and Giles Hundleby, a director, say developers and regulators need to think seriously about solutions
Offshore wind is now often commercially viable even without government subsidy, they say, but projects without government subsidy or long-term corporate PPA revenue are faced with uncertainty (also known as merchant risk). Strategies can be adopted by developers to mitigate this risk, but merchant pricing poses several potential issues for development, innovation and competition and is an issue that governments also need to address.
In a newly published paper on the issue of merchant risk, BVG Associates notes that price reductions in offshore wind have meant projects need less and less subsidy to be commercially viable. “Prices are now so low some developers and some countries are changing their approach,” they say. “Projects are now being put forward that do not require government subsidies or PPAs. This may be viable in the near future and is certainly likely to be popular with politicians and the public, but it risks starting on an ultimately self-destructive path.”
When windfarm developers choose to sell energy directly into the grid, they are operating in the merchant market. Rather than receive a fixed price per MWh they are exposed to the variations in that price on an hourly (or even half-hourly) basis. The revenue received is a weighted average of the energy supplied and the prices achieved. The annual revenue per MWh achieved by the windfarm is called the capture price.
The problem is that, as Dr Freeman points out, capture prices for offshore wind could be lower than average hourly price.
“Hourly power price varies because demand varies throughout the day and night; from weekdays to weekends; and from summer to winter. The price at which different power plants will supply energy varies from low-cost baseload suppliers to high-cost peak-power plants (when considered from lowest cost to highest this is called a merit-order).”
Renewables supply (which always features first in the merit order) varies with the amount of sunlight (for solar power) and wind speeds (for windfarms).
“In a market with negligible wind power capacity, it is likely the capture price wind power could achieve would be nearly the same as the annual average power price,” Dr Freeman explains. “However, it is already clear that in some markets, wind power capacity is at a high enough level to have a significant impact on power price,” as the chart reproduced here created by Henrik Stiesdal for the Danish market shows.
The chart shows that when wind power has a high share of the load demand, energy prices are low. “This is because most of the higher-cost suppliers in the merit-order are not needed and the energy demand remaining to be met comes from the suppliers at the lowest cost end of the merit order,” Dr Freeman explains.
“Unfortunately for windfarm owners, this high share of the demand happens most when wind speeds are high and the windfarms are producing at or close to maximum output. Conversely, power prices are higher when wind speeds are lower, and windfarms are producing less or even zero output. This is shown in the next illustration (see below) for another market with lower (but still significant) wind power capacity.
“The capture price when there is significant wind capacity in the system is clearly less than the annual average of the market price. The more wind power capacity there is on the system the steeper this relationship will be, and the lower the capture price for wind power.”
Dr Freeman said it has been estimated for the UK that capture prices would be below £30/MWh (US$37/MWh) (compared to contract for difference strike prices of £57.5/MWh in the UK 2017 auction, at 2012 prices) by 2030 if the planned 40 GW of offshore wind capacity is achieved by then. This is in the context of forecast average annual electricity demand in 2030, around 40 GW, with a peak demand of 60-65 GW.
Dr Freeman says windfarm developers can look at optimisation actions to increase capture prices, including options to increase the amount of energy supplied at lower wind speeds and/or when prices are higher. These include overplanting, using large rotors and control strategies.
Storage and power to gas aim to use energy when prices are low and convert it to other vectors or store it for sale when prices are high.
Regulators can also use some of the same actions, and others to mitigate the impact at a national or international scale, keeping the grid stable. These ‘mitigation’ options include using interconnectors to export energy and the adoption of smarter networks.
“The other action regulators could take is to move away from ‘zero subsidy’ for wind power,” said Dr Freeman. “In the zero-subsidy approach it is more difficult to drive competition between projects. It is hard to select between competing projects if they are not bidding for a government PPA at the lowest price.”
Another problem she highlights is that, if energy prices are high, consumers could pay too much for the wind energy delivered. Conversely, if future energy prices are forecast to be low, the business case for new projects could be undermined and projects not developed.
A move to contract for difference could work, Dr Freeman suggests, by setting projects in direct competition for a fixed-price PPA. While this will ensure the lowest prices for the end consumer, it will contribute to lowering capture prices, meaning the regulator could be providing top-up payments to the operator, which could add up to significant cost to the regulator unless this was clawed-back from the market generally.
“The solution is not clear yet,” Dr Freeman concluded, “ but international co-ordination of interconnectors and power to gas scale-up will certainly help whatever the approach.”
More of the work that BVG Associates does on wind energy can be found here.
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