Offshore wind is being built-out at a fast pace, but as a zero-subsidy era approaches the industry needs to hedge against uncertainty in the wholesale price of electricity
What do you expect the wholesale price of electricity to be 10 years from now? Don’t know? Nobody does, which is why offshore wind will continue to need some form of financial support.
Predicting wholesale electricity prices in the short to medium term can be tricky, let alone looking several years ahead. Take the UK market, for instance. At one point in Q2, the wholesale price of electricity spiked to levels not seen in a decade when the strong winds that characterised late winter came to a halt. As a result, the price for baseload power soared to around £80 (US$105) per megawatt hour, almost twice as high as one might have expected to see early in March. That was because National Grid needed to make greater use of expensive gas-fired power when the winds dropped.
As OWJ has many times reported, the cost of electricity from offshore wind has fallen steeply, primarily as a result of engineering innovation. There are still plenty of technical challenges for the industry to address, and opportunities for the supply chain to enhance efficiency through R&D, but there was a strong sense at Global Offshore Wind 2018 in Manchester that finance – not cost reduction – for offshore wind has become the major preoccupation.
There is every confidence in the industry that technical innovation will take it over the line and into an era of zero subsidies but financing a zero-subsidy merchant project is an altogether different kettle of fish compared to one with a nice chunky subsidy and guaranteed returns.
In Germany, where the coalition government has set a target of 65% of electricity to be generated by renewables, there is a concern that market revenues for offshore wind and other renewables could be ‘cannibalised’ as low-cost capacity enters the market. The same fear has been expressed in the UK. That could be a problem for offshore wind because if no one really knows what the wholesale electricity prices will be in future and you cannot predict what you are going to be paid for the electricity you produce, how can you make an investment decision? Add in the fact that the cost of capital for subsidy-free renewables will be higher than for projects supported by a subsidy and next-generation offshore wind projects could face a financing challenge.
Analysis by consultants such as Aurora Energy Research shows that, in the right circumstances, subsidy-free renewables could almost eliminate the need for high-cost gas-powered electricity generation. That will make it easier for governments to meet carbon targets, but the merchant nature of investment for subsidy-free windfarms would expose the market to increasingly complex drivers of capture prices – that is, the price an asset or technology actually achieves in the market.
As Cornwall Insight noted recently, the value earned from wholesale power is going to become increasingly important for renewables, but price cannibalisation will be a major complication. This is because of what it described as the depressive influence on the wholesale electricity price at times of high output from intermittent, weather-driven generation such as solar, onshore and offshore wind.
When there is a lot of wind in the system it tends to drive down the wholesale price – so much so that there is a risk of price cannibalisation – whereas, as happened this spring, when the wind is not blowing, the wholesale price goes up. That is one reason why there is so much interest in being able to store energy from offshore wind and other renewables – to prop up the capture price.
Contrast this scenario with the existing contracts for difference (CfD) regime in the UK, where generators are guaranteed a price for the power they produce, and the consumer effectively meets the difference between the wholesale price and the agreed ‘strike price.’ You can see why a lot of clever people are spending a lot of time thinking about new financing models for offshore wind, without which, some argue, it could become a victim of its own success.
Power purchase agreements (PPAs) are an option in the long term but that market is not sufficiently developed to help meet renewable energy targets right now. Moreover, a company entering into a PPA might struggle to manage intermittency from renewables and there might not be many large enough to enter a PPA for a large offshore windfarm, so some form of intermediary would probably be required.
All in all, there is a need for zero-subsidy offshore wind to find a way to reduce its dependence on the wholesale market. There are potential solutions, but just as the CfD scheme has provided certainty, reduced risk and played a key role in the hugely successful roll-out of offshore wind in the UK, so a new arrangement will be necessary as offshore wind transitions to zero-subsidy CfDs. It seems likely there will need to be a mechanism – such as guaranteed top-up payments when the capture price is low – that provides a solution, at least in the short term.
So, what are the options for offshore wind, given its variable nature?
Aurora’s head of GB renewables, Hugo Batten and his colleagues argued that offshore wind should be allowed access to segments of the electricity market it does not currently participate in and join other forms of generation in ‘revenue stacking’ – as forms of thermal generation such as gas do – securing contracts in the capacity market or for frequency response. It argued that doing so would help to derisk offshore wind and make it less dependent on the wholesale price of electricity. Another study, published in June 2018 by Imperial College London Consultants and Vivid Economics on behalf of the Natural Resources Defence Council, also suggested that renewables such as wind can participate in these markets without destabilising the system.
“In theory, offshore wind can provide a range of balancing and ancillary services to the grid largely because it has the technical capabilities to rapidly ramp-up and down,” said Aurora. “If offshore wind is able to monetise the provision of these services, then it can in effect revenue-stack much like traditional, dispatchable plants do today.”
The capacity market was established by the government in the UK as part of its Electricity Market Reform policy. The aim was to incentivise investment in sustainable, low-carbon electricity capacity at the least cost for energy consumers and help secure electricity supplies for the future. It is open to all capacity providers – including new and existing power stations, electricity storage plant, capacity provided by voluntary demand reduction and interconnectors. It is intended to ensure steady, predictable revenue streams on which providers can base future investment. In return for capacity payments, providers must deliver energy at times of system stress, or face penalties. Potential providers secure the right to receive capacity revenues by participating in a competitive auction process which sets the level of payments. Auctions are held four years ahead of delivery, with a subsequent auction held one year ahead.
Frequency response is the injection of power into the system to restore frequency to normal levels following the loss of a source of supply. It is provided by generators whose output increases or decreases automatically in response to changes in frequency. National Grid makes sure there is sufficient generation and demand held in readiness to manage all credible circumstances that might result in frequency variations and has been working with providers in a bid to allow non-dispatchable sources of generation – such as wind and solar – into frequency response. Tests carried out on Ørsted’s Burbo Bank offshore windfarm – where a first-of-its-kind wind power and battery hybrid system was installed to provide frequency response to help keep the grid frequency stable and maintain operability – suggest it is feasible.
The Imperial College Consultants/Vivid Economics report noted that while the UK electricity system has been able to absorb wind and solar generation relatively easily so far, higher levels of deployment must be carefully managed. “At higher levels, they present new challenges, such as the need for greater electricity system flexibility (such as with demand response or storage) and raise risks to reliability that must be addressed,” it said.
As it noted, for the electricity system to be reliable, a number of system needs have to be met. Historically these have been met with thermal generators. The need to maintain supply and demand in balance is well understood and, in the past, conventional thermal generators have together met these needs by generating electricity when needed and helping to stabilise system frequency.
“If variable renewables paired with smart resources (battery storage, demand response and interconnection) can largely substitute for thermal generators, then government should instead ensure electricity markets will deliver the mix of renewables and smart resources needed to decarbonise the electricity system,” the report said, although it noted some commentators argue that thermal generators continue to be needed to meet system needs, and as baseload.
The authors of the report analysed the requirements of the UK electricity system to 2030 and demonstrated that an electricity system with a high share of variable renewables and low share of thermal generation could meet requirements for adequacy; reserve; inertia (whether there is enough synchronous capacity generating electricity at all times to maintain system inertia above a given threshold); and frequency response.
“With technological innovation, even higher levels of variable renewables could be accommodated, with lower levels of thermal generation,” the report said, concluding that wind and solar could provide more than 60% of electricity generation by 2030 and that significant investment in smart resources (battery storage, demand response and interconnection) would also be needed to ensure reliability and minimise costs.
Although there are technical challenges to be met, all of this would seem to be good news for the offshore wind market as it transitions to zero-subsidy and projects undertaken at merchant risk, and other opportunities may also exist.
In the medium-to-long term, Aurora also suggested, offshore wind could provide other types of ancillary service, in addition to frequency response. A role as reserve is technically possible, it said, given that offshore windfarms are controllable for reserve purposes. Providing reactive power would be technically possible, but certain transmission connection issues would need to be considered; and inertia control would also be possible, if an obstacle regarding offshore windfarm decoupling from the onshore system could be overcome.
Looking even further ahead, in the long term, the next generation of offshore wind – widely perceived to be floating offshore windfarms built further offshore, which will have much larger capacity than existing bottom-fixed windfarms, where more regular winds will reduce intermittency – could enhance its credentials as a form of generation.
“Floating offshore wind could also have a potential role in the capacity market,” Mr Batten told the Global Offshore Wind 2018 conference, thanks to its high capacity factor and regularity.