Moving towards a net zero grid, and more intermittent forms of power, means generators need to think differently in order to maximise investment. As part of that new thinking, we are seeing innovative coupling of co-located technologies that can help smooth out the load on the grid, reduce network charging, provide different income streams and reduce risk for generators themselves.
Scottish Power, for example, has plans to invest in solar, which it will co-locate with batteries to capture and store excess energy. And Shearwater Energy is developing plans for the former Wylfa plant in Anglesey in north Wales which will combine small nuclear reactors and a wind farm.
But to what extent will this become the norm across major generation sites? Are the business models in place to drive this form of investment and what more needs to be developed to make such schemes viable? These were just some of the discussion points debated at a Utility Week roundtable, held in association with Addleshaw Goddard. Those taking part were drawn from across the energy spectrum, with a high proportion involved with generation and storage and some with co-located projects.
Participants agreed that talk of co-location was fashionable, and that the scope was certainly there. “We’re looking at the installation of solar, hydrogen, EV charging, and battery storage, and these are ideal for heat pumps to be located as well… utilisation of the grid connection is key,” said a National Grid ESO representative, adding: “We need to design optimised local energy markets, supported by baseload, with solar and storage co-location in those environments. Investors normally look at these projects case by case, but as a network and as a country we need to be thinking more holistically, and looking at a group of investments.”
But an emerging consensus was a questioning of the starting point, and what the benefit would be of co-locating different technologies, such as solar and battery storage, when technically they could work just as well on different sites?
“I spend my time looking at various policy aspects that affect investment in various parts of the electricity market,” remarked one renewables specialist. “You have to look for specific advantages that come from putting things on the same site. Most of our projects today are still independent, not co-located, but there’s a huge amount of interest from the industry to start looking at co-located assets.”
Talking about the company’s proposed project in Anglesey, a representative of Shearwater Energy remarked: “Much will be made about co-locating a low carbon asset with, say, hydrogen generation, and one of the issues we’re looking at now is if we build a nuclear plant, can we make use of some of the heat there? Can that be used to improve the efficiency of the electrolysis process, besides just the obvious stuff like putting batteries and solar on the same site?
“We have to look at all the opportunities: what are the advantages of hybrid projects?” he added.
Participants said it was crucial that funders grasped the business case. “We’ve been doing hybrid projects for several years, and lots of those haven’t worked. They often fall when it comes to bringing in external investment, because they become so complex that funders don’t understand and they can’t get behind it,” said one guest.
“You need to be absolutely clear of the benefits of co-location for any given project, and be able to articulate the case properly and that is often about keeping it simple and the revenue streams clear.”
Making co-location stack up
A range of factors can make co-location of hybrid technologies beneficial. Participants talked about the sharing of grid connection costs, one planning permission rather than two, and only one project management team and one set of construction facilities. But it was felt these were not game changers.
One guest commented: “In my view, the game changer is on the revenue side. In today’s market, there aren’t clear revenue synergies between solar and storage, because a solar plant will be almost entirely wholesale market revenues, with a little bit of ancillaries on the top. Whereas a storage project will be almost entirely providing grid services, and having little bits of top up in wholesale balancing.”
Another agreed: “The technical arguments in favour of co-location are generally weak, especially when you look at the sophistication of the grid. There are some operational savings to be had at one site instead of two, but they’re not significant.”
There were also warnings about making a decision based on any economic benefit that might stem from a quirk in the current regulations.
“Ultimately it’s down to the market investment signal. If the signal is there, plants will get built. Yes, regulation can slightly distort that market, for example if you’ve got an emerging technology and you want to give it a boost and get it going quickly, you can subsidise and that might change the game.
“But ultimately, mass decarbonisation needs to be on a merchant basis, so de-risking rather than subsidy.
“Looking forward, that really changes over time. As you get more and more storage on the system, more and more revenues are coming from the wholesale market. And when you get into that world, you get very significant revenue synergies, because you have this trading relationship between the battery and the solar farms.
“You can take advantage of price highs and price lows to charge your battery with the excess power, because it’s all then in the wholesale trading market. So that is where the core financial driver comes from, if you have enough foresight to think about what the market will look like in 10 years’ time.”
One participant said that co-location works well where the generation is serving an industrial energy user, for example a water works, where there would be less time with surplus generation. “The co-location point is trying to find those consumers, typically large industrials or people who have a predictable consumption pattern, and co-locating a technology where the resource is right for that and is economically attractive.
“Things like battery tech, we’ve reached a stage where a battery might be expensive, but it doesn’t need to do that much if you put it in an application where it’s only just buffering small amounts. Then it’s economic, today. And as the prices go down, it’s more and more economic, and it opens up the market.
“So it’s not just a question of, ‘can I put solar and wind plus batteries on a site?’, it’s also about finding the right places to put it, not just because the resource is there, but because the demand is there. That’s what makes it economic.”
The economics of hydrogen
Co-locating technologies to produce hydrogen and thus use it as a mechanism for energy storage formed a key theme in the discussion. But the jury was out on just how big a role hydrogen would play.
“In terms of co-location, it’s all going to be about where is the offtake? A large chunk of the cost of hydrogen is in transportation, so you want a pipeline, or ideally you want to be right next door to the plant. The co-location there is co-location with a customer,” was one comment. This, though, brought other issues to the fore – namely the difficulties of using hydrogen for heat.
“There are funders who are keen on hydrogen, but they still want to see a business case, and they want to understand the policy and regulation behind it as well,” remarked another guest.
Paul Dight, Head of Renewables and principal partner in the utilities team, and Richard Goodfellow co-head of Energy and Utilities both at Addleshaw Goddard, participated in the discussion. Here is what they took away from it.
“Co-location seems to be the fashionable thing to do, but there needs to be a benefit to putting assets together instead of separately – for example, to make better use of a site’s connection capacity. It is best to co-locate generation with demand, as this gets rid of the need to store surplus energy.
The discussion moved on to look at the wider strategic view and how hybrid projects fit in to that. In the next 10-15 years there will be a complete 180 degree switch from a generation mindset (where we control supply to match demand) to a demand mindset (where intermittent generation is weather-dependent so we have to control demand to match supply). This will make the flexibility services that co-located storage can provide much more valuable. One panellist commented, “if there are no constraints on the system, you have over-invested”. Storage is there to pick up the slack when there is excess renewable power.
There was lively disagreement on the role of hydrogen in the whole energy system. Converting electricity to hydrogen and back again is an inefficient process. But when any technology starts out it will always be less reliable, less efficient and more expensive than existing systems, just as offshore wind and solar panels were 5-10 years ago. It will take a few hydrogen demonstrator projects at scale before the market unlocks for more complicated projects. Regulation can distort the market by boosting emerging technology, but mass decarbonisation needs to happen on a merchant basis: ie, de-risking the investment rather than relying on a subsidy.
Unsurprisingly, it is not always easy to attract funders to hybrid projects. Different investors are often interested in different technologies due to varying risk profiles, so it is not easy to get an investor to fund co-located technologies in one package. Addleshaw Goddard has a great deal of experience in successfully getting these deals off the ground and we were able to share our experience on how to de-risk the investment and how to structure projects so that funders get comfortable and can understand the economics.
Finally, looking to the future, we are seeing the democratisation of renewable energy investment with the emergence of crowdfunding. This will lead to a different investment risk appetite. The future could be for co-located assets where the economics and policy made sense of it and this was an exciting place to be.
For more details: https://www.addleshawgoddard.com/en/