Electron’s vision for the transformation of the electricity sector puts digital infrastructure at the epicentre of the drive towards decarbonisation and decentralisation. The company uses blockchain technology to bring coordination and structure to fragmented data sets and markets. Engerati speaks to CEO Jo-Jo Hubbard to find out more about their ongoing projects and experience with working with utilities on digitalisation.
E: What’s the difference between digitisation and digitalisation?
JH: When people make a point of distinguishing between the two, digitisation usually means converting analogue information or processes into a computer-legible format (think smart meters), whereas digitalisation is about digitally native processes e.g. leveraging that information in business processes (think automated billing). However, these words are increasingly used interchangeably because one rather implies the other… Or it ought to, at least.
E: How will digitalisation of the energy sector facilitate decarbonisation?
JH: Digitalisation is key to enabling decarbonisation at scale, without collapsing the other two points on the energy trilemma: cost efficiency and security of supply.
Technically speaking, you can put solar panels on a few rooves without doing much to track or meter output as long as renewable penetration is low. Indeed, we did just that in the first phase of the transition when the focus was in getting as many renewable assets as possible in the ground. However, when you have substantial intermittent generation (think wind and solar), supply and demand still need to be balanced across the grid, but now you have times of great surplus (think sunny weekends or windy nights) and deficit (cold, still, overcast days).
Digitisation in itself will give you a static view of supply and demand capacity across the grid, but digitalisation also allows this data to be combined with weather data to produce time based forecasts, it allows storage or flexible assets (think batteries or heating/ cooling systems) to schedule their consumption around times of oversupply, or respond to price signals to alter their grid input or output. The better we get at shifting energy consumption to match renewable generation, the less and less we rely on fossil fuelled back-up capacity, which is where the vast majority of power sector emissions reside. And until we have these digitalised price signals and responsive markets in place, we can forget about electrifying industries such as transport and heat a while maintaining supply stability and cost efficiency.
E: Which areas of the energy sector have embraced digitalisation quickly, and where is there still a lot of potential for innovation?
JH: Actually, it feels like most of the potential for innovation is in the areas that are already digitalising. For example, electricity is moving a lot faster than gas because there is much more value at stake for asset optimisation. In the same way, first time buyers of electric vehicles are immediately digitally native due to visibility of cost (and carbon) savings versus power consumption from the devices in their house.
That said, the stand out area that remains surprisingly behind is an asset identity system: a register of all generation, storage or flexible assets in the system and their capabilities. This is partly a result of a coordination and data aggregation challenge. Different parties are responsible for recording distribution connected versus transmission connected assets, the meters of all those they service versus all those who have installed a piece of kit etc. No one party has a view of what and where all assets in the system are which means “whole system optimisation” is based on assumptions and guesswork.
We are working with National Grid, UKPN and SPEN to design and test a distributed asset register for flexibility and generation assets. The idea is to create a single point of inquiry as to asset identity and capabilities, and from there, coordinate access to many different data sets.
E: How does a utility go about choosing a digital solutions provider? What will distinguish the successful projects from the unsuccessful ones?
JH: Ah ha, so many ways - this could be for anything! Regulated monopolies have to set requirements and tender competitively if the project is over a certain size; many incumbent suppliers are constantly locked in trade-offs between patching old systems or building something new; many of the younger suppliers and aggregators have built digital and automated processes from the get-go (and more still can’t yet employ these to their full capability because regulatory codes, like quicker switching, are geared towards older systems.)
In terms of what will distinguish success - we are seeing more and more emphasis now on future proofing. Platforms need to be extensible: markets and business models and changing so fast, anyone whose platform cannot adapt will be at a substantial disadvantage sooner than they expect. Also, today digital projects should be designed upfront both for data security AND more granular data sharing/sales requirements.
E: What regulatory changes are required?
JH: Again, it depends on the use case but it’s clear that the way we are interacting with electricity grids is changing extraordinarily quickly and that’s requiring us to rethink fundamental questions like how to recover network costs. I would say, though, that I do not think of regulation as an impediment to the transition. Certainly, not in the way that legacy systems are!
This may be quite a UK-centric view though, because this country is fortunate enough to a world leading regulatory approach to innovation and market design. Ofgem, particularly through the sandbox but also through their outreach, are really focused on allowing innovators to test new ideas and their benefit to both customers and UK plc.
E: Are there any other countries which have a good example to follow, in terms of dynamic consumer pricing or other market designs that will promote efficient use of DER?
JH: “Good” depends on where you fall in the trade-off between power price stability vs spikes. Large differentials may not benefit all consumers, but they certainly encourage greater engagement from consumers and flexible assets. Australia is the go-to example for this.
E: Can you give us an update on the flexibility platform?
JH: Indeed I can! At Electron, we fundamentally believe in “layered” markets so we are focussed on developing an exchange that allows asset operators to sell multiple services at the same time. This could be anything from a distributed asset selling balancing services (ESO), constraint relief (DNO), and power (supplier/community) at the same time, or a large power plant selling power + inertia + transmission constraint services all at once. People tend to talk about energy markets and flexibility markets like two distinct things. This is not very helpful. “Flexibility” is more of a bundle of products than a single market.
Right now we are working with a number of DNOs in the UK to develop new local markets, particularly around curtailment and congestion relief. All stars aligning, we hope to see the first trades here this year and indeed we already have a prototype running. In parallel, we are working with a broader consortium of traders to develop an exchange in which multiple products are stacked together. For us, this is the only sensible way to design for “whole system value”, while allowing the definition of what constitutes that to evolve with the various products that are bought and sold in the market evolve themselves.
E: You also have live projects in South Korea and Switzerland? How are the challenges different in each country, or are there synergies?
JH: The UK has six distribution network operators, South Korea has one, and Switzerland has closer to 600, so the coordination challenge varies substantially, however all countries are looking at the same challenges around digitally representing assets and capabilities (for which our shared asset register approach remains fundamental), and then developing multiple, layered markets on top of this. What and where those markets are varies though. For example, in Switzerland we are developing a market for the Canton of Valais that enables local utilities to coordinate and financially settle between themselves. They estimate that this would save them €800,000/year, before you tamper with any power flows.
E: Which other countries offer opportunities for Electron?
JH: We like to get involved in market and platform design in multiple countries at the same time because it expands our thinking on new flexibility products and fundamental platform requirements, so you never know.
I suspect the UK be one of the first to move to new grid/marketplace approach though. This country has always favoured markets and has a history of early regulatory reform. That said, I have noticed that countries like to move first, but utilities like to move second! The grid was, first and foremost, designed not to fail after all.