In this bitesize Q&A Suzy Lycett, Content Manager at Electron, sits down with Chief Commercial Officer, Chris Broadhurst, to explore the growing role of distributed energy resources (DERs) and grid flexibility in the United States. Listen now – or read on for the transcript.
There are similarities in the challenges that the UK and the USA face in making better use of DERs. Could you explain those similarities and how the pieces of the jigsaw are close together in the US?
Chris Broadhurst: There are some real similarities at the physical grid level between the US and the UK. Both have very similar grids. Both are experiencing load growth and at the grid edge, DERs are connecting faster, so experiencing congestion and connection queues. So at the physical grid level – the challenges are very similar.
Looking at the operating models: in the UK, we have an regulated, unbundled model, where the DSO – the distribution system operator – just looks after the distribution grid. The TSO – transmission system operator – looks after the transmission system. Then you have retailers. And so the value a DER can provide is fragmented across those different actors. It’s difficult to coordinate that value across those different markets and levels of the network.
What’s interesting in the US is the vertically integrated utilities own more of that value chain. They own the distribution network. They may own generation assets and participate in the wholesale market, so there is more value on the table for them to realise through DERs. So we think that’s a really exciting opportunity.
And in the same way that we have these coordination challenges in the UK. It’s about data standardisation and interoperability – and it’s really the same problems in the US as we try to bring these siloed teams together and break down those cultural and operational barriers.
Needs the same solutions of better data standardisation and interoperability to allow for stacking and coordination, etc. So although structurally and from a regulatory perspective, there are some differences. A lot of the problems at the grid and within the distribution utility are really similar. We do think that’s where the real opportunity is for the US.
In the US there are some high cost regions like California, for example. So is this DER discussion currently limited to those regions, or more expansive?
Chris: There’s certainly lots of pioneering work happening in those areas. Yet there’s still a lot of congestion and constraints outside of those areas, like Texas, the Midwest and the Southeast. They’re all facing more constraints from renewables and electrification, and they’re all starting to introduce programs, Virtual Power Plants, and aggregation models, to address that.
Plus, extreme weather isn’t just isolated to California or the Northeast. That need for grid resilience and reliability is something that DERs can address.
The other aspect of this is data centers. It’s creating this huge load growth. They want access to land and cheap power that obviously isn’t just available in north-eastern California. Areas like Virginia, Georgia, and Arizona are seeing demand from hyperscalers who want that cheap land and access to power. But, with that, comes a huge load that needs to be connected to the grid. Utilities are therefore having to figure out how to deal with that.
DERs and DER flexibility is a great way of managing those large loads, and the co-located renewables that they bring with them. So, it’s definitely not just limited to California. Severe weather is certainly driving the need for it, but also large loads like data centers and where they want to connect is also a factor.
Would you say that utilities are incentivised to be creative in how they procure that growing load flexibility from DERs? What can be done to encourage der utilisation and participation?
Chris: So, they are incentivised today to procure flex from DERs. I think the challenge though, is that the need for them to buy flexibility is increasing. They need to pay more for flexibility from DERs and to do that more often.
The traditional program-based approach – where you need to go through a filing process and cost benefit analysis for a very specific, discrete part of the network and a very specific problem – is lengthy and takes time. That’s not necessarily helping utilities deal with the pace at which they’re seeing load growth and electrification.
Utilities are able to recover the costs of flexibility from DERs, but the way that they do it needs to be streamlined.
There are ways to do that with market platforms, for example, to streamline how the utilities can broadcast their needs, and also ways to improve how DER owners and aggregators can sell into those markets or programs.
So, we think the incentives to encourage DER participation exist and that can work within the existing regulatory regime, but we need to make it easier for the utilities to buy then easier for the DERs and aggregators to sell into.
