Exploring Grid Code Change GC0117

00:05:10 – Pete Aston

Hello and welcome to another podcast from Roadnight Taylor. I’m Pete Aston, one of the engineers here at Roadnight Taylor, and I am joined by my fellow engineers Catherine Cleary, Kyle Murchie and Philip Bale. So, welcome to you all.

00:18:10 – Catherine Cleary

Hi Pete.

00:19:02 – Pete Aston

We are going to be talking about a reasonably techy issue today, so it’s grid code change GC0117.

00:20:23 – Catherine Cleary

Makes it sound very techy.

00:30:15 – Pete Aston

It already sounds techy.

I’m going to read you the full title, which may take some time – improving transparency and consistency of access arrangements across GB by the creation of a pan-GB commonality of power station requirements.

00:43:17 – Kyle Murchie

Wow.

00:44:16 – Pete Aston

Which clearly no one understands what that means at all. Basically, let’s go through – what is this doing? I don’t know. We’re not highly highly prepared on this podcast, so which one of you wants to pick up on what this is talking about?

01:01:05 – Catherine Cleary

I’ll have a stab.

So, this is trying to standardise the threshold for large power stations. So, we currently have a threshold of 100 megawatts in England and Wales, 30 megawatts in South Scotland and 10 megawatts in North Scotland, and above that threshold generators are classed as large. They have to go through a BELLA or a BEGA process for National Grid. If they have a BEGA, they have to participate in the balancing mechanism. And that’s been the case for what? Pretty much since, since kind of the BETTA transition, so for the last over 20 years or so. And this proposal is aimed at changing those thresholds to standardise them at 10 megawatts. So, anything over 10 megawatts, or 10 megawatts and above in England, Wales, Scotland would be classed as large.

01:48:15 – Philip Bale

Which effectively makes it worse for everyone, because they’re also removing the BELLA option for people in the north of Scotland as well. So they’re trying to standardise everything by making it more punitive for everyone, including the very north of Scotland, but mainly south of Scotland and England and Wales. That’s a very significant difference.

02:08:00 – Pete Aston

So Philip’s jumping ahead already into why is it a good or bad idea.

You’ve already got Philip’s idea, and I think there should be a disclaimer. I don’t think any of us are going to say it’s a good idea.

02:17:21 – Catherine Cleary

No.

02:19:13 – Philip Bale

No.

02:22:13 – Pete Aston

Okay. So why was this introduced?

02:25:21 – Kyle Murchie

Is it worth saying that it was introduced in 2018, you know, this is not a new…

02:30:00 – Catherine Cleary

Yeah, it’s been hanging around for a while.

02:31:00 – Kyle Murchie

Yeah, it’s been hanging around for a long time and seems to have gone through a number of working group meetings for the 23, that have happened to date, which is quite a large number, without actually getting this through to kind of implementation.

02:48:02 – Pete Aston

I think it’s probably got paused along the way by Connections Reform, hasn’t it.

02:49:15 – Kyle Murchie

Yeah, yeah, because I think when we were looking at it earlier, the last meeting was beginning of 2024. Obviously, at that point it was known that Connections Reform was then going to be the next topic of conversation and actually during some of that Connections Reform conversation, this point did come up and about a question of whether it should be restarted. So, we can see that’s where it’s come from, and we’re now at a stage where we’ve got it restarted, and we’ve got a consultation. That’s when, remind me Pete, when does the consultation close?

03:22:08 – Philip Bale

Yes, so the reason we’re talking about it now is that there is a consultation out from Ofgem, which came out on the 28th of February and closes on the 11th of April, so hopefully, by the time this podcast goes out, there’ll still be a couple of weeks left for people to make comments back, and we would certainly recommend making a response back to this, because it is very significant.

03:48:01 – Catherine Cleary

Yeah, and this because this affects a lot of people who currently do not have BEGAs or BELLAs or any kind of agreement with NESO.

So I mean, I’m thinking all of the 49.9 megawatt solar projects in England and Wales, you know, but anyone effectively distribution, connected generation, that’s 10 megawatts or above, and I guess one of the reasons we don’t think it’s a great idea is partly because of the kind of burdens it places on those, those parties.

So if you, if this were to be introduced and those, kind of you know solar farms, for example, had to have a BEGA, that would mean they had to do a new application to get that BEGA agreement with NESO, so that’s, you know, a £20,000 application fee. They’d have to go through the national grid, the NESO compliance process.

So rather than just doing the G99 kind of type C or type D compliance process, they’d be doing a much more kind of in-depth sort of you know 18-month process, typically, you know, for a BEGA compliance process, which has a really significant cost to them. So I think you know we were sort of talking about kind of you know 100, maybe even £150,000 to go through that process. So in terms of development costs, you know they’re racking up already just on an individual project basis. So this is probably something which we don’t think there’s been very much discussion of the kind of costs to individual project developers. Obviously there’s a cost that get passed on through kind of generation prices to the end consumer. So we think it’d be really valuable for developers to feedback on what some of those costs, perceived costs are.

05:20:12 – Philip Bale

And the ongoing costs of having to go through and recertify in terms of doing as well.

05:24:23 – Catherine Cleary

Yeah unfortunately, yeah nowadays for NESO is not just a one-hit wonder. You have to go back and recertify your compliance every five years. So, yeah, there’s an ongoing compliance obligation there. I suppose there are some other things which people who, if this gets approved, and you have to have a BEGA that basically commits you to participating in the balancing mechanism. So you have to register the as a BM unit with Elexon, I think you have to have a control point; so, that basically means that you know normally developers or generating operators and owners would commission a third party to kind of be their 24/7 control point. You know you can pick up the phone from National Grid when you know there’s a system incident or something, but you know that’s a paid service, again that developers would have to pay for. So quite a few ramifications.

06:13:05  – Kyle Murchie

Plus a managerial services agreement as well, an MSE.

06:15:19 – Catherine Cleary

Yeah, yes, yeah. I mean I think is it worth saying that’s one of, so what was the, you know – why would anyone think this was a good idea?

I suppose it’s perhaps a personal question.

06:26:22 – Philip Bale

I’ll play devil’s advocate.

06:27:20 – Catherine Cleary

But one of the ideas is that Nisei, for example, would like there to be more participants in the balancing mechanism. You know, I guess that’s kind of saying, well, if we think we’ve got kind of like more participants in that market, it offers better value. We might actually get a kind of a more economic balancing services from a kind of a greater number of participants. And that’s what comes with the, if you are a balancing mechanism unit, you have to have what’s called a mandatory services agreement, so those are all of the kind of balancing service or ancillary services that your generation plant can offer and the sort of circumstances under which you’d offer them.

It can be a bit of a, I’m going to go out and say, it can be a bit of a sort of thankless paperwork exercise for intermittent generation like solar and wind that you know. Actually, you know a solar farm isn’t going to be offering frequency services, for example. So, it feels like a little bit of a kind of additional, quite significant additional burden to have to go through. You know you have to get that agreement in place. You have to do some on-site testing to show that you know in theory, if it was sunny and you weren’t choosing to operate, that you might be able to offer some frequency response services. Obviously, when it’s sunny, you know, solar farms are operating at their full capacity already, so it does feel like there’s a lot of extra steps we’re putting in for very little system benefit.

07:44:13 – Philip Bale

I think, on the flip side, so the reasons why they want to do it is around standardising, but I don’t personally think that’s a particularly good reason of doing it, of making it standard for everyone across the different areas.

Get the fact that there’s some requirements, European codes, different things, but it still feels like it’s a fairly sort of onerous approach of trying to do it, but I think the key one that gets brought up is around more visibility and control, and, yes, it will give more visibility, control of the generation and potentially allow more understanding as to what the true demand is, rather than the demand at the GSP interface where it’s coming through.

08:23:14 – Catherine Cleary

For NESO’s control room.

08:24:19 – Philip Bale

For NESO’s control room, but potentially this is a fairly, sort of sledgehammer approach of trying to crack a nut, which is – there is a better way of forecasting and understanding the embedded generation, the smaller stuff in terms of coming through, and just because there isn’t that visibility at the moment, there might be a far more cost effective way of going around doing that than bringing in the mandatory approach, with everyone above 10 megawatts having to be sort of subject to this.

08:51:50 – Pete Aston

And it seems to me that the whole idea of the industry introducing DSOs distribution system operators over what, the last five years or so was precisely to sort of have this visibility and control function, and the DSOs can provide visibility of the generators that are connected to the distribution network up to NESO. And so it sort of seems to me like this is either duplicating or almost trying to subvert the whole idea of a DSO.

09:25:30 – Kyle Murchie

Yeah, because I was thinking you do also have those additional markets as well, those additional markets within DNOs offering various different services out to those parties connected to the network. So you’ve now got a potential control aspect through your DSO which could conflict with, ultimately, what the balance mechanism is, or duplicate maybe not conflict, but certainly duplicate. Obviously, when this was drafted, the idea of a DSO, I’m trying to remember when exactly it was, but the working group was really starting off in what, 2017? So around about the same sort of time as the initial concept, this Mod came, came about, but it’s a bit questionable whether that’s still the right route or whether the DSO could still be/ have the opportunity to actually close much of the gap.

10:31:10 – Philip Bale

I think one of the things that would be interesting is looking back at the lessons from history.

So both me and Pete were both working at DNOs when the Appendix G got brought in and the whole aspect there was increasing visibility of generations which went smaller and smaller to the stage that a one megawatt generator had to have that visibility for NESO and NGET to or sort of NGESO at the time, to understand where they were. And arguably we’ve probably got to the stage now where we’ve realised that they have too much visibility and too much information and too much data, which is why we’ve got CMP446, which is looking at actually increasing that threshold up to 4.94 megawatts in terms of going through. And then equally, the embargo or the deadline for having generation applications at transmission coming in before a pause, 375 applications came in via NESO and it’s caused everything to clam up and close down and not be able to clock start projects. So I think there should be a little bit of an understanding of we’re trying to gain that visibility, the impacts it has on the system.

11:17:08 –  Catherine Cleary

Yeah, because so even from a NESO perspective, we talked about the burden on generators, but there’s a burden on NESO as a result of having to process and, interestingly, there’s a document in the code proposal, code change proposal, that suggests that NESO had estimated there might be 650 additional, like new BM entrants per year as a result of this. So that’s 650 extra BEGAs that NESO have to prepare, produce, 650 additional MSAs, 650 additional parties that Elexon have to take through the BM registration process.

11:53:10 – Philip Bale

And the TOs and the work that they’ll have to do as well.

11:55:55 – Catherine Cleary

So, it’s a, you know that seems like it’s a, you know that is not a minor administrative burden, that’s a very significant.

12:00:09 – Pete Aston

And it does seem to me that in the sort of work group documents there hasn’t been so much focus on how much is it going to cost? You know there’s sort of comments like it probably will cost some more and you know there’s some additional burden, cost burdens here and there, but it doesn’t really feel like it’s got to the heart of what that cost could be, including the cost to the generators.

12:22:40 – Kyle Murchie

When you think about the compliance team at NESO and the amount of projects that they process per year last year we might be talking about three gigawatts worth of generation coming to the system, but actually a significant number of those projects were over a gigawatt. So really, in terms of the number of projects that they’re actually processing per year is relatively small. I mean certainly a large metric, away from 650. So that team are already moving into the realm of you know posts, gate two offers being issued, moving those projects forward and hopefully having a larger number of projects completed, alongside potentially then taking on a significant increase in number of embedded projects that they have to process as well.

13:06:30 – Philip Bale

And the other complexity that we touched on briefly before we started this one, is obviously the application date for this is the 1st of June 2027. We’re going to go through the process of CP 2030, which is going to go through and reorder the queue, and then a comment that was made earlier is do all of these projects have to apply for BEGAs? If they have to apply for BEGAs, how does that result in the queue and the reordering of the queue? If it’s not done at the same time as CP2030, then that’s going to disadvantage some people where potentially they’re going to go into the back of the queue.

13:33:50 – Pete Aston

Yeah, so just to be clear on the June 27th date, it is for schemes that already have got an accepted offer – you have to have got financial close or ordered plant by June 27th. If you haven’t, then you would have to, then this would be applied to this would be applied to you and you’d have to apply for a BEGA, and I think that’s problematic with dates and Connections Reform.

14:01:00 – Kyle Murchie

On that point around ordering plan, talking about meeting FID, is it as specific as that or does it cover Milestone M7? I’m just thinking. Milestone M7 obviously allows you to have a subsidy award. Is it a bit broader than the specifics of FID?

14:19:06 – Pete Aston

I don’t know.

I’ll have to read while we’re talking about it.

14:23:00 – Kyle Murchie

And actually I’m thinking back to actually 2018, when this model was originally raised, did those milestones exist?

14:28:50 – Catherine Cleary

No, they didn’t exist in the same form. No, in the same form.

14:30:00 – Kyle Murchie

No, so they probably are slightly out of step, but you know, if they were in, that would be one thing, that Mod, even if it was to go forward, we have to clarify because a lot of things from a protections perspective under the Connection Reform Mods are all in relation to the milestones, and milestone M7 does crop up quite a lot. So what we wouldn’t want is this to be out of step from that.

14:57:10 – Pete Aston

Okay, shall I read you what it says. It is not intended for the proposal to be implemented retrospectively. If the proposal is approved, generators would only be affected if they are embedded power stations with a registered capacity of 10 megawatts and above, which applied for a connection agreement or modification application on or after the implementation date. So any new new scams that come along or concluded purchase contracts for their main plant and apparatus on or after the 1st of June 27.

15:25:07 – Kyle Murchie

Okay.

15:28:09 – Catherine Cleary

So, it’s basically saying we’re limiting the grandfathering to up to June 2027 in terms of implants.

15:33:40 –Kyle Murchie

The challenge there is if you’re a project where you can meet that criteria but you need to make a small change to your project, you know, reduce your capacity or alter the kind of ratio of technology, which we do see at the moment there’s a flexibility there, then by the sounds of that, that would trigger you now having to require that.

15:55:10 – Pete Aston

Well, you could be in the queue now, through Connections Reform, get a 2030 connection date and not be thinking about ordering plant till 2028.

16:06:30 – Philip Bale

Or you could be in the scenario where you’re actually going to get connected in 2029 but then actually can’t connect in 2029, because you then have to go back through and apply for your BEGA.

16:15:07 – Catherine Cleary

Which could be a different date.

16:15:45 – Philip Bale

Different date, different outcome, different cost, the delay associated with that, which actually means you can’t reach your fit until you actually know your baseline of what your network, what your project is.

So, yeah, there feels like there’s a lot of things that are baked in here as well, that is going to be a challenge.

16:34 – Pete Aston

Just picking up on another point one of the points of the initial Mod said it was going to help consistency – I think you mentioned that a bit earlier, Philip. So, you know they’ve reduced the bar or raised the bar for everyone, made it harder for everyone, but there’s still quite a lot of differences across the industry, aren’t there, depending on locationally. So even if this change came in, the consistency is still not there really.

17:01:10 – Catherine Cleary

I don’t think we, we haven’t improved the scenario in terms of how many different commercial arrangements could there be for embedded generators, because you could have projects. Well, I think you pulled out the examples, but you can have projects which were under the new transmission impact assessment limits, which is either five megawatts in England and Wales or 200 kilowatts in Scotland note the difference, you know, not standardised. And then you can have projects which were up to the 10 megawatts, which needed to go through that transmission impact assessment but didn’t need a BEGA, and then projects above the 10 megawatts and above, which needed a BEGA agreement. So you know we’ve already got kind of four different regions. We’re not going to change that.

17:42:09 – Philip Bale

And if you’re in Scotland, transmission is at 132 kV and actually you might be a 50-megawatt generator in Scotland and connect at transmission, not a distribution.

17:52:50 – Catherine Cleary

Which is the rationale for the original, you know the current status quo. The reason we have different limits for large in Scotland is that electrically significant is a different megawatt threshold because it’s a 33 kV network only.

18:04:10 – Pete Aston

And that feels appropriate.

18:07:06 – Catherine Cleary

I agree.

18:07:10 – Pete Aston

And the new level just feels inappropriate because it’s not reflecting the actual networks that are in place.

18:17:00 – Kyle Murchie

Yeah, I mean across the industry. If you were to say large and 11 megawatts, those two don’t…

18:22:00 – Catherine Cleary

I think you’d get a lot of laughs, wouldn’t you?

I think there’d be people saying my two-field solar farm doesn’t feel very large.

18:27:00 – Philip Bale

Or my rooftop solar scheme doesn’t feel very large because we are now seeing 11 megawatt rooftop solar schemes on big industrial commercial buildings.

18:36:02 – Catherine Cleary

So I guess we probably made it quite clear what our views are however, we’re not a particularly balanced podcast, but I think there’s an opportunity for people to feedback on the Ofgem consultation. There were some alternates proposed as part of the work group weren’t there, so the proposer’s solution was to lower everything to 10 megawatts. I think there was actually an alternate solution to raise everything to 100 megawatts. Say, okay, we’ll standardise, but standardise on what most people do, which is the majority of these schemes are England and Wales. So standardise on the 100 megawatts and maybe, you know, give the guys up in Scotland a bit of an easier ride. So I suppose that’s something which parties with projects in Scotland that are on the threshold might actually be quite interested in responding to, suggest that or support that alternative.

19:20:19 – Pete Aston

Yeah, so I think there was one official WAGCM which is not a WAGCM, a WAGCM with a grid code modification a W-A-G-C-M and then three other alternates listed in the Ofgem consultation.

But yeah, so doing a variety of different things.

19:41:50 – Catherine Cleary

All of which sound quite complicated even just reading them.

19:42:15 – Pete Aston

None of which just say can we just leave everything as it is because it’s not too bad?

19:43:56 – Catherine Cleary

I guess that doesn’t have to be raised as a wagon. This can just be not approved.

19:55: 00 – Philip Bale

I mean, I think it’s probably worth reflecting the fact that, whilst everything is okay from an embedded generation connection perspective, that it’s probably not okay from a NESO and a system balancing perspective and it’s only going to get worse. I think the comment that most of us will feel here is that this is probably not the answer. They’re the fact that there is an issue, but that potentially, this is going at it in completely the wrong way and that this is not the right thing to be doing.

20:21:03 – Catherine Cleary

And that DSOs, you know, could be the answer to a lot of those challenges, you know. And actually creating new services, new ancillary markets that embedded customers can play in, that are more appropriate, you know, for things like intermittent technologies,  I think would be a more effective solution.

20:37:20 – Pete Aston

I think I know we’ve gone through it just now, but I think, sort of as we’re drawing to a close, it would just be worth highlighting once more the implications for generators. So if you, as a large generator, the things that you have to do to sort of get that transmission access, so the first thing is going to be applying for a BEGA or a BELLA.

21:03:02– Catherine Cleary

No, no, just a BEGA.

21:05:55 – Pete Aston

Okay, BELLAs go all together.

So apply for the BEGA and we’re talking, what, 15 to 30-ish?

21:13:15 – Catherine Cleary

Yeah, about 15 to 30k at the moment.

21:14:59– Catherine Cleary

Something like that, based on current application fees.

21:17:55 – Pete Aston

It seems that’s still significantly more expensive than a DNO application. So that’s the first cost that goes in there. I guess the next one is you need some extra kit on site, do you? Is there an extra, you know, Is there any extra comms costs for connecting?

21:36:20 – Catherine Cleary

Yes. So short answer is yes and it depends slightly how you register the BM unit, and you basically need some metering comms costs in there and you need some slightly different, especially operational monitoring equipment. So people who’ve got Type C and Type D projects will be a bit familiar with that kind of operational metering monitoring requirement things like dynamic recorders and fault recorders. But there’s a bit more of an explicit list within the grid code. So, yes, some extra kit potentially.

22:09:05 – Pete Aston

Some extra kit.

22:09:45 – Kyle Murchie

Which comes along with some ongoing operation costs as well. It’s not just the capex to put it in. It’s that operation and who’s going to operate that on your behalf, or are you going to operate it yourself?

22:21:30 – Pete Aston

And then probably the more significant one is the compliance.

22:25:10 – Catherine Cleary

Compliance process, yes, needing to go through the compliance process with NISO. So although your technical requirements for compliance things like your fault-ride through requirements might not change very much, the process you go through does and we think that’s a really significant cost. So we reckon most generators end up budgeting sort of 100, 150k for going through the NESO compliance process even as an embedded generator.

22:48:22 – Pete Aston

And is that size specific, or is it just if you’ve got to comply?

22:54:42 – Catherine Cleary

You’ve got to comply. And we’ve got a case study about a 50 megawatt solar scheme which has just been through this process and it’s been treated in exactly the same way as a 1.5 gigawatt nuclear station would have been.

23:10:20 – Kyle Murchie

I think there’s another case study coming out which was around 500 to 800 megawatt scheme and, exactly as you say, the same process. So, although some aspects of the process are a little bit lighter, generally speaking you’ve still got the same duration. You know that 18 months we mentioned earlier is a starting point which is really quite significant as well if you’re thinking about projects that are going to be connected in the next few years. If you normally are going to require an 18-month period of compliance, that’s a significant addition to your building.

23:40:52 – Pete Aston

So it’s not just the cost up front is a potential time scale…

23:41:02 – Catherine Cleary

To delay your project.

It does delay projects, that you know. I guess that like we see that. But for those who you know are lucky enough to not have to deal with the compliance process, you know it absolutely, we absolutely see projects with their energization dates delayed because of either delays in in registering a BM unit or delays with the compliance process.

24:01:12 – Kyle Murchie

I think on the face of it can sometimes look like oh well, I’ll be get, I’ll be doing the same sort of process because now you know, if you’re a type CRD you’ll still be going through the process with having an ION and a FON. The terminology has aligned over recent years but actually what you need to do to get that ION and to get that FON is significantly greater than going through the NESOs process.

24:24:33 – Pete Aston

And then just looking at the numbers again just before we finish, I think, catherine, you said from one of the work group documents they were projecting maybe 650 projects a year coming through – that’s pretty significant. And then in terms of what’s already in the queue we just did a quick search just now and there’s over 2,000 projects that are 10 megawatts and above in the queue that probably don’t already have a BEGA and so potentially quite a proportion of those might not make the June 27 date and therefore might have to then apply through, as well as the sort of new schemes coming through. So that could be a pretty significant workload for what NESO do have to manage.

25:11:33 – Catherine Cleary

Yeah definitely.

25:12:27 –  Pete Aston

Okay, right, well, so in that highly balanced podcast, we’ve come to the conclusion that GC0117 probably doesn’t quite do what it was intended to do in terms of improving consistency and so on across the industry. But you listeners can have your say, so, respond to the Ofgem consultation by 11th of April and you can sort of make your views be known as well, whatever they are. But thank you, Catherine, Kyle and Philip, and thank you everyone for listening and we do hope you’ll join us for our next podcast.

Thank you very much.

Bye-bye

25:53:42 – Everyone

Thank you.