The National Grid’s Electricity System Operator (ESO), last week released it’s Electricity Ten Year Statement (ETYS) detailing the need for greater interconnection between Scotland and England, the changes in consumer behaviour and the probabilistic approach it is looking to take.
The ESO’s head of national control Julian Leslie, talked to Current± about the report, and the next steps.
Why do you put together the ETYS?
The ETYS is partway through an annual process. It starts with the future energy scenarios in July, then the ETYS in November and then in January the Networks Options Assessment (NOA), where we make those recommendations to the transmission owners (TOs) for their investments over the next year.
Even though we’re triggering a major reinforcement through the NOA it’s only signalling to the TOs to make that investment for the next 12 months and then later you reassess it and see whether it’s the right thing to be doing.
So we’ve got this constant cycle of always ensuring that – based on the future energy scenarios and the boundary capabilities required – we’ve got this annual check as to whether we’re still doing the right thing, and if the future energy scenarios go in a different direction then that process will catch it.
Therefore we can always ensure that we have the right investment being made on system, whatever the next 10/15 years throws at us.
How much more capacity is needed for wind power from Scotland to be effectively distributed?
This is a long process, and it starts with the Future Energy Scenarios, which determine the credible pathways for the future. That will determine how much wind in Scotland is going to be required under each of the scenarios.
What we then do through the ETYS is run those four scenarios, and create the graphs in the ETYS document that we published last week. You can see for each of the various scenarios the various boundary transfers that are required.
We then use the output of the ETYS, and feed that into the NOA, which will do an economic cost benefit assessments on least-worst regrets basis to determine what is actually required in terms of capacity on the system.
As the future energy scenarios change because of policy decisions or technology, pricing or whatever else it might be, then that will feed into the start of this annual process, which then determines the boundary requirements and what is the least-worst regrets cost benefit analysis, in order to build the next set of capacity.
When you’re looking ahead for the next 10 years, how can you be sure that they’ll be enough to balance the intermittency they create when technologies such as EVs have grown much faster than originally predicted?
There are several things. The way our future energy scenarios are developed, we use 650 stakeholders from all corners of the industry and the new participants are the EV car manufacturers. Obviously if a trade can’t predict a massive increase in uptake and it is faster than all predictions, then we can’t predict that.
However, the mechanisms we have in place for that, certainly from an EV perspective, mean we don’t see there will be constraints on the transmission system.
We are pushing hard to ensure electric vehicles must have smart charging, so they charge at a time when there is capacity because the renewables like wind are blowing and it’s not the peak demand of the day. We try and fill in the troughs with electric vehicle charging.
But notwithstanding that, then the electricity market reform and the capacity mechanism, which looks at t-minus four and also t-minus one, so four years and one year ahead, they made sure that based on the forecast predictions that even on those cold days when there’s no wind and solar, that there is enough controllable generation to meet the demand.
Are you expecting any problems with the uncertainty around Brexit and the election affecting European interconnectors, and how can you factor that into a ten year statement?
We spent a lot of time thinking about Brexit and the impact on interconnectors, from what we’ve seen of the legislation we believe that whatever the outcome of Brexit power will still flow across the interconnectors.
In any event, even if it didn’t, there is enough generation within GB in order to meet the potential shortfall that an interconnector might deliver. But we don’t expect that to be a problem; we’re still part of the single energy market. There may be additional tariffs that apply, but we just don’t know.
We think that power will still flow because at the end of the day, there’s a market for that energy and the energy will go to where the money is. There’s nothing in the Brexit legislation that would prevent the import of energy from Europe, so we’re pretty comfortable with that.
As you look into the longer term, obviously, it’s a question for interconnector developers as to whether the financial security and stability of the two markets remains investable.
But that’s a question for the network interconnector developers, not for the ESO. But in the future energy scenarios we’re still predicting a significant increase in interconnection with Europe.
Could you talk me through the probabilistic approach that you’re looking into taking?
We already use a probabilistic approach for thermal. If you look at the security quality supply standards, they were developed in the 90s and they were deterministic standards.
What we’ve done since 2010 is introduce something called Connect and Manage, which means that we can connect the generation and then manage the output to handle the reinforcements we made. That led the way for us to be able to apply that principle to all of the bigger bounded capability reinforcements.
What we do in the NOA process is we look at what is the likelihood, and what are the number of hours in the year when the wind was above a certain level? What is the cost of the transmission asset that’s going to deliver that, and what actions could we take in a balancing mechanism in order to manage the flow of power across that boundary?
Then we do that cost benefit assessment. We’re looking at the value of a transmission asset and the value of the forecast constrained costs based on 20 years of wind and solar data. This allows us to look at the likelihood of that boundary being exceeded and therefore either the action taken in the balancing mechanism or the reinforcement being built. By comparing those two we can work out is a better to build the assets or to constrain generation.
You’re still developing it for a broader electrical system though, are there any challenges that remain?
The scenario I just talked about is a traditional thermal probabilistic assessment. What we’re developing is a way to make sure that probabilistic assessment is applied much more broadly across all of our activities within the electricity system operator.
Also we want to expand it into voltage probabilistic assessment, as well as just thermal. So we are just expanding that probabilistic assessment today to be much more fully utilised across all of the system.