Summer Outlook - National Grid ESO
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Summer Outlook 2019 The Summer Outlook Report is an annual publication delivered by National Grid each spring. It presents our view of the gas and electricity systems for the summer ahead (April to September). The report is designed to inform the energy industry and support their preparations for this summer and beyond.
Welcome
Summer
Outlook
2019
Thank you for reading our this new format will enable you As always, we would really
Summer Outlook report. As we to interact with the Summer welcome your feedback so we
look forwards to this summer, we Outlook report in a way that can ensure our documents are
are confident that that there will meets your needs. as useful as possible. Email us at
be sufficient energy available to marketoutlook@nationalgrid.com,
meet demand, and that we have From 1 April 2019, the Electricity or you can join the conversation
the right tools in place to manage System Operator (ESO) will be using social media via LinkedIn,
operability in all scenarios. a new legally separate company Facebook and Twitter.
that will carry out our ESO function
This year, we have responded within the National Grid Group.
to stakeholder feedback by trialling Whilst this will provide focus to our Fintan Slye
a new format for this document. electricity activities, facilitating whole Director UK System Operator
We want to ensure that the Summer system outcomes is also one of our
Outlook is as clear and succinct key roles as an ESO going forward.
as possible, without losing the
richness of the data that underpins As we tackle the key energy
our analysis. challenges ahead of us, we expect
to see increasing interactions
In order to do this, we have between gas and electricity markets
produced a concise executive and operations. For this reason,
briefing pack. This aims to quickly documents such as the Summer
put across key messages from and Winter Outlooks will continue
the Summer Outlook, through to be produced on a dual fuel
interactive graphics. Accompanying basis and we will continue to
this, we have produced an in-depth draw out and explore whole
data workbook, with additional energy system themes in this
analysis that we know is valued year’s Summer Outlook.
by our stakeholders. We hope that
Summer Outlook 2019
1
Summer 01
Outlook
2019
Executive summary
Overview
Summer 02
Outlook
2019
Executive summary
1
We are confident that there will
3
Whole system thinking
be sufficient supply available to is becoming increasingly
meet energy demands for the important as long term
coming summer. We anticipate trends of decarbonisation and
similar gas and electricity demands decentralisation drive increased
to summer 2018. interaction between the gas
and electricity transmission
2
systems. In the short term this
is primarily due to gas fired
We have the right tools and electricity generators balancing
services available to manage the intermittent output of
operability for the coming renewable electricity generators.
summer, particularly during
periods of low demand, or when
access requirements increase for
delivery of key maintenance work.
4
We anticipate no additional
operability challenges for this
coming summer as a result
of the UK’s planned exit from
the EU. We have tested our
planning assumptions in a
broad range of scenarios and
via engagement with industry.
These scenarios fall within our
normal contingency planning.
Supply and demand
Summer 03
Outlook
2019
Executive summary
We are confident that there We do not think it is likely that Key statistics, electricity
will be sufficient supply available we will need to instruct inflexible
to meet energy demands for the generation to reduce output Electricity transmission peak demand 33.7 GW
coming summer. We anticipate in weeks when demand is low. Electricity transmission minimum demand 17.9 GW
similar gas and electricity However should this be necessary
demands to summer 2018. we have the tools to do so. Minimum available generation 39.8 GW
Electricity Demand – weather Gas Demand – during the summer
corrected demand seen on the gas fired electricity generation Key statistics, gas
transmission system at both a peak becomes a more significant
and minimum level will be similar component of GB demand, unlike GB gas demand 25.2 bcm
to last summer, as the recent trend winter when domestic heating
of increasing solar generation has dominates. This drives profiles to Total gas demand 36.1 bcm
slowed. Generation that is not become more variable in line with
connected to the transmission renewable generation. We also Above demand forecasts are weather corrected.
network (such as the majority anticipate greater levels of transit
of solar generation) reduces gas than last summer in response
transmission demand as more to market conditions.
demand is met locally.
Gas Supply – we anticipate
Electricity Supply – we will be increased liquefied natural gas
able to meet demand and our (LNG) deliveries compared to last
reserve requirement at all times summer. Whilst this could provide
throughout summer 2019 under competition for other supply
all interconnector scenarios. sources, it is likely to result in greater
transit flows to the continent.
Operational outlook
Summer 04
Outlook
2019
Executive summary
We have the right tools and services available to manage operability for the
coming summer, particularly during periods of low demand or when access
requirements increase for delivery of key maintenance work.
Key messages – electricity Key messages – gas
• Low transmission demand and • Managing reactive power and • Although the need for • We are expecting increased
high volumes of low inertia voltage levels will continue to maintenance remains high, volumes of LNG supply, which
generation can cause operational be challenging. We have tendered we anticipate no major risks affects flows of gas across GB.
issues over the summer. for the provision of (Enhanced) to National Transmission As LNG supply is less predictable
Reactive Power services for System (NTS) access for the than UK Continental Shelf supply,
• We will need to take day-to-day summer 2019 and 2019/20. planned summer schedule. we must be prepared to operate
actions to manage system the network in increasingly
frequency in times of low • Work continues to move smaller • During summer months, gas fired complex or new configurations
demand. Usually this will generation to new protection electricity generation becomes at relatively short notice.
involve working with flexible settings, which will reduce the a dominant component of gas
generation to reduce supply. need to manage system stability demand. Its variability results
using operational tools. in a need for close management
of system pressures. We are
reliant on timely and accurate
physical notifications to minimise
operability risks.
Whole energy system
Summer 05
Outlook
2019
Executive summary
Whole system thinking Figure 1
is becoming increasingly
important as long-term
Load factor of renewable and gas fired electricity generation summer 2018
• Output from gas fired
60% generation mirrors the output
trends of decarbonisation and from renewable generation,
decentralisation drive increased increasing when renewable
interaction between the gas and
50%
output decreases and
electricity transmission systems. vice versa.
Load fatcor (percentage)
40%
An example of this is how
increased renewable generation
• The resulting volatility in
30%
output required from gas
on the electricity system, coupled fired generation also means
with a gradual move away from 20%
the gas demand to these
coal, has a direct impact on the sites is more variable.
operation of the gas system. 10%
• In turn this variability has an
0% impact on how we configure
and operate the NTS,
01/04/2018
08/04/2018
15/04/2018
22/04/2018
29/04/2018
06/05/2018
13/05/2018
20/05/2018
27/05/2018
03/06/2018
10/06/2018
17/06/2018
24/06/2018
01/07/2018
08/07/2018
15/07/2018
22/07/2018
29/07/2018
05/08/2018
12/08/2018
19/08/2018
26/08/2018
02/09/2018
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23/09/2018
30/09/2018
07/10/2018
14/10/2018
21/10/2018
28/10/2018
increasing flexibility
requirements within
Renewables Load Factor Gas plant Load Factor and across days.
• The NTS compressor portfolio
is increasingly relied upon
to manage this variability
in operational pressures.
EU Exit impact
Summer 06
Outlook
2019
Executive summary
We anticipate no additional
operability challenges for • In all scenarios trading will • Should the UK leave the EU
continue, and electricity will flow. with no deal, cross border trading
this summer as a result of It is expected to flow from lower of energy would take place
the UK’s planned exit from to higher priced markets as is outside of the single market
the EU. We have tested our the case at the moment. framework, i.e. under World Trade
planning assumptions in a Organisation rules for the majority
broad range of scenarios and
via engagement with industry. • In a no deal scenario, the of countries, where no free trade
mechanisms of cross-border agreement has been negotiated.
These scenarios fall within our gas trade are not expected Furthermore, as is the case now,
normal contingency planning. to fundamentally change. flows on both gas and electricity
Gas shippers mostly purchase interconnectors may also be
Potential impacts concerning energy and capacity separately, impacted by fluctuations in
interconnector trading are and there would be no change currency exchange rates.
discussed below: from this in the event of a no
deal exit from the EU. The UK’s
• Currently when electricity Transmission System Operators
is traded over interconnectors (TSO’s) expect to have continued
with connected markets access to the Prisma gas
in the EU a day ahead of real capacity trading platform1
time, this is done using implicit to allocate capacity at
arrangements. This makes interconnection points.
trading faster and more efficient.
In the case of a no deal exit
from the European Union, these
arrangements would no longer
apply and interconnectors
would have to move to fallback
arrangements.
1
https://platform.prisma-capacity.eu/#/start
Key publications from the System Operator
Summer 07
Outlook
2019
Executive summary
System Operator publications The Operability Strategy Report System Operator publications 2019
The Summer Outlook Report considers the current operability Network Options Assessment Winter Outlook Report
is just one of the documents challenges the ESO faces and how January October
within our System Operator these are likely to change in future. The options available to meet Our view of the gas and
suite of publications on the future reinforcement requirements electricity systems for the
on the electricity system. winter ahead.
of energy. Each of these documents For gas, these issues are considered
aims to inform the energy debate in the Gas Ten Year Statement and
and is shaped by engagement Future Operability Planning Summer Outlook Report Electricity Ten Year Statement
with the industry. publications. We share aspects Spring November
of our analysis with the industry Our view of the gas and electricity The likely future transmission
systems for the summer ahead. requirements on the electricity
The starting point for our analysis during the development of these system.
is the Future Energy Scenarios documents to make sure that the
(FES). This document considers proposed solutions meet the needs
the potential changes to the of our stakeholders. Operability Strategy Report Gas Ten Year Statement
demand and supply of energy Summer 2019 November
Our view of future electricity How we will plan and
from today out to 2050. system needs and potential operate the gas network,
improvements to balancing with a ten-year view.
The network and operability services markets.
changes that might be required
to operate the electricity system Winter Review and Consultation Future Operability Planning
Future Operability Planning 2016
Future Operability
June November/December
Planning 2016
in the future are explored in the
UK gas transmission
A review of last winter’s How the changing energy
Electricity Ten Year Statement, forecasts versus actuals and landscape will impact the
System Operability Framework an opportunity to share your operability of the gas system.
and Network Options Assessment. views on the winter ahead. National Grid plc
National Grid House,
Warwick Technology Park,
Gallows Hill, Warwick.
CV34 6DA United Kingdom
Registered in England and Wales
No. 4031152
www.nationalgrid.com
Future Energy Scenarios System Operability Framework
Future Energy Scenarios
SystemOperability Framework 2015
Future Energy System Operability
July Regular updates
Scenarios Framework 2015
UK gas and electricity transmission UK electricity transmission
A range of plausible and How the changing
credible pathways for the energy landscape will
future of energy from today impact the operability
National Grid plc
National Grid House,
Warwick Technology Park,
Gallows Hill, Warwick.
CV34 6DA United Kingdom
Registered in England and Wales
No. 4031152
out to 2050. National Grid plc
National Grid House,
Warwick Technology Park,
Gallows Hill, Warwick.
CV34 6DA United Kingdom
Registered in England and Wales
No. 4031152
www.nationalgrid.com
of the electricity system.
www.nationalgrid.com2
Summer 08
Outlook
2019
Electricity
In this section we present our current view
of electricity demand for summer 2019.
We also provide an electricity supply and
operational view for the coming summer.
Our operational view is based on historic
performance and data provided to us by
generators. We use this data to present
a picture of operational surplus for each
week of summer and to determine the
actions we may ask generators to take
during periods of low demand.
In addition, our Europe and interconnected
markets section explores interconnector
behaviour, and provides market insights into
the impact to GB of pricing and renewable
generation in neighbouring countries.Electricity demand
Summer 09
Outlook
2019
Table 1
Key messages Weather corrected transmission system demand for summers 2016, 2017, 2018 and
normalised transmission demand for 2019.
In July 2018, we saw the lowest Our analysis suggests that this
transmission system demand downward trend will slow this Year Summer Daytime High summer
(TSD) on record at 16.3 GW summer as the growth of minimum (GW) minimum (GW) peak (GW)
(actual demand based on actual distribution connected
weather including station load). generation, mainly solar 2016 17.8 22.7 36.3
This continued the downward photovoltaics (PV), decreases and 2017 17.6 21.2 34.4
trend in demand that we have we anticipate minimal reductions
seen on the transmission system in underlying demand. Therefore 2018 18.0 21.0 33.9
since 2011, which has largely been we expect the weather corrected 2019 (forecast) 17.9 20.8 33.7
due to an increase in distribution demand in summer 2019 to be
connected generation. broadly similar to summer 2018.
•M inimum summer demand
is expected to be 17.9 GW.
• D aytime minimum demand
is estimated to be 20.8 GW.
• P eak demand for the
high summer period is
expected to be 33.7 GW.
Further information can be found
in the data workbook.Electricity demand
Summer 10
Outlook
2019
Summer system demands
Periods of low demand can have Weekly peak demand Summer minimum demands 200 MW lower than last year’s
an impact on how we operate the Figure 2 shows the weekly peak Historically, lowest demand on the weather corrected demand.
transmission system. As a result, demand for summer 2018, and transmission system has occurred
it is important that we understand our forecast for 2019. Our peak overnight. However, growth of Furthermore, weekly overnight
the minimum levels of demand demand for the high summer renewable generation has meant summer minimum demand for 2019
along with the peak demand that period between June and the that lower demands may occur in is expected to be 100 MW lower
we can expect to see during the end of August is 33.7 GW. This the daytime. As Figure 3 shows, than last year’s weather corrected
summer months. is 200 MW lower than last year’s daytime summer minimum demand demand, at 17.9 GW.
weather corrected demand. for 2019 is expected to be 20.8 GW,
Figure 2 Figure 3
Weekly peak demand for summer 2018 against our summer 2019 forecast (weather corrected) Summer minimum demands, 2018 and 2019 forecast (weather corrected)
45 30
44 29
43 28
42 27
41 26
40 25
Demand GW
Demand GW
39 24
38 23
37 22
36 21
35 20 20.8
34 19
33 18
32 17 17.9
31 16
30 15
14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43
Week number Week number
High summer period Forecast peak 2019 Peak 2018 High summer period
Weekly daytime summer minimum 2019 Weekly daytime summer minimum 2018
Weekly summer minimum 2019 Weekly summer minimum 2018Electricity demand
Summer 11
Outlook
2019
Daily demand profiles
Daily demand profile Peak demand timings Figure 4
During the summer months, Daily peak demand is largely Daily hourly demand profiles from the high summer period 2018
solar generation has a more influenced by the amount of solar
40
prominent impact on demand radiation. For example, if the sun
profiles. For a number of years, is shining all day, the peak demand 35
maximum solar generation is likely to occur either in the
output has coincided with the morning between 8am and 9am 30
fall in demand after lunchtime. or after sunset. The daytime
Demand GW
25
demands between 9am and
Figure 4 shows the daily hourly sunset are suppressed by 20
demand profile from the high distribution connected generation 15
summer period in 2018. This helps (mainly solar PV).
us to forecast the daily minimum 10 Typical summer minimum Potential minimum at times of high solar
and daily peak demand timings 5
for the coming summer.
0
Minimum demand timings 0:30 2:30 4:30 6:30 8:30 10:30 12:30 14:30 16:30 18:30 20:30 22:30 24:30
Figure 4 suggests that the daily Time
minimum demand is likely to occur Maximum and minumum demand range Average demand
between 5am and 6am. Demand Daytime (solar generating) Sunrise/sunset
then increases until 8am where it
remains relatively flat until 4pm.
After this, it starts to increase for
the evening peak in demand.Spotlight
Summer 12
Outlook
2019
Update on Network Innovation
Allowance (NIA) projects
1 3
Following our NIA project with the Finally, our partnership with
Installed solar PV capacity is now over Alan Turing Institute for Data Sheffield University reached another
Science, we developed and milestone during the winter of
13 GW and continues to have a significant implemented a new machine- 2018/19, with the release of an
effect on transmission system demand. learning based national solar power updated set of regional solar PV
model in September 2018. This is outturn estimates. These have
We have continued to enhance our ability the first time that such technology enabled the production of regional
to predict solar generation accurately, has been used in our suite of solar PV forecasts, which we
forecasting tools. Compared to utilise to strengthen our studies
and during the last 12 months we saw the previous models, this new tool of network planning and constraint
implementation of a number of projects: has reduced our mean absolute management during 2019.
solar forecasting errors across all Real time solar PV generation
timeframes by approximately 33%. output can be accessed here
We now have an enhanced suite of www.solar.sheffield.ac.uk/pvlive.
solar forecasting models, including
one from our NIA project with These projects are serving to
Reading University. improve the ESO’s management
of system balancing and
2 network constraints in view
Also in September 2018, our NIA of the significant impact of
project with the Met Office furnished solar generation. We continue
an improved data-feed of short-term to explore and implement further
forecasts of solar radiation, which initiatives to stay abreast of the
is the key driver of solar power changing energy landscape,
generation. The new values and balance supply and demand
addressed the tendency to under- accurately and economically.
forecast solar radiation, and
therefore solar generation.Electricity Supply,
Summer 13
Outlook
2019
including operational view
Figure 5
Key messages Weekly generation and demand summer 2019
54
52
50
48
46
39.8 GW Demand
44
42
40
38
GW
Based on current operational We are able to meet normalised 36
data the minimum available transmission demand and our 34
generation is expected to be reserve requirement at all times 32
30
39.8 GW in the week commencing throughout summer 2019 under 28
10 June (no continental all interconnector scenarios, 26
interconnector flow scenario). including throughout the shoulder 24
months of April and September. 22
20
01 08 15 22 29 06 13 20 27 03 10 17 24 01 08 15 22 29 05 12 19 26 02 09 16 23 30 07 14 21
April May June July August September October
Date
Max normal demand (including full Ireland export) Reserve requirement
Assumed generation with no continental IC flows Assumed generation with base continental IC flows
Assumed generation with high IC continental flows
*Please note data on the BM reports website does not include interconnector imports/exports and is
largely unadjusted (i.e. does not include derating or breakdowns – with the exception of wind where
this is accounted for via the assumed load factor).Electricity Supply,
Summer
Winter 14
Outlook
2019
>1
Executive
summary
including operational view
>2
Our role
>3
Electricity Operational view:
>4 •In the summer months, power • T his operational view doesn’t include
stations carry out planned any generator market response close
Gas to real time – for example if market
maintenance as there is typically
>5 lower demand and lower electricity prices increase, generators may
Glossary
prices than in the winter. move planned maintenance. For the
• To plan for the summer, the ESO latest OC2 data and operational view,
see the BM reports website2,
uses OC2 data submitted weekly by
generators, which includes planned updated each Friday.
maintenance dates. We also apply • ased on current economic
B
a breakdown rate to this data, to conditions, we expect some coal
account for unexpected generator power stations to temporarily shut
outages or restrictions close to down during summer 2019. This has
real time. already been indicated by the loss of
• This is then modelled against forecast availability of two 500 MW coal fired
units. Power stations in this position
normalised transmission demand
(including station load), may become available if the price
plus a reserve requirement of 900 increases until it is profitable to
MW and a range of interconnector generate, or if our control room
flows to provide a weekly view of approaches them with enough
the anticipated operational surplus notice. Furthermore, some plants
(see previous figure, based on data may decide to close if it is no longer
provided on 14 March 2019). economical to run. A 2,000 MW coal
fired unit has announced closure
from the end of September 2019.
• urther detail on available generation
F
for the summer, breakdown rates etc.
can be found in the data workbook.
2
https://bmreports.com/bmrs/?q=help/about-usOperational view continued
Summer 15
Outlook
2019
Key messages
Based on current data we expect – curtailing flexible wind farm
that during some periods this output at a national level via
summer inflexible generation the Balancing Mechanism
output plus flexible wind output or via direct trades
will exceed minimum demand – trading to reduce the level
(see Figure 6) of interconnector imports.
All actions will be carried out
We therefore anticipate that in economic order, with cheaper
we may need to take actions actions taken first. At a local
such as: level wind may also need
– requesting pumped storage units to be curtailed due to local
to increase demand by moving constraints or other issues.
water back to their top lakes
– (this increase in demand is
shown by the pink demand
line in Figure 6)Operational view continued
Summer 16
Outlook
2019
In the summer, there is a significant To help us understand actions Figure 6
reduction in transmission system we may need to take this Generation and minimum demand by week, summer 2019
demand, as there is less summer, we model levels of 32
requirement for heating and lighting, inflexible generation, and inflexible 30
and a higher output from distributed generation plus flexible wind output 28
26
generation such as solar. against forecast minimum demand 24
each week (see Figures 6 and 7). 22
Throughout the summer, the ESO 20
needs to keep the demand and These forecasts are updated weekly 18
supply of electricity in balance at and can be found on our website3.
GW
16
all times. To do this, the system 14
still needs to be able to respond As discussed previously, minimum 12
10
to the largest generation or demand demand is likely to take place in the 8
loss. We also need to maintain early morning, or in the afternoon 6
positive and negative reserve levels when output from distributed 4
to account for forecasting errors generation is at its highest. 2
and unanticipated reductions 0
in generator availability close 01 08 15 22 29 06 13 20 27 03 10 17 24 01 08 15 22 29 05 12 19 26 02 09 16 23 30 07 14 21 28
April May June July August September October
to real time (this is discussed Date
in further detail in the operability Nuclear Inflexible BMUs (eg CHP)
Plant total providing requlating reserve
Inflexible hydro I/C imports after trades
Plant providing voltage support Inflexible wind
toolbox section). Flexible wind Minimum demand Minimum demand inc. pumping
3
https://www.nationalgrideso.com/balancing-data/forecast-volumes-and-costsOperational view continued
Summer 17
Outlook
2019
Figure 7
Key messages Inflexible generation and minimum demand by week, summer 2019
32
Based on current data, we do 30
not expect inflexible generation 28
output alone to exceed minimum 26
demand in summer 2019. 24
22
20
18
parameters from generators, and
• The ESO can undertake a number
GW
16
inform participants of a risk of 14
of actions if supply risks being instructions to inflexible 12
higher than demand. Usually generation. To date a limited 10
these involve working with flexible number of local NRAPMs have 8
generation to reduce supply. 6
been issued, and no national
• If however these actions are not
NRAPM has been issued.
4
sufficient to bring supply and You can read more about
2
0
demand into balance, further NRPAMs on our website4. 01 08 15 22 29 06 13 20 27 03 10 17 24 01 08 15 22 29 05 12 19 26 02 09 16 23 30 07 14 21 28
action may need to be taken.
• ased on current data, we do
B
• In the longer term the number of April May June July
Date
August September October
actions we take as an electricity Nuclear Inflexible BMUs (eg CHP) Inflexible hydro I/C imports after trades
not expect inflexible generation system operator is likely to Plant total providing requlating reserve Plant providing voltage support Inflexible wind
output alone to exceed minimum increase as we continue to see
Minimum demand Minimum demand inc. pumping
demand in summer 2019. reduced demand at the summer
• If however demand levels fall close
minimum (with more distributed
to the level of inflexible generation generation capacity), and fewer
on the system, we can issue a flexible generators running
national or local Negative Reserve overnight and in the afternoon.
Active Power Margin (NRAPM)
notice. This is a request to
encourage more flexible
4
https://www.nationalgrideso.com/sites/eso/files/documents/NRAPM%20Forecasting%20Note.pdfEurope and interconnected markets
Summer
Winter 18
Outlook
2019
>1
Executive
(Electricity)
summary
>2
Our role
>3
Electricity Context Figure 8
Interconnector capacities.
>4 This figure shows interconnector capabilities, not expected flows.
Gas There are 5 interconnectors As renewable generation continues
connecting the GB electricity to grow in both GB and connected
>5 market with the Netherlands, markets, relative prices will be
Glossary
Belgium, France and Ireland. largely influenced by the weather,
The direction electricity flows on which impacts demand and the
these is determined by price, with amount of available renewable
electricity flowing from cheaper generation. Flows of electricity
areas to more expensive areas. may also be impacted by network
constraints, and these will be Moyle (0.5GW)
managed by collaboration between
the ESO and interconnectors.
Ireland
EWIC (0.5GW) Britned (1GW)
Netherlands
NEMO Link
IFA (2GW) (1GW)
Belgium
FranceEurope and interconnected markets
Summer
Winter 19
Outlook
2019
>1
Executive
(Electricity)
summary
>2
Our role
>3
Electricity A development since last summer In addition, the NEMO link Table 2
was the launch of the Integrated interconnector, connecting GB Planned and current interconnector outages, summer 2019
>4
Gas Single Electricity Market (ISEM) and Belgium, successfully went
in Ireland on 1 October 2018. live for commercial service on Interconnector Planned outages Current outages
>5 This integrated the all-island 31 January 2019. (full capacity) (resulting capacity)
Glossary
(Ireland and N Ireland) and
European electricity markets, Interconnectors may undertake France: IFA (2 GW) 01–26 April (1 GW) None
which was expected to help deliver planned outages over the summer, 04–06 June (1 GW)
increased levels of competition or experience fault outages. A table 17–28 June (1 GW)
and lower prices. of current fault outages and planned The Netherlands: 13–17 May (0 GW) None
outages for each interconnector is BritNed (1 GW) 16–20 Sept (0 GW)
listed in table IC-0.
Belgium: Nemo 23 Sep–4 Oct (0 GW) None
(1 GW)
Ireland: EWIC 07–13 May (0 GW) None
(0.5 GW) 21 May (0 GW)
28 May (0 GW)
19–21 Aug (0 GW)
N. Ireland: Moyle 12 – 20 June (0 GW) None
(0.5 GW)*
*Moyle currently has less commercial capacity, subject to TEC values: currently 307 MW for import and
450 MW for export.Spotlight
Summer 20
Outlook
2019
Review of interconnector
flows summer 2018
Key messages
Imports Exports
As anticipated, GB day ahead As expected we also saw
electricity prices remained above net exports of electricity on
prices in connected European interconnectors to Ireland
markets for most of summer 2018, during peak, switching to
leading to net imports on these imports overnight.
interconnectors.Spotlight
Summer 21
Outlook
2019
Review of interconnector
flows summer 2018
Figure 9 shows GB and European On some occasions from Figure 9
Day ahead baseload prices, summer 2018
day ahead electricity baseload September 2018 onwards, Belgian
prices for summer 2018. As can prices peaked at much higher levels 120
be seen here, the GB day ahead than GB (circled) due to outage Belgian prices peaking due
baseload price was consistently extensions on the Belgian nuclear 100
to nuclear outage extensions
higher than connected markets for fleet. Once these were resolved,
most of the summer leading to net Belgian prices dropped back close 80
imports into GB. to previous levels.
£/MWh
60
40
20
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02 03/1
09 04/1
16 04/1
23 04/1
30 04/1
07 04/1
14 05/1
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28 05/1
04 05/1
11 06/1
18 06/1
25 06/1
02 06/1
09 07/1
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23 7/1
30 07/1
06 07/1
13 08/1
20 08/1
27 08/1
03 08/1
10 09/1
17 09/1
24 09/1
01 09/1
08 10/1
15 10/1
22 10/1
29 10/1
05 10/1
1/
/
26
Date
UK summer baseload French summer baseload Dutch summer baseload
Belgian summer baseloadSpotlight
Summer 22
Outlook
2019
Review of interconnector
flows summer 2018
Table 3 shows interconnector flows In the daytime, the picture Table 3
Interconnector flows summer 2018
during the daytime, overnight and at changed for the Moyle and EWIC
peak times (5pm to 8pm) interconnectors that moved to
for summer 2018 (Nemo is not export for more daytime hours. IFA Moyle Britned EWIC
shown as it was not operational). At peak, the distinction between Daytime (7am to 7pm)
All interconnectors were importing continental European and Irish
for most of the overnight periods, interconnectors is again clear, with Import 95.6% 20.7% 88.0% 32.7%
particularly those connected to the former importing power from Floating 0.0% 0.3% 5.5% 13.6%
continental Europe. Europe for almost all peak hours.
Export 4.4% 79.0% 6.5% 53.7%
Total 100.0% 100.0% 100.0% 100.0%
Overnight (7pm to 7am)
Import 97.1% 62.8% 92.5% 71.8%
Floating 0.0% 0.1% 4.1% 12.3%
Export 2.9% 37.1% 3.4% 16.0%
Total 100.0% 100.0% 100.0% 100.0%
Peak hours (5pm to 8pm)
Import 99.4% 19.9% 94.3% 38.9%
Floating 0.0% 0.1% 3.1% 12.7%
Export 0.6% 80.0% 2.6% 48.3%
Total 100.0% 100.0% 100.0% 100.0%Europe and interconnected markets
Summer 23
Outlook
2019
(Summer 2019)
Figure 10 shows that forward prices In previous years, there were
Key messages import. Weather variations will for baseload electricity for summer some periods when IFA exported
also affect flows at all times, 2019 in GB are still higher than the from GB to France driven by
including peak. corresponding prices in the French, lower available French generation
Dutch and Belgian markets. due to nuclear outages. Planned
Therefore we expect to see similar French nuclear outages for this
import/export patterns as last year are lower than previous
2019 summer. NEMO link, as a new
interconnector, is expected to
summers, so are not expected to
significantly affect interconnector
Forward prices for summer 2019
are expected to remain higher Exports behave similarly to Britned as their
market prices and physical
flows. Further detail can be found
in the data workbook.
in GB than continental Europe. We expect GB to export to capabilities are similar.
We therefore expect there to Northern Ireland and Ireland during
be net imports of electricity peak times on the Moyle and Figure 10
on interconnectors from EWIC interconnectors. This may Day ahead baseload prices, summer 2019
continental Europe to GB be reversed to import with high 65
for most of the summer. wind output in Ireland or during 60
periods of system stress. The
availability of coal fired generation 55
in Northern Ireland will also impact 50
flows on the Moyle interconnector.
£/MWh
Imports 45
40
We expect imports into GB at 35
peak times via the IFA, BritNed
and Nemo Link interconnectors 30
although occasionally not at full
18
18
18
18
18
18
18
18
18
19
19
19
19
19
19
19
19
19
19
1/
1/
1/
1/
1/
2/
2/
2/
2/
1/
1/
1/
1/
1/
2/
2/
2/
2/
3/
/1
/1
/1
/1
/1
/1
/1
/1
/1
/0
/0
/0
/0
/0
/0
/0
/0
/0
/0
01
08
15
22
29
06
13
20
27
03
10
17
24
31
07
14
21
28
07
Date
UK summer baseload French summer baseload Dutch summer baseload
Belgian summer baseloadEurope and interconnected markets
Summer 24
Outlook
2019
(Summer 2019)
In addition, only two of the four Forecast flows at peak (5pm to Figure 11 Figure 12
coal-firing units in Northern Ireland 8pm) and overnight (7pm to 7am) Forecast interconnector flows at Forecast interconnector flows
peak 5pm to 8pm, high import scenario overnight, high import scenario
were awarded a 12-month contract are summarised in Figures 11 and
by the Northern Irish SO to support 12, which show flows under a
system stability and security of high import scenario, based on
supply. Should other units close, historic breakdown rates (see data
this may encourage more exports workbook for further detail).
through the Moyle interconnector.
750MW
750MW
1,000MW
1,000MW
1,000MW
1,000MW 1,988MW
1,988MW
Peak times 5pm to 8pm, import from Europe and Overnight, import from Ireland and Europe.
export to Ireland.3
Summer 25
Outlook
2019
Gas
In this section we look at the projected demand
for gas to cater for heating, industry, electricity
generation and export needs. We explore the
supplies of gas we expect to see this summer
and the impact of global markets on both supply
and demand patterns.Gas demand
Summer 26
Outlook
2019
Figure 13
Key messages Forecast gas demand profiles for summer 2019 – seasonal normal weather conditions
350
300
Peaks and troughs
IUK outage relate to weekends
EU export Renewables
250 and public holidays
200
mcm/d
Total gas demand across the Gas demand for GB electricity
network in summer 2019 is generation remains steady 150
expected to be greater than but, due to increased use
in summer 2018 on a weather of renewables and gas/coal 100
corrected basis. This is due price spreads, presents a
to an expected increasing variable profile of consumption. 50
flow of transit gas into Europe
as prices drive greater volumes Another significant impact 0
of LNG to be delivered into on demand uncertainty 1 Apr 1 May 1 Jun 1 Jul 1 Aug 1 Sep
UK terminals. continues to be the effect Exports to Ireland Daily metered
Date
Storage injection IUK/BBL physical exports
of weather on non-daily Electricity generation Non daily metered
metered (NDM) demand.Gas demand
Summer 27
Outlook
2019
Table 4 1. In summer 2019, we expect 3. Gas demand for electricity
Forecast total gas demand for summer 2019 and history for previous summers to see non-daily metered demand generation is expected to be
slightly higher than last year, slightly lower than last summer,
bcm 2014 2015 2016 2017 2018 2018 2019 aligned with seasonal normal as a result of lower overall
actual actual actual actual actual weather forecast
corrected weather conditions. Further electricity demand and increasing
NDM1 9.9 11.3 11.1 10.4 10.6 11.4 10.8 information about NDM demand renewable generation.
DM + 4.4 4.2 4.1 4.4 4.1 4.1 4.3
can be found in the data 4. Overall we expect total exports
Industrial2 workbook. to Ireland over the summer period
Electricity 9.2 8.3 11.6 10.5 10.3 10.3 10.1 2. Daily metered (DM) demand is to be largely the same as last
generation3 expected to decline year on year, year, despite the decline of
GB Total 23.5 23.8 26.8 25.3 24.9 25.7 25.2 mirroring the reduction in energy production from the Corrib field.
Ireland4 2.7 2.8 1.7 1.6 1.6 1.6 1.6 intensive industries and energy 5. With increasing LNG in the global
Export to 3.8 5.0 5.2 7.0 4.5 4.5 7.0 efficiency improvements. market, we expect to see gas
Europe5 However, significant new continuing to be routed to where
Storage 3.6 3.4 2.6 2.5 2.3 2.3 1.9 connections can slow that trend, the price is more attractive in
Injection6 and this year we anticipate a Europe (See page 32).
Total7 33.8 35.2 36.4 36.6 33.3 34.2 36.1 DM demand that is slightly higher 6. Overall storage injection this
than last year. summer is expected to be lower
than last summer as a result of
the warm winter. (see page 29).
7
All totals include NTS shrinkage and will therefore not tally.Europe and interconnected markets
Summer
Winter 28
Outlook
2019
>1
Executive
(Gas)
summary
>2
Our role
>3
Electricity Figure 14
Key messages IUK Export Flows
>4
Gas IUK outage 2019 IUK outage 2016, 17, 18
Our projection for 2019 is an In recent years, IUK has closed 0
>5 increase in exports to Europe for maintenance during June.
Glossary via the IUK interconnector This year, the maintenance window -10
in comparison to last summer. is planned much earlier, in April.
-20
Export flow mcm/day
-30
-40
The GB gas market is connected to Figure 14 shows export flows -50
Belgium by the IUK interconnector, in the last three summers, and
and to the Netherlands via the BBL our projection for 2019 is an -60
interconnector. increase in export to Europe in
comparison to last summer. -70
In recent years, gas has tended to 01 08 15 22 29 06 13 20 27 03 10 17 24 01 08 15 22 29 05 12 19 26 02 09 16 23 30
flow from GB to Belgium for most of This is the first year that IUK has April May June July August September
the summer and from Belgium to not had all its flows covered by long 2015/16 2016/17 2017/18
Date
2018/19 predictions
GB during the winter months term contracts. All of the existing
through IUK. This trend is largely contracts expired at the end of Also this year, the BBL pipeline, Currently there is no firm exit
driven by price differentials between September 2018. Currently about between Bacton in the UK and baseline capacity however, as
GB and European markets, so 55% of export capacity is covered Balgzand in the Netherlands, has with any other site, non-obligated
occasional days of import to GB by contract. Going forwards, indicated that it will make gas firm capacity could be made
might be expected during the contracts are likely to be booked transportation possible in both available by National Grid in addition
summer if prices dictate. It is on a much shorter term basis. directions from the summer of 2019. to interruptible.
increasingly influenced by the
availability of LNG being delivered
to UK terminals.Gas storage
Summer 29
Outlook
2019
Figure 15
Key messages Increasing trend of day to day cycling
2,500
Injection and withdrawal both increasing
2,000
Injection and withdrawal (mcm)
Storage Outage
1,500
1,000
Overall storage injection over We anticipate that significant 500
summer 2019 is likely to be lower storage injection is likely 0
than last year. This is because during the 2 weeks that the IUK 2014 2015 2016 2017 2018
of the relatively high level of interconnector is on outage. This -500
medium-range storage (MRS) outage is taking place earlier than -1,000
stock at the end of winter 2019, usual in the summer, and hence
due to a milder winter. we expect to have higher stock -1,500
levels than are typical during the -2,000
We expect continued day-to- early summer months.
day cycling into and out of Withdrawal Injection Lower withdrawal immediately following
very cold weather spell in March 2018
(MRS) in summer 2019.
With the closure of Rough as a We have seen an increasing trend
seasonal facility and its subsequent of these sites being used for day-
reclassification as a production to-day cycling, as shippers take
field; the remaining storage in advantage of gas price swings
GB is medium-range storage over shorter timescales. You can
(MRS). This has increased in total see the increasing trend in Figure 15
volume over recent years. Storage behaviour can differ
significantly across different years
as a result of this price driven trend.Summer
Outlook
2019 Gas storage 30
Figure 16 MRS starts to fill when IUK shuts Total injection over the summer
MRS stock levels down for maintenance. There is typically has a dependency on the
no export route for the supplied level of MRS at the end of winter.
1,600
gas, so it goes into storage. The IUK MRS stocks are currently higher
1,400 outage is in April this year (earlier than last summer as a result of
Sharp increase in stock than usual) and we expect that the mild winter (see Figure 16)
1,200 during IUK outage significant storage injection is likely
during those two weeks of outage.
MRS stock level/mcm
1,000 We therefore expect to have higher
800
stock levels than are typical during
the early summer months.
600
Stock levels at the start of
400 summer depend upon how
depleted they are at the end of
the winter (e.g. low stock levels
200 following very cold weather
spell in March 2018)
0
01 Oct 01 Nov 01 Dec 01 Jan 01 Feb 01 Mar 01 Apr 01 May 01 Jun 01 Jul 01 Aug 01 Sep 01 Oct
Date
2015/16 2016/17 2017/18 2018/19 ProjectionGas supply
Summer 31
Outlook
2019
1. The UKCS continues to be the 4. LNG deliveries are sensitive to
Key messages most significant supply of gas the world market and production
to the UK. We are expecting capacity has grown rapidly in
aggregate supply in summer 2019 recent years. They offer a more
to be similar to summer 2018. flexible response to increasingly
volatile supply and demand
2. Norway supplies gas through patterns than offshore production.
We expect that there will be We anticipate increased levels pipelines to Germany, Belgium We continue to see this additional
sufficient gas to meet demand of LNG in comparison to last and France as well as to GB. LNG supply being transported to
in summer 2019. summer, and excess supply being Norway production has been high Europe via the interconnector, in
exported to Europe in response to over the winter and is expected response to price trends. However,
Supplies from the UK continental gas prices in both GB and global to remain so. However due to the the locational diversity of LNG
shelf (UKCS) and Norway continue gas markets. expected increase in LNG supply supply is changing the way we
to be the dominant components. we believe it is unlikely that we operate our networks.
will see flows that are as high as
seen in the past few years. 5. Overall storage injection over
summer 2019 is likely to be lower
3. Our projection for 2019 is an than last year. This is because
Table 5 increase in exports to Europe of the relatively high level of MRS
Forecast and historic gas supply by source via the IUK interconnector in stock at the end of winter 2019,
comparison to last summer. due to a mild winter.
bcm 2014 2015 2016 2017 2018 2019
actual actual actual actual actual forecast
UKCS1 15.1 15.9 16.2 17.4 16.8 16.8
Norway2 7.4 11.3 12.4 13.1 13.3 12.4
Continent3 2.2 0.3 0.5 0.1 0.1 0.1
LNG4 7.5 6.2 5.3 3.2 1.4 5.3
Storage5 1.3 1.1 1.2 1.9 1.3 1.4
Total 33.4 34.8 35.6 35.7 32.8 36.1Liquefied natural gas (LNG)
Summer 32
Outlook
2019
Figure 17
Key messages LNG monthly send-out In early winter 2018 we have seen
a marked change from this pattern,
with supply heading towards levels
not reached since 2012.
We expect that LNG deliveries 1,800
this summer will be substantially 1,600
higher than last summer, but will
not match the high rates seen in 1,400
winter 2018.
1,200
Sendout mcm
Last summer the flows at LNG terminals
1,000 were at times down to minimum levels
LNG deliveries to NW Europe were LNG shipping costs rose sharply 800
higher during last winter than for during the winter, making Europe 600
many years. New liquefaction a more profitable market than
capacity has come on line in many Asian markets for cargoes from 400
producing regions, and total the US and from Yamal in NW 200
production capacity has grown Russia. The combined effect of
faster than global LNG demand. this has been that cargoes have 0
been delivered to GB, to all three
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
terminals. As a result, we expect 2016 2017 2018 2019
much higher LNG deliveries this Grain Dragon South Hook
summer compared to last year.Liquefied natural gas (LNG)
Summer 33
Outlook
2019
Figure 18 Figure 18 shows the increasing
LNG delivery cargoes variety of source and scale of
1,800 vessel delivery.
1,600
1,400
Monthly LNG delivery mcm
1,200
1,000
800
600
400
200
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb
2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2018 2019 2019
Date
US Trinidad Russia Qatar Peru Norway Nigeria Equatorial Guinea
Egypt Cameroon Algeria
This chart has been developed by National Grid using confidential proprietary data from the Argus
Media Group under licence. Argus shall not be liable for any loss or damage arising from any party’s
reliance on this data.Spotlight
Summer 34
Outlook
2019
Transit gas
We continue to experience gas Sale of forward flow capacity in IUK Figure 19
being delivered to GB and supplies is dependent on expected demand Increasing trend of day to day cycling
that are in excess of combined in Europe, and transit gas could
350
demand for GB and Ireland are then increase into the future, as a result
transported through our networks of increased fuel switching in Europe IUK Closed for
maintenance
Transit gas is the gas
supplied to GB that is above
300
for onward export into Europe. from coal to gas. the level of total GB demand,
and transported to Europe
This is known as transit gas. 250
via the interconnector
For almost the entire summer of
Gas flow mcm/day
Although gas demand is lower 2018, more gas was being supplied 200
during the summer months, total than was actually needed to satisfy
demand is only approximately combined GB demand and Irish 150
25% lower than in winter. As a exports (shown by the dark blue
result we see export flows via the line on Figure 19).
IUK interconnector offsetting the
100
reduction in GB and Ireland gas The surplus of supply was 50
demand. We are also currently exported to Europe. From early-
anticipating LNG deliveries that June through to mid-September, 0
are substantially greater in summer supplies from UKCS and Norway 1 Apr 2018 1 May 2018 1 Jun 2018 1 Jul 2018 1 Aug 2018 1 Sep 2018
2019 than last year, as discussed. alone were greater than the Date
demand. Norwegian gas was UKCS Norway LNG Storage Interconnectors GB demand and Irish exports
The effect on our network is that the using GB for onward transit to the
historical pattern of transporting the rest of Europe. The only time that
majority of gas North to South no supply and demand were aligned
longer exists. Supply patterns are was in June when IUK was closed
more evenly distributed around the for annual maintenance.
country, and on occasions we have
to reverse the flow, moving gas from
South to North.4
Summer 35
Outlook
2019
Operational outlook
In our role as System Operator, we need to
manage a number of operability issues on the
gas and electricity transmission networks over
the summer. This section outlines some of these
issues, and the tools and services available to
use to make sure we can operate the electricity
and gas systems securely and effectively.Operational outlook
Summer 36
Outlook
2019
(Gas)
Having timely and accurate physical System pressures are tending to
Key messages notifications from CCGTs helps us become higher in the summer, than
to identify and manage the risk of previously experienced, as a result
variability across the network. of increasing levels of transit gas.
Overall supply patterns become As a result we must place greater
less predictable when larger Increasing levels of LNG supply focus on enabling safe access for
volumes of LNG are delivered will impact patterns of gas flow the summer maintenance schedule.
The volume of maintenance to GB terminals. across GB, potentially reducing
remains high, but there are the traditional north to south flow, We continue to engage closely with
no major risks to NTS access. We must be prepared for and resulting in non-standard the industry to ensure that outages
non-standard and short notice configuration of the network. are coordinated and we will always
The variability of gas fired re-configuration of the network. aim to facilitate maintenance on the
electricity generation has an With LNG supplies being relatively network with minimal disruption to
impact on the management We are reliant on timely and closer to areas of demand, we our customers.
of system pressures. accurate demand nominations. could continue to see a reduction
in compressor usage for bulk You can find more details on our
gas transmission, but we must be website. The final Maintenance Plan6
During the winter months, the Gas for electricity generation prepared for the possibility that LNG is published at the end of March.
most dominant driver for gas also has an element of weather supply falls away, which can happen
demand is the need to provide sensitivity as it responds to the in summer due to price sensitivity. Improving Access to Data
heat. This dynamic changes in the varying levels of generation from In response to a number of recent
summer months as temperatures renewables. When clusters of This rapidly changing dynamic of industry engagements, National
increase. Instead the most Combined Cycle Gas Turbine the network means that we must Grid has mobilised a programme
significant driver for gas becomes (CCGT) generators exist in a be prepared to use compression of work to identify and deliver
gas fired electricity generation. particular region, this variability at relatively short notice to maintain enhancements to the operational
can have an increasing impact system locational pressures. data currently provided to the
on regional pressure management. industry through its website. For
Our thoughts on the longer term more information please refer to
https://www.nationalgridgas.com/insight-and-innovation/gas-future-operability-planning-gfop
impacts of this are now being our Operational Data User Guide7.
5
6
https://www.nationalgridgas.com/data-and-operations/maintenance
7
https://www.nationalgridgas.com/sites/gas/files/documents/Operational%20Data%20User%20Guide%20-%20 shared in the Gas Future
Version%201.pdf Operability Planning5 document.Operational outlook
Summer 37
Outlook
2019
(Electricity)
In order to balance supply and change of frequency (RoCoF)
Key messages demand, the ESO can take various and vector shift (see next slide)
additional day-to-day actions, as • manage reactive power in
described in the electricity supply different regions, to keep voltage
section. In addition, a number of levels stable. In periods of low
specific tools can be used when demand, this is likely to be actions
system conditions are challenging. to reduce the amount of reactive
The key factors that cause Both of these factors are impacted power on the system. These
operational challenges for the by the weather, so it can be In the summer of 2019 the ESO could include:
electricity transmission system difficult to forecast in advance may need to: – setting up contracts in advance
during the summer are: what services will be needed. • use footroom services in periods with appropriate generators.
• low transmission system We will use a number of tools of low demand to ensure that These would ensure minimum
demand (making it difficult to to manage these challenges. there is enough negative reserve profitability so that these
balance demand and supply, on the system generators keep generating
and affecting reactive power • take actions to manage local
(and providing reactive power
and hence voltage levels) network constraints. The Western capability) in periods where
• high proportions of low inertia High Voltage Direct Current they might otherwise have
generation (making it more (HVDC) link will help to relieve been uneconomic
difficult to manage system congestion on the transmission – undertaking trading actions
frequency). network between Scotland within day, or taking bid / offer
and England acceptances via the Balancing
• issue a local or national Negative
Mechanism so that generators
Reserve Active Power Margin provide reactive power capability.
(NRAPM) notice if demand levels
fall close to the level of inflexible We have also tendered for the
generation on the system (further provision of Reactive Power
described in the electricity supply Services for summer 2019 in the
section) You can read more South Wales and Mersey regions,
about NRPAMs on our website8 and for Enhanced Reactive Power
• use tools to manage the rate of services in Scotland for 2019/20.
8
https://www.nationalgrideso.com/sites/eso/files/documents/NRAPM%20Forecasting%20Note.pdfSpotlight
Summer 38
Outlook
2019
Update on loss of mains protection
settings for smaller generators
All generators have loss of mains balancing actions are having to The Distribution Code modifications If you own or operate generation
protection systems, designed to be taken on the transmission under DC0079 to change the loss which is a) connected to the
shut the generator down if there system to manage both RoCoF of mains protection settings at all distribution network, and b) uses
is an issue on the network they are and vector shift. generators greater than 5 MW and vector shift or RoCoF setting
connected to. Traditionally, these any new generators below 5 MW below 1 Hz/second for the loss
systems would monitor conditions Industry work is underway to have already been implemented. of mains protection, you may
on the electricity network such as systematically address the issues The next phase of DC0079 is to be able to receive a payment.
the rate of change of frequency in this area. Last summer, NG ESO, ensure the loss of mains settings This would support changing
(RoCoF) or vector shift events, UK Power Networks, SSE and at existing generators with the protection ahead of the
to understand if there was a Western Power Distribution jointly capacities below 5 MW, or any compliance deadline. Look
network issue. carried out an accelerated vector generators which use vector shift out for more information from
shift change programme. This protection, move to more suitable the ESO and your distribution
As system conditions have evolved ensured that generators in the relay settings as will be mandated network owner over spring 2019.
to accommodate an increase in most high risk areas changed their by the Distribution Code. Pending
renewable generation and closure protection settings away from vector approval from Ofgem, the
of conventional generation, these shift. As a result, the risk of a large implementation of this retrospective
historic loss of mains protection number of generators shutting down change will start this year.
techniques, such as RoCoF and following a vector shift event has
vector shift, have become less been reduced to within manageable As the volume of generation
suitable. There is a risk therefore limits. Remaining changes to both which has moved to these new
that generators shut down when vector shift and RoCoF relays will protection settings increases,
they don’t need to, and several take place as part of the wider the need to manage RoCoF and
generators shutting down at change programme. vector shift using operational tools
once can in itself cause network will be relaxed.
problems, such as a sudden fall
in system frequency. As a result,You can also read
