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Summer Outlook Report 2018 APRIL 2018
Summer Outlook Report 2018 01
How to use this interactive document
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and easily we have published the Summer Outlook
Report as an interactive document.
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backwards or forwards a page. on them to access further information.Summer Outlook Report 2018 02
Welcome to the 2018 Summer Outlook Report.
The report draws together analysis and feedback
from across the industry to present a view of supply
and demand for the summer ahead.
We had a great response to our • Winter Review and Consultation
recent readership survey and – explores the actual energy
I’d like to thank you for taking demand and supply patterns
the time to share your views. and how they compare with our
forecasts. This year it will include
Acting on your feedback we have: an analysis of the recent cold
• strengthened the information weather spell on both the gas
we have included on the and electricity systems. We’ll
markets we are connected to be publishing this in early June.
• provided more commentary
and background on the factors In them you can find out more
affecting these markets about the evolution of the energy
• provided more in-depth landscape, and how we’re
analysis of the recent changes working with our stakeholders
to the electricity generation to build and operate the gas and
capacity profiles of a number electricity systems of the future.
of major European countries Thank you for taking the time to read
• concentrated on the impact of this year’s Summer Outlook Report.
transit gas and the changing
profile of LNG supplies to GB. To find out more, and register
for email updates, go to our
The Summer Outlook Report is website. We want to make sure
just one in a suite of documents our publications are as useful
from the System Operator to you as possible, so please let
exploring the future of energy. us know what you think. You can
I encourage you to read our email your feedback to us at
other publications including: marketoutlook@nationalgrid.com,
• Response and Reserve Roadmap join the debate on Twitter
– explores the complexity of using #FutureofEnergy
balancing supply and demand
in a changing energy landscape Fintan Slye
• Future Energy Scenarios – will Director UK System Operator
explore the longer term trends
in the industry and how that
may impact the energy mix
from today to 2050. Look out
for the FES 2018, which we’ll
be publishing on 12 July 2018.Summer Outlook Report 2018 03
Contents
Executive summary.................................................04
National Grid’s role..................................................06 Chapter two
Accessing further information.............................07
Gas..............................................................................51
Chapter one Gas demand..............................................................52
Gas supply.................................................................59
Europe and interconnected markets..................62
Electricity................................................................... 11 Gas operational outlook.........................................65
Electricity demand..................................................12
Operational view including
generation/supply...................................................24 Chapter three
Europe and interconnected markets..................37
Electricity operational outlook.............................47
Appendix....................................................................70
Glossary.....................................................................76Summer Outlook Report 2018 04 Executive summary 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. Overview: Electricity summer 2018 Both peak and minimum transmission the daytime demands we see on the system demands this summer are expected transmission system are supressed by to be lower than the 2017 weather corrected it, which can make forecasting difficult. outturn. Minimum transmission system Solar PV and wind generation connected demand is expected to be 17 GW, this to the distribution networks have increased equates to 21.1 GW of underlying demand, to 12.9 GW and 5.7 GW respectively. only marginally lower than last summer’s Increased supply and demand variability minimum. Peak transmission system caused by these periods of low demand demand is anticipated to be 33.7 GW and high levels of renewable generation between the high summer months of June can create operability challenges. As a to August. We expect there to be sufficient result, we may need to take more actions generation and interconnector imports to curtail generation and possibly instruct to meet demand throughout the summer inflexible generators to reduce their output period. in order to balance the system. The increase in distribution connected In our operational outlook chapter we generation, for example wind and solar explore these challenges and we continue PV, has contributed to this downward to work with industry participants trend in demands. Solar PV continues to develop the tools and services needed to impact the daily demand profile because to manage them.
Summer Outlook Report 2018 05
Executive summary
Overview: Gas summer 2018
Gas from the UK and Norwegian Continental In the gas demand chapter, we explore
Shelf, or ‘beach’ gas, is expected to be the how much of an impact the effect of weather
dominant component of gas supplies into has on gas demand. The difference between
GB this summer. We anticipate that gas a day with high wind and solar generation
from the more flexible, ‘non-beach’ supplies, and a day with low wind and solar generation
particularly interconnector imports and can amount to 20 per cent of demand on
LNG will remain low. However, base a summer’s day. The change in demand
LNG volumes are expected to be higher patterns can introduce significantly more
than we have seen during winter periods. within day and day to day changes in
Our analysis informs us that the total gas flows on the gas transmission system, and
supply will be in excess of what is required reinforces the need for a more agile network.
to meet GB demand. As a result, we expect
to see GB sourced gas to be routed to This summer we expect to see one of the
where the gas price is more attractive. highest volumes of maintenance on the gas
Therefore we anticipate transit gas demand transmission system to date. Summer can
on the network during the summer period. be a challenging time to manage supply
and demand variability as well as providing
The increase in renewable electricity access to the network even though GB
generation not only has an impact demand is lower.
on the operability of the electricity
system, it also affects demand on We continue to work closely with our
the gas system. Lower overall electricity customers to minimise the impact of
demand, along with increased renewable maintenance during this busy period.
generation, means there is less of a As we continue to see our customers
requirement for gas fired electricity using the network in different ways, we
generation. As a result, we expect will continue to develop the operational
overall gas demand to be 35.7 bcm tools to manage the within day variations
this year, slightly lower compared of supply and demand on the network.
to summer 2017.Summer Outlook Report 2018 06
National Grid’s role
National Grid plays a vital role in connecting On the gas side, we own and operate the
millions of people to the energy they use, high pressure gas transmission network for
safely, reliably and efficiently. the whole of Great Britain. We are responsible
for managing the flow of gas to our connected
We own and manage the high voltage customers and businesses; working with other
electricity transmission network in England companies to make sure that gas is available
and Wales. We are also the System Operator where and when it is needed.
of the high voltage electricity transmission
network for the whole of Great Britain, We do not own the gas we transport and
balancing the flows of electricity to homes neither do we sell it to consumers. That is
and businesses in real time. the responsibility of the energy suppliers
and shippers.
We don’t generate electricity and we don’t
sell it to consumers. It is the role of energy Together, these networks connect people
suppliers to buy enough electricity to meet to the energy they use.
their customer’s needs from the power
stations and other electricity producers.
Once that electricity enters our network,
our job is to plan and operate the system
to make sure supply and demand are
balanced on a second-by-second basis.Summer Outlook Report 2018 07
Accessing further information
The Summer Outlook Report is just one of the together some of the other ways you can stay
ways we provide information to and engage up-to-date throughout the year.
with the industry. In this chapter, we’ve brought
Key publications from the System Operator
System Operator publications The For gas, these issues are considered in
Summer Outlook Report is just one of the the Gas Ten Year Statement and Future
documents within our System Operator Operability Planning publications. We share
suite of publications on the future of energy. aspects of our analysis with the industry
Each of these documents aims to inform the during the development of these documents
energy debate and is shaped by engagement to make sure that the proposed solutions
with the industry. meet the needs of our stakeholders.
The starting point for our analysis is the You can find out more about any of these
Future Energy Scenarios (FES). This document publications, and how they incorporate insight
considers the potential changes to the demand from our stakeholders, by clicking on the
and supply of energy from today out to 2050. document front covers on the next page
or by visiting our Future of Energy webpage.
The network and operability changes
that might be required to operate the
electricity system in the future are explored
in the Electricity Ten Year Statement,
System Operability Framework and
Network Options Assessment.Summer Outlook Report 2018 08
Figure 0.1
Key publications from the System Operator 2017/18
Network Options Winter Winter Outlook
Assessment Report
Outlook
Report
2015/16
January 2018 October 2018
The options available to meet Our view of the gas and
reinforcement requirements electricity systems for the
on the electricity system. winter ahead.
Summer Electricity Ten
Network Options Assessment 2015
Outlook Report Year Statement
Electricity Ten Year
Statement 2015
UK gas electricity transmission
April 2018 November 2018
Our view of the gas and The likely future
electricity systems for the transmission requirements
summer ahead. National Grid plc
National Grid House,
Warwick Technology Park,
Gallows Hill, Warwick.
CV34 6DA United Kingdom
Registered in England and Wales
No. 4031152
on the electricity system.
www.nationalgrid.com
System Needs and Gas Ten Year
Gas Ten Year Statement 2015
Product Strategy Statement
Gas Ten Year
Statement 2015
UK gas transmission
April 2018 November 2018
Our view of future electricity How we will plan and
system needs and potential operate the gas network,
improvements to balancing
National Grid plc
National Grid House,
Warwick Technology Park, with a ten-year view.
services markets.
Gallows Hill, Warwick.
CV34 6DA United Kingdom
Registered in England and Wales
No. 4031152
www.nationalgrid.com
Winter Review Future Operability
Future Operability Planning 2016
and Consultation Planning
Future Operability
Planning 2016
UK gas transmission
June 2018 November/December
A review of last winter’s How the changing
forecasts versus actuals and energy landscape will
an opportunity to share your
National Grid plc
National Grid House,
Warwick Technology Park, impact the operability
views on the winter ahead. of the gas system.
Gallows Hill, Warwick.
CV34 6DA United Kingdom
Registered in England and Wales
No. 4031152
www.nationalgrid.com
Future Energy System Operability
Future Energy Scenarios
SystemOperability Framework 2015
Scenarios Framework
Future Energy System Operability
Scenarios Framework 2015
UK gas and electricity transmission UK electricity transmission
July 2018
How the changing
A range of plausible and energy landscape will
credible pathways for the impact the operability
nal Grid plc
nal Grid House,
ck Technology Park,
future of energy from today
National Grid plc
National Grid House,
Warwick Technology Park, of the electricity system.
out to 2050.
ws Hill, Warwick. Gallows Hill, Warwick.
6DA United Kingdom CV34 6DA United Kingdom
tered in England and Wales Registered in England and Wales
031152 No. 4031152
nationalgrid.com www.nationalgrid.comSummer Outlook Report 2018 09
Accessing further information
Latest operational information
The information provided in our Outlook Gas
reports is based on the best data currently To support market participants and other
available to us. This outlook will change as interested parties, we publish a range of
we progress through the summer. There are data on the operation of the gas transmission
a number of sources of information you can network. The Market Information Provision
access for the most up-to-date view, both Initiative (MIPI) publishes information required
for electricity and gas. under UNC and EU obligations, as well as
additional information we feel is useful for
Electricity the market.
Much of our electricity analysis is based on
generation availability data provided to us by
generators. This is known as Operational Code
2 (OC2) data. As generators update their plans
each week, the picture of supply and demand
will change. You can access the latest OC2
data, which is published each Friday, on the
BM Reports website.
Our demand forecasts are regularly updated
throughout the year. The demands published
in this report are based on forecasts from
March 2018. For the most up-to-date information,
we encourage the industry to view our latest
forecasts on the BM Reports website.
The System Operator Notification Reporting
system (SONAR) provides real time operational
information for market participants and
members of the public. The system informs the
market about certain changes that generators
have made to their operational parameters, or
instructions the Control Room may have issued
to start up power stations. You can view these
notifications and sign up for email alerts via the
SONAR website.Summer Outlook Report 2018 10 Events We host industry events throughout the year to changes. You can find out more about discuss the operation of the gas and electricity our gas and electricity operational forums systems, and debate important industry on our website. Please tell us what you think We want to make sure that we continue publication. You can share your feedback by to provide you with the right information to emailing us at marketoutlook@nationalgrid.com. support your business planning. To do this, we’d like to know what you think about this
Summer Outlook Report 2018 11
Chapter
Chapter one
one
Electricity demand 12
Operational view including generation/supply 24
Europe and interconnected markets 37
Electricity operational outlook 47Summer Outlook Report 2018 12
Electricity
Chapter one
Summer demand
This section presents our current view of demand for summer
2018. All demand figures in this chapter are transmission system
demands. These demands are based on national demand plus
a station load of 500 MW. Further information on the demand
assumptions can be found at the end of this chapter.
Key messages
• Overall transmission demands will • Daytime minimum demand is estimated
be lower than 2017. to be 1.1 GW lower than 2017 at 20.1 GW.
• Distribution connected generation • Minimum summer demand is expected
will continue to grow. to be 0.6 GW lower than 2017 at 17 GW.
• Peak demand for the high summer
period is expected to be 33.7 GW.Summer Outlook Report 2018 13
Chapter one
Key terms
• Distribution connected generation: • Underlying demand: demand varies
any generation that is connected to the from day-to-day, depending on the weather
local distribution network, rather than to and the day of week. Underlying demand
the transmission network. It also includes is a measure of how much demand there
combined heat and power schemes of any is once the effects of the weather and the
scale. Generation that is connected to the day of the week have been removed.
distribution system is not directly visible to • Weather corrected demand: is the
National Grid and therefore acts to reduce demand seen on the transmission
demand on the transmission system. system, with the effect of the actual
You can access our latest daily distribution weather removed and the impact of
connected generation forecasts up to normal weather added.
7 days ahead on our website. • Network Innovation Allowance (NIA):
• High summer period: the period is a set allowance each RIIO network
between 1 June and 31 August, or weeks licensee receives as part of their price
23 to 35. It is when we expect the greatest control allowance. Its aim is to fund
number of planned generator outages. projects directly related to the Licensees
At the same time, this is when we network that have the potential to deliver
normally experience higher demand, financial benefits.
predominantly driven by the increased • Normalised demand: is the forecasted
use of cooling systems. demand using long term trends to estimate
• Transmission system demand (TSD): underlying demand with a 30 year average
demand that National Grid, as the (on a weekly resolution) for the weather
System Operator, sees at grid supply component added.
points, which are the connections to the
distribution networks. It includes demand
from the power stations generating
electricity (the station load) at 500 MW.Summer Outlook Report 2018 14
Electricity
Chapter one
Overview
The key characteristics of the summer period demand on record (actual demand based
is low demands and variability day to day. on actual weather including station load).
Periods of low demand have an impact In figure 1.1, we see that out of the 10 lowest
on how we operate the transmission system. system demands, seven occurred in 2017
As a result, it is important that we understand alone. This downward trend in demand
the minimum levels of demand along with is largely due to an increase in distribution
the peak demand that we can expect to see connected generation (both renewables
during the summer months. During summer and non-weather generations) connected
2017, we saw the second lowest system to the distribution networks.
Figure 1.1
Ten lowest demands
17.8
17.6
17.4
Demand GW
17.2
17.0
16.8
16.6
16.4
07/08 11/06 08/08 02/02 12/06 25/06 21/08 28/05 02/10 11/09
2016 2017 2016 2017 2017 2017 2016 2017 2017 2017
Date
System demandSummer Outlook Report 2018 15
Chapter one
Summer system demand
Our analysis suggests transmission demands network. Because it is connected to the
for the coming summer are likely to be lower distribution system and is therefore not
than last year’s weather corrected outturn. directly visible to us, it acts to reduce
This is mainly because of the increase demand on the transmission system.
in distributed energy sources combined Table 1.1 illustrates the gradual reduction
with an anticipated drop in the underlying in demands year on year along with our
demand. Distributed energy sources refer to forecast demands for summer 2018.
the generation connected to the distribution
Table 1.1
Weather corrected summer system demands for the last 3 years and the forecast for 2018
Year Summer minimum Day time minimum High summer peak
(GW) (GW) (GW)
2015 18.4 25.8 37.5
2016 17.8 22.7 36.3
2017 17.6 21.2 34.4
2018 (forecast) 17.0 20.1 33.7Summer Outlook Report 2018 16
Electricity
Chapter one
Weekly peak demand
Figure 1.2 shows the weather corrected This is 700 MW lower than last year’s weather
weekly peak demand for summer 2017, corrected outturn as a result of the increase
along with our forecast for 2018. Our in distributed generation and a reduction in
peak demand forecast for the high underlying demand.
summer period (between June and
the end of August) is 33.7 GW.
Figure 1.2
Weekly peak demand outturn for 2017 against our 2018 forecast
45
44
43
42
41
40
Demand GW
39
38
37
36
35
34
33
32
31
30
13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43
Week number
Peak summer period Forecast peak 2018 Peak 2017Summer Outlook Report 2018 17
Chapter one
Summer minimum demands
In order to support the operation of the transmission system because the availability
system during the summer months, it is of flexible plant during these periods is
important to consider both the summer reduced. The daytime summer minimum
minimum demand and the daytime summer demand for 2018 is expected to be
minimum demands. Historically, the lowest approximately 20.1 GW, 1.1 GW lower
demand occurred overnight; however, with than last year’s weather-corrected outturn.
the growth in renewable generation, wind
and solar PV, the lowest demand can now The summer minimum demand for 2018
occur during the day. Minimum demands is also forecast to be 17 GW, 0.6 GW lower
are becoming increasingly more significant than last year’s weather corrected outturn.
when balancing supply and demand on the
Figure 1.3
Weekly minimum demand outturns for 2017 and our forecast for 2018
30
29
28
27
26
25
Demand GW
24
23
22
21
20
19 20.1 20.2
18
17
16 17.1 17.0 17.1
15
13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43
Week number
Peak summer period
Weekly daytime summer minimum 2018 Weekly day time summer minimum 2017
Weekly summer minimum 2018 Weekly summer minimum 2017
In accordance with Grid Code, we publish in February 2018. For the latest forecasts,
our most recent forecasts on the BM reports please visit our BM reports website.
website1. Demands published in this report
are based on demand forecasts conducted
1
https://www2.bmreports.com/bmrs/?q=demand/2-52-weekaheadSummer Outlook Report 2018 18
Electricity
Chapter one
Daytime minimum demand 9 April, whilst the PV outturn had dropped
to 7.5 GW compared to the previous day,
In summer 2017, we experienced something
wind had increased to 1.9 GW, giving a
we hadn’t experienced before on the
total of 9.4 GW of distribution connected
electricity transmission system; we saw
generation. Accurate forecasts on the
the day time minimum demand fall lower
day meant the Control Room were well
than the overnight minimum.
equipped ahead of time to manage both
periods of low demand.
This happened on two occasions, on the
08 and 09 April and was caused by very
We see in figure 1.4 the effect that
high distribution connected generation.
distribution connected generation had
solar PV and wind output, coupled with
on the transmission demand for both
high temperatures during the day reduced
dates. We are likely to see this repeated
the demand on the transmission system.
if we get high PV days with wind and
high temperatures.
PV generation for the 08 April was 8 GW
and wind was approximately 900 MW,
giving a total of 8.9 GW. Similarly, on the
Figure 1.4
Daytime minimum demand vs overnight demand
36.0
34.0
32.0
30.0 08/04/17
Demand GW
28.0 09/04/17
26.0
24.0
22.0 23.1GW
22.5GW
20.0 21.0GW 20.8GW
18.0
00:30 04:30 08:30 12:30 16:30 20:30 00:30 04:30 08:30 12:30 16:30 20:30
Time
System demand Solar PV Wind Night level Daytime levelSummer Outlook Report 2018 19
Chapter one
Daily demand profile
In the daily half hourly demand profile in generation. The purple bars represent
figure 1.5, demand ranges from a minimum when solar begins to generate and/or
of 16.5 GW and a maximum peak of 35.4 GW when generation begins to reduce.
(please note this excludes the 500 MW station The red bars represent the times when
load). The orange bars represent the times there is no solar generation.
when there is the highest amount of solar
Figure 1.5
Daily half hourly demand profile from the high summer period 2017
40
35
Demand GW
30
25
20
15
0:30 2:30 4:30 6:30 8:30 10:30 12:30 14:30 16:30 18:30 20:30 22:30
Time
Demand range Average demand Overnight Sunset/sunrise Daytime
Figure 1.5 suggests the daily minimum During the summer months, demand profiles
demand is likely to occur between 5am and can change from day to day depending on
6am. Demand then increases until 8am, the levels of renewable generation on the
where it remains relatively flat until 4pm and system, in particular, solar PV. Variability
then begins to pick up for the evening peak. on the system has increased as the amount
Daily peak demand is largely influenced by the of renewable generation has grown which
amount of solar radiation, for example, if it is ultimately creates challenges when managing
a bright and sunny day, the peak demand is system operability. Maximum solar generation
likely to occur either in the morning between output usually coincides with the demand
8am and 9am, or after sunset. The daytime reduction after lunchtime.
demands between 9am and sunset are
suppressed by distribution connected
solar generation.Summer Outlook Report 2018 20
Electricity
Chapter one
Summer peak demand
Figure 1.6
Estimated summer peak demand timings
44
42
Peak demand GW
40
38
36
34
32
30
13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43
Week number
Peak after sunset Peak before 9am
Figure 1.6 shows our estimated timings for generation. The daily peak demand
the peak demand based on seasonal normal is significantly impacted by the amount
weather. Our analysis suggests daily summer of solar PV generation.
peak demand is likely to occur between
8am and 9am during weeks 23 to 30 due
to late sunset times and the amount of solarSummer Outlook Report 2018 21
Chapter one
Distribution connected solar generation
Figure 1.7
Historic and forecast PV capacity and daily maximum output
16,000
14,000
Solar capacity/output (MW)
12,000
10,000
8,000
6,000
4,000
2,000
0
Mar Sep Mar Sep Mar Sep Mar Sep Mar Sep Mar Sep Feb Aug Feb
2012 2012 2013 2013 2014 2014 2015 2015 2016 2016 2017 2017 2018 2018 2019
Month
Smoothed solar capacity Daily max solar output Forecast solar capacity
Daily max solar forecast
Figure 1.7 shows historic solar PV capacity Distribution connected solar capacity had
growth and daily maximum generation output. increased to 12.9 GW by February 2018.
It also includes our year ahead (March 2018
to February 2019) forecast for both installed
capacity and maximum daily output.Summer Outlook Report 2018 22
Electricity
Chapter one
Assumptions
All demand figures in this chapter are 2. Distribution connected solar PV capacity
transmission system demands. These in February 2018 was 12.9 GW. Currently
demands are based on national demand our 2-52 weeks ahead forecast assumes a
plus a station load of 500 MW. 110 MW increase in the capacity per month.
Our long range forecast models assumes
1. Underlying demand is corrected for around 14.7 GW of solar capacity by the
the impact of weather and day of week. end of March 2019.
This is likely to be 500 MW lower in 2018
compared with summer 2017. Our 500 MW 3. Distribution connected wind capacity
assumption is based on the analysis of has increased from 4.8 GW in 2017
the underlying demand levels over the to 5.7 GW, and we anticipate it will
last 12 months. be broadly flat this summer.Summer Outlook Report 2018 23
Chapter one
Spotlight:
Forecasting solar generation and
Network Innovation Allowance (NIA) projects
National Grid is involved in a number of solar PV forecasts. All solar power forecasts
projects with external partners to improve rely on an accurate prediction of the weather,
the monitoring and forecasting of solar in this case solar radiance; this has proven
PV generation. to be a dominant source of PV forecasting
error. Our NIA partnership with the Met
Because all solar is connected to the Office has led to a new post-processing
distribution networks, historically National technique, which had an immediate
Grid, as the System Operator, has no visibility impact during summer 2017 and we expect
of live metering from solar generation. to see further improvements during 2018.
This has meant that accurately forecasting From summer 2018, we will be joined by
demand has proved challenging. With a Natural Environment Research Council
installed solar PV capacity increasing since (NERC) sponsored meteorologist from the
2011, it has become an important component University of Reading. The project will focus
in our demand forecast. To improve the on whether extra meteorological information
accuracy of our demand forecasts, we have and data can be used to guide and adjust
launched a number of projects to help us to our solar forecasts.
tackle this directly. The result of this work has
meant that by summer 2017, we had seen a Another NIA project we are a part of
marked improvement in our daytime demand focuses on the methods used to translate
forecasting accuracy. As a result, our average forecast solar radiance values into solar
midday demand error has reduced. power generation. Our collaboration with
the University of Reading proposed a new
Our NIA partnership with Sheffield Solar model incorporating seasonal and time of day
continues to provide near-real time estimates effects, which is currently being assessed.
of national solar power outturn. Together
we have developed a system to produce We are also involved in a three month venture
localised outturns at each of the 327 Grid with the Alan Turing Institute for Data Science.
Supply Points in the UK. These datasets are This has resulted in a new artificial intelligence
invaluable for live monitoring and network based solar power forecasting model,
planning, as well as providing the framework which has shown accuracy improvements at
to build solar power forecasting models. 7 days ahead. We are also in the process of
We are now in discussion to continue evaluating this as a future forecasting model.
this collaboration to provide high frequency
data which will supply 5 minute solar outturn These projects are serving to improve
data, rather than the current 30 minute solar PV forecasting and monitoring and
outturn data, as well as improving and ultimately to improve our demand forecasts.
validating further outturn values. Real time We are also continuing to explore further
solar PV generation output can be accessed opportunities to enhance the improvements
here https://www.solar.sheffield.ac.uk/pvlive we have already seen, all of which help us to
balance supply and demand more accurately
We are also involved in a number of other and economically.
projects which address the accuracy of ourSummer Outlook Report 2018 24
Operational view including
generation/supply
Chapter one
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.
Key messages
• We are able to meet normalised demand • There is a possibility that we may have
and our reserve requirement in all weeks to instruct inflexible generators to reduce
throughout summer including the shoulder their output, in order to balance supply
months of April and September under all and demand.
interconnector scenarios.
Key terms
• Operational Code 2 (OC2): data: • Inflexible generation: types of
information provided to National Grid generation that require long notice periods
by generators. It includes their current to step down or ramp up their output, do
generation availability and planned not participate in the Balancing Mechanism
maintenance outages. or have obligations that influence when
• Operational surplus: the difference they can generate. Examples of inflexible
between the level of demand and generation include nuclear, combined heat
generation expected to be available, and power (CHP) stations, and some hydro
modelled on a week-by-week basis. generators and wind farms.
It includes both notified planned • Shoulder months: are those months that
outages and assumed breakdown are not technically heat driven months, nor
rates for each power station type. are they cooling driven months. Yet, they
• Flexible generation: types of can cause demand for either heating or
generation that can respond quickly cooling or both in the same month.
to requests to change their output,
such as interconnectors, some coal
and gas units, pumped storage and
most large wind farms.Summer Outlook Report 2018 25
Chapter one
Operational view
Our operational view is based on current requirement of 900 MW and a range of
generation availability data called Operational interconnector flows, to provide a week-by-
Code 2 (OC2) data. This is submitted weekly week view of the operational surplus.
by generators. In our analysis we have used
data provided to us on 15 March 2018. The operational view does not consider
any market response by generators to high
The OC2 data includes generators’ demand or tighter conditions. The availability
planned maintenance outages. To account includes those with capacity market contracts
for unexpected generator breakdowns, that are only incentivised to run during a
restrictions or losses close to real time, system stress event. We know that generators
we apply a breakdown rate to the OC2 data. have greater flexibility in planning summer
The breakdown rate is based on the units outages and, as market prices change
availability, maximum export limit (MEL), to reflect the level of operational surplus,
during the highest demand days over summer generators may take a commercial decision to
or winter excluding units we know are on move their planned maintenance programme.
planned outage. This is done by unit but For the most up-to-date information, we
grouped and applied by fuel type. The data encourage the industry to regularly view the
is then modelled against forecast normalised latest OC2 data, which is published each
transmission system demand, plus a reserve Friday on the BM Reports website.
Figure 1.8
Operational view summer 2018
54
52
50
48
46
44
42
40
38
GW
36
34
32
30
28
26
24
22
20
26 02 09 16 23 30 0714 21 28 04 11 18 25 02 09 16 23 30 06 13 20 27 03 10 17 24 0108 15 22
Mar Apr May Jun Jul Aug Sep Oct
Date
Max normal demand (including full Ireland export) Short term operating reserve
Assumed generation with low interconnector imports
Assumed generation with maximum interconnector imports
Assumed generation with medium interconnector flowsSummer Outlook Report 2018 26
Operational view including
generation/supply
Chapter one
Figure 1.8 compares the expected weekly Based on current operational data, the
generation and differing levels of interconnector minimum available generation is expected to be
flows, against the weekly normalised demand 42.1 GW in the week commencing 9 July (under
forecast for the summer period. It is based on the low interconnector scenario). We are able
the OC2 data provided to us by generators on to meet normalised demand and our reserve
15 March. requirement in this week, and throughout
the summer period, into the shoulder month
In the summer months, maintenance outages of September, even with low interconnector
reduce the available generation capacity from imports. Our operational view is based on
power stations. This is because power stations the best data currently available to us.
use this period to carry out maintenance to Changes to the notified generation and
ensure their availability over the winter months forecast demand will alter this outlook,
when there is higher demand and stronger potentially increasing or decreasing the level
market prices. Based on current economic of operational surplus. For the most current
conditions, we expect some coal power information, we encourage the industry to
stations to be temporarily mothballed during regularly view the latest OC2 data, published
summer 2018. We would expect them to each Friday on the BM Reports website.
become available if there was an obligation
to fulfil their Capacity Market contracts, if they Unlike the operational view presented here,
have them, or if the price increased to a level to the data presented on the BM Reports website
make it profitable to generate. These units can is largely unadjusted which means that it
require a few days’ notice to run. As a result of does not include derating for breakdowns;
these factors, the lowest levels of generation with the exception of wind, which is included
are typically seen during the high summer at an assumed load factor for each month.
period, between June and August. The forecast peak demand for the week and
a level of reserve are then compared to this
to calculate the operational surplus. Data on
BM Reports does not include interconnector
imports or exports.Summer Outlook Report 2018 27
Chapter one
Assumptions
1. Demand wind or solar forecast will increase the level.
The demand used in our operational view is However, we have assumed a real time reserve
normalised transmission system demand (TSD) requirement of 0.9 GW for each week of our
as mentioned in the ‘demand’ chapter. This analysis. This is shown in figure 1.8 as a purple
takes in to account the rise in output from the bar above the maximum normal demand.
increase in distribution connected generation
which acts as a reduction in demand. The 3. Available generation capacity
demand also includes the power used by during summer 2018
generating stations when producing electricity Figure 1.9 shows the generation capacity
(the station load at 500 MW) and interconnector expected to be available during summer 2018.
exports. We have assumed 1000 MW of This is from the maximum declared availability
export to Ireland across the Moyle and EWIC from the OC2 data, per unit, by fuel type, for
interconnectors during the peak demand period. the summer period. Later on we will apply a
The IFA and BritNed interconnectors are treated de-rating factor to account for breakdowns
as a source of generation. and restrictions and include planned outages
which will result in plant having decreased ability
2. Reserve to generate at its normal level for a particular
To be able to manage the second-by-second week. The capacity includes only the generation
regulation of system frequency and respond that is connected to the transmission system
to sudden changes in demand and supply, and submits data to OC2. This is higher than
National Grid is required to maintain a level of last year due to the increase in installed wind
reserve. In reality, this level of reserve varies capacity and some coal and gas plants that
daily depending on system conditions. A high were expected to close in 2018 remaining open.
Figure 1.9
Available generation capacity for summer 2018
80
70 4.00
60
29.4
50
0.8
GW
40 2.9
30 2.4
13.5
20
11.8
10 1.1
0 9.2
Capacity
Nuclear Hydro Wind Coal Biomass Pumped storage
OCGT CCGT InterconnectorSummer Outlook Report 2018 28
Operational view including
generation/supply
Chapter one
4. Generator breakdown They are based on the following:
The operational data provided to us by • historic summer breakdown rates over
generators only includes their planned the last 3 years
maintenance outages. As mentioned earlier, • they are taken from a units output against
closer to real time, there may be unexpected its capacity, on demand peaks higher than
generator breakdowns or availability reductions. the 80th percentile
To account for this in our analysis, we assume • it excludes zeroes if the outage was notified
a breakdown rate for each generation type. to us, and was therefore planned.
These rates are shown in table 1.2.
Table 1.2
Assumed breakdown rates for summer 2017
Power station type Assumed breakdown rate
Nuclear 8%
Interconnectors 0%
Hydro generation 5%
Wind generation 84%
Coal & Biomass 13%
Pumped storage 3%
OCGT 8%
CCGT 12%
To determine how much weekly output we for summer daytimes and is shown in figure
could reasonably expect from wind generation 1.10. We use the median wind load factor
this summer, we use a load factor as a of 16 per cent in our analysis as a scenario.
realistic scenario. This is calculated from This means there is a 50 per cent chance of
the historic wind farm load factor distribution the wind being either higher or lower than this.Summer Outlook Report 2018 29
Chapter one
Figure 1.10
Summer daytime wind load factors
100%
Percentage probability of exceeding
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Wind load factor
Wind load factor
Interconnectors
Our analysis is based on three possible The three interconnector scenarios listed
interconnector scenarios for periods of peak below, assume full export to Ireland, which
demand, shown by the graph in figure 1.8. adds 1,000 MW to expected demand:
Each scenario includes a varying level of import • Low imports of 500 MW, resulting
from Continental Europe. Further details on in a net export of 500 MW.
interconnectors can be found in the ‘Europe • Medium base case of 1,800 MW,
and interconnected markets’ chapter. resulting in a net import of 800 MW.
• Full interconnector imports of 3,000 MW,
resulting in a net import of 2,000 MW.Summer Outlook Report 2018 30
Operational view including
generation/supply
Chapter one
System operability during periods of low demand
In the summer, there is a significant reduction To help us to understand the actions that we
in the demand we see on the transmission may need to take this summer to respond to
system. This is because there is less of periods of low demand, we model levels of
a requirement for heating and lighting inflexible generation against current expected
compared with winter and a higher output minimum demands for each week. These
from distribution connected solar generation. forecasts are updated weekly throughout the
As as result, there are fewer generation units summer and can be found on our website.
needed on the system to meet demand.
To understand potential operability issues we
However, the system still needs to respond need to stack de-rated inflexible generation
to the largest generation or demand loss. against the forecast minimum demand.
It is also necessary to maintain positive and Ideally we want to keep this inflexible
negative regulating reserve levels. This is to generation producing electricity, plus volumes
account for forecasting errors and reductions for response and reserve which are required
in generator availability closer to real time. to be maintained. This is shown in figure 1.11
as a weekly resolution. Pumped storage
As a result, we need to make sure that there demand is included at an assumed load factor
is sufficient flexible generation on the system of 70 percent; this is a method of increasing
to be able to reduce their output low enough demand and is a routine action.
to meet that level of demand, and still have
the ability to increase or reduce further
to maintain sufficient frequency response.Summer Outlook Report 2018 31
Chapter one
Figure 1.11
Weekly minimum demand and generation profiles
32
30
28
26
24
22
20
18
GW
16
14
12
10
8
6
4
2
0
25 01 08 15 22 29 0613 20 27 03 10 17 24 0108 15 22 29 05 12 19 26 02 09 16 23 30 07 14 21
Mar Apr May Jun Jul Aug Sep Oct
Date
Nuclear Inflexible BMUs (e.g. CHP) Inflexible hydro
Interconnector imports after trades Plant total providing regulating reserve
Plant providing voltage support Inflexible wind
Minimum demand Minimum demand incl. pumping
Based on current data, we can see that As we approach real time, these requirements
inflexible generation is expected to exceed may change depending upon the weather,
minimum demand (blue line) during periods wind conditions and the generation available
of the summer. As a consequence, we on the day. We will continue to update this
anticipate that we will be asking pumped forecast during the summer. We will inform
storage units to increase demand by more and engage with inflexible generators where
than the assumed level by moving water back actions have been exhausted on flexible
to their top lakes, and trading further to reduce generation and further balancing is required
the level of interconnector imports. (please see appendix).Summer Outlook Report 2018 32
Operational view including
generation/supply
Chapter one
Modelling flexible wind generation
As the amount of installed wind capacity In figure 1.12, flexible wind farm output has
continues to increase, it has become been added to the cumulative minimum
economic to carry a proportion of regulating output (the pink bars at the top), assuming
reserve on large wind farms in times of high the same wind load factor of 51 per cent.
wind. Regulating reserve is the amount of It shows that if flexible wind does not
generation that National Grid holds back contribute to meeting the frequency response
on units, to manage the second-by-second and regulating reserve requirements, it will
regulation of system frequency to respond need to be curtailed this summer to ensure
to sudden changes in demand and supply. that supply does not exceed demand.
The flexibility of wind farms allows us to issue This curtailment will either be carried out
curtailment instructions if necessary, asking via the Balancing Mechanism or by direct
them to reduce their output for a short period. trades. There is a possibility of curtailment
The number of instructions we issue to wind across the summer period, depending on
farms is likely to increase in the future, as wind conditions. This action will be carried
we continue to see reduced demand at the out in economic order, along with increased
summer minimum (with more distribution pumping, and trades conducted to reduce
connected solar capacity) and fewer import on the interconnectors.
flexible generators running overnight
and in the afternoon.
Figure 1.12
Weekly minimum demand and generation profiles including flexible wind output
32
30
28
26
24
22
20
18
GW
16
14
12
10
8
6
4
2
0
25 01 08 15 22 29 0613 20 27 03 10 17 24 0108 15 22 29 05 12 19 26 02 09 16 23 30 07 14 21
Mar Apr May Jun Jul Aug Sep Oct
Date
Nuclear Inflexible BMUs (e.g. CHP) Inflexible hydro I/C imports after trades
Plant total providing regulating reserve Plant providing voltage support
Inflexible wind Flexible wind Minimum demand
Minimum demand incl. pumpingSummer Outlook Report 2018 33
Chapter one
In our analysis, we have only considered
possible wind curtailment at a national level.
It is also possible that we may need to curtail
wind at a local level this summer. Local issues
are likely to be caused by constraints on the
system resulting from faults, maintenance or
network design. They may result in a higher
level of generation in a geographical area
than is needed or that can be safely exported
to other areas of the electricity network.
You can find out more about constraints in the
appendix, or by accessing the latest forecasts
for potential wind curtailment on our website.Summer Outlook Report 2018 34
Operational view including
generation/supply
Chapter one
Modelling inflexible generation
Assumptions
1. Load factors this summer in the ‘Europe and interconnected
In order to determine how much inflexible markets’ chapter. More information about
generation is likely to be available during RoCoF can be found in the appendix.
periods of low demand either early morning The load factor for flexible and inflexible
or during the afternoon, we apply a load wind is determined from figure 1.13.
factor to each generation type. These load This shows that on at least one of the
factors, which are shown in table 1.3, are days where we might reasonably expect
based on historic availability over previous the lowest demand to occur, we can assume
minimum demand periods. We also apply a a wind load factor of 51 per cent. Again,
load factor to interconnectors. This is based there is a 50 per cent chance of the wind
on the price differential between Continental being higher or lower than this. The other
Europe and GB plus a reasonable number of load factors are chosen to represent a realistic
trades it would take to resolve rate of change low demand scenario. The interconnector
of frequency (RoCoF) issues by limiting the flows are after trade action which we would
size of the interconnector loss. You can find aim to do in advance of an issue.
out more about expected interconnector flows
Table 1.3
Inflexible load factor assumptions at minimum demand
Generator type Load factor
Nuclear 0.9
Inflexible Balancing Mechanism units (CHP) 0.5
Inflexible hydro 0.5
Flexible and inflexible wind 0. 51
Moyle interconnector 0.5
East West interconnector 0.5
BritNed 0.70
Interconnexion France-Angleterre 0.70Summer Outlook Report 2018 35
Chapter one
Figure 1.13
Wind load factors at minimum demand
100%
Percentage probability of exceeding
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0
Wind load factor
Wind load factor
Generation merit order
A generation merit order describes the As an example, figure 1.14 shows the output
sequence in which generators provide of different types of generators over the course
energy to the market at any given time. of a typical mid-summer day. It is based on
It is predominantly based on the cost of data from 17 August 2017. It does not include
producing it, for each type of generator. solar or embedded wind because these are
The price at which energy can be sold embedded and therefore do not make up the
varies throughout the day, depending transmission connected demand or generation
on the levels of demand and generation which is illustrated in figure 1.14. We expect
capacity on the transmission system. generator output to follow a similar pattern
in summer 2018.
The most cost-efficient power stations feature
first in the merit order, providing continuous
output across the day, known as baseload.
Less cost-efficient generators may respond
to peaks in demand, when the price at which
electricity can be sold is higher.Summer Outlook Report 2018 36
Operational view including
generation/supply
Chapter one
Figure 1.14
Generator output for a typical mid-summer day
35,000
30,000
25,000
Output MW
20,000
15,000
10,000
5,000
0
00:30 02:30 04:30 06:30 08:30 10:30 12:30 14:30 16:30 18:30 20:30 22:30
Most likely to run Time Least likely to run
Nuclear Interconnector Wind Hydro Other Gas OCGT
Coal OCGT Pumped storage
Nuclear power stations, as shown in figure stations. These power stations are called
1.14, typically provide a large proportion of the the marginal plant and are able to adjust
baseload in the summer. Wind generation also their output in response to price signals
features early in the merit order as it has no fuel as demand varies throughout the day.
costs. However, it can only run when the wind Based on analysis of current prices,
is blowing. As a result of their input costs and gas-fired units are likely to feature ahead
efficiency, the most variable generator output of coal in the generation merit order, as
is typically from gas and coal-fired power they will be more economical to dispatch.Summer Outlook Report 2018 37
Europe and interconnected markets
Chapter one
Our Europe and interconnected markets chapter
explores interconnector behaviour and provides
market insights into the impact to GB, of pricing
and renewable generation in neighbouring countries.
Key messages
•G
B forward prices for summer 2018 are exports of electricity on interconnectors
expected to remain higher than markets in to Ireland during peak, switching to imports
Continental Europe. overnight and during periods of high wind.
• Based on historical views and forward • Further nuclear outages in France are not
prices we expect there to be net imports likely to impact margins, even during the
of electricity on the interconnectors from shoulder months.
Continental Europe. We also expect net
Key terms
• Operational Code Section 2 (OC2) • Flexible generation: types of
data: information provided to National generation that can respond quickly to
Grid by generators. It includes their requests to change their output, such as
future generation availability and interconnectors, some coal and gas units
planned maintenance outages. and most large wind farms.
• Operational surplus: the difference • Inflexible generation: types of
between the level of demand and generation that require long notice periods
generation expected to be available, to step down or ramp up their output, do
modelled on a week-by-week basis. not participate in the Balancing Mechanism
It includes both planned outages and or have obligations that influence when
assumed breakdown rates for each they can generate. Examples of inflexible
power station type. generation include nuclear, combined heat
and power (CHP) stations, and some hydro
generators and wind farms.
Overview
The direction which interconnectors flow is interconnector availability for summer 2018
determined by price, which in turn is influenced based on outages, forward pricing and activity
by the weather, and the amount of renewable in Continental Europe. All of these factors may
generation available. This chapter looks at affect interconnector flows into or out of GB.Summer Outlook Report 2018 38
Europe and interconnected markets
Chapter one
Interconnectors
The weather impacts price because of The forward seasonal prices between the
the influence on demand and distributed GB, French and Dutch markets for summer
energy sources. This is as a result of the 2018 indicate positive price spreads in favour
increase in renewable generation and of the GB market. We expect to export
demand fluctuations caused by changes to Ireland during peak times on both the
in temperature. As a result, we expect Moyle and East West interconnector (EWIC)
occasional variations to interconnector interconnectors, turning to imports during
flow patterns. the night and periods of high wind.
The Netherlands and France
Interconnexion France-Angleterre (IFA), the
interconnector between France and GB, is
currently under a fault outage with a reduced
capability of 1.5 GW until the end of April. It is
then expected to be at its full 2 GW capability
this summer apart from two planned outages
for essential maintenance. These outages 0.5GW
are scheduled for 18 June to 29 June and
03 September through until 14 September
inclusive. During these periods the capability Ireland
will reduce to 1 GW.
0.5GW 1GW
The BritNed interconnector has a 1 GW
capability between GB and the Netherlands.
There are two planned outages this summer Netherland
scheduled for 14 May to 18 May and 17
September through until 21 September 2GW
inclusive. The capability will reduce to 0 GW France
during both of these outages.
We note that the start of the second BritNed
outage is within a few days of the completion
of IFA’s September outage. Any delay to the
return of IFA may impact the planned start
of BritNed or result in both IFA and BritNed
being on outage at the same time. At present,
this would not adversely impact security of
supply or operability; however, we will keep
this under review.Summer Outlook Report 2018 39
Chapter one
Ireland
The East West Interconnector (EWIC) is Moyle interconnector to Northern Ireland is
currently under a fault outage with zero expected to be at full capability throughout
capability until 29 March. It will be on a planned summer 2018, however, the maximum flow
outage for 9 days starting 01 May through until is subject to Transmission Entry Capacity
09 May inclusive. During this time its capability (TEC) values.
will reduce from 0.5 GW to 0 GW. The 0.5 GW
Increase in renewable generation since summer 2017
Renewable generation capacity including while solar capacities have increased
wind, solar and biomass also continues to significantly in the Netherlands, Belgium and
grow in Continental Europe and GB. These GB. Gas and coal capacities are generally
generation types now contribute towards a decreasing. Nuclear capacity has reduced in
larger proportion of the generation mix. Figure Germany since last summer and although the
1.16 shows the increases in the generation increase in its renewable capacity is not as
components in GB and neighbouring countries great as other countries, the total renewable
from 2017 to 2018 (negative values are shown capacity has reached a new record of 94 GW
in blue). The chart shows that onshore wind which equates to 47 per cent of total capacity.
capacities have increased in each country,You can also read
