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POST IMPLEMENTATION REVIEW OF P305
EXEC SUMMARY AND CONTENTS
This document summarises data and analysis provided by ELEXON to contribute to BSC Parties’ understanding
of BSC Modification P305 ‘Electricity Balancing Significant Code Review Developments’.
Using BSC data and considering the six month period after P305 was implemented, the following can be
observed:
● Overall, the market was more long than short since the implementation of P305 – the system was
net long in 62% of Settlement Periods since the introduction of Modification P305 (compared to
57% of Settlement Periods in the same time period of the last year);
● Parties’ Imbalance Volumes in the six months following P305 were the greatest compared to the
same period in the last four years;
● System Prices have decreased on average but a greater number of incidents of more extreme
System Prices have been seen;
● Parties’ Trading Charges have increased following the implementation of P305, but by a small
amount (£2/MWh) for most Parties;
● The Reserve Scarcity Price (RSP), Demand Control actions or Contingency Balancing Reserve
actions have not been used since the implementation of P305 and therefore it was not possible to
fully assess the impact of these parameters.
CONTENTS
EXEC SUMMARY AND CONTENTS .............................................................................................................. 1
1. BACKGROUND AND SCOPE OF THE ANALYSIS ................................................................................ 2
2. BALANCING BEHAVIOUR ............................................................................................................... 11
3. OVERVIEW OF PRICE TRENDS ...................................................................................................... 18
4. IMPACT ON PARTIES TRADING CHANGES .................................................................................... 26
5. PARAMETER ANALYSIS ................................................................................................................. 32
LIST OF APPENDICES .............................................................................................................................. 39
GLOSSARY ............................................................................................................................................... 40
CLASSIFICATION OF PARTY TYPES ......................................................................................................... 42
SUMMARY OF DATA ISSUES FOLLOWING THE IMPLEMENTATION OF P305 ......................................... 45
PUBLIC
ISG182 P305 POST IMPLEMENTATION REVIEW
Post Implementation Review
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1. BACKGROUND AND SCOPE OF THE ANALYSIS
The BSC Panel, made up of Industry representatives, highlights annually its strategic priorities and how to
address these. This year a priority was P305 and as such the Panel asked ELEXON to monitor the impacts of
P305.
This document summarises data and analysis provided by ELEXON to contribute to BSC Parties’ understanding
of BSC Modification P305 ‘Electricity Balancing Significant Code Review Developments’. Our review compiles
relevant evidence using Settlement data, but we do not provide an assessment of the Modification.
BSC Modification P305
BSC Modification P305 introduced a number of changes to the calculation of the cash-out price, and was
implemented on 5 November 2015. It was raised to progress the conclusions to Ofgem’s Electricity Balancing
Significant Code Review (EBSCR), which looked at addressing the Authority’s concerns with electricity
balancing arrangements.
The System Sell Price (SSP) and System Buy Price (SBP) are the ‘cash-out’ or ‘Energy Imbalance’ prices that
are used to settle the difference between contracted generation or consumption and the amount that was
actually generated or consumed in each half hour trading period. P305 implemented the following changes:
● A reduction in the Price Average Reference (PAR) value to 50MWh and the Replacement PAR
(RPAR) value to 1MWh upon implementation, and reduce the PAR value further to 1MWh on 1
November 2018.
● A single imbalance price so that SSP and SBP are equal to each other in each Settlement Period.
● A price for Short Term Operating Reserve (STOR) actions using a Reserve Scarcity Price (RSP)
which is determined with reference to a ‘static’ Loss of Load Probability (LoLP) function upon
implementation before switching to a ‘dynamic’ function on 1 November 2018.
● A price Demand Control actions at Value of Lost Load (currently £3,000/MWh) and a process for
correcting participants’ imbalance volumes following such an event.
National Grid raised P305 on 30 May 2014. The Panel agreed to submit P305 to an Assessment Procedure,
during which it was issued for industry Impact Assessment and the Workgroup’s Assessment Procedure
Consultation. The Workgroup recommended that the Alternative Modification should be approved, and its
Assessment Report was presented to the Panel on 12 February 2015.
The Panel initially recommended that both the Proposed and Alternative Modifications should be rejected, and
issued P305 for its Report Phase Consultation. The Panel made its final recommendation that both the
Proposed and Alternative Modifications should be rejected at its meeting on 12 March 2015.
The Authority approved the P305 Proposed Modification on 2 April 2015 for implementation on 5 November
2015 as part of the November 2015 Release.
The decision to approve BSC Modification P305 was based on defects identified in the calculation of cash-out
prices by the Electricity Balancing Significant Code Review (EBSCR). The concerns were as follows:
● Cash-out prices were calculated using an average of the cost of the actions that the System
Operator (SO) takes to balance the system, rather than the marginal action.
● The ‘dual price’ arrangements created unnecessary imbalance costs for parties because the price
for ‘helpful’ imbalances did not reflect the savings these imbalances create for the SO.
● They excluded the costs borne by the consumer during disconnection and voltage reduction.
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● The method for pricing reserve costs into cash-out did not accurately reflect the real time value of
this reserve, and excluded the cost of some reserve products altogether.
The EBSCR Final Policy Decision concluded that these defects could increase the cost of ensuring security of
supply to consumers because it could lead to inefficient balancing and dampen incentives for the market to
provide flexibility.
Analysis provided
We have carried out analysis using BSC data1 focusing on the six month period following the implementation of
P305 (ie 5 November 2015 to 30 April 2016).
The intention is to look back at the period since implementation and analyse what System Prices and Trading
Charges would have been had P305 not been introduced, and to look forward ahead of ‘phase two’ of the
changes being introduced in November 2018. We also make some comparison of the same six month period
across different years. There is one important caveat to any analysis, and that is that we cannot account for
any behavioural change that may have resulted from different System Prices.
To facilitate the analysis, we compare three pricing scenarios:
1. Live Prices (“Live”) – this is the price calculation that is used in calculating System Prices since 5
November 2015.
2. P217A Price Scenario (“P217”) – this is the price calculation that applied before P305 was
implemented on 5 November.
3. November 18 or Price Scenario (“Nov-18”) – this is the ‘phase two’ price calculation that will
apply from 1 November 2018, specifically to calculate imbalance prices with a lower Price Average
Reference (PAR) value and a Value of Lost Load (VoLL) of £6,000/MWh.
We also assess the impact of Parties’ Trading Charges during the period. To carry out this analysis, we have
split different BSC Parties into different Party Types2:
● Independent Generator
● Non Physical Trader
● Renewable Generator
● Vertically Integrated Player; and
● Independent Supplier.
We are presenting this review to the ISG at its June meeting. We welcome your comments which can be shared with the group prior to presentation at the Panel. Please email any feedback to
1 The data used is a combination of Settlement Runs using at least ‘SF’ data. 2 Note that the Party Grouping is based on our latest information and best understanding of Parties. See
Appendix 2 for details.
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Summary of workgroup views and evidence provided
We have aimed to provide data to address the views of the Modification workgroups. A summary of views
provided against the BSC Objectives are provided below. For a full report of the workgroup and the Panel’s
views on P305, see the Final Modification Report3.
Summary of Workgroup Members’ Views4
BSC Objectives Workgroup members’ views Evidence Provided Out of scope
(a) The efficient
discharge by the
Transmission
Company of the
obligations imposed
upon it by the
Transmission
Licence
Neutral (unanimous) N/A N/A
(b) The efficient,
economic and co-
ordinated operation
of the National
Electricity
Transmission
System
Beneficial (minority)
Strengthens incentive to balance
efficiently, particularly in times of
tight margin
Potential increase in liquidity
which will help participants
balance ahead of Gate Closure
Detrimental (majority)
LoLP values could send out false
signals and could encourage
balancing after Gate Closure if
high
Volatile prices may cause
participants to take longer
positions to avoid the
consequences of being short
More marginal prices increases
the risk of balancing actions
incorrectly impacting the
Absolute
Imbalance
Volumes
Party Imbalance
Volumes
Market Index
Volumes
Aggregated Party
Imbalances
Improvements in cost-
reflectivity will encourage
investment, driving long
run cost savings
Better reflects the value of
flexible generation, which
may help defer the
decommissioning of such
plant
3 The Final Modification Report (FMR) can be found at: https://www.elexon.co.uk/mod-proposal/p305/ 4 This shows a summary the different views expressed by Workgroup members – not all members necessarily agreed with all of these
views.
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imbalance price in subsequent
Settlement Periods
(c) Promoting effective
competition in the
generation and
supply of electricity
and (so far as
consistent
therewith)
promoting such
competition in the
sale and purchase
of electricity
Beneficial (minority)
Allows flexible and reliable plant
to gain advantage that reflect
their value to consumers
Single price removes the
inefficient price spread and the
net imbalance costs that creates
Incentivises participants to
balance positions, increasing
liquidity and encouraging
investment in flexible capacity
Sharpens the signals of scarcity
to the market
Detrimental (majority)
Volatile prices will have a
detrimental effect on smaller
participants
The distributional effects of P305
are unknown
The reduction in PAR to 50MWh
is too large a step and the
impacts this will have are
unknown
Single price may result in less
trading, reducing liquidity
Party Imbalance
Volumes
Market Index
Volumes
System Prices
Improves incentives for
flexible and reliable plant
to enter the market
(d) Promoting
efficiency in the
implementation of
the balancing and
settlement
arrangements
Detrimental (minority)
Introduces complex processes
with little proven benefit
Neutral (majority)
N/A N/A
(e) Compliance with
the Electricity
Regulation and any
relevant legally
Neutral (unanimous) N/A N/A
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binding decision of
the European
Commission and/or
the Agency [for the
Co-operation of
Energy Regulators]
(f) Implementing and
administrating the
arrangements for
the operation of
contracts for
difference and
arrangements that
facilitate the
operation of a
capacity market
pursuant to EMR
legislation
Neutral (unanimous) N/A N/A
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Market context
Outturn System Prices in the six months since the implementation of P305 are as much a function of the
market fundamentals as the changes to the calculation that were introduced; and this is an important caveat
to any historical comparisons.
It may be that the market conditions since the implementation of P305 have meant that some of the reforms
have not had the impact that some stakeholders expected. For example, in National Grid’s Winter Outlook
Review5, they noted that:
● Winter 15/16 was one of the mildest winters in almost sixty years;
● Peak demand was 1GW lower than expected; and
● Operational conditions were less challenging than anticipated.
Our own analysis on the changes in market fundamentals is presented in the section below. Graphs 1 and 2
show the fuel mix for the first six months of P305, and how this compares to the same time period from the
preceding year, using metered output data from generating BMUs (embedded generation is therefore not
captured).
Metered output from gas-fired plant increased by
over 10%, while coal output fell around 15%. Fuel
prices were largely the driving force behind this
trend, with gas plants becoming more economical to
run than coal plants. Wind also saw an increase;
with increased capacity installed and higher levels of
wind over 2015/16 compared to the previous year.
The average available generation per Settlement
Period has fallen since Winter 2014/15. This can be
seen in Graph 3, which shows average installed
capacity margins over time using Effective
Maximum Export Limits. Some of the factors
causing this are plant closures, decreasing demand
and increasing embedded generation. Available
capacity shows a seasonal shape, with less capacity
5 http://media.nationalgrid.com/media/1293/ng-winter-review-2016.pdf
Graph 3 – Average installed capacity margins by over time using Effective Maximum Export Limits
20
22
24
26
28
30
32
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
2014 2015 2016
GW
h
Graph 2 - 2014/15 Fuel Mix
37%
17%
22%
9%
8%5% 2% Gas
Coal
Nuclear
Wind
Interconnector
Bio
Hydro
Oil
Graph 1 - 2015/16 Fuel Mix
26%
32%
21%
7%
8%5% 1%
Gas
Coal
Nuclear
Wind
Interconnector
Bio
Hydro
Oil
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available over the summer months, as
generators typically performing maintenance in
summer.
Graph 4 shows average accepted Bid Price by
fuel type. Wind generators typically submit
negatively-priced bids to offset the cost of the
Renewable Obligation Certificates that they will
not receive if they are not generating. The
average Bid price of coal has tended
downwards, from around £40/MWh in January
2014 to around £20/MWh in April 2016.
Graph 5 shows average Offer Price by fuel type
(wind has been excluded since this fuel type has
substantial Offers accepted).
The period since implementation of P305 was
also a period of continued falling wholesale
prices. Graph 6 shows market prices, as
measured by the Market Index Price (MIP). The
MIP is a price (expressed in £/MWh), calculated
for each Settlement Period, to reflect the price
of wholesale electricity in the short term or
intra-day markets. Prices and volumes for
trades that occur within 12 hours of Gate
Closure are submitted by the Market Index Data
Provider(s) (currently APX and N2EX) and these
are used to calculate the Market Index Price6.
Aside from the impact that these conditions may
have had on the pricing of the underlying
balancing actions (such as Bids and Offers in the
Balancing Mechanism) used to set the price they
have also had a more direct impact on cash-out
prices. There were no Contingency Balancing
Reserve or Demand Control actions taken since
the November release, both of which would be
priced at £3,000/MWh for the purposes of the
System Price calculation. Further, the ‘less tight’
margins meant that the Reserve Scarcity Price
(RSP) did not have any impact on System Prices.
6 For full detail of the Market Index Price, see the Market Index Definition statement here:
https://www.elexon.co.uk/wp-content/uploads/2012/01/mids_v7.0.pdf
Graph 6 – Average Market Index price by day
0
5
10
15
20
25
30
35
05/1
1/2
014
28/1
1/2
014
21/1
2/2
014
13/0
1/2
015
05/0
2/2
015
28/0
2/2
015
23/0
3/2
015
15/0
4/2
015
08/0
5/2
015
31/0
5/2
015
23/0
6/2
015
16/0
7/2
015
08/0
8/2
015
31/0
8/2
015
23/0
9/2
015
16/1
0/2
015
08/1
1/2
015
01/1
2/2
015
24/1
2/2
015
16/0
1/2
016
08/0
2/2
016
02/0
3/2
016
25/0
3/2
016
17/0
4/2
016
MIP
(£
/M
Wh
)
Total Linear (Total)
Graph 4 – Average accepted Bids over time, split by fuel type
-120
-100
-80
-60
-40
-20
0
20
40
60
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
2014 2015 2016
Bid
Pri
ce
(£
/M
Wh
)
Coal Hydro Pumpedstorage
Wind Gas/CCGT/OCGT
Graph 5 - Average accepted Offers over time, split by fuel type
0
20
40
60
80
100
120
140
160
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
2014 2015 2016
Off
er
Pri
ce
(£
/M
Wh
)
Coal Hydro Pumpedstorage Gas/CCGT/OCGT
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Related work
This review focuses on the impact of the changes introduced as part of P305; other reviews are performed in
relation to specific aspects of the arrangements.
Market Index Price Review and issue group
The Market Index Definition statement is the document which contains the methodology for determining the
Market Index Price (MIP). Before P305, it was used to set one of the Imbalance Prices in each half hour.
Following the implementation of P305, it is only used in rare, defaulting circumstances (e.g. when there are no
balancing actions taken in a half-hour).
At its October 2015 meeting, the BSC Panel, following the Imbalance Settlement Group’s (ISG)
recommendations, asked ELEXON to form an Issue Group to look at the use of the MIP in those defaulting
situations. The Issue Group will be formed in June 2016 and will consider whether the MIDs remains fit for
purpose, and whether there are other options for setting default prices. The Issue Group’s recommendations
will feed into the annual MIDS review in August 2016, and the outcome will be discussed with the ISG and the
Panel.
Continuous Acceptance Duration Limit (CADL) and De-Minimis Threshold
The Continuous Acceptance Duration Limit (CADL) and the De-Minimis Acceptance Threshold (DMAT) are
parameters that are used in the calculation of the System Price, and they are subject to review every two
years. The next review of these parameters is due in October 2016.
CADL is used to identify short-duration Bid Offer Acceptances (BOAs) that are most likely to be associated with
system balancing actions and potentially exclude them from the Main Energy Imbalance Price calculation. It
has been set at 15 minutes since its introduction in 2001.
DMAT removes balancing actions smaller than a set value, currently 1MWh, from the Main Energy Imbalance
Price calculation.
Value of Lost Load (VoLL) Process Review
Value of Lost Load (VoLL) is a defined parameter in the BSC, and is currently set to £3,000/MWh. P305 has set
the VoLL at this level until 1 November 2018, when the VoLL will be increased to £6,000/MWh. As the VoLL
has been planned to be increased on this date, no review has currently been scheduled.
ELEXON plans to carry out a review of the VoLL in 2019. Subject to BSC Panel approval, the review process will
include bringing a consultation paper to the ISG for approval, reporting industry views back to the ISG and
presenting the ISG’s recommendations to the Panel. Any change would need a BSC Modification and would
need the Authority’s approval. In any case the Authority would receive a report from the Panel with its
decision.
Loss of Load Probability (LoLP) Calculation Statement review
The Loss of Load Probability Calculation Statement7 is a document which sets out the methodology for
determining the relationship between De-Rated Margin and the probability that there will be loss of load for a
given Settlement Period. LoLP is used to determine the Reserve Scarcity Price for a Settlement Period. Section
1.5 of the LoLP Statement specifies that the Panel may review this Statement from time to time and make
changes, subject to the Authority’s approval, in accordance with BSC Section T 1.6A. This section requires that
any suggested changes to be submitted to Industry for consultation and that the Transmission Company, as
well as all BSC Parties, to be informed of any change approved by the Authority.
7 https://www.elexon.co.uk/wp-
content/uploads/2014/10/37_244_11A_LOLP_Calculation_Statement_PUBLIC.pdf
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As stated in Section T 1.6A.7, the Panel may delegate responsibility to maintain and review the LoLP
Statement. Subject to BSC Panel’s approval, ELEXON’s review process will be overseen by the ISG and involve
Industry consultation before presentation to the Panel for decision. The Authority would need to approve any
change to the LoLP Statement. The LoLP calculation will change to a Dynamic LoLP Function on 1 November
2018, therefore, there is currently no plan to perform a review of the LoLP Statement. Industry will be
informed if the Panel determines that a review is necessary.
Review of Credit Modifications
Since November 2014, a number of BSC Modifications have been introduced to improve the Credit Cover
process: P306 ‘Expanding the definition of a ‘Letter of Credit’ to include regulated insurance companies’, P307
‘Amendments to Credit Default arrangements’ and P310 ‘Revised Credit Cover for Exporting Supplier BM Units’.
A first stage Post Implementation Review of those Modifications was undertaken in January (ISG177/02) and
February (Panel 249/15) 2016 and a second stage will be presented at the July 2016 ISG meeting and August
2016 Panel meeting.
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2. BALANCING BEHAVIOUR
In this section, we present data on:
● The overall imbalance on the system since P305 was introduced, and how this compares to
imbalances in the same time period the previous year (“Net Imbalance Volume”)
● Parties’ overall imbalances across the period, how these have changed over time, and how they
compare to the same time period in the previous year (“Parties aggregated Imbalances”)
● Parties’ overall imbalances, and how these differ at different times (peak times against off-peak)
● A measure of volumes of trades in the intra-day forward markets, compared to the same period
last year (“Traded volumes from Market Index Data Providers”)
Market balancing as measured by Net Imbalance Volume (NIV)
There were mixed views about the impact that P305 would have on the market’s incentive to balance. Some
argued that it would increase incentives to balance efficiently (noting that this would not necessarily mean
always having a fully balanced position ahead of Gate Closure), while others argued that it would increase
incentives to go long, in response to price volatility or to avoid the consequences of being short.
Net Imbalance Volume (NIV) is the net of all balancing actions taken by the System Operator for a Settlement
Period. It indicates whether the system was overall long or short in a Settlement Period, and this can be used
as one measure of overall imbalance or length of the system. Positive NIV denotes a short system and vice
versa.
Graph 7 shows the proportion of
Settlement Periods that were long and short
and how this compares to the same time
period from the preceding year. Overall, the
market has been long more frequently – the
NIV was long in 62% of Settlement Periods
from November 2015 to April 2016,
compared to 57% in the same period for
the preceding year.
0%10%20%30%40%50%60%70%80%90%
100%
14/1
5
15/1
6
14/1
5
15/1
6
14/1
5
15/1
6
14/1
5
15/1
6
14/1
5
15/1
6
14/1
5
15/1
6
Nov Dec Jan Feb Mar Apr
Pe
rce
nta
ge
of
Se
ttle
me
nt
Pe
rio
ds
Sum of Long Sum of Short
Graph 7 – Average System length per Settlement Period by Month
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Graph 8 shows how long and short the market has been on average across the Settlement Day over 2014/15
(5 November 2014 – 30 April 2015) and Graph 9 shows the same data for the 2015/16 year (5 November
2015 – 30 April 2016). The system length appears to vary more across the day in 2014/15, with the proportion
of times the system was long being greater over the morning peak (Settlement Periods 13 to 20) and the
evening peak (Settlement Periods 35 to 43).
Graph 8 – Average System length per Settlement Period 2014/15
Graph 9 – Average System length per Settlement Period 2015/16
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Pe
rce
nta
ge
of
Se
tte
lme
nt
Pe
rio
ds
Sum of Long Sum of Short
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47
Pe
rce
nta
ge
of
Se
ttle
me
nt
Pe
rio
ds
Sum of Long Sum of Short
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Graph 10 shows the magnitude of NIVs observed in 2015/16 compared to 2014/15 (positive NIVs denote a
short system and negative NIVs denote a long system).
Graph 10 – Frequency of Net Imbalance Volumes (NIVs)
0
200
400
600
800
1000
1200
-20
00
- -
19
00
-18
00
- -
17
00
-16
00
- -
15
00
-14
00
- -
13
00
-12
00
- -
11
00
-10
00
- -
90
0
-80
0 -
-7
00
-60
0 -
-5
00
-40
0 -
-3
00
-20
0 -
-1
00
0 -
10
0
20
0 -
30
0
40
0 -
50
0
60
0 -
70
0
80
0 -
90
0
10
00
- 1
10
0
12
00
- 1
30
0
14
00
- 1
50
0
16
00
- 1
70
0
18
00
- 1
90
0
20
00
-
Fre
qu
ency
NIV (MWh14/15 15/16
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Market balancing as measured by Parties’ aggregated Imbalance
Absolute Imbalances
NIV shows the net length of the system
(i.e. it shows whether the system is long
or short for a given half-hour), but this
hides the long and short imbalances faced
by market participants in each half hour.
Party imbalances are the difference
between contracted volumes of energy
and physical production and consumption.
In Graph 11 we present data on Parties’
absolute Imbalance Volumes. A second
plot shows Energy Imbalance Volumes as
a percentage of total demand. This shows
that there has been an increase in both
absolute Imbalance Volumes and
Imbalance Volumes as a proportion of
total demand over the past two years.
This trend appears to have continued
since the implementation of P305.
Graph 12 presents absolute Imbalance
Volume data from November to April for
the past 4 years. Parties imbalance
volumes were higher in 15/16 for every
month, except in April 14/15 when
Imbalance Volumes were 0.07 TWh
higher.
Graph 13 shows average absolute
Imbalance Volumes by Settlement Period
in 15/16 compared to the same period from the previous year. The absolute imbalance volumes are higher in
all Settlement Periods in 2015/16.
Graph 12 – Absolute imbalance volumes by year
1
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
2
Nov Dec Jan Feb Mar Apr
Imb
ala
nce
Vo
lum
e (
TW
h)
12/13 13/14 14/15 15/16
Graph 11 – Absolute Imbalance Volumes and as a percentage of total demand by month
-
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
0
0.5
1
1.5
2
2.5
Apr-
14
Jun-1
4
Aug-1
4
Oct
-14
Dec-
14
Feb-1
5
Apr-
15
Jun-1
5
Aug-1
5
Oct
-15
Dec-
15
Feb-1
6
Apr-
16
Imb
ala
nce
Vo
lum
e a
s a
Pe
rce
nt
of
To
tal D
em
an
d
Ab
so
lute
Im
ba
lan
ce
Vo
lum
e
(TW
h)
Imb Vol Imb Vol as percent of Total Demand
Graph 13 – Absolute imbalance volumes by Settlement Period
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
1 3 5 7 9 11131517192123252729313335373941434547
Imb
ala
nce
Vo
lum
e (
MW
h)
14/15 15/16
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Party Imbalances by Long and Short
Next we present imbalances split by whether
they were long or short imbalances. Some
stakeholders expressed the view that P305
may create incentives to ‘go long’ (i.e.
purposely contract more, demand less or
produce more electricity) particularly over
the peak periods, or in response to price
volatility. Overall, Parties long imbalance
over 5 November 2015 to 30 April 2016
were 25% greater and short imbalances
19% greater compared to the same period
from the previous year.
Graph 14 shows Party imbalances by long
and short imbalances per month (long balance volumes are displayed as positive volumes and short imbalance
volumes are displayed as negative volumes). Long imbalances were greater in each month in 2015/16, with
the exception of April 2016.
Short imbalances were greater
in every month in 2015/16.
Table 1 shows long and short
imbalance volumes split by
peak8 and off-peak Settlement
Periods for 5 November 2015
until 30 April 2016 and the
same period for 2014/15. The
average imbalance volume was greater (both longer and shorter) over the peak Settlement Periods, with this
effect being greater in 2015/16.
Table 2 presents imbalance volumes as a percent of Total Demand by different Party Type as categorised
using BSC Party IDs (see appendix two for classification of Party types for further detail). It can be seen that
independent Generators, Non-Physical Traders and Renewable Generators long imbalance percentages
increased significantly when comparing 2014/15 to 2015/16. This trend is being driven by a small number of
Parties within each Party type. The short imbalances remain largely consistent over the two time periods, the
only exception being non-physical traders, whose short volumes more than doubled. Again this trend is being
driven by a small number of market participants.
8 Peak periods are defined as Settlement Periods 15 to 38 for the purposes of this analysis.
Date Independent Generator Non Physical Trader Renewable Generator Supplier Vertically Integrated
14/15 0.072% 0.052% 0.043% 0.798% 1.406%
15/16 0.177% 0.188% 0.073% 1.164% 1.350%
Date Independent Generator Non Physical Trader Renewable Generator Supplier Vertically Integrated
14/15 0.125% 0.032% 0.036% 0.427% 1.337%
15/16 0.113% 0.077% 0.042% 0.498% 1.562%
Long
Short
Table 2 – Aggregated Imbalance Volume (MWh) as a percent of Total Demand by Party Type
-15
-10
-5
0
5
10
15
20
Nov Dec Jan Feb Mar AprA
cco
un
t Im
ba
lan
ce
(T
Wh
)14/15 15/16
Long
Short
Graph 14 - Aggregated long and short party imbalances
Table 1 – Aggregated long and short party imbalances (MWh) by peak and off-peak. Averaged by Settlement Period
Average Long
Volume (MWh)
Average Short
Volume (MWh)
Average Long
Volume (MWh)
Average Short
Volume (MWh)
Off-peak 5,908 5,196 7,415 6,071
Peak 8,000 6,496 9,734 7,690
14/15 15/16
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Balancing production and consumption accounts
Parties have two energy accounts – a
production account and a consumption
account – and Imbalance Volumes are
calculated separately for these.
Under a dual cash-out price, the spread
between the two prices for different kinds of
imbalances created a greater incentive to
balance each of these accounts separately.
However, since the introduction of a single
cash-out price as part of P305, any opposing
imbalances will have the same price, so the
incentive has lessened.
Graph 15 shows how daily gross Imbalances Volumes have changed over time. Following October 2015, both
the production and consumption accounts have been on an upward trajectory, suggesting greater Imbalance
Volumes.
Graph 15 – Daily gross imbalance volumes by account
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
2014 2015 2016M
Wh
Production Consumption
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P305 and intra-day liquidity The P305 Workgroup expressed mixed
feelings as to whether P305 would have a
beneficial or detrimental impact on liquidity
in the wholesale market.
Graph 16 shows Market Index Volumes
(MIV) as a measure of liquidity in the spot
markets from November 2015 to April 2016,
compared to the same time period of the
preceding year. These are volumes of trades
submitted by the Market Index Data
Provider(s) and reflect how much trade
occurred for the weighted products as
defined in the Market Index Definition
Statement (MIDS). They do not, therefore,
show total market liquidity, but can be used to give an indication of the level of trading before Gate Closure.
Using this metric, traded volumes have not changed significantly, with average volumes per day over the
2014/15 period as 35,587 MWh and 35,151 MWh over the 2015/16 period.
Graph 16 –Market index data traded volumes by day
0
10000
20000
30000
40000
50000
60000
70000
05/1
1/2
014
19/1
1/2
014
03/1
2/2
014
17/1
2/2
014
31/1
2/2
014
14/0
1/2
015
28/0
1/2
015
11/0
2/2
015
25/0
2/2
015
11/0
3/2
015
25/0
3/2
015
08/0
4/2
015
22/0
4/2
015
Vo
lum
e (
MW
h)
2014/15 2015/16
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3. OVERVIEW OF PRICE TRENDS
This section provides an overview of imbalance prices in the 6 months since the implementation of P305, as
well as prices recalculated using two different pricing scenarios:
● The P217 Price Scenario – the price calculation that was used before P305 was implemented.
● The November 2018 Price Scenario – the price calculation that will be used from 1 November
2018
For historic analysis we compare prices when the System is Long (“Long System Price”) and Short (“Short
System Price”) to capture the impact of the changes that made the cash-out price ‘more marginal.’
Overview of System Prices since the implementation of P305
Graph 17 shows the monthly average System Prices since P305 was implemented, as well as System Prices
when the system was short and when the
system was long. Average long System
Prices have decreased since November 2015
and short System Prices have increased. The
average price has been between
approximately £35/MWh and £40/MWh.
Tables 3 and 4 shows an overview of
System Prices since 5 November 2015, split
by a long and short system.
0
10
20
30
40
50
60
70
80
Nov Dec Jan Feb Mar Apr
2015 2016
Syst
em
Pri
ce
(£
/M
Wh
)
Long System Short System Average price
Graph 17 - Monthly average System Prices over time
Table 4 – Overview of long prices
Date Min (£/MWh) Max (£/MWh) Mean (£/MWh) Standard Deviation (£/MWh)
Nov-15 -39.96 40.00 27.27 6.65
Dec-15 -73.48 42.00 26.67 10.94
Jan-16 -35.00 43.29 27.12 6.78
Feb-16 -59.95 38.00 23.98 6.04
Mar-16 -63.02 39.70 21.92 10.03
Apr-16 -39.19 40.00 22.33 5.54
Table 3 – Overview of short prices
Date Min (£/MWh) Max (£/MWh) Mean (£/MWh) Standard Deviation (£/MWh)
Nov-15 18.43 178.00 53.15 19.69
Dec-15 39.00 140.00 53.53 15.33
Jan-16 33.17 225.00 57.24 27.40
Feb-16 30.00 151.00 54.92 21.67
Mar-16 21.10 517.55 71.66 59.27
Apr-16 30.46 161.19 59.20 30.41
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System Prices since P305 implementation compared to 2014/15
This section looks at System Prices since
the implementation of P305 and
compares these to historic System Prices.
Any differences will be a result of a
combination of the changes to the cash-
out price calculation as well as any
changes to market fundamentals.
Graph 18 shows the average System
Price (averaging SSP and SBP in both
directions pre-305) from November 2014
to April 2016. Using this measure, the
average price of imbalance has fallen
since the introduction of P305 from
£41.70/MWh in October 2015 to
£36.10/MWh in April 2016.
Graph 19 shows the frequency of System Prices occurring within defined price bands in 2014/15 compared to
2015/16. In 2015/16, most System Prices were between £20 and £30/MWh, whereas in 2014/15 prices were
more frequently between £30 and £40/MWh.
Graph 19 – Frequency of System Prices
0
1000
2000
3000
4000
5000
6000
-10+
-10 -
0
0 -
10
10 -
20
20 -
30
30 -
40
40 -
50
50 -
60
60 -
70
70 -
80
80 -
90
90 -
100
100+
Fre
qu
en
cy
System Prices (£/MWh)
14/15 15/16
Graph 18 – Average System Price (long and short)
0
10
20
30
40
50
60
Nov
Dec
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
2014 2015 2016
Syste
m P
rice
(£
/M
Wh
)
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Graphs 20 and 21 focus on the more extreme prices – above £70/MWh and less than £0/MWh. Eight
instances of prices greater than £250/MWh were seen in the 2015/16, whereas the highest price in 2014/15
was £173.71/MWh. The same trend is seen for the negative prices, with a lowest price of -£73.48/MWh in
2015/16 compared to -£57.26/MWh in 2014/15.
Graph 20 – Frequency of high System Prices
Graph 21 – Frequency of Low System Prices
0
20
40
60
80
100
120
70 -
80
80 -
90
90 -
100
100 -
110
110 -
120
120 -
130
130 -
140
140 -
150
150 -
160
160 -
170
170 -
180
180 -
190
190 -
200
200 -
210
210 -
220
220 -
230
230 -
240
240 -
250
250+
Fre
qu
en
cy
System Prices (£/MWh)
14/15 15/16
0
5
10
15
20
25
30
35
40
-80+
-80 -
-70
-70 -
-60
-60 -
-50
-50 -
-40
-40 -
-30
-30 -
-20
-20 -
-10
-10 -
-0.0
1
Fre
qu
en
cy
System Prices (£/MWh)
14/15 15/16
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Comparison of System Prices using different price scenarios
This section compares live prices with two different pricing scenarios. First, we consider what prices would look
like with the P217 (pre-P305) price calculation to highlight the impact of P305. Before the implementation
of P305, the price calculation had:
● A PAR of 500MWh and an RPAR of 100MWh;
● No non-BM STOR volumes or prices included in the price stack;
● No RSP, and instead a Buy Price Adjuster (BPA) that recovers STOR availability costs; and
● No Demand Control, Demand Side Balancing Reserve (DSBR), or Supplementary Balancing Reserve
(SBR) actions priced at VoLL.
Graph 22 shows the average System Price when the system was short using the two calculations by
Settlement Period from November 2015 to April 2016. Graph 23 shows the same when the system was long.
Graph 24A and Graph 25A show the same price data displayed as a function of distribution.
0
5
10
15
20
25
30
35
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46
Syste
m P
rice
(£
/M
Wh
)
Settlement Period
Average of Live Price Average of P217
Graph 23 – Average long System Price
0
20
40
60
80
100
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46Syste
m P
rice
(£
/M
Wh
)
Settlement Period
Average of Live Price Average of P217
Graph 22 – Average short System Price
0
1000
2000
3000
4000
5000
-80 -
-70
-70 -
-60
-60 -
-50
-50 -
-40
-40 -
-30
-30 -
-20
-20 -
-10
-10 -
0
0 -
10
10 -
20
20 -
30
30 -
40
40 -
50
50 -
60
60 -
70
70 -
80
80 -
Fre
qu
en
cy
System Price (£/MWh)
Live P217
Graph 24A – Average short System Price
0
500
1000
1500
2000
10 -
20
30 -
40
50 -
60
70 -
80
90 -
100
110 -
120
130 -
140
150 -
160
170 -
180
190 -
200
Fre
qu
en
cy
System Prices (£/MWh)
Live P217
Graph 25A – Average long System Price
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Graph 26 shows the magnitude of these price changes (there was no price change in 17.7% of Settlement
Periods).
On average, P305 prices were lower than P217 prices when the system was longer and higher when the
system was short. However there were some exceptions to this – 26.78% of live prices when the system was
short were lower than pre-305 prices. These differences were driven by the removal of the portion of the Buy
Price Price Adjuster (BPA) that was used to recover STOR availability fees. The proportion of the BPA related to
STOR availability fees was removed when the RSP was introduced with P305.
Graph 26 - P217 scenario System Price changes
0
500
1000
1500
2000
2500
3000
3500
4000
4500
-20+
-20 -
-15
-15 -
-10
-10 -
-5
-5 -
0
0 -
5
5 -
10
10 -
15
15 -
20
20 -
25
25 -
30
30 -
35
35+
Fre
qu
en
cy o
f P
rice
Ch
an
ge
System Price changes (£/MWh)
Long Short
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November 2018 scenario
The November 2018 Scenario is intended to reflect the effect of changes to the imbalance price parameters
that are due to come in on 1 November 2018. These are:
● A reduction in the PAR value to 1MWh (RPAR will remain at 1MWh); and
● An increase in the VoLL to £6,000/MWh, which will apply to all instances of VoLL in arrangements,
including the RSP function.
A ‘dynamic’ LOLP function will also be introduced from November 2018, but we have been unable to capture
the impact of this in the pricing scenario.
Graphs 27 and 28 show System Prices from November 2015 to April 2016 recalculated using the November
2018 scenario. Prices are always lower when the system is long under the November 2018 scenario and higher
when the system is shorter. Graph 29A and Graph 30A show the differences between the live scenario and
the November 2018 scenario at Settlement Period level.
0
1
2
3
4
5
6
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46
Pri
ce
Ch
an
ge
(£
/M
Wh
)
Settlement Period
Graph29A– Average short difference in System Prices
0
5
10
15
20
25
30
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46Syste
m P
rice
(£
/M
Wh
)
Settlement Period
Live Price Nov-18 Price
Graph 28 - Average long System Prices
0
20
40
60
80
100
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46
Syste
m P
rice
(£
/M
Wh
)
Settlement Period
Live Price Nov-18 Price
Graph 27 - Average short System Prices
-1.2
-1
-0.8
-0.6
-0.4
-0.2
0
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46
Pri
ce
Ch
an
ge
(£
/M
Wh
)
Settlement Period
Graph 30A– Average long difference in System Prices
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Graph 31 shows the magnitude of price changes, excluding those Settlement Periods where there were no changes (58% of all Settlement Periods).
0
500
1000
1500
2000
2500
-20+
-20 -
-15
-15 -
-10
-10 -
-5
-5 -
- 0
0 -
5
5 -
10
10 -
15
15 -
20
20+
Fre
qu
en
cy o
f P
rice
Ch
an
ge
System Price changes (£/MWh)
Long Short
Graph 31 – November 2018 scenario price changes
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P305 and price volatility
The removal of the dual cash-out price, in
combination with the changes to PAR making
prices ‘more marginal’, may have impacted the
price volatility faced by Parties.
The single System Price reflects the cost of the
underlying sell actions when the system is long,
and buy actions when the system is short.
Because of the difference between the prices of
buy and sell actions, there can be a material price
change when the system changes direction. On
average the price impact of the NIV ‘flipping’
direction is around £20/MWh.
An example of this is illustrated by Graph 32,
which shows the impact on prices when the
system direction changed from long to short on
21 April 2016. The system was only short for
three Settlement Periods on that day – 35, 36 and
37 – and the price was £108/MWh in each of
these.
Before P305, the Market Index Price was paid to
or by Parties with imbalances in the opposite
direction to the system. The Market Index Price
acted as a ‘buffer’ when the system changed
direction but the Parties’ imbalance hadn’t.
This can be illustrated by looking at the standard
deviation of prices. Graph 33 shows the monthly
standard deviation of prices that would have been
faced by a Party who was always short (“Short Party Price”), compared to the standard deviation of prices
when the system was short (“Short System
Price”).
Graph 34 shows the standard deviation of prices
that would have been faced by a Party who was
always long (“Long Party Price”), compared to
the standard deviation of prices when the system
was long (“Long System Price”). This shows
the increased price volatility in prices paid to
Parties with long imbalances following the
implementation of P305.
-1000
-800
-600
-400
-200
0
200
400
0
20
40
60
80
100
120
1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46
NIV
(M
Wh
)
Syste
m P
rice
(£
/M
Wh
)
NIV (MWh) System Price
Graph 32 – System Price plotted against the NIV for 21 April 2016
Graph 33 – Standard deviation of System Prices for a Short system and for a Party that is Short (Short Party Price)
Graph 34 - Standard deviation of System Prices for a Long system and for a Party that is Long (Long Party Price)
0
10
20
30
40
50
60
70Ja
n
Mar
May
Jul
Sep
Nov
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
2014 2015 2016
Sta
nd
ard
De
via
tio
n (
£/M
Wh
)
Short System Price Short Party Price (SBP)
0
5
10
15
20
25
30
35
40
45
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
May
Jul
Sep
Nov
Jan
Mar
2014 2015 2016
Sta
nd
ard
De
via
tio
n (
£/M
Wh
)
Long System Price Long Party Price (SSP)
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4. IMPACT ON PARTIES TRADING CHANGES
This section provides impact analysis on BSC Parties’ Trading Charges (specifically, Imbalance Charges and
Residual Cashflow Reallocation Cashflow) by comparing live prices with the P217A and November 2018 pricing
scenarios. Note that this analysis does not take into account of behavioural changes.
The impacts on Parties are presented in daily £/MWh (positive numbers indicate a Party is worse off and
negative numbers indicating a Party is better off), which is derived from changes in £ charges divided by the
absolute Credited Energy Volume traded by Parties.
The impact analysis is broken down by BSC Party types (based on our best knowledge, see appendix two for
further information), including vertically integrated players, independent generators, renewable generators,
independent suppliers and non-physical traders. This allows us to see how different types of participants are
impacted under different pricing scenarios.
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P217 Price scenario
This analysis compares Parties’ charges using live prices against P217A prices (i.e. prices had P305 not been
introduced). The impacts (£/MWh) can be seen in Table 5 below. Note that positive impacts represent Parties
being ‘worse off’ and negative impacts represent Parties being ‘better off’ as result of P305 when compared
against P217A scenario.
Year Month Type of Party
Mean Imbalance
charge impact
(£/MWh)
StdDev of Imbalance
charge impact
(£/MWh)
Mean RCRC
impact
(£/MWh)
StdDev
RCRC
impact
(£/MWh)
2015 Nov Independent Generator 0.05 0.16 -0.04 0.08
Non Physical Trader 0.25 1.29 0.00 0.02
Renewable Generator 4.58 5.95 -0.03 0.08
Supplier 1.24 3.26 -0.07 0.08
Vertically Integrated 0.48 2.25 -0.02 0.07
Dec Independent Generator 0.06 0.20 -0.04 0.08
Non Physical Trader 0.45 2.58 0.00 0.02
Renewable Generator 2.05 3.53 -0.02 0.14
Supplier 1.13 2.97 -0.06 0.09
Vertically Integrated 0.37 6.38 -0.02 0.09
2016 Jan Independent Generator 0.11 1.32 -0.03 0.10
Non Physical Trader 0.34 1.82 0.00 0.02
Renewable Generator 4.67 6.75 -0.03 0.09
Supplier 1.58 5.42 -0.07 0.08
Vertically Integrated 0.47 2.85 -0.02 0.09
Feb Independent Generator 0.06 0.27 -0.04 0.07
Non Physical Trader 0.38 1.63 0.00 0.02
Renewable Generator 4.60 6.17 -0.03 0.07
Supplier 1.25 3.15 -0.07 0.07
Vertically Integrated 0.47 1.95 -0.02 0.07
Mar Independent Generator 0.06 0.37 -0.04 0.14
Non Physical Trader 0.44 2.35 0.00 0.03
Renewable Generator 6.89 12.06 -0.05 0.16
Supplier 1.83 5.36 -0.10 0.13
Vertically Integrated 0.59 2.93 -0.03 0.14
Apr Independent Generator 0.30 1.30 -0.05 0.09
Non Physical Trader 0.38 4.58 0.00 0.02
Renewable Generator 7.14 11.77 -0.06 0.12
Supplier 1.60 4.69 -0.10 0.10
Vertically Integrated 0.55 2.55 -0.04 0.09
Table 5 - Average impact on Trading Charges with changing Pricing Arrangements
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Graph 35 shows the means and standard deviations of Imbalance Charge and RCRC impacts (in £/MWh) for
different types of Parties, during different time periods.
Graph 35 – Difference in Imbalance and RCRC Charges between P305 pricing and P217
Imbalance Charge impacts
The majority of Parties have incurred additional Imbalance Charges following the implementation of P305.
However the magnitude of the average increase in Imbalance Charges was £2/MWh for the majority of Parties,
except for renewable generators.
Standard deviation is a measure how scattered (or varied) the data can be away from its mean value in both
directions. The standard deviation of Imbalance Charge impact on renewables generators appeared to the
highest amongst all, suggesting more variation in Imbalance Charges (in both directions) for these Parties.
This is the followed by Suppliers, whose charges are more uncertain due to the nature of NHH customer
consumption. In contrast, the Imbalance Charge impacts on independent generators are of less variance.
The seasonal effect did not appear to be obvious, as Parties did not incur more Imbalance Charges in the
winter months (i.e. December to February), which may have been due to the mild winter in 2015/6. However
there has been an increase in charges in March and April 2016, likely to be due to the prolonged ‘winter’ and
unusually low temperature.
Residual cash-flow reallocation cashflow (RCRC) payments also increased by £0.10/MWh on a monthly average
basis.
-0.20
1.80
3.80
5.80
7.80
9.80
11.80
13.80
Independent
Genera
tor
Non P
hys
ical Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hys
ical Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hys
ical Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hys
ical Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hys
ical Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hys
ical Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Nov Dec Jan Feb Mar Apr
2015 2016
Pri
ce
Ch
an
ge
(£
/M
Wh
)
Mean Imbalance charge impact (£/MWh) Mean RCRC impact (£/MWh)
StdDev of Imbalance charge impact (£/MWh) StdDev RCRC impact (£/MWh)
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Impacts on renewable generators
Graph 36 the trading charges impact for renewable generators on a monthly average basis.
Graph 36 – Renewable generators imbalance charge impact on changing pricing arrangements
Out of the 13 renewable generators included in this analysis, one Party had very poor balancing performance
due to ‘spilling’ with no contracts in place. P305 has reduced the imbalance payment they have received by up
to £28/MWh in April. Seven other renewable generators have been impacted by around £7/MWh on average
throughout the analysis period, whereas the remaining Parties were impacted by less charges, which ranges
between £0 to £7/MWh.
-0.1
4.9
9.9
14.9
19.9
24.9
29.9
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
Nov
Jan
Mar
2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015 2016
Party A Party B Party C Party D Party E Party F Party G Party H Party I Party J Party K Party L Party M
Imp
act
(£/M
Wh
)
Average imbalance charge impact Average RCRC impact
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November 2018 price scenario
This analysis compares Parties’ charges using live prices against the November 2018 price scenario.
The numerical statistics of impacts (£/MWh) can be seen in the table below. Note that positive impacts
represent ‘worse off’ and negative impacts represents ‘better off’ as result had the full package of P305 been
implemented when compared against the live scenario9.
9 For avoidance of doubt, these statistics reflect further charge increase/decrease on top of the live charges, not P217A charges. Therefore
this is not a direct comparison to P217A charges, which is not within the scope of this analysis.
Year Month Type of Party
Mean
imbalance
impact
StdDev
imbalance
impact
Mean RCRC
impact
StdDev
RCRC
impact
2015 Nov Independent Generator 0.05 0.20 -0.03 0.08
Non Physical Trader 0.25 1.29 0.00 0.02
Renewable Generator 4.85 6.57 -0.03 0.08
Supplier 1.28 4.32 -0.06 0.11
Vertically Integrated 0.50 2.45 -0.02 0.08
2015 Dec Independent Generator 0.06 0.22 -0.04 0.09
Non Physical Trader 0.45 2.64 0.00 0.02
Renewable Generator 2.15 4.00 -0.01 0.14
Supplier 1.31 4.11 -0.06 0.10
Vertically Integrated 0.38 6.44 -0.02 0.09
2016 Jan Independent Generator 0.11 1.33 -0.03 0.10
Non Physical Trader 0.33 1.84 0.00 0.02
Renewable Generator 4.83 7.16 -0.02 0.09
Supplier 1.58 5.53 -0.06 0.08
Vertically Integrated 0.45 3.20 -0.02 0.10
2016 Feb Independent Generator 0.06 0.29 -0.04 0.07
Non Physical Trader 0.38 1.65 0.00 0.01
Renewable Generator 4.86 6.95 -0.03 0.07
Supplier 1.22 3.53 -0.06 0.07
Vertically Integrated 0.48 2.11 -0.02 0.07
2016 Mar Independent Generator 0.06 0.41 -0.03 0.13
Non Physical Trader 0.44 2.39 0.00 0.02
Renewable Generator 7.23 13.03 -0.04 0.16
Supplier 1.86 5.79 -0.09 0.13
Vertically Integrated 0.62 3.20 -0.03 0.14
2016 Apr Independent Generator 2.25 9.88 -0.04 0.11
Non Physical Trader 0.32 6.17 0.00 0.02
Renewable Generator 7.26 15.60 -0.05 0.11
Supplier 1.56 5.08 -0.09 0.10
Vertically Integrated 0.55 2.73 -0.03 0.08
Table 6 – Average impact on Trading Charges with changing the Pricing Arrangements to the November 2018 scenario
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Graph 37 displays the means and standard deviations of Imbalance Charge and RCRC impacts (in £/MWh) for
different types of Parties, during different time periods.
Graph 37 - Difference in Imbalance and RCRC Charges between P305 November 2018 pricing and live prices
Imbalance charge impacts
The November 2018 pricing scenario resulted in additional Imbalance Charges for BSC Parties. We have seen a
similar trend to the P217A scenario analysis that the overall impacts have not been significantly high. For the
majority types of Parties the average impacts of Imbalance Charge are limited to £2/MWh, with the exception
of renewable generators. Standard deviations of Imbalance Charge impacts have shown a similar trend as per
P217A analysis that renewable generators and Suppliers had more varied impacts on Imbalance Charges.
The average Imbalance Charge impact on independent generators appeared to be unexpectedly high in April
2016, with a high standard deviation. This was due to a new entrant Party having proportionally large
Imbalance Volumes (i.e. ‘spilling’ with no contract), which drove up the average figures. The impact analysis
suggests that this Party is ‘worse off’ in the winter 2018 scenario comparing to the live scenario, due to less
imbalance cashflow received.
RCRC impacts
PAR1 would have increased the total imbalance cashflow as well as Total Residual Cashflow across the
industry, and therefore, on average, Parties would have received more RCRC payment. The net impact on
RCRC would have been limited to £0.09/MWh during the analysis period.
-0.20
1.80
3.80
5.80
7.80
9.80
11.80
13.80
15.80
17.80
Independent
Genera
tor
Non P
hysi
cal Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hysi
cal Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hysi
cal Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hysi
cal Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hysi
cal Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Independent
Genera
tor
Non P
hysi
cal Tra
der
Renew
able
Genera
tor
Supplie
r
Vert
ically
Inte
gra
ted
Nov Dec Jan Feb Mar Apr
2015 2015 2016 2016 2016 2016
Pri
ce
Ch
an
ge
(£
/M
Wh
)
Mean imbalance impact Mean RCRC impact StdDev imbalance impact StdDev RCRC impact
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5. PARAMETER ANALYSIS
This section considers the more detailed aspects of imbalance pricing. We consider:
● The impact of moving to a smaller Price Average Reference (PAR), on the number actions setting
the price, in the pre-P305, live and November 2018 Scenarios
● Incidents of the Reserve Scarcity Price during the period, and how these relate to the
Utilisation Prices of Short Term Operating Reserve (STOR) balancing capacity
● De-Rated Margins (DRMs) across the period and National Grid’s forecasts of these
● The impact of including non-BM STOR volumes in the System Price calculation
Reduction in the Price Average Reference (PAR) Value
The Price Average Reference (PAR) volume is used to tag balancing actions such that a maximum volume of
PAR MWh is used to set the Energy Imbalance Price. The value of PAR P305 introduced was 50MWh, from
500MWh previously.
The P305 workgroup noted concerns that a smaller PAR value could amplify any errors or inefficiencies in the
current calculation, as there would be a smaller number of actions setting the price. Potential errors or
inefficiencies included:
● Incorrect flagging of the prices of system balancing actions by the Transmission Company; or
● The impact of plant dynamics, leading to a high-priced Offer being accepted in one Settlement
Period to resolve an issue at that time, because of the BMU’s physical abilities, the Offer may have
to persist for a longer period, impacting future Settlement Periods where a lower-priced Offer
would otherwise have been accepted.
Table 7 shows how many
balancing actions were left in the
PAR in the assessment period and
how this compares to the pre-305
PAR (500MWh) and the
November 2018 PAR (1MWh)10.
This shows that the average
number of actions in the PAR
decreases as the PAR value
decreases. It also shows that the
number of Settlement Periods
with only one action setting the price increases as the PAR value decreases. In the PAR50 and PAR1 scenarios,
the most frequent number of actions setting the price was 1 (although the frequency was greater in the PAR1
scenario).
The potential for erroneous system flags was mentioned as a concern during the P305 workgroup. National
Grid’s system flagging process is the ex-ante identification of BMUs or individual actions which could potentially
10 Separate actions from the same BMUs within a Settlement Period were treated as a single action for the purposes of this analysis.
Table 7 - Average number of balancing actions left in PAR
Average
number of
actions in the
PAR
Most frequent
number
of actions in the
PAR
Max number of
actions
in the PAR
Proportion of
SP's with only
one action in
the PAR
PAR500
(P217a) 5.19 2.00 23.00
13%
PAR50 (live) 2.40 1.00 23.00 37%
PAR1 (Nov-18) 1.63 1.00 23.00 69%
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be classified as system balancing actions (eg actions that were taken to
resolve locational constraints). The process for this is set out in their
System Flagging Methodology (SMAF) document11.
If the Transmission Company or another Party identifies an action which
should have been SO-flagged (or erroneously received an SO flag) these
can be corrected using the BSCP18 process. This must be brought to the
attention of the Transmission Company a minimum of eight Working
Days before the SF Settlement Run. Table 8 shows the number of
corrections to a System Flag since the implementation of P305.
11 This is one of the Transmission licence C16 statements, and can be found at: http://www2.nationalgrid.com/uk/industry-information/electricity-codes/balancing-framework/transmission-
license-c16-statements/
Table 8 – Number of flags resubmitted by National Grid
MonthIncidents of flags
resubmitted
November 26
December 12
January 8
February 3
March 5
April 0
Total 59
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De-Rated Margin (DRM), Loss of Load Probability (LoLP) and the Reserve Scarcity Price
P305 introduced the Reserve Scarcity Price (RSP)
which uplifts the prices of STOR balancing
capacity when it is higher than the capacity’s
original Utilisation Price.
The RSP is designed to respond to capacity
margins so that it rises as the system gets tighter
(ie the gap between available and required
generation narrows). It is a function of De-Rated
Margin (DRM) at Gate Closure, the likelihood that
this will be insufficient to meet demand (the Loss
of Load Probability, LoLP) and the Value of Lost
Load (VoLL, currently set at £3,000/MWh). The System Operator has determined a relationship between each
DRM and the LoLP which will determine the RSP12.
Graph 38 shows the daily minimum and average De-rated margin since data was available (7 March 2016).
Table 9 shows the LoLPs and RSPs that the 10 lowest DRMs equated to13. The System was long in six of these
ten Settlement Periods, with all System Prices in these Settlement Periods less than £24.10/MWh.
12
The methodology for LOLP is set out in the LOLP Methodology statement: https://www.elexon.co.uk/wp-
content/uploads/2014/10/37_244_11A_LOLP_Calculation_Statement_PUBLIC.pdf 13 Due to data issues (see appendix 3) DRM, LOLP and RSP data was only operational from Settlement Period 27 on 7 March 2016.
Date SPDRM
(MW)LoLP RSP RSP Used
System
Length
System Price
(£/MWh)
10/03/2016 37 1,496.48 0.0163 48.88 No Short 377.55
10/03/2016 38 1,582.23 0.0119 35.73 No Short 517.55
19/04/2016 36 1,800.67 0.0050 15.13 No Long 24.10
07/03/2016 37 1,813.48 0.0048 14.40 No Short 135.00
08/04/2016 19 1,832.39 0.0044 13.30 No Long 24.03
15/04/2016 18 1,855.79 0.0040 12.02 No Short 131.80
19/04/2016 37 1,864.40 0.0039 11.62 No Long 24.10
20/03/2016 39 1,881.98 0.0036 10.76 No Short 151.38
19/04/2016 38 1,887.13 0.0035 10.54 No Long 24.56
07/03/2016 39 1,965.74 0.0025 7.46 No Short 98.42
Graph 38 - Daily Minimum and average DRMs
0
2000
4000
6000
8000
10000
12000
14000
16000
07-M
ar
10-M
ar
13-M
ar
16-M
ar
19-M
ar
22-M
ar
25-M
ar
28-M
ar
31-M
ar
03-A
pr
06-A
pr
09-A
pr
12-A
pr
15-A
pr
18-A
pr
21-A
pr
24-A
pr
27-A
pr
30-A
pr
MW
Min of De-rated Margin Average of De-rated Margin
Table 9 – Ten lowest De-Rated Margins and corresponding Reserve Scarcity Prices
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The RSP will then be used to re-price STOR actions in the Imbalance Price calculation if it is higher than the
original Utilisation Price of the STOR capacity. No STOR actions were re-priced using the RSP in 2015/16, as
RSPs did not exceed STOR Utilisation Prices in any periods; the lowest STOR Utilisation Price seen was
£63.92/MWh. Graph 39 shows the ‘merit order’ of STOR Utilisation Prices from 7 March 2016 to 30 April 2016,
with the highest RSP of £48.88/MWh shown.
£48.88/MWh
0
100
200
300
400
500
600
0 2000 4000 6000 8000 10000 12000 14000
Uti
lisa
tio
n P
rice
(£
/M
Wh
)
Rank of actions
BM Non-BM Highest RSP
Graph 39 – Utilisation Prices of STOR plant, split by BM and non-BM capacity
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DRM as an informational tool
National Grid’s one hour forecast of DRM is the value used to set the LoLP and therefore the RSP. Indicative
forecasts of DRM and LoLP are also available from eight, four and two hours ahead of the start of each
Settlement Period, and values are also calculated at 12:00 each day for all Settlement Periods up to the end of
the next Operational Day (defined under the Grid Code as the period from 05:00 on one day to 05:00 on the
following day) for which Gate Closure has not yet passed.
These forecasts may act as an additional
informational tool for market participants
to drive balancing and prices in the
Balancing Mechanism, particularly when
margins are low. With the limited data
available, we considered whether DRMs
appear to have had an impact on System
Prices.
Graph 40 shows DRM plotted against
System Price for a short System. A weak
correlation can be seen. Prices become
higher as the DRM becomes lower but
there are many other factors affecting the
price. For example, the length of the NIV
and the time of day.
We also considered how the forecasts of
the five lowest DRMs evolved across the
different forecasts, see Graph 41. In the
case of the five lowest 1 Hour Ahead DRM
submissions, the difference from the 8
Hour Ahead submissions can appear quite
substantial. This is specifically the case for
the two lowest 1 Hour Ahead DRMs (SP 37
and SP38 on 10 March) which were below
500MWh at the 8 Hour Ahead submissions
and ended up circa 1,500MW by the time
of the 1 Hour Ahead submissions. Note
that the System Price for these two
Settlement Periods reached £377.55/MWh
and £517.55/MWh for SP37 and SP38
respectively.
Graph 40 – DRM plotted against System Price, where the System is short, with a logarithmic trend line added
0
100
200
300
400
500
600
0 5000 10000 15000 20000 25000
Syst
em
Pri
ce (
£/M
Wh
)
DRM
Log. (System Price)
Graph 41 - Five lowest DRM forecast variations throughout each submission
0
500
1000
1500
2000
2500
3000
DRM 8 HourAhead
DRM 4 HourAhead
DRM 2 HourAhead
DRM 1 HourAhead
De
-Ra
ted
Ma
rgin
(M
W)
10Mar-16 (SP 37) 10Mar-16 (SP 38)19Apr-16 (SP 36) 08Apr-16 (SP 19)15Apr-16 (SP 18)
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Graph 42 highlights the difference in DRM values between the indicative submissions (8, 4 and 2 Hour Ahead)
and the final one (1 Hour Ahead), which will set the LoLP.
As highlighted in the graph, the lower the final DRM is, the less accurate the previous submissions are. The 8
Hour Ahead is, on average, the least accurate (an average of 869.07MW from the final value), whilst the 2
Hour Ahead is, on average, the closest to the final 1 Hour Ahead submission (an average of 240.85MW from
the final value). These differences can highlight the difficulties to predict real time margin values and the level
of uncertainty brought by lower margins. However, the graph also indicates that when the final DRM
submissions are at their lowest levels (<2000MW), the difference with earlier submissions are below average
with an average difference of 787.97MW for the 8 Hour Ahead submissions.
Most variation in values came when final DRMs were between 5000MW and 10000MW. Most final DRM
submissions (43.2%) fell within this range.
Graph 42 - Correlation between accuracy of submissions and DRM values
-4000
-3000
-2000
-1000
0
1000
2000
3000
4000
5000
6000
0 5000 10000 15000 20000 25000
Dif
fere
nce
be
twe
en
su
bm
issio
ns a
nd
1
Ho
ur
Ah
ea
d D
RM
(M
W)
1 Hour Ahead DRM submissions (MW)
8 Hour Ahead Vs. 1 Hour Ahead 4 Hour Ahead Vs. 1 Hour Ahead
2 Hour Ahead Vs. 1 Hour Ahead
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The impact of including non-BM STOR volumes in the System Price calculation
Non-Balancing Mechanism Short Term
Operating Reserve (Non-BM STOR) is
reserve capacity that is not dispatched in
the Balancing Mechanism (BM). It can be
used by the SO to balance the system
during STOR Availability Windows. P305
introduced changes to include volumes and
prices for non-BM STOR actions in the stack
of balancing actions used to determine the
imbalance price. In addition to this, non-BM
STOR may be re-priced using the Reserve
Scarcity Price (RSP). Just under 3% of total buy balancing actions taken during the assessment period were
STOR actions. Of these, 70% came from
non-BM STOR plant (see Graph 43).
To assess the impact of including these
non-BM STOR volumes we re-ran the price
calculation without non-BM volumes.
Including non-BM STOR volumes had a
marginal impact on average System Prices
– prices were unchanged in 98% of long
Settlement Periods and 93% of short
Settlement Periods. However, there were
incidents of more material impact – the
inclusion of non-BM STOR volumes caused
the system to ‘flip’ from being net long to
net short in 24 Settlement Periods across
the period.
Graph 44 shows the price changes of
including non-BM in the price stack (when
there was a price change).
The price impact of including non-BM STOR
can also be seen in Graph 45 which shows
average System Prices by Settlement Period
when non-BM STOR was utilised.
Graph 44 - Price changes - non-BM STOR
0
10
20
30
40
50
60
<1
1 -
2
2 -
3
4 -
5
6 -
7
7 -
8
8 -
9
9 -
10
10 -
15
15 -
20
20 -
30
30 -
40
40 -
50
50 -
90
Co
un
t o
f S
ett
lem
en
t P
eri
od
s
Change in price (£/MWh)
Long Short
Graph 43 – BM STOR and no-BM STOR volumes used
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
Nov
Dec
Jan
Feb
Mar
Apr
2015 2016V
olu
me
of
acti
on
s (
MW
h)
BM STOR Non-BM STOR
Graph 45 – Price impact of including non-BM STOR in the price stack, in Settlement Periods when non-BM STOR was used
0
20
40
60
80
100
120
140
160
180
1 2 3 4 5 6 7 8 9 10111213141516171819202122232425
Pri
ce
(£
/M
Wh
)
Live System Prices - Long No NBM STOR - Long
Live System Prices - Short No NBM STOR - Short
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LIST OF APPENDICES
1. Glossary
2. Classification of Party types
3. Summary of data issues
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APPENDIX ONE - GLOSSARY
Term Abbrev. Definition
Bid A proposed volume band and price within which the registrant of a BM Unit is willing to
reduce generation or increase consumption (i.e. a rate below their FPN).
Bid/Offer
Acceptance
BOA A Bid or Offer within a given Settlement Period that was Accepted by the SO. BOAs are
used in the imbalance price calculation process e.g. to calculate NIV or the System Price.
Offer A proposed volume band and price within which the registrant of a BM Unit is willing to
increase generation or reduce consumption (i.e. a rate above their FPN).
System Price A price (in £/MWh) calculated by BSC Central Systems that is applied to imbalance
volumes of BSC Parties. It is a core component of the balancing and settlement of electricity in GB and is calculated for every Settlement Period. It is subject to change via
Standard Settlement Runs.
Replacement Price
A price (in £/MWh) calculated by BSC Central Systems that is applied to volumes that are not priced during the imbalance pricing process (detailed in BSC Section T) It is calculated
for every Settlement Period, and is subject to change via Standard Settlement Runs.
Utilisation Price The price (in £/MWh) sent by the SO in respect of the utilisation of a STOR Action which: (i) in relation to a BM STOR Action shall be the Offer Price; and
(ii) in relation to a Non-BM STOR Action shall be the Balancing Services Adjustment Cost.
Market Price The Market Price reflects the price of wholesale electricity in the short-term market (in £/MWh). You can find an explanation of how it is calculated and used in the Market Index
Definition Statement (MIDS).
Reserve Scarcity Price
RSP Both accepted BM and non-BM STOR Actions are included in the calculation of System Prices as individual actions, with a price which is the greater of the Utilisation Price for
that action or the RSP. The RSP function is based on the prevailing system scarcity, and is
calculated as the product of two following values: Loss of Lost Load (LoLP), which will be calculated by the SO at Gate Closure for
each Settlement Period; and currently set to £3,000/MWh.
Replacement
Price Average Reference
RPAR The RPAR volume is a set volume of the most expensive priced actions remaining at the
end of the System Price calculation, and is currently 1MWh. The volume-weighted average of these actions, known as the Replacement Price, is used to provide a price for any
remaining unpriced actions prior to PAR Tagging.
Long In reference to market length, this means that the volume of Accepted Bids exceeds that
of Accepted Offers
Short In reference to market length, this means that the volume of Accepted Offers exceeds
that of Accepted Bid
Net Imbalance NIV The imbalance volume (in MWh) of the total system for a given Settlement Period. It is
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Volume derived by netting Buy and Sell Actions in the Balancing Mechanism. Where NIV is positive, this means that the system is short and would normally result in the SO
accepting Offers to increase generation/decrease consumption. Where NIV is negative,
the system is long and the SO would normally accept Bids to reduce generation/increase consumption. It is subject to change via Standard Settlement Runs.
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APPENDIX TWO - CLASSIFICATION OF PARTY TYPES
Party Group name Type of Party
Party Group name Type of Party
Addito Supply Limited Supplier
Gold Energy Supply Ltd Supplier
AVRO ENERGY LIMITED Supplier
Good Energy Limited Supplier
Axis Telecom Ltd Supplier
Grangemouth CHP Ltd
Independent Generator
AXPO Supplier
Greater Gabbard Offshore Winds Renewable Generator
AXPO UK LIMITED Supplier
Green Energy (UK) Plc Supplier
Baglan Operations Ltd Independent Generator
Green Network Energy Limited Supplier
Barbican Power Limited Supplier
Gwynt y Mor Offshore Wind Farm Renewable Generator
Barclays Bank plc Non Physical Trader
Hanbury Energy Supplier
BARKING POWER LIMITED Independent Generator
Haven Power Ltd Supplier
Bayswater Energy Limited Supplier
Holborn Energy Limited Supplier
BES Commercial Electricity Ltd Supplier
Hudson Energy Supply UK Ltd Supplier
Bethnal Energy Limited Supplier
I Supply Energy Limited Supplier
BKW Energie AG Non Physical Trader
Iberdrola (ScottishPower) Vertically Integrated
BNP Paribas Non Physical Trader
Inovyn Chlor Energy LTD Supplier
Bord Gais Energy Limited Non Physical Trader
Intergen
Independent Generator
BP Gas Marketing Limited Non Physical Trader
IPM Energy Retail Ltd Vertically Integrated
Breeze Energy Supply Ltd Supplier
IPM Energy Trading Limited Vertically Integrated
British Energy Direct Ltd Supplier
Iresa Limited Supplier
Bronze Energy Supply Ltd Supplier
J.Aron & Company Non Physical Trader
Brookfield Renewable Supply 2 Non Physical Trader
JP Morgan Chase Bank Non Physical Trader
BTG Pactual Commodities Non Physical Trader
Kensington Power Limited Supplier
Business Power & Gas Limited Supplier
KOCH SUPPLY & TRADING SARL Non Physical Trader
Captured Carbon Non Physical Trader
Lavender Energy Supply Ltd Supplier
Cargill PLC Non Physical Trader
Limejump Energy Limited Supplier
Carrington Power Ltd Independent Generator
Lincs Wind Farm Ltd Renewable Generator
Cenergise Limited Non Physical Trader
LOCO2 Energy Supply Limited Supplier
Centrica Vertically Integrated
London Array Limited Renewable Generator
Citigroup Global Markets Ltd Non Physical Trader
MA Energy Limited Supplier
Compagnie Nationale du Rhone Non Physical Trader
Macquarie Bank Limited Non Physical Trader
Co-operative Energy Limited Supplier
Marble Power Limited Supplier
Copper Energy Supply Ltd Supplier
Marigold Energy Supply Ltd Supplier
CORBY POWER LIMITED Renewable Generator
Mercuria Energy Trading SA Non Physical Trader
Cornflower Energy Supply Ltd Supplier
Mercury Energy Supply Ltd Supplier
Corona Energy Retail 5 Ltd Supplier
Merrill Lynch Commodities LTD Non Physical Trader
Coulomb Energy Supply Limited Supplier
Mint Energy Supply Ltd Supplier
Covent Energy Limited Supplier
Mistral Energy Supply Limited Supplier
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Post Implementation
Review
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Party Group name Type of Party
Party Group name Type of Party
Daisy Energy Supply Ltd Supplier
Morecambe Wind Limited Renewable Generator
Danske Commodities A/S Non Physical Trader
Morgan Stanley Non Physical Trader
DONG Energy Vertically Integrated
MVV Environment Services Ltd Supplier
Dong Energy Power UK Limited Vertically Integrated
NDA Supplier
Donnington Energy Limited Supplier
NEAS Energy A/S Supplier
Drax Power Ltd Independent Generator
NEAS Energy Limited Supplier
Dual Energy Direct Limited Supplier
Nickel Energy Supply Ltd Supplier
E.ON Vertically Integrated
NIE Energy Ltd Non Physical Trader
E.ON Vertically Integrated
Noble Clean Fuels Limited Non Physical Trader
ECC AG Non Physical Trader
Nord Pool Spot AS Non Physical Trader
ECONOMY ENERGY SUPPLY LTD Supplier
Northern Ireland Electricity Non Physical Trader
Economy Energy Trading Limited Supplier
Opus Energy Limited Supplier
Economy Power Supplier
Osmium Energy Supply Limited Supplier
Edelweiss Energia S.p.A Non Physical Trader
Our Power Energy Supply Ltd Supplier
EDF ENERGY Vertically Integrated
OVO Electricity Ltd Supplier
EDF Energy PLC Vertically Integrated
Paddington Power Limited Supplier
Edgware Energy Limited Supplier
Palladium Energy Supply Ltd Supplier
Effortless Energy Ltd Supplier
Petroineos Trading Ltd Non Physical Trader
Eggborough Power Limited Independent Generator
PFP Energy Supplies Limited Supplier
Electrabel SA Non Physical Trader
POWER4ALL Limited Supplier
Electricity Plus Supply Ltd Supplier
PowerQ Ltd Supplier
ElectroRoute Energy Trading Non Physical Trader
Reuben Power Supply Limited Supplier
ENDESA GENERACION SAU Non Physical Trader
Robin Hood Energy Limited Supplier
Eneco Energy Trade Supplier
RWE Npower Vertically Integrated
Enel Trade SpA Non Physical Trader
Scira Offshore Energy Limited Renewable Generator
Energi Danmark A/S Non Physical Trader
SembCorp Utilities (UK) Ltd Renewable Generator
Energy Data Company Limited Supplier
Shell Energy Europe Limited Non Physical Trader
Energy24 Limited Supplier
Silver Energy Supply Ltd Supplier
Energya VM Gestion De Energia Non Physical Trader
Sinq Power Ltd Supplier
Engie (aka GDF SUEZ) Vertically Integrated
Smartestenergy Limited Supplier
EPG Energy Limited Supplier
Snowdrop Energy Supply Ltd Supplier
Epower Supply Ltd Supplier
Spark Energy Supply Limited Supplier
Erova Energy Limited Non Physical Trader
SSE Vertically Integrated
ESB Independent Energy (NI) Non Physical Trader
Stadtwerke Munchen GmbH Renewable Generator
ESBIG Trading Ltd Non Physical Trader
Statkraft Markets Gmbh Supplier
ESSO Petroleum Company Ltd Renewable Generator
Statoil Gas Trading Ltd Renewable Generator
Extra Energy Supply Limited Supplier
Switch Business Gas and Power Supplier
F & S Energy Ltd Supplier
Symbio Energy Ltd Supplier
Fallago Rig Wind Farm Limited Renewable Generator
Tailwind Energy Supply Limited Supplier
POST IMPLEMENTATION REVIEW OF P305
Post Implementation
Review
Page 44 of 46 V2.0 © ELEXON 2016
Party Group name Type of Party
Party Group name Type of Party
Farmoor Energy Limited Supplier
Team Supplier
Farringdon Energy Limited Supplier
Tempus Energy Supply Limited Supplier
First Hydro Company Independent Generator
The Renewable Energy Co Ltd Supplier
First Utility Limited Supplier
Tornado Energy Supply Limited Supplier
Flow Energy Ltd Supplier
Total Gas & Power Ltd Supplier
Foxglove Energy Supply Ltd Supplier
Trailstone GMBH Non Physical Trader
Freepoint Commodities Europe Non Physical Trader
Tulip Energy Supply Ltd Supplier
Future Energy Utilities Ltd Supplier
Utilita Energy Limited Supplier
GAELECTRIC ICT ROI Non Physical Trader
Vattenfall Energy Trading Supplier
Gazprom M & T Retail Ltd Supplier
Vavu Power Limited Supplier
GAZPROM MARKETING & TRADING LD Supplier
VAYU LIMITED Non Physical Trader
GB Energy Supply Limited Supplier
VIRIDIAN ENERGY SUPPLY LTD Non Physical Trader
GFP Trading Ltd Renewable Generator
VITOL SA Non Physical Trader
GNERGY Limited Supplier
VPI Immingham LLP
Independent Generator
Zeven Electricity ltd Supplier
POST IMPLEMENTATION REVIEW OF P305
Post Implementation
Review
Page 45 of 46 V2.0 © ELEXON 2016
APPENDIX THREE - SUMMARY OF DATA ISSUES FOLLOWING THE IMPLEMENTATION OF P305
This note provides a summary of pricing issues related to BSC Modification P305. All of these issues have now
been resolved, and for the avoidance of doubt, no retrospective price changes will be applied.
What are LOLP and DRM?
The implementation of BSC Modification 305 on 5 November 2015 created two new parameters that are used
in the calculation of imbalance prices: De-rated Margin (DRM) and Loss of Load Probability (LOLP). DRM is a
measure of available capacity and is calculated by the System Operator at gate closure. LOLP is the likelihood
that there will be insufficient capacity to meet demand. There is a LOLP for each DRM, and LOLP is a value
between 0 and 1.
DRM and LOLP may also be used in the calculation of the imbalance price. The LOLP for a given Settlement
Period is multiplied by value of lost load (VoLL, currently set to £3,000/MWh) to determine the Reserve
Scarcity Price (RSP). The RSP can then be used to re-price some actions from balancing capacity used to
provide reserve (Short Term Operating Reserve).
What was the issue – calculation and
publication of LOLP and DRM data?
1hr forecasts of DRM and LOLP are published at
Gate Closure on BMReports for every Settlement
Period, along with 12:00, 8hr ahead, 4hr ahead
and 2hr forecasts. The 1hr forecast may also be
used in the calculation of imbalance prices, if
DRMs are low enough to drive a LOLP high enough
to result in a RSP higher than the Utilisation Price
of STOR plant.
On 26 November 2015 an issue with the data was
uncovered and, following investigation, National
Grid, in consultation with ELEXON, decided to
suspend the production of DRM and LoLP from 27
November until the cause of the issue is found and
corrected.
On 8 December 2015, National Grid implemented a fix to the issue and resumed publishing DRM and LoLP
values until 27 January 2016 when a review of the data published uncovered erroneous values being produced
since 5 November 2015. National Grid, in agreement with ELEXON and Ofgem decided to stop sending LoLP
and DRM data again until the source is identified and a permanent solution developed.
Investigation and testing completed, the reporting of DRM and LoLP started again on Monday 7 March 2016
from 12:00 midday.
Following industry consultation, National Grid decided not to re-send data for the erroneous periods and
ELEXON will not recalculate System Prices retrospectively.
Since then, the BMRA experienced several smaller issues with missing DRMs and LoLPs which were re-sent by
national Grid and the last issue was resolved on 31 March 2016.
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What was the issue with flagging of BM STOR?
In order to re-price Short Term Operation Reserve (STOR) capacity with the Reserve Scarcity Price, STOR plant
are flagged with a ‘STOR Provider Flag’. Following the implementation of P305, some STOR providers were not
being identified using the STOR Provider flag when Acceptances were reported to ELEXON.
National Grid corrected this data each day manually using a process set out in BSCP18 for amending
Acceptances after the Settlement Period in time for the SF Settlement Run or sooner. A longer term fix to this
was implemented on 7 March. There was no price impact as a result of this error.
What was the issue with reporting of non-BM STOR volumes?
Non–Balancing Mechanism STOR (Non-BM STOR) is STOR capacity that is not dispatched in the Balancing
Mechanism. P305 introduced changes to include these volumes in the stack of balancing actions used to
determine the imbalance price. However, data issues meant that these actions were reported as a single,
aggregated volume for each Settlement Period, rather than individual balancing actions. Such data issues
related to the utilisation of systems originally designed to manage the transmission system as opposed to
reporting on it.
A solution to this was implemented on 11 March 2016, and non-BM STOR volumes have since been reported
on a disaggregated basis. Overall volumes of non-BM STOR submitted do not appear to have changed as a
result, but the number of actions attributed to non-BM STOR is greater: we now receive an average of 24
individual non-BM STOR actions when it is used. The overall price impact of submitting these files on a
disaggregated basis is ambiguous, as their impact will depend on how a greater number of smaller actions
relate to other balancing actions taken in that Settlement Period.
Will prices be retrospectively changed to include the corrected data from those issues?
As mentioned in ELEXON Circular EL02398, National Grid is minded not to retrospectively apply disaggregated
volumes and re-issue this data for recalculation of System Prices. This is in response to limited industry
feedback indicating a strong direction either way. To date, ELEXON is not due to recalculate and publish
impacted System Prices retrospectively.
In any case, National Grid will provide historical disaggregated non-BM STOR utilisation volumes which will be
published on the ELEXON Portal.