Transcript 2016 06 16 - I-SEM - Rules Working Group Meeting VIII

I-SEM – Market Rules Working Group
Meeting VIII
16th June 2016
1
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
2
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
3
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
4
Scheduling & Dispatch Plain English Update
Updates:
1. Impact of SEMC decision on new date for
System Services Auctions (4.2.7)
2. Inclusion of proposed Unit Under Test
Process (4.2.12)
3. Clarification of dispatch actions resulting
from each of the scheduling and dispatch
runs (4.3.4) along with an example
(Appendix 1)
4. Update to LNAF/SIFF algebra (4.3.7)
5
Unit Under Test Introduction
Currently there are two testing mechanisms available to Participants:
1.
Full – Day Testing
• Unit Under Test for full trading day
• Testing tariffs levied
• Five working days notice required to test
• Certain unit types exempt under Trading and Settlement Code
2. Within – Day Testing
• Testing not visible in SEM
• Test duration < 6 hours
• Unit liable for uninstructed imbalances
• Testing may be facilitated on the day if low impact
6
Unit Under Test in I-SEM
A single* Under Test mechanism is proposed for I-SEM, with changes including:
•
•
•
•
•
All testing visible to the market
All Unit types follow the same process
Testing can be requested by trading periods
Modified timelines for submissions
Participants will be able to submit Commercial Offer Data
Some things that will remain unchanged:
• All testing requires the approval of the TSO
• Testing tariffs will be levied
*A separate process will be developed for managing Interconnectors Under Test
7
Types of Testing
For the purpose of under test PN submissions, testing can be categorised as
follows:
1. Significant Testing: Including commissioning new or existing units, Grid Code
testing, testing following modifications to control systems or any tests that pose an
additional risk of trip.
2. Minor Testing: Any testing that does not pose an increased risk of trip.
8
Submission Timelines for Under Test PN
Significant Testing:
• Pre-approval from TSO required 5 working days’ in advance.
• Test PN submission no later than [hh:mm TBD] day-ahead.
• Subsequent modifications / cancellations permitted no later than [hh:mm
TBD] in advance of real time.
Minor Testing:
• Pre-approval required– could be just a phone call
• Test PN submission no later than [XX hours TBD] before Balancing Market
gate closure for minor tests.
• Subsequent modifications / cancellations permitted no later than [hh:mm
TBD] in advance of real time.
9
Submission of Under Test PN
• Following pre-approval from the TSO the participant submits a PN via the MPI
specifying the periods the unit is Under Test with an appropriate test flag
• Any PN submission that includes a test flag requires manual approval by the TSO
• As part of the approval process the TSO selects the appropriate testing tariff
• No part of the PN submission will be active in the market systems until it has
been approved
• Once a PN submission with a
test flag has been approved it
is included in all subsequent
scheduling runs
• The TSO will not dispatch
away from the PN unless for
reasons of system security
From Date/Time
To Date/Time
From MW
To MW
Test Flag
03/10/2016 10:45
03/10/2016 11:15
0
150
Y
03/10/2016 11:30
03/10/2016 11:50
150
250
Y
….Etc.
….Etc.
….Etc.
….Etc.
….Etc.
03/10/2016 15:00
03/10/2016 15:50
250
0
Y
10
Example 1: Unit Follows Under Test PN
• TSO approves under test PN in
market systems and selects
testing tariff
350
300
• Unit scheduled in accordance
with under test PN
250
200
• TSO issues dispatch instructions
as per under test PN
150
100
• Unit
follows
instructions
50
0
23:00
1:00
3:00
5:00
7:00
Approved Under Test PN
9:00
dispatch
• Unit subject to imbalance price
for difference between actual
output and ex-ante traded
position (if any)
11:00 13:00 15:00 17:00 19:00 21:00 23:00
Dispatch Quantity
Actual Output
• Testing tariffs levied on actual
11
output
Example 2: Unit Tripping
• TSO approves under test PN in
market systems and selects
testing tariff
350
300
• TSO issues dispatch instructions
as per under test PN
250
200
• Normal imbalance rules applied
150
• Unit trips at 12:00, output goes
to zero
100
50
• Unit updates availability to zero
0
23:00
1:00
3:00
5:00
Test PN
7:00
9:00
11:00 13:00 15:00 17:00 19:00 21:00
Dispatch Quantity
Actual Output
• Availability = zero = actual
output,
no
uninstructed
imbalance
• Testing tariffs based on actual
12
output
Example 3: TSO Dispatches Unit Away From PN
• TSO issues dispatch instructions
as per under test PN
350
300
• For system security reasons TSO
needs to change PN
250
200
• TSO dispatches unit as required
150
• Unit subject to imbalance price
100
50
0
23:00 1:00
3:00
5:00
Test PN
7:00
9:00 11:00 13:00 15:00 17:00 19:00 21:00
Dispatch Quantity
• Unit receives inc /dec price for
difference
between
actual
23:00
output and PN
Actual Output
• Unit pays testing tariffs on
actual output up until 17:00
when testing ends
13
Testing Tariffs
• Appropriate testing tariff will be selected by TSO when approving under test PN
• Currently there are two tariffs which can be applied to Full – Day Tests
• Type of test and previous performance of unit determine tariff
• Tariffs are reviewed annually
14
Testing Tariffs for I-SEM
Testing tariffs for 2017/2018 will be reviewed in accordance with SEM-12-014.
A review of the methodology may include:
• The cost components that make up the testing tariff and their applicability
under the new market design
• The tariff categories
• The criteria for determining which tariff category applies to a test
• The unit types to which the tariffs would apply
15
Summary (1/2)
SEM
I-SEM
Test Duration
Full Trading Day
From a single Trading Period to a full
Trading Day
Submission
Testing Profile Submitted via MPI
Test PN Submitted via MPI
Commercial Data
Unit does not submit commercial
data
Normal commercial data submission
rules apply
Timelines for Requests
5 working days’ notice to TSO for
pre-approval of full day tests.
5 working days’ notice to TSO for preapproval of significant tests.
Market submission no later than
09:00 D-2
Test PN submission no later than
[hh:mm TBD] Day-Ahead for preapproved significant tests
Test PN submission no later than [XX
hours TBD] before Balancing Market
gate closure for minor tests
16
Summary (2/2)
SEM
I-SEM
Modification to Requests
Latest 07:30 D-1
No later than [XX hours TBD] before
modification time
Capacity Payments
min (Metered Output, Dispatch
Quantity)
Reliability Option Quantity
Testing Charges
Metered Output x Testing Tariff
SEM
Trip Charges and Short
Notice Declarations
No for full day tests where testing
tariffs apply
Subject to review in 2017/18 testing
I-SEM
tariff consultation
Subject to review in 2017/18 testing
tariff consultation
17
System Services Update
• Revised date for the first System Services auction to the first half of 2018 for delivery
of services in October 2018
• In the interim, regulated tariffs will apply per System Service
• auctions could have resulted in different payments to different System Service
providers and would require co-optimisation of inc. and dec. costs with System
Services costs.
• In the interim, no impact on scheduling and dispatch process.
18
LNAF/SIFF Update
• Removal of ‘Notification Time Threshold’ and ‘SSII Threshold’ parameters
• With resultant simplification of calculation logic
Start-up cost in scheduling run = Submitted Start-up cost * [1 + (LNAF * SIFF)]
19
Example of Submitted PNs and Resulting Schedule
At 16:00 D-1, snapshot of PNs and long-term schedule for 08:00–21:00 on D
PNs
Unit A
Unit B
Unit C
Unit D
Unit E
Unit F
Unit G
Unit H
Total PN
Demand
Schedule
Unit A
Unit B
Unit C
Unit D
Unit E
Unit F
Unit G
Unit H
Total Sch
Demand
Availability
Max / Min
400 / 200
400 / 200
400 / 200
300 / 100
300 / 100
100 / 20
100 / 20
50 / 10
Availability
Max / Min
400 / 200
400 / 200
400 / 200
300 / 100
300 / 100
100 / 20
100 / 20
50 / 10
08:00
400
300
0
100
100
0
0
0
900
900
08:00
370
330
0
100
100
0
0
0
900
900
09:00
400
350
0
200
200
0
0
0
1150
1150
09:00
370
350
200
130
100
0
0
0
1150
1150
10:00
400
400
0
250
200
0
0
0
1250
1250
10:00
370
370
200
210
100
0
0
0
1250
1250
11:00
400
400
0
250
200
0
0
0
1250
1250
11:00
370
370
200
210
100
0
0
0
1250
1250
12:00
400
400
0
300
200
0
0
0
1300
1300
12:00
370
370
200
260
100
0
0
0
1300
1300
13:00
400
400
0
250
200
0
0
0
1250
1250
13:00
370
370
200
210
100
0
0
0
1250
1250
14:00
400
400
0
200
200
0
0
0
1200
1200
14:00
370
370
200
160
100
0
0
0
1200
1200
15:00
400
400
0
200
200
0
0
0
1200
1200
15:00
370
370
200
160
100
0
0
0
1200
1200
16:00
400
400
0
200
200
0
0
0
1200
1200
16:00
370
370
200
160
100
0
0
0
1200
1200
17:00
400
400
0
250
250
100
0
0
1400
1400
17:00
370
370
200
250
190
20
0
0
1400
1400
18:00
400
400
0
300
300
100
50
0
1550
1550
18:00
370
370
250
270
270
20
0
0
1550
1550
19:00
400
400
0
300
200
50
0
0
1350
1350
19:00
370
370
200
270
120
20
0
0
1350
1350
20:00
400
300
0
250
100
0
0
0
1050
1050
20:00
370
280
200
100
100
0
0
0
1050
1050
21:00
400
200
0
200
100
0
0
0
900
900
21:00
370
230
0
200
100
0
0
0
900
20
900
Dec
Inc
Example of Submitted PNs and Resulting Schedule
The schedule derived by LTS is driven by the following constraints:
•
•
•
Units A, B, D, E and F are constrained down from their maximum available output to provide operating reserve
headroom.
Unit C is constrained on for local voltage support, provision of inertia and operating reserve.
Given these constraints, units are re-positioned to re-balance supply and demand. Unit G is not scheduled to
run over the peak as it is more economic to source additional output from Unit C which is constrained on.
The LTS schedule represents a plan that is re-assessed in subsequent LTS runs and in the shorter term RTC and RTD
runs. Actual dispatch instructions (MW dispatch points, sync and de-sync instructions) are taken in line with the
latest market positions, unit technical capabilities and actual system conditions:
•
•
•
All of the MW dispatch instructions are issued in line with the ramping capability of each unit, (e.g. at 09:57
Unit B is dispatched from 350 MW to 370 MW) taking into account its declared ramping rate and actual system
conditions at the time (e.g. actual demand/wind and system frequency)
The commitment of Unit C will be taken in line with its notification time, e.g. at 03:00 Unit C is instructed to
sync and go to min load by 09:00. So while the 16:00 LTS run indicates the requirement for Unit C, a number of
subsequent LTS runs will have reassessed this requirement before the dispatch decision needs to be made.
Unit G is not committed – no new dispatch instruction is issued (last de-sync instruction remains valid).
21
Areas For Future Plain English & Working Group Update
•
•
•
•
Interconnector schedule management
System Operator – System Operator Trades
Managing events
New registration parameters
22
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
23
Calculation of Payments and Charges
• Areas of note:
– Changes to drafting approach for Imbalance
Component;
– Changes to settlement of explicit fixed costs:
• Additional cases for identifying payable costs;
• New functionality for identifying recoverable costs.
–
–
–
–
Functionality for DSU settlement;
Functionality for Market Power decision;
Miscellaneous smaller changes;
Examples spreadsheet.
24
Imbalance Component
• Previously had single provision with equation for all situations;
• Now have separate provisions for different situations:
1.
2.
Aggregated Settlement Period equal to Imbalance Settlement
Period;
Aggregated Settlement Period greater than Imbalance Settlement
Period:
a)
b)
Unit only traded ex-ante market products less than or equal to Imbalance
Settlement Period duration;
Unit traded ex-ante market products greater than Imbalance Settlement
Period duration.
• This approach removes need for FIMBAVG parameter introduced in
previous draft;
• Other changes:
– Summing all sub-ISP granular products within ISP;
– Provisions generalised for both Generator and Supplier Units to
remove repetition.
25
Imbalance Component
1.
Aggregated Settlement Period equal to Imbalance Settlement Period
(scenario for go-live):
𝑄𝑇𝐷𝐴𝑥𝛾 = 𝑄𝑇𝐷𝐴𝑥ℎ ×
𝑄𝑇𝐼𝐷𝑥𝛾 = 𝑄𝑇𝐼𝐷𝑥ℎ
𝐷𝐼𝑆𝑃
𝐷𝑇𝐷𝐴𝑥
𝐷𝐼𝑆𝑃
×
𝐷𝑇𝐼𝐷𝑥
𝑄𝐸𝑋𝛾
=
𝑄𝑇𝐷𝐴𝑥𝛾 +
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ>𝛾
+
𝑄𝑇𝐷𝐴𝑥ℎ +
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ≤𝛾
𝑄𝑇𝐼𝐷𝑥𝛾
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ>𝛾
𝑄𝑇𝐼𝐷𝑥ℎ
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ≤𝛾
26
Imbalance Component
2.
Aggregated Settlement Period greater than Imbalance Settlement
Period:
a)
Unit only traded ex-ante market products less than or equal to Imbalance
Settlement Period duration:
𝑄𝐸𝑋𝛾 =
𝑄𝑇𝐷𝐴𝑥ℎ +
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ≤𝛾
𝑄𝑇𝐼𝐷𝑥ℎ
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ≤𝛾
27
Imbalance Component
2.
Aggregated Settlement Period greater than Imbalance Settlement
Period:
b)
Unit traded ex-ante market products greater than Imbalance Settlement Period
duration:
𝑄𝑇𝐷𝐴𝑥𝛼 = 𝑄𝑇𝐷𝐴𝑥ℎ ×
𝑄𝑇𝐼𝐷𝑥𝛼 = 𝑄𝑇𝐼𝐷𝑥ℎ ×
𝐷𝐴𝐺𝑆𝑃
𝐷𝑇𝐷𝐴𝑥
𝐷𝐴𝐺𝑆𝑃
𝐷𝑇𝐼𝐷𝑥
Imbalance over hour
𝑄𝐸𝑋𝛾
=
𝑄𝑀𝐿𝐹𝛾 −
+
𝑊𝐹𝐼𝑀𝐵𝛾
𝑎𝑙𝑙 𝛾 ∈ 𝛼 𝑊𝐹𝐼𝑀𝐵𝛾
𝑄𝑇𝐷𝐴𝑥ℎ +
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ≤ 𝛾
𝑄𝑀𝐿𝐹𝛾 −
𝑎𝑙𝑙 𝛾 ∈ 𝛼
𝑄𝑇𝐷𝐴𝑥ℎ +
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ= 𝛼
𝑄𝑇𝐼𝐷𝑥ℎ
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ= 𝛼
𝑄𝑇𝐼𝐷𝑥ℎ
𝑥 𝑤ℎ𝑒𝑟𝑒 ℎ≤ 𝛾
28
Fixed Cost Settlement
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Pure Commitment (when Complex COD applies):
• Start cost payable;
• No-load costs payable for entire commitment period.
29
Fixed Cost Settlement
TSO No Load Costs Incurred
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Pure Decommitment (when Complex COD applies):
• Start cost recoverable;
• No-load costs recoverable for whole decommitment period.
30
Fixed Cost Settlement
TSO No Load Costs Incurred
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Early Start (when Complex COD applies):
• No start cost payable;
• No-load costs payable for additional commitment period.
31
Fixed Cost Settlement
TSO No Load Costs Incurred
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Deferred Start (when Complex COD applies):
• No start cost recoverable;
• No-load costs recoverable for reduction in commitment period.
32
Fixed Cost Settlement
TSO No Load Costs Incurred
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Early Off (when Complex COD applies):
• No start cost recoverable;
• No-load costs recoverable for reduction in commitment period.
33
Fixed Cost Settlement
TSO No Load Costs Incurred
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Deferred Off (when Complex COD applies):
• No start cost payable;
• No-load costs payable for additional commitment period.
34
Fixed Cost Settlement
TSO No Load Costs Incurred
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Keep On (when Complex COD applies):
• Start cost recoverable for prevented start;
• No-load costs payable for additional commitment period.
35
Fixed Cost Settlement
TSO No Load Costs Incurred
MW
Start Payable
Start Recoverable
No Load Payable
No Load Recoverable
Market Operation (FPN)
Physical Operation
t
Two-Shift (when Complex COD applies):
• Start cost payable for additional start;
• No-load costs recoverable for reduction in commitment period.
36
Demand Side Unit Settlement
Trading Site (TS)
Demand Site Unit
(DSU)
Trading Site Supplier
Unit (TSSU)
• Set DSU QM = QD
– Assumes DSU delivered;
– Flexibility to include functionality to incorporate actual delivery in the future.
• Set TSSU QM = -QD:
– Another separate Supplier Unit experiences the benefit of reduction in
demand at the imbalance price;
– This provision removes the benefit from the DSU to ensure against double
counting.
37
Market Power Decision
• Market Power Decision requirements:
– 8.17.2: “all actions of units deemed to be nonenergy for the purposes of the market power
mitigation functionality as part of imbalance
pricing will be settled based on 3-part offers
submitted to the TSOs”
• 2 Parts of implementation:
– Rules for determining when unit deemed to be
non-energy;
– Rules for settlement based on 3-part offers.
38
Market Power Decision
• Determining when unit deemed to be “nonenergy”:
– In imbalance pricing through combination of:
• SO Flagging (where information is available);
• NIV Tagging (where information is not available, e.g.
there are less SO Flagged actions than the NIV, or SO
Flagging switched off, NIV tagging assumes that the
most expensive actions are non-energy).
– If unit SO Flagged or NIV Tagged within Imbalance
Settlement Period, it is deemed to be non-energy.
39
Market Power Decision
• Settlement based on 3-part offers:
– If unit deemed to be non-energy, use the valid
Complex (3-part) COD submitted for the
calculation of BOA quantities and prices in
settlement;
– N.B. This does not apply for calculation of BOA
quantities and prices for the Imbalance Pricing
process:
• Results in different set of BOA quantities and prices in
Imbalance Pricing process and Imbalance Settlement
process.
40
Miscellaneous Smaller Changes
• Sign errors corrected in tests for Undelivered
Quantities and Biased Quantities, e.g.:
𝑄𝐴𝐵𝑈𝑁𝐷𝐸𝐿𝑢𝑜𝑖𝛾𝑛
= 𝑀𝑖𝑛 𝑀𝑎𝑥 𝑄𝐴𝐵𝐿𝐹𝑢𝑜𝑖𝛾𝑛 , −𝑄𝑈𝑁𝐷𝐸𝐿𝑅𝑢𝛾
𝑄𝑈𝑁𝐷𝐸𝐿𝑅𝑢𝛾𝑛
= 𝑄𝑈𝑁𝐷𝐸𝐿𝑅𝑢𝛾
𝑛−1
𝑄𝑈𝑁𝐷𝐸𝐿𝑅𝑢𝛾
𝑛−1
,0
− +𝑄𝐴𝐵𝑈𝑁𝐷𝐸𝐿𝑢𝑜𝑖𝛾𝑛
𝑛=0
= 𝑄𝑈𝑁𝐷𝐸𝐿𝑢𝛾
41
Miscellaneous Smaller Changes
• Changes to timing definitions:
– Instead of a BOA due to a “lack of instruction”, a
“pseudo-instruction” for settlement purposes only
is created.
Pseudo-DI to open o = 2
MW
Physical DI to open o = 1
o=1
o=2
FPN
h
h+1
42
Miscellaneous Smaller Changes
• Changes to Trade Opposite TSO:
– Added provision for qPNuβ(o=0)γ(t):
• i.e. where instruction issued for period where no PN yet
submitted, PN used is zero.
– Additional Max and Min functionality added to
qAOTOTSO and qABTOTSO:
• Ensure against negative values in qAOTOTSO, positive
values in qABTOTSO.
43
Miscellaneous Smaller Changes
• FAQ from site to unit:
– Adjusted provisions because of potential for “divide-by-zero” case
where no Accepted Bid Quantities on any units;
– In this scenario, the firmness of each unit is set equal to their FPN, no
impact on settlement.
• Clarity on PN quantities used for Information Imbalance Charge:
– QPN from qPN data present at end of half-hour PN Submission Period;
– PN Submission Periods are those from 13:30 TD-1 until Gate Closure.
• FPUG and FDOG applied to opposite Accepted Offer / Bid
Quantities which were undelivered over tolerance:
– QABUNDELOTOL, bids not delivered due to over-generation, therefore
FDOG should apply;
– QAOUNDELOTOL, offers not delivered due to under-generation,
therefore FPUG should apply.
44
Examples Spreadsheet
• Prioritised functionality developed:
– Accepted Offer and Bid Quantities and Prices;
– Biased Quantities;
– Undelivered Quantities;
– Imbalance Charge or Payment;
– Premium/Discount Payments.
• Other functionality in iterative development.
45
Examples Spreadsheet
• Features:
– Input minute-by-minute qD, qFPN;
– Input half-hour QEX, QM;
– Calculate half-hour QAB and QAO (split into price
bands), undelivered and biased quantities
according to rules;
– Visualise when incs/decs occurring;
– Calculate half-hour CIMB, CPREMIUM and
CDISCOUNT with results.
46
Calculation of Payments and Charges
•
•
•
•
•
•
•
•
•
•
•
•
•
CIMBuγ, the Imbalance Component Payment or Charge;
CPREMIUMuγ, the Premium Component Payment or Charge;
CDISCOUNTuγ, the Discount Component Payment or Charge;
CAOOPOuγ, the Offer Price Only Accepted Offer Payment or Charge;
CABBPOuγ, the Bid Price Only Accepted Bid Payment or Charge;
CCURLuγ, the Curtailment Charge;
CUNIMBuγ, the Uninstructed Imbalance Charge;
CIIuγ, the Information Imbalance Charge;
CFCub, the Fixed Cost Payment or Charge;
CTESTuγ, the Testing Charge;
CIMPuγ, the Imperfections Charge;
CREVvγ, the Residual Error Volume Charge;
CCAvγ, the Currency Adjustment Payment or Charge.
47
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
48
CRM Settlement
• Areas of note:
– Functionality added for load-following obligation;
– Functionality added for Difference Charges for
interconnectors;
– Adjustments to Stop-Loss Limit functionality;
– Miscellaneous smaller changes.
49
Load Following Obligation
• Features of functionality:
– Reduces requirement in line with reduction in
demand;
– Cannot exceed value of 1 (i.e. cannot increase
obligation above level of ROs held);
– Denominator is procured capacity, which is driven by
capacity requirement:
• Therefore the items which drive demand requirement
included in numerator:
– Demand provision;
– Fixed provision for reserve included to reflect CRM1 decision if
required for consistency with capacity requirement, subject to
consultation.
50
Load Following Obligation
𝐹𝑆𝑄𝐶𝛾 = 𝑀𝑖𝑛
𝑣 𝑀𝑖𝑛
𝛺
𝑄𝑀𝐿𝐹𝑣𝛾 , 0 + (𝑞𝑅𝐶𝑅𝑦 × 𝐷𝐼𝑆𝑃)
,1
𝑞𝐶
×
𝐷𝐼𝑆𝑃
𝛺𝑛
𝑛 ∈ 𝛾,𝑞𝐶𝐶𝑂𝑀𝑀𝐼𝑆𝑆 ≠0
Reserve in
Capacity
Requirement
Reduction of
Requirement
QMLF + QRCR
Demand in
Capacity
Requirement
ΣqC
Capacity
Procured
QMLF
51
Interconnector Difference Charges
• CRM2 Decision Requirements:
– 3.2.44 “Interconnectors that back Reliability
options will be liable to make difference payments
at times its reduced availability is restricting the
flow of electricity into the capacity market”
– 3.2.36 “…interconnectors will only pay difference
payments if they are unavailable and the
Balancing Market price is above the Reliability
Option strike price.”
52
Interconnector Difference Charges
• CRM2 Decision Requirements:
– 3.2.44 “Interconnectors that back Reliability
options will be liable to make difference payments
at times its reduced availability is restricting the
flow of electricity into the capacity market”
– 3.2.36 “…interconnectors will only pay difference
payments if they are unavailable and the
Balancing Market price is above the Reliability
Option strike price.”
Base on availability (ATC)
53
Interconnector Difference Charges
• CRM2 Decision Requirements:
– 3.2.44 “Interconnectors that back Reliability
options will be liable to make difference payments
at times its reduced availability is restricting the
flow of electricity into the capacity market”
– 3.2.36 “…interconnectors will only pay difference
payments if they are unavailable and the
Balancing Market price is above the Reliability
Option strike price.”
At times of import (no
difference charge if exporting)
54
Interconnector Difference Charges
• CRM2 Decision Requirements:
– 3.2.44 “Interconnectors that back Reliability
options will be liable to make difference payments
at times its reduced availability is restricting the
flow of electricity into the capacity market”
– 3.2.36 “…interconnectors will only pay difference
payments if they are unavailable and the
Balancing Market price is above the Reliability
Option strike price.”
Non-Performance
Difference Charge Only
55
Interconnector Difference Charges
• Functionality if importing:
𝑄𝐷𝐼𝐹𝐹𝐶𝑁𝑃𝛺𝛾
= 𝑀𝑎𝑥 𝑀𝑖𝑛 𝑄𝐶𝑂𝐵𝛺𝛾 − 𝑞𝐴𝑇𝐶𝑀𝐴𝑋𝐼𝐿𝐹𝑙𝛾 × 𝐷𝐼𝑆𝑃 , 𝑄𝐶𝑂𝐵𝛺𝛾 − 𝑄𝑀𝐿𝐹𝑙𝛾 , 0
56
Interconnector Difference Charges
• Functionality if importing:
𝑄𝐷𝐼𝐹𝐹𝐶𝑁𝑃𝛺𝛾
= 𝑀𝑎𝑥 𝑀𝑖𝑛 𝑄𝐶𝑂𝐵𝛺𝛾 − 𝑞𝐴𝑇𝐶𝑀𝐴𝑋𝐼𝐿𝐹𝑙𝛾 × 𝐷𝐼𝑆𝑃 , 𝑄𝐶𝑂𝐵𝛺𝛾 − 𝑄𝑀𝐿𝐹𝑙𝛾 , 0
Amount of requirement not met by import…
57
Interconnector Difference Charges
• Functionality if importing:
𝑄𝐷𝐼𝐹𝐹𝐶𝑁𝑃𝛺𝛾
= 𝑀𝑎𝑥 𝑀𝑖𝑛 𝑄𝐶𝑂𝐵𝛺𝛾 − 𝑞𝐴𝑇𝐶𝑀𝐴𝑋𝐼𝐿𝐹𝑙𝛾 × 𝐷𝐼𝑆𝑃 , 𝑄𝐶𝑂𝐵𝛺𝛾 − 𝑄𝑀𝐿𝐹𝑙𝛾 , 0
Amount of requirement not met by import…
…to the extent it is driven by lack of availability.
58
Stop-Loss Limits
• CRM2 Decision Requirements:
– 4.6.15: “When a Reliability Option is transferred:
• The plant from which it is transferred (that which is “buying” capacity)
retains the limit along with the history of any losses against that limit.
That limit continues to apply, so that if the unit becomes subject to a
Reliability Option again it is that limit, and any associated history of
losses, which will apply.
• The plant to which it is transferred (that which is “selling” capacity) is
has its existing stop-loss limit increased to account for the increased
sale of capacity – with no allowance for any history of losses against
that limit.”
– 5.4.20: “The Committee will initially set the annual stop-loss
limit to 1.5x the annual option fee for a capacity provider and is
minded to set the billing period stop-loss limit to 0.5x the
annual stop loss limit. Final values will be determined as part of
the parameters consultation process.”
59
Stop-Loss Limits
• CRM2 Decision Requirements:
– 4.6.15: “When a Reliability Option is transferred:
• The plant from which it is transferred (that which is “buying” capacity)
retains the limit along with the history of any losses against that limit.
That limit continues to apply, so that if the unit becomes subject to a
Reliability Option again it is that limit, and any associated history of
losses, which will apply.
• The plant to which it is transferred (that which is “selling” capacity) is
has its existing stop-loss limit increased to account for the increased
sale of capacity – with no allowance for any history of losses against
that limit.”
– 5.4.20: “The Committee will initially set the annual stop-loss
limit to 1.5x the annual option fee for a capacity provider and is
minded to set the billing period stop-loss limit to 0.5x the
annual stop loss limit. Final values will be determined as part of
the parameters consultation process.”
Base Annual SLL on actual revenue to date
and forecast revenue for rest of year 60
Stop-Loss Limits
• CRM2 Decision Requirements:
– 4.6.15: “When a Reliability Option is transferred:
• The plant from which it is transferred (that which is “buying” capacity)
retains the limit along with the history of any losses against that limit.
That limit continues to apply, so that if the unit becomes subject to a
Reliability Option again it is that limit, and any associated history of
losses, which will apply.
• The plant to which it is transferred (that which is “selling” capacity) is
has its existing stop-loss limit increased to account for the increased
sale of capacity – with no allowance for any history of losses against
that limit.”
– 5.4.20: “The Committee will initially set the annual stop-loss
limit to 1.5x the annual option fee for a capacity provider and is
minded to set the billing period stop-loss limit to 0.5x the
annual stop loss limit. Final values will be determined as part of
the parameters consultation process.”
Calculate accumulated Difference Charges on
unit basis, no adjustments for secondary trades
61
Stop-Loss Limits
• CRM2 Decision Requirements:
– 4.6.15: “When a Reliability Option is transferred:
• The plant from which it is transferred (that which is “buying” capacity)
retains the limit along with the history of any losses against that limit.
That limit continues to apply, so that if the unit becomes subject to a
Reliability Option again it is that limit, and any associated history of
losses, which will apply.
• The plant to which it is transferred (that which is “selling” capacity) is
has its existing stop-loss limit increased to account for the increased
sale of capacity – with no allowance for any history of losses against
that limit.”
– 5.4.20: “The Committee will initially set the annual stop-loss
limit to 1.5x the annual option fee for a capacity provider and is
minded to set the billing period stop-loss limit to 0.5x the
annual stop loss limit. Final values will be determined as part of
the parameters consultation process.”
Billing Period SLL multiple
of Annual SLL
62
Stop-Loss Limits
• Annual Stop-Loss Limit recalculated with each settlement cycle:
𝐶𝑆𝑆𝐿𝐴𝛺𝑏 =
𝐶𝐶𝑃𝛺𝛾 + 𝐶𝐶𝑃𝐸𝛺(𝑏′ > 𝑏)
× 𝐹𝑆𝐿𝐿𝐴𝑦
𝛾 ∈ 𝑏′ ≤𝑏
Actual Revenue to date
Forecast Revenue
• Billing Period Stop-Loss Limit based on multiple of Annual Stop-Loss
Limit:
𝐶𝑆𝑆𝐿𝐵𝛺𝑏
=
𝐶𝐶𝑃𝛺𝑏 + 𝐶𝐶𝑃𝐸𝛺(𝑏′ > 𝑏)
× 𝐹𝑆𝐿𝐿𝐴𝛺𝑦 × 𝐹𝑆𝐿𝐿𝐵𝑦
𝑏′ ≤𝑏
63
Miscellaneous Smaller Changes
• Supplier Capacity Charge Price provisions:
– In Plain English Document, equation illustrated
how such a price could be calculated;
– In legal drafting, price determined in similar way
to Imperfections Price: report, RA approval, etc.
• Loss adjustment of terms:
– In discussions with De-Rating / Capacity
Requirement team;
– May result in some changes in final legal draft.
64
Miscellaneous Smaller Changes
• Included QCOB in Difference Charge calculations rather
than qCCOMMISS x FDERATE, FSQC x QCNET:
– QCOB already incorporates limit of exposure to de-rated
commissioned capacity, and load-following obligation
calculation.
• Separated DSU and non-DSU Non-Performance Difference
Charges:
– More clear-cut difference between the two approaches than
single equation for all situations;
– Only care about FNDDS for actual DSUs.
• Supplier Difference Payments in DAM only considered for
negative quantities:
– Previous drafts would have resulted in a charge for positive
DAM quantities with a price greater than the strike price.
65
Miscellaneous Smaller Changes
•
Changed Strike Price formulation:
– In line with CRM3 consultation;
– Change in incorporation of carbon, and generalising terms relating to oil.
•
Previously:
𝑃𝑆𝑇𝑅𝑚
1
= 𝑀𝑎𝑥
𝐹𝑇𝐻𝐸𝑂𝑅𝑌𝑃𝑈𝑦
× 𝑀𝑎𝑥(𝑃𝐹𝑈𝐸𝐿𝑁𝐺𝑚 × 𝐹𝐶𝐴𝑅𝐵𝑂𝑁𝑁𝐺𝑚 , 𝑃𝐹𝑈𝐸𝐿𝐺𝑂𝑚
66
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
67
Dispute Process – Participant’s Feedback
 Early publication of the price is important, even if that price is “indicative”;
 With regard to certainty and accuracy in the setting of price, participants
generally leaned towards accuracy. While it is undesirable and should be avoided
as much as possible, participants generally felt that material errors discovered in
the price after its publication should be rectified as soon as possible;
 There was general acceptance that the price should be capable of being reopened to remedy errors but subject to a materiality threshold and some
limitations on the time allowable to raise a pricing dispute;
 Comments were received that indicated that other contractual arrangements that
relied on the imbalance price would likely be capable of accommodating
subsequent reopening and resetting of the price, provided this was not a regular
occurrence and was expedited as far as practically possible;
 Processes in other Markets should be considered for comparison.
68
Dispute Process – Proposal for Pricing Disputes 1/3
In light of the participant feedback received and consideration of approaches
adopted in other markets, the follow approach in relation to pricing disputes is
proposed for I-SEM:
 Imbalance prices to be published as soon as practical after each Trading Period;
 A limited time to be allowed for price disputes to be raised;
 Pursuit of price disputes to be subject to a materiality threshold;
 In the event that a dispute is raised the published price is to be flagged as such;
 Reasonable endeavour to be undertaken to resolve the dispute prior to issue of
final Settlement Documents;
 Other than the case of a manifest error, the published price shall not be reopened unless directed by a Dispute Resolution Board Panel or a court with
jurisdiction[or other judicial process].
69
Dispute Process – Proposal for Pricing Disputes 2/3
Timelines and thresholds proposed:
 Disputes to be raised within 5 WD (prior to Imbalance Settlement Statements) ;
 Similar to current rules for Data Query resolution, a reasonable endeavours
obligation on the affected parties to resolve price disputes prior to Settlement
Statements being published, should be imposed;
 A materiality threshold should be imposed with an onus on the raising Party on
providing supporting evidence that the disputed matter an impact greater than
the materiality threshold;
 Timing provisions for the raising of Credit Cover Disputes in case of Default or
Suspension are not specified; if resolution is required prior to the requirement to
provide additional credit cover, this provides its own incentives in this regard;
 Resolutions to Credit Cover Disputes will follow the current rules of 5 WD,
although best endeavour should apply to find a resolution within 90 mins.
70
Dispute Process – Proposal for Pricing Disputes 3/3
Cont.:
 A Dispute Resolution Board should make an initial assessment on the materiality
threshold being satisfied, within 5 working days of being appointed;
 The timelines for a Dispute Resolution Board decision on a price-related dispute
are proposed to be no different to other disputes under the Code, namely (as per
paragraph 2.308 of the existing Trading and Settlement Code):
(i) 30 Working Days after the appointment of the DRB where there are
no more than two Disputing Parties; or
(ii) 40 Working Days after the appointment of the DRB where there are
more than two Disputing Parties; or
(iii) such other period as may be proposed by the DRB and approved by
the Disputing Parties.
71
Dispute Process – Threshold
 Materiality threshold will be part of the Parameter setting exercise;
feedback from Participants on their preferred measure of materiality,
would be useful:
 absolute monetary value;
 % of Imbalance Price change;
 % of total market revenue change;
 % of raising PT original statements;
 a combination of two or more of the above options.
72
Settlement Reallocation
 Document issued on 28th April set out two approaches to implementation
for Settlement Reallocation
 Based on “single directional” or “multi-directional” solution
 “Single directional” approach based on one party to the agreement always
being the financially responsible party on behalf of both
 “Multi-directional” approach based on final settlement positions and may
result in either party being financially responsible in any given billing
period
 Responses from participants supported implementation of the “Single
directional” approach
 The updated plain English document has expanded further on this design
73
Settlement Reallocation
 Updates –
 Confirm that SRA will apply to all payments and charges as included on a
Settlement Document;
 If CRM and Imbalances settled on same document, this will result in SRA
applying between these;
 Noted that MO charge will be on a separate Settlement Documents but any
agreements will apply to these also (i.e., - one party takes financial
responsibility for payment on behalf of both parties to the agreement);
 Proposals for application of SRAs in Credit Cover Requirement calculation as
currently set out will work with the “single directional” implementation;
 Will see no Credit Cover Requirement for the party that is not financially
responsible;
 Will result in Credit Cover Requirements when agreements come towards
their end;
74
Settlement Reallocation
 Process steps set out potential definitions and steps that can form the
basis of the legal draft;
 Note terminology changes proposed –
 “Main participant” being the one whose monies are transferred from and is
therefore not financially responsible is now the “Secondary Participant”;
 “Partner participant” being the one who takes on financial responsibility for
both parties to the agreement is now the “Principal Participant”
 Error in process steps – text from current T&SC relating to SRAs between
currency zones included in error;
 As SRA is a financial transaction rather than related to the MWs, it is
proposed that for cross border SRAs, the prevailing Trading Day Exchange
Rate on the date of issue of the Settlement Documents will be used.
75
Market Operator Charge Basis
 Market Operator charge basis included in current T&SC;
 Applies FMOC on a rate per supplier unit and a rate per MW of installed
capacity per generator unit;
 Applies VMOC on a rate per MWh of consumption per supplier unit;
 Paper looks to consider what is the most appropriate way to charge MO
fee for I-SEM;
 Three options suggested for comment;
 Does not seek to assess what the fee covers nor what it is made up of;
 Setting the Market Operator rate will be subject to a later process;
 This sits outside of the T&SC today;
76
Market Operator Charge Basis
 Option 1 –
 Retain current arrangements (FMOC and VMOC as set out)
 Option 2 –
 Replace with FMOC approach
 Approach for generators will be same as today;
 For supplier units, based on a band of rates that would apply based on
average or forecast of consumption;
 Option 3 –
 Adopt current arrangement but apply VMOC only on imbalances
77
Market Operator Charge Basis
 Decision on which approach is best needs objectives and criteria
 What is the Market Operator charge intended to do?
 Recovery of operational costs as well as capital related costs incurred in the execution of
its role in administering the rules of the T&SC;
 Which option best facilitates this?
 What other criteria is important?
 Certainty?
 Transparency?
 Equitable application of costs across participants?
 Driving unintended behaviours?
 Flexibility?
78
Market Operator Charge Basis
 Interested in feedback from Participants on these approaches.
 Traffic light status approach could be applied to the table below if desired
MO Cost
Recovery
Certainty of
charge
Transparent
Equitable
Unintended
Behaviours
Flexibility
Option 1
Option 2
Option 3
79
Credit Cover Requirements
 Previously discussed the risk that arises with respect to volumes traded
but not yet delivered;
 Credit Cover calculations account for this in the Exposure Traded Not
Delivered element;
 This calculates a sellers potential exposure in imbalance settlement that
arises if sales in the ex-ante markets are not delivered;
 This can arise from a generator tripping or an assetless trader not closing
their ex-ante positions;
 While risk understood, the addition to the Credit Cover requirement may
not be sufficient in the event that Posted Credit Cover is short;
 A participant is unlikely to be able to respond to the Credit Cover Increase
Notice before the delivery failure has happened;
80
Credit Cover Requirements
 Had explored the concept of a TSO Trading Limits with ECC;
 Trading Limits currently used by clearing houses and clearing members to set
“caps” on participants’ trading in the ex-ante markets;
 Wanted to consider if the TSO could also set Trading Limits based on posted
credit cover with SEMO;
 This would result in offer not being accepted rather than other solutions;
 Differences between member structure between ECC, PX and SEMO meant
that mapping between the particpant level in SEMO to the member level at
the PX could not be guaranteed;
 Application of Trading Limit not effective in multi-NEMO environment;
 Appears that robust solution on the NEMO side may not be implementable
for I-SEM go-live;
81
Credit Cover Requirements
 Considered GB approach to this issue;
 In GB, participants are placed in level 1 and level 2 credit default with
Elexon where the ratio of their exposure to their posted collaterals
exceeds preset values;
 Contracted positions (based on ex-ante trades) are submitted to Elexon by
Electricity Contract Volume Notification Agents (ECVNA);
 For OTC trades, this can be the participant themselves;
 For exchange trades, this is the PX (counter party to all trades) that
submits these;
 Where a participant is in level 2 credit default, Elexon can refuse the
notification of a contract that increases the participants level of
indebtedness;
82
Credit Cover Requirements
 When contract notification is refused, for OTC contracts, this allows the
parties to cancel the contract and for the buyer to seek an alternative
seller;
 For exchange trades, the central counter party (PX) is responsible for the
imbalance that arises due to the refused contract;
 The PX is further required to post credit cover with Elexon;
 GB PX’s have built the requirement into their rules that members must
maintain the appropriate level of credit cover required under the BSC;
 Failure to do so would result in the member being in breach of the
exchange rules;
 No connection between the contract notification refusal by Elexon and the
PN submission to NGET;
83
Credit Cover Requirements
 For the I-SEM arrangements, a similar approach to GB is being considered;
 Contracted quantities from the ex-ante markets will be submitted to
SEMO by the EirGrid / SONI NEMO (ECC as counter party);
 SEMO will assess the exposure risk against the posted collateral for each
participant;
 Assessment will be of volume by Credit Assessment Price;
 If contracted position(s) are not covered by Posted Credit Cover, SEMO will
refuse the notificiations;
 ECC then held for imbalances that arise in settlement;
 As per GB, no connection between the contract refusal by SEMO and PN
submission to the TSO;
84
Credit Cover Requirements
 Intention is to develop text to be included in the data submission section
of the new rules;
 Considered part of the validation of contract notification by “scheduling
agent” (in I-SEM this will be ECC);
 Welcome comments from participants on this inclusion;
 Needs to be considered in the context of the total Credit Cover
Requirement calculation and new entity model for I-SEM;
 Not proposed to make any further changes to the Credit Cover
Requirement calculation in respect of this;
85
Credit Cover Requirements
 Most changes to this section as set out at last session;
 Exceptions relate to text updates post legal review (small wording
changes, removal of redundant clauses, fixing cross references, correcting
some errors);
 Notable amendments –
 Text on Bad Debt allocation moved from current location to section on
Shortfalls and Unsecured Bad Debt;
 Algebra updates to reflect changes in CRM settlement sections
(changes to variables and subscripts, etc.);
 Text relating to Modification 02_13 moved as pasted in the wrong
place in the first legal drafting;
 Explicit calculation of ESDpr added (overlooked in previous draft);
86
Comment Requests from Previous WG meeting
 Presented on comment that Bad Debt allocation should be on revenue
basis rather than volume;
 Suggested prices were imbalance price, ex-ante reference price or credit
assessment price;
 Still seeking participant feedback on this;
 Proposed amendment for treatment of “New Participants” and “Adjusted
Participants”;
 Proposed that “Adjusted Participants” are assessed based on percentage
change rather than new forecast;
 Have revised legal draft based on this approach;
87
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
88
BM Data Submission
• Areas of note:
– Change in Gate Window/Trading Window drafting
approach;
– Unit Under Test provisions apply to any dispatchable
unit submitting a PN (includes DSU and Pumped
Storage);
– Need for provisions on application of data in systems,
e.g. energy limits, to be clarified for final legal draft;
– Provisions for validation TOD (VTOD) set selection to
be included in final legal draft.
89
Gate Window / Trading Window Approach
• Current TSC approach:
– Define Gate Windows:
• Periods within which data can be submitted (EA1, EA2,
WD1);
• Fixed Gate Opening and Gate Closing Times for all.
– Define Trading Windows:
• Periods for which data is relevant;
• All Trading Periods in Trading Day (EA1, EA2, EP1, EP2) or
subset of Trading Periods (WD1).
– Define Trading Windows relevant to Gate Windows.
90
Gate Window / Trading Window Approach
• New TSC approach:
– Define Gate Opening for Trading Day;
– Define Gate Closures:
• Periods before which data can be submitted, for different
purposes;
• For submission of data by a Fixed Gate Closure Time (GC1,
GC2);
• For submission of data by a dynamic Gate Closure Time
depending on Trading Period (GC3);
– Define Gate Closures as relevant to Trading Day (GC1,
GC2) or Trading Period (GC3).
91
Units Under Test
• Currently exemption from granting Under Test
status to:
– DSU, Pumped Storage, Interconnector related units,
autonomous units.
• Under new arrangements, have data required for
granting Under Test status to:
– DSU and Pumped Storage;
– Physical Notification data required.
• Therefore these units can come under UUT
provisions in TSC.
92
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
93
Data and Information System – Review
 Revised Plain English is an advanced blueprint of the Initial Legal Draft;
 Amended definitions have been included; those segments that have been
removed are no longer part of the T&SC;
 Sections on Validation of Data and Default Offer Process have been
missed and will be included in the next version of the Balancing Market
Data Submission;
 This will include Physical Notifications as well.
94
Data Publication – Update on NIV calculation
 Net Imbalance Volume Forecast calculation: the system shall calculate a Forecast
QNIV for each Imbalance Settlement Period from the next Imbalance Settlement
Period to the end of the Trading Day for which the Day Ahead Market has most
recently closed, based on the following relationship:
Forecast QNIV = latest Load Forecast for the Imbalance Settlement Period
minus the sum of all latest Physical Notifications, where:
 For Wind Generator Units that have not submitted PNs, their PN for the
purposes of the Forecast QNIV calculation shall be set to the latest wind
forecast for that unit; and
 For Interconnectors the PN for the purposes of the Forecast QNIV
calculation is the latest reference programme.
The system shall publish Forecast QNIV immediately after each calculation, via the MPI
and the EirGrid website.
95
Data Publication – Update on Load Forecast
 Jurisdictional Load Forecast is based on the following historical data:
ROI:
net export of generators (excluding wind)
net import into IE from NI
net import into IE from GB
net export of wind generators
total IE DSU MW reduction
NI:
net export of generators (excluding wind)
net import into NI from IE
net import into NI from Scottish Power
net export of wind generators
Total NI DSU MW reduction
 Non-centrally monitored generation, (e.g. small scale CHP, small scale hydro, wind
etc.) are inherently captured as Load Forecast is based on historical demand data
and peaks adjusted to the forecasted circumstances of the lookout period with
considerations on energy efficiencies and large connections as described in the
‘Generation Capacity Statement’;
96
Data Publication – Update on Wind Forecast 1/2
 TSO Wind Forecast is provided by external providers for every windfarm that is
centrally monitored by the TSO*;
 TSO will provide details of each windfarm including N. of turbines, turbine types,
permissible capacity (min of Registered Capacity and MEC), installed capacity etc.
 This might include some out of market generation because all units >5MW have
to be controllable but don’t have to be in the Market if they are <10MW;
 Below de minimis, non-controllable wind generation is not accounted for;
 Requests for separate out of market generation reports is possible but would be
limited to controllable wind only (difference between TSO and SEMO Forecasts);
*This includes old legacy wind units that are still non-controllable and new Generators that are not yet
controllable but are in the process of becoming controllable.
97
Data Publication – Update on Wind Forecast 2/2
 Contract with wind forecast providers is limited to 4.5 days windows;
 Wind forecasts do not include curtailment forecast as these are only reflected by
the TSO in real time and would not be available to forecast providers;
 Providers are, however, supplied with outages information where these are
available;
 Requests for up to date Curtailment information is currently still under review;
 It is expected that Solar Forecasts will follow the same formats of wind forecast;
however, it might be procured to different providers and specifications could
change;
 Wind regions are not relevant for the TSO forecasting processes.
98
Data Publication – Other Updates
 Rep_050 ‘Imbalance Price Supporting Information’ is not anonymized:
‘Participant_Name’ and ‘Resource_Name’ are both fields in the report;
 Missing items: amendments have been requested to include ‘Administered
Scarcity Price’ and ‘Market Back Up Price’ in ‘Imbalance Price Report’ (008); ‘Strike
Price’ will be included in Capacity reporting requirements;
 Still under investigation:
 Reviewing the option of more dynamic timelines for TCG* Report to include
more up to date info on Operational System Constraints, Network System
Outage Schedule & Operating Reserve;
 System Long/Short Warnings, ASP Warning and Operating Reserve Warning;
 Anything else that is not currently in the ‘I-SEM Technical Specification’
(additional aggregations, reports or functionality), will have to go through PMO
Change Control Process.
*Transmission Constraint Group
99
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
100
Dispatch Instruction Profile – T&SC 4.55 to 4.60 - 1/4
 Paper concentrating on the details included in the Appendix O;
 The main body of the Code only refers generally to this process in paragraphs
4.55 to 4.60, which remain unchanged;
DISPATCH QUANTITY
4.55 Each System Operator shall submit to the Market Operator the Dispatch
Instructions in respect of each Generator Unit which is Dispatchable and is
registered within its Currency Zone, and may submit an associated Ramp Rate for
each Dispatch Instruction. Each System Operator shall submit this information to the
Market Operator in accordance with Appendix K “Market Data Transactions”, based
on Outturn Data, and the values submitted shall be net of Unit Load.
101
Dispatch Instruction Profile – T&SC 4.55 to 4.60 – 2/4
4.56 The Market Operator shall, in accordance with Appendix O “Instruction Profiling
Calculations”, determine the Dispatch Quantity (DQuh) for each Generator Unit u in
Trading Period h from the Dispatch Instructions submitted by the relevant System
Operator.
Maximisation Instructions
4.57 The relevant System Operator may issue a Maximisation Instruction to
maximise the Output of a Generator Unit under the terms of the Grid Code. Where a
System Operator issues a Maximisation Instruction in respect of a Generator Unit,
that Generator Unit will be treated as subject to Maximisation in the relevant
Trading Period or Trading Periods as set out within Appendix O “Instruction Profiling
Calculations”. The values for Outturn Availability which are submitted to the Market
Operator by the System Operator or the values of Availability Profile (APuh) which
are calculated by the Market Operator for that Generator Unit u for those Trading
Periods h will not be revised upwards to reflect the Short-Term Maximisation
Capability (STMCut) for Generator Unit u within Trading Day t.
102
4.58 In any Trading Period when a Generator Unit is treated as being subject to
Maximisation in accordance with Appendix O “Instruction Profiling Calculations”, the
Market Operator shall calculate the revised Dispatch Quantity (DQ’uh) as follows:
Under a Maximisation Instruction,

MGuh 

DQ ' uh  Max  DQuh , Min STMCut ,

TPD



Where:
1.
DQ’uh is the revised Dispatch Quantity in respect of Generator Unit u which
is treated as being subject to Maximisation in Trading Period h;
2.
DQuh is the Dispatch Quantity for Generator Unit u in Trading Period h prior
to revision, as calculated by the Market Operator in accordance with Appendix O
“Instruction Profiling Calculations”;
3.
TPD is the Trading Period Duration;
4.
MGuh is the Metered Generation for Generator Unit u in Trading Period h;
5.
STMCut is the Short-Term Maximisation Capability for Generator Unit u for
Trading Day t, which shall apply for all Trading Periods h within that Trading Day t.
103
Dispatch Instruction Profile – T&SC 4.55 to 4.60 – 4/4
4.59 The revised Dispatch Quantity (DQ’uh) may at such times exceed both the
Registered Capacity (RCu) and the Availability Profile (APuh) for the relevant
Generator Unit.
4.60 In the event that the revised Dispatch Quantity (DQ’uh) calculated pursuant to
paragraph 4.58 exceeds the greatest Accepted Quantity (Quhi), then the revised
Dispatch Quantity (DQ’uh) shall be used in place of the greatest Accepted Quantity
(Quhi) in all other relevant calculations under this Code.
104
Dispatch Instruction Profile – Review
 Removed references to New Dispatch Instruction Follow PNs: this will be dealt
through appropriate MWOF instructions that will ensure a profiled quantity equal
to the Physical Notifications;
 The potential new instruction on ‘Operation Mode’ for CCGT is still under review;
 It is likely that this will require a new Combination Code for SYNC instructions for
each individual Mode but this has not yet been defined;
 Further details will be provided by the vendor at the end of June;
 Also to be included in next version are details on the process for producing inputs
for QBOA calculations.
105
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
106
Administered Scarcity Price
Demand Control
Scarcity?
Voltage
Reduction
PDC= PFAS , QDC
= Max(FD–AD, 1)
1
Manual
Disconnection
PDC=PFAS, QDC =
Instructed DC
2
Automatic Load
Shedding
PDC= PFAS , QDC
= Max(FD–AD, 1)
3
PDC = PFLOOR,
QDC = 0
4
QSTR<ROR
PRS =
CRSP(QSTR)
5
Otherwise
PRS = PFLOOR
6
No Demand
Control
Reserve Scarcity
107
Administered Scarcity Price
3
Customer Voltage Reduction and Automatic
Load Shedding
5000
Demand
Control
4500
4000
3500
Demand (MW)
1
3000
2500
Forecast Demand
2000
Actual Demand
1500
1000
500
0
1
2
3
4
5
6
Imbalance Price Period (Hour 12)
108
Administered Scarcity Price
2
4
6
Planned/Emergency Manual Disconnection
– Takes place in blocks of X MW
– Demand Control Quantities based on
instructions sent to DSO
Where there is no Demand Control,
PDC = PFLOOR
Where there is no Reserve Scarcity,
PRS = PFLOOR
109
Administered Scarcity Price
5
Reserve
Scarcity Curve
to be
determined in
CRM
Parameters
consultation
110
Administered Scarcity Price
• Determination of Demand Control Bid Offer
Acceptances
– QAOuoiφ = QDCφ, PBOuoiφ = PFAS
– Treats Demand Control action in a similar manner
to any other energy action.
– Ensures Demand Control reflected in the NIV.
• Determination of Administered Scarcity Price
– PASφ = Max PDCφ , PRSφ
– PIMBφ = Max PIIMBφ , PASφ
– If Demand Control occurs, PIMBφ >= PFAS.
111
Ex-Ante Reference Price
• Comments received that PCURLγ process should be
based on actual trades for each unit rather than all
trades.
• Implies PCURLuγ i.e. each generator u has its own
PCURLuγ based on ex-ante trades.
• Exploring whether approach is possible and welcome
further detail from participants on suggested approach.
• Approach for market back-up price to remain broadly
the same.
• Both approaches to go to initial legal drafting for next
meeting.
112
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
113
Capacity Market Code
Proposed Timeline for CMC Development:
 CRM3 Decision – 8th July 2016
 Initial draft of CMC
 RWG9 – 27th July
 Plain English Doc 1
 RWG10 – 1st Sept
 Plain English Doc 2
 RWG11 – 6th Oct
 Initial Legal
 RWG12 – 10th Nov
 Final Legal
 Consultation – 25th Nov
 Four weeks
 RWG13 – 15th Dec
 Workshop
 Decision – 3rd Mar 2017
114
Capacity Market Code
•
•
The CMC is expected to take a similar form to
TSC.
The CMC is likely to include the following
areas:
–
–
Settlement
–
–
–
Transitional Arrangements
Interim Arrangements
Other areas:
•
•
Intro and Interpretation
Legal and Governance
•
•
•
•
•
•
•
–
–
–
Data and Information Systems
Trading
•
•
•
•
•
•
•
•
•
•
Registration (Party, Participant and Unit IDs
from Trading and Settlement Code)
Accession Process (this would be contractually
binding like the T&SC)
Qualification
Modifications (different from T&SC)
Dispute Resolution
Implementation Agreements
Other standard legal stuff
Reliability Option Register
Annual Auction
Secondary Trading
•
–
•
Outputs to Trading and Settlement Code
Implementation Agreement milestones and
bonds etc.
Capacity Requirement Methodology
Derating Methodology
Data Publication
Other Comms
Registration and Deregistration
Offer Data
Market Operator and System Operator
Transactions
Market Data Transactions
Agreed Procedures
The above section headings and layout may
differ as the CMC continues to develop and
be refined through the process.
115
Force Majeure – last meeting
 At May WG meeting proposed two changes to the existing FM
provisions
1. Clarify that FM would not relieve a participant of its
obligations to pay imbalance charges;
2. Remove the obligation on the Market Operator to determine
whether a participant’s claim of an FM event is valid
Canvassed alternative views or approaches.
116
Force Majeure – Feedback/Next Steps
The only comments received (verbally or in writing) supported
the proposals, no alternatives suggested.
Clarification sought re. generator prevented from delivering exante contract quantity due to network outages/constraints:
— addressed in SEMC ETA Building Blocks Decision SEM-15-064;
— units with firm access will not be exposed to imbalance charges
Therefore, progressed direct to initial legal drafting to reflect this
position and other editorials
In addition to clarifying that a FM does not relieve a participant
from imbalance payment obligations, the proposed rule clarifies
this also applies in respect of capacity payments.
117
Agent of Last Resort
 Market Operator to be assigned AOLR role
 AOLR role to be assigned through MO license
 Licence condition may require MO to develop/maintain
separate AOLR rules/procedures
 Discussions ongoing between MO and RAs regarding
implementation of license obligations and governance of
AOLR rules - further update next meeting
 Some minor updates to the AOLR Plain English Paper
118
AOLR- Update
 Brief clarifications in relation to:
 Submission of unit’s own forecast : Only TSO Forecast is used (currently Wind
only); units without TSO forecast can only submit a profile based on % of
Unit Capacity per each 15 mins;
 New parameter ‘Minimum Trading Volume’ only applies to IDM submissions;
however its applications are still under review;
 Validations of PNs submitted based on Unit Capacity;
 Lower and Upper Price Trading Range are the bids and offers for buying and
selling in Ex-Ante; if no value is specified they default to PFLoor and PCap;.
 Compared to other systems, AOLR is still at an early stage of
specifications. Please provide comments if you wish further changes to
the current design.
119
Parameter Setting Process
 A number of parameters exist within the current T&SC that will persist
along with a number of additional that have been developed as part of the
rules drafting;
 Project team have been considering approach to setting these values;
 Have reviewed the process applied for the original SEM as part of this;
 The process involved studies being carried out by RAs and TSOs during
2007;
 RA consultations issued in August 2007;
 Final decisions published during Market Trial;
120
Parameter Setting Process
 Process will include the following steps –
1)
Identify Parameters
2) Group where appropriate (e.g. – settlement, credit cover, etc.)
3) Consider RA tratment (e.g. – annually set, from time to time, etc.)
4) Carry out required studies / analysis
5) Public consultation process including
a)
Publication of relevant reports;
b)
Publication of consultation papers;
c)
Appropriate timeline for participant consideration and response;
d)
Review responses and SEMC decision;
121
Parameter Setting Process
Assessment
of
parameters
SEMC
Decision
Publication
Studies and
analysis
Public
Consultation
 In considering timelines, need to decide when parameters must be
decided;
 Working backwards from this date, public consultations are due early 2017
 Assessment of parameters will be completed later this year.
122
Appendices to the T&SC
 Appendices to be produced as part of the final market rules;
 Existing appendices will form the basis of the proposals for the new T&SC;
 Current set can be broken into
 Legal Documents;
 Data requirements; and
 Algorithm Descriptions.
 Break these down over next slides
 Intent is to roll these out over the next two releases of documents;
 Full set available for publication of consolidated rules in August;
123
Appendices to the T&SC
 Legal Documents includes the following;
 Standard Letter of Credit;
 Disute Resultion Agreement; and
 Form of Authority.
 Review of these shows that Letter of Credit and Dispute Resolution
Agreement can be adopted for I-SEM T&SC with minimal change (e.g.,
cross references, removal of redundant text)
 Form of Authority requires more work;
 References to the pool to be removed;
 Paragraph 2.3 has requirements around Price Taker concept which need to
be updated.
124
Appendices to the T&SC
 Data requirements covers the following –
 Data Publication
 Other Communitations
 Settlement Statements
 Participant and Unit Registration
 Offer Data
 Market Operator and System Operator Data Transactions
 Market Data Transations
 Meter Data Transactions
125
Appendices to the T&SC
 Data requirements
 A number of significant changes to these sections based on new data
items included in I-SEM;
 Data Publication and Offer Data will be updated to reflect market
design;
 Some will have lesser change required (e.g., data items for Participant
and Unit Registration, Other Communications incl. units under test,
etc.)
 Will need to remove redundant concepts and replace with new data
communication requirements (e.g., NEMO communications)
 Meter Data Transactions will need to be updated to reflect that
metering no longer required for pricing processes;
126
Appendices to the T&SC
 Algorithm Descriptions covers –
 Description of the Function for Determination of Capacity Payments;
 Operation of the MSP Software;
 Instruction Profiling; and
 Interconnector Unit Credit Cover Assessment.
 For I-SEM, only Instruction Profiling will be retained;
 Function for Determination of Capacity Payments will be replaced by
content in Capacity Market Code;
 Operation of MSP Software no longer relevant;
 Interconnector Unit Credit Cover concept no longer applicable;
127
Transitional Arrangements
 Last month discussed proposed TSC approach:
 Part A existing rules (maybe some amendments)
 Part B rules for I-SEM arrangements
 Part C possible transitional rules
 Explained more detailed to be provided as rules drafting
progresses
 Start to identify transitional provisions at July WG meeting
 Will need detailed arrangements to cover change of
trading day on the cut-over day
128
Intermediaries
 At May 2016 WG meeting reviewed existing TSC provisions on:
 Intermediaries
 Aggregated Generator Units
 Concluded that only editorial changes required for I-SEM, possibly
relocation of AGU provisions alongside the Intermediaries provisions
 Identified need to change terminology in the Form of Authority in TSC
Appendix C; and
 RAs to consider re-viewing Decisions SEM-07-11 and SEM-11-004 that
provide criteria for RA approval (due to changed terminology “Price
Maker”/”Price Taker”
 Inconsistency identified between Grid Code and TSC definitions of
generators eligible for aggregation
 Changes being drafted for initial review by the Rules WG at its July meeting
129
Market Operator/System Operator
 Definitions of Market and System Operator in TSC and Grid
Code will be unchanged
 Minor changes to existing TSC Market Operator paragraphs
2.117 – 2.125
• Change reference to “Pool” to “SEM”
• Delete paragraph re. MSP – redundant
• If required, enable MO participation in the SEM as AoLR
- Dependent on AoLR implementation
 Revised obligations on Market Operator will be imposed
through combination of MO license and TSC amendments
 Need for amended obligations on System Operator in terms
of the dispatch process is noted but again likely to be dealt
with in SO license and/or Grid Code.
130
Obligations on Parties
Paragraphs 2.126 – 2.130 of existing TSC
“Boilerplate” legal provisions regarding obligations on Parties to
comply with the Code
No material changes identified to date – except use of
terminology “Pool”
Legal review & any editorial changes to be presented to July WG
meeting

131
Balancing Market Operations Timetable
Concept of Balancing Market Operations Timetable presented at
April WG meeting

A number of comments received on indicative contents & will be
considered in finalising content
Content cannot be finalised until scheduling & dispatch process
finalised and consideration given to data publication requirements
Preliminary draft of rule provided in paper for May WG meeting
Comment requested inclusion of timings for credit cover reports
and settlement reruns
Draft rule has been amended accordingly
132
Agenda
 Welcome and house-keeping;
 Scheduling and Dispatch Process– Plain English part 2;
 Imbalance Settlement – Interim Legal Draft;
 CRM Settlement - Initial Legal Draft;
 Financial Settlement– Interim Legal Draft;
 Balancing Market Data Submission – Initial Legal Draft
 Information System and Data Publication update – Revised Plain English
 Dispatch Profile – Revised Plain English
 Administered Scarcity Price & Ex-Ante Reference Price – Initial Legal Draft
 Miscellaneous: Capacity Market Code, Force Majeure, AOLR Update, Parameter Definition Process,
Appendices Timelines Updates, Transitional Arrangements, Trading Sites, Intermediaries, Market Operator,
Obligations on Parties, Balancing Market Operator Timetable, Default Suspension and Termination.
 AOB & Next Steps.
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