This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
Slide 1
Cross Codes Forum 21 September 2012 ELEXON, National Grid &
Electralink
Slide 2
Introduction and Housekeeping Emma Piercy
Slide 3
3 What well cover today: Welcome to ELEXON Energy Supply
Company Administration Scheme European Network Codes Update on CUSC
& Grid code modifications Significant Code Review Update on
DCUSA change proposals & SPAA Update on BSC modifications
Slide 4
4 ELEXON Evacuation Muster Point If there is an alarm, follow
the instructions of the Fire Wardens The evacuation point is
here
Slide 5
Energy Supply Company Administration Dawn Armstrong System
Balancing and Retail Markets 5
Slide 6
66 SoLR arrangements tested several times Unlikely to work in
the event of a major suppliers insolvency Concerns around length of
time it could take to either sell the company or transfer customers
leading to excessive and unpredictable imbalance payments for other
parties Risk of financial failure spreading to other industry
participants Provisions included in Energy Act 2011 for a special
administration regime for supply companies Context
Slide 7
77 Energy Act 2011 provides broad legal framework Energy Supply
Company Administration Rules rules of procedure required for full
implementation (separate rules for Scotland) Modification of
licences to institute a cost recovery mechanism Legal
Framework
Slide 8
88 Rules mirror as far as possible ordinary insolvency rules
and include: Process for making an application; Steps to be
followed in energy supply company administration proceedings;
Energy administrator remuneration; Conduct of creditors and company
meetings; Provisions governing distributions to creditors; The
arrangements for ending energy supply company administration.
Energy Supply Company Administration Rules :
Slide 9
99 Provisions in the Energy Act for the company in esc
administration to repay any funding received from government.
Provisions for SoS to amend licences for the purpose of setting up
a cost recovery mechanism. Proposal is to replicate cost recovery
mechanism already in place for the special administration regime
for network and distribution companies. Costs smeared across
suppliers. Cost recovery mechanism
Slide 10
10 SoS issues a shortfall direction to Grid to raise the
charges it levies on electricity suppliers and gas shippers
Direction would include: which charge should be raised; details of
amount to be raised; how it is to be raised; when the payments are
to be made. How would it work?
Slide 11
11 Propose maximum flexibility to raise any of the charges Grid
currently levies on electricity suppliers and gas shippers m
Transmission Network Use of System and Balancing Charges
sufficiently broad in scope to allow Grid to increase to cover a
shortfall But changes necessary to: SLC 15 in electricity supply
licences SLC 19 to shippers licences SLC 15 was amended in 2006 to
allow Grid to raise the charge to discharge a shortfall direction
in relation to Energy Administration (SAR for network and
distribution). SLC 19 was a new condition inserted to allow Grid to
raise charges on shippers to discharge a shortfall direction.
Propose amending both allow Grid to raise charges to shortfall
direction in relation to esc administration. Proposed licence
changes
Slide 12
12 Draft England and Wales rules were published in June Aim to
publish Scotland Rules in September Licence changes for cost
recovery mechanism aim to publish October Rules on the statute book
and licence changes complete by April 2013 Timing
Slide 13
European Network Codes Information for the Cross-Codes Forum
Paul Wakeley Electricity Codes Regulatory Frameworks National Grid
21 September 2012
Slide 14
14 Agenda The Third Package European Network Codes Process
Status Further Information and Getting Involved
Slide 15
The Third Package
Slide 16
16 Third Package The European Third Energy Package was adopted
in July 2009, and has been law since March 2011 Key step forward in
developing a more harmonised European energy market Separation of
ownership of monopoly energy transmission activities The formation
of European Transmission System bodies, ENTSOG and ENTSO-E The
formation of ACER Agency for Cooperation of Energy Regulators ACER
and ENTSO-E both have a role in the development of European Network
Codes (ENCs)
Slide 17
17 Third Package ENTSO-E European Network of Transmission
System Operators 41 TSOs from 34 countries What ENTSO-E does:
Drafting European Network Codes (ENCs) Europe-Wide Ten-Year Network
Develop Plan (TYNDP) including a European generation adequacy
outlook, every two years Common network operation tools to ensure
coordination of network operation in normal and emergency
conditions Annual summer and winter generation adequacy
reports
Slide 18
Electricity European Network Codes
Slide 19
19 Electricity European Network Codes There are 12 areas where
Network Codes will be developed to support cross-border issues
Regulations on Data Transparency, Governance Guidelines and Tariff
Harmonisation are to be developed by the Commission Target date for
Single European Energy Market is 2014 Where there is a difference
to existing national rules, European Network Codes take
precedence
Slide 20
20 European Network Code Development Process The process for
developing the European Network Codes is defined in EU law 6
monthsTo fit work programme 1 year3 months By 2014 Network Code
becomes Law ACER reviews Network Code ENTSO-E develops Network Code
Commission invites ENTSO-E to develop Network Code ACER develops
FWGL Commission starts development process Comitology Commission 1
year? Stakeholder Engagement
Slide 21
21 The live Network Codes ACER Framework GuidelineENTSO-E
Network Code Grid ConnectionsRequirements for Generators (RFG)
Demand Connection Code (DCC) HVDC Capacity Allocation and
Congestion Management CACM (Day ahead and intraday) Forwards
Markets BalancingBalancing Network Code System OperationOperational
Security Operational Planning and Scheduling Load-Frequency Control
and Reserves
Slide 22
22 Drafting and Stakeholder Workshops Public Consultation
Revise Code Assembly Approval RFG DCC HVDCBalancing CACM Forwards
Op SecOp Sch & PlanLF&R Grid Connection FWGL CACM FWGL
System Operation FWGL Balancing FWGL 6 monthsTo fit work programme
1 year3 months1 year ?2014 Network Code becomes Law Comitology ACER
reviews Network Code ENTSO-E develops Network Code EC invites
ENTSO-E to develop Network Code ACER develops FWGL
Slide 23
23 October 2012 Highlights CACM Network Code is submitted by
ENTSO-E to ACER for review against the Framework Guidelines
Forwards Markets Network Code drafting due to commence Balancing
Network Code drafting expected to commence, once Framework
Guidelines completed ACER to publish opinion on RFG Network
Code
Slide 24
Implementation of European Network Codes within GB
Slide 25
25 Key Issues European Network Codes take precedence over
existing national arrangements - we must therefore change our Codes
There are elements of national choice in the ENC There will be
multiple ENCs with various timeframes / applicability which will
require changes to all GB Codes (Grid Code, STC, CUSC, BSC, D-Code,
DCUSA etc). Different thresholds in ENCs to those in GB, e.g. Grid
Code has Small, Medium and Large power stations; RFG has Type A, B,
C, D power generating modules. Type A applies from 800W
upwards
Slide 26
26 From Presentations from 4th Elec SG - DECC/Ofgem Stakeholder
Group How will Code Change be implemented?
Slide 27
Getting Involved / Further Information
Slide 28
28 How to get involved ENTSO-E workshops and consultations
http://www.entsoe.eu http://www.entsoe.eu Joint European Standing
Group: GB stakeholder workshops and consultations facilitated by
National Grid
http://www.nationalgrid.com/uk/Electricity/Codes/systemc
ode/workingstandinggroups/JointEuroSG/
http://www.nationalgrid.com/uk/Electricity/Codes/systemc
ode/workingstandinggroups/JointEuroSG/ DECC / Ofgem Stakeholder
Group http://www.ofgem.gov.uk/Europe/stakeholder-
group/Pages/index.aspx http://www.ofgem.gov.uk/Europe/stakeholder-
group/Pages/index.aspx
31 Grid Connection FWGL Network CodeDescriptionStatus
Requirements for Generators Harmonising and updating technical
connection requirements for all types of generators to facilitate
security of supply, as well as non-discrimination, effective
competition and the efficient functioning of the internal
electricity market. ENTSO-E drafting complete ACER now reviewing
Demand Connection Code Focuses on the connection of industrial
loads and DSOs and sets out requirements which will apply to the
demand side of the power system, contributing to system security
and efficient load management. Public consultation complete ENSTO-E
finalising drafting HVDCRules for the use of HVDC
technology.ENTSO-E drafting starts in Jan 2013
Slide 32
32 CACM FWGL Network CodeDescriptionStatus Capacity Allocation
and Congestion Management Aims to couple existing European
electricity markets to create a pan European internal market.
Harmonising market rules for calculating and allocating capacity in
the day-ahead and intraday timeframes. Undergoing ENTSO-E approval
Due to be submitted to ACER 1 October 2012 Forwards Market Aims to
couple existing European electricity markets to create a pan-
European internal market. Harmonises market rules for calculating
and allocating capacity in the Forwards Markets. ENTSO-E drafting
starts in October 2013
Slide 33
33 Balancing FWGL Network CodeDescriptionStatus BalancingRules
for cross-border exchange of reserves and balancing energy which is
consistent with operational standards. Awaiting final ACER
Framework Guidelines Commission to invite ENTSO-E to draft ENTSO-E
drafting expected to start in October 2013
Slide 34
34 System Operation (1) Network CodeDescriptionStatus
Operational Security Establishes common security principles,
including harmonising of quality of system operation and
coordination of operational activities. Applicable to TSO, DSOs,
generators and consumption. Public Consultation September October
2012 Operational Planning and Scheduling Covers activities and
tasks conducted prior to real-time operation and include outage
scheduling, day ahead congestion forecast and N-1 contingency
analysis (which could be complemented with other security analyses
like e.g. voltage stability analysis), but also the commercial and
TSO scheduling processes. ENTSO-E drafting continues. Public
consultation November- December 2012
Slide 35
35 System Operation (2) Network CodeDescriptionStatus Load,
Frequency & Reserves Code Considers the real-time balance
between generation and demand to control system frequency; to
achieve and maintain satisfactory frequency quality in terms of the
frequency deviations from the nominal value and how often these
deviations occur within a defined time period (standard deviation
of frequency). Early stages of ENTSO-E Drafting, due for
consultation Feb/Mar 2013
Slide 36
Place your chosen image here. The four corners must just cover
the arrow tips. For covers, the three pictures should be the same
size and in a straight line. CUSC and Grid Code Changes Emma Clark
Electricity Codes Regulatory Frameworks National Grid 21 September
2012
Slide 37
37 CUSC Modifications CMP201 Removal of BSUoS charges from
Generators Seeks to align GB arrangements with other EU Member
States by removing BSUoS charges from GB Generators. Panel
Recommendation Vote on 28 September 2012. CMP202 Revised treatment
of BSUoS charges for lead parties of interconnector BM Units
Removes BSUoS charges for Interconnector BM Units which furthers
the European Commissions objectives of facilitating cross-border
access and developing a Europe-wide single internal market in
electricity. Approved by Authority and Implemented on 31 August
2012. CMP203 TNUoS charging arrangements for infrastructure assets
subject to one-off charges Any user who pays a one-off charge will
not end up being charged again for the works through TNUoS.
Decision due on 18 September 2012.
Slide 38
38 CUSC Modifications (2) CMP206 - Requirement for NGET to
provide and update year ahead TNUoS forecasts Seeks to introduce a
requirement to publish a year ahead forecast of TNUoS charges which
would also be updated at regular intervals throughout the year. WG
report presented to August CUSC Panel, currently out for Code
Administrator Consultation. CMP208 Requirement for NGET to provide
and update forecasts of BSUoS charges each month Seeks to introduce
a requirement to produce accurate monthly updated forecasts of
BSUoS charges for the current and following financial years. WG
report to be presented to October CUSC Panel. CMP207 Limit
increases to TNUoS tariffs to 20% in any one year. Seeks to amend
the TNUoS charging methodology to revise the calculations of
tariffs for generation and demand so that no tariff can increase by
more than 20% in any one year. WG report to be presented to
September CUSC Panel.
Slide 39
39 CUSC Modifications (3) CMP209 (charging) and CMP210 (CUSC)
Allow Suppliers submitted forecast demand to be export Seeks to
allow suppliers to submit a negative demand forecast for the year
and receive the embedded benefits payments on a monthly basis
within year. WG report to be presented to September CUSC Panel.
CMP211 Alignment of CUSC compensation arrangements for across
different interruption types. Seeks to align compensation
mechanisms in order to treat parties fairly. CMP212 Setting limits
for claims: submission, validation and minimum financial threshold
values in relation to relevant interruptions. Seeks to adjust the
administrative arrangements with regard to dealing with claims,
such as timescales and levels of claim values. CMP213 Project
TransmiT TNUoS Developments Made up of 3 main elements Network
Capacity Sharing, Inclusion of HDVC in the charging calculation and
inclusion of island links into the charging methodology. Currently
in the Workgroup phase, implementation likely to be April
2014.
Slide 40
40 Grid Code Modifications A/12 Information required to
evaluate sub-synchronous resonance proposes changes to facilitate
the exchange of information required to evaluate and mitigate the
risk of sub-synchronous phenomena. Currently considering responses
and issues raised following Code Administrator Consultation. B/12
Formalising Two Shifting Limit (TSL) and other parameters seeks to
make TSL and certain items of other relevant data formal
parameters. Workgroup Report submitted on TSL following issue
raised by another party. A meeting was held recently to discuss
these issues and B/12 is now continuing exclusive of TSL. C/12
Safety Management of Three Position GIS Earth Switches Permits the
option of Earthing before Points of Isolation have been established
in England and Wales Transmission area. Industry Consultation
recently closed and responses being considered.
Slide 41
41 Grid Code Modifications (2) C/11 BM Unit Data from
intermittent Generation Amends definitions of Output Useable and
Physical Notification Revised Workgroup report and Industry
Consultation being drafted following further refinement to the
proposal by the Workgroup. B/10 Record on Inter- System Safety
Precautions (RISSP) Adds further clarity in connection with the
RISSP which provides a written record of safety precautions that
are to be utilised in accordance with the applicable provisions of
OC8. Final Report submitted to the Authority in November 2011 but
concerns regarding the impact on offshore parties. Report was
re-submitted in August 2012 after concerns addressed and Authority
approved on 6 September 2012.
Slide 42
42 Further Info Transmission Charging Methodology Forum (TCMF)
is the best place to raise transmission charging issues and get
info on current and forthcoming CUSC charging proposals: Usually
meets every 2 months Each CUSC/BSC Party entitled to send a
representative http://www.nationalgrid.com/uk/Electricity/Charges/T
CMF/http://www.nationalgrid.com/uk/Electricity/Charges/T CMF/
Electricity Balancing SCR Cross Codes Forum, 21 September 2012
Andreas Flamm
Slide 45
45 Contents Background History SCR Process Indicative timetable
Objectives of SCR Main interactions Primary considerations
Secondary considerations Next steps Electricity Balancing SCR
Slide 46
46 Background Long-standing concerns with electricity balancing
arrangements (eg cash- out prices may not fully reflect scarcity at
times of system stress) These were highlighted in cash-out reviews
in the past and in Project Discovery in 2010 Electricity cash-out
issues paper 1 November 2011 Open letter: decision to launch
electricity cash-out SCR 28 March 2012 Stakeholder event on scope
of electricity cash-out SCR 30 April 2012 Publication of launch
statement, initial consultation and P217A analysis 1 August 2012
Taking forward the SCR with a wide scope allows us to reform the
arrangements comprehensively. History
Slide 47
47 SCR Process Introduced in January 2011 following completion
of Code Governance Review Allows Ofgem to lead on a holistic review
of a code-based issue with a significant impact Open, accessible
and consultative process - 12 months (or longer if complex issue as
with the EB SCR, which we estimate will last ~18 months) Initial
consultation, draft policy decision, final decision Relevant
licensee directed to raise code mods GEMA to approve/reject System
changes may be required as part of implementation Background
Slide 48
48 Indicative electricity balancing SCR timetable Background
Usual BSC mod process
Slide 49
49 Objectives Incentivise an efficient level of security of
supply Incentivise optimal level of investment Pay firm customers
appropriately for the DSR service they provide if their demand is
involuntarily interrupted Incentivise plant flexibility and DSR
Increase the efficiency of electricity balancing Minimise market
distortions due to the need for the SO to balance the system
Incentivise participants to balance their position as far as is
efficient Appropriately reflect the SOs cost for balancing in
cash-out prices Ensure our balancing arrangements are compliant
with the European Target Model and complement the EMR Capacity
Mechanism Background
Slide 50
50 Main interactions European Target Model (TM) Throughout our
review we will aim to ensure that any changes are compliant with
the developing TM. We will also carefully consider timing of reform
to avoid costs associated with repeated market changes. EMR
Capacity Mechanism (CM) Electricity cash-out and CM have distinct
but complementary roles in providing security of supply. In policy
design and before implementing any reforms we will consider the
impact on the effectiveness of the CM carefully. Ongoing mods GEMA
to decide if mods raised during SCR are to be subsumed as falling
within scope For related mods raised prior to SCR launch normal mod
process applies, i.e. GEMA to decide whether to accept/reject
Background
Slide 51
51 Scope: Primary Considerations Changes to existing balancing
arrangements More marginal main cash-out price Single or dual
cash-out price Single or separate trading accounts Pay-as-bid or
pay-as-clear for energy balancing services Improvements to price
inputs Attributing a cost to non-costed actions Improved allocation
of reserve costs New balancing arrangements Balancing Energy Market
(BEM) Alternative arrangements for renewables Primary
Considerations
Slide 52
52 Changes to existing arrangements More marginal main cash-out
price Cash-out price may not fully reflect scarcity at times of
system stress We will consider making cash-out prices more marginal
(through changing PAR level). P217A analysis (work Ofgem has done
with Elexon and NG) indicates that mod P217A has reduced system
pollution of cash-out prices, which was one of the main obstacles
to lower PAR levels in the past. Single or dual cash-out prices
Dual cash-out prices have large spreads, increase risk and
complicate arrangements Economic theory: there should only be one
price for a commodity at a time. We would like to consider the
merits of a single price or of hybrid options. Primary
Considerations
Slide 53
53 Changes to existing arrangements Single or separate trading
accounts Participants who operate on both sides of the market are
required to balance their consumption and production positions
separately. We will consider the merits of allowing them to net of
their positions Pay-as-bid or pay-as-clear for energy balancing
services Theory: similar outcome with perfect foresight Practice:
no perfect foresight. Pay-as-clear more efficient since
participants are incentivised to bid their true marginal cost?
Primary Considerations
Slide 54
54 Improvements to price inputs Attributing a cost to
non-costed actions Some balancing actions available to the SO, such
as voltage control and involuntary demand disconnection, are not
currently reflected in the cash-out price Improved allocation of
reserve costs Target reserve cost more accurately into the periods
for which they are procured and/or in which they are used. Primary
Considerations
Slide 55
55 New balancing arrangements Balancing Energy Market (BEM)
Could allows anticipated energy imbalances on the system (and
individual participants imbalances) to be cleared at a point ahead
of real time. Would constitute a major change to current
arrangements Alternative arrangements for renewables Intermittent
renewables are not able to control their output to the same extent
as conventional generation. Fluctuations in wind output pose a
challenge to balancing the system. Is it more efficient overall for
intermittent generation to be aggregated centrally or de-centrally?
Need to consider effects on incentives for accurate forecasting and
independent aggregation. Primary Considerations
Slide 56
56 Scope: Secondary Considerations Secondary considerations may
become relevant depending on choices made on primary considerations
some may also warrant investigation separately. Improved provision
of information Creating a Reserve Market Amending gate closure
Residual cashflow reallocation cashflow (RCRC) Reverse price
Setting an information imbalance charge Secondary
Considerations
Slide 57
57 Next steps Stakeholder events during initial consultation
period W/C 3.9.12: Opening seminar & Workshop 1 Three further
workshops in September and October Initial consultation closes 24
October 2012 Find consultation questions in initial consultation
document Following end of consultation we will consider responses
and input received through stakeholder events for further policy
development Potentially additional closing seminar: November 2013
Potential further stakeholder seminars: Early 2013 Publish draft
decision and draft IA in spring 2013
Overview of Common Distribution Charging Methodologies in DCUSA
Open Governance - CDCM and EDCM The governance and change
management processes for the CDCM were implemented into the DCUSA
on 01 January 2010. The governance and change management processes
for the EDCM (import) were implemented into the DCUSA on 01 April
2012. There are two CPs currently going through the DCUSA Change
Process to bring in the following methodologies EDCM (export) 01
April 2013 Common Connection Charging Methodology - 01 October 2012
As the methodologies will be common among all DNOs, this brings
about many improvements, such as: More transparency The
complexities of the methodologies has been agreed, and dialogue
among all Parties have to be taken into account When there is a
change brought about by any Party, all DNOs must implement it and
model the changes.
Slide 61
DCUSA Change Process - Overview Pre-Change Process (Charging
methodology changes) CP raised Initial Assessment Industry
Consultation Working Group Assessment Change Report Implementation
Authority Consent Change Declaration Party Voting Parties Panel
Secretariat Ofgem Modelling Resource
Slide 62
Live DCUSA Change Proposals.
Slide 63
.
Slide 64
.
Slide 65
DCP 054 Revenue Protection/Un-recorded Units into Settlements
Ensures that a Revenue protection service is in place by either the
Company or the User and proper governance of the Theft of
Electricity Code of Practice. This code of practice has been
developed in cooperation with the SPAA Theft of Gas Code of
Practice A consultation on the Code of Practice will be issued
shortly. DCP 114 and DCP 115 NTC Amendments Capacity Management (
Over and Under Utilisation) DCP 114 - Seeks to provide rights to
the DNO, within the NTC, to take appropriate action where connected
customers are found to be over utilising their maximum import
capacity (MIC) and/or maximum export capacity (MEC). DCP 115 -
Seeks to provide rights to the DNO, within the NTC, to take
appropriate action where a connected customers requirements are
less that the maximum import capacity (MIC) and/or maximum export
capacity (MEC) agreed for their connection. DCP 114 and 115 are
reviewing consultation responses and will issue a Change Report to
the October DCUSA Panel.
Slide 66
Live DCUSA Change Proposals DCP 124 Third Party Network -
National Connection Terms Amendments DCP 124 introduces the
concepts of Licence Exempt Distribution Network Operators
Distribution System and Embedded Metering Point into section 1 and
5 of the National Connection Terms in order to apply equivalent
terms to a Licence Exempt Distributor. This change is currently
seeking legal advice, before it will issue a wider consultation to
the Industry. DCP 127 Gas First Smart Meter Installation Provides
for gas suppliers to accede to the DCUSA so their operatives can
de/re energise electricity meters to fit smart gas comms hubs
BEFORE there is a smart electricity meter. The Working Group has
drafted a guidance note containing advice for how this could work
in practice. A second consultation will be issued shortly. There
are related changes raised in SPAA and the MOCOPA.
Slide 67
Live DCUSA Change Proposals DCP 130 - Remove the discrepancy
between non-half hourly (NHH) and half hourly (HH) Un-metered
Supplies (UMS) tariffs Seeks to remove a differential in the DUoS
tariffs for HH UMS and NHH UMS customers that can sometimes
incentivise HH UMS customers to elect to be settled on a NHH basis
or vice versa. A consultation on this CP is now with Industry
Parties. DCP 137 Introduction of locational tariffs for the export
from HV generators in areas identified as generation dominated
Seeks to amend the calculation of DUoS charges for High Voltage
(HV) generators, such that the credits currently paid for the units
exported by HV generators would be reduced or removed for those
generators connected to primary substations that have been
identified as generation dominated. A consultation on this CP is
now with Industry Parties.
Slide 68
Live DCUSA Change Proposals DCP 141 to DCP 149 Billing Group
Change Proposals The DCMF MIG received many issues that were
related to billing procedures, and their the fact they are not
consistent among the DNOs. A Supergroup for Billing Issues was set
up to assess and develop these CPs. The first set of 9 changes have
been sent to Working Group status by the DCUSA Panel. A
consultation for each of these issues is now with Industry Parties.
DCP 152 Implementation of the combined EDCM for import and export
charges The EDCM for import charges was implemented on 1 April
2012. This CP seeks to implement the EDCM for export charges,
subject to approval from Ofgem of the methodology. A consultation
for each of these issues is now with Industry Parties.
Slide 69
Live DCUSA Change Proposals DCP 153 Service Level Agreement for
Resolving Network Operational Issues With the mass roll out of
smart metering it is expected that there will be an increase in the
number network operational issues identified. This CP seeks to
introduce Service Level Agreements on DNOs for the resolution of
these network issues. A consultation on this CP will be issued
within the month
Current SPAA Activities Meter Asset Managers Code of Practice
Defines the standards/processes MAMs that want to be/stay
accredited should adhere to Newly brought under the SPAA, as of 29
August 2012 Theft of Gas Nearing completion of the final draft CoP,
ready to be issued as a SPAA CP Data Protection Act Theft Risk
Assessment Service Gas Smart Working Issues Group Join gas codes
working group on changes required for enduring smart arrangements
Mods raised to the UNC and iGT UNC SPAA changes will be considered
later this year
Slide 72
Questions or Comments Michael Walls Governance Services Senior
Analyst ElectraLink Ltd. Email:
[email protected]@electralink.co.uk Tel:
020 7432 3014
Slide 73
Update on BSC Modifications David Kemp 21 September 2012
Slide 74
74 Active BSC Modifications ModTitlePhase P272 Mandatory Half
Hourly Settlement for Profile Classes 5-8 Assessment Procedure P274
Cessation of Compensatory Adjustments Assessment Procedure P276
Introduce an additional trigger/threshold for suspending the market
in the event of a Partial Shutdown Awaiting Implementation P278
Treatment of Transmission Losses for Interconnector Users Awaiting
Implementation P280 Introduction of new Measurement Classes With
Authority P281 Change of BSCCo Board of Directors & Chairman
Awaiting Implementation P282 Allow MVRNs from Production to
Consumption or Vice Versa Assessment Procedure P283 Reinforcing the
Commissioning of Metering Equipment Processes Assessment Procedure
P284 Expansion of Elexons role via the contract model Implemented
P285 Revised treatment of RCRC for Interconnector BM Units
Assessment Procedure P286 Revised treatment of RCRC for generation
BM Units Assessment Procedure P287 Allow the BSC Panel to conduct
Modification Business via teleconference Rejected
Slide 75
75 Issue: HH Settlement for PCs 5-8 not currently enforced New
meters in PCs 5-8 must be advance/smart All PC 5-8 meters to be
advanced/smart by 2014 Proposed Solution: All SVA Metering Systems
for PCs 5-8 will be settled as HH from April 2014 Alternate
Solution: As Proposed, but from April 2015 BSC Modifications P272
(1 of 2) P272 Mandatory Half Hourly Settlement for Profile Classes
5- 8 Phase Assessment Procedure Contact David Kemp 020 7380 4303
david.kemp@ele xon.co.uk Who will be impacted by P272? Suppliers
DCs MOAs LDSOs
Slide 76
76 Currently undergoing assessment by a Workgroup Workgroup
currently carrying out cost-benefit analysis Assessment Report to
Panel in November Workgroups Assessment Report was presented to
Panel in January Majority view to Reject both Proposed and
Alternate Majority view that Alternate better than Proposed Ofgems
view: Await outcome of P280, DCP 103 & MIG 22 before making
decision Report Phase Consultation will be issued in November BSC
Modifications P272 (2 of 2) P272 Mandatory Half Hourly Settlement
for Profile Classes 5- 8 Phase Assessment Procedure Contact David
Kemp 020 7380 4303 david.kemp@ele xon.co.uk
Slide 77
77 Issue: GVC can have adverse implications under the BSC New
entrants allocated volume from before they started Receiving
volumes from cheaper/more expensive periods Impact on accuracy of
LLFs Proposed Solution: Use re-initialisation to address
crystallised error when Compensatory Volume would otherwise be
excessive Alternate Solution: Limit period for which error can be
compensated 5 years prior to RF at time GVC performed BSC
Modifications P274 (1 of 2) P274 Cessation of Compensatory
Adjustments Phase Assessment Procedure Contact Talia Addy 020 7380
4043 talia.addy@elexo n.co.uk Who will be impacted by P274?
Suppliers LDSOs NHHDCs
Slide 78
78 Currently undergoing assessment by a Workgroup Assessment
Report to Panel in October Original solution was to end GVC
completely Proposer has since refined the solution to limiting GVC
Change is complex Workgroup has drafted and consulted on CSD
changes as well as Code changes Report Phase Consultation will be
issued in October BSC Modifications P274 (2 of 2) P274 Cessation of
Compensatory Adjustments Phase Assessment Procedure Contact Talia
Addy 020 7380 4043 talia.addy@elexo n.co.uk
Slide 79
79 Issue: Partial Shutdown would suspend entire Market
Disproportionate for small localised Partial Shutdowns Approved
Solution: Introduce Market Suspension Threshold: If not met, Market
continues as normal Does not affect Total Shutdowns Approved for
implementation on 31 March 2014 Better facilitates ABOs (b), (c)
and (d) BSC Modifications P276 (1 of 1) P276 Introduce an
additional trigger/threshold for suspending the market in the event
of a Partial Shutdown Phase Awaiting Implementation Contact Kathryn
Coffin 020 7380 4030 kathryn.coffin@e lexon.co.uk Who will be
impacted by P276? BSC Trading Parties
Slide 80
80 Issue: European regulations compensate GB for transmission
losses caused by Interconnectors Approved Solution: Set TLM to 1
for Interconnector BM Units Approved for implementation on 29
November 2012 (November 2012 Release) Better facilitates ABOs (a),
(c) and (e) BSC Modifications P278 (1 of 1) P278 Treatment of
Transmission Losses for Interconnector Users Phase Awaiting
Implementation Contact David Kemp 020 7380 4303 david.kemp@ele
xon.co.uk Who will be impacted by P278? I/C Users IEAs Indirect:
Other BSC Trading Parties
Slide 81
81 Issue: HH-settled customers charged on site-specific basis
Future changes (such as P272 and smart) will rapidly expand number
of HH Settled sites Costs to Distributors would be very large
Proposed Solution: Introduce 3 new Measurement Classes and
associated CCCs Allow sub-100kWh HH Settled customers to be
invoiced on aggregated basis Site Specific billing will remain for
those Suppliers who wish to continue to receive them BSC
Modifications P280 (1 of 2) P280 Introduction of new Measurement
Classes Phase With Authority Contact Dean Riddell 020 7380 4366
dean.riddell@ele xon.co.uk Who will be impacted by P280? Suppliers
LDSOs HHDAs HHDCs
Slide 82
82 Workgroup and Panel recommend Approve Better facilitates
ABOs (c) and (d) Recommend implementation on 1 October 2013
Currently with Ofgem for decision BSC Modifications P280 (2 of 2)
P280 Introduction of new Measurement Classes Phase With Authority
Contact Dean Riddell 020 7380 4366 dean.riddell@ele xon.co.uk
Slide 83
83 Issue: Concern that BSCCo Board can carry decisions against
will of non-executive Industry Directors ELEXON resource, budgets
& expenditure may not be supported by BSC Parties Proposed
Solution: 4 industry constituencies each elect an independent
industry Board Member Alternate Solution: Nomination Committee
identifies appointees for 4 independent Board Member positions
Terms of Reference subject to Panel oversight and appointments
subject to Panel ratification BSC Modifications P281 (1 of 2) P281
Change of BSCCo Board of Directors & Chairman Phase Awaiting
Implementation Contact Dean Riddell 020 7380 4366 dean.riddell@ele
xon.co.uk Who will be impacted by P281? BSC Parties
Slide 84
84 Workgroup and Panel recommended Approve Alternate Both
solutions better facilitate ABO (d) Alternate better facilitates
compared with Proposed Recommended implementation 10WD after
Authority decision (Code changes) Appointment of new Directors over
longer timescales Alternate Solution approved for implementation on
1 October 2012 BSC Modifications P281 (2 of 2) P281 Change of BSCCo
Board of Directors & Chairman Phase Awaiting Implementation
Contact Dean Riddell 020 7380 4366 dean.riddell@ele xon.co.uk
Slide 85
85 Issue: MVRNs can only reallocate energy from P BM Unit to P
Energy Account or C BM Unit to C Energy Account Proposed Solution:
Allow MVRNs to transfer energy from P BM Unit to C Energy Account
or vice versa Would also allow MVRN from P BM Unit to Lead Partys C
Energy Account or vice versa BSC Modifications P282 (1 of 2) P282
Allow MVRNs from Production to Consumption or Vice Versa Phase
Assessment Procedure Contact David Kemp 020 7380 4303
david.kemp@ele xon.co.uk Who will be impacted by P282? MVRNAs BSC
Trading Parties
Slide 86
86 Currently undergoing assessment by a Workgroup Assessment
Report to Panel in October Report Phase Consultation will be issued
in October BSC Modifications P282 (2 of 2) P282 Allow MVRNs from
Production to Consumption or Vice Versa Phase Assessment Procedure
Contact David Kemp 020 7380 4303 david.kemp@ele xon.co.uk
Slide 87
87 Issue: Concern that it is difficult to perform full
commissioning of Metering Equipment Some equipment is not within
control of Registrant or MOA when commissioning required Proposed
Solution: Relevant System Operator responsible for commissioning
CTs/VTs & providing certificates/records MOAs would assess
performance; notify Registrant of potential uncontrolled risks
Registrant works with SO to minimise risks BSC Modifications P283
(1 of 2) P283 Reinforcing the Commissioning of Metering Equipment
Process Phase Assessment Procedure Contact Claire Anthony 020 7380
4293 claire.anthony@e lexon.co.uk Who will be impacted by P283?
Metering System Registrants LDSOs MOAs
Slide 88
88 Currently undergoing assessment by a Workgroup Assessment
Report to Panel in November Changes to CoP4 and other relevant
documents will be drafted alongside Code changes Assessment
Procedure Consultation will be issued by October Report Phase
Consultation will be issued in November BSC Modifications P283 (2
of 2) P283 Reinforcing the Commissioning of Metering Equipment
Process Phase Assessment Procedure Contact Claire Anthony 020 7380
4293 claire.anthony@e lexon.co.uk
Slide 89
89 Issue: Currently ELEXON, as BSCCo, cannot undertake non-BSC
activity Proposed Solution: Enable, but not require, BSCCo to
outsource some or all BSC services to a BSC Services Manager
Alternate Solution: As Proposed, but with additional requirements
BSC Modifications P284 (1 of 2) P284 Expansion of Elexons role via
the contract model Phase Implemented Contact Dean Riddell 020 7380
4366 dean.riddell@ele xon.co.uk Who will be impacted by P284?
Indirect: BSC Parties
Slide 90
90 Workgroup and Panel recommended Reject Neither solution
better facilitate ABO (d) Alternate better facilitates compared
with Proposed Recommended implementation 1WD after Authority
decision Ofgem approved the Alternate Solution, which was
implemented on 18 September 2012 BSC Modifications P284 (2 of 2)
P284 Expansion of Elexons role via the contract model Phase
Implemented Contact Dean Riddell 020 7380 4366 dean.riddell@ele
xon.co.uk
Slide 91
91 Issue: CMP202 has removed BSUoS from Interconnector BM Units
CMP202 was implemented on 30 August 2012 Creates potentially
anomalous situation where Parties liable for RCRC but not liable
for BSUoS Proposed Solution: Exclude Interconnector BM Units from
RCRC BSC Modifications P285 (1 of 2) P285 Revised treatment of RCRC
for Interconnector BM Units Phase Assessment Procedure Contact
David Kemp 020 7380 4303 david.kemp@ele xon.co.uk Who will be
impacted by P285? I/C Users IEAs Indirect: Other BSC Trading
Parties
Slide 92
92 Currently undergoing assessment by a Workgroup Assessment
Report to Panel in October Report Phase Consultation will be issued
in October Being progressed in parallel with P286 BSC Modifications
P285 (2 of 2) P285 Revised treatment of RCRC for Interconnector BM
Units Phase Assessment Procedure Contact David Kemp 020 7380 4303
david.kemp@ele xon.co.uk
Slide 93
93 Issue: CMP201 proposes to remove BSUoS from generation BM
Units If approved, creates potentially anomalous situation where
Parties liable for RCRC but not liable for BSUoS Proposed Solution:
Exclude generation BM Units from RCRC Generation BM Unit: BM Unit
in a delivering Trading Unit BSC Modifications P286 (1 of 2) P286
Revised treatment of RCRC for generation BM Units Phase Assessment
Procedure Contact David Kemp 020 7380 4303 david.kemp@ele xon.co.uk
Who will be impacted by P286? Generators Indirect: Other BSC
Trading Parties
Slide 94
94 Currently undergoing assessment by a Workgroup Assessment
Report to Panel in October Report Phase Consultation will be issued
in October Being progressed in parallel with P285 BSC Modifications
P286 (2 of 2) P286 Revised treatment of RCRC for generation BM
Units Phase Assessment Procedure Contact David Kemp 020 7380 4303
david.kemp@ele xon.co.uk
Slide 95
95 Issue: Panel cannot make decisions on Modifications via
teleconference Proposed Solution: Allow Panel to make decisions on
Modifications by teleconference At least one Panel Member must be
present at meeting venue Self-Governance Modification Rejected by
Panel Does not better facilitate ABO (d) BSC Modifications P287 (1
of 1) P287 Allow the BSC Panel to conduct Modification Business via
teleconference Phase Rejected Contact Talia Addy 020 7380 4043
talia.addy@elexo n.co.uk Who will be impacted by P287? No impact on
BSC Parties
Slide 96
96 Upcoming Consultations: P283 Assessment Procedure
Consultation by October P272 Report Phase Consultation November
P274 Report Phase Consultation October P282 Report Phase
Consultation October P283 Report Phase Consultation November P285
Report Phase Consultation October P286 Report Phase Consultation
October BSC Modification Consultations These will be your last
chance to comment on these Mods!
Slide 97
97 www.elexon.co.uk/change/modifications/ Where can I find more
info on BSC Mods?