Transcript www.elexon.co.uk

Cross Codes
Forum
ELEXON, National Grid & Electralink
21 September 2012
Introduction and
Housekeeping
Emma Piercy
Welcome to ELEXON
What we’ll cover today:
• 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
3
ELEXON
Evacuation Muster Point
» If there is an alarm, follow the instructions
of the Fire Wardens
» The evacuation point is here…
4
Energy Supply Company
Administration
Dawn Armstrong
System Balancing and Retail Markets
5
Context
• SoLR arrangements tested several times
• Unlikely to work in the event of a major supplier’s 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
6
Legal Framework
• 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
7
Cost recovery mechanism
• 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.
9
How would it work?
• 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.
10
Proposed licence changes
• 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.
11
Timing
• 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
12
European Network Codes
Information for the Cross-Codes Forum
Paul Wakeley
Electricity Codes • Regulatory Frameworks • National Grid
21 September 2012
Agenda
 The Third Package
 European Network Codes
 Process
 Status
 Further Information and Getting Involved
14
The Third Package
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)
16
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
17
Electricity European Network Codes
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
19
European Network Code
Development Process
Commission
starts
development
process
 The process for developing the European
Network Codes is defined in EU law
1 year?
ACER
develops
FWGL
Commission
invites
ENTSO-E
to develop
Network
Code
ENTSO-E
develops
Network
Code
ACER
reviews
Network
Code
Comitology
Commission
Stakeholder Engagement
6 months
To fit work
programme
1 year
3 months
By 2014
Network Code
becomes Law
20
The ‘live’ Network Codes
ACER Framework Guideline ENTSO-E Network Code
Grid Connections
Requirements for Generators (RFG)
Demand Connection Code (DCC)
HVDC
Capacity Allocation and
CACM (Day ahead and intraday)
Congestion Management
Forwards Markets
Balancing
Balancing Network Code
System Operation
Operational Security
Operational Planning and Scheduling
Load-Frequency Control and
Reserves
21
EC invites
ENTSO-E
to develop
Network
Code
1 year
3 months
ENTSO-E
develops
Network
Code
ACER
reviews
Network
Code
1 year ?
2014
Comitology
Network
Code
becomes
Law
Grid Connection FWGL
RFG
Forwards
Balancing
ACER
develops
FWGL
To fit work
programme
HVDC
6 months
CACM FWGL
System Operation FWGL
Balancing FWGL
CACM
Public
Consultation
DCC
Op Sec
Op Sch & Plan
LF&R
Drafting and
Stakeholder Workshops
Revise Code
Assembly
22
Approval
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
23
Implementation of European Network Codes
within GB
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
25
How will Code Change be implemented?
26
From ‘Presentations from 4th Elec SG’ - DECC/Ofgem Stakeholder Group
Getting Involved / Further Information
How to get involved
 ENTSO-E workshops and consultations
 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/
 DECC / Ofgem Stakeholder Group
 http://www.ofgem.gov.uk/Europe/stakeholdergroup/Pages/index.aspx
28
Any Questions?
 [email protected]
 01926 655582
29
CUSC and Grid Code Changes
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.
Emma Clark
Electricity Codes • Regulatory Frameworks • National Grid
21 September 2012
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 Commission’s 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.
37
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.
38
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.
39
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.
40
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.
41
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/
42
Contact Information
 Email:
• [email protected]
• [email protected] (CUSC)
• [email protected] (Grid Code)
 Website:
• http://www.nationalgrid.com/uk/Electricity/Codes/systemcode/
• http://www.nationalgrid.com/uk/Electricity/Codes/gridcode/
 Phone:
 Emma Clark - 01926 655223
43
Electricity Balancing SCR
Cross Codes Forum, 21 September 2012
Andreas Flamm
Electricity Balancing SCR
Contents
• Background
– History
– SCR Process
– Indicative timetable
– Objectives of SCR
– Main interactions
• Primary considerations
• Secondary considerations
• Next steps
45
Background
History
•
Long-standing concerns with electricity balancing arrangements (eg cashout 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.
46
Background
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
47
Background
Indicative electricity balancing SCR timetable
Usual
BSC mod
process
48
Background
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 SO’s cost for balancing in cash-out prices
•
Ensure our balancing arrangements are compliant with the European Target Model
and complement the EMR Capacity Mechanism
49
Background
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
50
Primary
Considerations
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
51
Primary
Considerations
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.
52
Primary
Considerations
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?
53
Primary
Considerations
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.
54
Primary
Considerations
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.
55
Secondary
Considerations
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
56
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
57
58
DCUSA Change Proposals
Update
Michael Walls
Governance Services Senior Analyst – ElectraLink Ltd.
Email: [email protected]
Tel: 020 7432 3014
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.
DCUSA Change Process - Overview
Parties
Pre-Change Process
(Charging methodology
changes)
Panel
Secretariat
Ofgem
CP raised
Initial
Assessment
Modelling
Resource
Working Group
Assessment
Industry
Consultation
Change Report
Party Voting
Change
Declaration
Implementation
Authority
Consent
Live DCUSA Change Proposals
DCP No
DCP 054
•
Change Proposal Title
Revenue Protection / Unrecorded Units into settlements
.
DCP 102
Credit Cover calculation of 15 day value
DCP 114
NTC Amendments - Capacity Management (Over Utilisation)
DCP 115
NTC Amendments - Capacity Management (Under Utilisation)
DCP 117
Treatment of ‘Load related new connections & reinforcement (net of contributions)’ in the Price Control
DCP 118
Allocation of EHV Costs in the CDCM Price Disaggregation Model
DCP 120
Boundary Registrant Access Provisions
DCP 123
Revenue Matching Methodology Change
DCP 124
Third Party Network – National Connection Terms amendment
DCP 126
Require DNOs to publish and update year-ahead forecasts of DUoS tariffs
DCP 127
Gas First Smart Meter Installation
DCP 128
Bringing the EDCM Price Control Disaggregation (Extended Method M) under the DCUSA Open Governance
Framework
DCP 129
Bringing the CDCM Price Control Disaggregation (Method M) under the DCUSA Open Governance Framework
Live DCUSA Change Proposals
DCP No
Change Proposal Title
•
.
DCP
130
Remove the discrepancy between non-half hourly (NHH) and half hourly (HH) un-metered supplies (UMS) tariffs
DCP 133
500 MW network common model for CDCM input
DCP 135
Clarification of CDCM Charges
DCP 136
Notice period for Asset Cost Changes in the CDCM
DCP 137
Introduction of locational tariffs for the export from HV generators in areas identified as generation dominated.
DCP 138
Implementation of alternative network use factor (NUF) calculation method in EDCM
DCP 139
Non-Application of FCP charge for Category 0000 Customers
DCP 141
Invalid settlement classes
DCP 142
Using D2021 for all invoices/credit notes if it is used at all
DCP 143
Estimating missing reactive data
DCP 144
Prohibiting rounding of HH data
Live DCUSA Change Proposals
.
DCP 144
Prohibiting rounding of HH data
DCP 145
Mandating compliance with D2021 processes
DCP 146
HH invoice runs
DCP 147
Preventing UoS invoices containing non-UoS elements
DCP 149
Prohibiting HH invoices containing data from 2 different clock time calendar months
DCP 148
Rebilling to be done via credit/rebill
DCP 150
Implementation of Notice
DCP 151
HH Aggregated Tariffs
DCP 152
Implementation of the combined EDCM for import and export charges
DCP 153
Service Level Agreement for Resolving Network Operational Issues
DCP No
STATUS - CHANGE REPORT
DCP 131
Improving the predictability and transparency of CDCM inputs
DCP 132
Improving the transparency of CDCM target revenue
DCP 140
Inclusion of the Common Connection Charging Methodology into the DCUSA
DCP 134
Implementation of notice in DCUSA for changes to distribution timebands
DCP No
DCP 103
Withdrawn
DUoS Charges for sub 100kw HH settled sites
Live DCUSA Change Proposals
•
•
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 customer’s 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.
Live DCUSA Change Proposals
• DCP 124 – Third Party Network - National Connection Terms
Amendments
–
DCP 124 introduces the concepts of Licence Exempt Distribution Network Operator’s
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.
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.
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.
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
Supply Point Administration
Agreement (SPAA) Update
Michael Walls
Governance Services Senior Analyst – ElectraLink Ltd.
Email: [email protected]
Tel: 020 7432 3014
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
Questions or Comments
Michael Walls
Governance Services Senior Analyst – ElectraLink Ltd.
Email: [email protected]
Tel: 020 7432 3014
Update on BSC
Modifications
David Kemp
21 September 2012
Active BSC Modifications
Mod
Title
P272 Mandatory Half Hourly Settlement for Profile Classes 5-8
Assessment Procedure
P274 Cessation of Compensatory Adjustments
Assessment Procedure
Introduce an additional trigger/threshold for suspending the market in the event of
P276 a Partial Shutdown
Awaiting Implementation
P278 Treatment of Transmission Losses for Interconnector Users
Awaiting Implementation
P280 Introduction of new Measurement Classes
P281 Change of BSCCo Board of Directors & Chairman
With Authority
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 Elexon’s 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
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Phase
Rejected
BSC Modifications – P272 (1 of 2)
P272
Who will be impacted by P272?
•
Suppliers
•
DCs
•
MOAs
•
LDSOs
• 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
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Mandatory Half
Hourly
Settlement for
Profile Classes 58
Phase
Assessment
Procedure
Contact
David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
BSC Modifications – P272 (2 of 2)
P272
• Currently undergoing assessment by a Workgroup
• Workgroup currently carrying out cost-benefit analysis
• Assessment Report to Panel in November
• Workgroup’s Assessment Report was presented to
Panel in January
• Majority view to Reject both Proposed and Alternate
• Majority view that Alternate better than Proposed
• Ofgem’s view: Await outcome of P280, DCP 103 &
MIG 22 before making decision
• Report Phase Consultation will be issued in November
76
Mandatory Half
Hourly
Settlement for
Profile Classes 58
Phase
Assessment
Procedure
Contact
David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
BSC Modifications – P274 (1 of 2)
P274
Who will be impacted by P274?
•
Suppliers
•
LDSOs
•
NHHDCs
• Issue:
Cessation of
Compensatory
Adjustments
• 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
77
Phase
Assessment
Procedure
Contact
Talia Addy
020 7380 4043
talia.addy@elexo
n.co.uk
BSC Modifications – P274 (2 of 2)
P274
• Currently undergoing assessment by a Workgroup
• Assessment Report to Panel in October
Cessation of
Compensatory
Adjustments
• 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
78
Phase
Assessment
Procedure
Contact
Talia Addy
020 7380 4043
talia.addy@elexo
n.co.uk
BSC Modifications – P276 (1 of 1)
Who will be impacted by P276?
•
BSC Trading Parties
• 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)
79
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
BSC Modifications – P278 (1 of 1)
P278
Who will be impacted by P278?
•
I/C Users
•
IEAs
•
Indirect: Other BSC Trading Parties
• Issue:
• European regulations compensate GB for transmission
losses caused by Interconnectors
• Approved Solution:
• Set TLM to 1 for Interconnector BM Units
Treatment of
Transmission
Losses for
Interconnector
Users
Phase
Awaiting
Implementation
Contact
• Approved for implementation on 29 November 2012
(November 2012 Release)
• Better facilitates ABOs (a), (c) and (e)
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David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
BSC Modifications – P280 (1 of 2)
P280
Who will be impacted by P280?
•
Suppliers
•
LDSOs
•
HHDAs
•
HHDCs
• 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
Introduction of
new
Measurement
Classes
Phase
With Authority
• 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
81
Contact
Dean Riddell
020 7380 4366
dean.riddell@ele
xon.co.uk
BSC Modifications – P280 (2 of 2)
P280
• Workgroup and Panel recommend Approve
• Better facilitates ABOs (c) and (d)
Introduction of
new
Measurement
Classes
• Recommend implementation on 1 October 2013
Phase
• Currently with Ofgem for decision
With Authority
Contact
Dean Riddell
020 7380 4366
dean.riddell@ele
xon.co.uk
82
BSC Modifications – P281 (1 of 2)
Who will be impacted by P281?
•
BSC Parties
• 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:
83
• Nomination Committee identifies appointees for 4
independent Board Member positions
• Terms of Reference subject to Panel oversight and
appointments subject to Panel ratification
P281
Change of BSCCo
Board of
Directors &
Chairman
Phase
Awaiting
Implementation
Contact
Dean Riddell
020 7380 4366
dean.riddell@ele
xon.co.uk
BSC Modifications – P281 (2 of 2)
P281
• Workgroup and Panel recommended Approve
Alternate
Change of BSCCo
Board of
Directors &
Chairman
• Both solutions better facilitate ABO (d)
• Alternate better facilitates compared with Proposed
Phase
• Recommended implementation 10WD after Authority
decision (Code changes)
• Appointment of new Directors over longer timescales
• Alternate Solution approved for implementation on 1
October 2012
84
Awaiting
Implementation
Contact
Dean Riddell
020 7380 4366
dean.riddell@ele
xon.co.uk
BSC Modifications – P282 (1 of 2)
Who will be impacted by P282?
•
MVRNAs
•
BSC Trading Parties
• 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 Party’s C
Energy Account or vice versa
85
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
BSC Modifications – P282 (2 of 2)
P282
• Currently undergoing assessment by a Workgroup
• Assessment Report to Panel in October
Allow MVRNs
from Production
to Consumption
or Vice Versa
• Report Phase Consultation will be issued in October
Phase
Assessment
Procedure
Contact
David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
86
BSC Modifications – P283 (1 of 2)
P283
Who will be impacted by P283?
•
Metering System Registrants
•
LDSOs
•
MOAs
• 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
87
Reinforcing the
Commissioning
of Metering
Equipment
Process
Phase
Assessment
Procedure
Contact
Claire Anthony
020 7380 4293
claire.anthony@e
lexon.co.uk
BSC Modifications – P283 (2 of 2)
P283
• 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
88
Reinforcing the
Commissioning
of Metering
Equipment
Process
Phase
Assessment
Procedure
Contact
Claire Anthony
020 7380 4293
claire.anthony@e
lexon.co.uk
BSC Modifications – P284 (1 of 2)
Who will be impacted by P284?
•
Indirect: BSC Parties
• 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
89
P284
Expansion of
Elexon’s role via
the ‘contract
model’
Phase
Implemented
Contact
Dean Riddell
020 7380 4366
dean.riddell@ele
xon.co.uk
BSC Modifications – P284 (2 of 2)
P284
• 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
90
Expansion of
Elexon’s role via
the ‘contract
model’
Phase
Implemented
Contact
Dean Riddell
020 7380 4366
dean.riddell@ele
xon.co.uk
BSC Modifications – P285 (1 of 2)
P285
Who will be impacted by P285?
•
I/C Users
•
IEAs
•
Indirect: Other BSC Trading Parties
• 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
91
Revised
treatment of
RCRC for
Interconnector
BM Units
Phase
Assessment
Procedure
Contact
David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
BSC Modifications – P285 (2 of 2)
P285
• Currently undergoing assessment by a Workgroup
• Assessment Report to Panel in October
Revised
treatment of
RCRC for
Interconnector
BM Units
• Report Phase Consultation will be issued in October
Phase
• Being progressed in parallel with P286
Assessment
Procedure
Contact
David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
92
BSC Modifications – P286 (1 of 2)
Who will be impacted by P286?
•
Generators
•
Indirect: Other BSC Trading Parties
• 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
93
P286
Revised
treatment of
RCRC for
generation BM
Units
Phase
Assessment
Procedure
Contact
David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
BSC Modifications – P286 (2 of 2)
P286
• Currently undergoing assessment by a Workgroup
• Assessment Report to Panel in October
Revised
treatment of
RCRC for
generation BM
Units
• Report Phase Consultation will be issued in October
Phase
• Being progressed in parallel with P285
Assessment
Procedure
Contact
David Kemp
020 7380 4303
david.kemp@ele
xon.co.uk
94
BSC Modifications – P287 (1 of 1)
Who will be impacted by P287?
•
No impact on BSC Parties
• 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)
95
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
BSC Modification Consultations
• Upcoming Consultations:
• P283 Assessment Procedure Consultation – by October
•
•
•
•
•
•
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P272
P274
P282
P283
P285
P286
Report
Report
Report
Report
Report
Report
Phase Consultation
Phase Consultation
Phase Consultation
Phase Consultation
Phase Consultation
Phase Consultation
– November
– October
– October
– November
– October
– October
These will be your last
chance to comment on
these Mods!
Where can I find more info on BSC Mods?
www.elexon.co.uk/change/modifications/
97
Any Comments or Queries?
Claire Anthony
020 7380 4293
[email protected]
David Kemp
020 7380 4303
[email protected]
Dean Riddell
020 7380 4366
[email protected]
Talia Addy
020 7380 4043
[email protected]
98