Cross Codes Forum 21 September 2012 ELEXON, National Grid & Electralink.

Cross Codes Forum 21 September 2012 ELEXON, National Grid & Electralink

Introduction and Housekeeping Emma Piercy

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

4 ELEXON Evacuation Muster Point If there is an alarm, follow the instructions of the Fire Wardens The evacuation point is here

Energy Supply Company Administration Dawn Armstrong System Balancing and Retail Markets 5

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

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

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 :

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

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?

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

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

European Network Codes Information for the Cross-Codes Forum Paul Wakeley Electricity Codes Regulatory Frameworks National Grid 21 September 2012

14 Agenda The Third Package European Network Codes Process Status Further Information and Getting Involved

The Third Package

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)

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

Electricity European Network Codes

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

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

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

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

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

Implementation of European Network Codes within GB

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

26 From Presentations from 4th Elec SG - DECC/Ofgem Stakeholder Group How will Code Change be implemented?

Getting Involved / Further Information

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

29 Any Questions? [email protected] 01926 655582

Further Information on Network Codes

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

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

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

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

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

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

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.

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.

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.

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.

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.

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/

43 Contact Information Email: [email protected] [email protected] (CUSC)[email protected] [email protected] (Grid Code)[email protected] Website: http://www.nationalgrid.com/uk/Electricity/Codes/systemcode/ http://www.nationalgrid.com/uk/Electricity/Codes/gridcode/ Phone: Emma Clark - 01926 655223

Electricity Balancing SCR Cross Codes Forum, 21 September 2012 Andreas Flamm

45 Contents Background History SCR Process Indicative timetable Objectives of SCR Main interactions Primary considerations Secondary considerations Next steps Electricity Balancing SCR

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

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

48 Indicative electricity balancing SCR timetable Background Usual BSC mod process

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

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

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

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

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

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

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

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

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

DCUSA Change Proposals Update Michael Walls Governance Services Senior Analyst ElectraLink Ltd. Email: [email protected]@electralink.co.uk 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 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

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 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.

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.

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]@electralink.co.uk 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]@electralink.co.uk Tel: 020 7432 3014

Update on BSC Modifications David Kemp 21 September 2012

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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!

97 www.elexon.co.uk/change/modifications/ Where can I find more info on BSC Mods?

98 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]

Cross Codes Forum 21 September 2012 ELEXON, National Grid & Electralink.

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Transcript of Cross Codes Forum 21 September 2012 ELEXON, National Grid & Electralink.