Evacuation Muster Point

Cross-Codes Forum 18 October 2013

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

Update on BSC Modifications
David Kemp 18 October 2013

Active BSC Modifications
Title Phase P272 Mandatory Half Hourly Settlement for Profile Classes 5-8 With Authority P276 Introduce an additional trigger/threshold for suspending the market in the event of a Partial Shutdown Awaiting Implementation P283 Reinforcing the Commissioning of Metering Equipment Processes P286 Revised treatment of RCRC for generation BM Units P291 REMIT Inside Information Reporting Platform for GB Electricity P292 Amending Supplier & Meter Operator Agent responsibilities for smart Meter Technical Details P294 Addition of Offshore Transmission System and OTSUA to the definition of the Total System Report Phase P295 Submission and publication of Transparency regulation data via the BMRS Assessment Procedure P296 Introduction of a ‘Fast Track’ Modification Process following the outcomes of the Code Governance Review (Phase 2) P297 Receipt and Publication of New and Revised Dynamic Data Items

BSC Modifications – P272 (1 of 2)
Who will be impacted by P272? Suppliers DCs MOAs Distributors P272 Mandatory Half Hourly Settlement for Profile Classes 5-8 Phase With Authority Contact David Kemp 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 Alternative Solution: As Proposed, but from April 2015

Mandatory Half Hourly Settlement for Profile Classes 5-8 Phase With Authority Contact David Kemp Panel’s Recommendation: Reject both Proposed and Alternative Recommend implementation on 1 April 2014 (Pro) or 1 April 2015 (Alt) Currently with Authority for decision

Who will be impacted by P276? BSC Trading Parties P276 Introduce an additional trigger/threshold for suspending the market in the event of a Partial Shutdown Phase Awaiting Implementation Contact ELEXON Change 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 Authority: Better facilitates ABOs (b), (c) and (d)

Who will be impacted by P283? Metering System Registrants Distributors MOAs P283 Reinforcing the Commissioning of Metering Equipment Process Phase Awaiting Implementation Contact Claire Anthony Issue: Hard to perform full commissioning of Metering Equipment Some equipment not within control of Registrant or MOA when commissioning required Approved Solution: Relevant SO 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 Approved for implementation on 6 November 2014 Authority: Better facilitates ABOs (b), (c) and (d)

Who will be impacted by P286? Generators Indirect: Other BSC Trading Parties P286 Revised treatment of RCRC for generation BM Units Phase With Authority Contact David Kemp 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

Revised treatment of RCRC for generation BM Units Phase With Authority Contact David Kemp Panel’s Recommendation: Approve Recommend implementation on 1 April 2015 Currently with Authority for decision

Who will be impacted by P291? Transmission Company BSC Parties P291 REMIT Inside Information Reporting Platform for GB Electricity Phase Awaiting Implementation Contact David Kemp Issue: REMIT requires public reporting of inside information Preference for use of central reporting platforms Approved Solution: Place an inside information reporting platform on BMRS Messages submitted via Grid Code or ELEXON Portal Approved for implementation on 31 December 2014 Authority: Better facilitates ABOs (b), (c) and (d)

Who will be impacted by P292? Suppliers NHHMOAs LDSOs NHHDCs P292 Amending Supplier & Meter Operator Agent responsibilities for smart Meter Technical Details Phase Awaiting Implementation Contact Simon Fox Issue: New operating model – only Suppliers will be able to configure Smart Meters under the DCC This has a direct impact on responsibilities for sending MTDs Approved Solution: Provide ‘hook’ in Code to enable implementation of detailed requirements (CP1388/CP1395) Approved for implementation on 26 June 2014 Authority: Better facilitates ABO (d)

Who will be impacted by P294? Offshore Generators Transmission Company P294 Addition of Offshore Transmission System and OTSUA to the definition of the Total System Phase Report Phase Contact David Barber Issue: Offshore generator required to install metering at Boundary Point during development This metering becomes defunct when Offshore Transmission Assets are transferred to the OFTO Proposed Solution: Amend definition of ‘Total System’ Include ‘Offshore Transmission System’ and ‘OTSUA’ Address confusion between BSC and Grid Code Remove requirement to install metering at Boundary Point

Addition of Offshore Transmission System and OTSUA to the definition of the Total System Phase Report Phase Contact David Barber Panel’s initial Recommendation: Approve Final Recommendation at November meeting Recommend implementation 5WD after Approval

Who will be impacted by P295? Transmission Company Potential: Interconnector Administrators P295 Submission and publication of Transparency regulation data via the BMRS Phase Assessment Procedure Contact Talia Addy Issue: Transparency regulation requires data to be published on EMFIP TSOs provide this information to ENTSO-E Proposed Solution: BMRA act as data provider for National Grid’s data Data also published on BMRS Potential Alternative Solution: As Proposed, but with Interconnector data also published on BMRS Int. Administrators to submit info to BMRA in parallel with submitting to ENTSO-E

Submission and publication of Transparency regulation data via the BMRS Phase Assessment Procedure Contact Talia Addy Undergoing assessment by Workgroup Assessment Report to Panel in November Proposing implementation on 31 December 2014 Report Phase Consultation will be issued in November

Who will be impacted by P296? BSC Panel P296 Introduction of a ‘Fast Track’ Modification Process following the outcomes of the Code Governance Review (Phase 2) Phase Awaiting Implementation Contact Claire Anthony Issue: CGR2 introduces new ‘Fast Track’ Modifications Required to be introduced into BSC Approved Solution: Introduce new ‘Fast Track’ process into BSC Used to progress minor housekeeping changes quickly Approved for implementation on 6 November 2013 Authority: Better facilitates ABOs (a) and (d)

Who will be impacted by P297? Transmission Company P297 Receipt and Publication of New and Revised Dynamic Data Items Phase Assessment Procedure Contact Claire Anthony Issue: Grid Code EBS Group has made changes to the Dynamic Data Set Proposed Solution: Amend BSC to ensure data on BMRS corresponds with data submitted to Transmission Company by Parties

Receipt and Publication of New and Revised Dynamic Data Items Phase Assessment Procedure Contact Claire Anthony Undergoing assessment by Workgroup Assessment Report to Panel in November Proposing implementation on 6 November 2014 Currently out for Assessment Consultation Responses due by 24 October Report Phase Consultation will be issued in November

Consultations Current Consultations: Upcoming Consultations:
P297 Assessment Consultation – responses due by 24 October Upcoming Consultations: P295 Report Phase Consultation – November P297 Report Phase Consultation – November This will be your final chance to comment on these Modifications

Where can I find more information?

elexon.change@elexon.co.uk Any Questions? Adam Lattimore
Claire Anthony David Barber David Kemp Simon Fox Talia Addy

Adam Hipgrave Cross Codes Forum 18 October 2013
CUSC Changes Adam Hipgrave Cross Codes Forum 18 October 2013

CUSC Modifications Process
Change raised Urgent process Panel decision on progression Appeal to Competition Commission Workgroup assessment Industry consultation Panel Vote A CUSC change can be made by any CUSC or BSC Party, or National Consumer Council (Consumer Futures). 2 different types of proposals – standard and charging (different set of objectives). There are a number of different processes for the different types of changes proposed. The Panel and the Authority decide on the most appropriate course of action for each proposal. Can take various routes – WG, straight to consultation, Self Governance. WG assessment 4 months Consultation periods minimum 3 weeks. Ofgem have a 25 day kpi to make decision. May carry out IA (201, 213). Appeal allowed if Authority decision different to Panel decision. Ofgem decision to approve or reject Final report to Ofgem optional

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 voted on 26 April 2013 and Final Report sent to Ofgem on 9 May 2013. Ofgem will be publishing their Impact Assessment shortly Raised in December 2011 by NG. Has gone through a Send back by Ofgem. Panel voted that the Original and both the Alternatives better meet the Objectives, with a preference for the Original. (Original 2 years implementation, WACM 1 = 3 years, WACM 2 = 5 years.

CUSC Modifications (2) 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. Complex and extensive Workgroup process. 26 Workgroup Alternative CUSC Modifications (WACM) Panel voted in May that 8 of the 26 WACMs better facilitated the Objectives. Final Report sent to Ofgem on 14 June 2014. Impact Assessment closed on the 10th October 2013, awaiting Ofgem decision. Implementation – majority of Panel felt that April 2015 is appropriate to allow the market time to adjust to the changes.

CUSC Modifications (3) CMP218 – Changes required for use of new banking product to hold Users’ cash securities Seeks to facilitate the use of a new banking product by NGET. Raised in March 2013 and is being progressed as Self-governance. Code Administrator Consultation closed on 4 July 2013. The Panel voted unanimously that CMP220 better facilitates the Applicable CUSC Objectives. Implemented on 16th October 2013. National Grid Electricity Transmission plc would like to improve the processes for holding cash security provided by Users by utilising a new banking product. Instead of NGET having separate bank accounts designated to each User, NGET would use bank accounts in the name of NGET plc (“The Company”), one for the deposit of the security and the second associated account for interest purposes. Each user’s security and allocated interest would be attributed to a "virtual client account" which would have an individual reference number and name.

CUSC Modifications (4) CMP219 – CMP192 Post Implementation Clarifications Seeks to address issues with the legal text for CMP192 (Arrangements for Enduring Generation User Commitment) identified following its implementation. Raised in June 2013. Code Administrator Consultation was published on the 2 October 2013 and closes on 30th October2013. Being progressed as self-governance; Panel Determination Vote to be carried out in November.

CUSC Modifications (5) CMP221 – Interruption Compensation in the absence of Market Suspension during Partial Shutdown Seeks to extend the existing CUSC compensation to cover Settlement Periods during a Partial Shutdown where market operations continue. Raised in September 2013. Code Administrator Consultation was published on the 1st October and closes on 29th October. Background from FMR not sure how much you need, speak to Sally Lewis for further information. Balancing and Settlement Code (BSC) Modification P276 (to be implemented on 31st March 2014) introduces the concept of a Partial Shutdown under which normal electricity market operations continue to function. Prior to P276, a declaration (by National Grid) of a Partial Shutdown would initiate suspension of the Balancing Mechanism (BM) (and all contractual and credit positions), establishing a single imbalance price and the central dispatch of generation. Under P276, normal market operations will only be suspended (a Market Suspension Period)following a Partial Shutdown, if a specified Market Suspension Threshold is met or deemed to have been met. The threshold will be met or deemed to have been met if at any point during the Partial Shutdown: National Grid determines that the cumulative impact of the Partial Shutdown is equal to or greater than the amount stated in the BSC (currently 5% of National Demand lost from the Transmission System); National Grid no longer has sufficient pre-shutdown forecast data to accurately determine the amount of demand lost; or 72 hours have elapsed since the Partial Shutdown was declared. During a Partial Shutdown, parties which are dispatched through black start instructions issued by National Grid are eligible to claim black start compensation under the BSC. However, generators who lose access to the Transmission System through power loss will not be eligible for any compensation and if the market continues will be unable to take actions to correct their positions and will be subsequently exposed to imbalance against their contract volumes. Existing arrangements for loss of transmission access as a result of a system event are dealt with under CUSC Interruption Payments, from which interruptions due to Total or Partial Shutdown are currently excluded. The majority of the P276 workgroup members recommended that the existing CUSC compensation provision should be extended to cover Settlement Periods during a Partial Shutdown where market operations continue.

CUSC Modifications (6) CMP222 – User Commitment for Non-Generation Users Generation user commitment for pre- and post-commissioning sites was introduced into the CUSC in April 2012 for April 2013 go-live. Seeks to introduce enduring user commitment arrangements for interconnector and demand users by April 2015. Raised September 2013. First Workgroup meeting to be held on the 18th October. This proposal is intended to introduce enduring user commitment arrangements for sites where there is an offtake of electricity from the transmission system (excluding generation site supplies), specifically interconnectors, distribution network Grid Supply Points (GSPs) and directly connected loads. These arrangements should not seek to indemnify sunk costs, but to provide an incentive on users to signal their intentions early and hence allow Transmission Owners (TOs) to avoid inefficient investment. It is also intended that they be proportionate to the number and materiality of the users involved.

CUSC Modifications (7) CMP223 – Arrangements for Relevant Distributed Generators under the Enduring Generation User Commitment. Seeks to address issues associated with the way liability and security terms and conditions are set and calculated for distribution connected generators Raised September 2013. First Workgroup meeting to be held on the 18th October.

CUSC Modifications (8) CMP224 – Cap on the Total TNUoS Target Revenue to be recovered from Generation Users Seeks to ensure that the average annual generation transmission charges remain within the current prescribed European Commission range until December 2014, and within the revised range (if modified after ACER’s review) that may come into force from 1st January 2015. Raised September 2013. First Workgroup meeting to be held on the 24th October.

Contact Information Website:

Any questions? Adam Hipgrave National Grid
Commercial Analyst - European Code Development Transmission Network Services | Markets & Balancing Development National Grid House, Warwick Technology Park, Warwick, CV34 6DA T: M: E:

Adam Hipgrave Cross Codes Forum 18 October 2013
Grid Code Changes Adam Hipgrave Cross Codes Forum 18 October 2013

GC0042 Information on Embedded Small Power Stations and Impact on Demand
The Workgroup determined that further information than what is currently provided under PC.A is required to enable National Grid to efficiently plan and securely operate the transmission system. A list of additional requirements was agreed upon for each Embedded Small Power Stations (ESPS) of 1 MW and above The Distribution code will be be reviewed to enable the DNOs to capture any additional information that they are currently not entitled to receive Implementation date for the above information to be submitted was agreed to be the Calendar Week 24 data submission beginning 2015. Workgroup Report was presented at the September GCRP. Industry Consultation anticipated early 2014 (in line with the DCode). The increasing amount of embedded generation connected to the distribution networks (DNOs) is having a large impact on the transmission network. To maintain the security of the system, National Grid requires more visibility of Embedded Small Power Stations. In the past, the relatively low volume of embedded generation did not have any substantial impact on the National Electricity Transmission System (NETS). However due to the growth of embedded generation, the impact is becoming more noticeable especially in the planning and operation of the transmission network. The following list of additional requirements was agreed upon for each Embedded Small Power Stations (ESPS) of 1 MW and above: A unique name The fuel type, adopting the definitions of the Electricity Network Association (ENA) The registered capacity in MW The node on the single line diagram to which it connects to The geographical location (latitude and longitude) of the primary substation to which it connects to (only for photo voltaic and wind based ESPS). The voltage or power factor set point The Loss of Mains protection types and settings It was noted that there may be a need to gather some of the proposed data items prior to the implementation date of 2015 to satisfy the European Transparency regulation. This could be enacted via a staged implementation in the Grid Code or a separate information request. The Workgroup favoured implementing a single process change for the 2015 target date rather than the staged approach. It was agreed that ESPS below 1MW would not be considered at this stage due to the limitation in the amount of information available for these units.

GC0050 Demand Control and OC6
The Workgroup was tasked with assessing the existing capabilities of the industry to implement Demand Control instructions and evaluate whether current requirements are still fit for purpose. The Workgroup determined and assessed: The need for, and requirements of, Demand Control Instructions Existing capabilities of the DNOs to implement Demand Control Instructions The costs, benefits and risks of any actions necessary to ensure that DNOs can implement the required Demand Control Instructions in the required timescales under future system requirements Demand Reduction tests ongoing during October GC0050 Workgroup Report to be presented to January GCRP. DNOs positions around demand reduction being implemented within five minutes and investigated the timing of each of the steps that need to be taken to implement voltage reduction. The historic expectation was that a 3% voltage reduction would deliver a demand reduction of 5%; however studies have since indicated that the demand reduction for a 3% voltage reduction was variable, and more likely to be in the region of 3%. The current drafting of the Grid Code requires a 5% demand reduction at the time of the instruction introduced a degree of uncertainty around what could actually be delivered. DNO’s have suggested that they are unlikely to actually deliver a 3% voltage reduction within a five minute period, and all DNOs agreed that general demand reduction is more likely to be delivered in a period between 5-to-12 minutes. Demand Reduction tests involve the NGET control room issueing a demand control reduction and the DNO being tested is expected to carry out a voltage reduction to assess the delivery. Tests are being carried out at a time of stable demand, users/consumers will not notice a change.

The Workgroup have defined and critically reviewed the deficiencies
GC0063 Power Available The Workgroup have defined and critically reviewed the deficiencies A number of options have been considered, and the Workgroup are likely to recommend the submission of Power Available as an operational metering signal which would be fed to the National Grid Control Centre via SCADA with the definition of MEL used to indicate electrically connected capacity. There are still questions regarding the costs of implementation, and retrospective application that require further analysis The Workgroup is expected to present the Workgroup Report at the November GCRP and carry out an Industry Consultation during December. Workgroup are looking at whether Power Available is required in the UK by looking at the defect it attempts to resolve, how it can be implemented and the information currently available to NG as NETSO Deficiencies fell into two main categories Operational Data necessary for the SO to operate the Tx System Accurate Settlement of Bid Offer Acceptances The Workgroup concluded that the BOA settlement could be independently progressed through the BSC governance if it was considered necessary by BSC parties Power Available is an indication of the maximum achievable output which could be delivered by a wind farm under the current prevailing weather conditions when, for example, the current output may have been reduced for the provision of balancing services to the system operator. This workgroup originally ran in conjunction with High Wind Speed Shutdown until its conclusion

GC0035 Frequency Changes during Large Disturbances and their effect on the total system
The joint DCRP and GCRP Workgroup is examining how the maximum rate of change of frequency (RoCoF) seen by the electricity networks in GB is likely to increase, and how this impacts on the effectiveness of RoCoF based Loss of Mains (LOM) protection. Phase 1 (5-50MW Total Registered Capacity) Workgroup report presented in July Recommended changing RoCoF to 1Hzs-1 measured over 500ms Industry Consultation closed on 27 September Workgroup are reviewing the responses before presenting their recommendation to Ofgem Phase 2 Incorporates sub 5MW machines, inverter technology and multi-machine islands Requests for proposals for two independent studies will be published soon Workgroup will develop RoCoF withstand requirements Phase 1 = Plant between 5 and 50MW The first phase workgroup report was presented to the DCRP and GCRP in July; the report sets out proposals for changing RoCoF protection settings on plant above 5MW to 1Hzs-1 measured over half a second. Stakeholder workshops held in September Phase 1 only expected to the Dcode and Engineering recommendation changes Phase 2= smaller than 5MW machines inverter type machines (Solar) Multi machine islands (more than one generator on an island) RoCoF withstand requirement Other LOM types, namely Vector Shift Proposals for consultant work going out soon. Recommendations expected in 2014.

GC0037 (BMU Configurations Offshore)
Other areas of note GC0033 (Offshore Wind Farms not connected to an Offshore Transmission System) The Authority decision is expected on 22 October GC0037 (BMU Configurations Offshore) National Grid are reviewing the Industry Consultation response GC0071, 72 and 73 (Code Governance Phase 2 Modifications) The Authority decision is expected on 18 October GC0033 (Offshore Wind Farms not connected to an Offshore Transmission System) This proposal seeks to modify the Grid Code to ensure that the benefits afforded to ‘Power Park Modules’ in the Grid Code are restored to relevant Generators located Offshore and to improve the clarity of the code. The industry Consultation was published on 15th February 2013 and closed on 15th March 2013, with 3 responses received. National Grid submitted the Report to the Authority on 17th September, a decision is expected on 22 September GC0037 (BMU Configurations Offshore) This proposal seeks to modify the Grid Code to improve the information exchanged between NGET and Transmission Users regarding the configuration of Power Park Modules and BMUs given the operational flexibility now facilitated under the Transmission Frameworks. A workgroup investigated this issue and the Industry Consultation was published on 23 August 2013 and will close on 24 September 2013. GC0071: Code Governance Review (Phase 2): Significant Code Review GC0072: Code Governance Review (Phase 2): Code Administrator and Code Administration Code of Practice GC0073: Code Governance Review (Phase 2): Send Back Process These modifications propose changes to facilitate the implementation of Code Governance Review (Phase 2) into the Grid Code. GC0071: The Significant Code Review (SCR) process will require the licence holder to raise code Modifications in line with the directions issued by the Authority following an SCR. GC0072: This modification proposal seeks to make several changes to the Grid Code, including the requirement to establish an administrative body (the “Code Administrator”) and for the Code Administrator to maintain, publish, review and amend the Code Administration Code of Practice (CACOP). GC0073: The Send Back process will enable the Authority to formally ‘send back’ an Industry Consultation to NGET in circumstances where the Authority considers that it is unable to form a decision based on the content of the consultation.

Contact Information Website:

DCUSA Change Proposals Update
Michael Walls Governance Services Senior Analyst – ElectraLink Ltd. Tel:

What is the DCUSA? The Distribution Connection and Use of System Agreement is a multi-party contract between the licensed electricity distributors, suppliers and generators of Great Britain The DCUSA defines the rules for connecting and using the UK’s electricity network distribution systems It is essentially a legal contract which commenced on 6 October 2006 Parties to the DCUSA include: DNOs, Suppliers, IDNOs, DG, Gas Suppliers and OTSO

Current DCUSA Activities
DCUSA website review Smart Metering 31 Change Proposals in progress 21 of those are Charging Related Theft of Electricity (CoP) Induction training sessions Code Administration Code of Practice Next DCUSA Release 7 November 2013

DCUSA Change Process - Overview
Parties Panel Secretariat Ofgem Pre-Change Process (Charging methodology changes) CP raised Modelling Resource Initial Assessment Working Group Assessment Industry Consultation Change Report Implementation Party Voting Change Declaration Authority Consent

Overview of the DCMF MIG Pre-Change Process
Originator DCMF MIG DCMF DCUSA Issue submitted Issue defined Recommendation Decision CP Raised From Pre-Change Process to formal DCUSA Change Process Modelling Resource Industry Consultation Working Group Change Report Outcome Voting Implemented

Overview of Common Distribution Charging Methodologies in DCUSA Open Governance - CDCM and EDCM
The governance and change management processes for the Common Distribution Charging Methodology (CDCM) were implemented into the DCUSA on 01 January 2010. The governance and change management processes for the EHV Distribution Charging Methodology (EDCM) (import) were implemented into the DCUSA on 01 April 2012. The governance and change management processes for the Common Connection Charging Methodology (CCCM) were implemented on 30 October 2012. The governance and change management processes for the EDCM (export) were implemented on 01 April 2013. As the methodologies will be common among all DNOs, this brings about many improvements, such as: More transparency, and as the complexities of the methodologies have been agreed, dialogue among all Parties have to be taken into account for any change; and When there is a change brought about by any Party, all DNOs must implement it and model the changes.

The National Terms of Connection
Unless otherwise agreed, the NTC is the connection agreement between the end user and the distributor When you enter into your electricity supply contract with your supplier, you are also entering into a connection agreement with your electricity network operator on these terms

Charging Methodology CP Summary
Status CDCM EDCM CCCM Billing WG: Pre Consultation 7 (DCP 133, 159, 160, 161, 165, 178, 179) 1 (DCP 138) 1 (DCP 172) WG: Consultation 1 (DCP 158) 3 (DCP 162, 166, 167) WG: Post Consultation 8 ( DCP 137, 123, 117, 168, 169, 173, 174, 180) Change Report Voting Awaiting Consent Approved: Awaiting Implementation 1 (DCP 118) 5 (DCP 142, 144, 146, 147, 148) Approved: Implemented 10 (DCP 130, 126, 131, 132, 134, 136, 150, 163, 128, 129) 1(DCP 152) 1 (DCP 140) Rejected 1 (DCP 164) 1 (DCP 139) 4 (DCP 141, 145, 143, 149) Total 28 3 5 9

Charging Methodology CPs: Definition Stage
DCP Title Status DCP 117 Treatment of ‘Load related new connections & reinforcement (net of contributions)’ in the Price Control Working Group considering progression routes for the CP DCP 123 Revenue Matching Methodology Change Awaiting consultancy support DCP 133 500 MW network common model for CDCM input Impact analysis to be completed in January 2014 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 Awaiting Ofgem decision on Network Use Factor proposals DCP 158 DNO DUoS re EDNOs Working Group reviewing consultation responses DCP 159 Volumes data in the CDCM

DCP Title Status DCP 160 Non-Half Hourly (NHH) Notional Capacity Awaiting outcome of DCP 165 before progressing DCP 161 Excess Capacity Charges Working Group is drafting a consultation which will be issued shortly DCP 162 Non-Secure Connections in the Common Connections Charging Methodology Working Group reviewing consultation responses DCP 165 Voltage Level Approach to Unit Charges in the CDCM Awaiting outcome of DCP 179 before determining how to progress DCP 166 Additional text for the DNO Common Connection Charging Methodology to provide clarity where a customer requests a supply voltage in excess of the ‘minimum scheme’ for the capacity requested. DCP 167 Additional examples for the Common Connection Charging Methodology to illustrate ‘remote reinforcement and remote reconfiguration’ DCP 168 The Administration of Use of System charges relating to connections from Embedded Distribution Network Operator (EDNO) systems to Unmetered Supplies (UMS) for LA customers. Working Group is reviewing the consultation responses and determining how to progress

DCP Title Status DCP 169 Seasonal Time of Day (SToD) HH Metered Tariffs in the CDCM Awaiting the progression of DCP 123 DCP 172 Clarification of way in which voltage rise is used in determining the New Network Capacity Working Group drafting consultation document DCP 173 Retrospective changes of Tariff (LLFC / Unique Identifier) The Working Group will issue a second consultation on legal text and progression routes in due course DCP 174 Qualification and application of LV sub-station tariffs Change Report will be issued to Parties for voting today DCP 178 Notification period for change to use of system charges DCP 179 Amending the CDCM tariff structure Awaiting consultancy support DCP 180 Further reduction in the volatility of Use of System Charges Working Group reviewing consultation responses

Charging Methodology CPs: Implemented
DCP Title Status DCP 142 Using D2021 for all invoices/credit notes if it is used at all Implemented 1 October 2013 DCP 144 Prohibiting rounding of HH data DCP 146 HH invoice runs DCP 147 Preventing UoS invoices containing non-UoS elements DCP 148 Rebilling to be done via credit/rebill DCP 171 Housekeeping re Black Yellow Green DCP 177 Housekeeping change relating to DCP 127 to allow Gas Suppliers accession to DCUSA DCP 184 Housekeeping change following implementation of DCP127

DCUSA Contacts Charging Methodology CPs and DCMF/DCMF MIG
Roz Timperley Michael Walls DCUSA CPs, CCCM CPs and DCUSA SIG Claire Hynes Telephone – And finally if you have any DCUSA related questions here is how you can get in touch with us… 54

Supply Point Administration Agreement (SPAA) Update
Verena Leckebusch Governance Services Coordinator – ElectraLink Ltd. Tel:

Supply Point Administration Agreement (SPAA)
Multi-party agreement: inter-operational arrangements between gas suppliers & transporters Domestic gas suppliers and gas transporters required to accede SPAA - Agreement 24 Sections: Administration and governance arrangements 34 Schedules (mandatory/elective/voluntary): Pre-payment arrangements, erroneous transfers, duplicate meter points, crossed meters, Metering Schedule data, Theft of Gas arrangements et al. Market Domain Data (incl. market participant short codes, meter and converter models) SPAA Products Review of Gas Metering Arrangements (RGMA) AMR Processes Code of Practice for Gas Meter Asset Managers (MAMCoP) 56

Code Administrator and Secretariat (CAS)
SPAA Governance Executive Committee Change Board Expert Group GPEG MAMCoP Theft of Gas TRAS Forum FACC SPAA Board Code Administrator and Secretariat (CAS) talk through – list them; standard sub-committees and WGs – some of them convene on regular basis – others on ad-hoc basis; 57

SPAA Change Process 58

Current SPAA Activities
Smart Consequential Changes Background Smart Metering Implementation Programme “Legacy System Changes (Enduring)” 2011 Cross-code Smart Working Issues Group (SWIG): identification changes UNC, iGT UNC & SPAA SPAA Changes Modifications to SPAA & SPAA Products (RGMA, MDD): smart meter values and market participants (values and procedures for retrospective changes) Theft of Gas Arrangements Theft of Gas Code of Practice (CoP) Implemented in March 2013 Further enhancements (e.g. unregistered & shipper-less sites; Data Protection Act)  Version 2.0 to be implemented in February 2014 Theft Risk Assessment Service (TRAS) Supply Licence condition: Service to assist efforts to detect theft by using data to profile the risk of gas theft at premises Ongoing; CP 13/239 on TRAS arrangements awaiting implementation

Current SPAA Activities
Ofgem Code Governance Review (CGR) Phase 2 Aim to reduce red tape and ensure consistency across codes Changes to enact CGR2 final proposals/ Licence conditions due by 31 December 2013 Code of Practice for Gas Meter Asset Managers (MAMCoP) Version 3.0 to be implemented in November (MAM CP 12/001) MAM CP 13/002 ‘Ensuring Supply Contracts Are In Place Before Meter Fits’ Audit and Governance Review in view of Registration Agent re-procurement in 2014 Ofgem Approved Meter Installers (OAMI) OAMI = registered meter installers Ofgem codes of practice Opportunities to bring OAMI under SPAA governance? (current contract still runs until 2016) Further Activities: reconciliation MDD and UK Link data; review Metering Schedule Report

SPAA Change Register - Excerpt Smart Consequential Changes
CP Number Name Status Smart Consequential Changes CP 13/241 Gas Smart Metering System Operator (SMO) Retrospective Update Process Awaiting implementation CP 13/240 Smart changes to Schedule 31 'Procedure for the resolution of Crossed Meters' Appeal Window Open CP 13/237 Gas Smart Metering Retrospective Update Process Rejected (Published as SPAA Guideline) CP 13/236 Amendment to Schedule 20 to update with new Meter Mechanism codes Implemented (SPAA 9.5) CP 13/235 Inclusion of SMSO Id as MDD Market Participant Implemented (SPAA 9.6) CP 13/234 Amendment to Schedule 23 for the Foundation Stage of the Smart Metering Implementation Programme CP 13/231 RGMA Changes for Smart TRAS CP 13/239 TRAS Arrangements: TRAS Product Awaiting Implementation MAMCoP MAM 13/002 Ensuring Supply Contracts Are In Place Before Meter Fits Deferred MAM 12/001 Approve MAMCoP version 3.0 Further Changes CP 13/243 Changes to the Debt Assignment Protocol Process CP 12/227 Mandating Schedule 22 for Small Transporters CP 13/231 (Appeal Window Open, due for implementation June 2014) CP 13/236: Non-SMETS (NS), SMETS1 (S1), SMETS2 (S2) meter values (June 2013 release) CP 13/235: Smart Meter Operators (SMOs) market participant (October 2013 release) CP 13/241: SMO Update (Awaiting Authority Consent) CP13/237: Meter values Update (Rejected, published as SPAA Guidance)

Governance Services Coordinator – ElectraLink Ltd.
Questions or Comments Verena Leckebusch Governance Services Coordinator – ElectraLink Ltd. Tel:

The Supplier Obligation and Setting CfD Payments
Mark Bygraves, Director of Strategy and Development 18 October 2013

Content Background to ELEXON and to our CfD Settlement Agent role
How is Generator CfD payment and Supplier Obligation calculated How is Supplier Obligation collected in the meantime (Fixed vs Variable Levy) Backstops to provide certainty of payment to Generators Next Steps Executive responsible at Elexon for delivering our new EMR roles Been asked to talk about the supplier obligation and setting the CFD payments Not CM, Not CFD Allocation or Ts&Cs, nor Levy Control Framework Elexon’s existing role and our new SA roles Then how Generator payments and supplier’s ultimate liability for those payments is calculated Moving on to how funding is collected from suppliers in meantime (so called Fixed vs Variable Levy) Consequential mechanisms associated with that choice “Backstops”

ELEXON and our Settlement Agent Role
ELEXON’s existing balancing and settlement role We make sure that payment for imbalances in wholesale electricity supply and demand is settled accurately, fairly and efficiently ELEXON’s new Settlement Agent (SA) role for EMR April 2013 DECC confirmed intention to appoint ELEXON as SA for CfD & CM DECC: “ELEXON’s expertise and the fact that it already collects and processes the data that will be required for this work puts it in a unique position in the electricity market to fulfil the role as settlement agent for EMR” SA role to be separate from BSC role (both not for profit) Role driven by contract with CP, Supplier Obligation Regulations and CfD Ts&Cs DECC publications: CfD Supplier Obligation Policy update and response to call for evidence 7 August More information in October consultation Elexon is the BSCCo, central role in electricity wholesale market ELEXON compares all contracts to buy and sell electricity in the GB wholesale market with actual volumes We work out a price for the difference (imbalance) and make sure everyone is paid accurately and fairly for those differences by transferring funds This involves processing 1.25 million meter readings every day, handling £1.5 billion of our customers’ funds each year and holding nearly £350m in collateral [The rules are set out in the Balancing and Settlement Code (BSC) We administer the Code and provide and procure the services needed to implement it ] When Govt talked about new EMR regime to collect . Using powers that will be given to the SoS in the Energy Act Separate from BSCCo Working with Govt, don’t set policy This presentation drawing heavily on Aug publication “CfD Supplier Obligation Policy update and response to call for evidence” More in consultation Oct Meantime Collaborative Dev

Contract for Difference (CfD)
Source: UK Government White Paper, July 2011, licensed under the Open Government Licence v1.0

CFD Flows CfD Contract Licence Obligation BSCCo (ELEXON)
£ CfD Payment SP>RP CfD Generator CfD Counter-party (CP) £ CfD Costs Levy Licensed Suppliers £ Operating Costs Levy £ CfD if RP>SP Collateral & Backstops Collateral if RP>SP Services Contract Reconciliation £ Generation Volumes Settlement Agent (ELEXON) BSCCo (ELEXON) Left side is governed by terms of CFD Right side is a licence obligation Enforceable by Ofgem Classified as a direct tax, recoverable as a debt ELEXON is not the CP We hang off CP by way of contract, reflecting the CFD T&Cs and SO Supplier Obligation: to ensure that CP can meet its contractual obligations and provide certainty to Generators they will be paid Reference Price (RP) Data Supplier Volumes Supplier Obligation: to ensure that CP can meet its contractual obligations and provide certainty to Generators they will be paid Non payment is breach of Supply Licence

Lifecycle of CfD Generation Project
Phase 1 Policy Framework Established Legislation Takes Effect Stakeholders Prepare for Go-Live Phase 2 Allocation Process Application, assessment and CfD contract award CfD is signed by CP Phase 3 Project Achieves Financial Close Substantial Financial Commitment Satisfied Commissioning of project begins Phase 4 Conditions Precedent satisfied under contract Generation commences Phase 5 Payments start under the CfD Updates to contractual parameters (indexation, reference prices) Contract expires Phase 6 Potential for contract variation (e.g. change in law) Contract termination Allocation Process begins as First Come First Served. Moves to auction in future HMT Levy Control Framework is a financial cap, so limits number of projects Early or special projects (“FIDe”) have own negotiation with DECC, avoiding Phases 1 & 2 Collection of levy from Suppliers not shown DECC Delivery Body (NG) Generator Counterparty Generator Counterparty Generator Settlement Agent Counterparty Generator Counterparty Generator Setting of eligibility criteria and technology allocation parameters Strike Prices Managing the process for application and allocation of CfDs Offer contract Reserve fund(s) and collateral Invoicing and data reconciliation Handling receipts and payments Manage disputes

How is Generator CfD Payment and Supplier Obligation Calculated?
Strike Price – Ref. Price MWh CfD Payment How is Generator CfD Payment and Supplier Obligation Calculated? 1. For each CFD/FIDe: Strike price: technology specific, as adjusted by CFD/FIDe terms Reference price: day ahead or season ahead Generation metered volumes from BSC (HH volumes), private wire arrangements or NI Calculated half hourly, payable daily Total CfD Costs Supplier’s Market Share Supplier Obligation 2. For each Supplier: Calculation of payments to generators then look at how those are allocated to suppliers Ultimately – say ultimately as different regime to collect in meantime Simple calculation For every HH, just like the BSC CFD and FIDe For each HH work out difference and multiply by MW output to give CFD payment Then aggregate all that and add Op costs, Then allocate to suppliers in proportion to their mkt share for that HH Added complexity Adjustments as per CFD terms eg CPI indexation, capacity adjustments, Qualifying Change in Law Private wires, NI Day ahead - (utilising N2Ex and APX-UK if GB hub not available) EII volumes Reference price: Intermittent: GB day ahead hourly price published under GB European Market Hub Baseload: season ahead Total payments to Generators under CfDs and FIDe And operating costs of Counter-party and the Settlement Agent Based on volume of eligible electricity supplied each HH EII volumes discounted Calculated half hourly

How are CfD Payments from Suppliers Collected in Meantime?
Total CfD Costs Forecast Market Demand Forecast £/MWh “Fixed” POA Levy In advance, CP forecasts total annual CfD/FIDe costs CP forecasts total annual electricity demand EII eligible volumes discounted CP derives annual Fixed Rate Levy expressed in £/MWh Really a Payment on Account or POA Fixed POA Levy £/MWh designed to provide Suppliers with some certainty on costs to include in customer tariffs Suppliers charged using POA x Supplier’s actual Gross Demand for each HH (aggregated into daily billing periods) Billing period of 1 day; invoiced 7 days after; payable within 5 days CP also estimates operating costs of CP (incl SA) to derive separate Operating Cost Levy (£/MWh) Variables will be run through a model designed by DECC and Counterparty This fixed rate levy is therefore also referred to as an estimated levy rate or POA [Rate not set in legislation as will change In-year adjustments possible e.g. black swan events. More on this later] EII applies from 2015 or later (TBC). Suppliers Gross Demand excludes embedded generation and will be adjusted for Distribution and Transmission losses PoA rate runs from 1 April to 31 March

Backstops to Ensure Certainty of Funds to Pay Generators
CP can withhold payments to Suppliers if insufficient funds. So: Acts as working capital and held in cash Lump sum determined by CP’s model, paid annually and reconciled Suppliers pay based on market share Reserve Fund To cover Supplier Default Cash and Letters of Credit, not PCG Amount based on time between billing period and payment for that period Collateral Called upon when Suppliers’ collateral exhausted Lump sum paid annually, amount based on potential exposure if small Supplier(s) default Insolvency Reserve Fund Used to recover unpaid levy of defaulting Supplier(s) Tops up Insolvency Fund From non insolvent Suppliers, based on market share at time of mutualisation Mutualisation Supplier of Last Resort – effective mainly to cover small Suppliers Energy Supply Company Administration regime – appointment of energy administrator to run the Supplier SOLR/ESCA Reserve Fund – size Collateral required to cover billing cycle Insolvency fund - seen as short term unsecured debt eg sm S insolvent, exhausts collateral, prior to SOLR; Low because based on Sm S Tops up Insol Fund; By non insolv Ss, based on mkt share at time of mutualisation; Timing of notification TBC SOLR – effective mainly to cover sm S and small exposure (few days for SOLR) usually covered by Collateral ESCA – appointment of energy administrator to run the S with Financial Assistance from Govt if necessary All enforceable by Ofgem as breach of licence is not paid

Next Steps ELEXON is currently:
Identifying requirements of the settlement system Identifying changes to BSC to provide relevant information to SA Preparing to establish new EMR SA business Further information on Supplier Obligation in October consultation Primary legislation in force this winter and Secondary Regulations in force “July 2014”*; Payments ready to flow “End 2014”* * Source “CfD Supplier Obligation Policy update and response to call for evidence” 7 Aug Industry needs to know: Timing of first CfD/FIDe payments Timing of first levy collection, and of collection of backstop funds Amount of levy rates (CfD and Op costs) and amount of backstops Timing of notification of levy rates and backstops, to include in tariffs Over recovery pay back to Supplier Competitive tender before end of year System testing complete, payments ready to flow “End 2014” ELEXON can manage the additional complexity of: Reference Price data – sources of day ahead and season ahead EII exemption – Eligible EII volumes are excluded when calculating Supplier ‘s market share Extending to NI Suppliers and Generators Separate metering arrangements for private networks, NI Payments treated as tax, requiring additional separation Renewable Fuel Qualifying Multiplier and FMSA EII - Scope of exemption to be determined although extending to Suppliers in NI may wait until Generators in NI are covered by CfDs Termination payments to where? Change in law lump sum payments to Gen from where?

Cross-Codes Electricity Forum: Smart Update
Victoria Moxham 18 October 2013

Recap Source:

August: Key roles announced
Data and Communications Company Capita PLC Under licence regulated by Ofgem Smart energy code administrator and secretariat Gemserv Data Service Provider GCI IT UK Limited Communications Service Provider Arquiva Limited Scotland & North of England Telefonica UK Limited Wales & rest of England

SMIP working groups Source:

Publications & updates
Ofgem’s response to DECC’s open letter on proposed amendments to non-domestic roll-out licence conditions (23 Aug) Supplier reporting to Ofgem during the smart meter roll-out (30 July) Ofgem’s response to DECC’s further consultation the Foundation Smart Market (7 June) Ofgem’s response to the Department of Energy and Climate Change’s (DECC) consultation on the draft legal text to support transitional arrangements for Smart Metering (20 May)

Publications & updates
Smart Meters statistics (26 Sep) Designation of the Smart Energy Code and charging methodology (23 Sep) Foundation Smart Market: The Government Response to the Consultation on the Foundation Smart Market and Further Consultation (27 Aug) Smart metering equipment technical specifications: second version (24 July)

BSC Changes Modification Proposal P292
‘Amending Supplier & Meter Operator Agent responsibilities for smart Meter Technical Details’ Approved by Ofgem in June Will enable the changes to Supplier and Non-Half-Hourly Meter Operator Agent (NHHMOA) responsibilities for smart Meter Technical Details (MTD) proposed by the Department of Energy and Climate Change’s smart metering operating model Due to be implemented June 2014

Profiling and Settlement Review Group (PSRG)
ELEXON is reviewing the BSC profiling and settlement arrangements in light of the recent advances in metering and the rollout of smart meters developments PSRG established in March 2010 by the Supplier Volume Allocation Group (SVG) to assist in this review Current focus (Stage 2): how to maintain accuracy, equitability and efficiency of the profiling and settlement processes Improving the existing profiling approach Mandating half hourly settlement Reducing the settlement timetable How GSP Group Correction Factor could be applied to half hourly meters

Where to find further information
Monthly updates provided by ELEXON to the BSC Panel Smart metering pages on the ELEXON website Profiling and Settlement Review Group

European Network Codes
Adam Hipgrave Cross Codes Forum 18 October 2013

The challenge: Achieving a harmonised European energy market
Europe in a nutshell The challenge: Achieving a harmonised European energy market 83 83

The Third Energy Package
3 regulations and 2 directives. Adopted July 2009, law since March 2011 Key step forward in developing a (more) harmonised European energy market Separation of ownership of monopoly energy transmission activities Formation of European Transmission System bodies, ENTSOG and ENTSO-E Formation of ACER – Agency for Cooperation of Energy Regulators Security of supply Competitiveness Sustainability European Third Energy Package This came into law on 3 March It is a key step forward in developing a more harmonised European energy market. The main areas it addressed are: - Separation of vertically integrated energy transmission activities. - Requirement to develop and implement European Network Codes (ENCs). - Set up of ACER and ENTSO-E / -G European Network Code Development The ENCs will be European legislation and will take precedence over existing arrangements in the GB codes, where differences arise, and could have a far reaching impact on how things are done in the GB market. NG is represented on each of the code drafting teams set up by ENTSO-E. We are also managing stakeholder engagement within GB to foster engagement in the ENC process. 9 codes are currently under development dealing with Grid connections, Common European market rules and System operation. It is likely that further codes will follow. Major challenges/how we are managing: - Keeping to the implementation timelines (broadly up to 2014). - Achieving bought-into solutions that work for GB. (promoting stakeholder engagement in the ENC process; facilitating understanding of the code detail and reasoning behind decisions made) - Determining how to implement the codes, including how to revise the current GB commercial and regulatory framework to reflect the obligations and requirements in the ENCs. (Close liaison with Ofgem/DECC/DNOs to determine strategy for implementation; clear assignment of responsibilities between each)

European Network Code Development Process
Commission starts development process ACER reviews Network Code 3 months Comitology Commission 1 year? ACER develops FWGL 6 months Commission invites ENTSO to develop Network Code To fit work programme ENTSO develops Network Code 1 year Stakeholder Engagement By 2014 Network Code becomes Law

How to get involved ENTSO-E workshops and consultations
Joint European Standing Group: GB stakeholder workshops and consultations facilitated by National Grid DECC / Ofgem Stakeholder Group

The Priority Network Codes
Grid Connection Codes Market Codes System Operation Codes Requirements for Generators CACM Operational Security Demand Connection Code Forward Capacity Allocation Operational Planning and Scheduling HVDC Balancing Load-Frequency Control and Reserves

European Network Code Development Status: October 2013
6 months To fit work programme 12 months 3 months 1 year (?) ACER develops FWGL EC invites ENTSO-E to develop Network Code ENTSO-E develops Network Code ACER reviews Network Code ACER recommends Network Code to EC Comitology Network Code becomes Law Member State Implementation ACER revises opinion Revisions to Code after Opinion Grid Connection CACM System Operation Balancing Developed by EC* FCA Op Sch & Plan Op Sec Transparency Regulations HVDC Balancing LFCR DCC RFG CACM † Gov. Guide. 1 2 3 4 5 6 7 8 9 10 11 12 Preparation Member State Approval Council & Parliament Approval Drafting Approval Public Consultation Revise Code Approval * Areas developed by EC follow a different development process and there are no Framework Guidelines. † Governance Guidelines prepared by Commission are being merged with CACM NC.

To put it another way… Summer 2013 Highlights Throughout:
ENTSO-E to revise OS and OPS Network Codes Balancing Public Consultation runs until 16 August Comitology preparation for CACM, RFG and DCC continue. GB Code Panels asked to setup ECCAF September Final FCA Network Code to be submitted to ACER ACER Opinion on LFCR due

Application of ENCs to GB Codes
European Network Codes due to become law during 2014 in a phased manner GB will have 18 months – 3 years to demonstrate compliance (varies code-by-code) Alignment with GB Codes will aid application and compliance GB Code panels will retain their role to make changes to individual codes – strong feedback from all parties was to use existing processes A complex programme with a significant risk, which needs cross-code coordination

European Code Coordination Application Forum
Advises the Code Panels on coordination of application of European Network Codes to GB Codes No firm legal or governance role Constituted as a joint standing group of 7 code panels Grid Code, CUSC, BSC, SQSS, STC, D-Code, DCUSA Membership: 7 industry members representing Code Panels National Grid, Consumer Futures, DECC, Ofgem Chair appointed by DECC and Ofgem

Summary European Codes will supersede GB Codes
Network Codes become EU Law ‘by 2014’ Codes have varying compliance periods (typically ) Significant workload and changes over the next few years Complete development of Codes Apply them to the GB Framework Implement changes to the GB Operations and Market Ample opportunity to get your thoughts heard JESG / ENTSO-E consultations /DECC-Ofgem stakeholder group

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