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Cross Codes Forum

Cross Codes Forum. ELEXON, National Grid & Electralink. 21 September 2012. Introduction and Housekeeping. Emma Piercy. Welcome to ELEXON. What we’ll cover today: . ELEXON Evacuation Muster Point. If there is an alarm, follow the instructions of the Fire Wardens

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Cross Codes Forum

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

  2. Introduction and Housekeeping Emma Piercy

  3. Welcome to ELEXON What we’ll cover today:

  4. ELEXONEvacuation Muster Point • If there is an alarm, follow the instructions of the Fire Wardens • The evacuation point is here…

  5. Energy Supply Company AdministrationDawn ArmstrongSystem Balancing and Retail Markets

  6. Context • SoLR arrangements tested several times • Unlikely to work in the event of a major supplier’s insolvency • Concerns around length of time it could take to either sell the company or transfer customers leading to excessive and unpredictable imbalance payments for other parties • Risk of financial failure spreading to other industry participants • Provisions included in Energy Act 2011 for a special administration regime for supply companies 6

  7. Legal Framework • Energy Act 2011 provides broad legal framework • Energy Supply Company Administration Rules – rules of procedure required for full implementation (separate rules for Scotland) • Modification of licences to institute a cost recovery mechanism 7

  8. Cost recovery mechanism • Provisions in the Energy Act for the company in esc administration to repay any funding received from government. • Provisions for SoS to amend licences for the purpose of setting up a cost recovery mechanism. • Proposal is to replicate cost recovery mechanism already in place for the special administration regime for network and distribution companies. • Costs smeared across suppliers. 9

  9. How would it work? • SoS issues a shortfall direction to Grid to raise the charges it levies on electricity suppliers and gas shippers • Direction would include: • which charge should be raised; • details of amount to be raised; • how it is to be raised; • when the payments are to be made. 10

  10. Proposed licence changes • Propose maximum flexibility to raise any of the charges Grid currently levies on electricity suppliers and gas shippers m • Transmission Network Use of System and Balancing Charges sufficiently broad in scope to allow Grid to increase to cover a shortfall • But changes necessary to: • SLC 15 in electricity supply licences • SLC 19 to shippers’ licences • SLC 15 was amended in 2006 to allow Grid to raise the charge to discharge a shortfall direction in relation to Energy Administration (SAR for network and distribution). • SLC 19 was a new condition inserted to allow Grid to raise charges on shippers to discharge a shortfall direction. • Propose amending both allow Grid to raise charges to shortfall direction in relation to esc administration. 11

  11. Timing • Draft England and Wales rules were published in June • Aim to publish Scotland Rules in September • Licence changes for cost recovery mechanism – aim to publish October • Rules on the statute book and licence changes complete by April 2013 12

  12. European Network CodesInformation for the Cross-Codes Forum Paul Wakeley Electricity Codes • Regulatory Frameworks • National Grid 21 September 2012

  13. Agenda • The Third Package • European Network Codes • Process • Status • Further Information and Getting Involved

  14. The Third Package

  15. Third Package • The European Third Energy Package was adopted in July 2009, and has been law since March 2011 • Key step forward in developing a more harmonised European energy market  • Separation of ownership of monopoly energy transmission activities • The formation of European Transmission System bodies, ENTSOG and ENTSO-E • The formation of ACER – Agency for Cooperation of Energy Regulators • ACER and ENTSO-E both have a role in the development of European Network Codes (ENCs)

  16. Third Package – ENTSO-E • European Network of Transmission System Operators • 41 TSOs from 34 countries • What ENTSO-E does: • Drafting European Network Codes (ENCs) • Europe-Wide Ten-Year Network Develop Plan (TYNDP) including a European generation adequacy outlook, every two years • Common network operation tools to ensure coordination of network operation in normal and emergency conditions • Annual summer and winter generation adequacy reports

  17. Electricity European Network Codes

  18. Electricity European Network Codes • There are 12 areas where Network Codes will be developed to support ‘cross-border’ issues • Regulations on Data Transparency, Governance Guidelines and Tariff Harmonisation are to be developed by the Commission • Target date for ‘Single European Energy Market’ is 2014 • Where there is a difference to existing national rules, European Network Codes take precedence

  19. Comitology Commission European Network Code Development Process • The process for developing the European Network Codes is defined in EU law Commission starts development process ACER develops FWGL Commission invites ENTSO-E to develop Network Code ENTSO-E develops Network Code ACER reviewsNetwork Code Stakeholder Engagement By 2014 Network Code becomes Law

  20. The ‘live’ Network Codes

  21. Drafting and Stakeholder Workshops Public Consultation Assembly Approval Revise Code ACER develops FWGL EC invites ENTSO-E to develop Network Code ENTSO-E develops Network Code ACER reviewsNetwork Code Comitology Network Code becomes Law Grid Connection FWGL Balancing HVDC Forwards RFG CACM FWGL System Operation FWGL Balancing FWGL CACM LF&R Op Sch & Plan Op Sec DCC

  22. October 2012 Highlights • CACM Network Code is submitted by ENTSO-E to ACER for review against the Framework Guidelines • Forwards Markets Network Code drafting due to commence • Balancing Network Code drafting expected to commence, once Framework Guidelines completed • ACER to publish opinion on RFG Network Code

  23. Implementation of European Network Codes within GB

  24. Key Issues • European Network Codes take precedence over existing national arrangements - we must therefore change our Codes • There are elements of national choice in the ENC • There will be multiple ENCs with various timeframes / applicability which will require changes to all GB Codes (Grid Code, STC, CUSC, BSC, D-Code, DCUSA etc). • Different thresholds in ENCs to those in GB, e.g. • Grid Code has Small, Medium and Large power stations; • RFG has Type A, B, C, D power generating modules. Type A applies from 800W upwards

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

  26. Getting Involved / Further Information

  27. How to get involved • ENTSO-E workshops and consultations • http://www.entsoe.eu • Joint European Standing Group: GB stakeholder workshops and consultations facilitated by National Grid • http://www.nationalgrid.com/uk/Electricity/Codes/systemcode/workingstandinggroups/JointEuroSG/ • DECC / Ofgem Stakeholder Group • http://www.ofgem.gov.uk/Europe/stakeholder-group/Pages/index.aspx

  28. Any Questions? • Paul.Wakeley@nationalgrid.com • 01926 655582

  29. CUSC and Grid Code Changes Emma Clark Electricity Codes • Regulatory Frameworks • National Grid 21 September 2012

  30. CUSC Modifications • CMP201 – Removal of BSUoS charges from Generators • Seeks to align GB arrangements with other EU Member States by removing BSUoS charges from GB Generators. • Panel Recommendation Vote on 28 September 2012. • CMP202 – Revised treatment of BSUoS charges for lead parties of interconnector BM Units • Removes BSUoS charges for Interconnector BM Units which furthers the European Commission’s objectives of facilitating cross-border access and developing a Europe-wide single internal market in electricity. • Approved by Authority and Implemented on 31 August 2012. • CMP203 – TNUoS charging arrangements for infrastructure assets subject to one-off charges • Any user who pays a one-off charge will not end up being charged again for the works through TNUoS. • Decision due on 18 September 2012.

  31. 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.

  32. 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.

  33. 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.

  34. 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.

  35. 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/TCMF/

  36. Contact Information • Email: • Emma.Clark2@nationalgrid.com • cusc.team@nationalgrid.com (CUSC) • grid.code@nationalgrid.com(Grid Code) • Website: • http://www.nationalgrid.com/uk/Electricity/Codes/systemcode/ • http://www.nationalgrid.com/uk/Electricity/Codes/gridcode/ • Phone: • Emma Clark - 01926 655223

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

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

  39. Background History • 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.

  40. Background SCR Process • Introduced in January 2011 following completion of Code Governance Review • Allows Ofgem to lead on a holistic review of a code-based issue with a significant impact • Open, accessible and consultative process - 12 months (or longer if complex issue as with the EB SCR, which we estimate will last ~18 months) • Initial consultation, draft policy decision, final decision • Relevant licensee directed to raise code mods – GEMA to approve/reject • System changes may be required as part of implementation

  41. Background Indicative electricity balancing SCR timetable Usual BSC mod process

  42. Background Objectives • Incentivise an efficient level of security of supply • Incentivise optimal level of investment • Pay firm customers appropriately for the DSR service they provide if their demand is involuntarily interrupted • Incentivise plant flexibility and DSR • Increase the efficiency of electricity balancing • Minimise market distortions due to the need for the SO to balance the system • Incentivise participants to balance their position as far as is efficient • Appropriately reflect the SO’s cost for balancing in cash-out prices • Ensure our balancing arrangements are compliant with the European Target Model and complement the EMR Capacity Mechanism

  43. Background Main interactions • European Target Model (TM) • Throughout our review we will aim to ensure that any changes are compliant with the developing TM. We will also carefully consider timing of reform to avoid costs associated with repeated market changes. • EMR Capacity Mechanism (CM) • Electricity cash-out and CM have distinct but complementary roles in providing security of supply. • In policy design and before implementing any reforms we will consider the impact on the effectiveness of the CM carefully. • Ongoing mods • GEMA to decide if mods raised during SCR are to be subsumed as ‘falling within scope’ • For ‘related’ mods raised prior to SCR launch normal mod process applies, i.e. GEMA to decide whether to accept/reject

  44. Primary Considerations Scope: Primary Considerations • Changes to existing balancing arrangements • More marginal main cash-out price • Single or dual cash-out price • Single or separate trading accounts • Pay-as-bid or pay-as-clear for energy balancing services • Improvements to price inputs • Attributing a cost to non-costed actions • Improved allocation of reserve costs • New balancing arrangements • Balancing Energy Market (BEM) • Alternative arrangements for renewables

  45. Primary Considerations Changes to existing arrangements • More marginal main cash-out price • Cash-out price may not fully reflect scarcity at times of system stress • We will consider making cash-out prices more marginal (through changing PAR level). • P217A analysis (work Ofgem has done with Elexon and NG) indicates that mod P217A has reduced ‘system pollution’ of cash-out prices, which was one of the main obstacles to lower PAR levels in the past. • Single or dual cash-out prices • Dual cash-out prices have large spreads, increase risk and complicate arrangements • Economic theory: there should only be one price for a commodity at a time. • We would like to consider the merits of a single price or of hybrid options.

  46. Primary Considerations Changes to existing arrangements • Single or separate trading accounts • Participants who operate on both sides of the market are required to balance their consumption and production positions separately. • We will consider the merits of allowing them to net of their positions • Pay-as-bid or pay-as-clear for energy balancing services • Theory: similar outcome with perfect foresight • Practice: no perfect foresight. Pay-as-clear more efficient since participants are incentivised to bid their true marginal cost?

  47. Primary Considerations Improvements to price inputs • Attributing a cost to non-costed actions • Some balancing actions available to the SO, such as voltage control and involuntary demand disconnection, are not currently reflected in the cash-out price • Improved allocation of reserve costs • Target reserve cost more accurately into the periods for which they are procured and/or in which they are used.

  48. Primary Considerations New balancing arrangements • Balancing Energy Market (BEM) • Could allows anticipated energy imbalances on the system (and individual participants’ imbalances) to be cleared at a point ahead of real time. • Would constitute a major change to current arrangements • Alternative arrangements for renewables • Intermittent renewables are not able to control their output to the same extent as conventional generation. Fluctuations in wind output pose a challenge to balancing the system. • Is it more efficient overall for intermittent generation to be aggregated centrally or de-centrally? Need to consider effects on incentives for accurate forecasting and independent aggregation.

  49. Secondary Considerations Scope: Secondary Considerations • Secondary considerations may become relevant depending on choices made on primary considerations – some may also warrant investigation separately. • Improved provision of information • Creating a Reserve Market • Amending gate closure • Residual cashflow reallocation cashflow (RCRC) • Reverse price • Setting an information imbalance charge

  50. 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

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