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EDCM Development Workshop

EDCM Development Workshop. Welcome. 1 | Energy Networks Association. Introduction. Andrew Neves Central Networks CMG Chair. 2 | Energy Networks Association. Agenda morning. START 10am Ofgem Background and recent developments Overview of EDCM Charging Model

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EDCM Development Workshop

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  1. EDCM Development Workshop Welcome 1 | Energy Networks Association

  2. Introduction Andrew Neves Central Networks CMG Chair 2 | Energy Networks Association

  3. Agenda morning START 10am • Ofgem • Background and recent developments • Overview of EDCM Charging Model • Main charging proposal • LRIC/FCP charges and network use factors • Transmission exit and reactive power charges • Demand Scaling • Sole use assets • Generation charges and scaling • Application of charges and tariff structures • Justification of charges and addressing outliers • Interconnected network and IDNO charging LUNCH 1pm 13 January 2011 3 | Energy Networks Association

  4. Agenda afternoon LUNCH 1pm – 1.30pm • Break Out Sessions • Output from Breakout Sessions • Next steps • Ofgem – Forthcoming process • Questions CLOSE 3pm 4 | Energy Networks Association

  5. EDCM workshop Objectives and key issues for the EDCM Geoffrey Randall 13 January 2011 13 January 2011 5 | Energy Networks Association

  6. Ofgem’s objectives for the EDCM 13 January 2011 6 | Energy Networks Association

  7. Key issues – demand and generation charging Determination of the revenue targets • Are the proposed methods appropriate? Method used for scaling residual revenue • Demand: 2 approaches are presented – site specific assets approach and voltage level average assets approach • Any new arguments in favour of one option would be particularly helpful • Generation: fixed adder approach • Is the proposed approach appropriate? 13 January 2011 7 | Energy Networks Association

  8. 13 January 2011 8 | Energy Networks Association

  9. Background and developments Harvey Jones CE Electric DCMF Chair 9 | Energy Networks Association

  10. Background 10 | Energy Networks Association

  11. Background 11 | Energy Networks Association

  12. Background At the last workshop we told you about: • EHV boundary change • Pre-2005 DG • Governance processes • The decision to delay Since then we have been working on: • Deciding the most appropriate scaling options for EDCM • Publishing the consultation (21/12/10) • The transfer into the licence of the EDCM amendments 12 | Energy Networks Association

  13. Decision to delay – a reminder • Ofgem concerned over customer impacts, the need to consult on new scaling options and changes to generation charges: • DNOs asked to “justify” charges • Ofgem consulted stakeholders • Published decision to extend deadline on 27 August • Ofgem made specific requests of DNOs: • Further stakeholder consultation • Amend the methodology to address comments • Amend the methodology following sense checks • Work closely with customers 13 January 2011 13 | Energy Networks Association

  14. The consultation We welcome responses to this consultation, including contributions and ideas on the proposals, in particular on: • Whether the proposed methodology meets the objectives of the EDCM; • The proposed approaches to demand and generation scaling; • The proposed approaches for sense checking final charges and addressing outliers; • Application of charges to in-year consumption; and • Our approach to justifying charges under the EDCM. The deadline for responses to the consultation is Tuesday 1 February 2011. 14 | Energy Networks Association

  15. Overview of the model Shankar Rajagopalan Reckon LLP (ENA/CMG consultant)

  16. Overview of the EDCM model • The model calculates charges for demand and generation tariffs according to the methodology set out in the December consultation • EDCM charges apply to sites covered by Ofgem’s definition of an EHV designated property • Separate import and export tariffs will apply in the case of mixed generation and demand sites • Final charges include elements derived from LRIC or FCP methodologies 13 January 2011 16 | Energy Networks Association

  17. Overview of the EDCM model EDCM charges include the following components: • A fixed charge (both demand and generation) • A capacity charge (both demand and generation) • Unit rate charges for consumption during the super red time band (demand only) • Excess reactive power unit rate charge (for demand and generation with some exceptions) • A unit rate credit for export by non-intermittent generation 13 January 2011 17 | Energy Networks Association

  18. Overview of the EDCM model Demand tariff components are made up of the following: • Marginal charges calculated using FCP or LRIC methodologies • Transmission exit charges • Excess reactive power charges • An allocation of DNO direct operating costs • An allocation of DNO indirect costs • An allocation of DNO business rates (network rates) • An allocation of the part of the DNO’s allowed revenue which has not been allocated as above (residual revenue) 13 January 2011 18 | Energy Networks Association

  19. Overview of the EDCM model Generation tariff components are made up of the following: • Marginal charges (or credits) calculated using FCP or LRIC methodologies • Excess reactive power charges • Transmission exit credits for qualifying generators • An allocation of DNO direct operating costs to sole use assets • An allocation of DNO business rates (network rates) to sole use assets • A generation scaling charge (may be positive or negative) 13 January 2011 19 | Energy Networks Association

  20. Summary of EDCM demand tariffs 13 January 2011 20 | Energy Networks Association

  21. Summary of generation tariffs 13 January 2011 21 | Energy Networks Association

  22. FCP/LRIC charges and Network Use Factors Mo Sukumaran SSE Power Networks 22 | Energy Networks Association

  23. Introduction Ofgem allowed DNOs to choose, develop and implement the EDCM methodology for EHV pricing based either on the: • FCP - Forward Cost Pricing model or • LRIC - Long Run Incremental Cost model 13 January 2011 23 | Energy Networks Association

  24. Introduction Network studies produce £/kVA/annum cost that is reflective of the cost of future reinforcement of the network on a locational basis: • on a ‘Network Group’ (i.e. zonal) basis under FCP • on a ‘Nodal’ basis under LRIC Charges are part of EDCM Demand and Generation tariffs 13 January 2011 24 | Energy Networks Association

  25. Overview of Methodologies 13 January 2011 25 | Energy Networks Association

  26. FCP Network group Analysis 13January 2011 26 | Energy Networks Association

  27. LRIC Nodal Analysis Base power flow 13January 2011 27 | Energy Networks Association

  28. LRIC Nodal Analysis Base power flow 13January 2011 28 | Energy Networks Association

  29. LRIC Nodal Analysis Base power flow 13 January 2011 29 | Energy Networks Association

  30. Improvements - LRIC • Revision of generation modelling in the ‘Minimum Demand’ scenario • generation coincidence within GSPs introduced • ‘Sense-checking’ of power flows derived from the application of security factors • power flows approximated for branches with ‘security factors’ greater than 6 • ‘Sense-checking’ of recovery of branch reinforcement costs • ‘recovery factors’ introduced for branches for which total cost recovery is greater than the annuitised reinforcement cost 13 January 2011 30 | Energy Networks Association

  31. Improvements - FCP • Increased testing of impact of generation across network • increased testing around perimeter of network group • tests conducted at the ‘source(s)’ and all exit points within each network group • ‘Sense-checking’ of ‘test size’ generators (TSGs) • ‘circuit’ and ‘substation’ TSGs introduced • thresholds introduced – 100MW at the 132kV voltage level and equivalents for other voltage levels 13 January 2011 31 | Energy Networks Association

  32. Application of Network Use Factors (NUFs) NUF shows the network usage by an EDCM customer in comparison to the notional average usage from CDCM’s 500MW Model NUF = 1 indicates that the value of assets used by the customer at that network level is equal to the average value of assets used at that level by all customers (EDCM and CDCM) NUF = 2 indicates that the value of assets used by the customer at that network level is equal to twice the average value of assets used at that level by all customers All else being equal, a customer with a NUF = 2 will have a shared asset-based cost allocation which is twice that of a customer with a NUF of 1 13 January 2011 32 | Energy Networks Association

  33. Application of Network Use Factors (NUFs) • Through power flow analysis, for each customer, we: • Identify notional assets ‘deemed’ to be used by the customer • Calculate the sum of annuitised notional asset MEAV (£) at each voltage level. • Identify the customer usage in kW at the exit point, and hence the £/kW/annum value at each voltage level. • Some NUFs can be significantly greater than 2 • Calculation of NUFs from the power flow model analysis 13 January 2011 33 | Energy Networks Association

  34. Transmission exit charges Excess reactive power charges Simon Yeo Western Power Distribution 13 January 2011 34 | Energy Networks Association

  35. Transmission Exit Charges Demand Tariffs will have a charge Two options under consideration • Option 1: Uniform p/kW/day converted to p/kVA/day using site specific kW/kVA relationship and applied as part of capacity charge • Option 2: Uniform p/kWh applied to consumption during super red time band (see appendix 4 of consultation for DNO time bands) Consultation Q4 seeks views 13 January 2011 35 | Energy Networks Association

  36. Transmission Exit Charges Generation Tariffs may have a credit To receive a credit • Generator must have agreement with DNO to provide P2/6 support during supergrid transformer (SGT) outage conditions Credit calculated using a uniform £/kVA/yr (forecast expenditure ÷ system max demand) Applied on same basis as Charge 1 credits • converted to p/kWh and applied to units exported • only applies to non-intermittent generation 13 January 2011 36 | Energy Networks Association

  37. Reactive Power Charges Demand and Generation Tariffs include a charge for excess reactive power Sites subject to Grid Code requirements exempt • ‘Large’ generators as defined (100MW E&W, 30MW SPT, 10MW SHETL and 10MW for all offshore • These sites are required to operate continuous voltage control which can lead to reactive power flows For all other tariffs • Single non-locational charge proposed • p/kVArh = 0.889 x EDCM demand revenue / EDCM kWh • 0.889 set on the basis of a single reactive power factor band • Charge applied to reactive power units that take customers power factor below 0.95 13 January 2011 37 | Energy Networks Association

  38. Demand scaling Shankar Rajagopalan Reckon LLP (ENA/CMG consultant) 13 January 2011 38 | Energy Networks Association

  39. What is demand scaling? • Each DNO has an allowed revenue that is set as part of Ofgem price controls • DNOs recover their allowed revenue from EDCM and CDCM customers through use of system charges • An EDCM demand revenue target is the result of a fair split of the allowed revenue. • Recovery from marginal charges and allocated costs from EDCM demand customers may not match the revenue target • Scaling charges make up the difference 13 January 2011 39 | Energy Networks Association

  40. Two alternative scaling methods • We are considering two alternative approaches to demand scaling: • The “site specific” assets approach • The “voltage level” average assets approach • Both approaches raise the same amount of revenue from the EDCM demand customer group 13 January 2011 40 | Energy Networks Association

  41. Two alternative scaling methods The approaches differ in the way some DNO costs and scaling charges are allocated to customers • The site specific approach uses customer-specific notional asset values derived using power flow analysis • The voltage level average approach uses average asset values at each network level derived from the 500 MW model 13 January 2011 41 | Energy Networks Association

  42. Methodology overview 13 January 2011 42 | Energy Networks Association

  43. Steps in demand scaling Both approaches to scaling share the following steps: Step 1: Calculate the contributions from each EDCM demand customer towards the EDCM demand revenue target. Step 2: Allocate cost-based elements of the target to individual customers Step 3: Calculate the scaling charge to individual customers. 13 January 2011 43 | Energy Networks Association

  44. Step 1: Customer contributions • The EDCM demand revenue target is the sum of the EDCM share of: • DNO direct operating costs, indirect costs and network rates • DNO allowed revenue minus the above • The EDCM shares above are calculated as the aggregates of each customer’s contributions. • Contributions from customers are driven by notional asset values (including sole use assets for direct costs and network rates). Notional assets are network assets that are deemed to be used by the customer • Notional asset values are determined using the CDCM 500 MW model and network use factors from power flow analysis 13 January 2011 44 | Energy Networks Association

  45. Step 2: Customer allocations (1) • Each EDCM demand customer is assigned an allocation of individual cost-based target elements: • Direct operating costs • Indirect costs • Network rates • The indirect cost target is allocated on the basis of a measure of customer capacity and peak-time demand • Calculated as the sum of 50 per cent of import capacity and 100 per cent of demand during the DNO super-red time band 13 January 2011 45 | Energy Networks Association

  46. Step 2: Customer allocations (2) • The direct operating cost and network rates targets are allocated to individual customers on the basis of network assets used • The site specific approach uses site specific notional asset values to allocate these elements • The voltage level approach uses voltage level average asset values to allocate these elements • Sole use asset values are added to shared network asset values in both approaches 13 January 2011 46 | Energy Networks Association

  47. Step 3: Calculating the scaling charge (1) • A residual scaling target is calculated as the EDCM demand revenue target: • Minus the cost-based target elements relating to direct costs, indirect costs and network rates • Minus the forecast recovery from the application of FCP/LRIC charges to EDCM demand • Plus the cost of EDCM generation credits based on FCP/LRIC • In other words, the residual scaling target is set so that the total recovery from different charge elements is equal to the EDCM revenue target • The residual scaling target could be positive or negative 13 January 2011 47 | Energy Networks Association

  48. Step 3: Calculating the scaling charge • The residual scaling target is split into two • 80 per cent of the scaling target is allocated to individual customers on the basis of network assets used • The site specific approach uses site specific notional asset values to allocate the residual scaling target • The voltage level approach uses voltage level average asset values to allocate the residual scaling target • Sole use assets are not taken into account in either approach • 20 per cent of the scaling target is allocated to individual customers on the basis of their import capacity and peak-time demand (like the indirect cost target element) 13 January 2011 48 | Energy Networks Association

  49. Stylised example of demand scaling • Simplified example to illustrate the scaling approaches • Ignore sole use assets, generation charges or credits • DNO allowed revenue - £20 million • Direct operating costs - £3 million • Indirect costs - £4 million • Network rates - £3 million • Residual revenue - £10 million (Allowed revenue – costs) • Total network assets based on the CDCM 500 MW model - £200 million • £180 million assets used by CDCM customers 13 January 2011 49 | Energy Networks Association

  50. Customer information 13 January 2011 50 | Energy Networks Association

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