1. EDCM Development Workshop Welcome 1 | Energy Networks Association 13 January 2011

2. Introduction Andrew Neves Central Networks CMG Chair 2 | Energy Networks Association 13 January 2011

3. Agenda morning 3 | Energy Networks Association START10am 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 LUNCH1pm 13 January 2011

4. Agenda afternoon 4 | Energy Networks Association LUNCH 1pm – 1.30pm Break Out Sessions Output from Breakout Sessions Next steps Ofgem – Forthcoming process Questions CLOSE3pm 13 January 2011

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

6. Ofgem’s objectives for the EDCM What we have now What we want Why is this important? EfficiencySustainable development Competition Methodologies largely untouched for decades Revised cost reflective charging model - Efficient investment and use of existing assets will contribute to lower system charges and help fuel poverty - Facilitate the development of DG - Compliment smart metering roll out - Incentivise Demand Side Management - Facilitate IDNO competition by creating consistent IDNO charging framework Variety of methodologies across 14 DNOs Common charging methodology - Reduced administrative costs and charging risk premium - Lower barriers to new generation entrants - Lower barriers for new supply market entrants Pace of change dictated by DNOs Deadline (Submit April 2011, implement April 2012) - Cost reflective charges could reduce capex requirements - Measures to tackle climate change required as a matter of urgency - Development of IDNO market has been slow relative to IGT market Change depends on DNO modification proposals Common governance & non-DNO access - Consumers and suppliers will be able to propose efficient changes to DNO methodologies - Necessary to ensure methods are responsive to major changes anticipated on distribution networks - Ensures DNOs are accountable to needs of generation and supply markets 6 | Energy Networks Association 13 January 2011

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? 7 | Energy Networks Association 13 January 2011

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9. Background and developments Harvey Jones CE Electric DCMF Chair 9 | Energy Networks Association 13 January 2011

10. Background DateAction 1 October 2008 Ofgem publishes proposals for Common EHV Charging Methodology based on LRIC. SPEN and SSEPD raised statutory objections to the licence conditions mandating the LRIC method in these proposals. 20 March 2009 Ofgem decided not to refer to the Competition Commission, and came back with proposals for a choice between LRIC and FCP methods 1 July 2009 Licence conditions creating obligations on DNOs to develop and implement the common distribution charging methodology (CDCM), based on the HV/LV part of the October 2008 proposals, came into force. 31 July 2009 Ofgem proposed principles for the FCP/LRIC approaches and a set of licence conditions to mandate their development and implementation. There was no objection from DNOs to these proposals. 28 August 2009 DNOs published proposals for the CDCM. Ofgem accepted these proposals after relevant conditions had been met by DNOs in December 2009. The CDCM came into force on 1 April 2010. 1 October 2009 Licence conditions creating obligations on DNOs to develop and implement the EHV distribution charging methodologies (EDCM), based on FCP or LRIC as specified in the 31 July 2009 document, came into force. These conditions required DNOs to come forward with proposals for the EDCM by 1 September 2010 for implementation by 1 April 2011. 10 | Energy Networks Association 13 January 2011

11. Background DateAction 23 April 2010 DNOs published a consultation on options for the allocation of customers between the EDCM and CDCM methodologies (the EDCM/CDCM boundary). Responses were received from all DNOs and from three other stakeholders. Also published a summary of responses on 26 May 2010, available from http://2010.energynetworks.org/structure-of-charges-edcm/http://2010.energynetworks.org/structure-of-charges-edcm/ 15 June 2010 Ofgem issued a consultation document on the boundary between the EDCM/CDCM which seeks industry views on the options for defining the boundary to be used to determine whether customers should be subject to the EDCM or the CDCM. 25 August 2010 Ofgem modified the distribution licence to change the EDCM/CDCM boundary. 27 August 2010 Ofgem published a letter to the DNOs derogating the DNOs from the requirement to submit the EDCM methodology and illustrative tariffs on 1 September 2010. 1 September 2010 Publication of information about developments to the proposals since June 2010. 11 | Energy Networks Association 13 January 2011

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 January 2011

13. Decision to delay – a reminder 13 January 2011 13 | Energy Networks Association 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

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) 15 | Energy Networks Association 13 January 2011

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 Tariff componentUnitCorrespondence to tariff elements Fixed chargep/daySole use asset charges for direct operating costs and network rates Import capacity charge p/kVA/dayLocal element of FCP/LRIC charge 1, direct operating costs, indirect costs, network rates, demand scaling charge and possibly the transmission exit charge (Consultation Q4) Super-red unit ratep/kWhRemote element of FCP/LRIC charge and possibly the transmission exit charge (See Q4) Excess reactive power charge p/kVArhAverage charge based on DNO revenue per unit distributed.

21. Summary of generation tariffs 13 January 2011 21 | Energy Networks Association Tariff componentUnitCorrespondence to tariff elements Fixed chargep/daySole use asset charges for direct operating costs and network rates Export capacity charge p/kVA/dayBoth elements of FCP/LRIC charge 2 and the generation scaling fixed adder Generation creditp/kWhBoth elements of FCP/LRIC charge 1 for non-intermittent generation only Excess reactive power charge p/kVArhAverage charge based on DNO revenue per unit distributed. This would not apply to generation subject to grid code requirements (on the corresponding import tariff as well)

22. FCP/LRIC charges and Network Use Factors Mo Sukumaran SSE Power Networks 22 | Energy Networks Association 13 January 2011

23. Introduction 13 January 2011 23 | Energy Networks Association 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

24. Introduction 13 January 2011 24 | Energy Networks Association 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

25. Overview of Methodologies Long Run Incremental Cost Pricing (LRIC) Forward Cost Pricing (FCP) Price granularityNodeNetwork group Analysis periodInfinite10 years Network security standards Load: N-1 Generation: N-1 Load: N-1, limited N-2 scenarios Generation: N-1 Reinforcement requirements Change in NPV of reinforcements due to 0.1MW increment Cost of reinforcements in 10-yr period Network load growth Fixed at 1% across entire network Calculated for each substation from LTDS data Load analysis Assessment of impact of a 0.1MW increase in load at each node Sequential year-on-year modelling using expected substation loads Generation analysis Assessment of impact of a 0.1MW increase in generation at each node Probabilistic approach based on expected generation connections 13 January 2011 25 | Energy Networks Association

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

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

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

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

30. Improvements - LRIC 13 January 2011 30 | Energy Networks Association 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

31. Improvements - FCP 13 January 2011 31 | Energy Networks Association 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

32. Application of Network Use Factors (NUFs) 32 | Energy Networks Association 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

33. Application of Network Use Factors (NUFs) 33 | Energy Networks Association 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 VoltageEDCM User site specific cost CDCM User average cost NUFs 132kV£5/kW£10/kW0.5 132/33kV£40/kW£20/kW2

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

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) 38 | Energy Networks Association 13 January 2011

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 Customer132 kV customer33 kV customer 133 kV customer 2 Capacity50,000 kVA10,000 kVA40,000 kVA LRIC/FCP charge£2/kVA/year£10/kVA/year£5/kVA/year Avg 500MW assets at 132 kV £5 million£1 million£4 million Avg 500MW assets at 33 kV Not used£2 million£8 million Network use factors at 132 kV 0.411 Network use factors at 33 kV -0.52 Notional assets at 132 kV £2 million£1 million£4 million Notional assets at 33 kV Not used£1 million£16 million

51. Demand revenue target The EDCM demand revenue target is built up on the basis of notional assets EDCM notional assets are £24 million out of a DNO total of £200 million (12 per cent) EDCM demand revenue target is £2.4 million (12 per cent of allowed revenue), of which –Direct operating cost element is £360,000 –Indirect cost element is £480,000 –Network rates element is £360,000 –Residual revenue element is £1.2 million 13 January 2011 51 | Energy Networks Association

52. The scaling target The scaling target is the difference between the EDCM demand revenue target and the forecast recovery from other charges –The forecast recovery from the LRIC/FCP charge is £400,000 –The forecast recovery from direct operating costs, indirect costs and network rate allocations £1.2 million –The scaling target is therefore £800,000 (£2.4 million – £1.2 million - £400k) 13 January 2011 52 | Energy Networks Association

53. Allocation to customers The elements to be allocated to customers: –Direct operating cost element is £360,000 –Indirect cost element is £480,000 –Network rates element is £360,000 –Scaling element is £800,000 Indirect cost element and 20 per cent of the scaling element are allocated on the basis of capacity and demand during super-red time bands The other elements are allocated on the basis of assets –Voltage level average assets or site specific assets 13 January 2011 53 | Energy Networks Association

54. Voltage level assets approach 13 January 2011 54 | Energy Networks Association Customer132 kV customer33 kV customer 133 kV customer 2 Capacity50,000 kVA10,000 kVA40,000 kVA LRIC/FCP charge£100,000 £200,000 Avg 500MW assets at 132 kV £5 million£1 million£4 million Avg 500MW assets at 33 kV Not used£2 million£8 million Direct cost and network rates alloc £180,000£108,000£432,000 Indirect cost alloc£240,000£48,000£192,000 80 per cent residual£160,000£96,000£384,000 20 per cent residual£80,000£16,000£64,000 Total charges£760,000£368,000£1,272,000

55. Site specific assets approach 13 January 2011 55 | Energy Networks Association Customer132 kV customer33 kV customer 133 kV customer 2 Capacity50,000 kVA10,000 kVA40,000 kVA LRIC/FCP charge£100,000 £200,000 Notional assets at 132 kV £2 million£1 million£4 million Notional assets at 33 kV Not used£1 million£16 million Direct cost and network rates alloc £60,000 £600,000 Indirect cost alloc£240,000£48,000£192,000 80 per cent residual£53,333 £533,333 20 per cent residual£80,000£16,000£64,000 Total£533,333£277,333£1,589,333

56. Summary 13 January 2011 56 | Energy Networks Association Customer132 kV customer33 kV customer 133 kV customer 2 Capacity50,000 kVA10,000 kVA40,000 kVA LRIC/FCP charge£100,000 £200,000 Avg DRM assets at 132 kV £5 million£1 million£4 million Avg DRM assets at 33 kV Not used£2 million£8 million NUF at 132 kV0.411 NUF at 33 kV-0.52 Final charge under the voltage level approach £760,000£368,000£1,272,000 Final charge under the site specific approach £533,333£277,333£1,589,333

57. Comparison of scaling approaches Demand scaling should achieve two objectives –It should preserve the forward-looking signals from the FCP and LRIC charges –It must not lead to final charges that are materially different from a fair allocation of their forward looking business costs Both approaches would recover the same total amount of revenue from EDCM demand customers as a whole Charges for individual customers would be different –Differences are driven by the choice of asset values – site specific or voltage level averages 13 January 2011 57 | Energy Networks Association

58. Comparison of scaling approaches The voltage level average approach is better at preserving signals from FCP or LRIC –Under the voltage level approach, final charges to customers with the same capacity, demand patterns, sole use assets and uses the same network levels would differ only by their FCP or LRIC charges –The site specific approach additionally require the customers to use the same value of shared network assets The site specific approach produces final charges that represent a fairer allocation of DNO costs –NUFs allow a finer differentiation in the value of assets used by customers –Only if asset value is a fair allocation driver for DNO costs 13 January 2011 58 | Energy Networks Association

59. EDCM demand revenue 13 January 2011 59 | Energy Networks Association

60. EDCM demand revenue 13 January 2011 60 | Energy Networks Association

61. EDCM demand revenue 13 January 2011 61 | Energy Networks Association

62. Sole Use Assets Andy Pace Electricity North West 13 January 2011 62 | Energy Networks Association

63. Sole Use Assets – Definition (1) Sole Use Assets (SUA): Sole Use Assets are assets in which only the consumption or output associated with a single customer can directly alter the power flow in the asset, taking into consideration all possible credible running arrangements i.e. all assets between the customer's Entry/ Exit Point(s) and the Point(s) of Common Coupling with the general network are considered as sole use assets. 13 January 2011 63 | Energy Networks Association

64. Sole Use Assets – Definition (2) Point of Common Coupling: The Point of Common Coupling for a particular single customer is the point on the network where the power flow associated with the single customer under consideration, may under some (or all) possible arrangements interact with the power flows associated with other customers, taking into account all possible credible running arrangements. 13 January 2011 64 | Energy Networks Association

65. Sole Use Assets – Example (1) 13 January 2011 65 | Energy Networks Association

66. Sole Use Assets – Example (2) 13 January 2011 66 | Energy Networks Association

67. Sole Use Assets – Charges (1) SUA Charges applied are: –SUA MEAV (£) * Direct Operating Costs charging rate (%) –SUA MEAV (£) * Network Rates charging rate (%) Direct Operating Cost charging rate is calculated as total direct costs divided by total assets, and applying EHV operating expenditure intensity factor (68%) Network Rates charging rate is calculated as total Network Rates divided by total assets 13 January 2011 67 | Energy Networks Association

68. Sole Use Assets – Charges (2) 13 January 2011 68 | Energy Networks Association Previous Consultation – SUA charge was allocated to the import tariff Current Consultation – SUA allocated between the import and export tariffs proportionally to import and export capacity EDCM charges relating to sole use assets will be charged as a fixed p/day charge to both import and export tariffs. The charging rates are applied equally to sole use assets attributed to demand and generation tariffs.

69. Sole Use Assets – Charges (3) Application of demand scaling to SUA Charge: Demand scaling is not applied to the sole use asset charge in the consultation. DNOs considered applying a proportion of demand scaling to take account of replacement. Applying demand scaling means SUA would attract an allocation of residual revenue to the total EDCM revenue target Demand scaling is not applied as sole use assets tend to be fully contributed and are not always replaced. This position may change depending on consultation responses. 13 January 2011 69 | Energy Networks Association

70. Generation charges and scaling Oliver Day UK Power Networks 70 | Energy Networks Association 13 January 2011

71. Generation Charges 71 | Energy Networks Association Generation charges reflect both the costs and benefits provided by users exporting energy onto the network Costs are based on –Marginal charges from LRIC/FCP –Element relating to direct operating costs (sole use assets only) –Element relating to business rates (sole use assets only) –Scaling – maybe positive or negative Benefits are based on –Marginal charges from LRIC/FCP –Transmission exit 13 January 2011

72. Generation Tariffs 72 | Energy Networks Association Generation tariffs comprise the following elements: Fixed Charge –Reflects a proportion of sole use asset charge for direct operating costs and business rates –Proportion based on split of import agreed capacity and export agreed capacity Export Capacity Charge –Reflects both the local and remote LRIC/FCP charge 2 and the generation fixed adder Generation Credit –Reflects both the local and remote LRIC/FCP charge 1 Excess reactive charge –Reflects the average revenue per unit in the EDCM 13 January 2011

73. Generation Charge Rationale 73 | Energy Networks Association Generation users could trigger generation caused reinforcement during minimum demand conditions Some generation users could offset need for demand caused reinforcement during maximum demand conditions Generators do not meet other network costs – reflecting the view that the prime driver for the network is demand users Generation charges are scaled to meet a generation target revenue Generation credits are not scaled 13 January 2011

74. Generation Scaling 74 | Energy Networks Association Generation scaling is the process of matching generation charges to a generation target revenue Generation scaling is entirely separate from demand scaling Any shortfall or excess in meeting the revenue target will be adjusted using a single fixed adder to export capacity charges 13 January 2011

75. Generation Target Revenue 75 | Energy Networks Association The generation target revenue for the EDCM represents an estimate of the DNO expenditure caused by EDCM generation users The target revenue is based on the actual distributed incentive revenue for post 2005 generators and a notional distributed generation revenue for pre 2005 generators This target revenue excludes the revenue that would be attributed to CDCM generation 13 January 2011

76. Tariff Structures Pat Wormald CE Electric 76 | Energy Networks Association 13 January 2011

77. Tariff Structures 77 | Energy Networks Association 13 January 2011 The following tariff components are calculated within the EDCM: Tariff ComponentDemandGeneration Fixed chargeYes Capacity chargeYes Unit rate chargeYes – at the time of DNOs peak (super-red time period only) Yes for credits – all year round Excess reactive power charge Yes (with the exception of sites subject to grid code requirements) Under the EDCM, separate import (demand) and export (generation) tariffs will apply whenever metering allows for data about power flows in both directions to be recorded in settlements.

78. Demand Tariffs 78 | Energy Networks Association Marginal charges calculated using the FCP or LRIC methodologies; Transmission connection (exit) charges; An element relating to the direct operating costs of the DNO; An element relating to the indirect operating costs of the DNO; An element relating to the business rates (network rates) payable by the DNO; and An element relating to the part of the DNO’s allowed revenue that has not been charged using the cost-based charges above. 13 January 2011 Demand tariffs include the following elements which are calculated within the EDCM:

79. Tariff Components - Demand 79 | Energy Networks Association 13 January 2011 Tariff Component UnitCorrespondence to tariff elements Fixed chargep/daySole use asset charges for direct operating costs and network rates. Import capacity charge* p/kVA/dayReflects the local element of the FCP/LRIC charge 1, pre-allocation of direct operating costs, indirect costs, network rates and the demand scaling charge. Super-red unit rate* p/kWhReflects the remote element of the FCP/LRIC charge 1. Excess reactive power charge p/kVArhReflects average revenue per unit in the EDCM. Would not apply to sites subject to grid code requirements for generation. Application of tariff components for demand tariffs * May also include the transmission exit charge – (Consultation Q4)

80. Export Tariffs 80 | Energy Networks Association Marginal charges calculated using the FCP or LRIC methodologies; Credits based on FCP or LRIC methodologies; Transmission connection (exit) credits; An element relating to the direct operating costs of the DNO (for sole use assets only); An element relating to the business rates (network rates) payable by the DNO (for sole use assets only); and An element relating to generation scaling (this may be positive or negative). 13 January 2011 Export tariffs include the following elements which are calculated within the EDCM:

81. Tariff Components - Export 81 | Energy Networks Association 13 January 2011 Tariff Component UnitCorrespondence to tariff elements Fixed chargep/dayReflects sole use asset charges for direct operating costs and network rates. Export capacity charge p/kVA/dayReflects both local and remote element of the FCP/LRIC charge 2 and the generation scaling fixed adder. Generation credit p/kWh (negative) Reflects both the local and remote element of the FCP/LRIC charge 1 (and any transmission exit credit). Excess reactive power charge p/kVArhReflects average revenue per unit in the EDCM. Would not apply to sites subject to grid code requirements for generation. Application of tariff components for export tariffs

82. Tariff Structures 82 | Energy Networks Association 13 January 2011 Following feedback from the workshops and earlier consultations we have taken on board the need for customers to influence the level of their charges within the charging year. We therefore propose to implement unit charges and reactive power charges for demand, which will reflect the remote element of the FCP/LRIC charge 1. This was previously included as part of the capacity charge. One of the questions we are asking in the consultation is whether or not we should also include transmission exit charges as a unit charge rather than as currently proposed as a capacity charge. Most DNOs support the capacity charge option as this is a fixed cost to DNOs – however we welcome your views.

83. Justification of charges and addressing outliers Nigel Turvey Western Power Distribution 83 | Energy Networks Association 13 January 2011

84. Justification of charges (1) 84 | Energy Networks Association 13 January 2011 Derogation to delay the submission deadline included the following requirement on each DNO * : “To make changes to the methodology as required following sense checks, to ensure they are able to justify the level of charges – particularly where charges are moving significantly (either up or down) from current levels” * In a letter to DNOs on 27 Aug 2010

85. Justification of charges (2) 85 | Energy Networks Association 13 January 2011 Several licence conditions are of relevance to justifying charges: SLC 19.1 - The licensee must not discriminate between any person or class or classes of persons: –(a) in providing Use of System; …. 13B.8 - The second Relevant Objective is that compliance with the EDCM facilitates competition in the generation and supply of electricity and will not restrict, distort, or prevent competition in the transmission or distribution of electricity or in participation in the operation of an Interconnector. 13B.9 - The third Relevant Objective is that compliance with the EDCM results in charges which, so far as is reasonably practicable after taking account of implementation costs, reflect the costs incurred, or reasonably expected to be incurred, by the licensee in its Distribution Business. In addition, 50A.12 by referring to the original Ofgem specification requires a fixed adder to be used

86. Justification of charges (3) 86 | Energy Networks Association 13 January 2011 We believe that: calculating the amount of total required revenue that should be allocated to EDCM demand customers by assessing their usage of assets at the time of system peak, is a fair way to allocate required revenue Both proposed methods of scaling residual revenue after allocating marginal costs, operating cost etc, have some risk of producing non-cost reflective charges

87. Outliers 87 | Energy Networks Association 13 January 2011 Outliers with potentially non cost reflective charges can occur for several reasons including: –The customer’s characteristics are significantly different from the ‘average’ on the network. e.g. a customer with a large capacity who only uses a short part of the network may face large and potentially unjustifiable charges under the voltage level scaling approach –The power flow analysis could indicate usage of network assets that may not be strictly necessary to supply that customer if the network were designed from scratch. In such cases the site specific approach may result in charges that cannot be justified Consideration is being given to whether these issues can be addressed by ‘capping’ parts of the charges.

88. Outliers – Potential Solutions 88 | Energy Networks Association 13 January 2011 Potential solutions are: For the voltage level scaling approach –the ’80% of residual’ scaling element could be capped to an annuity on the value of site specific network assets used by the customer – this would improve the situation for customers using significantly less network than the average –As the site specific network assets are calculated at the time of peak demand, it may be appropriate to scale these site specific network assets to the agreed capacity of the customer to account for those with low demands at the time of system peak For the site specific scaling approach –the network use factors could be capped to a specific value e.g. set at 85 th percentile – this would improve the situation for customers that would use significantly less network if it were being designed from scratch

89. Justification of charges summary 89 | Energy Networks Association 13 January 2011 Resulting charges need to be justified After many options of scaling have been assessed it appears unlikely that there is one that produces justifiable charges in all circumstances Some form of capping to part of the charges may be necessary to address these outliers Ultimately, each DNO will have to satisfy itself that it is complying with the Licence

90. Interconnected Network Charging Alan Stewart SP Energy Networks 90 | Energy Networks Association 13 January 2011

91. Interconnected Network Charging (1) 91 | Energy Networks Association DNO to DNO interconnections –Normally Closed (Active), benefitting one DNO only, will be treated as EDCM user. –Closed, identifiable benefit to both DNOs, each DNO treats other as EDCM user. –Open (To provide backup), Special arrangements agreed, UOS charges agreed outwith EDCM –All Other, DNO charges other DNO as EDCM user 13 January 2011

92. Interconnected Network Charging (2) 92 | Energy Networks Association Offshore Network Charging –EDCM DNO to Unlicensed Networks, either –Part of Total System under BSC, can be treated as LDNOs –Or, EDCM to calculate import & export at boundary DNO to nested Networks –Dependant upon DCUSA modifications –Development by IDNO/DNO Enduring Billing Group 13 January 2011

93. IDNO Charging (1) 93 | Energy Networks Association LDNO Charging - CDCM –Portfolio tariffs for end users within CDCM Method M used to calculate discount percentages for LV, LVS & HV end users 33kV Boundary, 33kV s/stn Boundary & 132kV Boundary (E&W only) 2 Part charging process –Separate percentages for Operating Costs, Dep’n & RAV elements (Excl Transmission exit charges) –Split percentages for EHV network for EDCM asset levels Discount Calculated as ratio of network level provided by LDNO to sum of percentages for all network that would be provided by DNO –Generation End Users Treated similar to Demand Users 13 January 2011

94. IDNO Charging (2) 94 | Energy Networks Association LDNO Charging – EDCM –Portfolio tariffs for end users within EDCM Apply FCP/LRIC to calculate portfolio EDCM charge / credit Calculated as if EDCM end user notionally connected at boundary between DNO & LDNO Attract charges (credits) for reinforcement Caused (avoided) No charge for Sole use assets on LDNO network Charges for Sole use assets of an embedded DNO will be charged proportionally Demand Scaling to be applied as normal to EDCM user –Generation scaling applied as normal to generators connected to LDNO’s network 13 January 2011

95. IDNO Charging (3) 95 | Energy Networks Association LDNO Charging (Cont’d) –Future Developments Write a Current User manual for Model M Update Model M to create fully integrated model to incorporate CDCM and latest EDCM proposals Provide new CDCM User Manual following consultation responses Submit to DCUSA / in line with Open Governance 13 January 2011

96. Any Questions? 96 | Energy Networks Association 13 January 2011

97. Lunch Restart at 1.30pm 97 | Energy Networks Association 13 January 2011

98. Breakout sessions Breakout sessions: Pink, Green or Ice blue rooms 1:30 – 2:15 98 | Energy Networks Association 13 January 2011

99. Breakout groups 99 | Energy Networks Association 13 January 2011 Group AMoGroup BAndrewGroup CHarvey ICE BLUE ROOMGREEN ROOMPINK ROOM Andrew PaceAndrew NevesAlan Stewart Andy ManningBen NicaudieChristopher Granby Christine PearsonBrian Harris-RossClaire Campbell Colin PrestwichChris GoodwinConor Martin David SpeakeDominique TilquinCraig Handford Franck LatremoliereGeoffrey RandallDiana Kennedy Gary HolmesGlenn SheernGarth Graham Glyn LentonGraham RossGraeme Cooper Guy DonaldJamie PaulGrant Elder Julia HaugheyJohn ColeJane Griffiths Karl MaryonMark HedgesHarvey Jones Michael DoddPat WormaldHui Yi Heng Mo SukumaranPippa StirlingIan Walker Peter BarryShankar RajagopalanMatt McDermot Scott FrancisSimon RussellMike Harding Stephen BoothSimon VicaryNigel Turvey Steve MatthewsSimon YeoOliver Day Stephen AndrewsRekha Theaker Wasif AnwarYnon Gablinger Chenghong Gu

100. Breakout sessions feedback Feedback from breakout sessions: Group A Group B Group C 100 | Energy Networks Association 13 January 2011

101. EDCM workshop Stakeholder involvement and next steps Geoffrey Randall 13 January 2011 101 | Energy Networks Association 13 January 2011

102. How you can get involved It is important to engage with industry now and not wait until Ofgem consults on the submission. There are a number of ways to do this: Respond to the DNOs’ consultation Individual DNO workshops / talk to relevant DNO(s) Work streams B (EDCM model) and C (volatility/transparency) DCMF – discussion forum every 2 months, next meeting 15 February ENA site http://energynetworks.squarespace.com/structure-of-charges-edcm/http://energynetworks.squarespace.com/structure-of-charges-edcm/ If you have any further queries over the methodology please contact your DNO. If you require further assistance you can contact Ofgem at distributionpolicy@ofgem.gov.uk distributionpolicy@ofgem.gov.uk 102 | Energy Networks Association 13 January 2011

103. Next steps The key dates are: Consultation responses by 1 February 2011 DNOs’ EDCM submission to Ofgem 1 April 2011 Ofgem’s consultation ~ May 2011 Ofgem’s decision by end August 2011 EDCM implementation 1 April 2012 103 | Energy Networks Association 13 January 2011

104. 104 | Energy Networks Association 13 January 2011

105. Next steps 105 | Energy Networks Association Andrew Neves Central Networks 13 January 2011

106. Next steps Any Questions? 106 | Energy Networks Association 13 January 2011

107. EDCM Development Workshop Thank you! 107 | Energy Networks Association 13 January 2011