SSE Power Distribution EDCM Stakeholder Workshop 13 July 2010 Concert Hall, Perth

1. SSE Power Distribution EDCM Stakeholder Workshop 13 July 2010 Concert Hall, Perth

2. Introduction Safety briefing Today’s Agenda Mo Sukumaran

3. 10:15 Tea and Coffee 10:30 Introduction 10:40 Overview of the EDCM 11:00 EDCM/CDCM boundary 11:10 Pre 2005 EHV Generators 11:40 Review of power flow modelling 12:00 Lunch 12:40 Review of EDCM charging model 13:30 Price impact on customers 14:00 Questions & answers 14:30 Next steps & close Agenda

4. Overview of Extra High Voltage Distribution Charging Methodology (EDCM) Mo Sukumaran

5. DNO’s choice between two common EHV Distribution Charging Methodologies (EDCM), FCP and LRIC Applied to EHV customers and to HV customers currently on site-specific tariffs, subject to any change of the EDCM/CDCM boundary Uses FCP or LRIC charges based on estimated future reinforcements at different locations on the distribution network Locational prices Subject to DCUSA open governance arrangements Overview of EDCM

6. Oct 2008 - Ofgem proposes to introduce CDCM for HV & LV and LRIC for EHV; SP and SSE rejected this Jul 2009 - CDCM licence conditions come into force Sep 2009 - New EDCM licence condition allows DNOs to choose between LRIC or FCP for EHV charging methodology - DNOs jointly commence developing the two EDCM methodologies through the ENA Apr 2010 - DNOs implemented CDCM for HV & LV Jun 2010 - DNO and Ofgem consultation on charging boundary between EDCM and CDCM Jun 2010 - DNOs consult on EDCM charging methodology Aug 2010 - DNOs to submit EDCM charging methodology Apr 2011 - DNOs to implement EDCM subject to Ofgem approval Overview of EDCM

7. Overview of EDCM – Overall Process

8. Overview of EDCM – IDNO

9. Overview of EDCM/CDCM Boundary David Mobsby

10. CDCM applies to designated properties supplied at less than 22 kV, except those currently under site-specific arrangements If the licence is not changed, EDCM will apply to all designated properties at 22 kV or above (class A), and to all HV customers currently under site-specific arrangements (class B) Current EDCM/CDCM boundary

11. Classification of Customers Class A: Customers connected at 22kV or more Class B: Customers at less than 22kV but on site specific charges B1: 132kV/11kV substation B2: 33kV/11kV substation B3: Other HV site-specific customers (e.g. meter outside substation) Class C: HV Customers currently on CDCM tariffs C1: 132kV/11kV substation C2: 33kV/11kV substation C3: All other HV CDCM customers Classification of customers

12. Boundary Classes >=22kV >=66kV <66kV <22kV >=22kV <22kV <22kV Currently site specific Class A Class B3 Class B1 Class B2 Currently CDCM Class C3 Class C1 Class C2 EHV HV Classification of customers

13. Boundary Options Option NC – No Change Option RB – Raised Boundary Option LB – Lowered Boundary Option ORB – Optional Raised Boundary ENA Boundary Consultation

14. Responses to DNO Boundary Consultation 5 DNOs supported Raised Boundary (RB) 1 DNO supported Lower Boundary (LB) 1 DNO suggested new criteria (dedicated substation or greater than 10 MVA) 1 Customer – No Change 2 Customer – Optional Raised Boundary plus: Optional Lowered Boundary Transitional Relief ENA Boundary Consultation

15. Ofgem issued consultation on 15 June 2010 which closes on 13 July 2010 Three additional options:- “No Change 2 (NC2)”. This moves all 132/11 customers to EDCM. “Lowered Boundary 2 (LB2)”. Hybrid of NC2 and RB. This moves all 132/11 customers to the EDCM (like NC2) and moves all 33/11 customers to the CDCM (like RB). Authorised capacity / other hybrid approaches. Implementing any boundary change affects prices for all EDCM customers (and to a lesser extent CDCM customers) DNO’s EDCM proposals in August 2010 will reflect the boundary in the licence at that time Ofgem Consultation

16. Pre April 2005 EHV Generators Angus Rae

17. DPCR5 removed the exemption on pre April 2005 DG from paying export use of system charges Review of the contractual position of these generators is ongoing Different treatment of pre and post April 2005 DG and ‘undue discrimination’ needs to be considered EHV / EDCM Distributed Generation

18. 2010/11 EHV Generation Use of System (“GDUoS”) Charges Initial (April 2010) Position: GDUoS only applied to post 2005 EHV DG pending “industry-wide collaboration” on implementation for pre 2005 Collaboration failed to find an agreed solution Ofgem have asked DNOs to propose interim arrangements to comply with Licence obligations for remainder of 2010/11 SSE Power Distribution submitted a Charging Methodology Modification Proposal to Ofgem on 25th June EHV / EDCM Distributed Generation

19. SSE Power Distribution Modification Proposal From 1 October 2010 to 31 March 2011, GDUoS charges would apply to all EHV DG Discounted GDUoS rate would apply to pre 2005 DG where capitalised O&M was paid at connection (or believed paid) Standard GDUoS rate would apply to pre 2005 DG where either capitalised O&M was not paid or the O&M period has expired Proposed SHEPD discounted EHV GDUoS rate is 6.9 p/kVA/month Proposed SHEPD standard EHV GDUoS rate is 10.4 p/kVA/month If contracts exclude GDUoS charges, variation processes will be implemented EHV / EDCM Distributed Generation

20. Interim Modification Proposals Await Ofgem’s decision – veto or non-veto ? If non-veto, amended methodology takes effect from 1 October 2010 Continued development of EDCM charging proposals for EHV DG (particularly pre April 2005 EHV DG) Ofgem’s input crucial in developing final EDCM proposals EHV / EDCM Distributed GenerationNext Steps

21. Power flow modelling David Mobsby

22. EDCM Process Overview Network Data Load/Gen Data Cost Data Network Charging Models: FCP or LRIC Powerflow Modelling • Locational Tariffs in £/kVA/annum • FCP: Zonal Charges by Network Group • LRIC: Nodal Marginal Charges CDCM Results Sole Use Assets EDCM model (including demand scaling) EDCM Spreadsheet Model Transmission Exit Allowed Revenue Final EDCM Tariffs

23. Ofgem allowed DNOs to choose and develop the EDCM methodology for EHV pricing based either on the: FCP - Forward Cost Pricing model or LRIC - Long Run Incremental Cost model EDCM Methodologies

24. SSE along with Central Networks and Scottish Power (G3) developed the original FCP The EDCM common FCP is an improved version of the original FCP Both FCP and LRIC are still under development by Workstream A under the ENA ENW and WPD are also considering FCP EDCM Methodologies 2

25. aim to 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 What do the methodologies aim to do?

26. FCP Rationale • Aims to produce a charge relative to the reinforcements identified over a 10 year period starting from the charging year being considered. • Closely follows the planning process (ER P2/6) highlighting reinforcements that would be expected in the real world, resulting in a cost reflective model.

27. The model uses publicly available data - LTDS Charges are calculated by Network Group which create a hierarchical system for charging. If no reinforcements are found in a Network Group then the charge is zero for that group - another cost reflective feature. FCP Rationale 2

28. Network Groups

29. Network Group Information

30. Both Load and Generation charges are calculated using a network model, the Authorised Network Model, which remains static over the 10 years. The demands (load and generation) in the model are changed depending on the test being carried out. FCP can consider up to 3 demand sets, Maximum Demand, Minimum Demand and Maintenance Demand. Powerflow Analysis – Inputs

31. Maximum Demand Data – Considers the network with maximum loads and minimum generation*. Minimum Demand Data – Considers the network with minimum loads and maximum generation. Maintenance Demand Data – Considers the network with Maximum Demand loads scaled to a minimum of 67% and minimum generation*. * = the level of generation under ER P2/6 that can be relied upon to provide security of supply support (as described by the use of ‘F’ factors). Powerflow Analysis – Inputs

32. All loads in the model are based on LTDS data with an allowance for diversity. Reflecting locational growth rates All generation outputs in the model are based on export capacity. F-Factors are applied depending on the scenario being studied. Powerflow Analysis – Inputs

33. Two independent charge rates are calculated Charge 1 (£/kVA/annum) is calculated with the reinforcements identified in the Maximum Demand and Maintenance Demand scenarios. It is used for demand charges and generation credits. Charge 2 (£/kVA/annum) is calculated with the reinforcements identified in the Minimum Demand scenario. It is used for generation charges. FCP charge types

34. Two demand scenarios are considered in line with planning standard E/R P2/6: Maximum Demand scenario considering N-1 contingencies; and Maintenance Demand scenario for N-2 contingencies. Irrespective of the contingency type all overloads and their reinforcements are allocated to their Network Group Load Analysis

35. Load related reinforcements are identified by sequentially running contingency analysis over the 10 year period If a branch is flagged for reinforcement more than once during the contingency analysis then the earliest time the reinforcement is called for is taken into consideration Avoiding over recovery of Network Group Reinforcement costs Load Analysis 2

36. FCP Load Equation • i is the discount rate, which is assumed to be the pre-tax cost of capital set by Ofgem as part of the price control; • A is the cost (£) of each expected Network Group reinforcement over the 10 years period; • C is demand (kVA) of the Network Group at which each reinforcement would be required; • D is initial demand (kVA) in the Network Group; • g is demand growth rate calculated from • where Yis the number of years into the future when reinforcement is required; • T is the 10 years over which the cost is recovered.

37. Generation Analysis • Due to the non uniform growth of generation, it is appropriate to use a probabilistic test approach • Asset overloads are identified by using a Test Sized Generator (TSG). • The TSG is sized based on the 85th percentile of existing generators that are connected to the DNO’s network including committed generation schemes.

38. Test Size Generator - Information

40. The generation analysis considers the network operating with Minimum Demands as forecast for the first year charges are being calculated for. Only N-1 contingencies are considered If the TSG causes any overloads a probabilistic approach is used to calculate the cost as if the TSG were to connect at some time over the 10 year period. Generation Analysis 2

41. Generation Analysis 3 • Where a reinforcement is identified the ‘headroom’ capacity is evaluated and used to determine the timing of reinforcement Yj, using:- • Hj is the Test Size Generator Headroom for Branch “j” which is the maximum output from the TSG that does not cause Branch “j” to become overloaded • SV is size of the Test Size Generator that causes the overload to be identified.

42. FCP Generation Equation • j is the index of the Branch that requires reinforcement • Aj is the reinforcement cost of Branch “j” (£); • i is the discount rate; • Yj is the earliest time to reinforcement of Branch “j” (i.e. where reinforcement due to more than one TSG is required, this is the earliest time to reinforcement); • G is the initial generation level in the current year (kVA); • Pv is the probability of a single TSG connecting at voltage level “v”; • PVj is the probability that reinforcement of Branch “j” is required (where reinforcement due to more than one TSG is required, this is a composite probability) • MS and MC are, respectively, numbers of Substation TSGs and Circuit TSGs connected in the considered Network Group • SVS and SVC are, respectively, the sizes of Substation TSGs and Circuit TSGs

43. Key FCP and LRIC Features

44. EDCM Charging Model Mo Sukumaran

45. Overview of EDCM model

46. Step 1 – Data from power flow model (FCP) Charge 1: Also called demand charge Reinforcements caused by demand Charge to demand / Credit to generation Charge 2: Also called generation charge Reinforcements caused by generation Cost to generation / no credit to demand Gross kW and kVAr flows for demand & generation in maximum and minimum demand scenarios EDCM Charging Model - Input data

47. Step 2 – Other Data Inputs Customer dataset Location on network Sole Use Assets value Import / Export Capacity Average active/reactive consumption in super-red timeband: SEPD: weekdays November to February, time of day as CDCM red band SHEPD: weekdays October to March, time of day as CDCM red band Network support factor (whether generation is intermittent) Forecast volumes NGET exit charges (Transmission Connection) DNO data: Allowed Revenue Direct operating expenditure CDCM model assets and CDCM volumes EDCM Charging Model - Input data

48. Separate tariffs for generation and demand Demand-only site Pay demand charges Negative scaling issue to be addressed to remove credits to demand Site with export MPAN or MSID Pay or receive a generation tariff for exports Pay a demand tariff for imports Sole use asset charge applied to demand tariff Overview of EDCM tariffs

49. Summary of Demand Charging Elements: Charge 1 Sole Use Asset Charge Transmission Exit Charge Demand Scaling Demand Customer Charging Basis

50. DemandChargeBreakdown