April 9 , 2008

1. Potential developments in long-term charging arrangements (LTCA) for demand and generation customers April 9, 2008

2. Overview - enhanced long-term charging arrangements We are seeking to produce a holistic model that will address the charging issues that we are currently facing and is seen to be both rigorous and consistent in its approach. • We have formed a project team involving the University of Bath, to develop our position on long-term charging arrangements. • The proposals involve: • Combining a long-run incremental cost (LRIC) model for EHV customers with the currently approved distribution reinforcement model (DRM) at lower voltages; • Removing the current inconsistency in approaches for EHV customers; i.e. EHV (site-specific charges based on actual system configurations and utilisation) and HV/LV (average charges based on a representative model); • Developing a consistent demand and generation charging model based on the new LRIC/DRM combined model that could give negative charges to generators; • Developing an approach which is flexible enough to support future charging developments and has the potential to produce locational charges at the lower voltage levels.

3. Potential stage one developments on LTCA We are looking to develop a holistic model that will address all of the charging issues that we are currently facing and is seen to be both rigorous and consistent in its approach.Demand and generation charges are based on the same principles.Benefits of generation can be recognised.Flexible enough to facilitate further development. Nodal/locational EHV demand charges based on LRIC outputs Revenue reconciliation across all voltage levels to match demand allowances Average demand HV charges based on a typical representative model (DRM type principles) Average demand LV charges based on a typical representative model (DRM type principles) Operating costs (no scaling) Nodal/locational EHV generation charges based on LRIC outputs Revenue reconciliation across all voltage levels to match generation allowances Average generation HV charges based on a typical representative model (DRM type principles and negative coincidence factors) Average generation LV charges based on a typical representative model (DRM type principles and negative coincidence factors)

4. Current project timeline to implement stage 1 of our LTCA developments Stage 1 – represents the development of a LRIC approach at EHV (for demand and generation) and the use of a representative model at lower voltage levels Data to Bath Bath to process sample networks Raise awareness of CE’s plans on long-term charging arrangements Ofgem meeting Sample network impact and sensitivity analysis Charging model development Run LRIC on full network Document proposals and develop consultation paper Updating Ofgem on progress and agreeing the target implementation date – April or October 2009 Ofgem meeting Industry consultation Full network impact and sensitivity analysis The methodology used to calculate charges will be dependent on Ofgems decision – If they decide to consult we may have to produce two sets of charges Internal sign-off Sub. to Ofgem The proposed timeline is challenging and based on a April 2009 implementation data. We will have a better view of the most realistic implementation date once we have the sample network results from the University of Bath and have started to undertake the modelling of the full network. Ofgem decision Calculation of charges Internal sign-off Charge publication Jul-08 Oct-08 Feb-08 Mar-08 Jan-08 Apr-08 Jun-08 Dec-08 Sep-08 Nov-08 May-08 Aug-08

5. Longer-term plans for LTCA Long-term the model should be flexible enough to facilitate locational charges at lower voltage levels for both demand and generation customers. • The model needs to be flexible enough to facilitate future developments, which may include; • Demand and generation reactive power charges (Import/Export kVA/kVAr); • Short haul tariffs for mixed demand and generation developments; and • Locational signals further down the network. • This could be either LRIC at lower voltages, based on standard network configuration; or • The use of a number of locational yardsticks driven from the proposed model.

6. Potential developments in IDNO charging methodologies April 9, 2008

7. Initial thoughts on IDNO charging arrangements We are seeking to produce cost reflective IDNO charging arrangements that reflect any avoided costs and losses savings. • We are looking to develop IDNO charges that are cost-reflective and calculated using the same principles that are used to derive the charges for other customers (i.e. average charges based on DRM model principles); • We are currently considering: • Removing capacity charges for IDNO customers so that the boundary tariff has the same structure as the all the way tariffs; • Incorporating avoided costs (both operating and capital costs); • Incorporating any losses savings that they bring; • Creating a new IDNO customer group based on a NHH customer mix that represents the host DNO; and • Establishing a typical IDNO load profile so that more representative load and coincidence factors can be established – this will be based on Elexon data.

8. Establishing what an IDNO look like? The initial problem that occurred when trying to tackle the IDNO charging issue was the lack of actual site data at a useable level of granularity.Our thinking has been developed by asking a number of key questions Implementing this approach results in the following load profile which could be used to establish IDNO yardsticks How big will a typical IDNO site be in terms of customers? What will the customer mix be like on a typical IDNO site? Can an existing tariff be modified or is a new customer group and tariffs required? How do we develop an IDNO customer group and load profile?

9. Considerations on avoided costs and losses savings Avoided cost and losses savings could be built into the IDNO tariff based on the proportion of length of assets that the IDNO would install against the total length of assets to the 11kV network - resulting a discounted IDNO yardstick.Discounting the yardstick will demonstrate both displaced capital and operational costs from the end user charges. Band 2 (26%-50% of assets) Band 4 (76%-100% of assets) 100% LV yardstick discount 50% LV yardstick discount 3.85% * 50% = 1.93% Displaced from loss factor 3.85% * 100% = 3.85% Displaced from loss factor End User CE - 11kV Network 3.85% * 25% = 0.96% Displaced from loss factor 3.85% * 75% = 2.89% Displaced from loss factor Band 1 (1%-25% if assets) Band 3 (51%-75% if assets) 75% LV yardstick discount 25% LV yardstick discount 3.85% Losses

10. Next steps We will have a better view of the most realistic implementation date once we have consulted with the industry on our proposals.Also, if Ofgem consult on proposals we may choose to implement in April 2009. Finalise our thinking on the typical size of an IDNO size; the most appropriate customer mix; and what costs are avoided; Give some consideration as to whether, or not, there is the potential to move to a unit only charge at the boundary; Gain internal approval to the proposed approach; Documents our proposals; Potential industry consultation in May 2008, which would include a full impact and sensitivity analysis; Finalise proposals in mid June; Submission of modification proposal late June/early July; and Target implementation in October 2008, or a.s.a.p. after Ofgem decided not to veto our proposals.