1. G3 Update to DCMF 22nd November 2007

2. Significant progress made Consultation on common methodology - May Stakeholder workshop - June Summary of responses - July Updates to all DCMF meetings Series of helpful discussions with Ofgem Significant development in several key areas –refinements to tariff model, generation, scaling, reactive charges Impact generally to reduce price disturbance

3. % price movements compared to current charges. Scottish Power Energy Networks SPMSPD TariffMay %Nov %May %Nov % Domestic Unrestricted12.34%8.61%11.27%7.76% Domestic 2 rate-7.66%-14.12%-17.11%-26.36% Business Single Rate, LV29.21%26.33%10.20%4.06% Business Two Rate, LV8.60%6.08% Business MD, LVN20.31%18.14%-5.68%-8.00% Business MD, LVS-26.84%-5.25% Business HH, LVN9.31%7.70%18.27%15.16% Business HH, LVS-27.59%-7.51% Business HH, HVN-43.52%-28.22%-36.93%-3.95% Business HH, HVS-56.88%-40.83% UMS, good inventory-27.79%-25.90%-11.16%-11.69% UMS 24hr, good inventory-48.95%-50.04%-35.79%-37.74%

4. % price movements compared to current charges. Central Networks CNWCNE TariffMay %Nov %May %Nov % Domestic Single Rate24%13%25%13% Domestic Two Rate10%3%20%9% Small Non Domestic Single Rate22%14%24%18% Small Non Domestic Two Rate-1%-8%19%12% Medium Non Domestic LV 2 Rate15%6%12%7% Medium Non Domestic HV 2 Rate-57%-28%-56%-28% LV Half Hourly-8%-18%-19%-24% HV Half Hourly-55%-23%-51%-21% Unmetered Supplies-25%-30%-17%-18%

5. % price movements compared to current charges. SSE Power Distribution SEPDSHEPD TariffMay %Nov %May %Nov % LV Demand Domestic Unrestricted (PC1) 1.9%-2.3%16.3%2.8% LV Demand Domestic Restricted (PC2) 29.9%16.0%3.6%3.1% LV Demand Off-Peak 16.0%9.4%31.5%23.7% LV Demand Non Domestic Small Unrestricted (PC3)1.8%-1.2%-21.6%-16.6% LV Demand Non Domestic Small Restricted (PC4)-5.9%-7.6%-37.9%-15.4% LV Demand Non Domestic Medium Restricted (PC5-8)-7.7%-5.5%16.7%15.9% LV Demand Non Domestic Large (HH)11.0%7.8%5.9%5.1% HV Demand Non Domestic Large (HH))-29.7%-1.6%-25.7%6.8% Unmetered supplies22.2%18.2%-34.2%-35.1%

6. Implementation plans April 2008 probably remains achievable Would cause uncertainty around indicative tariffs G3 has therefore decided not to push for April G3 companies will make their separate proposals early in 2008 –Implementation targeted for October 2008, or April 2009 –Aim for early approval and therefore certainty for stakeholders

7. Possible G3+ approach! G3 is already a common methodology Developed and amended our approach Now close to fully integrated methodology Methodology “better” than G3 currents Methodology compatible with different network models and different tariffs G3 happy to share common methodology Could achieve Ofgem option 3

8. Recant development areas FCP/ LRIC Comparison Example of FCP on a real network Revenue Reconciliation Reactive Charging Generator Charging

9. Comparison of FCP and LRIC approaches

12. Example of FCP on a real network

13. Revenue reconciliation Revised MEAV fixed adder approach excludes customer funded assets at voltage of connection. More accurately reflects what the ‘scaling’ represents, i.e. return on capital employed for existing assets Avoids the cross subsidy issue that arise with other fixed adder approaches Reduces tariff disturbance from current charges

14. Revenue reconciliation Column [A]: contains the total kVA at each voltage level for all customer groups Column [B]: contains the unadjusted MEAV of the network at each voltage level Column [C]: contains the adjusted MEAV excluding deemed customer contributions. The amount to be excluded is calculated by using the proportion of the total demand at that network level that is represented by the customers directly connected at that level. What is therefore left is the MEAV of the network that is shared both by the customers at that level and the customers connected further down the network. Column [D]: uses the MEAV of the shared assets to work out the scaling proportion appropriate for each network level. Column [E]: uses the proportion from column D and applies it to the total amount of required scaling to calculate the scaling cost to be attributed to each network level. Column [F]: lists the amount of kVA at each network level that this scaling cost is to be apportioned between. Note: at the transformation levels (132/EHV, EHV/HV, HV/LV) this will not include customers connected at that level on a substation tariff but at the network levels (132, EHV, HV, LV) it will include the customers connected at that level on a network tariff. This is because customers connected to the substation are assumed to have paid the cost of their full share of that substation on connection and therefore should not pay for any of the remaining shared substation assets, however customers connected to the network will only have paid for their sole use assets and will still be making use of the shared network to which they have connected. Column [G]: calculates the voltage level kVA adder to be applied to all applicable customer groups by dividing column [E] by column [F]. Column [H]: list the applicable customer groups for each voltage level fixed adder.

15. Reactive charging The proposed methodology broadly follows that already approved for United Utilities. Reactive charging for half-hourly metered HV and LV customers. EHV customers and generators are charged per kVA. No separate reactive charges as costs are in the kVA charge. For each customer class the Network Cost (excluding the Fixed Charge) and Availability Charge are derived from the Tariff model as £/kVA/year. The Availability Charge is subtracted from the Network Cost to remove charges included elsewhere. The Load Factor is then used to derive a cost in p/kVAh. The marginal cost is given by the rate of increase of the kVA with kVAr. This defines the excess charge rate p/kVArh. Marginal cost determined at the average power factor of customers whose power factor is worse than 0.95 The excess charge rate is then applied to all kVArh in excess of one third of the kWh.

16. Reactive charging Network Cost= £54.37/kVA/yr (excluding fixed charge) Availability Charge = £12.50/kVA/yr Load Factor = 0.43 Network Cost - Availability Charge = £41.87/kVA/yr = 100*41.87/(0.43*365*24) = 1.11 p/kVAh Average power factor for Customer Class for half hours with power factor < 0.95: = 0.85 Sin(t) = Sqrt(1 - 0.85^2) = 0.527 Reactive charge = 0.527*1.11 = 0.585 p/kVArh

17. Generator charging Reconsidered our approach to align methods for demand and generation For generation, the following information is known: H 0 = the initial headroom, A=the cost of reinforcing the network G 0 = current level of generation S=a test size generator, determined by undertaking statistical analysis of past and current connection applications. If the headroom, H 0, is greater than the test size, then no marginal generation charge is levied as the connection of another generator is unlikely to cause any reinforcement costs.

18. Generator charging First, it is assumed that a generator of size S will connect within the period that is used for determining charges, N years (to match demand FCP, N is set to 10). The generation G at t years prior to reinforcement is then: G = G 0 +S – t S/N For an asset reinforcement cost of £A and a discount rate of i, then the charge per kVA per annum at t years prior to reinforcement is assumed of the same form as demand. FCP = k A Exp (-i t) where k is a constant determined from the condition that the total income accumulated equals the cost of the reinforcement. The value of the contribution from the generation in year t by the time of reinforcement is therefore: = (G 0 +S – t S/N) k A Exp(-i t) Exp(i t) = k A (G 0 +S – t S/N)

19. Generator charging This is summed over N years prior to reinforcement to give a total value by the time of reinforcement of: k A N(G 0 + S / 2) The value of k is given by equating this value to A, giving: k = 1/(N (G 0 + S / 2) ) The annual charge rate per kVA at time t years prior to reinforcement is therefore given by: FCP = A Exp(- i t)/ (N (G 0 + S / 2)) (£/kVA p.a.) with a zero rate at all times more than 10 years prior to reinforcement, where the time to reinforcement is H 0 N / S.

20. Generator charging Previous analysis based on the assumption that a test size generator is attached to each network group within the 10 year period. To match the revenue to the estimated cost, it is necessary to multiply by the probability of new generation locating to each network group. This probability, P v, will be different for each voltage level. The method proposed to derive P v is to use the assumptions for total GB DG capacity used in the joint government – OFGEM report “Review of Distributed Generation” published in May 2007 together with the Energy White paper and estimate the total ratio of DG as a proportion of demand. For the GB demand, we have used NGET’s Electricity demand projections as per their 7-years statement. The above are used to determine the total new MW of generation over the 10 year period. This is allocated to each voltage level in proportion to the existing generation capacity at each level. P v is then evaluated by dividing this value by the total implied by adding generation to each network group for that voltage level.

21. Generator charging Derivation of Pv

22. Generator charging example Effect on charge rates following the addition of 12,500 kVA generators to the 33kV network. The test size generator is 25,000kVA. No current generation connected and 16,800kVA of generation can be connected without the need of any reinforcement. Should the reinforcement be required it will cost £1,573k and will provide additional headroom of 154,500kVA. When the first generator connects, there is still no need to reinforce. The time to reinforce reduces, increasing the charge rate, but offset by the increase in the charge base reducing the charge per kVA. When the second generator connects the reinforcement will be carried out. Charges will reduce to zero as the the new headroom is such that the future costs are zero. This is a feature of all approaches that use forward-looking costs. However, the second generator is likely to pay for a proportion of the reinforcement costs through the connection charge using the cost apportionment rules.

23. Generator charging Current analysis indicates charges from this approach similar to what would be expected from the DG assumptions used in the DG price control. Approach will be used for HV generation charges and above, though not initially locational for HV. LV costs are currently forecast to be zero.

24. Significant development summary We have developed and amended our approach, as required, to reflect the constructive feedback we have received. The FCP approach for deriving marginal costs has been demonstrated to be robust, works with different growth assumptions and produces time of day signals. The overall tariff model is also robust with auditable data sources. Changed our approach to reactive charging following feedback to use a similar approach that has already been approved. The approach to generation has been significantly amended following feedback but we believe that the new methodology is sound and now consistent with the approach used for demand.