A DNO Perspective

1. A DNO Perspective by Stephen Parker for Structure of Charges Workshop 15 July 2003

2. Agenda • Reaction to Ofgem’s Initial Conclusions • Regulatory Framework • Charging Proposals • Detailed Issues • What Happens Next • Generator DUoS • Concepts for a Charging Methodology • Implementation • Final Thoughts

3. Regulatory Framework Common set of High Level Charging Principles A good idea but insufficient focus on DNO ability to maintain and develop an efficient network Introduce Transmission Style Licence ObligationsDisagree – significant reduction in commercial freedom and extension of administration Equalise Treatment of Demand and Generation Agree but significant issues to be addressed

4. Charging Proposals Shallow Connection Charging with Locational DUoS for EHV & Shallowish Connection Charging with Non-Locational DUoS for below EHV In principle we could support this approach so long as definitional difficulties can be resolved including; • Defining Generator DUoS • Defining Shallowish • Apportioning DUoS between demand and generation users • Apportioning DUoS between users at different voltages / locations

5. Detailed Issues Existing Generation Connections Favour exemption with cut off point by which all customers are charged on same basis. 15 years? Tariff Support and O&MImportant element of cost reflective charging. We want to adopt assets built to our standards and see TSA as a helpful feature of our commercial positioning Reinforcement Rule Not convinced that it is possible to establish a rigid rule

6. Detailed Issues Fixed & Variable Charges Important to retain freedom to adjust the balance of charges to reflect individual network circumstances Reactive Power ChargesWelcome this statement – incentives need to be considered Treatment of EHV Charges No problems with the current arrangements

7. Defining Generator DUoS? • Recovery of additional reinforcement/incentive costsIf recovered locally from individual connectees then equals deferred connection. If not recovered locally then may imply 2 RABs. Need methodology for apportioning between generators at different locations/voltages. • Fixed percentage of overall DUoS revenuesHow would this percentage be derived? Still need a methodology for apportioning between generators at different locations/voltages. • Simple entry / exitNetting off type approach. Maintains supplier hub and minimises implementation costs. Cost reflective?

8. Defining Generator DUoS? Develop Marginal Cost Model How do you capture the impact of multi-directional flows caused by the presence of distributed generation? Working with UMIST to consider how such a model could be developed Don’t have all the answers nor a full understanding whether the approach is practical to implement.

9. Concepts for a Charging Methodology Starting from the real network generic entry / exit pricing models are developed (currently 2 models are developed for the urban and rural networks) Each item of plant (transformer, cables, overhead lines) on the generic network can be classified as being either generator or demand dominated or (roughly) balanced If an additional unit is imposed on the plant during the point of maximum loading then this will require reinforcement.

10. Illustrative Example Description of the System Two generators: 1 MW wind farm at 11kV (200kW effective contribution) 15 MW CHP plant at 33kV (5MW effective contribution) Three load customers with peaks: 3MW on the 11kV feeder 10MW at the 11kV bus 50MW at the 33kV bus (Minimum demand 25% of MD)

11. What is the maximum flow through the 11kV feeder? Two conditions need to be investigated: • Maximum load minus Effective generation • Maximum generation minus Minimum load

12. Maximum flow through 11 kV feeder: Critical condition for the 11 kV feeder is driven by load

13. 57.8MW 12.75MW Repeating the analysis allows the polarity of the critical flows for each component of the network to be identified. 12.8MW 2.8MW

14. Concepts for a Charging Methodology Having established the direction of the critical flows the polarity of DUoS charges for demand and generation can be determined (e.g. demand customer will pay for use of all upstream assets that are demand dominated and get rewarded for use of all assets that are generation dominated) Temporal dimension to charging can be introduced by considering the point of the critical flows (e.g Typically for demand dominated plant, charges to downstream demand customer will be based on their peak demand (e.g.winter daytime) while generator payments will be based on their minimum output (or effective contribution) and applied during the same on peak period.

15. Concepts for a Charging Methodology To set DUoS charges for each individual user, per unit annuitised capacity costs are allocated to each item of plant There is full flexibility in implementation, from generic location and/or time of use specific or non-specific (simple, cost reflectivity being compromised) to fully locational specific time of use charges being applied on the real system (fully cost reflective and accurate, but potentially very complex)

16. Implementation Issues Practicality Is the right data available? How many tariffs? Volatility of charges? Balancing cost reflectivity against simplicity May represent a means of establishing EHV charges Meeting social and environmental objectives Demand charges and generation charges below EHV to be non-locational

17. Final Thoughts? • Changes to charging arrangements must reflect the significant change to (some?) distribution networks that DG will bring about • Maintaining simplicity will be challenging (is it really necessary?) • 1 April 2005 is challenging • Designing by Committee will be (even more) challenging