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Principles of Distribution charging: Electricity networks Introduction A three-stage approach involves the following steps: 1. The analysis and quantification of costs. The cost concept that is relevant here is the expenditures required to accommodate increased demand or generation and the expenditures that would be avoided if existing demand or generation were to discontinue. 2. Design of connection charges and/or use of system charges which would reflect those costs, taking account of various practical considerations. 3. Adjusting and adding to those charges so as to ensure that they will yield the DNO’s allowed revenue. 1.Cost analysis The costs that are relevant to making decisions are necessarily forward-looking costs, since decisions relate to the future. They are those forward looking costs which will be incurred if new demands are met and new generation accommodated and which would be avoided if existing demand and generation were to be terminated. The idea is that, by reflecting such costs to the DNO in its charges, demand and generation customers who directly pay those charges, or who pay them indirectly via their embodiment in suppliers’ charges, will have an incentive to take account of them in making their decisions. (This is the principle behind the idea of pricing at marginal cost as understood by economists. However “marginal” means “first derivative” which implies continuously derivable cost functions. These are scarcely found in electricity distribution where there is plant indivisibility because only a limited range of standard conductor, switchgear and conductor sizes are installed, making the term “marginal cost” inappropriate.) If the existing network and its utilisation are modeled in detail, the effect of postulated increments and decrements in demand and generation upon load flows can be predicted and the extra cost of accommodating them, or saved by ceasing to accommodate them, can be calculated. This is done in Framework and Methodology for Pricing of Distribution Networks with Distributed Generation A report to OFGEM by Professor Goran Strbac and Dr Joseph Mutale March 2005. The particular features of their work include the following: Required capacities take account of network security and thermal constraints but not voltage and fault-level considerations. In some cases they are determined by maximum load and secure generation output; in other cases by minimum load and maximum generation. Indivisibilities are ignored, circuits being treated as if capacity were continuously variable, so that marginal cost estimated are produced. The approach, which would require a prohibitively large effort to apply at the lower voltage levels, yields system charges which are locationally (even by individual node) and time-of-use specific. Load flow analysis is also used in Network benefits from introducing an economic methodology for Distribution charging, A Study by The Department of Electronic & Electrical Engineering University Of Bath (Furong Li, David Tolley, Narayana Prasad Padhy, Ji Wang) December 2005. This goes further, its main purpose being to consider the effects of charging as well as the determination of charges. Several approaches are followed as regards their determination. One of them, the ICRP model, finds the cost of meeting an increment of demand or generation at each node on the reference network. It assumes a security factor of 2 and ignores indivisibilities. The other, denoted the LRIC model, does allow for indivisibility, thus recognising the existence of unused capacity on the network. It assesses the additional cost that arises from the need to advance investment as a result of adding load or generation at any node on the system, or alternatively the reduction in cost that will result from postponing investment.1 Thus, time being divisible, it does consider a true marginal cost. This, however, is the marginal cost of investment timing which is relevant to when to invest but not to whether to invest. In other words, there is also a total (first-order) optimality condition to be met. The relevant non-marginal principle for cost reflection in charges is discussed below. But first a simpler, down to earth approach to cost analysis is proposed, for application at all voltage levels. Each DNO should assemble data on its recent and its planned reinforcement and replacement investments in circuits, transformers and switchgear. The cost of each such investment (if necessary price-updated for past investments; reliably estimated for future ones) should be tabulated, together with information about its contribution to KVA capacity, voltage control and fault level, noting security enhancement and any local circumstances affecting its cost. From those whose primary purpose was, or is planned, to increase capacity or to maintain it, averages for each voltage level, possibly distinguishing areas or circumstances within the DNO’s territory, should be calculated. These 1 The increase in the present worth of future investment resulting from the need to bring it forward in order to cope with an increment to forecast demand, for example, should be divided not by its size in MW but by the discounted value over the calculation horizon of that increment, in order to obtain an annual capacity cost per MW. would allow estimates to be made of typical costs per KVA that reflect a DNO’s actual experience and intentions. Note that: No distinction need be made between reinforcement and replacement. Investments which do either or both would all be covered and artificial distinctions between load-related and nonload-related investment are irrelevant. The estimates must make sense to the engineers without aiming at fictitious precision and should be accepted by their colleagues as in no way prejudicing the recovery of allowed revenue. O & M costs can be estimated and added Estimated unit costs are not a new concept since they have been used in the Distribution Reinforcement model as follows DISTRIBUTION CAPITAL COSTS OF MEETING A 500 MW INCREMENT AT 132KV AND 33 KV NGT charges & system components Transmission exit charges 132 KV switchgear & circuits Switchbay 2 400 mm cable per km 2 175 mm cable per km 2 175 mm overhead dual circuit per km 2 175 mm overhead single circuit per km Unit cost £000 Quantities £520 £1,012 £960 £333 £168 6 7.31 2.44 44.36 23.89 132/33 KV substations 2 x 90 MVA susbstation urban 3 x 60 MVA substation rural £713 £564 5 1 33 KV circuits Urban 300 mm2 cable per km 2 Rural 200 mm overhead dual circuit per km 2 Rural 200 mm overhead single circuit per km £196 £60 £38 140 60.8 15.2 Cost £000 £3,120 £7,400 £2,340 £14,773 £4,013 £31,646 Diversity factor Cost per Cumulated £ Cost per (Aggregate Cost per KW net cost KW MD ÷ KW Losses at aggregate per KW coincident Coincident aggregate peak MD after aggregate MD MD) MD hours losses MD 1.0% £15 £15.00 £15.15 £63.29 £78.29 1.06 £73.86 1.0% £74.60 £74.60 £3,565 £564 £4,129 £8.26 1.06 £7.79 2.0% £7.95 £82.55 £27,440 £3,648 £578 £31,666 £63.33 1.06 £59.75 2.0% £60.94 £143.49 MVA of required132/33 KV transformer capacity = 500 x Diversity factor ÷ Utilisation factor ÷ Power factor 78 km 132 KV circuits = average feeder length to substations (13) x no. substations (6) 140 km urban 33 KV circuits = no. substations (6) x average feeder length (4) x no. of feeders per substation (7) 76 km rural 33 KV circuits = no. substations (1) x average feeder length (9.5) x no. of feeders per substation (8) 2. Cost reflection. Indivisibility Indivisibility, the fact that plant comes only in standard sizes, is one of two reasons why plant utilization factors fall well below 100%. The other reason is to meet security requirements. Thus a substation may have to have two transformers, even though the maximum load it normally supplies is less than the capacity of one of them, in order to avoid lost load when one of them suffers an outage or when an outage elsewhere in the network results in an increase in the load to a level exceeding the capacity of either transformer alone. To simplify the discussion of reinforcement costs, suppose that security considerations do not apply, the rule being n-0 rather than n-1. F x E D C B A Contributions to simultaneous maximum demands are measured vertically, time is measured along the horizontal axis. The level of capacity is shown by the heavy black line. The advent of a new load D will require it to be increased by x. If this load had not been introduced, the advent of load E or F would have required it subsequently Economic efficiency requires that The capacity increase to meet the maximum demands of D, E and F should be installed if the present worth of the sum of their values to D, E and F exceeds its cost; and The alternative of meeting the maximum demands of D, E and F by reducing the maximum demands of A, B and C to an equal extent should be rejected if the present worth of the sum of the values to A, B and C of maintaining the level of their maximum demands exceeds that cost. These conditions will be met and discrimination avoided if either: 1. All six customers face annual maximum demand charges set so as to make the present worth of the payment by D, E and F cover the capital cost of the reinforcement. or 2. D, E and F are required to pay connection charges sufficient to cover the capital cost of the reinforcement. A, B and C would be entitled to an equivalent disconnection bounty if they reduced their maximum demands sufficiently to accommodate the maximum demands of D, E and F without the reinforcement. These alternatives might appear asymmetrical, with all six paying in case 1 but only D, E and F in case 2. But under this alternative, A, B and C would have paid connection charges earlier on, when they were connected. Uncertainty The difficulty with both alternatives is that the timing and amount of the maximum demands of E and F lie in the future and are thus unknown. Unfortunately. highly uncertain assessments are involved in the case of the advent of a new load D which will necessitate a capacity increase of x. When and whether E and F will turn up is a risk that someone must bear if capital is to be spent upon x. So the issue is whether demand customer D or the DNO is best fitted to bear this risk. In the light of this it will have to be decided how they will share the cost of the investment and how they will recoup or cover their share of it if and when E and F do turn up. Suppose that the DNO is to bear the risk. Then, in practice, resort has to be made to applying an assumed average future degree of asset utilisation in computing cost-reflective maximum demand charges or connection charges. (This will reflect both of the two reasons why plant utilization factors can be well below 100%: not only the indivisibilities of plant but also the n-1 security requirement.) If the degree of capacity utilisation of this type of asset in the DNO is ascertained to be, say, 50%, a possible solution would be to base charges on twice maximum demands multiplied by the unit cost of the reinforcement. The whole of its cost would enter the DNO’s RAB, so it would be allowed to recover it from D and its existing customers if E and F did not turn up. Spare capacity The preceding argument assumes that the introduction of D’s new maximum demand is known and imminent, so that reinforcement will have to be undertaken, existing customers being ready to continue to pay maximum demand charges, or having paid connection charges, which reflect the cost of sufficient new capacity to provide the desired security margin. In other parts of the system, however, existing capacity may exceed maximum demand by much more than is necessary to provide security. In such cases, new demands can be accepted without either any reinforcement or reduction of existing demands. What charges would be cost reflective in such cases? The short-run answer is that zero charges are appropriate. But although maximum demand charges are paid annually, they and connection charges are better adapted to providing a long-run message and incentive since they relate to the size of the system and the size of the customer. They are what customers pay for a continuing capability of the distribution system to meet their needs. Although the cost of providing this capability is a bygone, the money having been spent and the lines and transformers having no alternative use, there is a cost of maintaining the capability by replacing those lines and transformers when their condition deteriorates because of their age. Economic efficiency requires that the value to the customers of continued service exceeds the cost of the replacement which will become necessary if service to those customers is to continue. This condition will be met and discrimination avoided if all customers have to pay annual maximum demand charges set so as to make the present worth of the payment over the lifetime of assets cover the capital cost of their replacement. (Alternatively, at least in principle, they could be charged “connection renewal” sums to cover that cost.) Distributed Generation In their report to OFGEM DG-BPQ Analysis Summary of Findings dated March 2004, MottMacDonald/British Power International said that the main driver for expenditure on shared assets in the historical and interim periods had been the need to manage increased fault levels, but in future other main drivers were expected to be the need to increase network thermal capacity and to control voltage. In the historical and interim periods DNOs had largely been successful in accommodating DG on existing networks with occasional switchgear replacements where required for fault level management. In future this would need to change as networks needed to be strengthened and extended due to the increasing requirement to connect generators in remote areas where networks were weak, and the requirement to manage voltage as the number of generator connections increased. Looking forward, while in 18 out of 85 cases fault level would be the main reason for expenditure, thermal reasons would apply in 42 cases (reflecting an increasing number of generators likely to be exporting from remote locations) and voltage in 20. However, for projects requiring reinforcement due to fault, an increase in unit costs was likely, reflecting reducing levels of fault level headroom on the networks as installed capacity increased., Typical engineering work to accommodate increased fault levels is the replacement of circuit breakers, distribution ring main units, transformers and isolators. Dealing with thermal limitations requires upgrading cables and overhead lines, providing and extending substations and switchboards and replacement of transformers and circuit breakers. The engineering work required for voltage control is the provision of voltage regulators, shunt reactors and transformer and reactor tap changers. Contributions to O&M costs are collected, usually as a oneoff payment, as a component of the connection charge, typically 20 percent of it, covering contributions to network maintenance, control room operations, and emergency restoration of the network following fault conditions together with a contribution towards the general overheads of running the DNO Company. For O&M on shared assets, most DNOs apply the same percentage as on sole-use assets. The report distinguishes expenditure on shared assets required by connection of a distributed generator from general infrastructure strategic capex on the network to accommodate growth of the capacity of distributed generation and fault levels at particular locations, triggering switchgear changes, or a need for extra equipment to facilitate active network management. However, different DNOs had taken different approaches to the split of cost between strategic reinforcement and shared costs. Some DNOs took a strategic approach whereby agreed shared-asset network reinforcements would be undertaken in particular areas in anticipation of considerable wind generation connections. Thus there could be a choice between providing network capacity on an incremental basis, or by considering all the likely projects in advance of firm connection applications and providing it in a more strategic way. United Utilities had assessed the likely reinforcement costs that would be incurred by considering a range of pseudo-projects in areas identified as having significant potential. These pseudo-projects had then been developed into fully designed schemes and the resulting incremental network developments compared to the likely reinforcements that would result from a strategic approach to accommodating the same projects. The major reinforcements required proved to be very similar both in specification and cost for the two approaches, but the distribution of costs in the incremental approach led to very high costs falling on particular projects. Conclusion Distribution charges for demand customers should relate to demands at time of local peak and should reflect current unit costs of reinforcing and/or replacing plant grossed up by dividing by the average percentage of capacity utilisation. Reinforcement and replacement costs vary between areas due to size and distance, the lack of uniformity resulting in area differences in marginal cost levels. Furthermore there may be variation between areas in the timing of maximum demands. Hence a set of maximum demand charges based on estimated replacement or reinforcement costs, allowing the requisite capacity margins for security (and supplemented as necessary to ensure full revenue recovery) might be levied on winter night-time demands in some areas, winter daytime demands in others and, possibly in the future, on summer daytime demands elsewhere. Maximum demands might be measured individually or at times of the distribution area’s peak, and the equivalent alternative of high energy charges in all hours of potential maximum demand might prove preferable. Regarding charges to distributed generators, account needs to be taken of the conclusion in the MottMacDonald/British Power International report that the average unit costs of shared connection assets for each DNO exhibit a wide spread, the ratio of greatest to least estimates between DNOs being over 10:1 (£8.2k/MW up to £89k/MW). A number of DNOs had highlighted that projects requiring significant shared costs had not proceeded in the historical and interim periods due to the deep connection charging policy making connection uneconomic for small generators. A move to shallow connection charges would thus involve large cross subsidies, discouraging the choice of suitable sites and encouraging installation in uneconomic locations. 3. Assuring revenue recovery Finally account must be taken of the need for the recovery of a DNO’s allowed revenue, probably requiring DUOS charges which exceed the unit costs of replacement and reinforcement. The ideal is to raise this additional revenue in the way which minimises the effects on customer decisions. Thus if it is raised by adding to the maximum demand charges, this should raise them all by the same absolute amounts, as the Bath University report proposes, thus preserving the incentive effects of their absolute differences. Scaling them all up by the same percentage would distort the message. An alternative worth considering would be to raise the additional revenue by a uniform KWh charge on all KWh of demand and generation. However it is not necessarily worthwhile to introduce such differentiation of DUOS charges by area within the territory of a Distribution Network Operator. That must depend upon: The magnitude of the differences in level and/or timing Public acceptability of the area boundaries The probable permanence of the area boundaries The response of customers to area differentials What is not in doubt is that cost reflectivity requires maximum demand charges or connection charges for demand customers. This may seem redundant in the case of NHH-metered customers, but it would be wrong to treat the present system of profiles as given for all eternity. The parameters of the DUOS charging structure do not have to mirror the parameters of the tariffs paid by consumers. Thus although standard tariffs for domestic consumers include no peak component, the fact that marginal costs are primarily demand-related requires that DUOS tariffs paid by Suppliers should reflect this fact, by including a demand element. This can consist of demand charges based on profiled maximum demand and/or one or more KWh rates applied in periods of high demand. It is up to Suppliers to decide how they recover these costs in their tariffs, but including either of these peak-reflective components in what they pay the DNO will provide them with incentives to consider possible tariff innovations which involve smart metering or to influence consumption patterns in other ways. The case for differentiation in DUOS charges between areas within the territory of a Distribution Network Operator is much stronger for generation than it is for demand for the simple reason that DUOS charges constitute a larger share of a Distributed Generator’s total costs than they do of demand customers’ total costs. Hence locational responses will be more marked for generators than for demand customers. Ralph Turvey.