Download Principles of Distribution charging

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:
ƒ Required capacities take account of network security and thermal
constraints but not voltage and fault-level considerations.
ƒ In some cases they are determined by maximum load and secure
generation output; in other cases by minimum load and maximum
generation.
ƒ 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.
ƒ 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.
ƒ 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:
ƒ 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.
ƒ 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.
ƒ O & M costs can be estimated and added
ƒ 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
ƒ 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
ƒ 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:
ƒ The magnitude of the differences in level and/or timing
ƒ Public acceptability of the area boundaries
ƒ The probable permanence of the area boundaries
ƒ 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.