Reckon LLP
Project
CDCM — Unmetered tariffs and NHH/HH discrepancies
Date
Wednesday 9 March 2016
From
Franck Latrémolière
To
UMS working group
Title
Updated paper after today’s meeting and before receiving data
about the possible impact of idea 10
1.
This is a draft of the report of the unmetered supplies working group established by
the methodologies issues group (MIG) to investigate issues relating to:
(a) The creation of separate CDCM tariffs for the four categories (A, B, C and D) of
non half hourly unmetered supplies.
(b) Discrepancies between half hourly and non half hourly CDCM tariffs for
unmetered supplies.
(c) The recovery of costs incurred by DNOs in the UMSO activity.
Table of contents
Separate non half hourly tariffs for A, B, C and D ............................................................................ 1
Discrepancies between half hourly and non half hourly CDCM unmetered tariffs ....................... 2
Why average unit rates are different on single-rate and multi-rate tariffs ................................................................................. 2
Why the difference is particularly large for unmetered tariffs .................................................................................................. 3
Idea 1: Derive non half hourly unmetered tariffs from half hourly unmetered tariffs ............................................................... 3
Idea 2: Use half hourly cost allocation principles for non half hourly unmetered tariffs .......................................................... 4
Idea 3: Apply the coincidence correction factor to red unit rates only ...................................................................................... 4
Idea 4: Remove the coincidence correction factor from the CDCM altogether ........................................................................ 4
Worked example for ideas 1–4.................................................................................................................................................. 4
Idea 5: Remove the coincidence factors from the CDCM altogether ........................................................................................ 7
Idea 6: Use distribution time bands that are more closely related to the DNO peak ................................................................. 7
Idea 7: Add capacity charges to half hourly unmetered tariffs .................................................................................................. 7
Idea 8: Charge all unmetered supplies on capacity data instead of deemed consumption ......................................................... 7
Idea 9: Single one-rate tariff for all unmetered supplies ........................................................................................................... 8
Comparison of ideas 1–9 .......................................................................................................................................................... 8
Impact assessment for idea 9 .................................................................................................................................................... 9
Idea 10: seasonal time bands for half hourly unmetered supplies only ....................................................................................10
Elements of an approximate impact assessment for idea 10 .................................................................................................... 11
Separate non half hourly tariffs for A, B, C and D
2.
The only practical difficulty raised by the proposal to amend the CDCM model to
provide four separate non half hourly tariffs for unmetered supplies in categories A
(continuous), B (dusk to dawn), C (half night) and D (dawn to dusk) is the population
of input data for coincidence factor and load factor for these tariffs.
3.
In the CDCM as it stands, the coincidence factor and load factor for the single non
half hourly unmetered tariff are derived from data related to half hourly settled
unmetered supply. This is an exception to the rule that profiled consumption data
1
from the D0030 data flow are used to estimate coincidence factor and load factor for
non half hourly tariffs.
4.
The rationale for that exception is that DNOs have observed that the D0030 seasonal
pattern of profiled consumption data for non half hourly settled street lighting loads is
manifestly unrepresentative of the actual consumption pattern of these loads. In
particular, profiled consumption at 5 pm or 6 pm on a winter weekday is typically of
the order of 40 per cent of maximum consumption, when it should be at or close to
100 per cent.
5.
The working group has found a solution to this problem. The solution is to ask a
company running a pseudo-half hourly metering service to provide estimates of the
consumption patterns of typical loads within each of categories A, B, C and D, for
each GSP Group (DNO area), and for DNOs to use these data as the basis for
coincidence factor and load factor calculations.
6.
If this issue could be taken in isolation, then the group’s view would be that
introducing separate CDCM tariffs for the four categories of non half hourly
unmetered supplies would be feasible and would improve the accuracy and costreflectivity of the CDCM.
7.
But the group determined that this issue cannot be taken in isolation. Thus, the group
does not make any stand-alone recommendation about introducing separate CDCM
tariffs for the four categories of non half hourly unmetered supplies. The group’s
recommendations are at the end of this report.
Discrepancies between half hourly and non half hourly CDCM
unmetered tariffs
Why average unit rates are different on single-rate and multi-rate tariffs
8.
The CDCM specifies two different cost allocation mechanisms in respect of the
allocation of 500 MW model annuities and “other costs” (which include direct costs,
network rates and some indirect costs) to unit rates for demand.
9.
For single-rate unrestricted tariffs (which, for demand in the CDCM, are all non half
hourly), the driver of this allocation is the coincidence factor. This represents the
extent to which consumption is likely to coincidence with a very narrow period in
which overall consumption on the DNO’s network is at its higher. The very narrow
period used to estimate coincidence factors might be taken the instant of system peak,
or, perhaps more practically (and less vulnerable to volatility and measurement errors)
a handful of half hours in the year in which overall consumption on the DNO’s
network is at its highest.
10.
For multi-rate tariffs (both half hourly red/amber/green and non half hourly day/night)
and for non half hourly restricted tariffs, the drivers of this allocation are different at
different network levels, as they reflect peaking probabilities — the proportions of the
DNO’s network at each network level that peak in red, amber or green.
2
11.
It is not possible to achieve completely consistent results whilst applying these two
different cost allocation principles within a single tariff methodology.
12.
The CDCM that Ofgem approved makes an attempt towards consistency by applying
a single uniform coincidence correction factor for each multi-rate or restricted tariff.
The coincidence correction factor is set in such a way that, for a hypothetical network
level where every asset always peaks in red, the cost allocation would be the same for
unrestricted tariffs and multi-rate/restricted tariffs. This is specified at paragraph 72
of the CDCM. The main part of the model implementing these rules is the Multi
sheet.
13.
Inevitably, the definition of the coincidence correction factor means that the allocation
is not the same for network levels in which not every asset peaks in red — for
example for EHV/HV substations which quite often peak in green in areas without
gas (where night time electric heating is popular). So discrepancies will remain.
Why the difference is particularly large for unmetered tariffs
14.
Street lighting has a very strong seasonal pattern of consumption. This is unusual for
a half hourly settled customer group, and probably explains why the coincidence
correction factor is particularly large for half hourly unmetered tariffs. Specifically, in
many DNO areas, the coincidence of street lighting to a narrowly defined DNO peak
(probably a winter business day early evening) is much greater than the average
extent to which street lights consume during the red distribution time band (over the
year as a whole).
15.
This gives rise to a large coincidence correction factor for the half hourly unmetered
tariffs, and unduly makes the half hourly tariff unattractive compared to the
unrestricted non half hourly unmetered tariff for many loads.
16.
The magnitude of the discrepancy is probably enhanced by the fact that, uniquely for
a half hourly settled demand tariff, the half hourly unmetered tariff has large
contributions to its unit rates from the LV and HV/LV network levels, in which
peaking probabilities are least likely to be aligned with an overall DNO system peak.
(For other half hourly demand tariffs, costs or annuities attributed to these network
levels only contribute to capacity charges.)
Idea 1: Derive non half hourly unmetered tariffs from half hourly unmetered tariffs
17.
Idea 1 involves the following process:
(a) Use the CDCM model as current defined, but combining all UMS (NHH &
NHH) into the HH line.
(b) Determine coincidence and load factors based on the total UMS.
(c) Determine red, amber and green charges for this notional total UMS group.
3
(d) Apply each of the four ELEXON profiles for each GSP group to these red,
amber and green rates to determine an average p/kWh for each of UMS A, B, C
and D.
18.
This method ensures a form of consistency between half hourly and non half hourly
unmetered tariffs.
Idea 2: Use half hourly cost allocation principles for non half hourly unmetered tariffs
19.
Idea 2 is to use the multi-rate/restricted cost allocation principles for all unmetered
tariffs, even non half hourly ones.
20.
This is achieved internally within the CDCM model by activating a rule that causes
the tariffs “LV unmetered non half hourly A/B/C/D red amber green” to be treated as
restricted tariffs (like domestic off peak heating) rather than as unrestricted tariffs.
(But in contrast to domestic off peak heating, LV unmetered non half hourly A/B/C/D
red amber green have a coincidence factor entry, like multi-rate tariffs.)
21.
This has some similarities with idea 1, but does not involve any pre- and postprocessing of data aggregated across various UMS tariffs.
Idea 3: Apply the coincidence correction factor to red unit rates only
22.
In the approved CDCM, the coincidence correction factor affects unit rates across all
distribution time bands. A simple change to the CDCM to mitigate the impact of that
factor would be to apply it only to the red rate. This is still consistent with the
concept behind the coincidence correction factor since the only case in which the
coincidence correction factor achieves a perfect match is for a hypothetical network
level where all assets always peak in red.
Idea 4: Remove the coincidence correction factor from the CDCM altogether
23.
This idea is self explanatory.
Worked example for ideas 1–4
24.
To understand and compare the impact of ideas 1 to 4, the group developed a worked
example for a hypothetical DNO. (Any similarity to any actual DNO’s data should be
taken as a coincidence.)
25.
Some simple extensions to the CDCM have been made in the base case to create
mode UMS tariffs. In particular, separate non half hourly unmetered supplies tariffs
have been created for the four categories A, B, C and D.
26.
Unmetered units in this hypothetical DNO fall into nine tariffs:
(a) LV unmetered non half hourly A
(b) LV unmetered non half hourly A red amber green
(c) LV unmetered non half hourly B
4
(d) LV unmetered non half hourly B red amber green
(e) LV unmetered non half hourly C
(f) LV unmetered non half hourly C red amber green
(g) LV unmetered non half hourly D
(h) LV unmetered non half hourly D red amber green
(i)
LV unmetered half hourly
27.
These various tariffs deal with the proposal to separate the non half hourly tariffs by
UMS type, and with idea 2 (through the tariffs labelled “red amber green” in the list
above).
28.
To populate the worked example models, illustrative estimates of the red/amber/green
allocation and the coincidence factor of each UMS category have been used. They
are shown in table 1.
Table 1
Summary of UMS load profile assumptions
UMS category
Red
Amber
Green
Coincidence
Load factor
A (continuous)
8.9%
31.2%
59.9%
1.000
1.000
B (dusk to dawn)
5.0%
10.0%
85.0%
1.000
0.450
C (half night)
9.6%
17.8%
72.6%
1.000
0.250
D (dawn to dusk)
8.8%
61.6%
29.6%
0.000
0.500
Pseudo half hourly
5.6%
10.3%
84.1%
0.973
0.489
29.
A relevant feature of the consumption pattern assumed for street lighting that has been
assumed (and which the group considers to be realistic) is that the average
consumption is red (which includes a lot of daytime over the year) is significantly less
than the expected consumption at the time of DNO-wide peak (a dark winter early
evening).
30.
In the worked example, for the half hourly unmetered tariff category (assumed to be
dominated by street lighting), average consumption over the whole year is 29 MW
(257 GWh over 8,784 hours), implying a night-time consumption of around 60 MW,
whereas average consumption in red is only 18 MW (14 GWh over 783 hours). This
discrepancy leads to a large coincidence correction factor within the CDCM model.
5
Table 2
Summary of model results (average p/kWh)
A
B
C
D
HH
Base case
1.323
2.371
3.895
0.466
2.013
Idea 1 (approx)
3.204
1.890
3.033
3.887
Idea 2
1.323
2.232
3.456
0.466
Idea 3
1.348
2.416
3.969
0.475
Idea 3+1 (approx)
2.671
1.671
2.716
2.871
Idea 3+2
1.348
1.931
3.058
0.970
Idea 4
1.412
2.537
4.173
0.491
Idea 4+1 (approx)
1.411
0.970
1.357
1.635
Idea 4+2
1.412
0.970
1.357
1.635
1.792
1.012
31.
The main difference between the ideas is the role of the coincidence factor to the
DNO-wide system peak (as opposed to the red/amber/green allocation of units).
32.
Coincidence factors are the main drivers of the overall level of charges in the base
case and under ideas 2 and 3 (although the effect of coincidence factors is probably
less under idea 3). Ideas 2 and 3 do not have a very large effect on average charges.
33.
Under idea 4, coincidence factors are not used at all. Under idea 1, a single
coincidence factor is used for everything, so that the ratios between the rates for A, B,
C and D rates do not depend on the coincidence factors.
34.
A glaring effect of coincidence factors is on the relationship between the rates for
category B and category D. If coincidence factors drive prices, then category B pays
more per unit than category D, because category B consumes at the winter early
evening peak whereas category D does not. If, instead, the red/amber/green allocation
drives prices, then category B pays less per unit than category D, because category D
consumes a lot more during the business day amber period than category B.
35.
Any method that sets charges on a hybrid basis between red/amber/green and
coincidence factors is likely to have some kind of undesired discrepancy. The only
options in table 2 that avoid a hybrid basis are those based on idea 4, in which
coincidence factors are not used at all.
36.
Idea 3 and idea 4 have a material effect on tariffs other than unmetered tariffs. For
example, in the hypothetical example discussed here:
(a) Idea 3 reduces revenue from the domestic two rate tariff by 6 per cent.
6
(b) Idea 4 reduces revenue from the domestic two rate tariff by 26 per cent.
Idea 5: Remove the coincidence factors from the CDCM altogether
37.
Under this idea, all tariffs, even unrestricted single-rate tariffs, would be modelled on
the basis of red, amber and green consumptions, rather than coincidence to DNOwide peak. This would be a natural first step to complete de-linking.
38.
The working group has not investigated this option in detail as it would cause more
disturbance to tariffs other than unmetered tariffs than idea 4, without being better at
solving the specific problems that the working group was asked to address.
Idea 6: Use distribution time bands that are more closely related to the DNO peak
39.
Using more distribution time bands or more complex distribution time bands (e.g.
seasonal time of day bands) might reduce the discrepancies between different tariffs.
40.
The CDCM model can handle seasonal time bands as it is, and can easily be extended
to allow for additional time bands. But determining new, more complex, time bands
and populating models for these time bands would entail a significant amount of work
from DNOs.
41.
The effect on tariffs is uncertain. Changing the distribution time bands would almost
certainly have a large effect on unit rates and on charges for individual customers. It
could also have a big effect on average charging rates, particularly if idea 6 is
combined with idea 5.
42.
Idea 6 could also affect significantly the seasonal pattern of cashflows in the industry.
Idea 7: Add capacity charges to half hourly unmetered tariffs
43.
Half hourly tariffs for metered demand include capacity charges as well as unit rates.
Costs associated with the voltage level of supply and some costs associated with the
next voltage level up are recovered through capacity charges.
44.
Something similar could be done for half hourly unmetered users. This would
involve creating some new data collection arrangements or data flows so that
information on capacity (source data for which are held by the unmetered supplies
office and by the meter administrator) would be entered into the DUoS billing system.
Idea 8: Charge all unmetered supplies on capacity data instead of deemed consumption
45.
A radical extension of idea 7 would be to calculate distribution use of system charges
exclusively on the basis of inventory data held by the unmetered supplies office.
Charges would be based on the capacity and operating regime of each inventory item,
and the deemed consumption data created for the purpose of energy settlement would
not be used at all in calculating distribution use of system charges.
7
Idea 9: Single one-rate tariff for all unmetered supplies
46.
A simple way of avoiding any discrepancy between non half hourly and half hourly
tariffs is to use exactly the same tariff irrespective of how the energy is settled.
47.
Because of the way data are processed in the settlement system, this option requires a
single unmetered supplies tariff with a single rate to be used. This is because:
(a) data for non half hourly unmetered supplies cannot distinguish between
consumption at different times of day; and
(b) data for half hourly unmetered supplies are not disaggregated between categories
A, B, C and D.
Comparison of ideas 1–9
48.
The group conducted an initial sift of the ideas. This led to the rejection of the
following:
(a) Ideas 2 and 3 were rejected as they did not solve the problem of discrepancies
between half hourly and non half hourly tariffs, or remove the risk that these
discrepancies could unduly affect unmetered supplies’ choice of whether to trade
half hourly.
(b) Ideas 5 and 6 were rejected as they caused significant disturbance to tariffs other
than unmetered tariffs, which was not necessary to address the specific issues
that the working group had been asked to address.
49.
Idea 1 on its own was rejected on the ground that it would lead to an unjustified
overcharge of some types of unmetered supplies, particularly category A (continuous).
This is because under idea 1 the charging rate for each category would be affected by
the coincidence correction factor for unmetered supplies as a whole. That correction
factor may be high due to the seasonal characteristics of the dominant street lighting
loads outlined above. It seems unfair to charge high prices to continuous unmetered
loads simply because a high charge (per unit) for street lighting loads might be
appropriate.
50.
The group then noted some issues with the remaining options.
51.
The base case (separate tariffs for A, B, C and D but no other change to the CDCM
methodology) suffers from undesirable discrepancies between half hourly and non
half hourly tariffs. In particular:
(a) There is an undesirable incentive for continuous unmetered loads to trade non
half hourly.
(b) There is an undesirable incentive for street lighting loads that are considering
consumption management actions to trade non half hourly. Since consumption
management actions for unmetered loads are most likely to fall in the green time
8
band (for example, dimming street lighting in the middle of the night), the
benefits are greater on a single-rate tariff than on a red-amber-green tariff.
52.
Idea 4 would lead to substantial disruption to CDCM tariffs other than for unmetered
supplies.
53.
Ideas 7 and 8 would entail significant changes to billing processes. They would be a
departure from the principle that CDCM charges are levied on the basis of industry
data flows.
54.
Idea 9 would remove the incentive for half hourly unmetered supplies to choose
patterns of operation that reduce load during the DNO’s red time band.
55.
The group discussed the potential significance of these issues.
56.
The problems with the base case and with ideas 4, 7 and 8 were considered to be
significant. Any solution based on these ideas would require a lot of development
work and consultation before it could be taken forward.
57.
By contrast, the group thought that the problem with idea 9 was not, in fact, a major
issue. This is because the vast majority of unmetered loads that could plausibly
change their pattern of operation in response to charges are street lighting loads, and
there is no way in which these street lighting loads could deliver a significant
reduction of consumption at the time during the red time band at which relevant DNO
assets are most likely to require reinforcement, which is well after dusk on winter
weekdays, because public safety requires street lighting to be on at these times.
58.
Thus, abolishing the red/amber/green structure for half hourly settled unmetered
supplies, whilst it might lead to a loss of accuracy at the theoretical level, is unlikely
to cause a commercially or technically significant problem in practice.
Impact assessment for idea 9
59.
The group has conducted an initial assessment of the impact of idea 9 on tariffs in
each DNO area.
60.
The assessment has used, as source data, the most recent CDCM model published by
each DNO (or by the ENA on their behalf) for price-setting purposes.
61.
In the case of SEPD, the most recent model relates to an in-year change due to occur
on 1 July 2011. For the purpose of the impact assessment, the data in that model were
used to populate a full-year model.
62.
Table 3 summarises the impact of idea 9. Negative numbers refer to reductions from
the implementation of idea 9, positive numbers refer to increases from the
implementation of idea 9.
9
Table 3
Summary of the impact of idea 9
Area of impact
Range of magnitude of the impact
Unit rates for LV UMS (Pseudo HH Metered)
Replaces red-amber-green with single rate
Total revenue from half hourly unmetered tariffs
Between –£131,000 and +£534,000
Between –0.170 and +0.351 p/kWh
Between –10.7% and +10.9%
Unit rates for NHH UMS / new UMS tariff
Between –0.005 and +0.001 p/kWh
Between –0.2% and +0.1%
Red unit rates for other half hourly tariffs
Between –0.019 and +0.006 p/kWh
All other unit rates for all other tariffs
Between –0.005 and +0.004 p/kWh
Fixed charges for LV tariffs
Between –0.06 and +0.02 p/day
Fixed charges for HV tariffs
Between –0.19 and +0.04 p/day
Capacity charges
Between –0.01 and +0.00 p/kVA/day
Reactive power charges
Between –0.001 and +0.001 p/kVArh
Revenue by tariff for metered tariffs
Between –£292,000 and +£68,000
Between –0.008 and +0.001 p/kWh
Between –0.4% and +0.4%
63.
In aggregate over the 14 DNO areas, the impact of idea 9 on the total distribution use
of system revenue from half hourly unmetered tariffs is an increase of £1.36 million a
year, from £48.1 million a year to £49.4 million a year (2.8 per cent).
64.
The impact of idea 9 on individual half hourly unmetered users would depend on their
individual inventories as well as on the DNO area in which they are located.
Idea 10: seasonal time bands for half hourly unmetered supplies only
65.
The group was concerned that idea 9 was too simple and may be seen to lead to a loss
of cost-reflectivity, and that there was no good reason why it should lead to an
increase in the total revenue from distribution use of system charges for half hourly
unmetered tariffs.
66.
To address these issues, the group developed idea 10. Idea 10 entails the use of
different time bands for billing of half hourly unmetered tariffs from the red, amber
and green used for billing of other half hourly tariffs.
10
67.
The half hourly unmetered tariff would be billed on the following three time bands:
(a) A black time band which would be similar to (or the same as) the EDCM super
red time band, i.e. restricted to a winter period.
(b) A yellow time band defined as all times which are not in either green or black,
i.e. comprising the amber time band plus the part of the red time band which is
not in black.
(c) The green time band.
68.
One of the drivers for idea 10 was to ensure that expected revenues from non half
hourly unmetered tariffs would be unchanged. To achieve this, the black and yellow
rates would be derived from the red and amber rates in the current CDCM model as
follows:
(a) Yellow rate = amber rate.
(b) Black rate = ( red rate * forecast red consumption – amber rate * (forecast yellow
consumption – forecast amber consumption) ) / (forecast black consumption).
69.
This approach to tariff setting, and the fact that seasonal time bands would only apply
to the half hourlty unmetered tariff, are the things that differentiate idea 10 from idea
6; under idea 6, the calculation of the rates for seasonal time bands would be based on
peaking probabilities corresponding to these seasonal time bands.
70.
Idea 10 could not be expected, by itself, to remove two of the issues outlined above:
(a) the discrepancy between half hourly and non half hourly tariffs; and
(b) the problem that unmetered customers who reduce consumption during the night
would benefit from being on a non half hourly tariff compared to a half hourly
tariff.
71.
However, the group thought that idea 10 should be explored further because it might
enable the implementation of idea 1 (to address discrepancies between half hourly and
non half hourly tariffs) and of compulsory half hourly trading above certain threshold
(to address undue incentives to trade non half hourly).
Elements of an approximate impact assessment for idea 10
72.
DNOs are in the process of collecting data to estimate the effect of idea 10.
73.
To provide an interim assessment, the worked example presented above for ideas 1 to
4 can be used again. In that example, the red time band had 783 hours a year, the
amber time band had 2,741 hours a year, and the green time band had 5,261 hours.
Let us assume that the black time band contains 196 hours a year — one quarter of the
red time band. The yellow time band will therefore have 3,328 hours.
74.
In the worked example, annual half hourly unmetered consumption is split as follows
between red, amber and green:
11
(a) Red 14.3 GWh, equivalent to an average of 18.2 MW.
(b) Amber 26.6 GWh, equivalent to an average of 9.7 MW.
(c) Green 216 GWh, equivalent to an average of 41.1 MW.
75.
Let us assume that the black/yellow/green split for half hourly unmetered is:
(a) Black 8.7 GWh, equivalent to an average of 44.4 MW.
(b) Yellow 32.2 GWh, equivalent to an average of 9.7 MW.
(c) Green 216 GWh, equivalent to an average of 41.1 MW.
76.
The red/amber/green half hourly unmetered tariff from the worked example’s base
case is:
Red 21.586 p/kWh
77.
Amber 2.932 p/kWh
Green 0.609 p/kWh
Applying the rules of idea 10, this gives the following black/yellow/green tariff:
Black 33.940 p/kWh
Yellow 2.932 p/kWh
Green 0.609 p/kWh
78.
In order to combine idea 10 with idea 1, one needs an estimate of the
black/yellow/green distribution of units for unmetered supplies in categories A, B, C
and D.
79.
The only case that can be solved without further information is category A
(continuous). For category A, the weighted average of the black/yellow/green rates
(with black/yellow/green hours as weights) is 2.232 p/kWh.
80.
Table 4 shows the extent to which idea 10, in this hypothetical worked example, has
reduced the discrepancy between half hourly and non half hourly tariffs for a
continuous (category A) unmetered supply, and reduced the possible unfairness
arising from applying the half hourly unmetered tariff to a continuous load.
Table 4
Summary of model results (average p/kWh)
A
B
C
D
HH
Base case
1.323
2.371
3.895
0.466
2.013
Idea 1 (approx)
3.204
1.890
3.033
3.887
Idea 10
1.323
2.371
3.895
0.466
Idea 10+1 (approx)
2.232
2.013
[not estimated in this worked example]
12