cost of supply study for the city of ekurhuleni: a case study · premset mv switchgear level...
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Wilson recognised that, in order to be successful, a modern electricity utility has to complete a cost of supply (CoS) study in line with the principles of NRS 058 which prescribes how to regulate energy prices to different customer classes while being fair and equitable and at the same time yielding the expected budgetary income per annum.
To achieve this, the following specific objectives must be addressed:
l Understand the cost of electricity, from purchase to consumption, including technical and non technical losses.
l Understand the cost of equipment, from new equipment to replacing existing equipment.
l Understand the cost of support (people), from electrical employees (maintain and expand), to support functions e.g. financial, legal employees (billing).
l Understand the cost of cross-subsidisation, social responsibilities and prescribed price brackets by NERSA.
Reference to NRS 058
The NRS 058 document is used as guide to this study. Therefore, there will be constant referencing, quotes and direct text, tables and pictures used from the document. By no means do the authors claim the NRS 058 as their own work. Referencing to the NRS 058 document will be per paragraph number in brackets e.g. (NRS 058:3.4.2).
As far as possible, the aim of the model is to keep it as simple as possible, without losing credibility and accuracy to ensure the following objectives are met as documented in the NRS document.
The total cost of supply is given by the equation: (see eqn. 1 below).
Where:
Cost of supply: The total cost of supply in c/kWh per tariff group
Power cost: The total cost of energy purchases, including technical losses in c/kWh
Parts cost: Capital/maintenance cost apportioned per tariff group in c/kWh
People cost: Cost of the electrical department cost in c/kWh apportioned to tariff group
Pain cost: The cost of non-technical losses apportioned per tariff group in c/kWh
Profit: Average c/kWh contributing to the surplus is calculated as the planned surplus amount divided by the energy sold
NRS 058 – assumptions
NRS 058 provides clear guidelines to conduct a cost of supply study. Some trade-offs and assumptions however had to be made.
Consumption categories (NRS 058: 4.2.2.1)
The following different consumption categories proposed by NRS 058 are used in the study:
l Residential
l Commercial
l Industrial
l Reselling
l Losses:
-Technical
-Non-technical
Voltage/geographical location of the supply to a customer (NRS 058:4.1.4)
Due to the size of the COE supply area it was decided not to apply any geographic location factors or differentiation. Although the voltage levels used for this study are not the same as the NRS 058, it was agreed that the voltage levels in Table 2 will be used in the study.
These voltage differentiations are also reflected in the existing energy rates of the bulk consumption tariffs. These percentages differentiation in energy rates due to voltage levels were used as the first iteration of technical losses due to voltage levels.
To date COE have used a fixed value of 5,9% for technical losses based on previous high level engineering studies. A need has arisen to test this value for adequacy using engineering models. Technical losses are due to energy dissipated in the electrical components that make up the electrical distribution system and predominantly occur in the transmission/distribution lines, cables and transformers.
Auxiliary equipment used for metering and protection devices require energy that are not recovered by the direct billing.
The network model in the PowaMaster software was used to calculate the theoretical technical losses related to the COE network. A significant amount of work was required to enhance the PowaMaster model to include the complete medium voltage network as well as all the MV/LV transformer points. The Alberton network was selected as the network to be enhanced for detailed technical loss calculation.
The technical loss calculation approach in PowaMaster was broken up into a number of steps:
l Prepare the model in PowaMaster by adding electrical loads to the network at each MV/LV transformer supply point in the network by interconnecting the loads with sections of cable.
l Setup and scale the loads in PowaMaster to reflect the loads as recorded in the metering online (MOL) data.
l Create an Excel integration tool to automatically extract the losses results from the PowaMaster calculation results to report in the technical losses consumed in the electrical network.
Cost of supply study for the city of Ekurhuleni: a case studyby Stephen Delport, City of Ekurhuleni and Dr. Johan Delport, Electrical Energy Management Systems
The City of Ekurhuleni (COE) has been updating its set of tariffs on a yearly basis. The cost of supply study project was initiated by Mark Wilson, the head of the energy department. This was a ground breaking project in that it was one of the first detailed cost of supply study completed for the COE.
Eqn. 1: Cost of supply calculation.
Abbreviations Description
COE City of Ekurhuleni
FBE Free basic electricity
HV High voltage 22 kV – 132 kV
IMS Intelligent metering system
LV Low voltage 400/230 V
MOL Metering online
MV Medium voltage 6,6 kV to 11 kV
NAC No access charge
NRS 058 Cost of supply methodology for application in the electrical distribution industry
POD Point of delivery (normally Eskom supply point)
SUPRIMA Prepaid vending system used by the city of Ekurhuleni
VENUS Billing system used by the city of Ekurhuleni
Table 1: Abbreviations used.
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l Create a load sweep automation in Excel to automatically generate a set of technical loss results for changes in network load.
To adjust for higher losses at lower voltages Table 3 was used to distribute losses at different voltage levels. Using this table, the total losses is equal to the 4,46% calculated theoretical technical losses.
All the technical losses are differentiated by voltages only. From Table 3 it can be seen that lower loss factors are applied at higher voltages. The geographical location and the distance from the point of supply is not part of the model. It is assumed that COE is in “one distance zone”.
All 55 of the point of deliveries (PODs) are summated and used as one big POD. The following adjustments were made when the cost of the supply of electricity was calculated:
l Number of PODs for administration and service charges.
l Diversity between PODs when calculating the demand cost.
Constructing load profiles per tariff group
One of the main focus areas was the construction of a disaggregated load profile for the COE energy balance. To calculate the cost of supply for each tariff component it is important to have the contributing (disaggregated) load profile of each tariff group. This profile will be used to calculate each tariff group’s specific cost components based on the profile.
Available data
Eskom data was received and loaded into a MySQL database. Queries were run against the data to aggregate the total supply at various Eskom PODs. This was compared to internal COE summaries and agreed well.
Metering online (MOL) provided a large data dump of all interval meters. Data was analysed and all the tariff groups were identified. Queries were run against the database to obtain the load profile for each of the tariffs groups.
Data for the study have been extracted from IMS and SUPRIMA, loaded in the MySQL database. Queries were run against the data to obtain total monthly energy consumption and FBE figures.
The data of the following consumers/consumer group’s data were received from COE as monthly figures:
l Conventional residential and conventional commercial as a group. The initial idea was to run queries against the Venus system data.
l All CCC's streetlights and masts lighting and traffic lights. A spreadsheet with equipment counts were used to derive a load profile.
l Departmental civic centre use.
Construction of load profiles and energy balance
The main purpose of this analysis is to produce half-hourly load profiles per tariff group and voltage. There are currently ±45 variations on the current ±8 COE tariffs.
At this point the available data is used to do a first iteration of comparing the half hourly data available with the summary of COE.
The data compared favourably with the COE summaries and therefore the load profiles obtained from the raw analysis have been used in the study.
The process followed was to summate all the Eskom PODs and obtain:
l Half-hourly data.
l Sum of the maximum demand of each POD.
l Contribution of each PODs maximum demand to the maximum demand of Eskom.
l This diversity was used when calculating the total cost of supply.
The maximum demand was compared with MOL data:
l Use all the meters of the PODs.
l Add the half hourly data of all the PODs together and get the monthly maximum demands (MD sum of PODs).
The MOL data was analysed and the following was obtained per tariff group:
l Half-hourly data per tariff group.
l Maximum demand of each tariff group.
l Sum of the maximum demand of each tariff group. Add the monthly maximum demand of all the PODs together (sum of MDs). This is from the COE data supplied in sheet Eskom.
l Contribution of each tariff group’s maximum demand to the maximum demand of Eskom.
The original objective was to obtain the conventional residential and commercial readings from Venus. Due to the form of the information in Venus, this was not possible. This tariff group is split into two classes with information received from COE:
l Residential: 77% of total conventional meter readings.
l Commercial: 23% of total conventional meter readings.
The following information is used to construct the half hourly load profiles of the streetlights and high masts:
l From the data in the load is calculated as 16 602 kWh per 30 minutes.
l In other words, a maximum demand of 33 204 kW.
l The power factor used, from the sheet, is 0,87.
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Level Description
Low voltage (LV)
Voltages between 230 V, single phase and 400 V, three phase and 1 kV (included), three phase.
COE also has a tariff differentiation on the 400 V level, Tariff C and Tariff E 400 V substation supply
Medium voltage (MV) Voltages higher than 1 kV up to and including 11 kV
High voltage (HV) Voltages higher than 11 kV.
Table 2: Voltage differentiation.
Voltage level % differentiation in energy rates due to voltage levels
Previous years % was
≤400 V 8,65% 12%
≤400 V and in SUB 5,60% 10%
>400 V and ≤11 kV 3,50% 8%
>11 kV 0,00% 0%
Table 3: Applied loss factors per voltage level.
Fig. 1: Grand total profile for all PODs within COE.
l Winter on time for the lights is from 18h00 to 06h00.
l Summer on time for the lights is from 19h00 to 05h00.
l These assumptions sometimes created “spikes”, or “dips” in the non technical losses profile.
The following information is used to construct the half hourly load profiles of the traffic lights:
l From the data in the load is calculated as 1358 kWh per 30 minutes. In other words, 2716 kW. The power factor used, from the sheet, is 0,87.
l On time for the traffic lights is taken as 24 hours a day.
The departmental civic centre etc. half hourly profile is built up with the following tariff group:
l Ekurhuleni tariff B bus 150 A 3 phase.
l The result is then scaled to get the departmental civic centre etc., total kWh per month.
The all CCC's prepaid + FBE half hourly profile is built up with the following tariff group:
l Greenfield Alberton feeder data from MOL.
l The result is then scaled to get the all CCC's prepaid + FBE total kWh per month.
l This assumption created “spikes”, or “dips” in the non technical losses profile.
l If this assumption created a “spike”, or “dip”, that day was filtered with the previous week, same day, data, or next week, same day, data in the original Greenfield Alberton feeder data from MOL.
The information supplied is used to calculate the technical losses per tariff group, according to the supply voltage. The “direct supply from Eskom” group was put into the supply voltage group <=11 kV.
The following considerations were applied when calculating the losses:
l The total losses is the difference between the total purchases and the sum of the constructed load profiles.
l The total losses is the sum of the technical losses and the non technical losses.
l The more the technical losses, the lower the non technical losses and vice versa.
l For each tariff group, a new load profile
is generated, adding the relevant losses to each current load profile.
l From POs:
-Use all the meters of the Eskom and City Power PODs
-Add the half hourly data of all the PODs together.
l From MOL data:
-Use all the meters of customers
-Add the half hourly data of all the customers together, according to each tariff group and applied losses factor per voltage level.
l From COE data:
-Where there was no half hourly data, the constructed load profiles, described above are used.
Results of the energy balance
Disaggregated load profile
For interest sake an example view of the disaggregated load profiles for the peak week in a winter month is shown below. All 42 tariff variants are show together with the technical and non-technical losses and therefore are very difficult to show. This adds up to the “total purchased”.
In the winter losses comparison above the left axis indicates the scale of losses and the right axis the Eskom purchase totals. It can be seen that the non-technical losses are more than the technical losses. The technical losses follow the form of the Eskom graph. The whole equation balances on the determination of the non-technical losses. This means that when all the various load profiles including calculated technical losses is subtracted from the Eskom purchase totals the non-technical losses value is determined.
Zooming in closer the losses profiles can be compared with the total Eskom purchase.
High-level energy balance
The results of the model (using raw data) for the purchased energy per month and for the year when compared the energy summaries that was provided by COE is less than 0,1%, which indicates that there is a high level of confidence in the internal COE energy totals.
The results of the model (when using raw data) for the purchased demand per month and for the year when compared to the internal COE totals is 0%. Although there are monthly differences the average result for the year is the same for the model and the COE summaries. This is expected, because the average calculated diversity is used by the model. There are some differences per month. This can be addressed by using the monthly diversity factors in the model.
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High-level losses comparison
With the modelled load profiles per tariff group, the losses can be calculated. The technical losses are apportioned with regard to the voltage level, according to the tariff differentiations. It is recognised that there are more ways in which technical losses can occur, but for this study, only the voltage levels are used. The energy figures in kWh results are in the next table.
With higher technical losses one can expect a lower non technical loss percentage. This is given in the next table, with the total losses for the year.
Contribution to electricity cost per tariff group (power cost)
With the disaggregated load profiles per tariff group, the average purchase cost (c/kWh)
per tariff group can be calculated as follow:
l The maximum demand of each month is determined.
l For each tariff group, the half hourly consumption, including the technical losses, is used to calculate the electricity cost.
l Each tariff group’s contribution to the maximum demand of each month is determined.
l The Eskom electricity tariff is applied on the load profile of each tariff group, with the maximum demand value as the contribution to the total maximum demand.
l The total cost per month is divided by the total consumption per tariff group to get the monthly average cost in c/kWh per tariff group per month. This is the consumption only, in other words, kWh that was sold.
l The annual average cost is the sum of the monthly costs divided by the sum of the monthly consumptions, or energy sold, per tariff group.
It is important to remember that this average cost per month is calculated as if the tariff group received its energy at the intake point. In other words, technical losses included. The purchase cost is the average cost per kWh that COE pays Eskom for each kWh that is procured to sell on to a specific tariff group and includes the group’s contribution to maximum demand as well as losses.
It is very important to remember that for the annual average cost per tariff group the energy sold is used. The amount that the tariff groups costs COE is calculated (energy sold and technical losses included). This amount is then divided by the energy sold (only), in other words, the technical losses energy is excluded. Now this amount can be used to calculate the cost of energy sold to a tariff group.
Capital cost per tariff group (parts cost)
The asset list was received from COE. This was summarised into the voltage categories as discussed previously. The category “all other” was added, consisting of non HV, MV and LV related equipment but is needed to run and operate the system. Using this classification, the total asset values were distributed to voltage levels as indicated below.
A methodology was developed to distribute a portion of the total assets to the cost of supply study. The study aims to calculate at each voltage level a c/kWh that needs to be recovered to cover capital costs. The following assumptions were used:
l All tariff groups need the “all other”. They will share in the cost.
l All tariff groups need the HV part. It is apportioned per kWh consumed per tariff group in each voltage level.
l All MV and LV tariff groups need the MV part. It is apportioned per kWh consumed per tariff group in each voltage level.
l All LV tariff groups need the LV part. It is apportioned per kWh consumed per tariff group in each voltage level.
l For calculating the contribution to cost of assets, all total energy is used excluding technical and non technical losses.
l For a first iteration 7% of the asset replacement value will be used for the calculation. That is R1 702 582 925.
When a figure of 7% is applied to the total asset value table above the following values are obtained. What this means is that a total asset value of R1,703-billion would have to be accounted for per year as a c/kWh for every unit sold.
Fig. 2: Winter peak week profile disaggregation.
Fig. 3: Losses and purchase comparison: peak week in July 2014.
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As each lower voltage level needs the higher voltage level network the totals for each voltage level was apportioned to lower voltage levels in the ration of the energy sold at that level. This is also done as a proxy for levels were equipment is upgraded more frequently (LV) than other (HV). So although the total asset value is captured in the table above it is re-apportioned using this methodology to reflect replacement.
Using the above apportionment, the total rand value per voltage level can be used together with the total kWh sold at that level to calculate the average c/kWh that each voltage level need to make to recover 7% of
the total asset value in a given year. The results are summarised in the table below.
Energy department cost per tariff group (people cost)
The cost to operate the electricity department needs to be added to the cost of supply, including maintenance cost. The aim is to distribute a cost per kWh sold to each voltage level that reflects the cost to operate and run the department.
The energy department cost used is the total budget, excluding the following:
l Bulk purchases – electricity
l Depreciation – existing assets. This is assumed to be part of the assets calculation
l Grants and subsidies paid – free basic services – indigents
l Operating surplus
The amount for 2014/2015 was R 3,24-billion.
It would have been easy to apportion this cost to each tariff group if COE kept record of all cost per tariff group. That is not available.
This cost can be apportioned according to energy sold. This will penalise the large consumers, because normally it is not the large consumers that is causing all the “people” cost. It is the residential and small commercial consumers. The apportioning of the energy department cost will be done on the same basis as the asset cost, using the same percentages. It is very important to remember that for this calculation of annual average cost per tariff group for the assets, the energy sold is used.
Surplus
The average c/kWh contributing to the surplus is calculated as the planned surplus amount divided by the energy sold, excluding:
l Technical losses
l Non-technical losses
l Own consumption, like all CCC's street and masts lighting and traffic lights
l Own consumption, like departmental civic centre, etc.
This gives an average of 9,5788c/kWh sold.
Total cost of supply
The next table summarises the results of this study in terms of CoS for power, parts, people, pain and profit per tariff group as calculated as described.
Resellers investigation
This section provides brief comments related to the potential discount that can be provided to the resellers tariff. To obtain a view of a potential discount the advantages and disadvantages needs to be weighed. Some of the cost savings opportunities introduced by resellers are discussed as well as some of the disadvantages introduced by the system. According to the NERSA guidelines on electricity resale:
“8.3. The tariff rates and tariff structure according to which electricity is resold must be identical to the approved tariff rates and tariff structure that would have been applicable had the customer been supplied with electricity by the supplying licensee. This is in line with electricity pricing policy [Position 43(a)], which states that: non-licensed traders of electricity shall provide the electricity at terms, tariffs and services not less favourable than that provided by the licensed distributor in the area.”
This clause clearly states that customers may not be “worse” off procuring energy via a third party than if directly transacting with the supplier (municipality). The municipality may give the resellers a “more favourable” tariff, but this may be to the cost of other customers. This reduced tariff could be linked to the potential reduced costs the municipality incurs due to
Month Purchases (kWh) Technical losses (kWh) Technical losses (%)
201407 934 510 356 42 835 675 4,58%
201408 966 194 059 42 395 552 4,39%
201409 885 390 466 40 298 643 4,55%
201410 912 525 113 40 860 831 4,48%
201411 874 574 269 40 718 832 4,66%
201412 773 998 260 36 414 578 4,70%
201501 817 425 168 38 171 684 4,67%
201502 793 790 396 38 147 313 4,81%
201503 886 762 949 41 143 553 4,64%
201504 820 480 701 40 062 879 4,88%
201505 881 581 589 42 691 841 4,84%
201506 960 636 682 44 325 903 4,61%
Total 10 507 870 008 488 067 284 4,64%
Table 4: Technical losses comparison.
Month Purchases (kWh)
Non-technical losses (kWh)
Non-technical losses (%)
Total losses (kWh)
Total losses (%)
201407 934 510 356 127 173 424 13,61% 170 009 099 18,19%
201408 966 194 059 126 664 336 13,11% 169 059 888 17,50%
201409 885 390 466 77 926 642 8,80% 118 225 285 13,35%
201410 912 525 113 77 137 371 8,45% 117 998 202 12,93%
201411 874 574 269 56 883 335 6,50% 97 602 167 11,16%
201412 773 998 260 48 921 290 6,32% 85 335 868 11,03%
201501 817 425 168 54 195 473 6,63% 92 367 157 11,30%
201502 793 790 396 32 045 133 4,04% 70 192 446 8,84%
201503 886 762 949 47 146 072 5,32% 88 289 626 9,96%
201504 820 480 701 34 077 389 4,15% 74 140 268 9,04%
201505 881 581 589 46 077 880 5,23% 88 769 721 10,07%
201506 960 636 682 97 371 431 10,14% 141 697 334 14,75%
Total 10 507 870 008 825 619 776 7,86% 1 313 687 061 12,50%
Table 5: Non-technical losses and total losses comparison.
Voltage level Total rand value of assets
HV R4 408 160 944
MV R17 602 726 691
LV R1 250 356 342
All other R1 061 369 235
Total R24 322 613 211
Table 6: Asset value per voltage level.
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the services the reseller is providing. Some of these potential cost savings components are:
l Application of TOU tariff to resellers: It enables the licensee to charge a time of use (TOU) to residential end user load.
l Administration of accounts: All the account administration of the end users is undertaken by the reseller. The municipality only deals with one account of the reseller.
l Meter reading services (conventional or AMR): There is one meter to read instead of many end user meters. That burden is shifted to the reseller.
l Reduced risk: The collection of monies due is simplified to one customer. The reseller is burdened with collecting the amounts due from the end users.
l M a i n t e n a n c e : U n l e s s t h e r e i s a maintenance agreement with the municipality that burden is carried by the reseller as a contractually appointed building management agent.
l Capital cost: Normally the capital cost of supplying a point with electricity is paid by the customer or developer, not the Reseller. This cannot be seen as a benefit to either the municipality or the reseller.
The results of the CoS study have shown that the percentage of cost that will be for the reseller’s account is very small. This means the benefit that the reseller can get because of reduced cost to the municipality is very small.
What are the disadvantages of resellers to municipalities?
l Complaints, dispute resolution, quality of service, tariffs and pricing principles, and billing: Municipalities will receive complaints from reseller’s customers.
l Resellers operate outside the energy regulator’s radar screen: It is almost impossible for the end user to receive the benefits of programmes such as Free Basic Electricity even eligible, to the detriment of poor customers.
l Activities of resellers are currently unregulated: This means that the end user is at the mercy of the reseller. It also means that the energy regulator has no sight of their business, the customer and tariff data.
Voltage level 7% Rand value of assets
HV R308 571 266
MV R1 232 190 868
LV R87 524 944
All other R74 295 846
Total R1 702 582 925
Table 7: 7% of asset value per voltage level.
Voltage level HV MV LV All other Total per
voltage level
HV R37 814 990 - - R9 104 855 R46 919 845
MV R120 967 873 R550 515 433 - R29 125 883 R700 609 189
LV R149 788 403 R681 675 435 R87 524 944 R36 065 108 R955 053 890
Total R308 571 266 R1 232 190 868 R87 524 944 R74 295 846 R1 702 582 925
Table 8: Contribution of voltage levels to asset value according to assumptions.
Voltage levelTotal per voltage
levelkWh sold excluding
lossesc/kWh contribution to assets annual average
HV R46 919 845 1 233 307 769 4,2077
MV R700 609 189 3 945 277 172 19,6406
LV R955 053 890 4 885 237 309 21,6221
Total R1 702 582 925 10 063 822 251 16,9179
Table 9: Contribution in c/kWh per voltage level for assets.
Voltage level
% apportioning per voltage
level
Rand for energy department
Energy per voltage level sold excluding
losses (kWh)
People c/kWh per
voltage level
HV 18,95% R614 254 885 1 233 307 769 6,1036
MV 75,67% R2 452 850 747 3 945 277 172 37,5398
LV 5,38% R174 230 819 4 885 237 309 41,4915
Total 100,00% R3 241 336 451 10 063 822 251
Table 10: Contribution in c/kWh per voltage level for energy department cost.
l Pricing structure/excessive tariffs: Their customer base is captive and vulnerable to being charged exorbitant prices with minimal prospects for recourse. Some resellers charge tariffs above the approved tariffs by NERSA for a municipality.
With the information currently available, it is not possible to recommend what “discount” or “more favourable tariff ” a reseller is entitled to. What needs to be quantified is how much the resellers is savings the municipality. To ensure that the benefits accruing to the municipality is derived it would be necessary to police all of the above. This will add another burden to the municipality.
It is proposed that a study be completed to quantify the actual cost per customer per tariff group to the municipality. That will include things like meter reading (manual or AMR), bills, stamps, envelopes, chasing of payments, non-technical losses, etc. The outcomes of this study will help to quantify the benefits that could be passed on to the reseller segments, if any.
Possible changes in tariffs and motivations
It is not meaningful to propose ways to address the reasons why the CoS per tariff group is more than the income derived for some tariff groups. It was already shown that
the changes in the number of customers per tariff group, load factors, etc., is the main drivers of the cost of electricity per tariff group. This means that every time there is a CoS study, there will be tariff groups that costs more than what the group’s income is. Of course one may look at a tariff group individually and evaluate the different elements of the tariff, but that will also change during a year.
The biggest differences may be evaluated annually, especially where there are large cross subsidisations. It may not be possible to change some of the tariffs, but the cross-subsidisation may be quantified.
One alternative is that one may relook the methodology used to calculate the contribution of each cost of supply component (power, parts, people, pain, and profit) to the total cost calculated. Some of the options/questions that can be explored are:
l Is the use of the voltage level the only way to calculate the contribution to the cost of the parts and the people per tariff group?
l Should the analysis also take the number of customers per tariff group into consideration?
l Hould parts and people cost be added as a c/kWh or as a fixed charge per customer or a combination?
l How will the financial system be able to handle different options?
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20 65th AMEU Convention 2016
One may also relook at the actual budgeted figures used for the study. For example, the study showed that the cost of electricity (sold including technical and non-technical losses) is only 61,0% and the combined cost of parts and people the remaining 39,0%.
Currently the budgeted surplus is 6,6%. NERSA’s guideline allows for electricity cost to be 75% and other cost 25% of the total. It is recommended to change parts and people cost contribution to proposed NERSA allowance of 25% by adjusting assets to 2,45% and people to 60% of the current figures. By adjusting these figures, the cost of supply model will result in 75% purchase cost and 25%, other cost as stipulated by NERSA’s benchmarks.
If this is done, the cost of electricity (sold and technical and non-technical losses) is 75,3%. The combined cost of parts and people is the other 24,7%. Then the calculated surplus is 8,1%. This is more in line with NERSA’s contribution to electricity cost and other cost, but not yet with the
Tariff group name Power c/kWh
Parts c/kWh
People c/kWh
PAIN (non-technical losses)
c/kWh
Profit (surplus) c/kWh
Total c/kWh, excluding surplus
Total c/kWh, including surplus
Income in c/kWh
Tariff A business 78,6853 21,6221 41,4915 7,9690 9,5788 149,7679 159,3467 159,2372
Tariff B residential 114,3747 21,6221 41,4915 7,9690 9,5788 185,4573 195,0361 141,0023
Tariff C <=11 kV 74,2370 19,6406 37,5398 7,9690 9,5788 139,3864 148,9652 121,6891
Tariff C <=11 kV No NAC 82,0122 19,6406 37,5398 7,9690 9,5788 147,1616 156,7404 118,124
Tariff C 400 V 79,4773 21,6221 41,4915 7,9690 9,5788 150,5599 160,1387 125,3356
Tariff C 400 V (substation supply)
75,8565 21,6221 41,4915 7,9690 9,5788 146,9391 156,5179 125,91
Tariff C off-peak 11kV 78,2243 19,6406 37,5398 7,9690 9,5788 143,3737 152,9525 148,5502
Tariff C off-peak 400V 87,8705 21,6221 41,4915 7,9690 9,5788 158,9531 168,5319 146,9479
Tariff D <=11 kV 68,4470 19,6406 37,5398 7,9690 9,5788 133,5964 143,1752 95,7715
Tariff D > 11 kV 64,1788 4,2077 6,1036 7,9690 9,5788 82,4591 92,0379 86,1888
Tariff D 400 V (substation supply)
101,3359 21,6221 41,4915 7,9690 9,5788 172,4185 181,9973 141,0008
Tariff E <=11 kV 72,3112 19,6406 37,5398 7,9690 9,5788 137,4606 147,0394 111,9694
Tariff E > 11 kV 73,9145 4,2077 6,1036 7,9690 9,5788 92,1948 101,7736 114,2018
Tariff E 400 V 78,7394 21,6221 41,4915 7,9690 9,5788 149,8220 159,4008 128,6043
Tariff E 400 V (substation supply)
75,7176 21,6221 41,4915 7,9690 9,5788 146,8002 156,3790 122,727
Tariff E 400 V No NAC
77,0634 21,6221 41,4915 7,9690 9,5788 148,1460 157,7248 176,2398
Res resellers <=400 V 79,2566 21,6221 41,4915 7,9690 9,5788 150,3392 159,9180 125,0775
Res resellers >400 V 76,2772 19,6406 37,5398 7,9690 9,5788 141,4266 151,0054 125,2634
Conv. residential 76,4706 21,6221 41,4915 7,9690 9,5788 147,5532 157,1320 164,4181
Conv. commercial 79,4517 21,6221 41,4915 7,9690 9,5788 150,5343 160,1131 163,3437
All COE street and masts and taffic lighting
61,5041 21,6221 41,4915 7,9690 9,5788 132,5867 142,1655 130,9752
Departmental, civic centre, etc.
79,2729 21,6221 41,4915 7,9690 9,5788 150,3555 159,9343 130,9752
All COE's prepaid and FBE 79,1639 21,6221 41,4915 7,9690 9,5788 150,2465 159,8253 90,7169
Non-technical losses 89,4247 – – – – 89,4247 89,4247 0
Table 11: Summary of the results of the study in terms of power, parts, people, pain and profit per tariff group.
possible surplus. It may also be that some of the parts and people’s cost can be funded from the surplus, but that will only balance the books to come closer to NERSA’s benchmarks.
Conclusion
It is recommended that all municipalities execute a detailed CoS study. The good data records of the COE assisted in making this study somewhat easier as far as that component goes, but the sheer size of a city made the study fairly complex.
A monthly energy balance that entails comparison between kilowatt-hour units billed (sales) and kilowatt-hour units purchased from Eskom will provide insight in terms of possible energy losses. This information may then be used to execute meter audits to ensure tampering and other non-technical losses are kept as low as is practical.
Any municipality’s electricity tariffs must be derived from a sound basis, taking into account the expected income and expense
figures. Solid statistical figures must be gathered to guide this process.
Further progression of the tariff structure, and especially tariff levels, will only be gained following a CoS study by a specialist tariff consultant with adequate experience in the field of large scale electricity distribution.
Acknowledgement
The author wishes to acknowledge and thank Dr. Freddie Fryer (Ekurhuleni), Tobie Nortje (EON Consulting) as well as Dr. Johan Delport for their comments and editorial contributions.
References
[1] www.meterinonline.com data base
[2] Actual Ekurhuleni metering data via VENUS.
[3] Dr. Johan Delport, Tariff Specialist and Cost of Supply study for Ekurhuleni Metropolitan Municipality 2012/13 and 2014/15.
Contact Stephen Delport, Ekurhuleni Metropolitan Municipaility, Tel 011 999-5263, [email protected]