Annex N – Marginal cost based tariffs
Introduction
1 In this annex we set out further details our derivation of:
(a)
our (unscaled) marginal cost based BST and retail tariffs from pure
marginal costs, as set out in Section 7; and
(b)
our calculation of BST and retail base tariffs, the above charges scaled
to allow EGAT, MEA and PEA to meet their financial requirements, as
set out in Sections 8 and 9. These revised base tariffs reflect 1999 fuel
cost levels. Actual tariffs paid by consumers will include an Ft
element as described in Section 10 of the main report.
Unscaled marginal costs based tariffs
Unscaled BST
2 We show the calculation of the unscaled BST in Table N.1. The unscaled BST at
each “voltage level”1 is the sum of:
(a)
the generation cost at each voltage level; and
(b)
the cumulative transmission capacity charge at that voltage level.
3 In Part A of the Table we show that the cost of peak generation at the entry to the
transmission system is 1.38 Baht / kWh, and the cost of off-peak energy is 0.78
Baht/kWh. In Part B we show EGAT’s marginal transmission capacity cost
expressed in Baht/kW/month. We have converted this into a Baht/ peak period kWh
charge in Part C of the Table.
4 The marginal costs BST is the sum of the cumulative generation and transmission
marginal costs, which we show in Part E of the Table. When cumulating energy and
transmission marginal costs it is necessary to take appropriate account of transmission
losses2- we reproduce the transmission loss factors in Part D.
We use the term “voltage level” here for convenience. We note that under the proposed structure of
charges, there will be different charges at the exit of the 230:115kV sub-station and at the end of the
115 kV lines, which, strictly speaking, are at the same voltage.
1
2
For example, the peak period marginal cost based BST at exit of 500:230kV substation is the cost of
generation at entry to the transmission system, 1.38 Baht/kWh scaled by the loss factor between the
entry to the transmission system and the exit of the 500:230kV substation, 3.64%, plus the cost of
transmission capacity to the exit of the 500:230kV system, 0.36 Baht/kWh, resulting in a figure of 1.79
Baht/kWh. The cost at the exit of the 230:115/69kV sub-station is the BST at 500:230kV, scaled for
incremental losses in the voltage tier, 0.30%, plus the additional capacity cost, 0.28 Baht/kWh.
1
Unscaled retail tariffs
5 We have calculated unscaled retail tariffs using the following high level steps:
(a)
we calculated the cumulative marginal peak and off-peak generation
costs at each voltage level in MEA’s area and each of PEA’s regions;
(b)
we calculated the cumulative Baht/kW transmission and distribution
capacity costs at each voltage level in MEA’s area and each of PEA’s
regions
(c)
we allocated the B/kW capacity charges to Baht/kWh energy charges
as appropriate for each tariff category. The allocations reflect:
(i)
our recommendations to have demand charges for MGS, LGS
and Specific business customers only; and
(ii)
the desire to preserve continuity with existing arrangements;
(d)
we calculated the sum of generation, transmission and distribution
charges at each voltage level in MEA’s area and in each of PEA’s
regions;
(e)
we calculated nationally averaged values for the sum of generation,
transmission and distribution charges. The national averages reflects
the spread of customers across MEA’s area and each of PEA’s regions
specific to each tariff category;
(f)
we added the customer related charges3 (meter reading billing and
collection charges) for each category to create the unscaled marginal
cost based tariffs.
6 We discuss these steps in more detail below.
7 We present the marginal generation costs at each voltage level in MEA’s area and
each of PEA’s regions in Table N.2. The results are based on:
(a)
the calculated marginal generation cost of 1.38 Baht/kWh during peak
periods and 0.78 Baht/kWh during off-peak periods; and
(b)
the marginal transmission and distribution losses presented in Table
N.3.
3
Customer related costs include meter reading billing and collection, and connection costs. However,
connection costs are only applicable to new customers, since existing customers have already paid a
contribution through existing connection charges.
2
8 We present the cumulated transmission and distribution marginal costs in
Baht/kW in Table N.4. As stated in Annex K, for the purposes of cumulating we have
assumed a stylised model in which energy passes from the EGAT system to:
(a)
MEA at the exit of the 500:230kV sub-station; and
(b)
PEA at the exit of the 230:115/69kV sub-station.
9 The tariff categories can be divided into two classes:
(a)
Smaller customer tariff categories, which will generally be charged
flat rate energy charges4 and monthly standing charges only5:
Residential, SGS, Government, Agricultural pumping and
Temporary customers. For these smaller customers more expensive
metering is unlikely to be cost effective, so all transmission and
distribution capacity costs are allocated to Baht/kWh charges;
(b)
Larger customer tariff categories: MGS, LGS and Specific business
customers6 who be required to migrate to mandatory7 Baht/kW/month
demand charges and differential peak and off-peak Baht/kWh
charges. For these larger customers, for the purpose of calculating
illustrative unscaled charges, we allocated 50% of transmission and
distribution capacity costs to Baht/kWh charges. The remaining costs
are charged as Baht/kW/month charges.
10 The allocation of transmission and distribution capacity costs to peak and off-peak
Baht/kWh in each area/region is shown in Table N.5. We then summed the
generation, transmission, and distribution charges for each category and calculated the
flat rate charges for the smaller tariff categories. We present the aggregated charges
for all categories in Table N.6, and the “flat rate” charge for smaller tariff category in
Table N.7.
11 We calculated the flat rate charges using estimates of the percentage of total
energy consumed during peak hours, calculated from the 1996 TLFS load profile
research data. We show the percentage of total energy that each category consumes
during peak hours in Part A of Table N.7, and the resulting flat rate charges in Part B.
4
Flat rate energy charges = Baht/kWh charges that are not time of day/week dependent
5
Customers in these tariff categories may opt for Time of Use tariffs, which have differential peak and
off-peak energy rates, provided that they install the appropriate metering.
6
Standby and interruptible customers will also fall into this category, but these tariffs are derived from
the tariffs for other larger customers and we have discussed only the major tariff categories.
7
Whilst we propose that all such customers should be required to migrate to time of Use tariffs with
differential peak and off-peak energy rates, we recognise that not all such customers currently have
appropriate metering, and that it is impractical to require them all install such metering immediately.
Therefore a transition tariff, with a single rate B/kWh will also be necessary.
3
12 We then calculated nationally averaged generation, transmission and distribution
charges in the following way:
(a)
smaller customers tariff categories: we weighted the charges in
MEA’s area and each of PEA’s regions using data specific to each
category8. The calculation and the resulting weighted averages for
each of the smaller tariff categories are shown in Table N.8.
(b)
larger customer tariff categories: we calculated nationally averaged
aggregated charge by weighting together the charges presented in
Table N.6 by the weights for the aggregate of all three classes. We
considered weighting the charges to reflect the spread of customers in
each separate tariff category, but this would result in slightly different
charges for neighbouring MGS/LGS/Specific business customers9,
which would be hard to justify on equity grounds and might result in
perverse incentives. The weights and the resulting nationally averaged
charges are shown in Table N.9.
13 The only customer related costs to be reflected in tariff for existing customers are
marginal meter reading, billing and collection (MRBC) costs, which we have shown
in Table N.10.
14 Finally we summed the generation, transmission and distribution and the marginal
MRBC cost to derive the unscaled marginal cost based tariffs, which we present in
Table N.11.
Scaled tariffs
15 In Sections 8 and 9 we presented revised BST and retail base tariffs scaled to
allow EGAT, MEA and PEA to meet their combined financial requirements. We
show the calculation of these numbers in more detail below.
16 We calculated the scaled tariffs using the following high level steps:
(a)
we unbundled the accounts for EGAT’s generation and transmission
businesses, and both MEA’s and PEA’s distribution and retail supply
businesses;
(b)
we calculated financial requirements for each of the separate
businesses, and a combined financial requirement for:
(i)
the aggregate of MEA’s and PEA’s distribution businesses;
(ii)
the aggregate of MEA’s and PEA’s retail supply businesses;
8
We used forecast annual consumption for FY 1999 from the TLFS September 1998 forecasts to
generate the weights
9
See Part B of the Table, where we also show the impact of weighting by each separate tariff category
4
(c)
we scaled the generation, transmission, distribution and retail supply
costs separately so that the NPV earned from the scaled charges would
equal the NPV10 of the financial requirement of EGAT’s generation,
EGAT’s transmission, the aggregate of MEA’s and PEA’s distribution
businesses and the aggregate of MEA’s and PEA’s retail supply
businesses respectively11. The financial requirements are shown in
nominal terms in Table N.12. These financial requirements were
generated by the first iteration of the financial model. The Base
Allowed Revenues presented in Section 5 and Annex G have the same
NPV as the financial requirements in Table N.12, but reflect the actual
tariff revenue profile (i.e. the results of the scaling exercise) rather than
the financial requirement used to generate the scaled tariffs;
(d)
we summed:
(i)
the scaled generation and transmission charges at each
voltage level to calculate the scaled BST; and
(ii)
the scaled generation, transmission, distribution and retail
supply charges to calculate scaled “target” retail tariffs,
and adjusted them in the light of agreed policy constraints
in order to calculate recommended retail tariffs.
17 The high level steps are explained in more detail below.
Calculation of scaled generation and transmission charges, and BST
18 In Table N.13 we show the calculation of the scaled generation charges at each
transmission voltage level12. In Part A of the Table we show the unscaled generation
charges. The charges are calculated by applying the loss factors presented in Table
N.1 to the cost of generation at entry to the transmission system, 1.38 Baht/kWh
during peak periods and 0.78 Baht/kWh during off-peak periods, and therefore
represent the marginal cost of generation at each voltage level.
19 In Part B we show our forecast of EGAT sales by voltage level used to calculate
the required level of scaling. The forecast is consistent with the TLFS September
1998 load forecasts. However, we have:
10
We equated the NPVs using a nominal discount rates of 12.35% (5% inflation and 7% real discount
rate. This is equal to a 12.35% nominal discount rate since 1.05 X 1.07 = 1.1235).
11
Given forecast volumes over the period 2000-03 as per the TLFS September 1998 load forecasts.
We also calculated forecast peak period and off-peak, and peak MW demand for each tariff category
using the TLFS load foreacst and TLFS load profiles from the 1996 TLFS load profile research.
12
Shown only for those voltage levels at which bulk supply is taken
5
(a)
split sales at 115/69kV into those at the exit of the 230:115/69kV substation and those at the end of 115kV lines13, based upon the split
provided by EGAT in its demand balance;
(b)
disaggregated into peak period and off-peak period sales, based upon
the TLFS 1996 load profile research data.
20 In Part C of the Table we show the scaling factor that is required to uplift the
unscaled charges to ensure that generation charges covers EGAT’s generation
financial requirements. In Part D we show the resulting scaled charges, and in Part E
we show the calculation of the resulting revenue from scaled generation charges and
the reconciliation between revenues from scaled charges and the financial
requirement. The NPVs in the Table and all other tables in this Annex are presented
in FY1998 values.
21 In Table N.14 we show the scaling calculation for transmission capacity charges
(calculated using the same methodology). The data is presented in the same format as
the calculation for generation. In Table N.15 we show how we calculate the BST by
summing generation and transmission charges.
Calculation of scaled distribution, retail supply charges and retail tariffs
22 In this annex we explain the calculation of the recommended tariffs.
calculated the recommended tariffs by calculating:
We

“Target tariffs”. Tariffs, fully rebalanced to reflect marginal costs,
after scaling to meet EGAT, MEA and PEA’s financial
requirements; and then

“Recommended tariffs”. The recommended tariffs have been
calculated by rebalancing existing 1999 total tariffs (1999 base
tariffs plus 1999 Ft) towards target tariffs subject to the policy
constraints on tariff rebalancing agreed with NEPO. The key
constraint is the requirement that the average base tariffs for any
customer category14 should not exceed the average total tariff in
FY1999;
23 In any year of the tariff period FY2000 to FY2003, the total tariffs will comprise
recommended base tariffs plus Ft (which has been rebased and set to zero in FY1999).
24 In the main report we also presented two alternative sets of base retail tariffs

13
“Unrebalanced tariffs”. Existing tariffs uniformly scaled to the new
financial requirements;
There are no sales at the end of 69kV lines
We have defined “customer category” differently from tariff category. See later in the section for
explanation
14
6

“Alternative re-balanced tariffs”.
Existing tariffs rebalanced
towards target tariffs but with a different set policy constraints from
the recommended base tariffs. The key difference is that tariff rebalancing can increase tariffs for any tariff category by up to 10% in
real terms pa.
25 These in Annex R.
Target retail tariffs
26 In calculating scaled target retail tariffs we have reflected:
(a)
Generation: the weighted average of scaled generation costs reflected
in the BST, scaled by nationally averaged distribution losses to each
distribution voltage level;
(b)
Transmission: the weighted average of scaled transmission costs
reflected in the BST, scaled by nationally averaged distribution losses
to each distribution voltage level;
(c)
Distribution:
(d)
(i)
nationally averaged scaled distribution capacity costs;
(ii)
nationally averaged marginal distribution losses
Retail supply related costs: scaled marginal meter reading, billing and
collection costs only, since the other component of customer related
costs, connection costs are to be charged to new customers only, and
are excluded from both revenues and costs in the calculation of
financial requirements and tariffs.
27 We show the weighted average generation and transmission costs in Table N.16
and the nationally averaged distribution losses in Table N.17.
28 We propose that scaled distribution capacity costs be reflected in tariffs in the
following manner:
(a)
smaller customers tariff categories: all costs be allocated to
Baht/kWh charges;
(b)
larger customer tariff categories: 100% of scaled distribution
charges for MGS, LGS and Specific business customers be
reflected as Baht/kW/month demand charges. The reason for this
proposal is that the allocation of all scaled transmission costs to
Baht/kWh charges and all scaled distribution costs to Baht/kW/month
charges results in Baht/kW/month charges that are similar in
magnitude to current charges.
7
29 To calculate standardised national distribution charges we have included the cost
of MEA’s 230kV system in with its 115/69kV system, and it is this cost which is
reflected in the nationally averaged charge for the 115/69kV system.
30 We show the calculation of the scaled, nationally averaged distribution charge and
reconcile the revenue received from the scaled charges with the financial requirement
for distribution in Table N.18. The cumulated distribution charges are calculated
based on the distribution losses in Table N.17, and the reconciliation is calculated
using forecast retail sales volumes presented in Table N.1915.
31 We then calculated “flat rate” Baht/kWh generation, transmission and distribution
charges for smaller customers from the peak and off-peak charges. The calculation is
shown in Table N.20. In Part A of the Table we show the unbundled peak and offpeak charges. In Part B we show, for each tariff category, the percentage of total
consumption consumed during the peak. We used the national average figure for the
category. We calculated the national average by weighting together the percentages
for each tariff category in MEA’s area and each of PEA’s regions 16, using forecast
consumption in FY 2000. In Part C of the Table we show the resulting unbundled
“flat rate” charges.
32 In Table N.21 we show the aggregation of generation, transmission and
distribution charges for MGS, LGS and Specific business customers.
33 In Table N.22 we show the scaling calculation for retail supply related costs, and
in Table N.23 we add together the charges for generation, transmission, distribution
and retail supply related costs and present a summary of the target retail base tariffs.
34 In Table N.24 we show the forecast revenue resulting from the target retail
tariffs17 for FY2000.
Recommended base retail tariffs
35 The target base tariffs do not take account of policy constraints on tariff
rebalancing. We calculated recommended base tariffs based upon the following key
policy constraints.
(a)
the need to maintain a progressive block for residential customers
which ensures that larger residential customers continue to crosssubsidise smaller residential customers (less than 150kWh/month).
Cross-subsidy will remain greatest for very small consumers, those
with consumption less than 35 kWh/month;
15
The MW demand, and peak and off-peak volume forecasts for each tariff category were calculated
from the TLFS September 1998 forecasts using data on load profiles from the TLFS 1996 load research
project
16
As estimated by the TLFS 1996 load research project
17
Calculated by multiplying target tariffs by forecast consumption in Table N.19
8
(b)
the average unit base tariff for each customer category in FY2000
should be no more than the average total tariff in FY 1999. For this
purpose we have defined customer category to mean tariff category,
the following exceptions:
(i)
given the need to cross-subsidise smaller residential
customers we have viewed residential customers as three
customer categories, very small (less than 35kWh/month),
small (35-150kWh/month) and large (150+ kWh/month);
(ii)
we have viewed MGS, LGS and Specific Business customers,
as single group, since we recommend a unified Baht/kW and
Baht/kWh tariff for them; and
(iii)
we did not apply this constraint to streetlighting, for which a
tariff is being introduced for the first time18;
36 In Table N.25 we show that target tariffs exceed current tariffs for residential
customers, agricultural customers and government customers. Therefore we have to
calculate revised tariffs for these customers which are consistent with the policy
constraints.
37 In Table N.26 we show how we calculated our recommended progressive block
structure for residential customers. In order to calculate such a progressive block
structure we:
(a)
calculated the average tariff paid by three representative consumers: a
very small customer consuming 35kWh per month; a small customer
consuming 150kWh per month, and a large customer consuming
450kWh per month (the average consumption for customer consuming
in excess of 150kWh per month);
(b)
calculated new base tariffs, which equated the charges paid by three
representative consumers with the 1999 average tariff. We have
simplified the progressive block structure by reducing the number of
blocks from eight to three. We proposed that very small customers
should not face a monthly charge, accordingly we have set the
Baht/kWh charge for the first 35kWh in FY2000 so that the
representative very small customer faces no increase (or decrease) in
average tariff. We propose small customers should pay half the target
monthly charge, and have set the Baht/kWh charge for the 35th to 150th
Baht/kWh in FY2000 so that the representative small customer faces
no increase (or decrease) in tariffs. We propose that large residential
customers should pay the full target monthly charge, and have set the
Baht/kWh charge so that the representative large residential customer
faces no increase (or decrease) in charges in FY2000;
18
We understand that under some abnormal circumstances, a very small percentage of streetlighting is
currently charged for
9
38 In order to forecast the impact of these recommended tariffs on revenues received
by MEA and PEA we forecast:
(i)
the number of customers whose monthly consumption was in
each of the bands 0-35 kWh (very small customers), 35150kWh (small customers) and more than 150kWh (large
customers);
(ii)
the volume of consumption in each band (i.e the first 35 kWh
per month, the 35th-150th kWh per month, more than 150kWh)
39 The forecasts were based upon the TLFS aggregate load forecasts for residential
volumes and customer numbers and sample data provided by MEA and PEA. Our
forecasts are presented in Table N.27.
40 In Table N.28 we show the calculation of recommended tariffs for agricultural
pumping. We calculated the recommended Baht/kWh and Baht/month charges by
setting the Baht/month charges at the target rate, and adjusting the Baht/kWh charges
appropriately to achieve an average tariff equal to the 1999 average tariff.
41 In Table N.29 we show the calculation of the recommended government tariffs.
Again, we have adjusted the Baht/kWh charges to meet the constraint, and reflected
the full Baht/month target tariff in the recommended tariff19.
42 .These policy constraints mean that it is not possible to fully rebalance tariffs, i.e.
it is necessary to have cross-subsidy between customer categories. Agricultural
pumping, residential and government tariffs are cross-subsidised by charges in excess
of target tariffs levied on other categories.
43 We have levied an additional charge of 25% of target tariffs on temporary tariffs
as measure to incentivise temporary tariff customers to move on to permanent tariff
category, and have levied additional charge of just over 3% on SGS, MGS, LGS,
Specific business and streetlighting tariffs, which is the amount necessary to recover
the cross-subsidy in favour of agricultural, residential and government customers.
44 We show the calculation of the recommended charges for temporary, SGS, MGS,
LGS, Specific Business and streetlighting in Table N.30.
45 In Table N.31, we summarise the resulting recommended retail tariffs for each
year. In Table N.32 we show the revenues received by MEA and PEA, based upon
the load forecasts and the recommended tariff revenues, and in Table N.33 we show
the reconciliation of these revenues with the aggregate sector financial requirement
(the sum of generation, transmission, distribution and retailing revenues).
19
We have taken this approach because, we have offset these reductions in tariffs against the monopoly
distribution and transmission charges for agriculutral and government customers, which are Baht/kWh
charges.
10
46 In Tables N.34 and N.35 we show the recommended tariffs for FY2000,
unbundled into the generation, transmission, distribution and retail components. The
unbundled tariffs reflect the scaled generation, transmission, distribution and retail
charges and the allocations of the cross subsidy (necessary in the light of policy
constraints).
47 We have made in a manner which does not distort competition. The key principle
is that TUOS and DUOS charges payable by independent suppliers in respect of free
customers (MGS, LGS and Specific Business customers) should be the same as the
transmission and distribution components of the published retail tariff for those
categories. Therefore we have allocated the additional charges necessary to cover the
cross-subsidy to distribution charges, and set the DUOS charges equal to the
distribution charges, inclusive of the cross-subsidy element.
48 The tariff categories which are receiving the cross-subsidy, residential,
agricultural pumping and government are all captive customers20, so the allocation of
cross-subsidy has no implications for competition. We have allocated the reductions
in charges to distribution. However, where the reduction in charges exceeds the
distribution charge, we have allocated the charges to transmission and then to retailing
(monthly) charges.
20
i.e. not free customers
11