1
Introduction
In this Final Report, we present the key results and conclusions from all three phases
of our work to review the level and structure of bulk supply and retail electricity
tariffs in Thailand. Where appropriate, we have taken account of comments made
during discussions of the draft of the report.
In this section, we begin by describing the background, objectives and scope of this
review, next, we summarise the phasing of our work and, finally, we describe the
structure of this report. In subsequent sections, we describe the policy objectives and
constraints, the key findings of our investment and operating efficiency reviews, the
financial requirements of the utilities and the calculation of marginal cost based
tariffs. We then recommend practical bulk supply and retail tariffs, which allow the
utilities under efficient operation to meet their financial requirements, and a revised
tariff adjustment mechanism
Background, objectives and scope
1.1
For some years, the Royal Thai Government (RTG) has been promoting a
programme of power sector reform and privatisation as a means to improve efficiency
and to mobilise resources for the sector. This programme has become more urgent
following the economic crisis and severe depreciation of the Baht since July 1997,
which has both substantially reduced expected demand and substantially increased
Baht costs of supply.
1.2
Given the economic circumstances, and the plans for reform and privatisation,
there are concerns that the present tariff arrangements are no longer appropriate.
Accordingly, the RTG, through the National Energy Policy Office (NEPO), has
commissioned this review of tariff structure, level and adjustment mechanism. The
objectives and scope are:
(a)
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relating to tariff levels:
(i)
to review the investment and operating plans of the utilities;
(ii)
to review the financial criteria for setting utilities’ revenue
requirements and, if appropriate, propose revised financial
criteria;
(iii)
to review the remittance rate to government and, if
appropriate, propose a revised remittance rate;
(iv)
to review the current and projected financial performance of
the utilities;
(v)
to review the financial models of the utilities;
(vi)
to estimate efficiency improvement factors, X factors, for the
transmission business of the Electricity Generating Authority
1
of Thailand (EGAT) and the distribution and supply
businesses of the Metropolitan Electricity Authority (MEA)
and the Provincial Electricity Authority (PEA); and
(vii)
(b)
(c)
to determine tariff levels for the period to 2002.
relating to tariff structure:
(i)
to review the bulk supply tariff and associated subsidy
mechanism for rural electrification;
(ii)
to review the need for a uniform national retail tariff and
associated subsidy mechanism;
(iii)
to estimate marginal costs of generation, transmission,
distribution and supply;
(iv)
to recommend the structure of bulk supply tariffs taking into
account underlying marginal costs and any cross-subsidy
necessary in the interest of uniform tariffs; and
(v)
to recommend the structure of retail tariffs taking into account
underlying marginal costs and social considerations;
relating to tariff adjustment:
(i)
to review the mechanism for setting base tariffs and the
mechanism for automatic adjustment;
(ii)
to recommend a mechanism for tariff setting consistent with
the future sector structure which encourages efficiency and
energy conservation; and
(iii)
to recommend a mechanism for tariff adjustment which
encourages efficiency while appropriately balancing the
financial risks facing the utilities and their customers.
Workplan
1.3
We have addressed these objectives and scope of work in three phases:
(a)
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as described in our Inception Report, in Phase I, background review,
efficiency review and diagnostic, we carried out a thorough review of
existing reports and interviewed senior officials to understand the
policy objectives and constraints. We also conducted a brief efficiency
review of the three utilities. We examined the financial performance
of the utilities against the “cash-based” financial criteria introduced in
1996 and we reviewed the financial criteria. We reviewed the present
tariff setting mechanisms. We recommended an approach to locational
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charging. Finally, we examined the suitability of the utilities’ financial
models for use for regulatory purposes in Phase III and concluded that
we should develop a simpler integrated model which can be used with
confidence for regulatory purposes;
(b)
as described in our Interim Report, in Phase II, tariff structure, we
developed estimates of the marginal costs of generation, transmission,
distribution and supply, based on the utilities’ investment and
operational plans, as revised following our Phase I efficiency review.
We determined marginal cost based tariffs for each major tariff
category by weighting these estimates by the customer characteristics
reported by the Thai Load Forecast Sub-committee. Based on this
analysis and other tariff design considerations, we made
recommendations on revisions to tariff structure, which we
subsequently modified following discussion with the Steering
Committee, NEPO and the utilities. We also developed a simpler
integrated financial model of the three utilities. We used this model to
make a preliminary estimate of the overall level of tariffs that allows
the utilities, under efficient operation, to meet the financial criteria.
Finally, we examined the extent of cross-subsidy required among the
utilities (to maintain uniform national tariffs and avoid large tariff
increases for smaller customers) and we identified the extent of crosssubsidy within the present tariff categories; and
(c)
in the last phase, Phase III, tariff levels, in discussion with NEPO and
the utilities, we finalised input data for the financial model. We ran the
financial model under the refined base case and a small number of
sensitivities to establish the overall level of tariffs that allows the
utilities, under efficient operation, to meet the financial criteria without
undue risk. We set bulk supply and retail tariffs by scaling the
marginal cost based tariffs to reach these tariff levels while taking due
account of other policy considerations (eg any cross-subsidy to meet
social objectives). We also recommended a revised tariff adjustment
mechanism. Finally, we prepared this report which brings together the
work in all three phases of the project, taking account of helpful
comments made by the Steering Committee, NEPO, the utilities and
the wider public on the material presented in our Inception and Interim
Reports and in the draft of this report.
Report structure
1.4
Following this introduction, we have set out the remainder of this Final Report
as follows:
(a)
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in Section 2, we summarise the policy objectives and constraints on
the tariff review and our understanding of the priorities and we note the
likely private sector response to the challenges facing the sector;
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(b)
in Section 3, we summarise the key conclusions from our review of
demand forecasts and the investment and operating efficiency of the
utilities;
(c)
in Section 4, we present our proposals for revised financial criteria
which reflect the changed circumstances;
(d)
in Section 5, we present estimates of the financial requirements of
each of the three utilities, based on the financial criteria, and hence
estimates of the overall level of tariffs that allows the utilities to meet
these financial criteria. We also examine the extent of financial
transfer required among the utilities to maintain uniform national
tariffs given the differing costs of supply;
(e)
in Section 6, we describe briefly the methodology used to estimate the
marginal costs of generation, transmission, distribution and supply
and we present our estimates of marginal costs;
(f)
in Section 7, we discuss a number of practical issues related to tariff
design and we present marginal cost based tariffs. We also compare
marginal-cost based tariffs with present tariffs to identify the extent of
cross-subsidy within the present tariff categories;
(g)
in Section 8, we present our recommended bulk supply tariff and the
supporting rationale;
(h)
in Section 9, we present our recommended retail tariffs and
supporting rationale; and
(i)
in Section 10, we propose a revised tariff adjustment mechanism.
1.5
In a separate volume, we present a number of supporting annexes that contain
further details of our analysis.
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2
Policy objectives and constraints
2.1
In this section, we set out our understanding of the policy objectives and
constraints relating to tariff setting and tariff adjustment. This understanding is based
on discussions with the Minister, members of the Steering Committee and with senior
officials of NEPO and the utilities, and on our background review of existing policy
documents such as the Privatisation Master Plan. We also note the implications of
these policy objectives and constraints for tariff design. Finally, we note the likely
private sector response to the challenges facing the sector.
Policy objectives
2.2
This tariff review has been triggered primarily by the economic crisis in
Thailand, and is being undertaken against the background of the intended shift of the
sector towards greater private sector ownership and more competitive market
arrangements.
2.3
The combination of these two factors has prompted policy makers in
Government and NEPO to question whether the current regulatory arrangements and
tariff adjustment mechanisms are now delivering tariffs which are appropriate in
current circumstances. More specifically, we were asked to consider, as a key policy
objective in this review, how tariffs might have been affected in the current economic
downturn had the sector already moved to a more privately owned and competitive
structure – and, where possible, to introduce recommendations on tariff levels,
structure and adjustments mechanisms which more closely reflect what might prevail
in such circumstances. This is seen as desirable in its own right, and consistent with
the intended reform of the sector over the next few years.
Tariff objectives
2.4
Our recommendations on tariff levels, structure and adjustment mechanisms
take the key policy objective discussed above as a guiding principle, and, in addition,
seek to meet the following specific tariff design objectives:
(a)
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efficiency: the tariff regime should promote efficiency in the sector,
both in terms of:
(i)
allocative efficiency: the tariff should reflect underlying
marginal costs of electricity provision, allowing producers
and consumers to allocate resources efficiently in response to
tariff price signals. For example, with electricity prices
reflecting marginal costs, consumers face the correct incentive
when considering extra electricity consumption or an
investment in energy efficiency;
(ii)
productive efficiency: the cost of electricity provision should
be the lowest possible consistent with the required quality of
service, reflecting efficient investment and operation. Market
discipline can ensure efficient provision in generation and
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supply where effective competition can be developed.
However, regulatory controls will be necessary until effective
competition in generation and supply is established and to
ensure efficient provision in transmission and distribution
which are natural monopolies;
(b)
equity: the tariff regime should recognise wider policy objectives by:
(i)
preserving a degree of cross-subsidy: to support low income
customers and to maintain the uniform national tariff at
least for the present (currently, MEA and PEA apply the same
tariff throughout the country, although it is more expensive to
supply customers in areas of low load density than in areas of
high load density). In due course, we understand that the
uniform national tariff will be phased-out;
(ii)
appropriately balancing the interests of the utilities and their
customers: there is some concern that the present tariff setting
mechanism may have unduly insulated the utilities from the
consequences of the economic crisis;
(iii)
ensuring a level playing field between utilities and competing
suppliers (initially, we understand only small power producers
(SPPs) will compete to supply final customers);
(c)
cost recovery: the tariff regime should allow the utilities sufficient
revenue to finance an efficient investment programme and to cover
efficiently incurred operation costs, including an appropriate return
commensurate with the risks of their business;
(d)
simplicity: the tariff regime should be understood by customers.
Large customers are sophisticated users and should be able to
understand and respond to more complex price signals than small
customers;
(e)
stability: the tariff regime should be relatively stable to give producers
and consumers confidence to make investment decisions based on the
tariff price signals; and
(f)
ease of implementation: the tariff regime should ensure any
transaction costs associated with implementation are exceeded by
benefits. In particular, metering costs mean that complex tariff
structures may not be appropriate for low volume customers.
Key constraints
2.5
The key tariff policy constraints are:
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(a)
to accommodate medium-term sector structure and ownership
changes: the tariff regime should be robust to
(i)
the separation of EGAT’s generation and transmission assets;
(ii)
the split of PEA into a number of distribution/supply
companies;
(iii)
the development of a wholesale electricity market (power
pool) from 2003; and
(iv)
the extension of retail competition to more final customers
(b)
to accommodate short-term open access: the tariff regime should
include unbundled transmission and distribution charges to enable
open access by SPPs to compete to supply final customers located on
industrial estates;
(c)
to avoid changes that could provide grounds for legal challenge and
compensation claims, for example, any changes which cast doubts on
the existing tariff adjustment mechanism.
2.6
We note that these policy objectives and constraints inevitably conflict. For
example, tariff levels that encourage productive efficiency may impede cost recovery
and tariff structures that encourage allocative efficiency may be inequitable.
Accordingly, tariff design involves judgements about the appropriate trade-offs
among the objectives and constraints.
Implications
2.7
We set out below the implications for tariff design which we have drawn from
these policy objectives and constraints. We describe in turn the implications for tariff
structure, tariff level and tariff adjustments which shape our later recommendations.
Tariff structure
2.8
The key implications are:
(a)
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tariffs should be unbundled to identify clearly the components relating
to generation, transmission, distribution and supply. This is because:
(i)
the transmission and distribution components will be required
as the basis for deriving open access “use of system” charges,
(ii)
this transparency will help to ensure that the utilities cannot
cross-subsidise their (potentially) competitive activities from
their monopoly activities;
7
(iii)
(b)
the separation will be more consistent with the medium-term
sector reform;
tariff structure should reflect underlying marginal costs as far as
possible, but allowing for essential cross-subsidy to:
(i)
protect low income customers;
(ii)
maintain, at least for the tariff review period (FY2000 to
FY2003), the uniform national tariffs;
(c)
generation and transmission tariff structures should preserve flexibility
to accommodate future wholesale market designs; and
(d)
in the medium-term, when EGAT ceases to be a central purchaser,
generation or transmission prices should provide signals to potential
independent generators about the costs of locating new generation in
differing areas (and, in principle, should provide similar signals to
potential new loads-though these generally have little choice of
location).
Tariff level
2.9
The key implications for tariff levels are:
(a)
levels should be set to reflect the costs of “efficient” investment and
operation, rather than the actual costs of the utilities to provide the
required quality of service, to place clear incentives on the utilities to
operate efficiently;
(b)
in the medium-term, tariff levels should be consistent with the
introduction of a wholesale market and private sector ownership.
Accordingly, to avoid step changes, there should be a controlled
transition so that by the medium-term, generation tariffs reflect the
levels which will prevail in a competitive wholesale market; and
(c)
administrative measures, such as levies, may be necessary to maintain
cross-subsidy from any parts of the market subject to competition and
to ensure a “level playing field” between EGAT, MEA and PEA and
new suppliers. Without such measures, free1 customers will migrate to
independent suppliers to escape the cost of cross-subsidy to other
customers.
Tariff adjustments
2.10
The key implications for tariff adjustments are:
Here and elsewhere in the text, we use the term “free” customer for customers eligible to receive
supply from suppliers other than EGAT, MEA and PEA.
1
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(a)
(b)
the base tariff setting mechanism should:
(i)
provide separate transitional regulatory control over
generation, transmission, distribution and supply activities
which simulate market disciplines;
(ii)
allow for cross-subsidy from high income to low income
customers and from MEA and EGAT to PEA;
the automatic adjustment mechanism should
(i)
encourage efficiency: it should allow pass-through to
customers only of changes in strictly uncontrollable costs. It
is particularly important to encourage efficient procurement of
generation from EGAT’s own plant, independent power
producers (IPPs) and SPPs as generation costs are the largest
component of electricity costs;
(ii)
appropriately balance the interests of the utilities and their
customers; and
(iii)
as far as possible, maintain the existing format to avoid
presentational problems and potential legal challenges.
Market responses
2.11 As noted above, the key policy objective of this tariff review is to deliver
recommendations on tariff levels, structure and adjustment mechanisms which mirror
as closely as possible those which would emerge in a more privately owned and
competitive industry. As described in our Inception Report, on the utilities’ own
projections of investment and operating costs, tariffs would need to rise considerably
to meet current financial criteria. We describe below how we would expect privately
owned competitive utilities to behave in the current economic climate in Thailand.
We recognise that the utilities are already making strenuous efforts to reduce
investment and operating costs, and that they do not have the same freedoms as
private companies while they remain in the public sector. However, we believe that
consideration of a private sector response in a competitive market is helpful in
identifying possible options open to both the utilities and the RTG in trying to help
electricity consumers in the present difficult economic circumstances.
In the present situation of substantial surplus capacity, and in a competitive market,
the electricity tariff would fall. This reduction in tariff would result in falling profits
for private sector companies unless they were able to reduce their costs sufficiently to
offset the lower tariff. Depending on the extent of the surplus, some power producers
would find that market prices did not even cover their costs, and they would incur
losses. These power producers would be forced to reduce costs or cease operation.
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In such adverse economic circumstances, there are broadly four ways in which a
private sector company might try to improve its financial situation:
(a)
amend its investment plans;
(b)
reduce its operating costs;
(c)
consider asset sales and additional borrowings; and
(d)
review its financing arrangements.
Investment plans
A private sector company would carefully review all its investment plans and defer all
non-essential investment. Clearly all investment which had not yet commenced could
easily be rescheduled, but projects under construction would also be assessed to
identify what might be the costs of stopping construction, and what costs could be
saved by so doing.
This is, perhaps, of greatest direct importance in the generation segment of the
industry, given the current high and rising plant surplus on the system. In a
competitive electricity market, prices would not simply rise to finance the growing
plant surplus. On the contrary, prices would initially fall, and we would then expect
to see:
(e)
no further capacity additions to the system – action would be taken to
cancel or delay any planned new generation plant (either their own, or
planned purchases from new IPPs and SPPs); and
(f)
removal of surplus plant from the system – any plant which was not
expected to run and which has positive avoidable costs of operation,
would either be retired or “mothballed”.
It is important to note that the effect of these actions would be to bring the wholesale
market for energy back towards balance, and hence return generation prices back
towards their long run equilibrium level. The financial requirements of the utilities
will, however, have been reduced – by reducing capital expenditure requirements and
reducing total operating costs.
Similarly on transmission and distribution, we would expect to see a private sector
competitive company reviewing and reducing its planned capital expenditure on the
system, in response to:
(g)
the reduced generation investment plan;
(h)
the lower system demand and projected growth rate; and
(i)
the apparent reduction in customer’s ability and willingness to pay for
enhanced supply security in times of severe economic downturn.
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Operating costs
Operating costs would also come under critical scrutiny to seek to reduce the
company’s own costs and bought-in costs such as:
(j)
staff numbers and salaries; and
(k)
purchases, such as fuel or materials.
We would expect to see, in a depressed and significantly over-supplied competitive
market, quite radical cost reduction measures – as private sector companies fought to
compete and remain in business.
Additionally, where it does not face competition, the private sector would review
critically its performance standards to the extent permitted by regulation, perhaps
seeking temporary exemptions from selected performance standards.
Asset sales and additional borrowing
We would also expect a private sector competitive company to take action to improve
its short term financial position in such adverse circumstances by considering
measures to raise additional cash. This might be achieved through:
(l)
the sale of non-productive assets (i.e. assets which are not core to the
business and which yield little or no net revenue)
(m)
additional borrowing, against the security of core productive assets – a
measure which would only be pursued if the debt service costs fall
below the return earned by the asset in the business;
(n)
the sale of core productive assets – a more radical measure, only to be
pursued if a price at least equal to the asset’s value in the business can
be secured; and
(o)
the sale of shares in the business as a whole – to raise additional equity
finance in circumstances where the company’s debt carrying capability
is exhausted.
Review its financing arrangements.
Finally, a private sector company facing severe financial difficulties would, where
possible, seek to renegotiate, or reoptimise its existing loan portfolio. Most typically,
this would involve discussions with key lenders to seek agreement to:
(p)
debt rescheduling (to defer imminent repayments)
(q)
temporary debt service relief; and
(r)
debt-for-equity swaps.
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Summary
Above, we have identified a number of categories of action that we expect a private
sector company would take in the current economic circumstances in Thailand. They
are actions that would be forced upon them in any over-supplied and depressed
competitive market. In the next section, we report the key findings from our reviews
of the utilities’ investment and operating efficiency and we indicate, where possible,
our views on the scope for such actions. Unless actions of this sort are taken, the
utilities’ current financial projections show that significant real tariff increases would
be required to allow them to meet the current financial criteria.
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3
Investment and operating efficiency review
In this section, we summarise our high level reviews of the current generation,
transmission and distribution investment and operating efficiency. This analysis helps
inform our later recommendations on tariff levels that should fund efficient
investment and operation.
We begin with a brief review of the demand forecast which underlies the investment
and operation plans. We then discuss generation, transmission and distribution
investment plans in turn. We examine particularly the methodologies for determining
the physical investment programmes to check that the physical programmes seem
reasonable and to check that the corresponding financial investment plans seem
reasonable. Next, we examine generation, transmission and distribution operating
efficiency. We compare operation and maintenance policy and key performance
indicators with international benchmarks. Finally, we take account of the recent study
that focused on the relative efficiency of the Thai utilities.
We give further details of the demand forecast review and the investment and
operating efficiency reviews for EGAT generation, EGAT transmission, MEA and
PEA in Annexes A, B, C, D and E respectively.
Review of demand forecast
The Thai Load Forecasting Subcommittee (TLFS) prepares new forecasts for the
sector at the end of each financial year. The load forecast prepared in September
1998 contains three scenarios for load growth over the period FY1999 to FY2011
assuming rapid economic recovery (RER), moderate economic recovery (MER) and
the low economic recovery (LER). The MER forecast underlies the present
investment plans for EGAT, MEA and PEA.
We have reviewed trends in consumption and the TLFS forecasting methodology to
determine the suitability of the MER load forecast as a basis for sector investment and
operational plans. The main findings of our review are that:
(a)
the load forecast methodology is sound;
(b)
the MER forecast provides:
(i)
a sensible basis for long term investment planning; but
(ii)
an optimistic view of short-term growth given the out-turn
demand for the first six months of FY1999.
However, we believe the current demand forecast represents a reasonable basis on
which to undertake the current tariff review.
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Review of investment plans
We have carried out a high level review of each utility’s investment plan for the
period FY1999 to FY2011. We are of the firm view that, given current economic
circumstances, there are further reductions that could be made in all of the investment
plans - particularly EGAT’s generation and unspecified future transmission expansion
plans, and both MEA’s and PEA’s distribution system development programme. On
the latter however, we recognise that this may have an undesirable impact on the
distribution system reliability.
We summarise below the main findings of our review and provide more detailed
comments in the annexes.
EGAT’s generation investment plan
In Annex B, we summarise EGAT’s most recent power development plan (Revised
PDP99-01), we describe EGAT’s generation planning methodology, and we review
the principal assumptions made by EGAT in operating its investment-planning model.
Our key conclusions are that:
(c)
there will be considerable surplus generating capacity over the next
few years, because of lower than expected demand and firm
commitments to new power plant projects which are planned to be
commissioned over the period FY1999-2003;
(d)
the generation investment planning methodology is broadly
reasonable. The methodology uses a probabilistic planning model to
select, from a menu of candidate plants, the “least cost” investment
plan that meets the demand forecast, subject to a number of
constraints. By least cost plan, we mean the plan that minimises the
cost of investment, operation and unserved energy to the planning
horizon. The principal constraints are the security constraints that, in
each year,:
(e)
(i)
there will be at least a 25% reserve margin; and
(ii)
the loss of load probability (LOLP) will be less than 1
day/year;
some assumptions in the generation planning should be revised.
Specifically, we consider that:
(i)
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the 25% minimum reserve margin constraint is inappropriate.
In our view, the model should freely minimise the costs of
investment, operation and unserved energy without a reserve
margin constraint. However, if EGAT continues to use such a
constraint, we consider that an 18% minimum reserve margin
would be more appropriate given the size of system,
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proportion of hydro plant, rate of load growth and value of
unserved energy;
(ii)
some plants which were treated as committed should be
treated as candidate plants when determining the investment
plan;
(iii)
the existing, committed and candidate plants should be
modelled on the basis of net generation (excluding auxiliary
consumption and losses) rather than gross generation;
(iv)
the forced outage rates for some plant types should be
adjusted to reflect international experience.
EGAT has subsequently reflected these changes in its modelling of generation
marginal costs but these changes have not all been reflected in its financial modelling.
EGAT’s transmission investment plan
We set out details of our review of the methodology, planning criteria and
transmission investment plan in Annex C. Our key conclusions are:
(f)
the deterministic methodology and criteria that EGAT uses for
transmission planning provide a sound basis on which to develop the
transmission system. However, EGAT may wish to consider the
adoption of probabilistic type planning criteria in due course with a
view to achieving further savings;
(g)
there may be scope for further reductions in the investment plan to
reflect the changed economic circumstances and the revised load
forecast. We think that some 60% of the total investment budget of
some 380,000 million Baht should be re-examined to confirm how
much of it is still required. In particular we recommend that the
following projects are re-examined:
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(i)
transmission developments under Transmission System
Expansion projects TS10 to TS15 inclusive, which represent a
total combined investment of some 160,000 million Baht (or
some US$4,500 million).
These schemes, which are
scheduled to start at various stages between 1999 and 2008
and end between 2003 and 2013, are we understand still in the
formative stages (the first of these projects, TS10, is not due
to be presented for approval before September 1999). Our
view is that it would be imprudent to approve such a large
proportion of the transmission investment plan on the basis of
such little information;
(ii)
the latter stages in development of the 500 kV transmission
projects for Independent Power Producers (the TIP1#2 and
TIP2 schemes). The two schemes involve a total investment
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of some 55,000 million Baht (some US$1,500 million). They
were originally planned and approved in 1996, but work on
these schemes is not due to commence until 2003 and 2005
respectively. We believe that the need for these schemes
should be re-confirmed;
(iii)
investment of some 8,500 million Baht (some US$140
million) associated with IPPs still under negotiation and
EGAT generation schemes which may be delayed;
(iv)
transmission sub-projects which may not yet have started
under the TS8 and TS9 projects should be examined to see
whether they are still required.
Based on these comments, EGAT has made some small amendments to its
transmission investment plans used both for calculating marginal costs and for its
financial modelling. However, we remain unconvinced that the capital expenditure in
its amended plan is justified, particularly in the later years. We note, however, that
this has little impact on tariff setting for the period FY2000-2003.
MEA’s distribution investment plan
We have reviewed the methodology and criteria MEA use for system planning, and
we are satisfied that they provide a sound basis on which to develop its plans for their
transmission, sub-transmission and distribution systems. We describe this review in
Annex D and summarise our main conclusions below.
The planning criteria require the system to be designed to an N-1 security standard
from 230 kV transmission substations down to 12 kV primary distribution feeders.
However, our discussions with MEA’s system planners have indicated that such
levels of security are not always provided.
In its customer service standards, MEA also defines reliability targets, in terms of the
system average interruption frequency index (SAIFI) and system average interruption
duration index (SAIDI). However, we are not clear how these indices are used to
influence system planning. In principle, use of these reliability indices commits MEA
to further investment above that required to satisfy the basic planning criteria, which
are designed principally to meet new demand growth. However, greater reliability
requires additional investment in the transmission plant which is probably
inappropriate in the current economic circumstances.
MEA plans on two timescales:
(h)
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long term plans cover a period of up to 20 years. The current longterm plan covers the period FY1992 to 2011 and is set out in 1998
price levels. For the period FY1999 to 2011, the current long-term
plan includes investment for projects not completed under the Seventh
Plan and Revised Eighth Plan and estimates of expenditure under the
Ninth and Tenth Plans. We understand that it has been revised to take
account of the changed economic circumstances; and
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(i)
Five-year plans, consistent with the long-term plans, which cover the
early part of the long term planning period. These include a
contingency allowance and are set out in current price levels. The five
year plans are not prepared on a rolling basis:
(i)
the current five year plan, “the Eight Power Distribution
System Improvement and Expansion Plan” covering the
period FY1997 to FY2001 was prepared originally on the
basis of the 1994 load forecast but has been revised recently
to take account of the substantially lower 1998 MER load
forecast;
(ii)
the next five year plan “the Ninth Power Distribution System
Improvement and Expansion Plan” covering the period
FY2002 to FY2006 will not be available until mid 2000.
The long-term investment plan for the period 1999 to 2011 shows a total investment
required of some 109,000 million Baht of which some 83% is to meet load growth
and 17% to improve system reliability. Clearly this investment programme is very
sensitive to the assumed demand forecast and to the speed of reliability improvement.
We have compared the original and revised five year plans for the Eight Plan period
to confirm whether MEA’s development plans have sufficiently taken account of the
revised load forecast. We consider that MEA’s investment plans for this period
are broadly consistent with the revised load forecast. The revised plan comprises a
reduction of some 30% in investment over the plan period to a new total of some
38,000 million Baht (US$1,060 million).
The revised plan is intended to meet the following objectives:
(j)
to meet a growth in system demand of almost 600 MW over the period
1997-2001 reaching a forecast peak demand of 6225 MW in 2001,
equivalent to an average annual growth rate of about 2%;
(k)
to attain the same level of system reliability as that planned under the
original Eighth Plan and affect at least a 20% reduction in supply
interruptions; and
(l)
to limit investment during the current severe economic downturn and
hence reduce upward pressure on MEA’s tariffs.
Given these objectives, we consider that the investment plans are reasonable.
However, under the severe economic circumstances, we consider that the reliability
improvement objective might be relaxed and some investment in reliability
improvement might be delayed.
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PEA investment plan
We have reviewed the methodology and planning criteria PEA uses for system
planning and, as with EGAT and MEA, we are satisfied that they provide a sound
basis on which to develop its plan for its 115 kV and primary distribution systems.
We have not seen planning criteria for low voltage distribution, so are unable to
comment on their suitability. We describe this review in Annex E and summarise our
main conclusions below.
The planning criteria define the basic system design requirements, including
provisions for firm capacity at all sub-transmission and primary substations,
construction of new feeder circuits with spare capacity for load transfers under
emergencies, guidance on maximum substation transformer and line loadings,
maximum voltage drop limits etc. Consequently we are satisfied that they adequately
define the system planning requirements. There is no requirement to provide N-1
security other than at substations where the provision of two transformers will provide
some degree of security.
As with MEA, the PEA planning criteria do not provide any guidance as to planning
the system to improve reliability of supply although PEA has a commitment with
NEPO to improve its SAIFI and SAIDI reliability indices. PEA system planners have
stated to us that even if the reliability targets are achieved the performance will still be
relatively poor.
PEA has had independent surveys and measurements undertaken of the quality of its
supply and it is concerned that up to 25% of its customers (i.e. more than 2 million)
are dissatisfied with the reliability of supply and a similar number are unhappy with
the quality of supply voltage received. Consequently, the revised PEA investment
programme for the period of the Eighth Plan FY1997-2001 is designed to maintain
investment in 115 kV transmission lines and substations and in the distribution system
to achieve significant improvements in reliability of supply.
The PEA distribution system is principally a rural distribution system with pockets of
urban development covering about 99 % of the surface area of Thailand. The
distribution system is split into four regions: North, Northeast, Central and Southern
and into three areas within each region. The investment plan identifies future
development on a regional basis. The revised PEA investment plan for the Eighth
Plan is separated into six programmes:
(m)
115 kV transmission lines and substation construction;
(n)
distribution system construction;
(o)
distribution system dispatching centre construction;
(p)
rural electrification and renewable energy development;
(q)
strengthening operational and service capability; and
(r)
research and development.
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18
The revised investment plans shows a reduction for the Eighth Plan of some 17%
corresponding with a reduction of some 10,000 million Baht (some US$280 million)
from to some 50,000 million Baht. To achieve this PEA is making reductions of
around:
(s)
US$100 million, or some 14% of its 115 kV transmission line and
substation construction programme;
(t)
US$180 million, in secondary measures such as:
(i)
cancelling from the Eighth Plan of the construction of seven
regional distribution system despatch centres and its research
and development plans;
(ii)
making a reduction of more than 70% in its plans for
strengthening operational and service efficiency by changing
a number of full scale projects into pilot schemes.
However, PEA plans to maintain its original budget for its distribution system and
rural electrification programmes, though this results in some reduction to the physical
plans due to rising costs.
In our view, from a purely economic perspective, the revised investment plan of PEA
for the Eighth Plan is an inadequate response to the projected downturn in demand
associated with the Moderate Economic Recovery forecast. Under the severe
economic circumstances, we consider that some investment in quality and reliability
improvement might be delayed. However, we have some sympathy with the view
that, since investment has struggled to cope with the massive increase in customer
demand in recent years, the recent downturn in system demand represents an
opportunity for PEA to make up lost ground on quality and reliability.
Review of operating efficiency
We now discuss in turn EGAT’s generation and transmission operating efficiency,
MEA’s distribution efficiency and PEA’s distribution efficiency. We note that our
reviews have been somewhat limited by the lack of data and suitable comparators.
EGAT generation operating efficiency
We have carried out a brief review of the operating efficiency of EGAT’s generation.
We summarise our findings below and provide more details in Annex B.
Concerning our findings on operational efficiency:
(u)
some specific power stations appear to have lower than expected
thermal efficiencies;
(v)
operations and maintenance procedures are broadly satisfactory,
though planned outage periods seem longer than expected; and
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19
(w)
there is considerable scope for productivity improvement in EGAT’s
generation business.
We have not probed EGAT’s generating plant despatch philosophy, although, we note
that the economics of water usage are not considered in despatching hydro plant.
EGAT Transmission operating efficiency
We have undertaken a brief review of the operational efficiency of EGAT’s
transmission. We summarise our findings below and provide more details in Annex C.
Concerning operation and maintenance (O&M) policy, we conclude that EGAT is
in line with other major transmission utilities around the world. Accordingly,
provided EGAT works to this policy, then its operation and maintenance practices are
satisfactory.
Concerning key performance indicators, we have examined the following and
compared them with similar indicators from international transmission companies and
from other utilities in Thailand and south east Asia:
(x)
productivity ratio of energy delivered/employee (including trend
data);
(y)
operational efficiency relating to:
(z)
FP3Maintext.doc
(i)
number of O&M employees/circuit-km of transmission line;
(ii)
O&M costs/GWh energy delivered;
(iii)
O&M costs/circuit-km of transmission lines;
(iv)
system energy losses;
reliability performance relating to:
(i)
outage rates/circuit-km of transmission line;
(ii)
system average interruption frequency index (SAIFI) and
system average interruption duration index (SAIDI) reliability
measures; and
(iii)
unserved energy.
20
Productivity
Although productivity measured by energy delivered/employee has risen by some
80% over the four year period to 1997, it is still relatively poor in comparison with the
best performing international transmission companies, such as those in Australia,
Argentina and the UK. Similar trends are apparent in other productivity parameters
such as employees per circuit-km.
Efficiency
EGAT has more transmission O&M employees per 1000 circuit-km of line than any
other of the transmission companies considered in our sample. However, EGAT’s
O&M costs/circuit km are broadly in line and its O&M costs/GWh of energy
delivered are relatively low in comparison with other transmission utilities. Whilst in
part this may reflect efficient performance, we note that EGAT:
(aa)
benefits from relatively low staff costs; and
(bb)
has relatively poor reliability performance (in terms of energy
delivered/energy demanded).
We believe that system energy losses are reasonable. Total losses are considerably
lower than two comparable local utilities but marginally higher than the majority of
transmission companies in the international sample used for comparison.
Reliability
Our comparison of reliability performance has concentrated on forced outage rates per
circuit-km and on the amount of unserved energy, since we do not have access to
SAIFI and SAIDI data for many other transmission companies.
The amount of energy delivered compared to that demanded on the EGAT system
was poor in comparison with other transmission companies indicating that there is
room for improvement. Regarding forced outage rates per circuit-km EGAT’s
performance is comparable with that of most of the transmission companies sampled,
although the number of outages per circuit was high in comparison with other
transmission utilities. EGAT’s SAIDI is considerably higher than the other utilities
for which data are available.
In summary, we note that, although EGAT’s productivity measured by energy
delivered/employee has been improving steadily in recent years, there is considerable
scope for further productivity improvement. In terms of operational efficiency, we
consider that there should for further reductions in the workforce and that modest
reductions in energy losses should be sought, if EGAT is to achieve similar levels of
efficiency to those currently enjoyed by comparable organisations. There is also
significant scope for improvements in reliability both in terms of achieving reductions
in the outage rate and the duration of the outages.
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21
MEA’s distribution operating efficiency
We have undertaken a brief review of the operating efficiency of MEA’s distribution
activity. We summarise our findings below and provide more details in Annex D.
We focus on number of key performance indicators relating to productivity, efficiency
and reliability which are compared with those of other utilities. We have also
reviewed MEA’s operation and maintenance procedures and believe them to be
broadly in line with other distribution utilities around the world.
Productivity
Productivity measured by energy sales/employee, customers/employee and
employees/circuit km has shown an average annual improvement of around 7% to 8%
over the last five or six years but remains below the level achieved by comparable
utilities. This suggests that the London Economics’ targets (see later) for reductions
in controllable costs should be readily achievable.
Efficiency
We note that O&M costs/GWh of energy delivered are well below that of PEA and of
two Australian comparators. We also consider that MEA’s energy losses of around
4% are reasonable.
Reliability
We note that system reliability as expressed by SAIFI and SAIDI has improved since
1993: SAIFI has fallen from 6.91 to 4.70 and SAIDI has fallen from 195.7 to 146.6.
However, in 1998, while the SAIFI met the target for that year (4.75 compared with
4.70), the SAIDI index was above the target (146.6 compared with 118.5). To meet
the targets in 2001 more substantive improvements will be required. The SAIFI and
SAIDI are significantly poorer than those for UK distribution companies.
In summary, although MEA’s productivity is improving at a annual average of
about 7%, there is scope for further improvement. In terms of operational
efficiency, we consider that there is scope for further reductions in the workforce
and for other efficiency improvement measures once the recession is over. The
present level of electrical losses seems reasonable. There is, however, scope for
further improvements in system reliability and MEA should be working to
achieve performance levels in the long term which are better than the targets
currently set by NEPO.
PEA distribution operating efficiency
We have undertaken a review of the operational efficiency of PEA’s distribution
business. We summarise our findings below and provide more details in Annex E.
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We focus on key performance indicators relating to productivity, efficiency and
reliability which are compared with those of other electricity utilities. We have also
reviewed PEA’s operation and maintenance policy and are of the opinion that they
show a tendency for more regular maintenance attention than we would consider
common practice. This could reflect concerns over the reliability of certain types of
equipment.
Productivity
Productivity measured by energy sales/employee, customers/employee and
employees/circuit km has shown an annual average improvement of some 5 to 12% in
the last six years but remains below the level currently achieved by comparable
utilities. This suggests that the London Economics’ targets for reductions in
controllable costs should be readily achievable.
Efficiency
We note that PEA’s O&M costs/GWh delivered are well above those of MEA and
about three quarters of that of two Australian utilities. Given PEA’s problems with
system reliability we can understand PEA’s high O&M expenditure relative to
MEA’s. However the number of O&M employees per 1000 circuit-km (i.e. 15) is
well below the transmission companies, which like PEA have to operate and maintain
a large dispersed network.
System energy losses of 6.2% are much higher than MEA’s and outside of the range
we would consider economic. We consider that there is scope for reduction in losses
of some 1% or 2% in the next few years. We note that the trend in system losses is
upward which indicates that the system is becoming less efficient. We believe this is
because system reinforcement has not kept pace with increase in demand.
Reliability
We note that the reliability performance of the PEA system is variable and although
there are indications that some aspects of the supply reliability are on target others are
not. Even if the target figures for 2001 were achieved in all cases, the reliability of
the supply would still be inadequate in many respects.
The SAIFI for industrial customers is currently better than the target figure agreed
with NEPO for the year 2001 for industrial customers (i.e. 3.33 interruptions/
customer/year compared with a target of 4.4). Similarly the SAIFI for urban
customers is better than the target (12.3 compared with 12.7). However, the SAIFI for
rural customers of 20.4 still needs to improve if the target of 18.3 is to be met in 2001.
The SAIDI shows that supplies to industrial customers currently achieve the target of
132.0 whilst urban and rural supplies require major improvement if the 2001 targets
are to be met.
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23
In summary, although PEA’s productivity is improving at an annual rate of
between 5 and 12 % per year, depending on how productivity is measured, there
is scope for further improvement. In terms of operational efficiency, we consider
that there is scope for further reductions in the workforce and for the reimplementation of efficiency improvement measures once the recession is over.
We consider that electrical losses should be reduced by some 1% to 2 %. There
is also major scope for further improvements in system reliability and PEA
should be working to achieve performance levels in the long term, which are
considerably better than the targets currently set by NEPO.
Report on Productivity of Thai Electricity Companies
In a study conducted in 1997 and 1998, London Economics (LE) estimated the
potential efficiency gains that could be achieved by EGAT, MEA and PEA using a
mixture of time trend analysis and international comparisons.
The key points to note are:
(cc)
Generation. It looked at the productivity gains achieved by plant in
Thailand in the period 1991 to 1996. It recommended that EGAT’s
generation should be expected to achieve a 5.8%pa reduction in
controllable costs over a 3 to 5 year period, the average for EGAT’s
plant over the period 1991-96;
(dd)
Transmission. It compared EGAT’s transmission business with
transmission companies in the UK and Australia. It looked at the
period 1993 to 1994 and found that EGAT had been improving
efficiency faster than the comparators, but was still 32% less efficient
than might the best company. It recommended that the transmission
business should be subject to a 2.6% pa reduction in allowed
revenue in respect of controllable costs over a 3 to 5 year period, the
average rate at which the companies compared were increasing
efficiency; and
(ee)
Distribution. It compared the relative efficiency of MEA and PEA’s
regions during the period 1991 to 1996. It did not use international
comparisons because it considered that it did not have data from
sufficiently comparable companies. It found that MEA was more
efficient than PEA, and that MEA had been able to achieve 5% pa
efficiency improvements.
On this basis it recommended that
distribution should be subject to a 5.1% pa real reduction in
allowed revenue in respect of controllable costs over a 3 to 5 year
period.
We have the following comments on the LE analysis:
(ff)
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for understandable reasons, the conclusions are based upon relatively
little data. LE did not use international comparisons for distribution
and generation, and the data for transmission is based on a short time
period, 1993 to 1994;
24
(gg)
the recommendations are based upon what the utilities have been able
to achieve historically. There are drawbacks to this approach.
Historical performance is not necessarily a guide to what could be
achieved in the future;
(hh)
the tariff adjustment regime has given the utilities relatively little
incentive to cut costs in the past. If properly incentivised, they may
be able to achieve larger gains - a more comprehensive international
benchmarking exercise is necessary to ascertain what level of savings
may be feasible; and
(ii)
the recommendation on potential savings achievable by the
transmission business appears conservative. It is based upon the
average improvement achieved by the comparator group, despite the
fact that:
(i)
EGAT had achieved greater gains than the average;
(ii)
EGAT still lags the comparator companies by 32% so has
scope for significant gains.
Conclusions
On the basis of our high level analysis of the potential for efficiency improvement, we
have no significant reason to challenge LE’s estimates of feasible operating efficiency
improvements. Indeed, we think that LE’s suggestions may be conservative as the
distribution target is based on historic trends in Thailand and the transmission target,
based on international comparison, has been exceeded in Thailand. Nevertheless, we
believe that LE’s estimates of feasible operating efficiency improvement represent a
reasonable basis on which to determine allowed revenues and tariffs in this review.
We consider that:
(jj)
while the productivity of each transmission and distribution business
has improved significantly since 1993, the performance is still below
that of similar transmission and distribution businesses in other parts of
the world;
(kk)
there is scope for further improvement in efficiency in all three
utilities; and.
(ll)
there is scope for further improvement in supply reliability. We are
uncertain, however, how these improvements are to be funded in
current economic circumstances.
FP3Maintext.doc
25
4
Financial performance criteria
In this section, we present the financial criteria that we propose should be used to
define acceptable financial performance and hence to determine the allowed revenue
that the utilities may recover through tariffs. We begin with a brief description of the
current financial criteria. We then propose some amendments to the definitions of
these ratios mainly to allow for proceeds from the disposal of substantial assets
(which were not envisaged when the current criteria were defined). Finally, we
describe how we apply the revised financial criteria to determine the allowed revenue.
Current financial performance criteria
The current “cash based” measures of financial performance were introduced as a
means of setting allowed revenues for the financial year 1997. Subsequently, they
have been incorporated into the covenants contained in loan agreements with the
World Bank. These criteria are:
Ratio
Criteria
Self-Financing Ratio
Minimum 25%
Debt Service Cover Ratio
Minimum 1.3 for EGAT
Minimum 1.5 for MEA and PEA
Debt/Equity Ratio
Maximum 1.5 : 1.0
(Short and Medium Term Debt)/Total Long Term
Debt
Maximum 15%
These ratios are defined as follows:
(a)
self-financing ratio (SFR) is the ratio of funds generated from internal
sources over the average three-year capital expenditure, where;
(i)
funds from internal sources comprise:

net cash income for the year, including both operating and
non-operating income, after deduction of provisions for major
repairs, bonus, remittance to Ministry of Finance and interest;

less loan repayments and provision for bullet repayments of
bonds;

plus reduction (less increase) in non-cash working capital;
(ii)
capital expenditure is the average over three years (the year,
the previous year and the following year2);
2
SFR will clearly be based on projections of capital expenditure for the current year and following
year.
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26
(b)
debt service cover ratio (DSCR) is the ratio of net cash income,
before interest, over debt service requirements for the year;
(c)
debt/equity ratio is the ratio of long-term debt over total equity;
(d)
(short and medium term debt)/total long-term debt is the ratio of all
debt maturing less than five years from the date on which it was issued
over total long-term debt.
As noted in our Inception Report, there have been a number of inconsistencies in the
utilities’ calculations of these criteria due to different interpretations. Further, these
criteria do not allow adequately for major divestments such as the sale of Ratchaburi.
However, we consider that the overall approach using “cash based” criteria remains
appropriate.
Proposed amendments to the definition of the ratios
We propose that the above financial criteria continue to be used for the purposes of
setting the allowed revenues for the utilities, with some modifications to their
definitions. We summarise below the proposed modifications, which reflect our
discussions with the utilities and the World Bank and we give full details of the
revised definitions in Annex F. We begin by setting out the proposed modifications,
we then discuss in more detail the most important change which concerns
incorporation of proceeds from asset sales or divestments.
Proposed modifications to definitions of SFR and DSCR
We recommend the following amendments and clarifications to the existing formulae
set out in the covenants to the World Bank loan agreements.
In the case of SFR, the main amendments are:
(e)
cash received from the sales of assets or investments should be
included in funds from internal sources as an annuity over the life of
the assets;
(f)
for the calculation of net cash income, the book losses (or profits) on
disposal of assets should be treated as if they were additional (or
surplus) depreciation (that is, they should be added back to net profits);
(g)
the calculation of the three-year average capital expenditure should be
based on the actual (or projected) expenditure in each year, net of any
cash received from customers or other parties as contribution towards
construction of assets. These customer contributions should not be
included in funds from internal sources;
(h)
repayment of loans should be net of any loans received as a result of
refinancing;
FP3Maintext.doc
27
(i)
(j)
funds from internal sources should:
(i)
exclude any short-term borrowings from sinking funds for the
repayment of bonds
(ii)
include any repayments of short-term borrowings from
sinking funds for the repayment of bonds.
the movement in non-cash working capital should exclude the
movements:
(i)
on the current portion of long-term debts; and
(ii)
on accounts for the payment of Bonus and Remittance to the
MoF. Instead, the actual Bonus and Remittance paid in the
year should be deducted from net cash profits.
In the case of DSCR, the main amendments, which represent a shift in emphasis from
servicing debt to managing the net debt position of the utilities, are:
(k)
cash proceeds from the disposal of assets or investments should be
deducted from the debt service obligations. The level of deduction
should be the same as that applied in the SFR, that is an annuity over
the life of the assets divested;
(l)
interest payments included in total debt service obligations should be
net of interest receivable; and
(m)
net cash income should be before interest payable net of interest
receivable.
We recommend that all three utilities amend their financial projection models to
reflect these revised definitions of SFR and DSCR.
Treatment of net cash proceeds from asset sales and divestments
The most important change we have recommended is that the net cash proceeds raised
as a result of asset sales or divestments should be taken into the calculation of the SFR
and DSCR, irrespective of the utilities’ plans for using the net cash proceeds. Without
such treatment, the utilities could accumulate large cash balances from asset sales yet,
at the same time, request tariff increases to meet SFR and DSCR. Our preferred
approach is that the net proceeds be included as an annuity over the estimated life of
the assets sold (i.e. as if the net proceeds were rentals received under a notional
“lease” arrangement) as:
(n)
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we wish to ensure that when generation assets are sold and replaced by
power purchase arrangements, tariffs paid by customers should not be
unduly affected. Customers have already financed the investment in
28
the asset and would have expected to receive the benefits over the life
of the assets; and
(o)
we can structure the annual level of these notional rentals to reflect the
specific nature of the divestment and its replacement with power
purchase arrangements. For example, it may be appropriate to take a
higher proportion of the net proceeds during the first few year of the
notional “lease”. Other treatments may not reflect net proceeds
smoothly in the calculation of required revenues and may lead to
substantial changes in the level of tariffs between price control periods.
In 1997, when the “cash based” financial criteria were developed, major divestments,
such as that of Ratchaburi, were not envisaged. In the case of Ratchaburi, the net
sales proceeds are expected to be some Baht 54,400 million (cash proceeds will be
some Baht 64,000 million in the financial years 2000 and 2001 but EGAT will invest
Baht 9,600 million in the new holding company that will own Ratchaburi). EGAT
plans to retain the debts incurred in respect of Ratchaburi, which will total some Baht
42,300 million at the time of disposal. However EGAT is considering options for
early repayment of other more expensive loans with balances of some Baht 18,000
million.
We have considered and rejected two other approaches to incorporating the net cash
proceeds into the ratios:
(p)
(q)
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to include the net book profit on disposal of the assets in the
calculation of internally generated funds in the year of disposal. In our
view this is inappropriate because:
(i)
the net book profits include depreciation and so do not
represent cash, while the ratios are designed to focus on cash
generated by the businesses;
(ii)
this means allowed revenue, and hence tariffs, will be strongly
influenced by financing decisions made by the utility. For
example, the projected proceeds from the sale of Ratchaburi
are considerably higher than the net book profits as EGAT
intends to sell the assets free of debt (although EGAT plans to
use part of the cash proceeds to reduce future borrowings and
make early repayments of existing high-costs debt);
(iii)
the net proceeds should be used to offset the cost of debt and
so should be used in both the calculation of SFR and DSCR;
to include the net proceeds in the calculation of SFR (as part of
internally generated funds) and DSCR (as part of net cash income) in
the year in which the proceeds are received. This approach overcomes
the disadvantages of the net book profit approach, but will result in
severe distortion to tariffs:
29
(i)
the required revenues and resulting tariffs will be significantly
reduced in during the financial years 2000 to 2003 (as the
financial performance criteria are applied on average over the
tariff period).
(ii)
tariffs may need to be significantly increased at the end of this
period. In the case of Ratchaburi, this will be exacerbated by
the fact that the costs of financing the assets will continue
paid by EGAT (and ultimately customers) through the price at
which electricity is purchased by EGAT from Ratchaburi; and
(iii)
the resulting allowed revenues might not be sufficient to meet
the debt service obligations in every year.
In summary, we consider that:
(r)
benefits from disposal of assets should be shared with the customers as
early as possible and should not be used to support inefficient
operation of the utilities;
(s)
customers should not continue to contribute to the debt service
obligations on loans relating to assets no longer owned by the utilities.
In the case of Ratchaburi, this will be taken into account in the
electricity purchase price paid by EGAT; and
(t)
tariff levels should not be unduly influenced by the financing decisions
made by the utilities.
Application of financial criteria
In the next section, we use these financial criteria to assess the projected financial
performance of each utility for the purposes of setting allowed revenues. The key
objective is to allow sufficient revenue to enable the utilities to carry out all necessary
investment and maintain efficient operations whilst remaining financially sound. In
applying the criteria, we have adopted the following principles.
(u)
the financial criteria should continue to focus on the level of cash
generated by each utility:
(i)
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each utility should achieve its target SFR, DSCR and D/E
ratio. The use of the SFR as the key financial constraint on
financial performance remains valid and should continue to
underpin the setting of the allowed revenue for the three
utilities. We also consider that the target level of 25%
remains appropriate (i.e. each utility should continue to plan
to fund at least 25% of its capital expenditure from internal
source and to fund the remainder from loans). Similarly, we
consider the DSCR and D/E targets remain appropriate;
30
(ii)
the ratio of short and medium term debt to total long-term
debt should provide a useful guide to utilities when they are
developing financing plans to meet planned investment.
However, we have not used this ratio in setting allowed
revenues as the utilities have not yet agreed with the Ministry
of Finance their financing plans for investment in next
planning period (FY2002 to FY2006). We are aware that in
the current economic climate, the total debt service costs
faced by the utilities are influenced not only by the term of
debt but also by the source (foreign or local currency
denominated). Appropriate financing plans should not result
in unnecessarily high debt service costs in any price control
period;
(v)
each utility should meet its target ratios on average over the price
control period and tariffs should be set accordingly. We do not
consider that tariffs should be adjusted each year to ensure that the
target ratios are met in each year as the level of the ratios in a
particular year depend strongly on the pattern of capital expenditure
and of loan repayments. It is not possible for the base average tariff to
grow smoothly and for the utilities to achieve all ratios in all years;
(w)
each utility should achieve a minimum DSCR in the year of 1.10 as
each utility should be able to earn sufficient profits each year to meet
its annual debt service obligations;
(x)
calculation of the financial ratios should be identical for each utility
and, as far as possible, easily derived from the annual financial
statements;
(y)
the same financial targets should be applied to each segment of the
electricity chain (generation, transmission, distribution and supply) as
to the company as a whole. However, the overriding constraint will be
the achievement of the financial criteria by each company as a whole;
and
(z)
for the purposes of setting allowed revenues, average ratios are
calculated from the present value of the relevant cash flows over the
tariff period, discounted at 12.35% (nominal per annum).
We stress that any changes to the financial criteria and their interpretation which
impact on loan covenants will need to be agreed with the lenders. We understand
that, given current economic circumstances, the World Bank is willing to review
without commitment temporary relaxation of financial criteria.
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5
Financial requirements
Introduction
In this section we summarise the average tariff levels which would be required to
allow each of the utilities to meet its revised financial performance criteria under a
range of scenarios. Based on this analysis, we recommend the base allowed revenues
for each of the utilities, which should be used to determine tariffs and the financial
transfer between utilities to maintain the uniform national tariff. We also describe
briefly our consolidated financial model, which has been used for the financial
projections. This section comprises:
(a)
summary of assumptions;
(b)
discussion of a number of scenarios;
(c)
definition of the proposed Base Allowed Revenues (BAR) for each
utility, including separate estimates for generation, transmission,
distribution and supply, based on a plausible set of assumptions;
(d)
presentation of the financial performance of each utility, allowing for
income from the BAR and Ft assuming EGAT’s fuel price projections,
and the financial transfer between the utilities to support a uniform
national tariff;
(e)
presentation of two sensitivities around the financial projection
assumed to establish BAR; and
(f)
a brief description of the financial modelling.
In this section and elsewhere, all calculations exclude value-added tax (VAT).
Assumptions
We have set out the key assumptions used in the financial projections in Annex G
(Part 1). We have reflected the assumptions provided by the utilities in our
consolidated financial model as far as possible, given the time required to incorporate
them into our analysis. In particular, we have used EGAT’s projections of fuel and
electricity purchase costs. However, at the time of completing our analysis, we were
unable to accommodate all assumptions, for example:
(g)
the utilities had not agreed the investment financing plans for the later
financial years (2002 and 2003) with the Ministry of Finance;
(h)
EGAT’s revised view on its operating costs due to the projected
cancellation or completion of construction projects in 2002 and 2003
(EGAT claims that the costs of surplus construction workers, which
were previously capitalised, should be included in its operating costs).
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We have made the following important modifications to the assumptions which we
have drawn from the financial projections provided by the utilities:
(i)
application of a common Bulk Supply Tariff (BST) to MEA and PEA.
This means that the cross-subsidy to preserve uniform national tariffs
implicit in the existing BST has been eliminated. Instead, the crosssubsidy has been provided as an explicit financial transfer between the
supply businesses of EGAT, MEA and PEA. This is discussed in more
detail below;
(j)
revisions to assumptions on investment and the related costs of
investment for EGAT and PEA (reflecting the utilities’ own revised
assumptions);
(k)
harmonisation of the cost of electricity purchased by MEA and PEA
with the revenues earned by EGAT from the BST (as estimated by the
model);
(l)
harmonisation of debtors days assumed by EGAT for the sale of
energy to PEA and MEA with the creditors days assumptions used by
PEA and MEA respectively;
(m)
calculation of net interest receivable on cash balances, based on the
projected revenues and the average cash balances in each year; and
(n)
exclusion of Ft “overhang”. As our projections seek to ensure that the
utilities meet their financial criteria on a forward looking basis, we
have not made an explicit allowance for the impact of cash received in
FY2000 to FY2003 from Ft not yet charged to customers. In our
model, the base year is 1999 and the opening balances reflect the
audited results for 1998 and the projected results for 1999 under
PDP99-01.
For each scenario, we have scaled the revenues so that the following key financial
performance criteria, as defined in Section 4, are met:
(o)
(p)
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on average over the four year period:
(i)
a minimum self-financing ratio (SFR) of 25% for all three
utilities;
(ii)
a minimum debt service cover ratio (DSCR) of 1.30 for
EGAT and 1.50 for MEA and PEA;
(iii)
a maximum debt : equity ratio of 1.5 for all three utilities; and
in any one year, a minimum projected DSCR of 1.10 for all three
utilities.
33
Scenarios
The scenarios consider the following factors:
(q)
differing treatments of the proceeds from the sale of Ratchaburi in the
calculation of the key ratios (Scenarios 1, 2 and 3);
(r)
relaxation of the requirement to meet the DSCR criterion (Scenario 4);
(s)
differing levels of efficiency savings in non-fuel operating costs
(Scenarios 5, 6, 7 and 8);
(t)
the impact of further reductions in capital expenditure (Scenario 9);
and
(u)
the impact of reduced payments of remittance to the Ministry of
Finance (Scenario 10).
We summarise the results of this analysis in Tables 5.1 to 5.10 and describe each
scenario briefly below.
(v)
Scenario 1 – the utilities’ own projections for investment and
operating costs (including fuel and electricity purchase costs),
taking the net proceeds from the sale of Ratchaburi as a level
annuity and with remittances of 35% of operating profits and 50%
of profits on the sale of assets. In this scenario, the binding ratios are:
for MEA and PEA jointly3, the need to achieve a 25% minimum SFR;
and for EGAT, the need to achieve a minimum annual DSCR of 1.10
in FY2001. The resulting average BST for the period FY2000 to
FY2003 represents an increase of 11% on the predicted FY1999 level
and an increase in the average retail tariffs of 10% for PEA and 9% for
MEA (reflecting the new level of financial transfer (cross-subsidy)
between MEA and PEA discussed below) (See Table 5.1);
(w)
Scenario 2 – as Scenario 1 but with net proceeds from disposal of
Ratchaburi included in the calculation of SFR and DSCR on cash
received basis. Despite the inclusion of the sales proceeds from
Ratchaburi in the calculation of DSCR for FY2000, the binding ratio
for EGAT is still the achievement of a minimum annual DSCR of 1.10
in the FY2001. This treatment of the net proceeds from the sale of
Ratchaburi results in a higher BST than under Scenario 1, since the
level of Ratchaburi proceeds allocated to 2001 is lower than for
3
In our modelling of the scenarios, we scale the national revenue to ensure that MEA and PEA jointly
achieve the target financial ratios. As PEA’s average tariff is lower than that of MEA (due to customer
mix) and PEA (unlike MEA) pays a bonus which varies with net income, the scaling mechanism in our
modelling means that MEA exceeds the 25% target SFR when this binds on PEA. Later, in our
modelling which sets the BAR (and in the sensitivities), we adjust the financial transfer from MEA to
PEA to ensure that both utilities achieve the same SFR which slightly exceeds the 25% target.
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34
Scenario 1. This is reflected in the resulting retail tariffs. Again, the
binding ratio for MEA and PEA jointly is the 25% minimum SFR.
The average BST would increase by 13% over its FY1999 level and
the average retail tariffs charged by PEA and MEA would increase by
about 12% and 10% respectively (See Table 5.2);
(x)
Scenario 3 – as Scenario 1 but with the calculation of the annuity
“rental” from the net proceeds of selling Ratchaburi adjusted so
that 25% of the proceeds are taken in the first five years. Under
this scenario EGAT achieves a minimum annual DSCR of 1.1 in
FY2001 with lower tariffs than under Scenario 1. The average BST
would increase by 9% over its FY1999 level and the average retail
tariffs charged by PEA and MEA would increase by 8% and 7%
respectively (see Table 5.3);
(y)
Scenario 4 – as Scenario 2 but with relaxation of minimum annual
DSCR requirement. If the utilities, and EGAT in particular, were to
reduce debt costs in specific years through rescheduling or refinancing
so that the minimum DSCR did not become binding, the increase in the
average BST would be restricted to 2% and the consequential increase
in the average retail tariffs charged by PEA and MEA would be
restricted to 2% and 1% respectively (see Table 5.4);
(z)
Scenario 5 – as Scenario 1 but with our estimate of controllable
costs including efficiency savings in line with London Economics’
recommendations.
The achievement of efficiencies in cash
controllable costs (excluding fuel and electricity purchases) would
result in the increases in average tariffs being restricted to some fourfifths of the levels required under Scenario 1. This is because reduced
operating costs imply higher profits and greater ability to meet debt
servicing requirements at a given tariff level (see Table 5.5);
(aa)
Scenario 6 – as Scenario 1 but with our estimate of controllable
costs reduced by 1.5 times London Economics’ recommended
efficiency savings. When the sales proceeds from Ratchaburi are taken
on a simple annuity basis, the need for EGAT to meet the minimum
annual DSCR of 1.10 in FY2001 limits the immediate flow through to
tariffs of such cost reductions. Although further savings will increase
cash profits for the payment of debt service, the minimum annual
DSCR of 1.10 is still binding for EGAT and hence further savings
have a diminishing impact on tariffs (see Table 5.6);
(bb)
Scenario 7 – as Scenario 1 but with our estimates of controllable
costs reduced by 0.5 times London Economics’ recommended
levels. Under this scenario, the expected increases in tariffs over the
FY1999 levels are slightly higher than those expected under Scenario 5
and approximately nine-tenths of the increase required under Scenario
1 (see Table 5.7);
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35
(cc)
Scenario 8 – as Scenario 1 but with EGAT salaries increased in
line with the consumer price index. The projections of MEA and
PEA escalate salaries at CPI (5% per annum) while EGAT uses a
higher level (7.5%). If EGAT restricted salary increases to CPI, there
would be a moderate reduction in tariffs compared with Scenario 1.
As for Scenario 6, when the sales proceeds from Ratchaburi are taken
on a simple annuity basis, the need to meet the minimum annual DSCR
of 1.10 in FY2001 limits the immediate flow through to tariffs of such
cost reductions (see Table 5.8);
(dd)
Scenario 9 – as Scenario 1 except the utilities make a 10%
reduction in planned capital investment. This reduction is assumed
to apply to MEA and PEA, to EGAT’s transmission business and to
EGAT’s generation business in respect of its own generation
investment. The impact of this assumption is relatively limited
because, although it improves SFR, it does little to relieve the
minimum annual DSCR (as while it reduces the overall amount of
debt, the majority of the reduction in debt payments occurs after the
end of the tariff control period). Under this scenario, the average BST
remains similar to that under Scenario 1, while the increase in retail
tariffs compared with FY1999 levels is limited to 9% for PEA and 8%
for MEA (see Table 5.9);
(ee)
Scenario 10 – as Scenario 1 except remittances to government are
reduced, so that only 30% remittance is paid on adjusted net operating
profits and no remittance is paid on profit on disposal of assets. As the
definition of DSCR is based upon a measure of cash profits after
remittances, reductions in remittances mitigate required tariff
increases. This action, which is effectively a hidden subsidy, will
reduce the increase in BST by approximately two-thirds of the level
under Scenario 1 with corresponding reductions in average retail
tariffs. This is mainly because the minimum DSCR no longer binds on
EGAT (see Table 5.10).
Base Allowed Revenues
We have used the above scenarios to recommend appropriate levels of base allowed
revenue (BAR) to be earned by each utility during the financial years 2000 to 2003,
given the current economic and financial climate in Thailand and the findings of our
efficiency review. We have recommended BARs which, together with projected Ft
revenues, we consider will be sufficient to allow the utilities to invest and operate
appropriately and to meet their financial criteria.
We set out the recommended base allowed revenues (excluding Ft) in Tables 5.11
(EGAT), 5.12 (PEA) and 5.13 (MEA). We set out the total base allowed revenues for
the retail sector (PEA and MEA) in Table 5.14. We set out the resulting average base
tariffs in Table 5.15. The average base retail tariff for 2000 falls by 2% compared
with the expected total average tariff for 1999 and thereafter remains sensibly
constant throughout the tariff period. The small variations in the average base tariff
reflect the changes in customer mix between categories.
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36
The total allowed revenues (base allowed revenues and Ft) are set out in Tables 5.16
(EGAT), 5.17 (PEA) and 5.18 (MEA), with the combined revenues for MEA and
PEA in Table 5.19. The average total tariffs, including Ft, are presented in Table
5.20. These show substantial increases in nominal terms due to rises in fuel and
electricity purchase costs, as projected by EGAT, and expected inflation over the
tariff period.
The equivalent average tariffs are presented in constant 1998 prices in Tables 5.21
(excluding Ft) and 5.22 (including Ft). The base tariffs show substantial falls in real
terms but the total tariffs increase in real terms reflecting projected rises in fuel and
electricity purchase costs.
We summarise the percentage changes in unit tariff levels, averaged over the period
FY2000 to FY2003, compared with 1999 total average tariff levels (including Ft) in
the following table:
Base Tariff Total Tariff Base Tariff Total Tariff
Nominal
Nominal
Constant
Constant
Prices
Prices 1998 Prices 1998 Prices
excluding Ft including Ft excluding Ft including Ft
Bulk Supply Tariff
-5%
20%
-16%
6%
Average Retail Tariff
-2%
19%
-13%
5%
PEA average tariff
-2%
20%
-13%
4%
MEA average tariff
-2%
18%
-13%
6%
Given the current economic circumstances, we consider that the proposed base
allowed revenues, together with the projected revenues from the tariff adjustment
mechanism described in Section 10, provide a fair balance of risk between customers
and utilities, and are sufficient to enable each utility under efficient operation:
(ff)
to invest in its business;
(gg)
to operate its business to appropriate standards; and
(hh)
to meet its financial criteria on average for the financial years 2000
through 2003.
The base allowed revenues reflect the following key assumptions:
(ii)
the utilities’ own assumptions on operating costs adjusted to achieve
the following annual reductions in controllable costs as recommended
by London Economics (we show the calculations in Annex H):
(i)
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generation - 5.8%;
37
(jj)
(ii)
transmission - 2.60%; and
(iii)
distribution and supply - 5.10%.
the utilities’ own assumptions on investment and the financing
obligations, with some amendments agreed with the utilities:
(i)
small reductions in EGAT’s planned transmission expenditure
and related financing costs; and
(ii)
revisions to the level and phasing of PEA’s planned
investment in distribution assets to meet new demand and the
related financing costs;
(kk)
an allocation of recovery of total unit fuel costs (including costs of
electricity purchases) between the base tariff and the projected Ft for
fuel. Broadly speaking, the base tariff allows recovery of 1999 unit
fuel costs and 5% of the difference between EGAT’s projected unit
fuel costs and projected 1999 unit fuel costs. The projected Ft for fuel
allows recovery of 95% of the difference between EGAT’s projected
unit fuel costs and the projected 1999 unit fuel costs. To the extent
that unit fuel prices are lower or higher than projected unit fuel costs,
EGAT’s profits will increase or decrease. In Section 10, we detail our
proposals for a revised tariff adjustment mechanism, designed to
provide reasonable protection against fuel price volatility, while at the
same time introducing incentives for EGAT to minimise the costs of
fuel. We show the steps in calculation of the proportion of total unit
fuel cost recovered in the base tariff in Tables 5.23 to 5.25. For
example, Table 5.25 shows that of total fuel and electricity purchase
cost of 1.339Baht/kWh in 2002, 0.9740Baht/kWh is recovered in base
BST and 0.3650 in Ft;
(ll)
an allocation of recovery of cost changes due to projected inflation
(CPI) between the base tariff and the projected Ft for inflation. We
assume CPI of 2.83% for the purposes of setting the base tariffs. The
projected Ft for inflation adjusts for the difference between the utilities’
projection of inflation (5%) and this value. The projected Ft for
inflation thus includes the following amount:
Base tariff x (5% – 2.83%)
We show the steps in calculation of the inflation element recovered in
Ft in Table 5.23 to 5.26. For example, Table 5.26 shows that the
wholesale Ft recovers a further 0.0684Baht/kWh in respect of inflation
in 2002, leading to a total wholesale Ft of 0.4334Baht/kWh;
(mm) reduction in the planned remittance to the Ministry of Finance so that
only 30% is paid on adjusted net operating profits, reflecting the level
of taxation faced by a private sector company, and no remittance is
paid on the book profits on the sale of Ratchaburi;
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38
(nn)
revised definition of financial ratios to reflect the receipts of net
proceeds from the asset sales as recommended in Section 4. We
recommend that level of net proceeds included in the ratios be based
on a notional “lease” arrangement. Under this approach an annual
rental is taken to the calculation of SFR and DSCR. This rental is
calculated as an annuity of the net proceeds, recovered over the
estimated life of the plant (25 years) using a discount factor of 12.35%
(nominal). We set out the allocation of Ratchaburi sales proceeds in
Table 5.27;
(oo)
the base allowed revenues for transmission are set so that this business
achieves its target financial performance criteria;
(pp)
the base allowed revenues for generation are set so that, allowing for Ft
revenues, EGAT as a whole (including lignite mining and direct
supply) achieves the target financial performance criteria. Revenues
for the lignite business are recovered from the generation business;
(qq)
the base allowed revenues for distribution are set so that, allowing for
Ft revenues, the combined distribution businesses of MEA and PEA
together achieve the target financial performance criteria;
(rr)
the base allowed revenues for supply (i.e. the retail tariff revenues) of
MEA and PEA are set so that, allowing for Ft revenues, the combined
distribution and supply businesses of MEA and PEA together achieve
the target financial performance criteria.
Of course, there are many other possibilities to improve financial performance and
hence to reduce the need for tariff increases. For example, in addition to the measures
assumed in our calculation of the BAR, the utilities may also consider reducing the
costs of financing, through refinancing or rescheduling of debts. EGAT is already
considering further refinancing options, in addition to those included in its financial
projections. In addition, it may be possible to further reduce the generation charges
by weighting the proportion of proceeds included from the sale of Ratchaburi towards
the first five years after divestment.
Financial performance
We have prepared projections of the financial performance of each of the utilities on
the basis of:
(ss)
recovery of the BAR;
(tt)
recovery of Ft revenues based on EGAT’s projections of future unit
fuel costs (i.e. not the FY1999 unit fuel costs) and the difference
between the utilities’ projected rate of CPI and the assumption of 2.8%
CPI (as described above); and
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39
(uu)
the payment of a lump sum financial transfer to PEA from MEA to
enable PEA to achieve the target financial ratios while preserving a
uniform national tariff.
We summarise the average financial performance over the tariff period in Table 5.28.
This demonstrates that all three utilities can meet their financial criteria4. We set out
full details of these financial projections in Annex G (Part 2).
On an annual basis, the financial ratios may not be met (although the target ratios will
be met on average over the period). The projected annual ratios are summarised for
each of the utilities in Tables 5.29 to 5.31.
In Table 5.32, we also compare the average tariffs with the average tariffs projected
originally by the utilities (which did not meet the financial criteria). The table shows
that on average the proposed BST is some 3% higher than that originally projected by
EGAT, while the proposed average retail tariffs are some 11% and 9% higher than the
original projections of PEA and MEA, respectively. These higher tariffs mean that
the utilities will have more cash than originally projected and consequently should
review their investment financing plans. Any changes to financing plans, in particular
reduced new borrowings, should not significantly affect the achievement of the
financial ratios.5
Following discussion of the draft of this report, we have paid particular attention to
the operating cash balances and net debt position over the period. By net debt, we
mean:
(vv)
total long term debt, including the current portion, and bank overdrafts
and short-term loans; less
(ww) sinking funds for bullet repayment of loans and cash balances and
other deposits.
We recommend that all three utilities review their financing plans.
projections, set out in Annex G (part 2), we note that:
(xx)
On our
EGAT’s cash balance becomes slightly negative and net debt reduces
substantially over the period to 2003. We consider that the cash
position can be improved by reducing somewhat EGAT’s planned use
of Ratchaburi proceeds to retire debt over the period;
4
On its own assumptions, PEA marginally exceeds the maximum debt:equity ratio but we consider that
this is due to inappropriate future borrowing which, in practice, can be avoided.
5
The impact of reduced borrowings will be to reduce the cash balance. However, there will be a
broadly neutral impact on net interest charges (reduced debt service on borrowings offset by reduced
interest receipts on the cash balance). We note that changes in borrowings should not impact
significantly on the utilities’ ability to meet their financial criteria as both interest payable and
receivable on the cash balances is included in the calculation of SFR and DSCR.
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(yy)
PEA accumulates cash over the period and has unnecessary levels of
long term debt. We suggest that PEA reduces its planned new
borrowings to ensure its debt: equity ratio falls below 1.5; and
(zz)
MEA has a relatively unchanged cash and net debt position over the
period. This suggests that its borrowing plans accurately reflect its
planned capital expenditure.
Financial transfers
The financial transfers necessary to maintain the uniform national tariff are set out in
Table 5.33. To preserve incentives, these transfers should be made as lump sum
payments from MEA to PEA (not as now in the form of an artificial reduction in the
BST to PEA and an artificial increase in the BST to MEA).
The financial transfer represents the difference between the revenues required by
MEA and PEA individually to achieve the financial ratios and the actual revenues
they will recover under the proposed uniform national tariff schedules that recover the
revenue requirements of all three utilities. These differences arise as a result of the
differences in underlying costs of supply.
We have estimated that the lump sum financial transfer to PEA will amount to some
8.5% of its retail BAR or 0.1666Baht/kWh at the bulk supply point. The total
payments for the period FY2000 to FY2003 will decrease by 35% over the crosssubsidy included in the current bulk supply tariff.
This payment will be made entirely by MEA and will represent approximately 12.5%
of MEA’s base allowed revenue or some 0.2709 Baht/kWh at the bulk supply point.
The total payments made by MEA increase compared with the level of cross-subsidy
included in the current bulk supply tariff as EGAT ceases to contribute directly (since
we propose that EGAT’s direct customers pay the appropriate bulk supply tariff rather
than the retail tariff). We stress that MEA achieves its financial performance criteria
after these payments have been made.
Sensitivities
During discussion of the draft of this report, we were asked to examine two
sensitivities around the projections used to establish the base allowed revenue: firstly
with a higher level of remittance to the Ministry of Finance; and secondly with the
average unit costs of fuel and electricity purchases by EGAT assumed to remain
constant at 1999 levels.
In the first sensitivity set out in Table 5.34, we assume that remittance of 40% will be
paid on adjusted net operating profits and the book profits on sale of Ratchaburi.
Accordingly, average base tariffs will be approximately 0.06Baht/kWh (3%) higher
than our proposals (which assume remittance of 30% on adjusted net operating profits
and no remittance will be payable on the profits of sale of Ratchaburi).
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In the second sensitivity set out in Table 5.35, the projected Ft for fuel is zero as the
average unit cost of fuel and electricity purchases remains constant at 1999 levels.
Consequently, lower working capital costs mean that average base tariffs would be
approximately 0.02Baht/kWh (1%) lower than those proposed. We show the full
financial projections for this sensitivity in Annex G (Part 3).
Financial model
We have based the above projections on a high level consolidated financial model of
the utilities. This model prepares summary financial statements for each of the
utilities and incorporates the following main features:
(aaa)
unbundled projections for:
(i)
EGAT (generation, transmission and (direct) supply);
(ii)
PEA and MEA (distribution and supply);
(bbb) consolidated projections for EGAT (including lignite), PEA and MEA;
(ccc)
calculation of the financial criteria (on a common definition for all
three utilities) directly from the summary financial statements;
(ddd) calculation of the additional revenues (or scaling) necessary to allow
each utility to meet each of its key financial criteria;
(eee)
incorporation of target efficiency improvements in non-fuel cash
operating costs of generation, transmission and distribution.
(fff)
capability to calculate the financial transfers required among the three
utilities to maintain uniform national retail tariffs; and
(ggg) capability to run a range of scenarios.
In Annex H, we have set out a brief description of the model and an outline of the
methodology used to calculate the necessary scaling of marginal cost revenues and the
financial transfers among the utilities.
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6
Marginal costs
In this section, we present our calculations of marginal costs. We begin with a brief
discussion of why we use marginal costs and the common assumptions underlying our
calculations. We then summarise our final estimates of generation, transmission,
distribution and customer related marginal costs. In later sections we use these to
determine marginal costs based tariffs, to estimate the extent of cross-subsidy within
the existing tariff structure and to make recommendations on new base tariffs.
Following discussion of our Interim Report, we have made a number of changes to
our calculations reflecting both revisions in approach and assumptions agreed with
NEPO and the utilities, and revised data provided by the utilities. We note the
changes at the relevant points in this section
Marginal costs
If all goods and services in the economy are priced at their marginal costs, it can be
shown that resources are allocated optimally and hence economic welfare is
maximised. Even if other goods and services are not priced at marginal costs, it can
also be shown that welfare is maximised if a particular good or service is priced at its
marginal costs, provided substitutes and complements for the particular good or
service are also priced around marginal cost.
Marginal costs are the cost of the optimum response to an additional increment in
demand for the good or service. Economists distinguish between short run marginal
costs (SRMC) and long run marginal costs (LRMC). In the short run, some of the
factors of production, including capital, are fixed. In the long run, all factors are
variable. Therefore in the context of the current situation in Thailand, SRMC based
prices would fully reflect excess capacity caused by the economic downturn, whereas
LRMC based prices would reflect future equilibrium conditions when economic
growth had eroded the excess capacity.
In principle, short run marginal costs provide the most economically efficient price
signals. In practice, however, in the electricity sector, few apart from large producers
and consumers can understand and respond to such rapidly varying price signals.
International practice, therefore, is generally to use an approximation to LRMC for
tariff setting purposes. A common approach is to reflect the net present value of the
incremental costs resulting from a sustained increment in demand over a number of
future years. In the early years, incremental costs reflect any short run disequilibrium;
in later years, incremental costs tend towards the equilibrium LRMC. This approach
therefore approximates to LRMC but does not provide an equilibrium LRMC. We
adopt this approach and all references to marginal cost below refer to this approach
unless stated otherwise.
Long run marginal costs in the electricity supply industry comprise:
(a)
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marginal capacity costs: the incremental costs of new generation,
transmission, distribution and capacity together with any increased
costs of unserved energy;
43
(b)
marginal energy costs: the incremental costs of energy generation and
associated transmission and distribution losses; and
(c)
marginal customer-related costs: the incremental costs of additional
connection assets and metering and billing costs.
Typically, the marginal capacity and energy costs vary with:
(d)
time: for example, incremental demand at peak periods occasions both
increased capacity and energy costs, whereas incremental demand at
off-peak periods occasions only increased energy costs;
(e)
geography: incremental demand remote from the lowest cost available
generation incurs relatively high electrical losses in transport.
Furthermore, transmission constraints may prevent transport from the
lowest cost source to particular locations, requiring use of higher cost
available generation or transmission reinforcement; and
(f)
voltage: incremental demand at lower voltages uses more voltage
levels and hence incurs higher electrical losses and capacity costs.
The marginal customer-related costs typically vary with voltage and customer type.
Common assumptions
In determining the long-run marginal costs of electricity supply on the Thai system,
we have made a number of key assumptions:
(g)
voltage levels: for EGAT’s network, we have estimated marginal costs
at the exit of: the 500:230kV substation; the 230:115/69kV substation;
the 115kV lines; and the 115kV:medium voltage (MV) substation .
For the distribution networks, we have estimated marginal cost at the
exit of the 230kV, 115/69kV, MV system6, and the low voltage (LV)
system7. After discussion with the utilities, we have merged the
115kV and 69kV voltage levels since they are alternative voltages supply is stepped down from 230kV to MV through either 115kV or
69kV, but not through both tiers in sequence. Further details are
presented in Annex K;
(h)
price level: we have expressed all marginal costs in constant FY1998
price levels (year ending 30 September 1998);
(i)
inflation: we have assumed local inflation at 5% per annum and
foreign inflation at 3.5% per annum for all future years;
6
The MV system comprises 12kV and 24kV in MEA’s area and 22kV and 33kV in PEA’s area.
7
The LV system consists of 220/400V in MEA’s area and 230/380V in PEA’s area.
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44
(j)
discount rate: at the request of NEPO, we have revised our discount
rate and have used a 7% real discount rate to reflect the current
economic conditions; and
(k)
exchange rate: we have taken the utilities’ assumptions.
Generation marginal costs
We briefly summarise our approach and results below. We present our detailed
estimates and methodology in full in Annex J.
Our approach
Our approach involved two stages:
(l)
Stage 1: the use of a generation investment planning model (EGAT’s
PROSCREEN model) to estimate the annualised marginal cost, and its
split between marginal capacity cost and marginal energy cost; and
(m)
Stage 2: the allocation of these costs over the hours of the year, in the
case of:
(i)
marginal capacity costs, based on estimates of the daily
profile of loss of load probability (LOLP) as a proxy for
capacity stress;
(ii)
marginal energy cost, based on estimates of the daily profile
of marginal energy costs.
Estimates of generation marginal capacity and energy costs
We summarise the marginal capacity and energy costs in Table 6.1 and, as described
further below, we consider that these figures are reasonable.
In an equilibrium situation, the marginal capacity costs should approximate to the
capital and fixed operation and maintenance costs of an open cycle gas turbine
(OCGT), which we have estimated at around US$75/kW per year (including a reserve
margin of about 20%). However, it is projected that there will be a large surplus of
generating capacity until 2007 when the first new plant is commissioned. In this
disequilibrium situation we would expect the marginal capacity cost (using our
chosen methodology) to be considerably lower than the fixed cost of an OCGT. Thus,
we think that our estimate of US$36/kW per year is reasonable.
We considered carefully whether the significant projected generation surplus in the
next few years merited the use of a different methodology. We considered three
options:
(n)
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to disregard the surplus and set the capacity cost at the full OCGT
capital and fixed operation and maintenance cost;
45
(o)
to reflect only the short run marginal capacity cost into the tariff
structure – which, in the current surplus, would be close to zero; or
(p)
to retain our chosen methodology, which effectively
discounted average between the above extremes.
estimates a
We confirmed with NEPO that the third approach, remains appropriate - in order to
maintain a consistent signal in the tariff structure of the impact of peak demand on the
need for new generation capacity, while moderating the size of that signal in the
current surplus conditions.
We consider the marginal energy cost of 0.85 Baht/kWh to be consistent with other
information we have seen. The projected surplus capacity will reduce the marginal
energy costs compared with an equilibrium situation, since lower merit order plant
will be at the margin.
Following discussion of our Interim Report, we agreed that the tariffs should not
contain regional variations in energy costs. As explained in our Interim Report
there is likely to be a medium to long-term transmission constraint south of Bang
Saphan in EGAT’s Southern region, which could lead to significant region variations
in cost. However, we obtained insufficient information on marginal costs in the two
areas to identify significant differences.
Allocation of marginal capacity cost over the year
We have used estimates of LOLP to allocate annualised marginal generation capacity
costs to hours of the year. Profiles of LOLP cannot reliably be estimated for the next
few years because the levels of LOLP are very small (due to the surplus capacity).
We have therefore made estimates of LOLP in 20098 and assumed that the profiles in
the earlier years will be similar.
The present peak period defined by EGAT is 0900 to 2200 hours from Monday to
Saturday. This definition is not fully supported by our LOLP analysis. In particular,
our specific calculations indicate that:
(q)
Saturdays should be excluded from the peak period, as, even though
Saturday load profiles are similar to weekday load profiles, LOLP is
negligible on Saturdays (as on Sundays). However, we have been told
that the reduced load on Saturdays, which causes this negligible LOLP,
may not persist (as it is due to some industrial customers adopting five
rather than six day working patterns as a temporary response to the
changed economic circumstances);
8
It should also be noted that incremental capacity costs are zero initially and only significant in the
latter part of the period under consideration, i.e. around 2009, so that the choice of year is consistent
with the incidence of incremental capacity costs.
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46
(r)
public holidays should be excluded from the peak period9;
(s)
Mondays might be excluded, as LOLP is again negligible on certain
Mondays of the year and is generally lower than for other days of the
week;
(t)
there may be a case for higher charges in the afternoon and evening
than in the morning when LOLP is generally higher; and
(u)
the weekday peak period appears to extend only from 0900 to 2100
hours rather than 0900 to 2200.
We recommend that the definition of the peak is only changed from the present
definition to the extent that the change is significant, sensible and clearly
demonstrated by our findings. On this basis, we propose that the only changes that
should be made are to exclude Saturdays from the peak at least for the next few years
(this should be kept under review and revised once again if consumption patterns
shift) and to exclude public holidays from the peak if this is practical.
Allocation of marginal energy cost over the year
We have obtained information from EGAT on the plant that was typically at the
margin at different times of the past year, and the marginal energy costs of each of
these plants. Unfortunately, no forward-looking estimates were available, and we
have therefore had to make our own estimates of how this historical information
might change as the balance of supply and demand moves into a period of large
surplus.
We have again concluded that Saturdays should not be included in the peak period.
The data from EGAT also broadly supports the retention of the present peak hours of
the day, namely 0900 to 2200. There appears to be some seasonal variation in the
marginal energy costs but the “peak” months are not all contiguous, and they differ
substantially from the peak months identified three years ago in our 1996 report. We
do not therefore suggest that the definition of the peak is complicated at this stage by
including a seasonal variation.
In conclusion, we propose that the peak period for both marginal capacity and
marginal energy costs should be 0900 to 2200 hours for all weekdays (except public
holidays) in all months of the year. We consider that this definition provides an
appropriate balance between tariff simplicity and stability, and adequately reflects the
results of our analysis.
9
We understand that current metering for the BST and for large customer retail tariff will usually
permit separate measurement of consumption on public holidays and other working days. However,
this will require the meters to be reset annually to distinguish between public holidays and working
days during the forthcoming year. Given the potential for error, the utilities should consider carefully
whether this is practical.
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Transmission marginal costs
We summarise below our revised estimates of transmission marginal costs, describing
in turn the three components: marginal capacity costs, marginal transmission losses,
and marginal connection and customer service costs. We give further details in
Annex K.
EGAT notes that the cost of supply varies significantly across the 115/69kV system in
the PEA area. At EGAT’s request, we have estimated the cost of supply at two
locations on the 115/69kV system:
(v)
at exit from the 230:115/69kV substation; and
(w)
at the end of the 115/kV lines.
Marginal capacity cost
The marginal capacity cost is the major component of transmission marginal costs.
We have prepared our estimates using the long-run average incremental cost (LRAIC)
approach. The methodology involves the following main steps:
(x)
to identify the new demand at each voltage level in future years, and
the “optimal” incremental costs required to meet this new demand;
(y)
for each voltage level, to discount the incremental costs and the
incremental demand in each year, to produce a present value of each;
and
(z)
divide the discounted costs by the discounted demand to derive the
LRAIC.
We summarise the marginal capacity cost estimates in Table 6.2. These estimates
reflect a revised investment plan provided by EGAT.
In principle, marginal capacity costs should be allocated to the times of peak
transmission system stress. However, in practice it would be difficult to introduce
different peak periods in different parts of the country, and would add greatly to the
complexity of the bulk supply tariff.
We have obtained from EGAT information on system power flows over five main
500kV and 230kV routes on 29 to 31 January, 17 to 28 February and 1 to 16 March
1999 (i.e. 31 days in total). This information is insufficient to identify any seasonal
patterns. We have therefore focused our analysis on how the times of peak
transmission system stress vary by day of the week and hour of the day, over each of
the five routes.
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48
The available information indicates that the system power flows on all five routes are
lower on Sundays than on other days. We have insufficient information to decide
whether Saturdays should be included in the peak or off-peak period as EGAT sorted
its data so that Saturdays were included as weekdays. The information also shows
that the peak hour on each route would fall within the present peak period definition
(0900 to 2200 hours) for four out of the five routes.
In our view, the data we have are inadequate to justify regional peak periods for
transmission charging (a significantly more complex tariff structure), but broadly
support a peak period for transmission that is similar to that for generation.
Accordingly, we recommend that the transmission marginal capacity cost should be
spread over the same peak period as for generation.
Marginal transmission losses
In Table 6.3, we present estimates of the level of transmission losses, for the peak and
for the off-peak periods, based on EGAT’s revised estimates of average transmission
losses and transmission losses at the system peak. We describe the calculation in
Annex K.
Marginal connection and service costs
We have not been able to estimate accurately the marginal connection and service
costs associated with bulk supply points (BSPs) on the transmission network. This is
because EGAT’s transmission investment costs do not separate out the costs of
connection and service from those of transmission lines and substations.
We believe that the marginal connection and service costs, relating to the bulk supply
points (BSPs) associated with new demand, are around:
(aa)
50,000 Baht/MVA per year for connections at the 230kV, 115kV and
69kV levels, and 100,000 Baht/MVA per year for connections at the
33kV and 22kV levels, inclusive of capital and O&M costs; plus
(bb)
135,000 Baht per year for meter costs, including CTs and VTs,
inclusive of capital costs and O&M costs, and for meter reading,
billing and collection costs.
Distribution marginal costs
We summarise below our estimates of distribution marginal costs for the standard
voltage tiers (we have combined the estimates for the 115/69kV systems). We
describe in turn the marginal capacity costs and distribution losses for MEA’s and
PEA’s distribution networks. We give further details in Annex K.
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49
Capacity cost
We have estimated distribution marginal capacity costs using the same LRAIC
methodology as for transmission. We present our estimates of marginal costs within
each voltage tier, expressed in US$/kW per year and in Baht/kW per year, in Table
6.4. The table shows that:
(cc)
marginal costs are generally lower at higher voltages tiers, as would be
expected;
(dd)
the cumulative marginal costs in MEA and PEA’s central region are
below those of PEA’s other regions, particularly at lower voltage
levels, again as would be expected.
In general terms, we expect peak distribution system stress to occur at times of system
peak demand (as, unlike transmission flows, distribution flows are unidirectional). We
therefore propose that distribution marginal capacity costs should be allocated to the
same peak hours as for generation and transmission.
The distribution capacity cost estimates differ to some extent from those in our
Interim Report reflecting:
(ee)
combination of the 115 and 69kV voltage tiers;
(ff)
adjustment of MEA’s costs to allow for investment to maintain the
current levels of system security; and
(gg)
adjustment of the MW demand balances.
Distribution losses
We have estimated the marginal cost of distribution losses in a similar manner to
transmission system losses. We present the estimated distribution loss factors in
Table 6.5. The table shows that losses vary significantly:
(hh)
by time, we show averages for the peak and off-peak periods based on
an assumed loss function. Peak losses are some 50% higher than offpeak losses;
(ii)
by geography, particularly at lower voltage tiers.
PEA has
significantly higher loss percentages at lower voltage tiers, with the
cumulative loss percentage being over 15% in PEA’s North East
region during the peak, compared with about 6% during peak periods
in MEA’s area; and
(jj)
by voltage, especially when the cumulative effect is taken into
account.
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50
Customer-related supply costs
Finally, we present marginal customer-related costs, comprising:
(kk)
distribution connection costs; and
(ll)
customer service including meter reading, billing and collection
(MRBC) costs.
Both of these costs are largely fixed annual costs which depend on the type of
connection and meter. We give details in Annex L.
Connection costs
In Table 6.6, we set out estimates of annual connection costs for an assumed10
representative type of connection for each customer class. The annual connection
costs comprise:
(mm) annuitised capital and installation costs. This based on cost data
provided by MEA and PEA, annuitising over an average asset life of
15 years at a 7% real discount rate; and
(nn)
O&M costs assumed to be 2% of capital cost each year.
We note that:
(oo)
MEA estimates that the annualised cost of connecting a residential or
SGS LV customer is about 220 Baht pa, whereas PEA estimates that
the corresponding cost is about 180 Baht pa;
(pp)
costs for the MGS category vary from around 300 Baht pa when direct
connection is possible to around 17,000 Baht in MEA’s case and
35,000 Baht in PEA’s case, when CTs and VTs are required; and
(qq)
costs for the LGS category and many of the specific business
customers are similar to those for MGS customers but will be higher
for those at the highest voltages.
Meter reading billing and collection (MRBC) cost for MEA and PEA customers
We set out our estimates of marginal MRBC costs for the various tariff categories in
Table 6.7. The estimates include some revised data provided by PEA since our
Interim Report.
10
We have based the representative type of connection on data provided by MEA on connections by
customer tariff category, with the exception of agricultural pumping, for which we have made an
assumption.
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51
We use average costs as a proxy for marginal costs because our incremental unit cost
estimates are negative in some years11 (i.e. costs appear to decrease with increase in
customer numbers). We have assumed that marginal MRBC costs are half average
costs. We note that as MRBC costs are a small proportion of total marginal costs so
that total marginal costs are not sensitive to the assumption about the relationship
between average and marginal MRBC costs.
We note that MEA’s cost per customer appears significantly higher than that of PEA a similar pattern to the previous estimates made in 1996. While this may in part
reflect differences in underlying costs, it may also reflect differences in the allocation
of costs. Given this uncertainty, we have taken the weighted average as our best
estimate of the marginal cost in both MEA and PEA’s area.
11
Incremental unit costs are the increase in MRBC costs divided by the increase in the number of
customers. Incremental unit costs can appear to be negative if cost reductions due to efficiency gains
exceed and obscure cost increases due to increase in customer numbers.
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52
7
Marginal cost based tariffs
In this section, we discuss a number of issues related to tariff design, we present some
observations on measures necessary for competitive supply to free customers and then
we present aggregate marginal costs to each voltage level and our recommendations
on a practical tariff structure based on marginal costs. We propose, in turn, structures
for bulk supply and retail tariffs and for transmission and distribution use of system
charges.
Tariff design issues
We discuss below a number of practical issues relating to tariff design, concerning:
(a)
coverage;
(b)
extent of uniform national tariffs:
(c)
metering; and
(d)
power factor.
In general terms, we have sought to minimise changes to the tariff structure, given
that it will need to be revised once again with the introduction of the power pool.
Tariff coverage
We propose that all customers should have the right to be supplied under one of the
published tariffs though we propose that large customers should have the right to
negotiate individual contracts with terms that reflect more closely their individual
characteristics. We propose that the tariffs cover all electricity supply costs with the
exception of connection costs of new customers which would be recovered by a
separate connection charge12.
Extent of uniform national tariffs
Following discussion of our Interim Report, we have been given policy guidance that
the present uniform national tariffs should continue for all customer categories, at
least for the next tariff review period. In our Interim Report, bearing in mind the RTG
policy for decentralisation, we had suggested immediate introduction of regional
tariffs for larger customers (which would result in lower tariffs in MEA and PEA’s
central regions and higher tariffs in PEA’s other regions) while maintaining uniform
national tariffs for smaller customers. In our view, in the longer term, tariffs for all
customer categories should vary regionally to reflect regional differences in the costs
of supply.
12
An alternative would be to identify a separate connection charge for all existing customers, but this
would provide no efficiency benefits in terms of changed behaviour (as the connection costs of existing
customers are sunk costs) and would be administratively complex.
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53
To maintain the uniform national tariff, there needs to be some cross-subsidy both
within a tariff category and potentially between tariff categories. Ideally, we propose
that the necessary cross-subsidy be contained within the relevant tariff category (for
example, urban residential customers support rural residential customers). However,
to the extent that this cross-subsidy burden is not supportable within the relevant
customer categories, then some cross-subsidy from other customer categories is
necessary. We discuss the issue of cross-subsidy further in Section 9.
Metering
In making tariff recommendations, we must ensure that the cost savings which may
result from changes in consumption patterns arising from more sophisticated price
signals exceed the increased metering and other transaction costs associated with
more sophisticated tariff structures. In Table 7.1, we show data on the meter types
used by each customer category. In Table 7.2, we show data on the average costs of
the meter and its installation, and for higher voltage customers, the costs of any
associated current transformers (CTs) and voltage transformers (VTs). These data
were provided by MEA. We note that there are clear cost increases moving from 45A
to 100A single phase supply, moving to three phase supply and moving to higher
voltage supplies requiring CTs and VTs but the additional costs of time of use meters
for three phase supplies are not significant.
Ideally, all customers would have metering which recorded energy in all charging
periods (i.e. time periods in which there was significant cost variation) and which
recorded capacity usage to avoid any need for averaging based on customer
characteristics.
For larger customers, international practice is to measure both energy and capacity
usage. At low voltage, these meters can be directly connected; at higher voltages
these meters will have associated CTs and VTs. Some particular issues arise
concerning capacity charging:
(e)
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charging based on contracted demand or metered demand: as
noted in our 1996 report, contracted demand charges are used to cover
the costs of equipment reserved for a particular customer whereas
metered demand charges are used to cover the remainder of costs
which are not associated with equipment reserved for a particular user.
We recommend charging based on metered demand only as:
(i)
typically less than 10% of total capacity costs relate to
equipment close to the customer, which is not covered by a
separate connection charge, and which could be considered as
reserved for the customer; and
(ii)
this is current practice in Thailand and many other countries.
A UNIPEDE report “Structure of electricity pricing” dated
May 1997 which surveyed 31 countries showed that, for
medium and large non-domestic customers, between 48% and
60% of countries had metered demand charges and between
16% and 25% of countries had contracted demand charges
54
only (with the remainder having both metered and contracted
demand charges or other structures). For small non-domestic
customers and domestic customers, most countries did not
have demand charges;
(f)
metering peak period kWh or peak kW or peak kVA: as noted in
our 1996 report, the choice depends mainly on trade-offs between
incentives to reduce demand throughout the peak period and incentives
to reduce spikes in demand. Charging for capacity based on kWh
consumption in a defined peak period provides incentives to reduce
demand throughout the peak period but provides no incentives to avoid
spikes in demand. Charging based on peak kW or peak kVA
consumption provides no further incentive to reduce demand once a
maximum demand has been recorded in a particular charging period
but, providing the integration interval is short, provides incentives to
avoid spikes in demand. Charging based on peak kVA also provides
direct incentives to improve power factor;
(g)
integration interval; we recommend that the current 15 minute
integration interval is used to determine maximum demand (i.e. the
maximum demand in kW/kVA is taken as four times the consumption
in kWh/kVAh recorded in the 15 minute period of highest
consumption in the charging period). We make this recommendation
as:
(h)
(i)
we consider that a relatively short integration period is
necessary to provide sufficient incentive to avoid demand
spikes;
(ii)
this is current practice in Thailand and many other countries.
The UNIPEDE report mentioned above noted that in the 31
countries surveyed “the demand integration period is
generally 15 minutes (exceptions, France – 10 minutes;
Luxembourg, Japan and South Africa – 30 minutes; Norway 60 minutes)”;
allocation of capacity costs to energy charges: given the costs of
demand metering, capacity costs can, in principle, be recovered
through metered or contracted demand charges for larger customers
whereas capacity costs can be recovered only through energy charges
(or, possibly, through contracted demand charges if current limiters are
installed) for smaller customers. Efficiency considerations would
suggest all capacity costs should be recovered through demand charges
but equity and continuity considerations suggest at least some capacity
costs should be recovered through energy charges. We propose that
capacity costs are recovered as follows:
(i)
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bulk supply tariff: through energy charges as this was
preferred when we debated the issue in 1996, is consistent
with the introduction of a power pool and is less likely to
55
result in demand spike problems (because of the averaging
effects at higher voltages);
(ii)
medium general service, large general service and specific
business retail tariffs: in part through demand charges (as all
customers on these tariffs already have demand metering and
demand spikes are more likely to be an issue) and in part
through energy charges. In this section we illustrate charges
assuming that 50% of transmission and distribution capacity
costs are recovered in the demand charge. Remaining
capacity costs are to be recovered in energy charges. We note
that the present retail tariff structure is intended to recover
generation and transmission capacity costs through energy
charges and distribution capacity costs through demand
charges. In setting scaled charges in Section 9 the allocation
is designed to maintain some continuation of tariffs, so that
rather different percentages of capacity cost are allocated to
demand charges.
For smaller customers, international practice is to employ an energy only meter
perhaps with some time-of-day rates and, occasionally, with current limiters.
Accordingly, we propose that capacity costs for residential, small general service and
pumping retail tariffs are recovered:
(i)
through demand charges where suitable metering exists; and
(j)
otherwise through energy charges (as installation of demand metering
or current limiters would not be cost-effective)13.
Power factor
We have reviewed and broadly endorse the key conclusions of the work recently
carried out by Chulalongkorn University. On the basis of a sample of model networks
provided by the utilities, its report “Optimum Power Factor Study” noted that:
(k)
power factor correction is most cost effective in $/kVAr terms when
applied on MEA’s and PEA’s distribution systems (as power factor
correction on transmission systems is far electrically from the load and
power factor correction at dispersed distribution loads loses scale
economies);
(l)
bulk supply power factor charges should apply for lagging power
factor below 0.875 in 2001 and below 0.900 in 2005 (as optimum
power factor at bulk supply points will be between 0.875 to 0.925 in
13
As an illustration, if directly signalling the cost of capacity through demand metering to an average
residential customer caused some 10% of its demand to shift from peak to off-peak period, the annual
saving would be some 200 Baht whereas the annual additional cost of demand metering would be some
1600 Baht.
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56
2001 and 0.900 and 0.950 in 2005). Accordingly, we propose that bulk
supply power factor charges apply for lagging power factor below
0.875 to 2003 and for power factor below 0.900 from 2004. We note
that a cost-reflective power factor charge to 2003 would be some
1.75Baht/kVar/month for each lagging kVAr in excess of the kVAr
level equivalent to a power factor of about 0.875. Chulalongkorn
University estimates that the value:
(i)
to the transmission system of improvement in lagging power
factor at bulk supply points is some 1.75Baht/kVar/month for
improvement from 0.85 to 0.875 in 2001 (and some
3.21Baht/kVar/month for improvement from 0.85 to 0.900 in
2005); and
(ii)
to the distribution system of improvement in lagging power
factor
at
bulk
supply
points
is
a
further
12.49Baht/kVar/month for improvement from 0.85 to 0.875 in
2001;
(m)
retail supply power factor charges should apply for lagging power
factor below 0.900 for above 2MW customers and below 0.850 for
other customers. Chulalongkorn University estimates that the value of
improvement in lagging power factor at customer terminals is lower
than 10Baht/kVar/month for all of the MEA sampled systems and for
most of the PEA sampled systems. Accordingly, the current power
factor charge of around 15Baht/kVar/month for each lagging kVar in
excess of the kVAr level equivalent to a power factor of about 0.900 or
0.85 remains broadly appropriate;
(n)
power factor bonus should not be offered for power factor within the
target ranges as this may create an overcompensation problem in the
long run (and, in any event, each distribution utility makes substantial
savings itself if its power factor is within the target range).
Given the desire expressed by NEPO to include some incentive to improve power
factor (above that represented by charges reflecting marginal costs), we propose that:
(o)
bulk supply tariff: power factor charges be introduced as at least
1.75Baht/kVar/month for each lagging kVAr in excess of the kVAr
level equivalent to a power factor of about 0.875 (we understand that
the Energy Policy Committee has recently agreed to apply a power
factor charge of 5.0Baht/kVar/month with effect from January 2002);
(p)
retail tariff: power factor charges be amended for MEA and introduced
for PEA as:
(i)
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LGS or specific business over 2MW: 15Baht/kVar/month for
each lagging kVAr in excess of the kVAr level equivalent to a
power factor of about 0.900;
57
(ii)
(q)
MGS or specific business below 2MW: 15Baht/kVar/month
for each lagging kVAr in excess of the kVAr level equivalent
to a power factor of about 0.850;
power factor rebates should not be offered for power factor within the
target ranges.
Current practice in MEA is an additional power factor charge for each lagging kVAr
in excess of the kVAr level equivalent to an average power factor of about 0.85
[cos(tan –10.63)]. This is generous compared with eg Portugal, where charges apply
when average power factor falls below 0.93 [cos(tan –10.4)], Israel where charges
apply when power factor falls below 0.92, and Turkey and most UK distribution
companies which make charges when power factor falls below 0.89 [cos(tan –10.5)].
Free customers
Although mostly not related to our work on tariffs, we note that there will need to be a
number of measures taken to allow free customers to obtain competitive supply
including:
(r)
publication of transmission and distribution use of system charges to
enable competitive suppliers to provide energy to free customers
through existing networks;
(s)
administrative arrangements to deal with the (inevitable) mismatches
between the energy consumed by a free customer and the energy
provided by its supplier. (One approach would be for EGAT to
provide or absorb excess at a defined price, the settlement price, in a
number of distinct settlement periods. This price might most simply be
set equal to the generation component of the BST. Another approach,
which would inhibit competition, would be to adjust the generation
component of the BST to reflect the load factor of provision or
absorption of excess);
(t)
registration of mismatches, approaches include:
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(i)
installing metering on both customer and supplier suitable to
record the actual energy consumed by a free customer and the
energy provided by its supplier in each settlement period; and
(ii)
installing metering on the supplier only and imputing energy
consumed by a free customer in each settlement period based
on defined customer characteristics.
58
Recommended tariff structure based on marginal costs
In Section 6 we showed separately the pure marginal costs for generation,
transmission, distribution and customer related costs. In Table 7.3 we show the
generation, transmission and distribution marginal capacity costs and customer related
costs for each tariff category. In Table 7.4 we show the marginal costs cumulated to a
particular voltage level. We have cumulated the transmission and distribution cost
using the following stylised assumptions:
(u)
EGAT’s costs are cumulated to each of the key bulk supply voltages,
the exit of the 500:230kV substation, the exit of 230:115/69kV
substations; the end of 115kV lines and the exit of 115kV:MV
substations;
(v)
customers in MEA’s area bear the cumulated costs of EGAT’s
generation and of EGAT’s transmission system to the exit of the
500:230kV sub station, of the exit of MEA’s 230kV lines and MEA’s
lower voltages as appropriate; and
(w)
customers in PEA’s area bear the cumulated costs of EGAT’s
generation and transmission system to the exit of the 230:115kV
substation, of PEA’s 115kV system, and PEA’s lower voltages as
appropriate.
We have therefore presented the costs for EGAT at the key bulk supply voltages, and
for MEA and PEA at the exit of each standard voltage tier. The model reflects
EGAT’s concerns that bulk supply from the 115kV system should be charged for at a
different rate depending on whether the bulk supply point is at the exit of the
230:115kV sub-station, or at the end of 115kV lines.
We note that the costs are denominated in a combination of:
(x)
per kWh costs, for generation costs, including losses;
(y)
per kW per year costs, for transmission and distribution capacity costs;
and
(z)
fixed costs, for MRBC costs. (We do not show marginal connection
costs, which would apply only to new customers.)
The table shows that:
(aa)
energy costs vary only slightly between regions; and
(bb)
cumulative transmission and distribution marginal costs vary much
more significantly between regions, and that they are significantly
higher at lower voltage tiers.
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Based upon our examination of marginal costs, and the above principles we now
propose a set of marginal costs based tariffs (i.e. before scaling to meet financial
requirements). We consider in turn pure marginal cost based tariffs for:
(cc)
the bulk supply tariff;
(dd)
retail tariffs;
(ee)
transmission use of system (TUOS) charges; and
(ff)
distribution use of system (DUOS) charges.
Bulk supply tariff
A Bulk Supply Tariff (BST) will continue to be offered by EGAT to MEA and PEA
and, in addition, we propose will now be offered to EGAT’s direct customers. The
structure of the BST should reflect the marginal costs of:
(gg)
generation produced and delivered to EGAT’s grid, including both the
energy and capacity components;
(hh)
EGAT’s transmission capacity; and
(ii)
transmission losses within EGAT’s grid.
In addition, bulk supply customers should be charged a connection fee for any new
investment required to expand bulk supply point connection capacity and a power
factor charge for lagging kVAr below the threshold recommended by Chulalongkorn
University.
We have calculated a marginal cost based BST tariff schedule (excluding connection
and power factor charges). We present the results as per kWh charges in Table 7.5.
We note that the BST varies by:
(jj)
time: the peak period (Monday to Friday, 09.00 to 22.00, excluding
public holidays) BST is between two and three times the off-peak BST,
depending on voltage level. This reflects the allocation of capacity
costs to the peak period; and
(kk)
voltage: for example, in peak periods, bulk supply costs at medium
voltage are about 60% more than the costs at 230kV.
Retail tariffs
Based on the above tariff design principles we recommend the following structures
for retail tariffs:
(ll)
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residential customers should continue to be charged under a
progressive block tariff structure, but the number of blocks should
60
be reduced to three: less than 35kWh/month, between 35kWh/month
and 150kWh/month; and above 150kWh/month14.
Ideally, the
progressive block structure would be replaced with a single “flat rate”
charge, plus a fixed monthly service charge to cover the fixed costs of
MRBC and a rebate for low consumption customers. Such a structure
would be more cost reflective than the current progressive block
charging structure since the marginal cost of energy is independent of
the kWh of consumption by a given customer in the month and would
protect low consumption users. However, in discussion of our Interim
Report, it was agreed that it would be more acceptable to retain some
progressive blocks;
(mm) SGS, government, agricultural pumping and PEA’s temporary
customers should face a Baht/kWh charge which varies by voltage
level only to reflect generation, transmission and distribution system
costs (including connection costs associated with existing customers)
plus a fixed monthly charge to reflect MRBC costs15. In the case of
SGS and agricultural pumping, charges are not currently differentiated
by voltage level. Although most SGS customers are connected at LV,
and most agricultural customers are connected at MV, we propose that,
subject to any policy constraints, charges should be differentiated by
voltage levels;
(nn)
MGS, LGS and specific business should be charged:
(i)
demand charges in the peak period only, and that the
demand charges should be consistent with the current level of
demand charge;
(ii)
peak and off-peak energy charges16 to reflect time varying
energy costs (including losses) and the remainder of the
transmission and distribution capacity costs;
(iii)
monthly service charges to reflect the fixed costs of MRBC;
and
(iv)
power factor charges.
14
Residential customers should also have the right to opt for a Time of Use tariff provided they will
pay for appropriate metering. The Time of Use tariff should be the same as the Time of Use tariff
faced by MGS, LGS and Specific Business customers
15
These customers should also have the right to opt for a Time of Use tariff, provided they will pay for
appropriate metering
16
We recognise that not all existing MGS, LGS and Specific business customers have a meter which is
capable of measuring peak and off-peak energy, so that a transition tariff, with a single Baht/kWh
energy rate will be necessary
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61
The peak period should be defined as 09.00 to 22.00, on Monday to
Friday (not Saturday as now) and, if practical, should exclude public
holidays. Some MGS, LGS and specific business customers currently
face tariffs with “flat rate” energy charges. We propose that these
customers should be given incentives (or simply be required) to
migrate to tariffs with peak and off-peak energy charges (as these
customers are large enough to justify appropriate metering). One
incentive would be to offer the choice between cost reflective peak/offpeak energy tariffs and “flat rate” transition tariffs which exceed costs.
Further, we suggest that the utility bears the cost of the necessary
meter change;
(oo)
Standby customers. We have reviewed the structure of existing
standby charges. Standby customers pay the same Baht/kW capacity
and Baht/kWh energy charges, as MGS, LGS and Specific
business customers in months in which they take standby power,
and receive a 70% discount on demand charges in months in
which they do not take standby power17. Demand charges are based
on contracted standby demand, rather than metered demand. We
consider that the current structure is generally appropriate, but
propose that they pay the same Baht/month service charge as LGS
customers, since they are likely to be large customers;
(pp)
Interruptible customers. If interruptible customers are genuinely
interruptible at all times of peak capacity, then they should not face
capacity related costs, and should be charged for energy related costs
only. However, in a system, such as Thailand, characterised by
little seasonality and a prolonged peak each week day, it is likely
that interruptible customers will contribute to capacity
requirements unless the terms of the contract allow highly frequent
and prolonged interruption. Under the current tariff interruptible
customers pay the same Baht/kWh energy charges as comparable noninterruptible customers, but receive a discount of about half to twothirds on their Baht/kW charges on the interruptible portion of their
demand. Under the current structure Baht/kW charges are related to
distribution costs, thus they effectively receive a reduction against
distribution capacity costs. However, transmission capacity costs at
higher voltages are more likely to be avoidable through interruption
than distribution capacity costs incurred close to the customer
connection. Therefore we propose that interruptible customer
receive a 50% reduction on both transmission and distribution
costs on their interruptible demand, and pay the same charges as
MGS, LGS and Specific business customers on their Firm Demand18.
17
Unless they are qualified co-generators under the SPP regulations, in which case they receive an 85%
discount.
18
We have defined Interruptible Demand and Firm Demand as per the MEA tariff booklet
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62
We also propose that they pay the same Baht/month service charge as
LGS customers, since their demand is likely to exceed 2MW; and
(qq)
Street lighting. Street lighting is mainly provided free of charge, but
we recommend that charges should be introduced for street-lighting.
Where street lighting is metered, we propose that the charge be
made per kWh of metered consumption. Where the street lighting
is unmetered, we propose that the charge be made on estimated
consumption. The kWh consumption can be estimated based upon on
simple assumptions on wattage and the hours in the month for which
the light operates, and should be charged at a flat rate Baht/kWh tariff
which reflects the expected relative peak and off-peak usage of street
lights.
In addition, all new customers should be charged a cost reflective connection
charge19. This could be charged as a single initial sum, or as a monthly sum based on
cost recovery over the life of the asset (we suggest 15 years). We consider that
connection charges for residential and SGS could continue to include some averaging
(for instance by banding charges according to connection distance).
We have calculated revised marginal cost based tariffs which reflect our
recommended structures and marginal cost calculations. We show the calculated
marginal cost based tariffs, excluding connection (which are only applicable to new
connections), for each major tariff category at each relevant voltage in Table 7.6. We
also show the average charge per kWh of consumption that this implies for a typical
customer on this tariff.
We note that:
(rr)
the estimated marginal cost based charge for residential customers is
2.00 Baht/kWh, plus a fixed monthly charge of approximately 12
Baht/month;
(ss)
the estimated marginal cost based charge for SGS customers at low
voltage is 2.24 Baht/kWh plus a charge of 17 Baht/month. The
Baht/kWh charge exceeds the equivalent charge for residential
customers reflecting SGS customers’ relatively higher use of peak
period energy;
(tt)
the marginal cost based charge for agricultural pumping for the
majority of customers (who are connected at MV) is 2.13 Baht/kWh
kWh with a monthly charge of 29 Baht/kWh. At LV the Baht/kWh
charge of 2.69 is higher than for residential or SGS customers. This
19
There may need to be some connection charges based on standard costs for small customers (as at
present)
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63
reflects the assumption that agricultural pumping happens only during
daylight hours;
(uu)
government tariffs are generally higher than other tariff categories at
equivalent voltages, reflecting their higher relative peak period usage
of electricity;
(vv)
MGS, LGS and specific business tariffs will contain identical
demand, peak and off-peak energy charges at a given voltage, and will
differ only in respect of service charges; and
(ww) the marginal cost based charge for street-lighting is 1.59 Baht/kWh.
Although it is policy to retain nationally uniform tariffs for all tariff categories in the
short-term, in Table 7.7, we show illustrative geographically varying marginal cost
based tariffs for the smaller customers.
These tariffs illustrate that geographically varying tariffs could result in some
residential customers paying up to 35% more than customers in other regions. The
effect is more pronounced for tariff categories such as agricultural, with a relatively
greater peak period usage.
Transmission and Distribution Use of System Charges
An SPP or IPP selling directly to customers and using:
(xx)
EGAT’s network only will be required to pay a Transmission Use of
System (TUOS) charge to EGAT, to cover the capacity cost of the
network;
(yy)
MEA’s or PEA’s network only will be required to pay Distribution
Use of System (DUOS) charge; and
(zz)
EGAT’s network and MEA’s or PEA’s network will have to pay both
TUOS and DUOS charges.
Nationally averaged marginal costs based TUOS and DUOS charges, including
relevant loss factors are shown in Table 7.8. TUOS costs are apportioned 100% to
Baht/kWh charges like the BST, and DUOS costs are apportioned 50% to Baht/kWh
charges and 50% to Baht/kWh charges, like retail tariffs. The costs are cumulated
separately for transmission and distribution down to a particular voltage tier. The
charge payable comprises:
(aaa)
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cumulated capacity charges from the point of generator connection to
the to the point of customer connection. The cumulation of charges
takes appropriate account of the fact that capacity used by a customer
at voltages higher than the connection voltage exceeds metered
demand due to distribution losses; and
64
(bbb) cumulative transmission/distribution energy losses charges . The
SPP/IPP must deliver enough energy to meet its customers’ metered
demand, plus the relevant cumulated transmission and distribution
losses set out in Table 7.8.
Cross-subsidy between customer categories
We now compare the marginal cost based tariffs with current tariffs to identify the
extents of cross-subsidy among customer categories in current tariffs. Customer
categories which pay more than marginal cost contribute to cross-subsidy and
customer categories which pay less than marginal costs receive cross-subsidy.
Bulk supply tariff
We have compared the revised estimates of marginal cost based BST with the
“current BST” to determine whether there is cross-subsidy between BST consumption
at different voltages, or at different times. We have taken the “current BST” to mean
the projected BST schedule for FY1999 assuming a wholesale Ft of 0.37 Baht/kWh
(EGAT’s own assumption). The results, expressed in constant FY1998 price levels,
are shown in Table 7.9.
The comparison shows that:
(ccc)
the “current BST” generally exceeds marginal cost based BSTs. On
average, the current BST exceeds marginal cost by 4%;
(ddd) there is a relative cross-subsidy in favour of peak consumption..
Current off-peak tariffs exceed marginal cost, whilst peak tariffs are
approximately equal to or below marginal cost; and
(eee)
there is a relative cross-subsidy in favour of bulk supply at lower
voltages. Current peak charges are at around marginal cost for bulk
supply at 230kV, some 10% below marginal cost for bulk supply at the
exit of 230kV:115/69kV substations, and 30% below marginal cost for
bulk supply at lower transmission voltages.
Retail tariffs
We have also compared the marginal cost based retail tariffs with “current” retail
tariffs for each customer category to identify existing cross-subsidy between retail
customer categories. In Table 7.10, we present the comparison, expressed in FY1998
price levels and based on the following definitions:
(fff)
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marginal cost based average tariffs: the national revenue, excluding
VAT, from the relevant customer category divided by forecast energy
demand; and
65
(ggg) “current average tariffs”: the estimated average unit revenue for the
relevant customer category in FY1999, excluding VAT and including
EGAT’s projection of Ft for FY1999 (0.41 Baht/kWh).
The comparison between marginal cost based tariffs and “current” tariffs shows that:
(hhh) “current” tariffs are generally in excess of marginal cost based
tariffs by about 7%;
(iii)
there is a significant relative cross-subsidy in favour of agricultural
pumping customers for whom “current” tariffs are about 40% below
marginal costs20. Clearly, street-lighting is also subsidised since this
is almost exclusively provided free of charge (although we have not
shown a tariff, in line with the policy guidance received);
(jjj)
residential customers, as a class, pay tariffs which broadly reflect
marginal cost. However, the existence of the progressive block means
that larger residential customers cross-subsidise smaller residential
customers.
We have calculated that customers consuming
35kWh/month “currently” pay an average of 1.49Baht/kWh, those
consuming 150/kWh/month pay 2.05Baht/kWh, and large residential
customers pay an average of 2.60Baht/kWh;
(kkk) business customers generally pay in excess of marginal cost:
(i)
LGS customers and Specific Business tariffs are around 15%
in excess of marginal cost. The data shown relate to those on
the Time of Day (ToD) tariff, the majority of customers; and
(ii)
MGS and SGS customers face tariffs approximately 5% to
10% in excess of marginal cost.
As with bulk supply tariffs, we note that marginal cost retail tariffs will have to be
scaled up to allow the companies to meet their revenue requirements.
Summary
In this section, we have set out practical marginal cost based tariffs for the main
customer categories and compared these with current tariffs to indicate the extent to
which current tariffs are not cost-reflective. In Sections 8 and 9 we adjust these
marginal cost based tariffs to meet the financial requirements. In making these
adjustments, we seek to ensure that tariffs are as cost reflective as possible, subject to
social considerations and continuity considerations, because cost-reflective tariffs
provide the correct price signals for producers and customers to make investment and
operational decisions (for example when considering trade-offs between expanding
electricity supply or taking demand side measures).
Even taking into account PEA’s revised view that the majority of agricultural pumping customers are
connected at MV
20
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66
8
Recommended bulk supply tariff
In this section we present the recommended Bulk Supply Tariff (BST). We begin by
outlining the key principles behind the design of the BST. We then present a high
level explanation of the derivation of the recommended BST from marginal costs, and
the recommended BST itself. Finally, we compare our recommended tariff structure
with the current tariff structure.
Key principles
We have designed the BST on the following key principles:
21
(a)
the BST should continue to be nationally uniform. We have
insufficient evidence to introduce geographically varying charges and
in any event we have received policy guidance that charges should
continue to be nationally uniform;
(b)
the BST should reflect the sum of generation marginal costs, scaled
to meet the financial requirement of EGAT’s generation business,
and transmission marginal costs, scaled to meet the financial
requirements of EGAT’s transmission business21. This approach to
scaling ensures that competition between EGAT’s generation business
and SPPs/IPPs is not distorted;
(c)
the base tariff should reflect expected 1999 fuel price levels and
inflation of 2.8%. The tariff adjustment mechanism discussed in
Section 10 should compensate for differences between out-turn fuel
price levels and expected 1999 fuel price levels, and for changes in
inflation from 2.8%;
(d)
the base BST should permit the design of base retail tariffs which are
on average, at least 2% lower in nominal terms in 2000, than the
average total retail tariff in 1999 (i.e. than the base BST and wholesale
Ft in 1999), and which remain at that level until 2003;
(e)
there should be separate charges for bulk supply at the exit of
230:115/kV substations and at the end of 115kV lines, given
substantial differences in underlying bulk supply costs. This should
also help to ensure that 115kV lines, which are essentially distribution
lines, are constructed by the distribution utilities;
(f)
the BST should include power factor charges to provide incentives
for bulk users to manage the power factor on their system, in the same
way as retail customers. As noted in Section 7, marginal cost based
bulk supply tariff power factor charges would be introduced at 1.75
Baht/kVar/month for each lagging kVAr in excess of the kVAr level
As set out in Section 5.
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67
equivalent to a power factor of about 0.875. However, we reflect the
power factor charges of 5 Baht/kVar/month agreed by the Energy
Policy Committee in our proposed tariff; and
(g)
existing connections should not be transferred to alternative
voltages, other than for reasons of substantial demand growth.
The voltage relativities in the BST are intended to provide appropriate
price signals to influence the investment decisions of new users.
However, there will be inefficient investment if existing users seek to
change connection voltage (as investment has been made in their
existing connections). Administrative measures are likely to be
required to ensure such transfers do not occur.
Recommended BST
In Table 8.1 we show the components of the scaled BST, the scaled energy and
transmission charges, and the resultant recommended BST. All figures exclude VAT.
Table 8.1 shows that:
(h)
we have scaled the energy charge to 115% of marginal costs to
ensure that the generation business meets its financial requirements.
The requirement to scale up marginal generation costs is to be
expected, given the excess capacity projected to be commissioned in
the next few years;
(i)
we have scaled the transmission charge to 70% of marginal costs,
indicating that marginal cost exceeds the financial requirements of the
transmission business;
(j)
the overall impact of the scaling to meet the respective financial
requirements of generation and transmission is to:
(i)
increase tariffs relative to marginal costs at higher
voltages and during off-peak hours where generation is a
greater proportion of total cost; and
(ii)
reduce tariffs below marginal costs at lower voltages
during peak hours where transmission is a greater proportion
of total costs.
We do not propose to introduce separate charges for connection to the transmission
system during the tariff review period. As noted during discussion of the draft of this
report, the BST allows recovery of the total costs of transmission including
connection costs – to introduce separate connection charges would therefore represent
double counting. However, we suggest such separate cost-reflective connection
charges are established in due course.
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In Table 8.2 we compare the recommended BST with the current BST. We show the
current BST, excluding the MEA surcharge and PEA discount, and assuming
wholesale Ft is 0.37Baht/kWh (consistent with the fuel price assumption in the
recommended new base tariff).
In terms of structure, Table 8.2 illustrates a number of differences between the
recommended and current BST. The recommended BST:
(k)
includes separate charges for bulk supply at the exit of 230:115kV
substations and at the end of 115kV lines;
(l)
includes an average charge for bulk supply at the exit of 230:115kV
substation from the exit of a 230:69kV station;
(m)
has a peak period of 09.00 to 22.00 from Monday to Friday, excluding
public holidays rather than from Monday to Saturday, including public
holidays; and
(n)
has two rather than three energy rates.
In terms of level, Table 8.2 shows that the recommended BST would result in:
(o)
similar levels of charge during peak periods at 230kV;
(p)
slightly higher peak period charges at the exit of 230:115/69kV
substations;
(q)
significantly higher peak period charges at the exit of 115kV lines and
at MV; and
(r)
slightly lower off peak charges (and a longer off-peak period).
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69
9
Recommended retail tariffs
In this section we present two sets of revised retail tariffs: “target base tariffs” which
are fully rebalanced to reflect underlying marginal costs and “recommended base
tariffs” which are partially rebalanced reflecting policy constraints agreed with
NEPO. In any year of the tariff period FY2000 to FY2003, the total tariffs will
comprise recommended base tariffs plus the expected tariff adjustment Ft (which has
been rebased and set to zero in FY1999).
We begin this section by summarising the key principles used to derive the target base
tariffs and the resulting target base tariffs. Next, we summarise the key principles
used to derive the recommended base tariffs from target base tariffs and present the
recommended base tariffs in the form of a revised tariff booklet. The tariff booklet
shows recommended base tariffs for each tariff category together with the
recommended transmission use of system (TUOS) and distribution use of system
(DUOS) charges. We then compare the recommended base tariffs with existing
tariffs. Finally, we present expected total tariffs. We set out the detailed calculations
in Annex N.
Target base tariffs
We have derived the target tariffs based on the following principles and constraints:
(a)
the tariffs should be based on scaled marginal costs for each tariff
category at each voltage level. We have reflected:
(i)
a weighted averaged of the generation and transmission
charges at the various bulk supply voltages presented in
Section 8, and applied loss factors to calculate the generation
and transmission cost components at each standard
distribution voltage level;
(ii)
nationally averaged marginal distribution costs for each
voltage level scaled down by about 70% to meet the
combined financial requirements of MEA’s and PEA’s
distribution businesses;
(iii)
marginal customer related costs scaled up by about 340% to
meet the combined financial requirements of MEA’s and
PEA’s retailing businesses;
(b)
the base tariff should reflect expected 1999 fuel price levels. The
tariff adjustment mechanism (Ft) discussed in Section 10 should
compensate for differences between out-turn fuel price levels and
expected 1999 fuel price levels;
(c)
the average base tariff for FY2000 should be at least 2% lower in
nominal terms than the average total tariff for 1999 (i.e. the base
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70
tariff plus Ft for 1999), and should remain at that level throughout the
period to FY2003;
(d)
in designing tariffs for MGS, LGS and Specific business customers we
have allocated 100% of transmission capacity costs to peak
Baht/kWh charges and 100% of distribution capacity costs to
Baht/kW charges. This approach is consistent with current practice,
and the scaled demand charges are similar in magnitude to current
demand charges, so maintain consistency of price signal.
We present a summary of the target retail tariffs for FY2000 for each tariff category at
each relevant voltage level in Table 9.1. Tariffs are shown in nominal terms and
exclude VAT.
In Table 9.2 we compare the target base tariffs with 1999 total tariffs for each tariff
category. The 1999 total tariffs, include an estimated retail Ft level of 0.41, the
expected 1999 level. We show the comparison for the aggregate of the larger
customers (MGS, LGS and Specific Business customers) since we have proposed a
unified Baht/kW and Baht/kWh tariff structure for these categories 22. Table 9.2
shows that if tariffs were fully rebalanced agricultural pumping, residential and
government tariffs would increase by 28%, 9% and 7% respectively. There
would be a reduction in tariffs paid by larger customers and SGS customers of
about 6%. Temporary customers would also pay less.
Recommended tariffs
Following discussions with NEPO, it was agreed that recommended tariffs should
reflect target tariffs as far as possible subject to the following social policy
considerations :
(e)
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);
(f)
the average unit base tariff for each “customer category” in FY2000
should be no more than the average total tariff in FY1999. For this
purpose we have defined customer category to mean tariff category,
with following exceptions:
(i)
22
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 to 150kWh/month) and large (above
150kWh/month);
There are minor differences with respect to retail charges and power factor charges
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71
(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 do not apply this constraint to street lighting, for which a
tariff is being introduced for the first time23.
These policy constraints require cross-subsidy between customer categories as well as
within customer categories. Agricultural pumping, residential and government tariffs
are cross-subsidised by charges in excess of target tariffs levied on other categories.
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 street lighting tariffs, which is the amount necessary to recover
the cross-subsidy in favour of agricultural, residential and government customers.
We present the resulting recommended base tariff schedules in the revised Tariff
Booklet. At NEPO’s request, we also show two further sets of base retail tariffs in
Annex R:
(g)
“Unrebalanced tariffs”. Existing tariffs uniformly scaled to the new
financial requirements;
(h)
“Alternative rebalanced tariffs”. Existing tariffs rebalanced towards
target tariffs but with a different set policy constraints from those
reflected in the recommended base tariffs. The key difference is that
tariff rebalancing can increase tariffs for any tariff category by up to
10% pa in real terms.
Tariff Booklet
In the Tariff Booklet, each schedule shows the total Baht/kW, Baht/kWh and
Baht/month charge at each relevant voltage, expressed in nominal terms and
excluding VAT. We also show appropriate power factor and connection charges.
These charges remain constant in nominal terms throughout the period. We show the
unbundled generation, transmission, distribution and retail components of
recommended base tariffs in Annex N.
We propose that the new tariff schedules replace the existing tariff schedules and that
customers are obliged to transfer to the new tariff schedules as soon as appropriate
metering can be installed. We see significant disadvantages in leaving customers on
obsolete tariffs, both in terms of fairness and in terms of practicality. We describe
each schedule in turn below.
23
We understand that under some abnormal circumstances, a very small percentage of street lighting is
currently charged for
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In Schedule 1, we set out our recommended residential tariffs. We recommend a
three step progressive block tariff structure. We recommend base charges of: 1.346
Baht/kWh for consumption less than 35kWh/month; 1.820 Baht/kWh for
consumption between 35kWh/month and 150kWh/month; and 2.525 Baht/kWh for all
consumption over 150kWh/month. In addition, we propose that:
(i)
customers whose consumption consistently exceeds24 150kWh/month
should face a standing charge of 40.90 Baht/month, which fully
reflects scaled customer related costs;
(j)
customers whose consumption regularly exceeds 35kWh/month should
pay half that amount as a monthly standing charge;
(k)
there should be a minimum charge of 10 Baht/month.
We have not proposed a monthly standing charge for small residential customers
since it is not consistent with social policy considerations.
We have also illustrated a Time of Day which residential customers may opt for if
they pay for appropriate metering. This tariff is the same as the Time of Day tariff
recommended as standard for larger customers.25
In Schedule 2, we set out our proposed tariffs for Small General Service (SGS)
customers. We propose that SGS customers on the standard SGS tariff connected at
LV will pay a single flat rate charge of 2.436 Baht/kWh, plus a standing charge of
57.95 Baht/month. SGS customers on MV will pay a lower flat rate charge of 2.018
Baht/kWh. SGS customers may also opt for the Time of Use tariff, provided that they
pay for appropriate metering.
In Schedules 3, 4 and 5, we set out our proposed tariffs for Medium General Service
(MGS), Large General Service (LGS) and Specific Business customers
respectively.
We recommend that the should all three tariff categories should face the same
structure and level of charges, with the exception of monthly and power factor
charges. All larger customers should face Time of Use charges, with peak and offpeak Baht/kWh rates. However, we recognise that not all larger customers currently
have appropriate metering, and that it is impractical to install such metering
immediately. Therefore, we have calculated two tariffs:
(l)
the standard tariff for larger customers with peak and off-peak energy
rates which will result in charges that will reflect an individual
customer’s characteristics;
24
We propose that the current definition of large residential customers, with a consumption of greater
than 150kWh/month, determines whether a residential customer is deemed to consistently exceed
150kWh/month (and is therefore liable for the standing charge).
25
Including the 3% cross-subsidy element for larger customers
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(m)
a transition tariff, which has a single Baht/kWh energy charge for all
periods. This tariff has been calculated to be equivalent to the standard
tariff for customers whose characteristics are typical of larger
customers.
We recommend that MEA and PEA install metering so that larger customers can be
moved to the standard tariff as soon as reasonably practical.
The standard tariff includes a special category of “Existing 115kV customers on
TOU” tariffs26. Exceptionally, given representation made during discussion of the
draft of this report, we suggest that the existing 115kV customers on the TOU tariff
continue to enjoy this reduction (i.e. they continue to pay some two–thirds of the
Baht/kW charges and some 95% of the peak Baht/kWh charges of 69kV customers).
By way of example, the schedules show that larger customers connected at 69kV
should pay the following base tariffs:
(n)
a demand charge of 76.73 Baht/kW/month;
(o)
a peak energy charge of 2.407 Baht/kWh;
(p)
an off-peak energy charge of 0.974 Baht/kWh; and
(q)
a standing charge of 218.17 Baht/month for MGS, 277.97 Baht/month
for LGS and 210.44 Baht/month for Specific Business customers.
All larger customers should face power factor charges. MGS and Specific Business
customers should pay 15 Baht/kVar/month for each lagging kVAr in excess of the
kVAr level equivalent to a power factor of about 0.850, whilst the LGS customers
should pay 15 Baht/kVar/month for each lagging kVAr in excess of a power factor
level of about 0.900.
In Schedule 6, we present our proposed tariffs for government customers. We
propose that the standard tariff structure should comprise a single Baht/kWh charge
plus a standing charge. However, like other tariff categories, government customers
may opt for the Time of Use tariff if they pay for the appropriate metering.
Government customers will pay a standing charge of 163.23 Baht/month plus flat rate
charges of:
(r)
2.315 Baht/kWh at LV;
(s)
1.906 Baht/kWh at MV; and
(t)
1.736 Baht/kWh at 69kV and above,
26
No such category exists for the transition tariff, since by definition, all existing customers on TOU
tariffs have metering capable of measuring peak and off-peak usage so will be on the standard tariff.
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In Schedule 7, we set out our proposed tariffs for agricultural pumping. We propose
that they should pay a standing charge of 98.85 Baht/month plus a flat rate charge of
1.554Baht/kWh . Agricultural customers may also opt to take the Time of Use tariff
if they pay for the appropriate metering.
In Schedule 8, we set out our proposed tariff for temporary customers, namely a
standing charge of 40.90 Baht/month plus a flat rate charge of 2.614 Baht/kWh.
In Schedule 9, we set out our proposed tariff for standby customers. For continuity,
we have based the design of the standby tariff on the principles used for the current
standby tariffs:
(u)
in months in which standby power is consumed, standby customers
will pay the same Baht/kWh and Baht/kW charges as the relevant
MGS, LGS or Specific Business tariff that would otherwise apply,
provided that they do not exceed the contracted standby demand.
However Baht/kW charges will continue to be charged on contracted
standby demand, rather than metered demand. If the contracted
demand is exceeded, Baht/kWh charges, which cover distribution
costs, are charged at a penal rate of double the relevant MGS, LGS or
Specific Business tariff; and
(v)
in months in which standby customers do not take standby power they
receive a 70% discount on Baht/kW charges, unless they are qualified
as co-generation plant under the Small Power Producers regulations, in
which case they receive a 85% discount.
We also propose that standby customers pay the same standing charges and power
factor charges as LGS customers, since standby customers are likely to be larger than
2MW.
In Schedule 10, we set out our proposed interruptible tariff. As stated in Section 7,
we believe that interruptible customers should pay the relevant generation costs and
50% of the transmission and distribution capacity costs of non-interruptible
customers. Accordingly, the interruptible tariff is based on the same generation cost
as the MGS/LGS/specific business tariff, but 50% of the transmission and distribution
related Baht/kW charge. We also propose that interruptible customers should face the
same standing charges and power factor charges as LGS customers, since they are
likely to be over 2MW demand.
In Schedule 11, we set out our proposed new tariff for street lighting, a flat rate charge
of 1.626 Baht/kWh.
Recommended TUOS and DUOS charges
We have calculated TUOS and DUOS charges applicable to customers being supplied
independently of EGAT, MEA or PEA. TUOS and DUOS charges both comprise
capacity charges and loss factors. These charges have been designed in a manner
which does not distort competition, specifically:
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(w)
the TUOS charges reflect the same scaled transmission marginal costs
and transmission loss factors as the BST;
(x)
the DUOS charges are equivalent to the distribution element of the
retail charges charged to MGS, LGS, specific business, street lighting
and temporary customers (see unbundled tariffs in Annex N). The
charge includes the cross-subsidy element of retail charges which we
have allocated to the monopoly distribution charge. This approach
ensures that all free customers (MGS, LGS and specific business)
customers will pay the cross-subsidy element, regardless of supplier.
The TUOS and DUOS charges for use of each voltage tier27 are set out in Schedule 12
of the Tariff Booklet. For use of multiple voltage tiers, Baht/kW charges should be
calculated by cumulating the presented charges for the voltage tiers in question,
taking into account that capacity charges for each kW of demand at the customer
meter have to be adjusted at higher voltages for the impact of losses28.
Comparison of new and existing tariffs
In Table 9.3, we compare the recommended tariffs for each customer category with
the 1999 total tariffs. Again, the 1999 total tariff includes an estimated 1999 average
retail Ft of 0.41Baht/kWh.
For residential customers we show the comparison for a representative very small
customer (with consumption of 35kWh/month), a representative small customer
(150kWh/month) and a representative large customer (450kWh/month29) The
comparison shows that:
(y)
overall average base tariffs will be 2.2 % lower than current
tariffs;
(z)
base tariffs for all representative residential customers30,
agricultural customers and government customers will be equal to
current tariffs in nominal terms;
In the interests of uniform national tariffs, and for simplicity we have averaged the costs of MEA’s
230kV system with those of MEA’s and PEA’s 115/69kV system and propose a single charge for use
of distribution system above MV. This approach is consistent with the design of retail tariffs.
27
28
So for example, demand charges for an LV customer served by a generator connected at MV are
140.11Baht/kW/month plus 57.78Baht/kW/month x (1.0590), where: 140.11Baht/kW/month is the
charge for LV; 57.78Baht/kW/month is the charge for the MV system; and 5.90% is the peak period
LV loss factor applied to correct metered demand to MV demand
29
The current average for customers with a consumption in excess of 150kWh/month
30
The aggregate amount paid by residential customers will rise slightly as the consumption/consumer
rises because of the progressive block structure.
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(aa)
base tariffs for SGS customers will be 3% lower than current
tariffs;
(bb)
base tariffs for larger customers will be 3% lower than current
tariffs
(cc)
base tariffs for interruptible customers will be about 4% lower
than the current interruptible tariff. We expect that proposed tariff
would result in an average unit charge of approximately 1.50Baht/kWh
at 69kV, compared with the most favourable current tariff equivalent
to 1.56Baht/kWh31.
In Table 9.4, we also show the equivalent average base tariff and percentage increases
for the recommended tariffs and the alternative sets of tariffs described in Annex R:
“unrebalanced tariffs”; and “alternative rebalanced tariffs”.
We note that:
(dd)
the recommended tariffs show no increases for any tariff category
(following policy guidance) and decreases for SGS and the larger
business tariffs;
(ee)
the unrebalanced tariffs show a 2.2% decrease for all tariff categories;
and
(ff)
the alternative rebalanced tariffs show increases for residential,
government and agricultural pumping customers and decreases for
SGS and larger business tariffs (reflecting underlying marginal costs
more accurately than the recommended tariffs).
Total recommended tariffs including Ft
We have also calculated the expected average total retail for each customer category
during the period FY2000 to FY2003 for our recommended tariffs. In addition to the
base tariff, the average total tariff includes in Ft:
(gg)
the 95% pass-through of expected fuel price increases over and above
1999 levels;
(hh)
the pass-through of effects due to a level of inflation of 5%.
31
We note that the interruptible tariff remains higher than those of some utilities in Europe and the
United States where interruptible tariffs tend to be in the range of 2.5Usc/kWh to 3.0USc/kWh. This
reflects the higher cost of electricity in Thailand where interruptible tariffs based on marginal energy
cost alone (i.e. excluding any capacity costs) would be some 1.00Baht/kWh or about 3.6USc/kWh.
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We show, in Table 9.5, that the average total tariff (including Ft) which results
from recommended tariffs is projected to be 2.23 Baht/kWh in FY2000, rising to
2.49 Baht/kWh in FY2001, 2.52 Baht/kWh in FY2002 and finally 2.68 Baht/kWh
in FY2003.
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10 Tariff adjustment mechanism
Introduction
Our proposals for a revised tariff adjustment mechanism (i.e. revised Ft) are explained
below under the following headings:
(a)
a summary of our assessment (in our Phase 1 report) of the present
tariff adjustment mechanism;
(b)
our assumptions concerning the unbundling of the businesses for the
purposes of this tariff study;
(c)
our assumptions about the wider regulatory context;
(d)
the scope of revised Ft, setting out what components should be
included;
(e)
the arrangements for each component of the revised Ft;
(f)
how the revised Ft should be applied; and
(g)
arrangements for adjustments to financial transfers.
In preparing our proposals, we have considered carefully the main objectives set out
in our terms of reference for the revised tariff adjustment mechanism, namely:
(h)
to maintain sufficient stability to the utilities’ financial position;
(i)
to encourage efficiency improvements and energy conservation;
(j)
to provide transparency and fairness to consumers; and
(k)
to ensure that the new arrangements are in line with the future structure
of the power industry in Thailand.
We have also taken into consideration the timescale within which it is proposed to
introduce the new tariff structure and adjustment mechanism, and the resources
available in NEPO to implement any changes. If the new arrangements are to be
introduced quickly, it will be essential that the new adjustment mechanism is
relatively straightforward to implement.
It is not possible to satisfy all these objectives, as there are inevitable conflicts
between them. Our proposals necessarily represent a balance, particularly between:
(l)
increasing the incentives for greater efficiency;
(m)
avoiding undue financial risks to the utilities; and
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(n)
keeping the arrangements simple in order to make them transparent
and easy to implement.
Summary of Phase 1 recommendations on Ft
We reviewed the present Ft arrangements in Phase 1 of our study. The formulae as at
May 1999 are set out in Annex O, together with our assessment of these
arrangements. We propose that there should be two major changes.
The first is that Ft should be unbundled. As we make clear elsewhere in this report,
there will be separate charges for generation, transmission, distribution and supply.
Similarly, there should be separate “Ft’s”, so that transmission and distribution
charges for third party access are separately identified, and so that retail customers
can see a breakdown of their bill into its constituent parts.
Our second major proposal is that the Ft formula should be amended to strengthen
the efficiency incentives, through replacing the detailed nature of the Ft
adjustments by broader incentive-based regulation. The approach we recommend
is that the utilities are set an allowed revenue for four years, and are then left to
manage their businesses within these allowed revenues in the intervening years. The
utilities are thereby given incentives to manage their businesses as efficiently as
possible, in the knowledge that they will be permitted to retain any increase in profits,
if they are able to reduce their costs more than is assumed in establishing their
allowed revenues. The benefits to consumers arise from the efficiency improvements
achieved over the intervening years, which can (at least in part) be passed on to
consumers from the start of the next tariff review. If there are no incentives, these
efficiency improvements may not take place at all.
Unbundling assumptions
Other consultants are addressing the restructuring of the industry over the next few
years, but we have had to make some specific assumptions about how to unbundle the
accounts of each utility for the purposes of developing proposals for allowed revenue
and Ft for each business. For the purposes of this tariff study only we have split
EGAT’s allowed revenue into three parts, and have split each of MEA and PEA’s
allowed revenue into two parts. The seven parts which result – referred to as
“businesses” in this section - are set out in Figure 10.1.
In our financial projections for EGAT(S), we have, for simplicity, not allocated any
supply costs as they are considered to be negligible. Consequently, our financial
accounts for EGAT(S) include only the pass-through of generation and transmission
costs (see Annex G).
Wider regulatory context
In order to make our proposals for the adjustment of the Ft formula, we have had to
make a number of assumptions about the wider regulation of the electricity utilities
over the next four years. As far as possible we have assumed continuity with past
policies. In particular, we have assumed that:
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(o)
revised “Base” charges will be established at the beginning of the
tariff period, which will remain unchanged during the four years
FY2000-2003. We have used the term “charges” to reflect the fact that
some businesses will make a charge to their customers (e.g. the
transmission and distribution businesses) rather than charging a tariff;
(p)
the level of the Base charges will be set by reference to a Base
Allowed Revenue for each business (broadly on the lines of section
7.1 of NEPO’s November 1996 document “Electricity Tariff
Restructure”);
(q)
there will be a Ft component which captures any changes in the
Base charges due to variations in selected uncontrollable factors;
(r)
the Ft component will be calculated for, and applied to, four month
periods; and
(s)
the Ft component will continue to be added as a flat rate to energy
charges (but not to demand charges).
Our specific proposals are illustrated in Figure 10.2, and can be summarised as
follows:
(t)
establish a level of Base Allowed Revenue (BAR) for each business
of the three utilities for the four Fiscal Years 2000-2003, divided into
12 four month periods. This BAR remains fixed for the four years, and
provides the initial reference point for all subsequent tariff adjustment
calculations;
(u)
establish an annual average Base Charge (in Baht/kWh) for each
business, which will yield the BAR if specific assumptions (relating,
for example, to demand and inflation) are met;
(v)
introduce a revised Tariff Adjustment Mechanism which
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(i)
calculates a Revised Allowed Revenue (RAR) for each
business in a specific four month period, based on out-turn
figures rather than the projections in respect of certain specific
uncontrollable assumptions underlying the Base Allowed
Revenue (BAR);
(ii)
calculates the Actual Revenue (AR) earned by the business
during the same four month period, based on the charge
allowed for the period and out-turn demand;
(iii)
calculates the Over-recovery or Under-recovery of allowed
revenue, which is the difference between the Revised
Allowed Revenue (RAR) and the Actual Revenue (AR); and
81
(iv)
converts the Over- or Under-recovery (which is due only to
the selected uncontrollable factors) into a Ft component (per
kWh), which is added to (or subtracted from) the energy
charges to customers in the next four month period after the
calculations have been made32. The Ft adjustment is
calculated to yield the amount of the Over- or Under-recovery
during the four month period on the basis of the demand
assumptions used to establish the BAR.
The most important changes from the present regime are that:
(w)
all efficiency factors (“X” factors) are included in the projections
of the Base Allowed Revenue (BAR), not in Ft. The underlying
philosophy is that the BAR of each business is set at a challenging but
realistic level, based on the best estimates that can be made at the time.
Subsequently, adjustments are only made (through Ft) to changes in
selected uncontrollable assumptions, which, if not allowed for, would
expose the utility to unreasonable financial risk; and
(x)
there will be separate BARs and Ft’s for each business.
As explained in Section 5, we are also proposing new arrangements for financial
transfers between the utilities. In particular, we propose that these arrangements
should be divorced from the BST charging structure, so that more appropriate price
signals are given to MEA and PEA relating to the cost of marginal purchases of bulk
power. Similarly, we propose that adjustments to the financial transfers between
utilities (due to adjustments to the BAR of EGAT, MEA and PEA) should be
separated from the four-monthly Ft adjustment mechanism. However, for completion,
we discuss at the end of this section our proposals for the adjustment of financial
transfers.
Scope of revised Ft
In accordance with the principles and general approach set out above, we propose that
Ft be adjusted to include fewer variables and less detailed adjustments. We have
therefore attempted to identify only the most important uncontrollable costs, and to
develop more general formulae rather than ones which precisely measure the impact
of changes in costs. In this way the management of the utilities will have greater
incentives to seek out and implement efficiency improvements.
The criteria we have used to select the most important uncontrollable variables are
that they are:
32
It was noted during discussion of our Draft Final Report that this arrangement results in an eight
month delay in receiving/paying an under-recovery/over-recovery of allowed revenue. However, it
would add enormously to the complexity of the tariff adjustment mechanism to introduce a shorter
delay. We do not consider that such an increase in complexity is justified, particularly, since Ft could
fall as well as rise from one period to another.
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(y)
strictly outside the control of the utilities; and
(z)
are likely to expose the utilities to undue financial risks over the next
few years.
On these criteria, we propose that Ft should comprise adjustments for:
(aa)
fuel and energy purchases;
(bb)
inflation;
(cc)
demand; and
(dd)
pass-through of adjustments from one business to another.
Items (a), (b), and (c) are included in some form in the present Ft formula, although
not necessarily in the same form as we propose below. Item (d) is required following
the unbundling of the businesses.
We also propose that NEPO should monitor the capital expenditure and service
standards of the utilities, to check whether there are any major instances, either of
under-investment compared with planned investment at the time when the utility’s
Base Allowed Revenue (BAR) was established, or of reduced service standards to
customers. NEPO may wish to require the utilities to submit reports on these issues at
the end of each financial year. If there are blatant instances of under-investing or
cutting service standards to save costs, NEPO may decide that there is justification for
a special adjustment to the BAR of the utility in the following financial year(s).
In order to maintain broad incentives, and to keep the revised Ft simple, we have
deliberately excluded from our proposals three specific items which are in the present
Ft formula, namely adjustments for:
(ee)
the full effects of changes in consumption patterns (e.g. switches from
peak to off-peak);
(ff)
the impact of exchange rate fluctuations on debt repayments; and
(gg)
the pass-through of Demand Side Management (DSM) costs.
We consider that, in normal circumstances, efficient management should be capable
of handling the risks and uncertainties arising from the first two items. We also
consider that the businesses must, in preparation for privatisation, start to face similar
commercial risks to those faced by the private sector. However, in extreme abnormal
circumstances (e.g. a sharp change in the exchange rate), a further component could
be added to Ft as has occurred in the past33.
33
This recommendation is based on work carried out in May/June 1999, since when the value of the
Baht has depreciated. If NEPO considers that the depreciation has been sufficiently sharp to merit the
inclusion in the revised tariff adjustment mechanism of a new component to cover exchange rate
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We are also reluctant to make special provision for DSM costs, particularly to ensure
that there are incentives for effective DSM investments. Our reasons for excluding
DSM are set out in more detail in Annex P.
We propose that DSM costs should be treated in a similar way as capital expenditure
and service standards described above. DSM activities are currently undertaken by
EGAT. DSM costs, which are a very small proportion of total costs, are included in
EGAT’s financial projections, and therefore will be allowed for in our estimates of
allowed revenue. We propose that EGAT’s BAR should be based on current best
estimates of the costs of DSM activities over the next four years, and that EGAT
should manage its actual costs in the same way as its other costs. We recognise,
however, that these arrangements might encourage EGAT to reduce its discretionary
DSM expenditure below desirable levels, and therefore propose that EGAT should be
required to report to NEPO at the end of every financial year its actual expenditure on
DSM compared with the estimates in its BAR.
Proposed arrangements for each component of revised Ft
We summarise in the following paragraphs our specific proposals for each Ft
component.
Fuel and energy purchases
Energy costs form the major part of the costs of EGAT(E), and a substantial part of
the cost basis for the retail tariffs. The adjustment for fuel prices is therefore
especially important. It is, however, only applicable to EGAT(E) (although the
supply businesses should be permitted to pass through any variations).
In our Inception Report we observed that the present Ft formula provides no
incentives for EGAT to minimise the costs of fuel. There are two main ways in which
incentives might be introduced:
(hh)
to establish Power Purchase Agreements (PPAs) for all EGAT’s power
stations with built-in incentives for efficiency. Variations in energy
payments under the PPAs can then be simply passed through in Ft (as
recommended in our 1996 report); or
(ii)
to allow only partial pass-through of fuel costs to charges or tariffs.
Full pass-through, as at present, provides no efficiency incentives.
volatility, a similar component could be added on the lines of that in the present F t formula relating to
foreign denominated debt. However, it should be noted that the inclusion of such a component could
distort the choice, by the businesses, or whether to borrow in local or foreign currency.
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In principle, option (a) remains our preferred approach, but we do not consider that it
is feasible to implement it within the required timescales. We understand that EGAT
has prepared some PPAs for its power stations, but that they are only internal
arrangements. Before they could form the basis of pass-through in a revised Ft
formula, they would need to be scrutinised to ensure that they provide appropriate
efficiency incentives. In addition, we had assumed in our 1996 report that power
procurement would be undertaken by a separate body on an arms-length basis, but
such arrangements have not yet been introduced and will presumably now be
reviewed in the context of the separate power pool study.
Option (b) - partial pass-through - is therefore the only practical way in which
efficiency incentives can be introduced into the tariff adjustment arrangements for
EGAT’s fuel costs.
There are two approaches which can be considered in designing a formula for the
partial pass-through of fuel costs:
(jj)
to apply a simple pass-through of a percentage (e.g. 95%) of any
variation in total fuel costs above or below the costs included in the
generation business’s allowed revenue; or
(kk)
to introduce a more complex formula, under which the various types of
fuel costs are treated separately with specific incentives for each type.
For example, there might be full pass-through of specific costs which
are considered to be uncontrollable (e.g. energy payments to IPPs),
while others are subject to tailor-made incentives in relation, for
example, to normative thermal efficiencies, world prices etc.
The “simple” approach provides broader incentives and therefore exposes the utility
to greater financial risk. The second approach reduces the financial risk, but at the
cost of greater complexity.
We propose that the “simple” approach should be followed. The “complex” approach
suffers from an important disadvantage: given the absence of a formal separation
between EGAT’s generation and despatch functions, there is a substantial risk that the
different treatment of the various fuel types would introduce perverse incentives for
non-optimal behaviour (e.g. encouraging EGAT to distort despatch away from least
cost generation towards generation from plants for which EGAT makes most profit).
In addition, the complex approach will be difficult to implement quickly, and will
require substantial NEPO resources to agree the detail with EGAT.
We therefore propose that a formula should be introduced which provides for a partial
pass-through of variations in fuel costs. The essence of our proposal is as follows: if
the actual costs incurred by EGAT are higher than assumed in setting its allowed
revenue (after adjusting for variations in demand), EGAT should only be permitted to
recover 95% of the additional costs through higher charges. In this situation, EGAT
will have to make savings elsewhere to absorb the remaining 5% of additional costs.
Conversely, if EGAT’s costs are lower than assumed in setting its allowed revenue,
95% of the cost savings will be passed on to consumers in lower charges, and EGAT
will be able to retain the remaining 5%.
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The appropriate percentage pass-through will depend on the ability to establish
reasonably realistic projections of fuel and energy payment costs when setting
EGAT(E)’s allowed revenue. There are a number of uncertainties including future
fuel prices, variations in the availability of hydro power due to the weather, and
uncertainties over the precise phasing and costs of new plant scheduled to be
commissioned over the next four years. Accordingly, we propose a relatively large
percentage pass-through (i.e. 95% of the increase/decrease in costs).
We stress that the allowed revenue for EGAT has been set based on EGAT’s own
projections of fuel and electricity purchase costs. If these are central estimates,
EGAT is equally likely to gain or lose from fuel and electricity cost movements. As
shown in Section 5, EGAT would meet its financial criteria if its fuel and electricity
cost projections are realised and the tariff adjustment mechanism allows only 95%
pass through of the difference between projected fuel prices and 1999 fuel prices (as,
in effect, the base tariff allows for 5% of the difference between projected fuel price
levels and 1999 fuel price levels).
We have considered whether this pass-through formula should apply only to the fuel
costs of EGAT’s power stations or should also include payments made to IPPs and
SPPs (and Lao Republic and Malaysia). We propose that it should cover all sources
of power so that EGAT is given incentives to optimise despatch as well as to
minimise the fuel costs of its own stations. We also propose that it should cover both
energy and availability payments to IPPs and SPPs. If availability payments are
excluded, incentives might be introduced which distort either the negotiation (or
renegotiation) of the split between energy and availability payments; or the optimum
scheduling and despatch of EGAT plant versus IPP/SPP plant.
In calculating the difference between actual costs and allowed revenue, we propose
that EGAT(E)’s Base Allowed Revenue should also be adjusted for changes in
demand as described below.
Inflation
We have allowed the BAR to cover for domestic inflation of 2.83% per year over the
period. Thus, we propose that there should be an adjustment in the Ft such that the
allowed revenue is increased or reduced to the extent that inflation is higher or lower
than 2.83% per year. The way in which the adjustment is made is discussed below
under “Application of revised tariff adjustment mechanism”. We stress that in setting
the BAR of each business for FY2000-2003, we have ensured that the utilities can
meet their financial requirements through BAR and Ft revenues, with EGAT’s
projections of fuel prices and with inflation at 5% per year.
Demand
The BARs in this report are founded on the assumption that demand over the period
FY2000-2003 will be as projected by the TLFS in its MER case. If demand is higher
or lower than forecast, we propose that the allowed revenues of the businesses should
be increased or reduced. Our proposals for adjusting the Base Allowed Revenues for
changes in demand are discussed below under “Application of revised tariff
adjustment mechanism”.
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We also propose that the demand for the network businesses should be measured as
follows:
(ll)
net generation sent out for EGAT(E);
(mm) units transmitted for EGAT(T) - calculated using normative losses to
encourage the optimisation of transmission losses; and
(nn)
units distributed, for the MEA and PEA distribution and supply
businesses - calculated using normative losses to encourage the
optimisation of distribution losses.
Pass-through of adjustments
For the purposes of this tariff study, we have assumed that the supply businesses of
EGAT, MEA and PEA pay the charges for generation, transmission and distribution
to EGAT(E), EGAT(T) and the distribution businesses respectively. Accordingly,
any Ft adjustment added to, or subtracted from, the charges for these services will feed
directly through to the financial position of the supply businesses. We propose that
the impact of these Ft adjustments should be passed through in the allowed revenues
for the supply businesses.
Application of revised tariff adjustment mechanism
The process for the adjustment of tariffs is explained in simplified terms below. The
detail is given in Annex Q. We start by illustrating the process by reference to those
businesses where there will only be adjustments for variations in inflation and demand
(i.e. the transmission and distribution businesses). We then explain the process for the
adjustment for fuel and energy purchase costs, which applies only to EGAT(E). In
contrast, the pass-through adjustments – which apply only to the supply businesses of
the three utilities – are relatively straightforward.
Our proposals for the adjustments for inflation and demand are as follows:
(oo)
Step 1: Calculate the Base Allowed Revenue (BAR) for each business
(see Section 5). This BAR should cover the twelve four-monthly
periods for the Fiscal Years 2000-2003. In addition, calculate the
average Base Charge, which would yield the BAR over the period (on
a discounted basis) if there is no change in the assumptions underlying
the BAR (see Sections 8 and 9).
(pp)
Step 2: Establish the split of this BAR into the proportions which are
intended to provide allowed revenue to cover (i) the fixed costs and (ii)
the variable costs of the business. The “fixed” allowed revenue
remains fixed for the four years of the tariff period, except for changes
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in the assumptions relating to inflation. The “variable” allowed
revenue will vary with changes in both inflation and demand34.
(qq)
Step 3: Recalculate the BAR for the first four month period during the
course of the second four month period, using the actual rate of
inflation and the actual level of demand, to give a Revised Allowed
Revenue (RAR). The “fixed” portion of the BAR is adjusted only for
actual inflation compared with forecast inflation, while the “variable”
portion of the BAR is adjusted for both actual inflation and actual
demand. The RAR is effectively the revenue that would have been
allowed for the period, if it had been possible to forecast inflation and
demand accurately when the BAR was established35.
(rr)
Step 4: Estimate the Actual Revenue (AR) which the business earned
during the period, which is calculated from the Base Charge (plus any
allowable Ft-type adjustment) for the period multiplied by the out-turn
demand. This amount will not necessarily be the same as the cash
revenue received because of working capital movements and changes
in consumption patterns.
(ss)
Step 5: Estimate the difference between the AR and the RAR
calculated in Steps 3 and 4. This difference will give the overrecovery or under-recovery of allowed revenue during the period.
(tt)
Step 6: Convert the over-recovery or under-recovery of revenue
from Step 5 into an adjustment per kWh. This adjustment is then
added to, or subtracted from, the (average) Base Charge in the next
four month period after the calculations have been made (i.e.
adjustments for the period October 1999 - January 2000 would be
made in June - September 2000).
(uu)
Step 7: Convert the average adjustment per kWh derived from Step 6
into an equivalent adjustment in stang/kWh to the specific Base energy
charges charged by each business to customers. This is the Ft
adjustment.
(vv)
Step 8: Repeat Steps 3 to 7 for each successive four month period.
Our proposals for the adjustments for fuel and energy purchase costs are as
follows:
34
In the case of the supply businesses, there will also be allowed revenue to cover charges paid for
generation, transmission and distribution, for which increases or decreases resulting from Ft
adjustments can be passed through. In the case of EGAT(E), there will also be allowed revenue to
cover fuel and energy purchases costs, for which the adjustment process is described later.
35
In the case of the supply businesses, the BAR will also be recalculated for adjustments in passthrough costs. In the case of EGAT(E), the BAR will also be recalculated for adjustments for
variations in fuel and energy purchase costs, as described later.
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(ww) Step 1: Establish, for each four month period for FY2000-2003, the
proportion of the BAR for EGAT(E) intended to cover fuel and energy
purchase costs (i.e. fuel for EGAT’s power stations and energy and
availability payments to IPPs, SPPs, Lao Republic and Malaysia).
This is the Base Energy Revenue.
(xx)
Step 2: After the end of the first four month period (i.e. October 1999 January 2000), and when the information is available, adjust the Base
Energy Revenue by multiplying by the actual net generation during the
period and dividing by the projected net generation during the period,
to give the Revised Energy Revenue. Unfortunately net generation
cannot yet be measured directly by EGAT, and will therefore need to
be derived by adding estimated transmission losses to bulk supply
point demand36.
(yy)
Step 3: Establish the Actual Energy Costs which EGAT(E) incurred
during the period October 1999 - January 2000.
(zz)
Step 4: Estimate the difference between the Actual Energy Costs from
Step 3 and the Revised Energy Revenue from Step 2, and calculate
[95]% of the difference.
(aaa)
Step 5: Add the result from Step 4 to the Revised Energy Revenue
calculated in Step 2. This gives the proportion of EGAT(E)’s Revised
Allowed Revenue intended to cover EGAT(E)’s fuel and energy
purchase costs.
(bbb) Step 6: The Revised Allowed Revenue from Step 5 is included in
EGAT(E)’s total RAR calculated at Step 3 in the previous paragraph,
and the process continues as in the succeeding steps in that paragraph.
Financial transfers
We have recommended earlier that the financial transfers between the utilities should
not be made through differential tariffs, but as lump sum payments from MEA to
PEA. We propose that “Base” annual lump sums for the period FY2000 to FY2003
should be determined at the same time as the BARs and Base Charges are established
as set out in Section 5.
We also propose that adjustments be made to these lump sums on an annual basis.
More specifically we propose that:
36
This solution is not ideal as it exposes EGAT(E) to the risk that the transmission business will not
control transmission losses efficiently. However, it seems better that the alternative which would be to
measure net generation from gross generation less estimated auxiliary consumption and losses in
EGAT’s power stations, as the alternative provides no incentive for EGAT(E) to control such auxiliary
consumption and losses and poses greater estimation problems. In the medium term, the solution is to
measure net generation directly. In the meantime, it may be possible to undertake spot checks of actual
net generation compared with the estimated figure.
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(ccc)
at the end of each fiscal year, an amended allowed revenue is
calculated for EGAT, MEA and PEA, which takes account of:
(i)
the Revised Allowed Revenues of each business in the three
four-monthly periods in the year; and
(ii)
the over-recovery or under- recovery added to, or subtracted
from, the allowed revenues over the year;
(ddd) the appropriate lump sum payments for the previous year are
recalculated, replacing the Base Allowed Revenues for the year by the
amended allowed revenues calculated in (a) above;
(eee)
the difference is derived between the actual lump sum payments made
by each utility and the lump sum payments in (b) above; and
(fff)
the (annual) differences for each utility in (c) above are converted to
monthly amounts, and are recovered over the next 12 months by
adjusting the (originally planned) monthly payments over these 12
months. We have assumed that steps (a), (b) and (c) above will not be
completed until the third month of the new fiscal year (i.e. by the end
of December), so that the adjustments will be made to the monthly
payments over the 12 months January to December.
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