Governance and Administration of System and Market Operations

_________________________________
System and Market Operations
An overview of international experience
in governance and administration
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slEconomics is a boutique economics consulting firm providing specialised
advice to governments, regulators and corporate clients in the area of utilities
and infrastructure. We are based in Sydney Australia and have an international
network of associates to bring global experience to local initiatives.
Contact details
Dr Stephen Labson
slabson@transafricanenergy.com

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TABLE OF CONTENTS
1 INTRODUCTION AND OVERVIEW 1
1.1 Overview of our study 2
2 TRANSMISSION & SYSTEM OPERATOR 5
2.1 France – RTE 5
3 INDEPENDENT SYSTEM OPERATOR 11
3.1 California ISO 11
3.2 Australia - AEMO 12
4 CENTRAL BUYER / IPP ADMINISTRATOR 17
4.1 Mexico single buyer model 17
4.2 Thailand single buyer model 21
4.3 California’s power purchase administrator 22
5 ENERGY PLANNING 26
5.1 Thailand energy policy and Power Development Plan 26
5.2 Mexico Works & Investment Program of the Electric Sector 32

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1 Introduction and overview
When considering governance and administration of the electricity system and
market operator one finds a number of structural forms in which the basic
activity is carried out – and often bundled with related functions of transmission
operation, central buyer/IPP administrator and energy planning.
The four stylised models shown in the picture below are commonly referred to
when looking at electricity industry structure. However, it is recognised that this
is more of a spectrum rather than discrete and mutually exclusive set of
models. Nevertheless, one needs to put some structure to the matter at hand,
and we hope this provides a good place for departure.
To provide some sense of where one might head in examining these issues
(and for example only) a Transmission & System Operator might also carry out
Central Buyer functions, and have an important role in Energy Planning.
Alternatively, there are examples seen globally where there is full separation
between the Transmission Operator; System Operator; Central Buyer; and
Energy Planning. Needless to say, there are a number of permutations in-
between these polar cases.
Moreover, what we have so far simply called a “Central Buyer” is also more
accurately assessed in terms of a spectrum of models, perhaps ranging from
a literal single buyer monopoly; a central buyer in parallel to a competitive
market; a market operator or aggregator, through to administration of power
procurement and/or legacy contracts as an agent to the power purchaser.
What we have attempted to do in this briefing is to highlight various aspects of
governance and regulation pertaining to these stylised models by way of
providing selected international examples and case studies. The short case
studies we provide here are simply meant to provide some indication of key
issues that would need to be addressed, and provide a starting point for the
detailed analysis, and administrative and regulatory design that would need to
be carried out once one has determined the preferred model based on
comparative analysis of the options at hand.
We have tended to use examples from the same country across a couple of
functions (i.e. Thailand Single Buyer and Energy Planning; and California’s
Transmission
& System
Operator
Independent
System
Operator
Central Buyer
/ IPP
Administrator
Energy
Planner

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ISO and Power Purchase Administrator as they can shed some light on
linkages between the various functions and models providing a more holistic
view (to the degree we have had time to bring out these points).
Finally, we wish to note that we have taken large excerpts from external
sources and have attempted to attribute those references. However, given the
severe constraints on time to complete this study we have perhaps not been
as rigorous in this regard as we would normally be. We will be happy to provide
more detailed citations of reference documents and sources of information as
time allows.
1.1 Overview of our study
While we do not wish to imply that there is a single ‘finding’, or set of
recommendations stemming from our selected review of international
experience, we hope it is help to provide in a consolidated format some of our
broad thinking as related to governance and regulation of the activities
considered here.
Transmission & System Operator
Countries such as France and the UK have created separate Transmission &
System Operators (TSOs) from what was previously a state owned vertically
integrated monopoly structure. In the case of the stand-alone TSO, high
voltage transmission networks and systems operations are combined in one
entity with its own governance and regulatory structures. In this regard, primary
governance structures for a TSO are usually cast within fairly standard
corporations law pertaining to the country at hand (whether state owned or
private) in line with ownership of significant transmission assets.
Given the significant role a TSO plays within the electricity supply industry
(ESI) detailed sets of rules and regulations apply. Where some level of cross
ownership is allowed between the TSO and other segments of the industry (i.e.
as in France where the parent company is also a generator) rules and
regulations pertaining to non-discriminatory access and dispatch become of
particular importance to mitigate any incentives the TSO might have to favour
related companies over competitors in that segment of the market.
Independent System Operator
For the purpose of this study we look at what is commonly referred to as an
Independent System Operator (ISO). In practice however, ISO can vary
significantly in roles and responsibilities and might carry out a range of
functions such as:
 Market operator / balancing market
 Ancillary services and reserve power purchases
 Energy planning (e.g. provision of information in regard to needed
investment).

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Moreover, there are unique aspects to consider in design of regulatory
approaches for revenue allowances for an unbundled ISO are that:
 A stand alone ISO does not typically have a large fixed asset base (i.e.
RAB). Following from the point above, the balance sheet of an ISO
might not be substantial, although its financial risk might be
considerable. A reserve account and other such features might be
needed to address prudential requirements. This would become
considerably more important if Single Buyer responsibilities were rolled
into the ISO.
 If the cost of ancillary services is attached to the ISO (which is often the
case) a large proportion of total costs will be driven by external and
potentially volatile costs necessitating a more direct recovery of actual
costs of operations than might be found in a TSO.
 The specific activities carried out by ISO will vary across jurisdictions.
Many have Market Operations responsibilities, and some might share
some system control responsibilities with regional entities.
The ISO would often have a broader base of governance, perhaps with cross
industry representation, and might be set up as a ‘not-for-profit’ organisation,
or as an entity of government.
From a broader perspective many of the scope of rules pertaining to the TSO
would be applicable to the ISO (excepting for the way in which the revenue
allowance and funding is managed as discussed above).
Central Buyer / IPP Administrator
What discussed in the beginning of this section, what we refer to generally as
a “Central Buyer / IPP Administrator” in fact covers a spectrum of models
perhaps ranging from a:
Single Buyer – where literally applied provides a statutory monopoly on the
purchase and sale of power. This is often bundled with the role of generator,
and TSO, perhaps with sales to separate distribution business.
Central Buyer – that might have significant power procurement
responsibilities, but not a complete monopoly in regard to power purchase and
on-sale.
Market operator or aggregator – e.g. providing balancing services to a
competitive wholesale market, or aggregating bulk power supplies and costs
in sale to suppliers.
IPP traders / administrators - that are responsible for:
 trading and administration of pre-existing (legacy) PPAs as an agent to
the counterparty to the PPA, or in some cases with counterparty
liability; and/or
 responsibility for procurement of new power purchases, also with or
without direct financial ownership of PPAs.

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From a governance and regulatory standpoint, perhaps the key differentiator
of the stand-alone Buyer is that it may have significant financial exposures as
counterparty to power purchase agreements (PPAs) but a limited balance
sheet. The Buyer will usually have significant capital at risk and will need to
satisfy prudential requirements in the purchase of power. In such cases
substantive reserve accounts may need to be provided for to fill this role.
Moreover, the Buyer activity is not generally conducive to simple fixed revenue
or price cap type regulatory models often applied to other segments of the ESI.
Theoretically, one might try to set some benchmark purchase price and
incentivise the Buyer to outperform against that benchmark, but accurately
defining such benchmarks will in most cases be problematic. It will be
impossible to determine if under or over performance against benchmarks is
due to management’s actions; driven by purely external factors; or simply due
to error in setting the initial benchmark rate placing it in a financially
unsustainable position. We provide further discussion of this matter in the later
part of this section.
Energy planning
The energy planning role and associated governance structures are tied
directly to the nature of the market in a given jurisdiction.
 Decentralised competitive electricity markets typically tend towards less
prescriptive planning structures, whereas centralised markets tend
towards more prescriptive regimes.
 Governance of planning agencies in markets primarily served by private
sector suppliers is often broad based - inclusive of industry players,
customers and government; whereas planning in state-owned electricity
supply industries is more often overseen by governmental bodies.
 The scope for competition also drives approaches to planning and
governance across the supply chain.
o For example, in countries where there are competitive wholesale
electricity markets the role of generation planning is largely
addressed by way of information disclosure, and where there is
centralised generation investment, it tends to be limited to
procurement of short to medium term reserve capacity.
o Alternatively, transmission and distribution investment and
planning is not often carried out in a competitive environment
(although there are counter examples) and more centralised and
prescriptive investment and planning regimes apply to these
segments of the industry.

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2 Transmission & System Operator
Countries such as France and the UK have created separate Transmission &
System Operators (TSOs) from what was previously a state owned vertically
integrated monopoly structure. In the case of the TSO, high voltage
transmission networks and systems operations are combined in one entity with
its own governance and regulatory structures. In this regard, primary
governance structures for a TSO are usually cast within fairly standard
corporations models (whether state owned or private) in line with ownership of
significant transmission assets. As will be explained in a section that follows,
this contrasts to the Independent Operator (ISO) which would often have a
broader base of governance, perhaps with cross industry representation, and
might be set up as a ‘not-for-profit’ organisation.
However, given the significant role a TSO plays within the electricity supply
industry (ESI) detailed sets of rules and regulations apply. Where cross
ownership is allowed between the TSO and other segments of the industry
rules and regulations pertaining to non-discriminatory access and dispatch
become of particular importance to mitigate any incentives the TSO might have
to favour related companies over competitors in that segment of the market.
We provide below an overview of the TSO established in France to highlight
some of the key issues of governance and regulation. (We note that greater
detail on rules pertaining to the system operator function of the TSO will be
provided in our section on ISOs).
2.1 France – RTE1
The French power sector has traditionally been dominated by Electricité de
France (EDF) one of the world’s the world’s largest utilities with revenues of
some €64 billion, operating a diverse portfolio of 120,000+ megawatts of
generation capacity in Europe, Latin America, Asia, the Middle-East and Africa.
EDF held a monopoly in the distribution of electricity in France until 1999, when
the first European Commission directive to harmonize regulation of electricity
markets was implemented. Generation in France is still dominated by EDF,
which holds around 85% of the generation capacity, but a wholesale market
and open access provisions allow for market participation by competitors. The
four main alternative generators operate a total generation capacity of 6%, with
the remaining 9% belonging to a large number of small-sized generators and
industrial companies.
Around 60 operators take part in trading activities, which mainly consist of
carrying out arbitrage transactions in the various wholesale market segments.
These operators are mainly subsidiaries of European energy groups, but there
are also banks present in the field.
Until November 19, 2004, EDF was a government corporation, but it is now a
limited-liability corporation under private law (société anonyme). The French
government partially floated shares of the company on the Paris Stock
Exchange in November 2005, although it retains roughly 80% ownership and
is required that the government retains at least 70% of shares.
1
Source: Rte web site

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2.1.1 Establishment of the TSO – legal separation of RTE from EDF
High voltage transmission and system operation is carried out by RTE, a
subsidiary of EDF. The Law of 9 August 2004 states that RTE as the network
and system operator:
 retains responsibility for maintaining, operating and developing the
electricity transmission system,
 becomes the owner of its industrial assets, and
 is a company whose capital continues to be held entirely EDF, the State
or other firms or institutions belonging to the public sector.
Suppliers of electricity to end consumers are composed of incumbent suppliers
(EDF and 166 local distribution companies) and 26 alternative suppliers, 9 of
which propose commercial offers to small-sized sites, 10 to medium-sized
sites, and 25 to large-sized consumption sites.
RTE Board structure
RTE is a limited company with an Executive Board and a Supervisory Board.
In accordance with its statutes, the Executive Board is the only body competent
to carry out operations relating directly to the operation, maintenance and
development of the public electricity transmission grid, under the missions
entrusted to the company.
Executive Board
The Executive Board is made up of four members, each appointed for a period
of five years.
The Supervisory Board
It is made up of 12 members, each appointed for a five-year mandate: Six
representatives of the shareholder EDF, two representing the State, and four
representing employees.
2.1.2 Rules and regulation facilitating non-discriminatory access
Given that RTE is a subsidiary of EDF, a robust set of rules and regulations
are essential component of non-discriminatory access and use of the network
within the context of the European Union. The European directives of 1996,
1998 and 2003, transposed into French law, organised the opening of the
electricity and gas markets to competition by providing for:
 the free choice of the electricity and gas supplier for customers;
 freedom of establishment for producers and suppliers;
 a right to non-discriminatory, transparent access available at a fair price,

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for all users of distribution and transmission grids and networks, LNG
terminals and underground natural gas storage facilities.
To ensure the fulfillment of these three major principles, the directives have
made the independence of the transmission and distribution system operators
mandatory (for distributors serving more than 100,000 customers) with regard
to the production and trading activities of integrated companies, but without
demanding grid or network ownership unbundling. These markets are
organised today between activities open to competition (production, trading
and supply of all consumers) and monopoly activities which are nevertheless
regulated (transmission and distribution, LNG terminals, natural gas storage
facilities).
In reconciling the needs of the French market with the construction of the
European internal market France established Commission de régulation de
l'énergie (CRE). The role of the CRE is to:2
“Guarantee the right of access to public electricity grids and natural
gas networks and facilities. To perform this mission, CRE:
• proposes tariffs to the government for the use of the electricity and gas
transmission and distribution systems, and of the LNG terminals;
• settles disputes pertaining to the access and use of the public electricity
grids and natural gas facilities, and imposes penalties on operators or users
of electricity or gas infrastructures for failing to meet contractual obligations.’
Ensure the satisfactory operation and development of electricity grids
and gas networks, as well as the independence of their operators. To
perform this mission, CRE:
• endorses the investment programmes of the transmission system
operators, both for electricity and for natural gas;
• approves the principles of legal and account unbundling between
transmission, supply and distribution activities, and monitors compliance
with codes of good conduct and the independence of the gas and electricity
system operators;
• supervises the organisation of the balancing mechanism on the electricity
grids and the satisfactory balancing of the natural gas transport networks;
• in close cooperation with the regulators of all the Member States, approves
the methods for calculating and allocating interconnection capacity.
Contribute to the construction of the European internal market for
electricity and gas, by the harmonisation of the rules of access to the
grids and networks and the optimization of interconnections between
domestic markets. To perform this mission as a member of ERGEG,
CRE:
• participates in European deliberations pertaining to regional “electricity”
and “gas” initiatives, designed to achieve progressive breakthroughs in
terms of the management of exchanges at cross-border interconnections
and the emergence of European regional markets;
2
Source: CRE web site

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• monitors the coherence and consistency of regional initiatives, a
prerequisite for market integration;
• participates in drawing up the operating rules of the European internal
market.
Overseeing transactions conducted on wholesale markets, organised
or not, for electricity and natural gas, as well as cross-border
exchange. To perform this mission,
 CRE exercises oversight combined with powers of enquiry and
sanction, alongside the Competition Authority.
Contributing to the implementation of support mechanisms for
electricity generation and the supply of electricity and gas. To perform
this mission, CRE:
• implements the calls for bids issued by the French Minister for Energy in
connection with the multiannual programming of energy generation
investments;
• issues consultative opinions on retail tariffs for electricity generated by
cogeneration or from renewable energies;
• manages the compensation mechanism for suppliers assuming public
service duties (assessment of the costs to the suppliers and associated
contributions, collection and compensation of suppliers bearing costs in
connection with the French Deposit and Consignment Office (Caisse des
Dépôts). These charges result:
• for electricity, from the support mechanisms for generation by
cogeneration and from renewable energies (calls for tender, purchase
obligation), from tariff equalisation in favour of customers of non -
interconnected areas and from mechanisms set up for persons in a
vulnerable situation;
• manages the mechanism for compensation of suppliers bearing costs
connected with the French transitional regulated tariff for balancing
markets.
2.1.3 Transfer capacities – outages and system constraints3
One of the more significant matters related to non-discriminatory access is in
regard to how transmission capacity is allocated to users when there are
system constraints and financial transfers (payments or charges) that would
be made in such cases.
In view of the geographical situation within the European network, RTE is
called upon to a considerable extent by the players of the market to set up
exports or imports between France and the interconnected neighbouring
countries. Demand has increased and this has resulted in the growth of cross-
border exchanges while, at the same time, the environmental regulations make
it more difficult to build new transmission facilities.
This situation tends to create congestion phenomena, sometimes leading RTE
3
This section is taken from material on the RTE web site

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to limit electricity transfers on some interconnections, whereas the play of the
market may result in exchange volumes that are higher than the transmission
capacity available. To cope with these difficult situations, RTE can either limit
the access to the network or adapt the generation programmes so as to provide
additional capacity whenever possible. In this case, the customers who have
access to the network may bear an extra congestion price which serve to
compensate for the costs of these adaptation of schedules.
Considering the fact that the physical characteristics of the network limit the
interconnection capacity, RTE has set up conditions for the allocation of this
capacity to meet the requests in a transparent and non-discriminatory way.
These conditions have been set up, either in co-ordination with the
neighbouring TSO's (England, Belgium and Italy), or unilaterally when the
context has not yet allowed or required a bilateral agreement with the
neighbouring TSO's (Germany, Switzerland and Spain).
To guarantee a good degree of transparency and ensure that all parties fully
understand the process by which flows are reconstituted, RTE publishes the
following data regarding the calculation of imbalance settlement and
reconciliation:
National reference load curve.
This curve corresponds to net extraction by the Public Distribution Network
on the Public Transmission Network, calculated on the basis of metering
data measured at RTE HV/MV delivery point substations.
National Profiling Imbalance.
This curve corresponds to the difference between net extraction of Public
Distribution Network (PDN) on the Public Transmission Network metered
by RTE and aggregated Balance Responsible flows on PDN calculated by
Grid Operators by the way of remote metering, profiling and estimating
losses.
National alignment coefficient.
This curve corresponds half-hour by half-hour points to the coefficient that
correct the consumption estimated by the Grid Operators on Public
Distribution Network for all Balance Responsible flows in order to adjust her
to the real level.
National Residual load curve, financial amount of residue, annual energy
consumed nationally as estimated by profiling.
During temporal reconciliation, there exists an imbalance during the half-
hourly period, between the national reference load curve and the sum of the
load curves allocated to the balance responsible entities within the Public
Distribution System. This imbalance corresponds to the lack of precision
with regard to the profiles. This imbalance, calculated over a period of a
year, constitutes the load curve for the national residue. Its annual energy
is nil by construction.
Imbalance settlement price

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For a given half hour, if the balancing mechanism trend is the reverse of the
results of the Balance Responsible, the Settlement Price of the Negative
Imbalances (resp. Positive) is the Average Weighted Price of the Balancing
carried out Upwards (resp. Downwards) over this same period, adjusted by
a multiplier the value of which is : 1 + K. Otherwise, the Powernext price is
the one that is applied. As from July 1st 2006, the coefficient K is equal to
0.05.
The Physical Consumption of the Balance Responsible Entity is subject to
a monthly payment by the Balance Responsible Entity to RTE.
From February 1st, 2009, the price charged is 0,11 €/MWh.
2.1.4 The Balancing Mechanism
The power network is constantly affected by a range of unforeseen factors that
can disrupt the balance between the supply and demand for electricity. These
are mainly compensated for by automatic control systems, which are installed
directly at generating facilities. However, some such unforeseen factors can
be major (e.g. the sudden shutting down of a generating facility). To re-
establish the balance between supply and demand for electricity, RTE needs
a real-time backup energy reserve. It obtains this reserve by calling upon
generators and consumers connected to the network to modify their operating
schedule at short notice. This is the role of the "balancing mechanism"
introduced by RTE in 2003.
Via a system of upward and downward offers, market players with flexibility
reserves give details of the technical and financial conditions in which RTE can
call upon them to adjust their consumption. RTE selects these offers according
to their price and the technical restrictions indicated by the players
concerned.This mechanism also enables RTE to ease "congestion" on the
network, when the transmission of electricity is held up by bottlenecks. This
can occur, for example, when a power line trips out, if the capacity of adjacent
lines is insufficient to carry the electricity.
The creation of the balancing mechanism in France was a major step on the
road to building the European internal electricity market. It has since been
extended to cover generators outside France (Switzerland, Spain and the UK).
It works according to market rules, and helps to guarantee the security of the
power system. As of 31st December 2004, 18 balancing players were
declared and the volume called by RTE reached 12 TWh (7.8 TWh downward
and 4.2 TWh upward). To give players greater visibility and to help them
understand how the system works, every day RTE provides them with a range
of information intended to enable them to make offers (operating margins,
balancing prices, etc.). In addition, RTE publishes historical records of all the
data validated since the mechanism was launched.

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3 Independent System Operator
For the purpose of this study we look at what is commonly referred to as ISOs.
In practice however, system operators might carry out a range of functions
such as:
 Market operator / balancing market
 Ancillary services and reserve power purchases
 Energy planning (e.g. provision of information in regard to needed
investment).
Moreover, there are unique aspects to consider in design of regulatory
approaches for revenue allowances for an unbundled ISO are that:
 A stand alone ISO does not typically have a large fixed asset base (i.e.
RAB). Following from the point above, the balance sheet of an ISO
might not be substantial, although its financial risk might be
considerable. A reserve account and other such features might be
needed to address prudential requirements. This would become
considerably more important if Single Buyer responsibilities were rolled
into the ISO.
 If the cost of ancillary services is attached to the ISO (which is often the
case) a large proportion of total costs will be driven by external and
potentially volatile costs necessitating a more direct recovery of actual
costs of operations than might be found in a TSO.
 The specific activities carried out by ISO will vary across jurisdictions.
Many have Market Operations responsibilities, and some might share
some system control responsibilities with regional entities.
3.1 California ISO4
The California ISO (CAISO) is a not-for-profit public benefit corporation brought
on line in 1998 when the state restructured its electricity industry, and is
responsible for the operation of the long-distance, high-voltage power lines that
deliver electricity throughout most of California (the California grid) and to
neighboring control areas and states, as well as with Canada and Mexico. The
Board of Governors is composed of five members appointed by the California
Governor and confirmed by the California State Senate.
CASIO operates day-ahead and hour-ahead markets for transmission
congestion and ancillary services, operates a real-time market for balancing
energy, and administers reliability-must-run (RMR) contracts. RMR contracts
allow the CASIO access to power at contractually agreed-upon prices from
generation units which, due to their location and other factors, must be
operated at certain times to ensure the local transmission reliability. CAISO
also performs a settlement and clearing function by collecting payments from
users of these services and making pass-through payments to providers of
such services. Any market defaults are proportionately allocated to market
4
Sourced from CAISO annual report 2008

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participants based on net amounts due them for the month of default.
CAISO’s principal objective is to ensure the reliability of the California grid,
while fostering a competitive wholesale marketplace for electrical generation
and related services in California. CAISO operates pursuant to tariffs filed with
the Federal Energy Regulatory Commission (FERC).
3.1.1 Revenue requirement
CAISO charges a Grid Management Charge (GMC) to market participants to
recover the company’s operating costs, capital expenditures and debt service
costs, and to provide for an operating reserve. GMC revenues are recognized
when the related energy transactions take place. All of the company’s
receivables are due from entities in the energy industry, including utilities,
generation owners, financial institutions and other electricity market
participants. For the years ended December 31, 2008 and 2007, approximately
54 percent and 53 percent, respectively, of GMC revenues were from two
market participants. In the event of a payment default by a market participant,
GMC revenues have a priority claim against any market-related receipts, which
means that even if an entity defaults on a GMC invoice, the CAISO receives
the full GMC so long as sufficient funds were received on market invoices.
The 2008 and 2007 unbundled GMC rates were comprised of the following six
service categories: core reliability services; energy transmission services;
forward scheduling; congestion management; market usage; and settlements,
metering and client relations.
An operating reserve is calculated separately for each GMC service category
and accumulates until the reserve becomes fully funded (at 15 percent of
budgeted annual operating costs for each rate service category). In
accordance with the tariff, any surplus operating reserve balance is applied as
a reduction in the revenue requirement for the following year. These operating
reserve amounts are included in the net assets of the company. The tariff
requires GMC rates to be adjusted not more than once per quarter in the event
that projected annual billing determinant volumes differ by more than five
percent from those projections used to set rates.
The following table summarizes the pro forma bundled GMC rate based on the
budgeted revenue requirement divided by the estimated control area
transmission volume.
2008 2007 2006
Pro forma GMC rate per MWh . . . . . . . . . $ 0.755 $ 0.760 $ 0.724
Estimated volume in millions of MWh . . . 253.70 250.00 249.20
3.2 Australia - AEMO5
The Australian Energy Market Operator (AEMO) was established to manage
5
AEMO, An Introduction to Australia’s National Electricity Market, 2009.

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Australia’s National Electricity Market (NEM) and gas markets from 1 July 2009
by consolidation of various pre-existing entities. AEMO’s core functions cover
the following areas:
• Electricity Market - Power System and Market Operator
• Gas Markets Operator
• National Transmission Planner
• Transmission Services
• Energy Market Development
Created by the Council of Australian Governments (COAG) and developed
under the guidance of the Ministerial Council on Energy (MCE). AEMO
operates on a cost recovery basis as a corporate entity limited by guarantee
under the Corporations Law. Its membership structure is split between
government and industry, respectively 60 and 40 percent, with this
arrangement to be reviewed after three years of operation. Government
members of AEMO include the Queensland, New South Wales, Victorian,
South Australian and Tasmanian state governments, the Commonwealth and
the Australian Capital Territory.
A key aim of AEMO is to provide an effective infrastructure for the efficient
operation of the wholesale electricity market, to develop the market and
improve its efficiency and to coordinate planning of the interconnected power
system. AEMO’s primary responsibility is to balance the demand and supply
of electricity by dispatching the generation necessary to meet demand.
AEMO’s key financial objective of being self-funding is achieved through the
full recovery of its operating costs from fees paid by market participants.
With respect to the electricity market AEMO has two core roles:
• Power System Operator
• Market Operator
AEMO manages the market and power system from two control centres in
different states. Both centres operate around the clock, and are equipped with
identical communication and information technology systems.
The entire NEM, or individual regions within it, can be operated from either or
both centres. This arrangement ensures continuous supply despite the risks
posed by natural disasters or other critical events, and provides AEMO with
the flexibility to respond quickly to dramatic changes in the market or the power
system.
3.2.1 Governing legislation
When the NEM commenced, a National Electricity Code provided guidelines
for how the market was to operate. These guidelines were developed following
comprehensive consultation and extensive trials conducted between
governments, the electricity supply industry and electricity users as part of a
government-driven deregulation and reform agenda.
In June 2005, the National Electricity Code was replaced by the National
Electricity Law and Rules. The Law and Rules were recently amended to

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replace NEMMCO with AEMO as the national electricity market and system
operator. AEMO’s functions are prescribed in the National Electricity Law while
procedures and processes for market operations, power system security,
network connection and access, pricing for network services in the NEM and
national transmission planning are all prescribed in the Rules.
3.2.2 Key responsibilities of AEMO
AEMO is required to operate the power system efficiently and ensure agreed
standards of security and reliability are maintained.
Security of Supply
AEMO’s highest priority as power system and market operator of the NEM is
the management of power system security. Security of electricity supply is a
measure of the power system’s capacity to continue operating within defined
technical limits despite the disconnection of a major power system element,
such as a generator or interconnector. The maintenance of power system
security ensures the power system is operated in a way that does not overload
or damage any part of it or risk overload or damage after a credible event.
Power System Reliability
Reliability is a measure of the power system’s capacity to continue to supply
sufficient power to satisfy customer demand, allowing for the loss of generation
capacity. The shortfall of supply against demand is referred to as unserved
energy. Reliability standards are established in the NEM that determine that
unserved energy per year for each region must not exceed 0.002 percent of
the total energy consumed in that region that year.
Supply Reserve
The power system is required to be operated at all times with a certain level of
reserve in order to meet the required standard of supply reliability across the
NEM. Calculation of the minimum reserve requirements recognises reserve
sharing in a national context. The minimum reserve levels across the different
NEM regions are listed in the Electricity Statement of Opportunities on the
AEMO website.
Managing Security and Reliability
In all but extraordinary circumstances, market forces keep supply and demand
in the NEM in balance. However, during periods of supply shortfall when
system security or reliability of supply is threatened, the Rules endow AEMO
with authority to use a variety of tools to restore supply and demand balance.
The tools include demand side management, the power of direction, load
shedding and reserve trading.
Security and Reliability Directions
AEMO has the power to direct registered generators into production when a
supply shortfall is expected and some generators are known to have withheld
some of their total capacity from the market. AEMO only uses this power of
direction to protect power system security or supply reliability.

15
Load Shedding
In the event that demand in a region exceeds supply and all other means to
satisfy demand have been implemented, AEMO can instruct network service
providers to shed some customer load. This action is only taken when there is
an urgent need to protect the power system by reducing demand and returning
the system to balance. Load shedding involves a temporary suspension of
supply to customers in a specific part or region of the NEM where system
security is at risk.
During a period of load shedding, supply is withdrawn from those NEM regions
affected by the shortfall in proportion to the demand levels at the time the
shortfall began. The proportioning process determines the amount of load
shedding for each affected region up to the point where interconnectors are
operating to their maximum transfer capacity. Once the interconnectors reach
their maximum transfer capacity, the importing region must bear any additional
load shedding locally.
By implementing load shedding, AEMO protects the integrity of power system
operation so that widespread and long-lasting blackouts are avoided. It also
ensures that the hardship caused by a sustained supply shortfall is shared in
an equitable fashion.
Reserve Trading
When there is sufficient notice of an upcoming shortfall of supply that threatens
to compromise minimum reserve margins, AEMO may tender for contracts for
electricity supply from sources beyond those factored into AEMO’s usual
forecasting processes. At these times, emergency generators and other
generators connected directly to the distribution network who submit tenders
may enter contracts to boost supply in the NEM so the widespread supply
interruptions that may otherwise have occurred can be avoided. In the same
way, some electricity consumers may offer for a financial consideration to
decrease their demand at times of supply shortfall so that demand and supply
are brought into balance.
3.2.3 Revenue requirement
AEMO operates on a break-even basis by recovering the costs of its
operations by levying fees on industry participants. This is done on the basis
of proposed costs of operations with funding for fixed assets on a needs basis
and levying fees to market participants. The fees comprise both fixed and
variable components that take into account the type of participant and their
share of trade in the market. The structure of fees payable to AEMO is
determined periodically, while the actual fee levels are set annually.
More specifically, AEMO’s annual revenue allowance/budget is based on:
 operating costs;
 a depreciation charge recovering capital expenditures;
 a charge for finance costs of borrowings; and
 amortisation of establishment costs

16
In accordance with its Members’ Agreement, AEMO produces a Statement of
Corporate Intent (SCI) each year providing details of the areas for focus in the
upcoming year. The SCI also includes its budgeted revenue requirements. In
this case AEMO’s governance structure acts as a self regulating device, with
Members’ and users’ interest meant to be addressed through representation
on the board of directors.6
6
We note that this form of ‘self regulation’ even for not-for-profit entities is not universal. For example, in the US,
RTO fees are regulated by FERC under typically complex US rules and regulations.

17
4 Central Buyer / IPP Administrator
What we refer to generally as a “Central Buyer / IPP Administrator” in fact
covers a spectrum of models perhaps ranging from a:
Single Buyer – where literally applied provides a statutory monopoly on the
purchase and sale of power. This is often bundled with the role of generator,
and TSO, perhaps with sales to separate distribution business.
Central Buyer – that might have significant power procurement
responsibilities, but not a complete monopoly in regard to power purchase and
on-sale.
Market operator or aggregator – e.g. providing balancing services to a
competitive wholesale market, or aggregating bulk power supplies and costs
in sale to suppliers.
IPP traders / administrators - that are responsible for:
 trading and administration of pre-existing (legacy) PPAs as an agent to
the counterparty to the PPA, or in some cases with counterparty
liability; and/or
 responsibility for procurement of new power purchases, also with or
without direct financial ownership of PPAs.
From a governance and regulatory standpoint, perhaps the key differentiator
of the stand-alone Buyer is that it may have significant financial exposures as
counterparty to power purchase agreements (PPAs) but a limited balance
sheet. The Buyer will usually have significant capital at risk and will need to
satisfy prudential requirements in the purchase of power. In such cases
substantive reserve accounts may need to be provided for to fill this role.
Moreover, the Buyer activity is not generally conducive to simple fixed revenue
or price cap type regulatory models often applied to other segments of the ESI.
Theoretically, one might try to set some benchmark purchase price and
incentivise the Buyer to outperform against that benchmark, but accurately
defining such benchmarks will in most cases be problematic. It will be
impossible to determine if under or over performance against benchmarks is
due to management’s actions; driven by purely external factors; or simply due
to error in setting the initial benchmark rate placing it in a financially
unsustainable position. We provide further discussion of this matter in the later
part of this section.
4.1 Mexico single buyer model 7
Since the nationalization of the industry in 1960, the Mexican Constitution
strongly limits private participation in the energy sector. By constitutional
mandate, the government has control of transmission, distribution, and
generation when aimed at “public service”. There are two key state-owned
7
This section has been taken directly from: Alejandra Núñez-Luna, Private Power Production in Mexico: A
Country Study. 2005; and from, Getting the Deal Through – Electricity Regulation 2009, published in November
2008 by Law Business Research.

18
enterprises which have a monopoly over the energy industry as a whole:
Petróleos Mexicanos (PEMEX), the state’s oil enterprise37, and Comisión Federal
de Electricidad (CFE), the electricity company which controls generation,
transmission and distribution of power.
The Secretaría de Energía (Ministry of Energy) is responsible for planning and
formulating energy policy, as well as for approving exploration activities related
to natural resources, and the Comisión Reguladora de Energía (CRE or Energy
Regulatory Commission) is responsible for the regulation and oversight of
private power generation and gas distribution. At the federal level, beyond the
electricity industry, the Ministry of the Treasury (Secretaría de Hacienda)
approves –in practice, sets- the electricity tariffs proposed by CFE (retail
distribution).
4.1.1 A Single Buyer model and private sector investment
In 1992, partly in response to Chapter VI of the North American Free Trade
Association, the Electric Power Public Utility Law was amended to allow private
participation in the generation and transmission of power, establishing six
permit modes for power-related activities that are excluded from the concept
of public service. Since then, the government has encouraged the participation
of private developers in the electricity sector. This has been mainly driven by
a lack of government funds to meet the significant increase in demand during
the past decade.
The statutory amendment in 1992 opened the door to private participation in
generation “not for public service”. Private generators are allowed, but must
sell their production through long-term power purchase agreements to CFE,
unless energy produced is used for export or self-supply. Private companies
cannot compete with the SOEs. CFE generates more than 4/5 of the total
electricity produced in the country (43,534 MW of installed capacity as of
2002). The LFC (recently amalgamated into CFE), which serves parts of
Mexico City, Morelos, Hidalgo and Puebla, generates 2% and PEMEX 4% (for
selfsupply). CFE also control the transmission grid, and distributes electricity
to 25 million users. That leaves 10.5% of total electricity generation to the
private sector, of which 5% comes from cogeneration and self-supply, and
5.6% from IPPs.
4.1.2 Transition to competitive models
The federal government is looking to foster the participation of private
companies in the electricity sector, particularly in power generation. Although
its independent power production programme has proved successful, with
private independent power producers accounting for a considerable
generation capacity of more than 11,450 megawatts (MW), the CFE may be
restricted in continuing its programme by public debt ceilings affected by the
programme's contingent liabilities. In order to keep pace with demand between
2007 and 2016, Mexico will need:
 an additional 16,286MW in generation capacity (achieved through the
installation of facilities generating 22,153MW and the decommissioning
of facilities generating 5,867 MW);

19
 over 13,000 kilometres of transmission lines, and transformation
substations with over 29,300 megavolt amperes capacity; and
 a significant number of distribution lines and distribution substations.
These activities require approximately $60 billion in investment. The lack of
public resources to cope with demand has become one of the leading drivers
for structural reform in the sector, along with the lack of scrutiny and
transparency of CFE rates and service conditions; and the excessive costs of
power for industrial processes.
The federal government and the main political parties have proposed bills for
some form of structural reform. Most of the proposed bills to restructure the
electricity sector have a number of common factors, namely:
 the creation of a wholesale energy market;
 the segregation of the national electric grid from the CFE;
 the creation of an independent system operator in charge of
dispatching the system and operating the national electric grid as a
common carrier; and
 greater authority for the Energy Regulatory Commission as the
independent regulator of the electricity sector.
4.1.3 The current single buyer model in Mexico
While these options for restructuring continue to be debated, the current model
remains that of the single buyer, with private participation is allowed in activities
such as:
 independent power production - private power generation facilities
aimed at supplying all of their capacity and power output to the CFE;
 self-supply - private power generation facilities aimed at supplying
power for self-supply purposes to a holder of the relevant permit and
its shareholders;
 co-generation - private power co-generation facilities aimed at
supplying power to establishments associated with the co-generation
process and the shareholders of the co-generation company;
 small-scale production - private power generation facilities with a
capacity not exceeding 30MW, operating for export purposes or
supplying all of the power to the CFE;
 private power generation facilities - installations with a capacity not
exceeding 1MW, developed by cooperatives or non-profit associations
to supply power to rural communities or isolated areas;
 exports / imports - private power generation facilities that export the
entire associated output; and imports - importing power for self-supply
purposes.
An independent power production company may also be entitled to hold other
permits with respect to the same generation facility (eg, co-generation, self-
supply or export permits).

20
Source: CFE
4.1.4 Administrative Rules for Independent Power Producers.
As mentioned above, IPPs can generate more than 30 MW of electricity, but
under the statute they are obliged to sell it to CFE. Power projects are initially
determined by CFE – which determines the amount of installed capacity
needed, the type of plant and technology as well as the duration of the contract-
and then offered for bidding, pursuant to the Ministry of Energy’s approval and
through their inclusion in CFE’s plans and programs (Programa de Obra e
Inversiones del Sector Eléctrico or POISE, which stands for “Work Program
and Investments of the Electricity Sector”).
The contract is awarded through competitive bidding on the basis of the lowest
average generation price. The CFE also facilitates the signature of fuel
contracts – in some cases with PEMEX. Once the contract has been awarded,
an administrative authorization must be obtained from the regulator (CRE).
Because permits for IPPs are only granted to Mexican citizens or corporations
organized under Mexican law and domiciled in Mexico, foreign corporations
must set up subsidiaries or Mexican joint ventures for the purpose of building
and operating power plants, in most cases the subsidiary being incorporated
solely for the IPP project. Once authorization has been granted, investments
are entitled to national treatment and protection against expropriation.

21
4.2 Thailand single buyer model
The Thai electricity sector is dominated by the Electricity Generating Authority
of Thailand (EGAT) which operates as a state-owned enterprise involved in
the generation and transmission of energy throughout Thailand, and as single
buyer, selling wholesale power to both the state-owned Metropolitan Electricity
Authority (MEA) and the Provincial Electricity Authority (PEA). The group
produces over 15,000 megawatts (MW) of electricity each year and purchases
additional power from independent power producers and small power
producers.
4.2.1 Generation, Single Buyer, Transmission and System Operator
EGAT remains the principal entity in the power sector of Thailand, with
responsibility to provide electricity for the whole Kingdom by generating,
transmitting and selling bulk energy to two state owned distributors.
Since 1992 EGAT had started to form subsidiaries in compliance with the
government's privatization policy in order to increase private sector
participation in the electricity supply industry and reduce investment burden of
both EGAT and the government. Private sector participation in the power
sector had been initiated in the form of IPPs and Small Power Producers
(SPPs). The Electricity Generating Company Plc (EGCO) had been formed as
a subsidiary of EGAT with a total installed capacity of 2,056 MW (with EGAT
selling down its shareholding over time). In 2001 Ratchaburi Power Company
was created as a wholly owned subsidiary of EGAT, of which a partial
shareholding was listed in the Thai stock exchange.
During the 1990’s EGAT concluded negotiations with seven IPP bidders for a
total capacity of 6,677 MW of capacity. The SPP program includes projects of
4,638 MW, of which part is sold to EGAT, and some directly to large
commercial end users. This broad structure of the Thai ESI since the late
1990’s is illustrated below:
Thai ESI Structure and position of single buyer

22
Perhaps the key characteristics of the ESI relevant to this study are that the
state-owned EGAT:
 Owns and operates a significant proportion of total generation supply
in the Kingdom.
 Owns and operates the high voltage transmission system.
 Responsible for systems operations and planning (with planning
guided by government policy, and needing endorsement of Cabinet).
 Acts as power purchaser from SPPs, and IPPs (with limited direct sales
from SPPs to end users under specific circumstances).
 Sells power by way of bulk supply agreements with the two state owned
distribution businesses.
While EGAT is the single buyer and is the counterparty to PPAs, the Ministry of
Energy (through its Energy Policy and Planning Office, and in a recent solicitation
its IPP Power Purchase Proposal Evaluation and Selection Subcommittee) has
responsibility for the procurement process.
EGAT does, however, provide and publish key inputs (such as the overall Power
Development Plan which is guided by government policy and needing endorsement
by Cabinet). (We discuss this further in section 5.1 on Energy Planning on the Thai
PDP).
4.3 California’s power purchase administrator
As a consequence of California’s energy crisis and electricity sector
restructuring in the early 2000’s, the State Department of Water Resources
(DWR) responsibilities for power purchases for the state were significantly
increased. DWR now oversees a large portfolio of power purchase contracts
and recovers its costs by way of an annual revenue determination process set
out in legislation. While the current role of DWR in respect to power purchase
and on-sale to distribution businesses was born out of crisis, it nevertheless
provides a interesting example of how a stand-alone PPA administrator can
work in practice.
For the purpose of this study, we have focused on how financial requirements
are funded within the context of its regulated revenue allowance.
4.3.1 Funding the PPA administrator and regulated revenue allowance
DWR's California Energy Resources Scheduling (CERS) division manages
billions of dollars of long-term electricity contracts. CERS division was created
in 2001 with the passage of AB1X during the state's energy crisis. CERS
function was to procure electricity on behalf of the state's three largest investor
owned utilities (IOUs), such as Pacific Gas and Electric and Southern
California Edison, which were experiencing extreme financial difficulty during
the crisis.
The CERS division is financially responsible for the long-term contracts
entered into by DWR, with funding for the contracts provided by $13 billion in

23
ratepayer-supported Power Supply Revenue Bonds. However, the IOUs
manage the receipt and delivery of the energy procured by the contracts.
The material below is taken directly from DWR’s revenue determination as
submitted to the California Public Utilities Commission.8
We have provided a
portion of that document (with some minor paraphrasing done by us) in the
section below that we hope illustrates key components of that regulatory
approach to revenue regulation that are rather unique to this sub-sector of the
ESI.
_____________________________________________________________
DWR - SCOPE OF REVENUE REQUIREMENTS
The costs of the Department’s purchases to meet the net short requirements of retail
end use customers in the three California investor-owned utilities’ (“Utilities” or
“IOUs”) service territories, including the costs of administering the long-term
contracts, are to be recovered from payments made by customers and collected by the
IOUs on behalf of the Department.
The terms and conditions for the recovery of the Department’s costs from customers
are set forth in the Act, the Regulations, the Rate Agreement and orders of the
Commission.
Among other things, the Rate Agreement contemplates a:
 “Bond Charge” (as that term is defined in the Rate Agreement) that is designed
to recover the Department’s costs associated with its bond financing activity
(“Bond Related Costs”); and a
 “Power Charge” (as that term is defined in the Rate Agreement) that is
designed to recover “Department Costs”, or the Department’s “Retail Revenue
Requirements” (as those terms are defined in the Rate Agreement), including
power supply related costs.
During 2009, the Department projects that it will incur the following power
procurement-related Costs:
(a) $3.691 billion for long-term power contract purchases to cover the net short
requirement of customers;
(b) $28 million in administrative and general expenses; and
(c) $(76) million in other net changes to Power Charge Accounts (including operating
reserves).
This projection results in a revenue requirement of $3.642 billion.
OPERATING RESERVE ACCOUNT
In each Revenue Requirement Period, the Department calculates the Operating
Reserve Account Requirement (“ORAR”) as the greater of
8
State of California Department of Water Resources, Revision to the Determination of Revenue Requirements
For the Period January 1, 2009 through December 31, 2009. Submitted To The California Public Utilities
Commission Pursuant To Sections 80110 and 80134 of the California Water Code. Oct. 2008

24
(a) the largest aggregate amount projected by the Department by which Operating
Expenses exceed Power Charge Revenues during any consecutive seven calendar
months commencing in such Revenue Requirement Period; and
(b) 12 percent of the Department’s projected annual Operating Expenses; provided,
however, that the projected amount will not be less than the applicable percentage of
Operating Expenses for the most recent 12-month period for which reasonably full and
complete Operating Expense information is available, adjusted in accordance with the
Indenture to the extent the Department no longer is financially responsible for any
particular Power Supply Contract. All projections are to be based on such assumptions
as the Department deems to be appropriate after consultation with the Commission and
taking into account a range of possible future outcomes (i.e., “Stress Cases”).
Additionally, the ORAR shall include, but shall not be limited to, the Priority Contract
Contingency Reserve Amount (“PCCRA”). The PCCRA is the maximum amount
projected by the Department to be payable by the Department under and pursuant to
Priority Long Term Power Contracts in any calendar month during such Revenue
Requirement Period. All projections are to be based on such assumptions as the
Department deems to be appropriate after consultation with the Commission. Based
on the Stress Cases described below under “Sensitivity Analysis”, the Department
determines the ORAR for the 2009 Revenue Requirement Period to be $543 million,
reflecting an amount equal to the PCCRA. The Department projects to meet the ORAR
on or before June 1, 2009.
DEBT SERVICE RESERVE ACCOUNT
For purposes of calculating the amount of the Debt Service Reserve Requirement from
time to time, interest accruing on Variable Rate Bonds during any future period will
be assumed to accrue at a rate equal to the greater of
(a) 130 percent of the highest average interest rate on such Variable Rate Bonds in any
calendar month during the twelve (12) calendar months ending with the month
preceding the date of calculation, or such shorter period that such Variable Rate Bonds
shall have been outstanding, or
(b) 4.0 percent. For the 2009 Revenue Requirement Period, the Department will
calculate projected interest on unhedged Variable Rate Bonds at 4.935 percent.
For the 2009 Revenue Requirement Period, the Department has determined the Debt
Service Reserve Requirement to be $950 million. The Department projects to maintain
this amount at all times during the Revenue Requirement Period.
RESERVE ACCOUNT STRESS TESTS
The Rate Agreement requires the Department to evaluate its costs and cash flows on a
monthly basis and to notify the Commission of its Retail Revenue Requirements no
less than once annually, thereby ensuring that Bond Charges and Power Charges are
adequate to meet financial obligations associated with the Bonds and the power supply
program. From the date the Department first initiates any necessary revised Retail
Revenue Requirement proceeding, it expects no more than seven months will elapse
before it receives modified levels of revenues associated with the filing.
As explained in prior Department revenue requirement determinations, during this
seven month period the Department would endeavour to identify any material changes
in its revenue requirement, proceed through its own administrative determination of

25
its modified revenue requirement, notify the Commission of the new revenue
requirement for purposes of allocating the costs among customers, and finally begin
receiving the modified level of revenue. To ensure its ability to meet its financial
obligations during this seven month period, the Department must maintain reserves
that are adequate to meet normal anticipated expenses, unexpected variations in these
expenses, and/or reductions in revenue receipts resulting from factors beyond the
Department’s control.
_________________________________________________________________

26
5 Energy planning
The energy planning role and associated governance structures are tied
directly to the nature of the market in a given jurisdiction.
 Decentralised competitive electricity markets typically tend towards less
prescriptive planning structures, whereas centralised markets tend
towards more prescriptive regimes.
 Governance of planning agencies in markets primarily served by private
sector suppliers is often broad based - inclusive of industry players,
customers and government; whereas planning in state-owned electricity
supply industries is more often overseen by governmental bodies.
 The scope for competition also drives approaches to planning and
governance across the supply chain.
o For example, in countries where there are competitive wholesale
electricity markets the role of generation planning is largely
addressed by way of information disclosure, and where there is
centralised generation investment, it tends to be limited to
procurement of short to medium term reserve capacity.
o Alternatively, transmission and distribution investment and
planning is not often carried out in a competitive environment
(although there are counter examples) and more centralised and
prescriptive investment and planning regimes apply to these
segments of the industry.
In preface to this section on energy planning, we also note that legislation in
South Africa sets out the various roles and responsibilities in this regard. We
do not mean to provide comment on the overall approach set out in relevant
South African legislation, nor have we aimed to provide a comparative analysis
of various approaches to energy planning. Our simple aim here is to provide
a few examples of how energy planning is carried out in several other countries
so as to highlight issues and options one might consider in undertaking such
comparative analysis.
5.1 Thailand energy policy and Power Development Plan
The Thai electricity sector has a number of similarities to that of South Africa
including a dominant state-owned utility acting as the single buyer of private
sector power in transition to more competitive market approaches.
The landscape of Thailand's energy sector was shaped in the 1990s when
government began entertaining the idea of privatizing a large portion of its
state-owned entities, including those in its energy sector. In 1992, the
government created the National Energy Policy Council (NEPC). This council
amended the EGAT Act of 1968 in order to end EGAT's longstanding
monopoly on power generation, which in turn allowed for the private production
and sale of electricity. The NEPC also laid the groundwork to allow IPPs and
small power producers (SPPs) into the Thai market.
In October 2002, after the bureaucratic reform of the Thai government, the

27
Ministry of Energy was established. Various energy-related agencies that used
to be scattered under different ministries were transferred to be under the
Ministry of Energy so that the energy sector management and the planning
and development of national energy programs, including regulation, would be
more streamlined. The Energy Policy Committee (EPC) was renamed as the
Committee on Energy Policy Administration (CEPA), chaired by the Minister of
Energy.
Current Structure of Thailand's Energy Sector Management
Members of the above-mentioned governing bodies, their respective authority
and duties are summarized as follows:9
The National Energy Policy Council (NEPC)
Members:
Prime Minister - Chairman
Deputy Prime Minister (as assigned by the Prime Minister) - Vice Chairman
Minister to the Prime Minister's Office (as assigned by the Prime Minister)
Minister of Defence
Minister of Finance
Minister of Foreign Affairs
Minister of Agriculture and Cooperatives
Minister of Transport
Minister of Natural Resources and Environment
Minister of Energy
Minister of Commerce
Minister of Interior
Minister of Science and Technology
9
From EPPO web site, Energy Sector Planning in Thailand, August 2009.
National Energy Policy Council
(NEPC)
Natural
Cabinet
Committee on
Energy Policy
Ministry of Energy
Energy Policy and
Planning Office
The Office
of the
Electri
Policy Frameworks
Energy
Regulat

28
Minister of Industry
Permanent Secretary of the Ministry of Energy
Secretary-General of the Council of State
Secretary-General of the National Economic and Social Development Board
Director of the Bureau of the Budget
Director-General of the Energy Policy and Planning Office - Member and Secretary
Authority and Duties:
1) To recommend national energy policies and national energy management
and development plans to the cabinet.
2) To set criteria and conditions for energy pricing in accordance with national
energy policies and national energy management and development plans.
3) To monitor, supervise, co-ordinate, support and expedite the operations of
all committees with authority and duties related to energy, including
government agencies, state enterprises and the private sector, to ensure that
their operations are in accordance with national energy policies and national
energy management and development plans.
4) To evaluate the implementation pursuant to national energy policies and
national energy management and development plans.
5) To perform other functions as assigned by the Prime Minister or the cabinet.
The Ministry of Energy (MOEN)
The Ministry of Energy was established on 3 October 2002, pursuant to the
Act on Organization of Ministries, Sub-Ministries and Departments, B.E. 2545
(2002). Various energy-related agencies that used to be scattered under
responsibilities of different ministries were then transferred to be under the
Ministry of Energy so that the energy management and the planning and
development of national energy programs, including regulation, would be more
streamlined.
The Departments under the Ministry of Energy:
 Office of the Minister
 Office of the Permanent Secretary
 Energy Policy and Planning Office (EPPO) - formerly the National
Energy Policy Office (NEPO), Office of the Prime Minister
 Department of Mineral Fuels (DMF) - formerly the Natural Fuels
Division/ Department of Mineral Resources, Ministry of Industry
 Department of Energy Business (DOEB) - formerly the Bureau of Fuel
Oil/ Department of Commercial Registration, Ministry of Commerce, the
Petroleum Industry Division, Ministry of Industry, and the Fuel Storage
Safety Control Division/ Department of Public Works, Ministry of Interior
 Department of Alternative Energy Development and Efficiency (DEDE)
- formerly the Department of Energy Development and Promotion

29
(DEDP), Ministry of Science, Technology and Environment
The State Enterprise and Autonomous Public Companies under the Ministry
of Energy:
 Electricity Generating Authority of Thailand (EGAT), formerly a state
enterprise under the Office of the Prime Minister.
 PTT Public Company Limited (PTT), from the Ministry of Industry
 Bangchak Petroleum Public Company Limited (BCP), from the Ministry
of Finance
The Public Organization under the Ministry of Energy:
 The Energy Fund Administration Institute (EFAI) - an independent
agency responsible for procurement of fund to stabilize domestic retail
oil prices and for other tasks in compliance with the government
policies relevant to the Energy Fund Administration.
The Independent Organization under the Ministry of Energy:
 The Energy Regulatory Commission (ERC) - appointed on 1 February
2008 under the Energy Industry Act.
Remarks: Another two energy-related state-enterprises, i.e. the Metropolitan
Electricity Authority (MEA) and the Provincial Electricity Authority (PEA) are
currently under the Ministry of Interior.
Structure of the Ministry of Energy (since October 2002)
The Committee on Energy Policy Administration (CEPA)
Members:

30
Minister of Energy - Chairman
Permanent Secretary of the Ministry of Energy
Permanent Secretary of the Ministry of Transport
Permanent Secretary of the Ministry of Natural Resources and Environment
Permanent Secretary of the Ministry of Commerce
Permanent Secretary of the Ministry of Industry
Secretary-General of the National Economic and Social Development Board
Secretary-General of the Council of State
Director-General of the Fiscal Policy Office
Director-General of the Energy Policy and Planning Office - Member and Secretary
Representative of the Energy Policy and Planning Office - Member and Assistant
Secretary
Authority and Duties:
1) To recommend national energy policies, national energy management and
development plans, and energy-related measures.
2) To provide comments on energy-related programs and projects of various
agencies and suggest priorities for the programs and projects.
3) To monitor petroleum prices and determine contribution rates to be collected
for the Oil Fund in accordance with the framework and guidelines prescribed
by the NEPC, including other tasks as may be assigned by the Prime Minister
with regard to the Oil Fund management and in pursuance to the law on
remedy and prevention of fuel oil shortage.
4) To recommend policies and measures on energy pricing and monitor
electricity tariff adjustments pursuant to the automatic tariff adjustment
mechanism.
5) To consider and recommend to the NEPC royal decrees, ministerial
regulations and other measures to be enacted under the Energy Conservation
Promotion Act.
6) To bid ministries, bureaus, departments, local administrations, state
enterprises and any individuals to present technical, financial, statistics
information and/or other details pertinent to the national energy policies and
national energy management and development plans.
7) To perform any other task as may be assigned by the NEPC or its Chairman.
8) To appoint sub-committees to assist with particular tasks as deemed
necessary.
Energy Policy and Planning Office (EPPO)
 Serves as the Secretariat to the NEPC, the CEPA and the ENCON
Fund Committee and hence carry out duties as stipulated in, among
others, the National Energy Policy Council Act (1992), as amended up

31
to No. 2 (2007) and No. 3 (2008); the Energy Conservation Promotion
Act (1992), as amended up to No. 2 (2007); and the Emergency Decree
on Remedy and Prevention of Shortage of Fuel Oil (1973), as amended
up to No. 3 (1977);
 Recommends to the NEPC and/or the Minister of Energy national
energy policies, energy management and development plans,
including energy measures to ensure adequate and efficient energy
supply in line with the economic conditions of the country;
 Proposes measures for the solution and prevention of oil shortages, in
accordance with the Emergency Decree on Remedy and Prevention of
Shortage of Fuel Oil (1973) and co-ordinate the implementation of
these measures with related agencies;
 Recommends policies and measures on petroleum pricing and
taxation, and determine the framework for the Oil Fund management;
 Sets energy conservation and alternative energy measures and
determine the framework for the Energy Conservation Promotion Fund
management with a view to promoting energy conservation and
alternative energy;
 Coordinates, monitor and evaluate outcomes of the implementation
pursuant to the energy policies and energy management and
development plans of the country, as well as manage energy funds;
 Collects, process and disseminate data and statistics related to the
energy sector, analyze energy situations/trends and develop energy
outlook of the country.
Thailand Power Development Plan10
The Power Development Plan is a detailed planning guide setting out
Thailand’s medium term power needs in terms of factors such as reliability of
power supply, fuel sources and diversification, generation technology types,
power purchases, transmission expansion, etc. The current PDP covers the
period 2008-2021.
- EGAT formulates the PDP under the policy framework of the Ministry of
Energy.
- The PDP is to be approved by the National Energy Policy Council (NEPC).
- The PDP is to be endorsed by Cabinet.
The PDP is an important document as it sets out the intended split of
generation projects in terms of:
- EGAT power plant projects
- IPP power purchase projects
10
See EGAT Thailand Power Development Plan 2008-2021, revision 2. May 2009 (EGAT web cite)

32
- Renewables
- SPP power purchase projects
- VSPP power purchase projects
- Imports from cross-border power projects
The PDP also sets out transmission expansion projects fpor the planing period
aligned with the generation plan.
Energy Regulatory Commission (ERC)
Formerly, the government, through the National Energy Policy Council, would
both determine energy policy and regulate the operation of the energy industry.
Since 11 December 2007, Thailand's Energy Industry Act, B.E. 2550 (2007),
has come into force. Under the Act, the Energy Regulatory Commission (ERC)
was appointed on 1 February 2008 to regulate the electricity and natural gas
industry under the policy framework of the government, with the establishment
of the Office of the Energy Regulatory Commission (or OERC) to function as
the Secretariat to the ERC. Therefore, since February 2008, the energy
industry regulatory function has been transferred from the NEPC to the ERC.
Major Authority and Duties of the ERC:
 To regulate the energy industry operation to be transparent and
standardized so as to protect the benefits of energy consumers, and to
ensure its compliance with the objectives of the Energy Industry Act
and the policy framework of the government;
 To establish a license issuance process, including issuance of
announcement on the categories of licenses for energy industry
operation and recommendation of issuance of a royal decree specifying
categories, capacities and characteristics of energy business that are
exempted from a license requirement;
 To determine measures enhancing security and reliability of the power
system;
 To establish regulations and criteria regarding power supply and issue
requests for proposal for power purchase, and ensure that the selection
procedures are fair for all parties concerned; and
 To provide comments to the Minister of Energy regarding the Power
Development Plan, plans for investment in the power sector, natural
gas procurement plan and plans for energy network system expansion.
5.2 Mexico Works & Investment Program of the Electric Sector
The broad structure of energy planning and investment are:
Comisión Federal de Electricidad: It prepares energy demand studies, it
prepares its electrical prospective, it formulates the program for works and
investment of the electric sector, prepares feasibility studies of each plant,

33
discloses and develops project bids, supervises work execution, carries out
negotiations with inhabitants and owners of the regions affected by projects.
Ministry of Finance: It analyzes and approves of the budgets prepared by the
Comisión Federal de Electricidad and it assesses the expense execution and
the compliance of goals and objectives of projects.
Ministry of Energy: It participates in the Coordination, Planning, program
authorization, budget execution and project bidding, and it tracks the
construction of Power Plants.
5.2.1 Works & Investment Program of the Electric Sector
Mexico’s dominant state-owned utility Comisión Federal de Electricidad (CFE)
platys a substantial role in planning the National Electric System. CFE produce
annually the “Works & Investment Program of the Electric Sector” with a 10
year horizon (the spanish acronym is POISE). POISE defines a detailed
physical and financial investment program updated yearly for the next 10-year
period. It is prepared including the necessary infrastructure projects to meet
the demand for the planning period. The Work and Investment Program
prepared by the CFE is subject to the consideration and authorization of the
Ministry of Energy.
Important areas covered in the POISE for the planning period include:
 Demand growth forecast
 Overall generating capacity needed
 Required investments by source of funding (i.e. CFE or IPP).
 Generation types and technologies
 Fuel sources
 Specific project cites
 Anticipated tender dates (IPPs and/or construction of CFE projects)
 Gas pipeline investments (per fuel supply requirements)
 Transmission and distribution upgrades and expansion
***End of document***

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