Trans African Energy Pty - Establishment of an Independent Sytem Operator

TRANS AFRICAN ENERGY
_________________________________
Independent System Operator
Key issues to address in establishment of an ISO
in South Africa
________________________________
Contact: Dr Stephen Labson
Email: slabson@transafricanenergy.com

Trans African Energy Pty
2
TABLE OF CONTENTS
EXECUTIVE SUMMARY
1 INTRODUCTION AND FRAMEWORK FOR ANALYSIS 1
1.1 Introduction 1
1.2 Overview of ISO roles 2
2 GOVERNANCE AND RULE MAKING 5
2.1 Overview of governance requirements 5
2.2 Governance within the context of the South African Grid Code 6
2.3 Key issues in transition to an ISO 8
3 SYSTEM OPERATIONS FUNCTIONS 10
3.1 System operations requirements 10
3.2 Key issues 10
4 POWER TRADING MANAGEMENT 14
4.1 Power trading management requirements 14
4.2 Key issues 15
5 POWER SYSTEM PLANNING AND INVESTMENT 16
5.1 System adequacy and planning 16
5.2 The current situation for energy planning and investment 16
5.3 Key issues 18
6 MARKET ADMINISTRATION AND DEVELOPMENT 19
6.1 Market administration functions 19
6.2 Market development functions 21
7 ISO CORPORATE FUNCTIONS 23
7.1 Corporate functional requirements 23
7.2 Budget and revenue source 23

3
7.3 Corporate operational requirements 24
7.4 HR issues 26
8 SELECTED INTERNATIONAL EXAMPLES 28
8.1 California ISO 28
8.2 Australia - AEMO 30
8.3 Mexico single buyer model 34
8.4 Thailand single buyer model 38
8.5 California’s power purchase administrator 40
8.6 Thailand energy policy and Power Development Plan 43
8.7 Mexico Works & Investment Program of the Electric Sector 50

1
1 Introduction and framework for analysis
1.1 Introduction
There has been ongoing interest in setting up an Independent System
Operator (ISO) in South Africa with draft legislation being developed from time
to time. However, there does not seem to us to be a consensus view on the
scope or role of the ISO or consequential restructuring of the ESI that it might
entail.
Nevertheless, the importance of the matter us such that it warrants discussion
at a number of levels. The part of that discussion we would like to engage in
pertains to the practical aspects of establishing such an entity.. In this regard,
we wish to highlight that we have not aimed to undertake a normative study –
that is – we do not mean to recommend which model should be applied. Our
aim is simply to highlight key issues that would need to be addressed should
South Africa decide to establish an ISO.
Pending further resolution and definition of ISO we have assumed a minimalist
view to industry restructuring.
 An ISO is formed as a stand-alone entity – perhaps as a public
enterprise or an entity of government.
 Wholesale power arrangements are established that might involve
some combination of bilateral arrangements with the possibility of a
central power purchasing authority.
 Generation and transmission are largely kept intact in a vertically
integrated business.
 Restructuring of the distribution sector is not implemented during the
short to medium term time frame considered here and not explicitly
evaluated (nor retail competition).
It is assumed that new (or changed) roles in this market are defined through
legislation and/or regulations and licensed with oversight by a regulator. We
believe that our assumptions are reasonably robust to a range of modifications
and revisions to these assumptions as the South African ISO model is more
fully defined. However, as our review is based on working assumptions – our
analysis would need to be updated in line with new information as it is provided.
The following diagram illustrates the broad structure of the ISO that is assumed
in focusing our analysis.

2
Industry structure – working assumption only
1.2 Overview of ISO roles
Under this structure there are two core roles that an ISO tends to play1
.
 The first of these essentially defines an ISO, in that the ISO has the
role of a systems operations manager, dispatching independent of
the generation owners and operators. In some markets the ISO is part
of the transmission entity but, where it is not, the ISO role needs to also
encompass transmission system operation, including monitoring of
power flows and constraints and (as required) issuing switching
instructions.
 The second main role can be that of power trading manager or
alternatively put an Independent Market Operator (the “IMO”) and this
role varies considerably depending on the design of the wholesale
power trading arrangements that are to apply. This may encompass a
gross or net pool, or a central buyer concept. Further the trading
arrangements may be structured based on energy only, for energy and
capacity separately and may include arrangements for purchasing
ancillary services. And this role may be combined in the same entity
with the System Operator, or may be undertaken by a separate party.
1
For convenience in this report we will use the term ISO to include power trading operations (sometimes
referred to as an IMO), except where the distinction is important

3
The indicative functions that an ISO might potentially be asked to fulfil are
illustrated in the following diagram. We stress that there is no single defined
model for an ISO and different markets tend to allocate different functions
across different organisational models. However, we think the representation
below offers a reasonably generic starting point for analysis.
Illustrative ISO functions
There are several other groups of functions that are frequently placed in an
ISO as indicated in the exhibit above. These can be grouped as:
 Power system planning function
 Market2
administrative functions, and
 Market development functions.
Power system planning and investment involves the role of establishing
and/or monitoring planning reserve margins, and some role (whether
2
In this report we will use the term “market” to cover the suite of arrangements under which power is purchased
from more than one party and on-sold to more than one party. This includes the Central Buyer/Single Buyer
model.

4
prescriptive or informational) in planning for new generation and new
transmission.
Market administration functions often include matters such as wholesale
metering and reconciliation, authorising new connections, dispute
management, market monitoring and compliance reporting and performance
reporting.
Market development functions include the establishment and ongoing
management of rules, codes, procedures and protocols.
Finally there is a range of ISO corporate functions including finance/funding,
HR and IT.
Our review addresses each of these functions in turn with a focus on those that
tend to have the most significant implications either for the new ISO itself or for
the generation/transmission/supply entity. The structure of the rest of this
document is thus as set out below:
Section Topic
Section 2 Governance and rule making
Section 3 System operations functions
Section 4 Power trading management
Section 5 Power system planning and investment
Section 6 Market administration and development
Section 7 Corporate functions
Annexure International case studies

5
2 Governance and rule making
2.1 Overview of governance requirements
Governance arrangements need to be structured in a manner that clearly
identifies parties responsible for achieving core objectives. Objectives relevant
to the role of the ISO include:
 System security and adequacy of supply objectives;
 infrastructure planning and investment objectives;
 system access objectives;
 common quality objectives; and
 power trading support related objectives.
In addition, there will be economic, environmental and other wider policy
objectives that the ISO will be required to take into account and comply with.
Generally, a government body will hold the responsibility for setting objectives
through legislation, policy, regulation, and/or rules and an independent party
(e.g. an ISO or transmission company) will have the responsibility for ensuring
delivery of the outcomes relevant to system operation and transmission. The
requirements on other parties to follow and comply with instructions can be
contained in a rules compliance regime including grid codes, connection
codes, licencing conditions, market rules, etc.
2.1.1 Legal framework
The ISO will have certain powers typically provided for under legislation and
supporting regulations. This will include:
 Establishing the ISO itself, including its articles of association, financial
structure and ongoing funding sources.
 Powers which establish a set of Market Rules which govern the roles
and actions of the ISO and the roles and actions of participants in the
market.
 Codified change processes for the Rules. This may be managed by
the ISO or by a separate body. For example, in Australia the AEMC
manages Rule change processes and the market operator (AEMO)
operate in accordance with the Rules (albeit with input to Rules change
processes).
 Powers under the Rules for industry policies, procedures and
protocols to be developed, typically administered by the ISO but with
input from market participants.

6
 There are various options for enforcing the performance of an ISO.
In some jurisdictions the System Operator is contracted to provide
services and achieve outcomes. In other jurisdictions the objectives of
the System Operator are set out in regulations and/or rules. Whichever
approach is taken clear performance obligations and measures must be
laid out. There are also typically certain legal responsibilities and
indemnities provided to the ISO that would need to be addressed in
establishment of the new entity.
 A dispute resolution process. There is typically a range of complex
and significant matters that the ISO is responsible for, at some stage it
is likely that a market participant will wish to call for review of a decision
or action taken by the ISO. For example, generation plants may need to
be either ‘constrained off’ or constrained on’ when system requirements
dictate. While there would normally be definitive rules guiding the ISO’s
actions in this example, it is conceivable that at some stage there will
be a dispute on how the ISO has applied relevant rules. The ISO might
be well placed to address disputes between market participants,
however there needs to be an external body to which disputes with the
ISO itself can be escalated.
2.2 Governance within the context of the South African Grid Code
We note the South African Grid Code (Governance Code)3
in conjunction with
relevant legislation describes the provisions necessary for the overall
administration and review of the various aspects of the Grid Code and many
of the issues briefly outlined above.
The current framework, which we have so far assumed would be employed as
a template going forward, is summarised below.
2.2.1 Administrative authority
NERSA is the administrative authority for the Grid Code in terms of section 15
of the Electricity Regulations Act, 2006 (Act 4 of 2006). NERSA shall ensure
that the Grid Code is implemented and complied with for the benefit of the
industry.
2.2.2 The Grid Code Advisory Committee (GCAC)
The GCAC (constituted by NERSA) is established to:
 Ensure a consultative stakeholder process is followed in the
formulation and review of the Grid Code.
 Review and make recommendations regarding proposals to amend the
Grid Code.
 Review and make recommendations regarding proposals for
exemption to comply with the Grid Code.
3
The South African Grid Code - Governance Code Rev 7.0 – March 2008

7
 Facilitate the provision of expert technical advice to NERSA on matters
related to the Grid Code.
2.2.3 Composition of the GCAC
Under the current Grid Code, NERSA is responsible for the composition of and
constituencies represented by the GCAC to ensure that it is at all times
reflective of the evolving industry. NERSA may decide to expand the
composition of the GCAC as part of the membership review process in
consultation with the GCAC.
The GCAC shall consist of at least the following:
 One member representing the System Operator
 One member representing transmission network service providers
(TNSPs)
 Two members representing generators
 Two members representing distributors
 One member representing large end-use customers
 One NERSA member appointed i.t.o. the NERSA governance
procedures
 One member representing black economic empowerment interests
2.2.4 Grid Code Secretariat
Currently, the System Operator is appointed as the Grid Code Secretariat. The
secretariat plays an important role in that it is responsible for developing
procedures for the review of proposed amendments and exemptions to the
Code by the GCAC. Moreover (as summarised by us), the secretariat is to:
 Assist, when requested, in the preparation of submissions to the
GCAC.
 Prepare amendment and exemption proposals for submission to the
NERSA following review by the GCAC.
 Publish the Grid Code
 Inform participants of the progress with applications for amendment or
exemption.
 Co-ordinate the activities of the GCAC.
 Function as a formal communication channel for the GCAC.
2.2.5 Rule change
The current Governance Code sets out the process for rule change which can
have important implications for individual market participants and the industry
more generally. Key aspects of the (current) process are summarised below
to further highlight the potential importance of the GCAC and the secretariat in
regard to rule changes:

8
 Once the GCAC has reviewed submissions in regard to proposed
amendments and exemptions to the Grid Code, the Secretariat shall
prepare the formal recommendation to NERSA.
 The chairperson of the GCAC and one member nominated by the
GCAC shall attend the presentation to NERSA.
 An applicant may attend the NESA Board meeting if the GCAC does
not unanimously recommend the proposal, and is entitled to make
representations to the NERSA Board.
 NERSA shall give notice to the Secretariat of the decisions reached.
The Secretariat is responsible for communicating these decisions to
participants.
 The Secretariat shall update the Grid Code with the approved
amendments and exemptions.
2.2.6 Complaints pertaining to the Secretariat, GCAC, or NERSA
In addition to setting out the process for resolution of disputes between parties,
the Governance Code provides that any complaint regarding the operations of
the Secretariat or the GCAC shall firstly be addressed in writing to the
Secretariat. If the complaint is not resolved, the matter shall be referred to
NERSA.
Any objection to decisions by the NERSA shall be made in writing to the
NERSA. Participants may appeal to the High Court against decisions taken
by the NERSA about which they are aggrieved.
2.3 Key issues in transition to an ISO
While the current structure of governance set out in the SA Grid Code may well
provide a strong basis for an ISO, we anticipate some important dynamics
moving forward4
:
 The ISO would often have a broader base of governance than for a
public enterprise). There are examples internationally where the ISO
might be set up as a ‘not-for-profit’ organisation perhaps with joint
government and industry representation at board level.
 It is our view that a range of matters set out in the Grid Code or related
rules may be increasingly be taken to the GCAC, the Regulator, and
perhaps to appeal as various market participants pursue their individual
interests in Grid Code amendment and/or compliance.
 Incoming market participants are likely to call for changed
representation on the GCAC (or similar body) so as to more strongly
influence the working of that body.
 The ISO would likely assume Grid Code Secretariat functions.
4
We wish to note that as a scoping document, we have not undertaken a comprehensive review as to the
suitability of applying the existing set of Grid Codes to a new industry model.

9
 ISO operational performance will be monitered and ertain indemnities
may need to be provided to the ISO with regard to operational
performance and liabilities.

10
3 System operations functions
3.1 System operations requirements
The ISO is responsible for the safe and reliable operation of the power system.
The South African Grid Code sets out operational aspects of this responsibility
in regard to power transfers and stability of the Interconnected Power System
(IPS).
An important aspect of this responsibility is in managing the power system in
real time by dispatching generation to meet load requirements. The method
of dispatch will vary according to the type of market. For example:
 in a gross power pool, dispatch of all generation is according to real-
time market offers;
 in a net pool, generators each provide their dispatch schedules to the
ISO, which then issues dispatch instructions according the schedules
and operates a net balancing market; and
 in a central buyer market the buyer is likely to provide dispatch
schedules and the ISO issues dispatch instructions according to those
schedules and against criteria set out in Rules (i.e. dispatch rules).
In order to manage the power system, the ISO is also likely to have
responsibility for dispatching ancillary services such as frequency control,
instantaneous reserve (including instantaneous load shedding) and voltage
support in order to maintain common quality standards. As with generation
load dispatch, there are a variety of mechanisms by which ancillary services
may be dispatched.
The ISO may also have the role of Transmission System Operator (TSO);
that is, the role of managing transmission system operations and switching.
However this is not necessarily the case and the TSO role can be retained
within the business of the transmission asset owner. In this case the
transmission asset owner will be required to operate the transmission system
according to agreed protocols.
Because of its central role, the ISO would also typically have responsibility for
managing, or at least co-ordinating, planned transmission and generation
outages.
3.2 Key issues
The types of technical protocols and codes very briefly outlined above can
have significant implications for individual market participants. While a
comprehensive review of such matters is beyond the scope of our analysis, we
do wish to illustrate the types of issues that might be subject to debate as
existing protocols, market rules, and codes are further codified or revised. We
do stress that this is more for illustrative purposes, as we have not had access

11
to the full set of existing rules pertaining to the South African IPS and we have
not been briefed on the expected future state of such rules.
3.2.1 Power transfers - network access
An important structural consideration for the operation of an electricity market
is the access arrangements for participants. The approach taken will have
implications for an ISO and market participants. The options can be
considered to be ‘open access’ or ‘managed connection’. In an open access
arrangement all generators and loads are provided with rights to connect to
the system but may be constrained by the real time capacity of the system. In
an open access arrangement the ISO will be required to manage dispatch of
generation and/or load taking into consideration system constraints. Under a
managed connection approach only generators and/or loads that can be
guaranteed constraint free operation will be connected to the system.
The implicit or explicit network access rights that are assigned may well have
a significant effect on the operations of generators and therefore could have
significant financial impact on various market participants. There is a range of
different models for access (from physically firm, to financially firm to non-firm)
each with different implications when a generator is constrained on or off from
the system.
 It is our understanding that under the South Africa Grid Code market
rules set out the way in which parties are remunerated / charged for
constrained on / off generation in the SA IPS.5
 As the South African ESI becomes more segmented it is conceivable
that the existing rules may need to be further codified to deal with
constraints affecting various parties.
Market participants can have a great deal at stake in regard to the detailed
nature of access rules, and we anticipate considerable attention to be focused
on this matter going forward.
3.2.2 Ancillary services to achieve common quality objectives
It is important that certain common performance components are maintained
within defined quality parameters. These common quality components include:
 frequency management;
 voltage management; and
 reserves management.
5
For example, it is our understanding that under the SA Grid Code, constrained generation is considered an
ancillary service and the cost to generation is remunerated by the transmission provider. In some jurisdictions
generators are not remunerated when constrained off the system. The scope of our review is not to review the
merits of such approaches, but we raise this to illustrate the type of market rules issues that will no doubt start to
be raised by external parties as the SA ESI becomes more segmented.

12
The above ancillary services are typically purchased from asset owners by
the ISO. It is our understanding that this is the case for the SA IPS currently.
Common quality objectives are set by a governing body and these provide the
basis on which the ISO manages ancillary services. The design of the common
quality arrangements typically includes the following considerations:
 only aspects of quality that are truly common should be included
(parties should be free to agree requirements for other aspects of
quality bilaterally where feasible);
 common quality performance objectives for the System Operator
should be specified at a high level to provide scope for innovation in
planning and practice;
 market arrangements should be preferred to mandating technical
requirements on asset owners. When technical performance
requirements are mandated, these should be limited to minimising
overall costs;
 how the System Operator sets out and communicates the means by
which it intends to plan for and achieve the objectives and an
assessment of ancillary services requirements including a plan for how
the ancillary services will be provided and/or procured.; and
 how the costs of ancillary services will be met and recovered from the
market.
The SA Grid Code might continue to provide the basis for these standards.
However, as new participants enter the market, what might have been
‘common’ objectives may become segmented in line with individual interest of
various parties. To the degree this occurs, we would anticipate far greater
focus by market participants on rule change in the form of submissions to the
GCAC.
3.2.3 Transmission system operation and implications for market participants
Where the ISO is separate to the Transmission System Operator (TSO) the
responsibility for provision of transmission network capacity and its availability
is likely to be allocated to the TSO. At times of system constraints there may
be a tension between the need to meet demand versus increasing loading on
network assets. These types of tensions can materialize at times of planned
outages on the transmission network when generation is also withdrawn from
the market at short notice giving rise to supply and system constraints.
 In effect the TSO can become the ‘supplier of last resort’ in the sense
that it might be expected to stand-down planned maintenance or run
on temporary overload if generator outages occurred. Clarity is
required regarding how these arrangements would be managed as it is
possible that even for relatively small IPP generation facilities localised
outages could (adversely) effect transmission operations.

13
An argument for maintaining a combined SO/TSO is that coordination can be
improved between the system operation role and transmission asset
management.
 Alternatively, if assuming the TSO and the dominant generator are in
one entity it is conceivable that second-tier generators (i.e. IPPs) will
consider this a potentially discriminatory arrangement to the degree
that transmission outages might be managed so as to minimise the
impact on the combined generation/transmission entity. In such cases
the governance and dispute process pertaining to the ISO and its role
in coordination of outages will become increasingly important.
We understand that the Grid Code sets out rules and protocols pertaining to
transmission capacity and constraints. However (and without prejudice) the
types of matters illustrated here may lead to pressure to further codify existing
rules and could motivate closer examination of Grid Code compliance
(especially where new market participants might have a special interest).

14
4 Power trading management
4.1 Power trading management requirements
Power trading arrangements include arrangements for purchasing and on-
selling energy, capacity and ancillary services. The trading arrangements
define the form of the ‘market’ and we use this term generally to cover all forms
of arrangements for the purchase, sale or settlement of power or other
services. For the purpose of this review, we have assumed that there will
remain a combined ISO/IMO that is responsible for certain aspects of market
settlements at the wholesale level. 6
Central buyer or wholesaler responsibilities present another component of
trading arrangements and this may or may not involve the ISO/IMO itself.7
Our
working assumption is that that the ISO/IMO would also have some level of
responsibility for purchase and sale of power. What we refer to generally as a
“Central Buyer / IPP Administrator” would cover a spectrum of models perhaps
ranging from a:
 Single Buyer – where literally applied provides a statutory monopoly
on the purchase and sale of power.
 Central Buyer – that might have significant power procurement
responsibilities but not a complete monopoly in regard to power
purchase and on-sale.
 Market aggregator or wholesaler – 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:
o 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
o responsibility for procurement of new power purchases, also
with or without direct financial ownership of PPAs.
In addition to purchase of power, the ISO needs to dispatch ancillary services
which include frequency control, voltage support and instantaneous reserves
(in the form of spinning generation reserves and/or instantaneous load
shedding) and these services need to be purchased, and costs recovered.
This may be through service level agreements with the incumbent
generation/transmission entity, or through market based approaches that can
include tenders for services and/or periodic auctions.
6
At one end of the spectrum may be a gross pool in which the IMO accepts bids and offers, dispatches (through
the ISO function) and settles (through the IMO function) on this basis. In a net pool the IMO acts to balance the
energy market net of bilateral contract arrangements, dispatching generators to meet their (notified) obligations
and dispatching balancing generation only based on dispatch rules. Such pools may be ‘energy only’ or they
may involve separate capacity and energy trading arrangements.
7
While we have made the working assumption that buyer or wholesaler responsibilities would be placed into the
South African ISO, one can find counter-examples where these roles are held by separate entities.

15
4.2 Key issues
In setting out what we see as key issues going forward pertaining to the ISO
power trading responsibilities we wish to note that this matter is still to be
determined. However, there are some broad issues we would like to highlight
within the context of our preliminary scoping of issues.
4.2.1 Financial viability of the ISO
 If the ISO acts as Buyer it may have significant financial exposures as
counterparty to power purchase agreements (PPAs) and on-sale
arrangements The Buyer will usually have significant capital at risk and
will likely need to satisfy prudential requirements in the purchase and
sale of power. In such cases substantive reserve accounts and probably
some form of government guarantee may need to be provided for to fill
this role.
 Alternatively, the more limited role of IPP trader – or perhaps only
contract administrator is likely to carry significantly less financial risk and
thereby require far less stringent prudential requirements and a vastly
simplified system of governance and controls put into place
commensurate with this risk profile.
 In any case, it is typical for the ISO to procure Ancillary Services. As
discussed elsewhere in this review, working capital needs for this
component alone will be substantial and suitable prudential standards
and guarantees of payment to AS providers may need to be put into
place.
4.2.2 Incentives for efficient procurement of energy and ancillary services
With the significant financial risk exposure that such power trading functions
might entail for the joint ISO / Buyer, it is anticipated that a model would be
implemented that places the most significant of these risks back with major
market participants (e.g. through back-to-back vesting contracts if a
wholesaler, or the ISO taking a more minimalistic contract administrator type
role).
At a very broad level of thinking this might entail a full pass through of costs
for the ISO (which is the typical model for a standalone ISO). In this case ISO
incentives for efficient procurement of energy and ancillary services will
become important.
 For energy purchases from IPPs, presumably competitive tendering
processes will be applied and purchase price assessed against internal
and external benchmarks.
 For ancillary services the market is likely to be rather centralized
(perhaps within Eskom as the major provider or generation specific
services for some time still). Ober he medium term we would expect to
see more decentralized supply of ancillary services.

16
5 Power system planning and investment
5.1 System adequacy and planning
System adequacy is vital to the success of an electricity market. Central to
achieving this is the management of supply / demand margins and providing
information on the level of investment in new infrastructure (generation and
transmission) to meet forecast demand. The ISO will typically maintain a
significant level responsibility in this area due to the information base that it
holds. It may involve the following functions:
 Establishing and/or administering the acceptable level of planning
margin, based on analysis of forecast load and its variation;
 Playing a key role in developing long term load forecasts, monitoring
generation and transmission developments and providing information
to inform investors in new generation plants. This can take the form of
reports on anticipated generation adequacy and reports such as a
“Statement of Opportunities” (SOO) for generation development,
transmission reinforcement or load development. The SOO would
describe opportunities on a locational basis and also address
interdependencies between projects.
 Develop and/or administer emergency and contingency planning with
regard to system stability, forced outages, supply restoration, and
disaster management. Similarly protocols for addressing financial
impacts related to such use of emergency powers need to be in place
so as to define and perhaps indemnify the ISO from claims stemming
from its administration of such powers.
There are a number of alternative approaches to the ISO’s role with regard
to system adequacy and planning that would go far beyond provision of
information and protocols outlined above.
We note that within the context of South African ESI this is largely a matter
for government to decide by way of legislation, and that many of these
issues are addressed in the Grid Code. With this in mind we briefly
summarise our understanding of the situation as it currently exists, and
potential implications for establishment of the ISO going forward.
5.2 The current situation for energy planning and investment
5.2.1 New generation planning and investment
Under South Africa legislation energy planning (or more specifically, Integrated
Resource Planning) is administered by the System Operator, in consultation
with the Department of Energy and NERSA – and subject to approval by the
Minister.8
The planning role pertaining to the System Operator in developing
the integrated resource plan includes:
8
Department Of Energy Electricity Regulation Act, Electricity Regulations On New Generation Capacity

17
 adoption of the planning assumptions;
 determination of the electricity load forecast;
 modelling and scenario planning based on the planning assumptions;
 determination of a base plan derived from a least cost generation
investment requirement;
 risk adjustment of the base plan, which shall be based on:
o the most probable scenarios; and
o government policy objectives for a diverse generation mix, including
renewable and alternative energies, demand side management and
energy efficiency.
Having regard to the need for new generation capacity in the integrated
resource plan, the system operator shall undertake a feasibility study to
determine whether procurement of the generation capacity should be
undertaken by Eskom as part of its services as the national electricity producer,
another utility provider or an IPP. The matter is then to be considered by the
Minster for Finance and Minister (for Energy).
If approved, the regulator may impose a licence condition on the buyer to buy
all the new generation capacity procured by the system operator in accordance
with the approved integrated resource plan.
5.2.2 Transmission planning and investment
The Grid Code requires the National Transmission Company (NTC) to annually
publish a five year ahead Transmission System development plan indicating
the major capital investments planned (but not yet necessarily approved). The
plan is to include:
 the acquisition of servitudes for strategic purposes
 a list of planned investments including costs
 diagrams displaying the planned changes to the TS
 an indication of the impact on customers in terms of service quality and
cost
 any other information as specified by the NERSA from time to time.
Before any development of the network proceeds, the NTC is to compile a
detailed development investigation report. The NTC shall invest in the
transmission system when the required development meets the technical and
investment criteria specified in the Grid Code, or if the investment is in
response to a customer request for transmission service and the cost is
recoverable from the customer or group of customers concerned in
accordance with the NERSA approved connection charges guidelines.

18
5.3 Key issues
It is often viewed that the primary role of the ISO is clearly defined as real time
coordination of supply and demand so that it is not seen as having
responsibility for the availability of and investment in generation and
transmission assets. This same view would place a responsibility of the ISO
to signal potential supply constraints and capacity shortfalls but the ISO would
not be held accountable for making assets available.
 In many markets there is a tension between the desire for central
control and diversified market led decision making. It is important that
the role of the ISO (or any other body) is clear in this regard.
 If there is to be a strong central planning role, then this role must be
clearly prescribed. However, if generation investment is to be market-
led, then it is counter-productive to have a central party also being “held
responsible” since this default role is likely to undermine commercial
investment opportunities.
We further note that to the degree that transmission planning largely remains
with the transmission operator, there will need to be a strong focus on
coordination between generation and transmission planning process if they are
administered per the existing Grid Code (i.e. generation planning administered
by the SO, and transmission planning by the NTC).
A related issue for the ISO is that in a more competitive environment it will be
necessary to ensure that there are appropriate confidentiality provisions with
regards to information provided to the ISO, whilst still ensuring that the
information (once aggregated) can be used by the ISO to fulfil its planning and
reporting role.

19
6 Market administration and development
As noted previously, we use the term ‘market’ to cover the suite of system
administrative, operating arrangements and trading arrangements. While
there is some overlap between these functions and what we have covered in
previous sections, we wish to highlight in this section the ongoing evolution of
such arrangements; the role of the ISO; and to motivate implications for market
participants.
6.1 Market administration functions
A range of market administrative functions may move to the ISO. These
include:
 Administering market metrology and providing wholesale energy
reconciliation services;
 Administering aspects of connection and access to the system;
 Managing disputes that relate to ISO functions;
 Reporting on ISO performance (against the strategic objectives, such
as common quality objectives);
 Compliance monitoring and compliance reporting with regard to other
parties (for example reporting failure to follow dispatch instructions).
 Contingency plans (and perhaps market suspension) in the case of a
default, or in the case of failure, of some aspect of the market trading
arrangements.
Most of these functions are allocated to various segments of the
interconnected power system under the current Grid Code, and we have made
the working assumption that this would form the basis for the future structure
of the ISO – although we note that we have not been given guidance on this
matter and our preliminary analysis is subject to change if this assumption
proves to be wrong. We provide a brief overview of each matter below.
6.1.1 Metrology and reconciliation
The Metering Code specifies transmission tariff and energy trading metering
requirements and clarifies responsibility in terms of metering installations. The
Code is applicable to:
 main metering installations and check metering installations used for
the measurement of active and reactive energy
 the collection of metering data
 the provision, installation and maintenance of metering equipment
 the accuracy of equipment used in the process of electricity metering
 testing procedures for metering installations
 storage requirements for metering data, and

20
 competencies and standards of performance of participants.
Broadly speaking, the NTC is responsible for administration and oversight of
these matters.9
Metering data for use in energy trading and billing is
confidential information and shall be treated in accordance with the Information
Exchange Code, section 6. This will become of greater importance with the
addition of IPPs so as to provide ensure that their metering information is not
shared with utility generation.
6.1.2 Connection management
Connection may be managed in large part by the transmission and distribution
network entities (applying transparent connection rules and processes).
However the ISO must have the ability to manage and dispatch generators and
large loads (in its Power System Operations role) once connected, and
therefore must have some role in authorising connection. In its Power Trading
Management role, the ISO may also have certain prudential requirements to
be established before connection is authorised. Many if not all of these matters
are likely covered in the Grid Code, but is possible that additional attention will
need to be given to the ring fence between transmission and generation so as
to ensure non-discriminatory access to the interconnected power system by
IPPs.
6.1.3 Dispute management
The Grid Code provides a process for dispute management and we anticipate
this providing a strong basis for the new ISO structure. Indeed, the ISO should
enhance the impartial process for administering disputes.
However, with the advent of new market participants we anticipate a range of
formal complaints that the ISO may either be best placed to consider; or in
other cases may have taken actions that are the subject of a complaint by
market participants
In light of the above, we would anticipate the need for additional codification of
the areas in which the ISO is to have responsibility vis-à-vis the regulator, and
in particular, how commercial disputes are to be handled (e.g. the ISO would
not typically be seen as well placed to address disputes of a purely commercial
nature).
6.1.4 ISO performance reporting
The independence of the ISO can also prove itself through the separation of
strategic performance setting from market operations. In this regard it is
important that clear performance targets are set under governance
arrangements, and that the ISO is established with the tools and processes to
be able to accurately report against these targets.
We observe in some markets concerns expressed by some generators at
certain decisions taken by the System Operator. It is vital that the ISO is able
to demonstrate its independence by having clear and transparent procedures
and by being able to demonstrate that it has followed these procedures (or to
9
Please see the Metering Code for a formal description of responsibilities in this regard.

21
disclose where it has not). In this regard it is normal to have an ongoing ISO
procedures audit process in place.
6.1.5 Compliance monitoring and reporting
In many jurisdictions the system operator plays an important role in monitoring
and reporting on market participants’ performance and compliance with
various protocols (such as the Grid Code). Under the current Grid Code, the
System Operator has a number of responsibilities in regard to compliance
monitoring and reporting – with ultimate responsibility for oversight with
NERSA.
We would anticipate the ISO to retain (and perhaps have added to) its
responsibilities for compliance monitoring and reporting as this is a natural
function for an independent entity with the type of expertise and information
the ISO would have. Again, the Grid Code sets out the broad governance
process that would pertain to compliance based issues, but we would
anticipate the need for further codification of the full scope and role of the ISO
in this regard as the market develops.
As an example of what we have in mind here, there are probably cases where
the current ‘internalised’ structure of the industry has allowed for prudent use
of rather more informal arrangements in regard to compliance based issues.
Alternatively, establishment of an ISO may lead to a more literal and proactive
approach in compliance monitoring and reporting by that entity. This would
likely have implications for areas that are currently perhaps not fully aligned to
strict interpretation of compliance with conditions of licence and related codes
and rules.
6.2 Market development functions
6.2.1 Rule changes
Some aspects of the market – such as legislative empowerment and Rules,
will be outside of the ISO and it will need to be ensured that a suitable arms-
length body has responsibility for this (see under Governance). On the other
hand it is important that the ISO has input to any rules change or legislative
change processes, primarily to ensure that the changes are workable and in
line with defined overall objectives.
The current Grid Code sets out the process for rule change which can have
important implications for individual market participants and the industry more
generally. Our working assumption is that the ISO will play a broadly similar
role as compared to the current situation – including its role as Grid Code
Secretariat and membership to the GCAC.
As we have noted elsewhere in this review, it is anticipated that a range of
matters set out in the Grid Code or related rules will be increasingly be taken
to the GCAC (i.e. submission for rule change). Moreover, establishment of an
ISO may lead it to take a more proactive role in regard to market development
and associated rule changes that that may entail.

22
6.2.2 IT, business process and communications
Establishing the ISO will externalise a lot of business processes that are
currently internal to the incumbent utility. Depending whether the ISO adopts
new systems or contracts for use of legacy systems in the incumbent utility,
there may be a need for new interfaces and new communications channels.
In either case, other parties (such as IPPs and independent suppliers) will
expect to be able to interface with the ISO on the same terms as the incumbent
utility. There will be an expectation that the ISO will develop and publish a
range of procedures, plus IT interface standards and communications
protocols, for use by the industry.
This is a significant set of tasks. Some prioritisation is important: it is probably
not necessary, and may be unnecessarily risky, to cut over all processes and
systems simultaneously. However certain processes and systems will need to
be available for ISO start up and it is essential that they are appropriately tested
before go-live. A clear transition plan is required. Input will be required from
parties outside the ISO and a steering group/working group structure is likely
to be required. Following start up, these groups would likely continue to
monitor the workability of processes and procedures and to progressively
develop and adapt them.

23
7 ISO Corporate functions
7.1 Corporate functional requirements
Establishment of an ISO will require that the complete range of corporate
support in administration, operation and governance of the entity is put into
place. This is a substantive matter in its own right, and a complete scoping of
this important issue would probably be better undertaken once government
policy on the ISO (i.e. the ISO model) is fully set forward.
However, three broad areas of corporate functions we would like to highlight
at this preliminary stage of work - and unique to transition from the current state
to an ISO are:
 Budget, funding of costs, and revenue source
 Corporate operational requirements
 HR
We provide some initial comments on these matters below.
7.2 Budget and revenue source
7.2.1 Budget
A sufficient budget and funding mechanism will need to be put into place to
establish the ISO and to maintain on an ongoing basis its operational and
financial viability.
Fixed assets - We assume that where feasible fixed assets would be
transferred to the ISO with arrangements for remuneration to be decided.
Depending on the commercial structure of the ISO (e.g. not-for-profit) an
establishment budget would typically be provided for once-off costs. These
‘establishment fees’ might be ring fenced from a regulatory accounting
perspective and charges allocated to market participants accordingly.
Operating expenses - Core system operating expenses are manpower; IT
and systems; and energy services (e.g. ancillary services). There will be both
establishment and ongoing costs related to people, IT and systems that are
fundamental to the operation of the ISO. We discuss some related issues
pertaining to transfer of people and systems in sections below.
Purchase of ancillary services - Energy services represents a significant
financial exposure to the ISO. For a stand alone entity it will represent a
significant need for working capital. Moreover, ISOs are often ‘not-for-profit’
entities, and as such, have no retained earnings to draw from or fixed assets
(i.e. balance sheet) in which to borrow against.
Wholesale trading functions – If wholesale and/or buyer responsibilities are
placed with the ISO it will require a significantly greater level of financing and
control of associated risks.

24
As an illustration of what we have in mind, as a wholesaler in power purchases
and sales the ISO will have to be provided working capital sufficient to cover
variability between power purchases and sales taking account of daily, weekly,
monthly and annual variability, as well as counterparty risk of delay or default
on payments. Similarly, power suppliers would likely need counterparty
guarantees and/or explicit government guarantees for power that might be sold
to the wholesaler.
Depending on the extent of energy services that the ISO is responsible for,
prudential requirements will need to be established, and a funding structure for
the ISO established in order to meet such requirements. This is a considerable
issue in its own right, and we would advise thorough consideration is given to
this matter as the intended wholesale trading / buyer model becomes further
defined.
7.2.2 Funding and revenue source
ISO costs are typically drawn from market participants reflecting the nature of
the services provided by the ISO and often on a ‘causer pays’ basis (to the
degree cost causality can be established). Depending on the form of ownership
and governance, fees might be decided by market participants; or regulated
under similar governance processes as for the transmission network charges.
Our working assumption at this stage is that ISO fees would be regulated by
NERSA. However, there are unique aspects to consider in design of regulatory
approaches for revenue allowances for an unbundled ISO in that:
 Standard regulatory approaches often applied to asset intensive
network businesses (i.e. utilising rather fixed revenue allowances) are
not ideally applied to an ISO. A stand alone ISO does not typically have
a large fixed asset base (i.e. RAB). Following from this point, the
balance sheet of an ISO might not be substantial, although its financial
risk will often be considerable. As discussed in section 5 of this review,
a reserve account, frequent periodic adjustments, and other such
features might be needed to address working capital and prudential
requirements. This would become considerably more important if
wholesaler / buyer responsibilities are 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 combined system operator
/ transmission business.
We have provided examples of how funding and revenue sources are
accounted for in other jurisdictions in the Annexure (sections 9.1; 9.2; and 9.5)
to this review.
7.3 Corporate operational requirements
As noted above, establishment of an ISO will require that the complete range
of corporate support would need to be provided for. For the purpose of this

25
initial scoping of issues we would highlight several key aspects of corporate
operations that will need to be considered in establishment of the ISO:
 Financial reporting and controls
 Transfer of IT/systems licences
 Service level agreements and transfer pricing
7.3.1 Financial reporting, data systems, and controls
The operations of an ISO will be determined by the structure and complexity
of the market in which it operates. Complex open access markets with security
constrained economic dispatch (such as PJM, New England and New
Zealand) require sophisticated financial reporting and controls to provide real
time settlements and data for numerous market participants. However,
managed connection arrangements with a central buyer approach, place a
lower level of real-time management requirements on the ISO.
 Whatever market structure is adopted, reliable and secure data
communications systems between participants (generators and loads)
and the ISO are of paramount importance for maintaining the integrity
of system performance and financial settlement.
7.3.2 Transfer of IT/systems licenses
Operational tools that are used by system operators include systems such as:
 Demand forecasting systems
 Scheduling and dispatch systems
 Communications management systems (for dispatch control, generator
response etc.)
 Reserves management systems
 Market pricing systems (in power pools where dispatch is based on
offers)
 Commercial arrangements may need to be made for transfer of existing
licences to a new entity. At this stage we do not see any
unsurmountable problems in this regard, but do caution that such
transfers can in some cases be costly depending on the nature of
existing contracts and resources needed to transferred.
7.3.3 Service level agreements and transfer pricing
There are a number of significant service level agreements and transfer pricing
arrangements that would need to be either transferred or codified in moving
from legacy agreements to the ISO.
 Ancillary services - On establishment of an ISO (and assuming that
the ISO is responsible for procurement of ancillary services) all transfer
pricing arrangements will need to be undertaken within standard
commercial arrangements. Moreover, it is likely that relevant process
and contracts would need to be provided to market participants, and as

26
independent sources of ancillary services enter the market, additional
competitive processes may need to be employed in procurement of
these services.
 Energy payments and charges – To the degree that the ISO is a
financial intermediary between generators and off-takers, complete
contracts will need to be established between parties. There is a range
of approaches that can be taken, such as a relatively simple bulk pricing
arrangement, through to real time cost reflective pricing. However,
even for the relatively simple bulk pricing arrangements quantity risk
(e.g. MWhs bought and sold) might be substantive and the ISO would
need to be provided with some form of hedge arrangement for both
prices and quantities.
As an example of the type of arrangements that might be considered,
one option is to arrange vesting contracts to apply from the outset
between generators and off-takers. As for example applied in Western
Australia, contracts could start as being for “all requirements”; in other
words passing demand risk back to the generator. The vesting
contracts would then wind back over a period of time and are replaced
by negotiated contracts, which may have a different risk profile.
While the broad principles of the arrangements outlines above might not
necessarily change significantly in establishment of an ISO, there would be
considerable work ahead in fully codifying them – particularly having in mind
that change of agreements in the future would be between commercially
sperate parties. In our experience development of such contracts in
restructuring can prove to be very difficult, and we are aware of situations in
other jurisdictions where significant transactions of the type noted above have
been undertaken between separate parties without contracts for a
considerable period of time – certainly not an ideal situation.
7.4 HR issues
We anticipate that there will be new HR issues arising from establishment of
an ISO. Two key aspects of this are set out below:
7.4.1 HR
To the degree that the ISO is set up as an entity fully separate from Eskom
Holdings (e.g. perhaps as a public enterprise or other government entity) we
would anticipate transfer of personnel to the new entity.
 Thorough consideration will need to be given on how to best retain the
skill base needed for the specialised activity of the ISO, and transfer of
employee entitlements that might be applied to ensure a seamless
transfer of staff.
 The specific corporate structure under which the ISO is established will
in many cases dictate the range of terms and conditions of employment
that may be provided to personnel. For example, a public enterprise or
similar entity established under the PFMA might have relatively greater

27
flexibility in regard to certain conditions of employment than as
compared to an office embedded within department of government.
Both of these related matters will be crucial in the establishment of the ISO so
as to retain the skill base needed in delivery of this crucial part of the electricity
supply chain.
7.4.2 Skills development
The final model chosen for the ISO will also have implications pertaining to
skills development and retention.
 For the more traditional aspects of the SO, retention of existing skills
might be the primary focus.
 However, to the degree that the ISO is given substantive power
wholesaling/trading responsibilities – new skills may have to be
developed and two rather different skill bases will need to be retained in
the ISO going forward.

28
8 Selected international examples
In the annexure below we have aimed to highlight various issues pertaining to
the establishment and operation of an ISO by way of providing selected
international examples and case studies.
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
ISO and Power Purchase Administrator as they can shed some light on
linkages between the various functions and models providing a more
integrated view to the matters at hand.
8.1 California ISO10
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
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).
8.1.1 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
10
Sourced from CAISO annual report 2008

29
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

30
8.2 Australia - AEMO11
The Australian Energy Market Operator (AEMO) was established to manage
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.
8.2.1 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
11
AEMO, An Introduction to Australia’s National Electricity Market, 2009.

31
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
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.
8.2.2 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

32
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.
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.
8.2.3 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;

33
 a depreciation charge recovering capital expenditures;
 a charge for finance costs of borrowings; and
 amortisation of establishment costs
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.12
12
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.

34
8.3 Mexico single buyer model 13
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
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).
8.3.1 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.
8.3.2 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
13
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.

35
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);
 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.
8.3.3 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

36
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).
Source: CFE
8.3.4 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

37
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.

38
8.4 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.
8.4.1 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

39
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).

40
8.5 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.
8.5.1 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
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.14
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:
14
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

41
 “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
(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

42
(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
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.
_________________________________________________________________

43
8.6 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
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:15
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)
15
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

44
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
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:

45
 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
(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)

46
The Committee on Energy Policy Administration (CEPA)
Members:
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

47
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
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.

Trans African Energy Pty - Establishment of an Independent Sytem Operator

Trans African Energy Pty - Establishment of an Independent Sytem Operator

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Viewers also liked

Viewers also liked (20)

Similar to Trans African Energy Pty - Establishment of an Independent Sytem Operator

Similar to Trans African Energy Pty - Establishment of an Independent Sytem Operator (20)

More from Stephen Labson

More from Stephen Labson (17)

Recently uploaded

Recently uploaded (20)

Trans African Energy Pty - Establishment of an Independent Sytem Operator