Trans African Energy Pty - Establishment of an Independent Sytem Operator

TRANS AFRICAN ENERGY

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Independent System Operator Key issues to address in establishment of an ISO in South Africa

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Contact: Dr Stephen Labson Email: [email protected]

Trans African Energy Pty

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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


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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


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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.


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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


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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.


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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


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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.


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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


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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:


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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.


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ISO operational performance will be monitered and ertain indemnities

may need to be provided to the ISO with regard to operational

performance and liabilities.


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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


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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.


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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.


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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).


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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.


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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.


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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


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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.


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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.


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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.


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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.


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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


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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

ElectriPolicy 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.


48

Thailand Power Development Plan16

The Power Development Plan is a detailed planning guide setting out

Thailand’s medium term power needs in terms of factors such as reliability of

power supply, fuel sources and diversification, generation technology types,

power purchases, transmission expansion, etc. The current PDP covers the

period 2008-2021.

- EGAT formulates the PDP under the policy framework of the Ministry of

Energy.

- The PDP is to be approved by the National Energy Policy Council (NEPC).

- The PDP is to be endorsed by Cabinet.

The PDP is an important document as it sets out the intended split of

generation projects in terms of:

- EGAT power plant projects

- IPP power purchase projects

- Renewables

- SPP power purchase projects

- VSPP power purchase projects

- Imports from cross-border power projects

The PDP also sets out transmission expansion projects fpor the planing period

aligned with the generation plan.

Energy Regulatory Commission (ERC)

Formerly, the government, through the National Energy Policy Council, would

both determine energy policy and regulate the operation of the energy industry.

Since 11 December 2007, Thailand's Energy Industry Act, B.E. 2550 (2007),

has come into force. Under the Act, the Energy Regulatory Commission (ERC)

was appointed on 1 February 2008 to regulate the electricity and natural gas

industry under the policy framework of the government, with the establishment

of the Office of the Energy Regulatory Commission (or OERC) to function as

the Secretariat to the ERC. Therefore, since February 2008, the energy

industry regulatory function has been transferred from the NEPC to the ERC.

Major Authority and Duties of the ERC:

To regulate the energy industry operation to be transparent and

standardized so as to protect the benefits of energy consumers, and to

ensure its compliance with the objectives of the Energy Industry Act

and the policy framework of the government;

To establish a license issuance process, including issuance of

announcement on the categories of licenses for energy industry

operation and recommendation of issuance of a royal decree specifying 16 See EGAT Thailand Power Development Plan 2008-2021, revision 2. May 2009 (EGAT web cite)


49

categories, capacities and characteristics of energy business that are

exempted from a license requirement;

To determine measures enhancing security and reliability of the power

system;

To establish regulations and criteria regarding power supply and issue

requests for proposal for power purchase, and ensure that the selection

procedures are fair for all parties concerned; and

To provide comments to the Minister of Energy regarding the Power

Development Plan, plans for investment in the power sector, natural

gas procurement plan and plans for energy network system expansion.


50

8.7 Mexico Works & Investment Program of the Electric Sector

The broad structure of energy planning and investment are:

Comisión Federal de Electricidad: It prepares energy demand studies, it

prepares its electrical prospective, it formulates the program for works and

investment of the electric sector, prepares feasibility studies of each plant,

discloses and develops project bids, supervises work execution, carries out

negotiations with inhabitants and owners of the regions affected by projects.

Ministry of Finance: It analyzes and approves of the budgets prepared by the

Comisión Federal de Electricidad and it assesses the expense execution and

the compliance of goals and objectives of projects.

Ministry of Energy: It participates in the Coordination, Planning, program

authorization, budget execution and project bidding, and it tracks the

construction of Power Plants.

8.7.1 Works & Investment Program of the Electric Sector

Mexico’s dominant state-owned utility Comisión Federal de Electricidad (CFE)

platys a substantial role in planning the National Electric System. CFE produce

annually the “Works & Investment Program of the Electric Sector” with a 10

year horizon (the spanish acronym is POISE). POISE defines a detailed

physical and financial investment program updated yearly for the next 10-year

period. It is prepared including the necessary infrastructure projects to meet

the demand for the planning period. The Work and Investment Program

prepared by the CFE is subject to the consideration and authorization of the

Ministry of Energy.

Important areas covered in the POISE for the planning period include:

Demand growth forecast

Overall generating capacity needed

Required investments by source of funding (i.e. CFE or IPP).

Generation types and technologies

Fuel sources

Specific project cites

Anticipated tender dates (IPPs and/or construction of CFE projects)

Gas pipeline investments (per fuel supply requirements)

Transmission and distribution upgrades and expansion

***End of document***

Economy & Finance

Trans African Energy Pty - Establishment of an Independent Sytem Operator