Acknowledgement
This research work would never have been undertaken without the initial suggestion and
intellectual support of the former Vice-Chancellor of the University of the West Indies
Professor; Rex Nettleford, who was every dear friend. I also wish to acknowledge the
contributions of Professor Martin Cave from the University of Warwick and LSE and
Michael Webb of Frontiers Economic, London both of whom commented on the initial
papers and suggested ideas and improvements.
I am also particularly indebted to Janet Mwaippo, my Tanzania Secretary, who had the
tedious task of typing from the manuscript and also having to make endless corrections; to
Sandra Griffiths who had the task of finally formatting the document and also to my wife
Faye, who in addition to having to endure many lonely evenings, also had to undertake the
burden of reading and editing the entire typescript. Her suggestions, especially from the
point of her legal knowledge have helped to improve the presentation. Without the
motivation and intellectual support of Vice-Chancellor Professor Rex Nettleford this work
would not have been completed. Finally, to my supervisor Professor Edwin Jones, whose
guidance and advice on a range of issues and comments on the draft chapters, contributed
immensely to the final document.
i
Table of Contents
Page
ACKNOWLEDGEMENT
i
TABLE OF CONTENT S
ii
GLOSSARY
vii
LIST OF TABLES (with page Numbers)
xvi
LIST OF FIGURES (with page Numbers)
xviii
TEXT OF THESIS
Chapter One
Restructuring For Competition in Electricity Markets
Introduction
1
The Economics of Electric Utility
2
Restructuring the Electricity Industry
8
The Impact of New Technologies on Scale Economics
9
Rise of Competition in Bulk Electricity Markets
12
Public Ownership VS Private Ownership
15
The Case for Private Ownership of Electricity
19
The Effects of Regulation
21
Vertical and Horizontal Restructuring
23
Electricity Industry Structural Models
26
The Wholesale Bulk Electricity Markets
31
Conclusion
34
End Notes
36
ii
Chapter Two
A Four Phase Development Model for Electricity Markets
The Four Phase Development Model
44
Model One Stage: Franchised Monopoly Phase
47
Move Away From the Franchised Monopoly Phase
52
Model Two Stage: The Purchasing Agent Phase
55
Model Three: Bulk Electricity Market Phase
66
Bulk Electricity Market Design Options
73
Governance Structures of Power Pools and Exchange Markets
76
Model Four: Retail Competition or Consumer Choice Phase
78
Competitive Transformation of the Electric Utility Industry
86
Selection of Case Countries
93
End Notes
94
Chapter Three
A Formula For Radical Reform: The British Electricity Experiment
Introduction
99
1980s Political and Economic Thinking on Electricity Privatisation
103
The Pre-Privatisation Structure
108
Restructuring the England and Wales Electricity System
116
Privatisation Programme
122
Post-Privatisation Changes to the Industry Structure
125
The Scottish and Northern Ireland Electricity Reform
138
Bulk Electricity Market - The Pool
144
Critique and Changes to the Pool after 2000
152
End Notes
157
iii
Chapter Four
British Electric Utility Regulatory Reform
The Case Against Rate of Return Regulation
161
British Approach to Utility Regulation
164
RPI- X Regulation
169
Rationale for Excluding Generation From Regulation
171
Transmission Price Regulation
172
Distribution Price Regulation
176
Regulating the Competitive Transformation of the Retail Market
179
Changes to UK Regulation
183
The Verdict
186
End Notes
192
Chapter Five
Ownership, Deregulation and Privatisation of Electric Utility;
The Jamaican Case
The Early Years
196
Private Franchised Monopoly and the Failure of Public Utility Commission Style
199
Regulation
State Ownership and Government Failure
202
Industry Structure and Deregulation of Generation
206
Problems with the Introduction of the Single Purchaser Model
209
The Case for Unbundling the Utility
211
Aborted Privatisation
218
Public Ownership with Internal Management Performance Contract
222
The Final Act of Privatisation
230
Summary and Conclusion
234
End Notes
240
iv
Chapter Six
Radical Restructuring and Privatisation of a Small Electric Utility Market:
The Case of Bolivia
Introduction
243
The Structure of the Industry Before Unbundling
248
The Restructuring Programme
251
The Divestiture Programme
253
Bolivia Bulk Wholesale Electricity Market
259
The Regulatory Framework
263
Regulation of Transmission
264
Regulation of Distribution Prices
266
Outcome
268
Lessons Learnt
273
End Notes
276
Chapter Seven
Sub-Saharan Africa Electricity Reforms:
Three Country Case Studies
Macro-economic and Market Background
279
Rationale for Public Ownership of Electric Utility
284
Financial, Economic and Technical Performances
285
Institutional, Managerial and Regulatory Failures
287
The Role of Donor Agencies
289
The Challenge of attracting Foreign Direct Investment
290
Cote d’Ivorie Reforms
295
The Reforms in Ghana
300
The Tanzanian Power Sector Reforms
304
Regional Interconnection Opportunities
309
Conclusion and Policy Implications
310
End Notes
314
v
Chapter Eight
Analysis and Conclusion
Global Trends In Electricity Sector Reforms
317
Structural Options
317
Purchasing Agent as a Reform Option
319
Bulk Electricity Market as a Reform Option
321
The Main Sub-options Under Bulk Electricity Markets
323
Retail Competition as a Reform Option
325
Main Lessons Learnt
327
The Rise of the Regulatory State
329
Conclusions
330
End Notes
333
BIBLIOGRAPHY
335
vi
Glossary
AGR
Advanced gas cooled reactors
ATC
Available transmission capacity
Averch – Johnson
Effect
Phenomenon under ROR regulation whereby regulated
firms have incentive to over-invest in capital intensive
solutions relative to other inputs as this increases the rate
base and hence regulated returns; lead to “gold planning”
over investment
AES
Allied Energy Systems Americas Inc.
Affermage Contract
An exclusive operating lease where the lessor takes
responsibility for capital investment and the lessee
operating costs and operating risks originated in
francophone countries
ABB
Asea Brown Boveri
ADB
African Development Bank
ANARE
I’Autorite Nationale de Regulation du Secteur de
I’Electricite
BOOT
Build Own Operate and Transfer
BOT
Build Operate and Transfer
BPC
Bulk power contract; contract for energy with power taken
at any point in the system
Base load
The lowest load continuously supplied by electric power
system over a period of time
BNEL
British Nuclear Fuels Plc
By-pass
Right of certain category of customers to purchase directly
from producers (generators) or the market, requires equal
access to the network
BST
Bulk supply contract
BEA
British Electricity Authority
CCGT
Combined cycle gas turbine
vii
CCGG
Combined cycle gas generation
CEGB
Central Electricity Generating Board
CfD
Contracts for Difference
CRI
Centre for the Study of Regulated Industries
Capacity payments
Payments covering the fixed or capital cost of a generating
plants capacity, cost is sunk costs.
Competition for market Form of competition involving two or more firms
competing for the right to supply a monopolistic market
Competition in the
market
Product market competition, rivalry between two or more
firms to meet customers demands
CPI
Consumer Price Index
Constrained-on
Generation set which despite their output being offered at
a price in excess of SMP are called on by the transmission
operator to operate as a result of limitations on the
transmission system, demand forecasting errors or
breakdown of other generation sets.
Constrained-off
Generation set which despite their output being offered at
a price equal to or lower than SMP are instructed by the
TO to operate as a result of limitations on the
transmission system, demand forecasting errors or
breakdown of generation sets.
COBEE
Compania Boliviana de Energia
COM IBOL
Corporacion Minera de Bolivia
CESSA
Compania Electrica Sucre S.A
CRE
Cooperativa Rural de Electricidad
CNDC
Commitee National de Despatcho de Cargo
CDC
Commonwealth Development Corporation
CIE
Compagnie Ivoirienne d’Electricite
CIPREL
Compagnic Ivoiriene d’Production de Electricite
CRI
Centre for the Study of Regulated Industries
viii
DGES
Director General of Electricity Supply
DGFT
Director General of Fair Trading
Dispatch
Issue of instruction to release generated power into the
electricity system
Designated customer
A customer who’s expected annual consumption will be
less than 12,000 kWh, but excluded customers with
unmetered supply or who are under the terms of a multisite contract or who have half-hourly metering or
maximum demand metering
DTI
Department of Trade and Industry
DGUR
Director General of Utility Regulation
ELECTROPAZ
Electricidad de LaPaz S.A.
EATS
Economically adapted transformer system
EECI
Energie Electrique Cote d’Ivoire
FNEE
National Electricity Fund
ENDE
Empresa Nacional de Electricidad S.A
ECG
Electricity Corporation of Ghana
ELFEC
Empresa de Luz y Fuerza Elictrica de Cochabamba S.A.
ELFEO
Empresa de Luz y Fuerza Electrica de Oruro S.A
EU
European Union
ESI
Electricity Supply System
ESMAP
Energy Sector Management Assistance Programme
EdF
Electricite de France
EWG
Exempt wholesale generators
ERB
Electricity Regulatory Board
E&W
England and Wales
FCC
Federal Communication Commission
ix
FERC
Federal Energy Regulatory Commission
Gross pool
Mandatory trading of all electricity through the centralised
bulk electricity market
GDP
Gross Domestic Product
HE
Hydro Electric (Scottish)
Hedge Contract
Financial contract typically between generator (seller) and
retail/distributor (buyer) which establishes a fixed price
for a defined amount of electricity (seeks to hedge price
risk in the spot market)
IMF
International Monetary Fund
IPP
Independent Power Producer
ISD
Independent Systems Operator
ISER
Institute of Social and Economic Research
IEA
Institute of Economic Affairs
Installed capacity
The highest capacity of output measured at the main
alternator terminals which generating station or generating
set is designed to be able to maintain indefinitely without
causing damage to the plant
IFC
International Finance Corporation
IDA
International Development Agency
IPTL
Independent Power Tanzania Ltd.
JPSCo
Jamaica Public Service Company Ltd.
JTC
Jamaica Telephone Company Ltd.
JLPCL
Jamaica Light and Power Company Ltd.
JPUC
Jamaica Public Utilities Commission
JPPC
Jamaica Private Power Company Ltd.
JEP
Jamaica Energy Partners Ltd.
LNC
Leucadia National Corporation
x
LOLP
Loss of load probability
LRMC
Long run marginal cost
LDC
Load Dispatch Centre
VOLL
Value of loss load
MMC
Monopolies and Mergers Commission
MPP
Merchant Power Plant
MA&SO
Market Administrator and System Operator
Manweb
Manweb Plc.
Merit Order
Dispatching of generator sets in an interconnected system
ranked to establish economic order of preference usually
based on the incremental cost of generation; from lowest
cost to highest cost in ascending order
NED
Northern Electricity Department
NP
National Power Plc.
NE
Nuclear Electric Plc.
NIE
Northern Ireland Electricity Plc.
NGG
National Grid Group
NGC
National Grid Company
NETA
New Electricity Trading Arrangement
NSHEB
North of Scotland Hydro Board
Open access
Similar to common carriage, traditionally a common
carrier was required to provide transport to all firms
requesting it without discrimination
OFGEM
Office Gas and Electricity Markets
OECD
Organisation of Economic Cooperation and Development
OFT
Office of Fair Trading
OCGT
Open cycle gas turbine
xi
OUR
Office of Utility Regulation
PES
Public Electricity Supplier
PE
Public enterprise
PJM
Pennsylvania – New Jersey – Maryland (used to refer to
this regional power market).
PPA
Power purchase agreement
PUC
Public Utilities Commission
PURC
Public Utility Regulatory Commission
PWR
Pressurised water reactor
PX
Power Exchange
PSP
Pool selling price, price which forms the basis of payments
for electricity by suppliers in the E&W Pool
PPP
Pool purchase price – price which forms the major part of
the generator revenues under the pool trading system
PURPA
Public Utility Regulatory Policy Act
Pool
Electricity trading market for bulk power in England and
Wales
Peak Load
That part of power demand which occurs for relatively
short period. Plant designed for peak load may operate for
only 30% of the time
Pumped Storage
Use of turbines to pump water to a reservoir at the top of
a hill during periods where it can be released to generate
power in peak periods, or called on to meet sudden
shortfall
PPT
Private purchase tariff
QF
Qualifying facilities
ROR
Rate or return (system of controlling profits of regulated
company)
Revenue Cap
System of controlling prices of regulated companies that
focuses on the maximum revenues (rather than profits or
xii
price) the firm may recover from a regulated activity
(variation of price cap)
REC
Regional electricity company
Rate base
The valuation of a firms capital and costs used to
determine the allowable return under ROR regulation
Reserve
Additional generation capacity which is held in reserve to
cater for the possibility of plant breakdowns and
unexpected surges in demand
Run of the River
A hydro electric system using flows of stream as it occurs
and having little or no reservoir capacity for storage of
water
Ramsey Pricing
Theory of efficient pricing aimed at reducing the
distortion impact; used as a principle for designing two or
multi-part pricing in utilities.
Regulatory Period
Typically taken as 5 years, at the end of which the utility
presents plans for investment and is subject to its price
being reviewed.
SADC
Southern African Development Community
SSAP
Southern Africa Power Pool
SSA
Sub-Saharan Africa
SIN
Siestema Inter Connectedo National
SEPSA
Servicios Electricos Potosi S.A.
SIRESE
Sectoral Regulatory Authority
SE
Superintendent of Energy
SB
Single buyer
SMP
System marginal cost being the highest price of a
generating set in the pool which clears the market
SRMC
Short run marginal cost
SOE
State own enterprise
STS
Second tier supplier, supplier licensed to sell to liberalised
xiii
customers in a franchised zone
SSEB
South of Scotland Electricity Board
SWALEC
South Wales Electricity Plc
SWEB
South Western Electricity Plc
SEEBOARD
SEEBOARD Plc.
Spinning reserve
The status of generating sets in which the turbines are
spinning and able to generate more electricity in response
to the system
Spot market
Market in which bulk electricity (commodity) is traded,
establishing a price which equates supply and demand for
each half hour or hour of day
TANESCO
Tanzania Electricity Supply Company Ltd.
TDA
Transportadora de Electricidad S.A.
T&D
Transmission and Distribution Company
TAI
Total average interruption
TPA
Third Party Access
TCT
Total cost of transmission
TI
Tariff income
TO
Transmission Operator
“Take or Pay”
A contractual obligation which requires a firm or party to
take or pay for electricity or fuel or other contractual
obligation, which requires the company to make payment
in event that the firm does not take the electricity or fuel
Uplift
An amount of the PPP giving the PSP to cover additional
cost due to forecasting errors, transmission and
operational constraints and provision of ancillary services
UWI
University of the West Indies
UEB
Uganda Electricity Board
VRA
Volta River Authority
xiv
VOLL
Value of loss load
WEM
Wholesale electricity market
Wheeling
Transportation of electricity across (high voltage)
transmission (or lower voltage) generation lines
WIEC
West India Electric Company Ltd.
YPFB
Yacimientos Petroliferos Fiscales Bolivanos
Yardstick competition
Use of performance comparisons between different
suppliers to provide competitive discipline often linked to
specific incentive rules to reward above average
performance and penalise below average performance.
“X”
A factor used to indicate level of productivity
improvements that can be obtained, calculated as the
Retail Price Index less the productivity factor “X”
Abbreviation of Units
kW
Kilowatt (1000 watts)
kV
Kilovolts (1000 volts)
kVA
Kilovolt ampere (1000 volt-amperes)
kg
Kilogram
km
Kilometre
MW
Megawatt (1000 kilowatts)
MWh
Megawatt hour (1000 kWh)
GW
Gigawatt (1000 MWh)
GWh
Gigawatt hour (1000 MWh)
kWh
Kilowatt hour (1000 watt hours)
xv
List of Tables
Table 1
Characteristics of the UK System in the 1980s
Table 2
Electricity Privatisation Programme 1990 – 1996: Sales
Proceeds
Table 3
Output By Market Share – Percentages
Table 4
Installed Capacity in England and Wales: 2000/01
Table 5
Percentage Share of New CCGT Capacity Commissioned:
1990 to 2000
Table 6
Fuel Use Changes in Percentage Share: 1990/91 and
2000/01
Table 7
Summary of Who Own Whom – 2000 (Intermediate holding
companies have been omitted for clarity)
Table 8
Changes in Electricity System’s Workforce
Table 9
Profitability of ESI After Privatisation
Table 10
Characteristics of Distribution
Table 11
Pre and Post-Management Contract Results - Jamaica,
JPSCo – Annual Revenues and Profitability
Table 12
Jamaica – JPSCo, Number of Employees/Labour
Productivity and Number of Customers
Table 13
Energy Losses – Jamaica JPSCo
Table 14
Pre- and Post-Performance Management Contract Results
– Bulk Power and Industrial and Consumer Retail Prices
Table 15
ENDE Generating Plant Capacity – 1994
Table 16
Bolivia, Installed Generation Capacity in 1994
Table 17
Generation Companies Capacity in the SIN – 1996
Table 18
Electricity Demand by Distribution Within the SIN:1996
Table 19
Post – Privatisation Distribution of Share Ownership
xvi
Table 20
Bolivia: - Revenues From Divestiture
Table 21
Bolivia Average Real Retail Tariff – (in 1997 US¢/kWh)
Table 22
Bolivia Profitability, Return on Equity – Percentage
(After Taxation)
Table 23
Bolivia Labour Productivity: GWh per Employee
Table 24
Bolivia Number of Customers in the Interconnected
System by the Distribution Companies
Table 25
Bolivia Energy Losses: Percentages
Table 26
Macro-Economic Characteristics of Case Countries
Table 27
Electricity System’s Characteristic: Year 1993/94
Table 28
Economic Characteristics: Decades of the 1980s and
1990s
Table 29
Regulatory Regime in Selected SSA Countries
xvii
List of Figures
Figure 1
Figure 2
Figure 3
Figure 4
Figure 5
Figure 6
Figure 7
Figure 8
Figure 9
Figure 10
Figure 11
Figure 12
Figure 13
Figure 14
Figure 15
Figure 16
Sub-Additivity and Economics of
Scale and Natural Monopoly
Cost Curve Showing Plant Size –
1930-90
Franchised Monopoly Model
Franchised Multiple Distribution
Structure
Franchised Monopoly (Phase 1 –
Model One) Integrated Industry
Structure
Purchasing Agent Structure (US
System after Liberalisation)
T&D as Single Purchaser
(Horizontally Unbundled
Generation)
Transco as Single Purchaser
(Horizontally Unbundled Gencos
and Discos with Large Consumer
Bypass)
Single Purchaser (Phase Two Model
Two) Industry Structure (Electricity
Flows)
Single Purchaser (Phase Two Model
Two) Industry Structure Financial
Flows)
Bulk Electricity Market Structure
(UK System Immediately after
Privatisation)
Electricity Wholesale Market (Phase 3
Model Three) Industry Structure
(Electricity Flows)
Electricity Wholesale Market (Phase 3
Model Three) Industry Structure
(Financial Flows)
Bulk Electricity: Mandatory Power
Pool Design
Bulk Electricity: Balancing Trade
Design
Customer Choice Structure (Open
xviii
Figure 22
Network Structure)
Retail Competition (Phase 4 Model
Four) Industry Structure Electricity
Flows
Retail Competition (Phase 4 Model
Four) Industry Structure Financial
Flows
Four Phase Electricity Restructuring
Model
Pre-Privatisation UK Industry
Structure (1997)
Annual Average Electricity Price
(1999/2000 prices)
Price Reductions Since Privatisation
Figure 23
CNDC Organisational Structure
Figure 24
SSA Restructuring Framework
Figure 17
Figure 18
Figure 19
Figure 20
Figure 21
xix
1
Chapter 1
Restructuring For Competition in Electricity Markets
Introduction
Electricity has three important characteristics and these features have over the years had a major
impact on the structure of the industry and its trading arrangements. First, electricity cannot
readily be stored, with the result that the demand at any point in time must be matched by supply
from generators, and failure to balance power inflows and outflows can within seconds result in
serious deterioration of the systems operation. Second, it can only be transported through wires,
which makes it a network industry. The nature of electricity is such that it is a formless product
and in its transportation from generation to consumers it is not possible to trace its source of
origin. Kirchof’s law states that; ‘power flows automatically and instantaneously along the path of
least resistance and must conform to system- wide constraints of energy balance and frequency1‘.
Arbitrage in power markets cannot be conducted as though electricity will flow along a path
determined by contracts as in the case of other markets. Thirdly, electric utilities carry natural
monopoly characteristics, with the result that until recently the industry was partially or totally
excluded from market competition.
These three features critically presented major challenges to reformers in the 1980s in their quest
to move to a competitive and privatised industry structure. How these problems are resolved have
had a major bearing on the transformation from a single utility monopoly industry structure, which
dominated the scene for most of the post-war years to a market based structure.
2
Electricity production and supply consist of four district activities in the production and delivery
value chain; generation at power stations, transmission through high voltage wires from generation
plants to distribution wires, distribution through low voltage wires to customers’ premises, and
supply, the buying and selling of electricity to customers or end users. The generation process
involves production using various sources from hydro-electricity, internal combustion engine,
steam turbines powered by fossil fuels, nuclear plants, wind driven turbines, photovoltaic
technology and other forms of renewable energy. The transmission function is more than simply a
transportation network. It is a complex coordinating system that integrates the various generators
into an overall structure to provide reliable flow of electricity to dispersed distribution points or
demand nodes and involves transformers, substations, as well as the transmission wires.
Historically, the control function has been addressed within the context of a vertically integrated
industry where all four functions come under one integrated management control structure. It has
been estimated as a general rule that generation accounts for about 65% of total cost, transmission
10%, distribution 20% and supply 5%. These proportions vary in different systems depending on
technology, size of country and density of connections. The important point of note is that
generation accounts for the greater portion of system cost.
The Economics of Electric Utility
The industry is said to possess natural monopoly characteristics with significant benefits from
economies of scale and scope. Investments in the electric production and the deliveryvalue chain,
especially in transmission and distribution are specific and once costs are incurred they cannot be
recovered if a decision is made to leave the market, given the fact of low residual value of
specialised goods that cannot be used in any other productive activity. These irreversible costs act
as strong barriers to entering and leaving the market. The large investments, long capital recovery
period and irreversible costs further present a high level of risk to potential investors. In order to
mitigate these risks, investors tend to seek long-term guarantees best obtained from integrated
systems, in order to reduce the uncertainty of trading with third parties. Major changes in
technology, however, have led to increased questioning of the extent to which scale economies
continue to exist. However, a number of commentators’ for example, Gegax and Nowtony2 (1993)
have argued that:
3
“In short a large body of evidence indicates that the electric utility industry has not
exhausted economies of scale. Regulators cannot justify a policy to encourage
entry into the electric utility industry solely on the basis that economies of scale in
generation have been exhausted”.
For these two economists, radical restructuring of electricity industry and the imposition of entry
conditions are unwarranted in what remains an essentially natural monopoly and were not called
for in the USA in the early 1990s.
Joskow and Schmalensee (1983)3 stated that there is little doubt that the establishment of regional
or national network can potentially be of great benefit to electricity consumers. To be included
among the gains are the realisation of plant level scale economies, increased reliability of supply,
efficient production from coordinating the operations of differing marginal costs of supply, lower
total capacity requirements, resulting from aggregation of differing load characteristics, economies
from coordination of maintenance schedules and economies from responding to emergencies.
Electric industry has been considered over the years as a natural monopoly. For Baumol4:
“a natural monopoly exists when a single firm can produce a desired level of output
at a lower total cost than any output combination of more than one firm”.
There is therefore, the condition of sub-additivity.
Another important economic condition is that economic efficiency is achieved when prices equal
incremental or marginal cost. However, where for a strong natural monopolist incremental cost is
less than average cost, that firm is not viable. The monopolist will need at least to recover average
cost. This, however, may not be the most economic outcome.
Baumol5 Panzar, and Willig states that:
(sub-additivity) “Surely, is what anyone has in mind, at least implicitly, when
speaking of a monopoly being “natural” and that is what economists were
undoubtedly groping for when they (as it turns out, mistakenly) identified natural
monopoly with economies of scale”.
Alternatively6 Gegax and Nowotny state that:
4
“an industry has been called a natural monopoly if a single firm producer can find
price-output combination that precludes profitable entry by others”.
For Gegax and Nowotny7:
“The issue of economies of scale arises because such a cost condition is sufficient,
but not a necessary condition of natural monopoly in a single product firm. A
single product firm exhibits economies of scale if its long run average cost function
is decreasing. While it is true that a production process, which exhibits economies
of scale, is sub-additive at that output level, a production process may also be subadditive though it exhibits increasing average cost. It is a stronger condition to
require decreasing average cost, than to require only that costs be sub-additive
while allowing for increasing average cost. A firm that exhibits decreasing average
cost is called a strong monopoly. A firm that exhibits increasing average costs, but
whose costs are sub-additive is a weak monopoly”.
A weak natural monopoly may not be able to prevent entry to the industry, however, regulators
sometimes prefer a single firm producing that output, rather than several firms producing the same
output and in so doing regulate entry, in which case prices must also be regulated.
Electric transmission and distribution show major economies of scale (increasing returns and
decreasing average costs), which has made it preferable, for production to be carried out in largescale integrated systems. Economies of scale in the generation sector depend on the relative size of
demand with respect to the optimal scale of production for each of the respective production
technologies. Generation is a weak monopoly.
Beyond a certain level of demand, located on an upward curve of average costs, it is possible to
reach a situation of decreasing returns and dis-economies of scale, even for the technology having
the highest optimal scale of production. Even in the upward part of the average cost curve, where
returns are declining and dis-economies of scale occur, or as shown in Fig. 1 at points 1, 2 and 3
there can be sub-additivity and as a result a natural monopoly without the benefit of economies of
scale.
In networks such as water pipeline, rail track, gas pipeline and power transmission and distribution
it would be a waste of society’s resources to have several parallel networks of the same type
5
competing with each other. If they were to compete only one firm would survive. Network
systems also display high sunk costs, requiring large and lumpy investments to enter and to
maintain operation in the market8.
In a multi-product firm it is economies of scope, which results in sub-additive conditions as stated
by Baumol, Panzar and Willig (1982) 9. It is the indivisibilities and specialisation, which creates
jointness and distinguishes the multi-product firm from the single product firm. Economies of
scope exists in the multi-product firm if it is less costly for it to produce a given combination of
outputs, than to produce the same level of each of the distinct output in separate unbundled firms.
It is the economies of coordination that determine sub-additivity of the cost function in an electric
system.
COSTS
D: DEMANDS
A,B, & C: OPTIMAL SCALE S:SUBADDITIVITY LIMIT (ONE CO.
PRODUCES AT LOWER COST)
NATURAL MONOPOLY
COMPETITION
Source: Illustration developed from Baumol’s condition of sub-aditivity and economies of scale.
Coordination economies arise from successfully matching diverse usage or demand patterns with a
capital-intensive supply system. Network economies on the other hand arise from the joint
production of multiple services on a network and the low production incremental cost of adding
6
more services. Whether an electric utility is vertically integrated or unbundled there is still the
necessity for a continuous balancing function or for coordination and this coordination creates an
external cost10 in the unbundled firm, while it is internalised11 in the integrated utility. Unforeseen
demand surges or equipment failures, require central intervention by the grid operator, which may
require some generating plants to be unexpectedly dispatched or turned off. The central grid
operator requires a considerable amounts of information to be able to have substantial control
over the whole system.
Should there be an unbundled structure an externality effect to other firms is created, in that
operators may not always bear the full consequences and costs of their decisions within the system.
Decisions of one firm can drastically affect the systems viability and reliability and in so doing
impose costs on others who are not party to the decision. The firm may, therefore, be
opportunistic and engage in activities knowing that it is not singularly meeting the cost of its
decision. Where several unbundled firms exist in the chain of production process, one firm must
provide the balancing and system dispatch function. If the vertically integrated structure remains,
then the utility is in a position to use its control of the transmission to discriminate in favour of its
own generation sets.
In the vertically integrated electric utility the single firm bears the full costs or derives the full
benefits from its decision and hence the externalities are internalised. Internalisation is no longer
possible when several independent firms operate at different stages of the production process.
New institutional arrangements are needed to facilitate coordination in the unbundled production
process. Reliance on voluntary cooperation to resolve transmission issues may be difficult in a
competitive environment. The establishment of central coordination in order to overcome the
externalities associated with the unbundled structure would seem to be in conflict with the goal of
promoting competition through the encouragement of individualistic decision-making. The
benefits of coordination have to be balanced against the benefits of competition and how this
trade-off is addressed is one of the important features of recent electricity marketing arrangements.
How to balance the natural monopoly in transmission with competition in the potentially
competitive generation sector has been a central issue in designing power markets. Long-term
bilateral contracts or power pools are now creating these arrangements. They, however, have
Williamson’s (1979)12 transaction costs associated with them;
7
“Transaction costs are central to the study of economics; identification of the
control dimensions characterising transactions, describes the main governance
structure of transactions and indicates how and why transactions can be matched
with institutions in a discriminating way”.
The central focus of transaction costs is exchange of goods and differs from principal agency
theory in that the former is concerned with contracts of labour and exchange of services.
Transaction costs result from the several contracts that flow from more than one operator in the
unbundled structure. In Tanzania, in the case of the proposed Songas Independent Power Project
(IPP) there are over 30 contracts involved, while in
Jamaica, IPP entry into the production
process resulted in an even greater number of contracts. Firms often prefer to enter into longterm contracts, with very detailed conditions to reduce uncertainty, as well as to reduce the risk of
rent seeking or opportunistic behaviour. The more firms in the system the greater the number of
contracts and the higher the transaction costs are likely to be.
Vertical integration also provides opportunities for cost savings in resource usage at the planning
stage through the timing of needed investments, as well as in scheduling maintenance activities. At
the same time, horizontal integration within the single firm may also create lower costs, and
provide for increased load diversity, while lowering the amount of reserve capacity. All power
systems need reserve capacity, both reserve margin and spinning reserve to accommodate
unexpected increases in demand, equipment failures and regular maintenance. Joskow, (1997)13, has
also argued that the separation of generation from transmission does
“not fundamentally transform a sector with natural monopoly characteristics to one
where these characteristics are completely absent. - - - - - a separate generation sector now makes sense in that generation of electricity is no
longer a natural monopoly as a consequence of technological change is incorrect”.
Generation has always been a weak natural monopoly and the tradition has always existed in many
systems where there has been numerous un-integrated generating and transmission entities unaffiliated to the fully integrated utilities. Beesley and Littlechild (1997) 14 counter this argument by
stating the view that:
8
“The unbundling of organisations might involve sacrificing economies of scale is
dubious, for the state of the industries were determined largely by political or
administrative, not market forces. In the absence of competition one cannot know
in advance precisely what structure will prove efficient”.
The factors that militate against unbundling are those that would lead to loss of the benefits of
internalisation. Whether there is a net benefit from un-integrated operation depends to a large
extent on whether the benefits from competition can more than offset the cost disadvantages of
unbundling, loss of internalisation and increased transaction costs. In this respect system size,
density of connection and a number of other factors must be taken into consideration.
Restructuring the Electricity Industry
The features outlined above have in the past led to an industry that has been characterized by large
systems. Experience of the past has also been that utilities would build larger and larger power
plants, often of sizes up to 4000 MW to benefit from scale economies in the generation sector. The
preferred mode of operation was not only vertical integration but horizontal integration as well.
This conventional industry structure more or less prevailed up until the 1980s.
The first major
structural change to the industry commenced in 1978 in the United States with the introduction of
the Public Utility Regulatory Policy Act. (PURPA)15. This initiative was, however, to have a far
reaching implication for the industry, and this implication has extended to the global arena.
PURPA gave rise to a new player in the market, the independent power producer and in so doing
unleashed for the first time major competitive forces within the industry.
Experiences in the USA soon showed that IPPs could bring plants into operation often in very
short time frame and on budget. A direct result of this development is that IPPs share of
generating capacity in the USA increased from 3.6% in 1987 to 7.2% in 1995. Since 1990, IPPs
have contributed over half of all new investments in the generating sector in the USA. In most
instances these plants were of the sizes of 50-80 MW and could reliably be integrated into the
system in modular form. Additionally, existing utilities were restricted by the law from owning
more than 50% of the capital of the new producers. They in turn were restricted from making
sales direct to purchasers other than the utilities.
9
In effect small independent power producers were given a protected market entry as wholesalers of
bulk power supplies. Price determination was based on the utilities full-avoided cost or the
incremental cost of adding new capacity. Although required purchase prices were to be at the
incumbent utilities avoided cost, regulators calculated these prices in some states in ways that led to
artificially high bulk electricity purchase prices. This further gave impetus to the growth and
expansion of the IPPs16. Generally, they are permitted to sell at wholesale market-based rates and
the Federal Energy Regulatory Commission (FERC) in return does not regulate these marketbased rates. PURPA therefore, facilitated the entry of the independent power producer with longterm power purchase agreements (PPAs) into the electricity market to supply new capacity on the
basis of competitive bids and in so doing heralded large-scale entry competition into the market for
the first time.
IPPs, however, came to encounter restrictions on access to the incumbent utility’s transmission
system. The introduction in 1992 of the Comprehensive National Energy Policy Act broke the
incumbent utility’s monopoly of the electricity transportation system by imposing common carrier
status on both transmission and distribution. IPPs and exempt wholesale generators (EWGs) on
the basis of open access to the transmission and distribution system were for the first time able to
supply bulk power to very large consumers or to the wholesale markets where they could sell at
unregulated market rates. These developments expanded competition to another level that of
wholesale competition among generating firms as distinct from competition for new capacity.
The lower prices, which IPPs often charge later, resulted in divergences between the regulated
prices of the incumbent utilities and the prices of the IPPs, with the result that IPPs were able in
many cases to under bid the incumbent utility in proposed projects. The price of bulk power in
the inter-utility wholesale market in the late 1980s in the USA was on average10% higher than the
prices of the IPPs17.
The Impact of New Technologies on Scale Economies
It is not so much the institutional changes, however, but the impact of the new technologies (the
new aero-derivative combined cycle generation often from cheaper natural gas) that has unleashed
10
the forces leading to the radical changes in the industry structure and its trading arrangements, as
well as to increased competitive activities18. The advent of small, natural gas fuelled generators,
coupled with falling prices of natural gas drastically reduced the capital cost of minimum efficient
scale generating plants.
These new combined cycle generating gas plants (CCGG), often have thermal efficiencies as high
as 55% to 60% compared to the old coal or oil fired plants, with efficiencies of less than 40%. The
fact that they are available in small systems made entry to the generation sector of the industry
much easier19. These smaller systems are also easier to run and maintain than the larger scale
plants. Additionally, they have reduced planning and construction lead-time and can be installed in
a much shorter time frame. They are now produced in standardised units in competitive markets
by several firms. It has, therefore, been easier for IPPs to obtain financing for new plants because
of this shorter construction lead-time and lower financing costs.
The development of combined cycle gas turbine (CCGT) plant has had a radical effect on the
overall economies of generation. The fixed cost of installing a CCGT plant in the early 1990s in
England and Wales was around US$600-650 per kilowatt, compared to US$750-800 for oil fired
plant, US$900-1,200 for coal plant, and US$2,250 for a nuclear plant. Towards the end of the
1990s the capital cost of installation of the latest CCGT technology had fallen to US$373-450 per
kilowatt.
11
Source: Hunt and Shuttleworth, Reproduced from ESMAP,
World Bank ’Energy Service For the World’s Poor’, April
2000, p. 47
Fig. 2 above shows cost curves of optimal generation plant size, over the period 1930-1990. In the
1930s optimal thermal plant size was under 75MW. By 1970 optimal plant size had increased to
400 MW, increasing further to just less than 1000 MW by 1980. With the introduction of CCGT,
optimal plant size has again fallen below 75 MW.
New financial market innovations also allowed for the debt associated with IPP type (nonrecourse) financing, to be developed with the effect that the debt can be readily sold and hence the
sunk cost hazard of investment experienced with large integrated plants are significantly
minimised. The assignability of long term contracts also helps potential entrants to secure long
term financing since a creditor can now step in and operate the system in the event that the buyer
defaults. The market is therefore, made more contestable20. For Baumol:
“a contestable market is one into which entry is absolutely free, and exit is
absolutely costless. We use “freedom of entry” in Stigler’s sense, not to mean that
12
it is costless and easy, but that the entrant suffers no disadvantage in terms of
production technique or perceived product quality, relative to the incumbent and
that potential entrants find it appropriate to evaluate profitability of entry in terms
of incumbent firms’ pre-entry prices”.
With these developments, pressure has been building up in the USA since the latter part of the
1990s to extend competition from the bulk electricity market to the retail market. This would
require generating companies or incumbent utilities to sell directly to final consumers in the
franchised areas of the respective utilities, paying regulated rates for use of the utilities’
transmission and distribution lines.
Rise of Competition in Bulk Electricity Markets
There is no doubt that there has been a significant development in electric utility economics.
Tenenbaum, Lock and Barker21 conclude that:
“There is now broad (through not universal) acceptance that at least the generation
function is potentially competitive. However, there is equally broad acceptance
that the transmission function and at least the wires business in the distribution are
in most circumstances a natural monopoly”.
Joskow22 also supports the view that transmission and distribution sectors remain natural
monopoly sectors. He however, maintains the position of integration and states that:
“the available empirical evidence suggests that at the very least the distribution of
electricity has important natural monopoly characteristics”
He is also of the view that electricity supplies:
“should continue to be distributed to retail customers by franchised monopoly
companies, subject to price regulation”
In Joskow’s view:
“the optimal organisational form for an electric utility is incompatible with
competition in distribution or transmission or with separate generation sector made
up of competing firms”
13
He also voiced the view that:
“vertical integration between generation, transmission and distribution and
horizontal integration between interconnected generation plants represents the
most efficient organisational arrangements for supplying electricity”.
Joskow failed to separate the electricity retail business, which is a competitive segment of the
industry from the distribution wires business, which continues to display the natural monopoly
characteristics. In contrast Yarrow23, however, contends that:
“While arguments for the existence of significant economies of coordination are
generally sound, the attainment of such benefits does not necessarily require the
creation or retention of a single company responsible for all electric generation and
transmission activities-------------------------- for a number of reasons, however, scale economy arguments in favour
of a single firm production are not entirely convincing even accepting the
economies”.
The old economy of scale argument today for a single firm production is more powerful when
used to support a case for the conventional fossil or nuclear fuel based plants. The French
Electricite de France (EdF) which is 85% nuclear based would seem to fall into this category.
Economies of learning are much more significant for nuclear technologies.
There is, therefore, a strong rationale for easing entry restrictions based on the premise that
economies of scale have been exhausted from centralised production technology. Economies of
scale are exhausted if the rate of increase in production cost rises fast or faster than output. A
direct result of these developments has been growing liberalisation of electricity generation markets
since the early 1990s.
The England and Wales system; 52,400 MW, Argentine 15,000 MW and Chile 3,000 MW, which
were the first set of markets to undergo restructuring were however, considered to be fairly large
systems where scale economies may have been exhausted at the time of divestiture. There was still
a debate in the early 1990s in the UK that 50,000 MW was the minimum efficient scale system for
the operation of an electricity company.
14
Christensen and Greene24 focussing on firm level in 197624 concluded that economies of scale
existed up to 4000 MW. Atkinson and Halverson25 in 1984 concluded that scale economies
continue to exist at firm level up to 12000 MW. Well over 100 countries, however, have systems
smaller than 1,000 MW. The question has, therefore, arisen as to how small a system should be
before a competitive industry operation can be ruled out? This is the type of question several
African countries with small systems must answer should they decide to take to liberalisation of
their electricity markets. In the larger system it will be possible to provide for more radical
restructuring and more intensive competition, as there is still the possibility of large size operating
units, following from the unbundling process.
In as late as 1990 consultants examining the Kenyan system, where the installed capacity was then
706 MW concluded that there was no scope for competition between a horizontally unbundled
and separately owned generation sector. The consultants further concluded that even though there
were no competitive possibilities in generation there were, however, benefits to be gained from
vertical separation of generation into a single operating company. These conclusions were to
influence the restructuring exercise in Kenya with the result that generation was unbundled into a
separate company from transmission and distribution.
Jamaica voiced pretty much the same conclusion in 1993 against disintegration and stated that
separation of generation was not a feasible option and that the unbundling of the electricity
industry was more a policy option for countries with large systems. In the opinion of Coopers and
Lybrand; the Jamaican consultants at the time, horizontal separation of generation and vertical
separation of transmission and distribution and further horizontal unbundling of distribution for
the Jamaican system was not economically feasible for an operation of such small size. The World
Bank in 199426 also argued that:
“a minimum market size maybe necessary before unbundling becomes worthwhile,
however, and in the very small markets of many low income countries, vertical
separation of generation from transmission and distribution may not produce
sufficient efficiency gains to offset the additional co-ordination costs”.
The question still remain how small is small? Recent electricity industry restructuring has involved
two distinct activities, changing ownership or privatisation and changing the industry’s structure by
15
unbundling vertically and horizontally. Privatisation should not be confused with vertical and
horizontal restructuring. The effects are different, although they maybe reinforcing. Private
ownership and operation, of itself, carries certain costs and benefits.
Public Ownership Vs Private Ownership
The historical approaches to dealing with electricity and other network utilities, especially over the
last 50 years, have been state ownership. Electricity production in developing countries has been
regarded as a public service and this has been fundamental to their development strategies. The
placing of electricity to meet micro-economic and social development has been a basic policy
strategy of most post-independence administrations. State ownership is said to provide the
environment that would ensure the attainment of social, political and welfare maximising
objectives.
Electric utility, particularly when state owned, has been required to undertake costly tasks, such as
uniform or below cost pricing to certain segments of consumers or is required to provide financial
support through cross-subsidies to other sectors of the economy as in the case of support to coal
mining and the nuclear industries in the UK. Such policies have resulted in substantial departure
from efficient allocation of resources and the attainment of productive and allocative efficiencies.
When prices are below the cost of production and such prices are guaranteed to all users and not
just to those who need it most, the result is over consumption and unjustified waste. This concept
was not only shared by developing country administrators, but by multi-lateral and bilateral
organisations as well as most donor agencies. Infrastructure projects were seen as a means to
alleviating social inequalities and promoting development.
Experiences of state management of utilities, especially in developing countries have been well
documented. Political intervention in day to day operations and lack of managerial accountability
criteria for evaluating performance of public enterprises have resulted in a catalogue of disaster,
with the sector characterised by very low levels of service availability, high levels of disinvestments, poor and inconsistent services, low productivity and excess and burdensome debt
services costs to tax payers. Private ownership and government regulation also may not prove to
be the answer. Intimately tied to the structural problems are regulatory deficiencies. In most
16
developing countries regulation as an economic concept, that is a set of legal and institutional
provisions that seek to redress inefficient market operation in cases where there is market failure
are relatively unknown.
Moving from a fully state owned industry with modest restructuring, such as separation of
generation from transmission and distribution and privatisation may provide the opportunity to
obtain some of the benefits of private ownership.
Strong theoretical arguments have been
advanced over the years to support the transfer of ownership from the state to the private sector.
These arguments have been based on the theories of property rights - De Alessi (1980)27, Alchain
(1965)28, Demsetz (1966)29, Furubotn and Pejovich (1965)30 - principal and agency; Rees (1965)31;
Jensen and Meckling (1976)32, Aharoni (1986)33, Bös (1991)34, Parker and Stephen (1996)35 transaction cost economics; Williamson (1979)36, North (1961)37 - public choice; Tulloch (1965)38,
Niksanen (1971)39, Buchanan, et.al., (1978)40, Mitchell (1988)41.
The principal and agency theory42 states that publicly held firms are not exposed to the discipline
of product and financial market, they do not face the threat of takeovers, the competitive market
for management and hard budgets and they are not exposed to bankruptcy.
monitoring is at best very weak.
Shareholder
Private ownership is said to change the motivation of
management towards profit making and leads to higher levels of efficiency, especially where a
competitive environment is provided. A private firm will be less willing to provide uneconomic or
subsidised services. Private firms have a general incentive to produce services in quality and the
variety, which consumers prefer. In general, principals are assumed to be better risk bearers than
agents, while agents are assumed to be specialised managers. Agency problems are more acute
when the interests of agents and principal diverge, as is more likely with public enterprise. Beesley
and Littlechild (1977)43 have argued, therefore, that ownership matters.
The property rights theory44 states that the inability of the taxpayer to transfer individual rights, so
as to capitalise on gains and losses, as is the case with the public firm reduces the individual’s
incentives to minimise cost and maximise return. The setting up of opaqueness in the firm’s
decision-making process makes it difficult for individual taxpayers to directly influence
management decisions. For property rights the issue is one of incentives, in that under public
ownership there are weak incentives for efficiency enhancing behaviour.
17
Public choice theory on the other hand places emphasis45 on the incentive structures facing the
public officials.
Cost efficiency of the firm takes second place to other political issues.
Bureaucrats it is argued will maximise, their utility functions by trading privileges to special interest
groups in return for various financial or social benefits. Politicians are vote maximisers often to
the detriment of social welfare. They also trade special privileges in return for votes. The general
conclusion of public choice is that political maximisation is often in conflict with cost efficiency
and the tendency is for political maximisation to replace cost efficiency. An example of this
practice has been years of cross-subsidy of the electricity industry in the UK to prop up the coal
industry and certain manufacturing interests in order to secure the votes of the unionised workers
in these industries. Public choice theory has had significant impact on public policy formulation,
especially in the utilities since the 1970s.
As early as 1970s, Friedmann (1974)46 highlighted the point that the demarcation line between
public and private enterprise was in a flux, with many striking similarities. In the 1970s it was more
the state that was invading the traditional private enterprise preserves. Since the 1970s, further
breakdown of the demarcation barriers has come more from the private sector invading areas,
which traditionally were public enterprise preserves. Friedmann, however, advanced the view that:
“two further significant points which have often been forgotten in the debate. First
there are three criteria as determinative of the question whether an enterprise is
called public. They are: (a) who owns them? (b) Where do they get their
financing? (c) How much control is exercised by government over them?”
In the case of public enterprise, ownership is less important, in terms of economic performances.
More crucial is the level of participation in management by the government. The higher the level
of direct ministerial and political intervention in management, the more likely efficiency will be
impaired. In the case of private enterprise, ownership may also be less important.
Many
enterprises remain legally private in terms of ownership, but in effect are dependent on state
financing; through grants, subsidies, interest free loans, long-term advances on public contracts
and this may compromise or defuse their commercial commitments.
18
There is also substantial empirical research evidence to support the position that private firms
perform more efficiently than public firms and that the transfer of ownership from the state to
private hands leads to improved efficiency. Atkinson and Halverson (1986)
47
Boordman and
Vining (1989) 48, Bishop and Kay (1989) 49, and more latterly Shirley and Nellis (1991) 50, Goodman
and Loveman (1999151 have presented empirical analysis to support the position that private
ownership and privatisation itself brings superior performances. One of the most thorough
empirical evidence has been the study carried out by the World Bank; Galal, Jones, Tandon and
Vogelsang (1992).52. They analysed the post-privatisation performances of twelve companies in
Britain, Chile, Malaysia and Mexico to determine whether the transfer to private ownership
increased efficiency – and, if so, how the cost benefit of adjustment were allocated. Net welfare
gains were identified in eleven of the twelve cases. Peltzman (1971)53 reaches the conclusion that
price structures of public enterprises are less responsive than private enterprises to cost of serving
specific consumer groups. For Peltzman:
“The willingness of government enterprise management to trade profits for political
support will lead managers to use the pricing system as a mechanism for
redistributing wealth within the political constituency”.
Megginson, Nash and Randenborgh (1994)54, in a more elaborate study of 149 companies listed as
being privatised, compared post and pre-privatisation performances of 61 companies from 18
countries and 32 different industries and found that mean and median profitability, real sales,
operating efficiency, output per employee and capital investment spending increased significantly
after privatisation. The conclusion also showed that operating performances improved in both
non-competitive and competitive environment, that improvement in profitability was not due
merely to increases in prices and that privatisation itself – the involvement, of private investors in a
firm’s ownership structure and control critically impacts on a firms operating and financial
performances. The World Bank 1994 - World Development Report55 - further points out that the
effectiveness of infrastructure provision derives not so much from general conditions of economic
growth and development but from the institutional environment. In its review the Bank found a
common pattern in developing countries consisting of operational inefficiencies; inadequate
maintenance, excessive dependence on fiscal resources, lack of responsiveness to users’ needs,
limited benefits to the poor and insufficient environmental responsibility.
19
The Case for Private Ownership of Electricity
Privatisation exposes the companies to the pressures of financial market competition, even if
product market competition is not possible. Floatation through stock exchanges help increase the
total capitalisation of financial markets.
There are also the benefits of the sale proceeds, and
further recurring benefits from tax revenues which is more likely to flow from a privatised
company.
Beesley and Littlechild56 argue that:
“Privatisation will generate benefits for consumers because privately owned
companies have greater incentives to produce goods and services in the quantity
and variety which consumers prefer -----------The discipline of the capital markets accentuates this process; access to additional
resources for growth depends on previously demonstrated ability -------------.
Resources tend to be used as consumers dictate, rather than according to the
wishes of government, which must necessarily reflect short-term political pressures
and problems. --------.
Private companies will be less willing to provide uneconomic services”.
While the conclusion, therefore, is that ownership of itself is not the major factor affecting
differences in productive efficiency, (Pollitt, 1995) 57 it is how such ownership control is exercised.
Public ownership provides the opportunity for influences other than cost efficiencies to dictate
managerial decisions. Research undertaken by Price and Weyman-Jones, (1993)58 in the gas
industry also showed significant increase in productivity following the privatisation of the gas
industry in the UK in 1986.
Empirical studies on public and private enterprise performances in respect of electric utilities are
mixed. Kumbhakar and Hjolmarsson (1994)59 found that privately owned firms in electricity
distribution were relatively more efficient than municipal utilities and that the efficiency of mixed
(public – private) firms were closer to privately owned firms.
20
Hjalmarsson and Veiderpass (1992a) and (1992 b)60 found that when scale economies are
accounted for in electricity retail distribution in Sweden, the differences between different types of
ownership were very small, low efficiency was more associated with lack of competition in the
industry.
Dilorenzo and Robinson (1982)61 Fare, Grosskopf and Logan (1985)62, Neuberg (1977)63 found no
significant differences; More (1970)64 found private firms to be more efficient. Hollas and Stansell
(1987)65 concluded from their studies that privately owned firms tend to be more price efficient
than municipally owned electricity firms.
Vickers and Yarrow (1991)66 stated there are major problems with many of the empirical studies.
There are problems of measuring key variables such as allocative efficiency and distributional
effects, often firms of a similar nature do not exist which allow for like-with-like comparison
between public and private, the elapsed time of several privatisations has been short and there are
difficulties in distinguishing between the effect on efficiency from changes which result from
ownership, as distinct from changes which result from competition or regulatory policies.
Empirical studies also yield conflicting results on the relative efficiency of public and privately
owned utilities, depending on the extent to which researchers have been able to control the effects
of differences in input prices, technology and economies of scale.
The general conclusion is that private firms are more efficient in competitive environments,
Boardman and Vining (1989) 67. In the case of natural monopoly the results are mixed; some give
the advantage to public ownership, and yet others find no significant differences. Two major
factors seem to be at work, either that of regulatory policies on monopoly behaviour (public or
private) or a competitive environment. The most significant points, however, to emerge from the
evidence are that of the importance of competitive environment, regulatory policy and incentives
for efficiency. In state owned electric utility, the superior public efficiency may be associated with
natural monopoly condition. For Beesley68:
“Competition is the most important mechanism for maximising consumer benefits
and for limiting monopoly power. Its essence is in rivalry and freedom to enter
21
markets. What counts is the existence of competitive threats from potential as well
as existing competitors”.
An issue which leads to tension in the privatisation process is that the more monopolistic the
structure of the industry at the time of divestiture, the more likely the prospects of monopoly
profits and the earning of economic rent, the more attractive the company will be to prospective
buyers, and the higher the likely divestiture income to the Treasury. The benefits of unbundled
competitive structure, which tends to fetch lower divestiture prices, must therefore be balanced
against the longer-term benefits to consumers and the general economy that is likely to flow from a
more competitive industry.
More and more governments are now recognising that direct intervention by the state to remedy
market failure carries substantial negative costs. Problems arise from adapting to rapidly changing
conditions, and resolving and reconciling different and at times conflicting objectives. It has also
been shown that it is now possible to attain social and economic objectives, such as income
redistribution through targeted subsidies while operating in competitive markets69.
The Effects of Regulation
There is also growing awareness of the major inefficiencies brought about by the regime of the
regulated monopoly70. Regulatory reforms in the US of the 1970s and 1980s demonstrated that
largely unregulated competitive industries yield more efficient performances in such traditionally
regulated industries as air transport, railway, trucking, national gas distribution and long distance
telephone. Regulation should not be retained when underlying market conditions have changed
and is no longer relevant. There will, however, be strong pressures in some quarters to protect
vested interest and also from those who seek to extort economic rent. Stigler (1971)71 in his
analysis states that:
“regulation imposes costs but does not yield benefits. Regulatory agencies are
subject to capture, and maybe used by the industry to defend the status quo,
preventing new entrant and maintaining high levels of profitability despite being
inefficient”.
22
An example of this is the case of the State Regulatory Commissions in the USA in frustrating the
introduction of more competition in the retail sector of the industry. The emergence of smart
metering and micro-processor based systems that offer distributed control of selected circuits at
customers’ premises which make it possible to unbundle electricity so that consumers can tailor the
reliability of service by end use has been available for widespread use in the USA for many years.
In fact according to Beesley and Littlechild72:
‘’The promotion of competition is not traditionally associated with regulation of
utilities in the USA. The Regulatory Commissions have a long record of resisting
entry and it has persuasively argued that the real purpose of regulation was to
protect the incumbent from competition”.
Different regulatory regimes have different effects on cost efficiency. Averch and Johnson (1962)
73
states that under rate of return regulation the form of regulation popularly adopted in the USA
the firm has a strong incentive to over invest in capital, “gold plating” to increase the size of the
rate base and obtain higher returns. Regulators also face the major problem of information
asymmetry. The firm knows how to manipulate costs in order to maximise profits in the presence
of the constraints imposed by the regulator. The regulator can only imperfectly observe costs and
does so by incurring a regulatory resource cost, Byron and Myerson (1982) 74. Leibenstien (1996) 75
further states that the problem of information asymmetry makes it very difficult to regulate
vertically and horizontally integrated monopolies, hence New Zealand’s approach of introducing
strict information disclosure requirements in the sectors of the electricity industry which continue
to display natural monopoly characteristics.
The move to yardstick competition in electricity distribution also reduces the extent to which the
regulator has to rely on information from the regulated. Yardstick competition, in electricity
distribution is a special case of incentive regulation and involves the decoupling of the utility’s
price structure from the firm’s reported costs.
The objective is to reduce the asymmetric
information problem. According to Wyman-Jones:
“a set of empirically derived competitive efficiency measures are developed under
yardstick regulation which seeks to compare firms within a given industry by first
determining which firms are performing most efficiently, i.e., constitute the frontier
23
of the industry’s production function, and then constructing an index of how any
given firm differs from those which make up the frontier firms”.
This is the methodology being adopted for the distribution sector in the post-privatised Panama
electricity system. Demsetz76 also states that:
“Public utility regulation has been criticised because of its ineffectiveness or
because of its undesirable effects on production. --The natural monopoly theory provides no logical basis for monopoly prices. The
theory is illogical. Moreover for the general case of public utility industries, there
seem no clear evidence that the cost of colluding is significantly lower than it is for
which unregulated market competition seems to work’’.
Developing country governments, therefore, need to weigh the policy options of direct ownership
or that of private ownership and regulation of prices and entry conditions against the substantial
welfare losses which from experiences have been attributable to state ownership, as well as to
privately owned regulated firms, against the benefits of private ownership and competition and
especially such benefits as the diversification of capital and the opportunity for wider investment
flows which comes with private ownership.
Vertical and Horizontal Restructuring
Vertical unbundling involves the creation of two or more economic entities in different stages of
the production chain, such as separation of the transmission from both generation and
distribution. Unbundling serves to isolate relevant costs and revenues and reduces the opportunity
for cross-subsidies and predatory pricing practices between the monopoly and competitive parts of
the system. It also provides for yardstick competition and reduces the potential to use market
power to the detriment of competitors.
Vertical integration and vertical control (Yarrow 1994), 78
“can have anti-competitive effects that outweigh the benefits from reducing or
eliminating the externalities. The anti-competitive effects tend to occur as a result
of an extension of market power: a firm with market power at one stage of
production maybe able to increase its profits by using that power to reduce
competition at another stage of production. In general vertical integration and
vertical control are unlikely to be problematic where there is significant horizontal
24
competition at different stages of the production and supply chain for then there is
no great market power to extend in the first case). However, even where there is
substantial market power at one stage of production stage “A” say, it remains
difficult to justify any general presumption against vertical integration or control
given the existence of potentially significant economic externalities when vertical
integration and vertical control between generation and transmission is weakened,
the case for weakening the vertical links must rest on the view that there is some
substantial, offsetting benefits to be had from separation ----------Yet at first sight it can be difficult to see how such argument can be sustained. The
core of market power in electricity supply systems lies in the natural monopoly
activities of transmission and distribution. If, therefore, transmission is suspended
from generation that market power will be left substantially in tack”.
When a single firm controls the monopoly sector such as the transmission system and is also
involved in the competitive sector such as generation it has the opportunity to stifle competition
by charging either prohibitive or discriminatory prices or setting discriminatory technical standards
of interconnection. Separation also reduces the requirements for regulatory oversight and
regulatory costs.
Whether vertical unbundling brings net benefits depends on the foregone economies of scale and
scope, weighed against the benefits facilitated by competition. An option is accounting separation,
requiring the vertically integrated firm to provide separate accounting for the separate vertical parts
or operational separation, allowing for single ownership of the vertical parts but requiring a
separate third party to operate the monopoly entity. Both accounting and operational unbundling
requires heavy regulatory controls to minimise opportunistic behaviour.
Vertical and horizontal restructuring has different effects from privatisation. Vertical separation of
each stage into monopoly generation, monopoly transmission and monopoly distribution may
serve to increase the effect of monopoly power while at the same time results in loss of economies
of scale and coordination. An unregulated chain of monopolies will tend to sell at higher prices
than an unregulated integrated monopoly, hence regulations is still crucial for the unbundled
vertical monopolies.
It is the combination of vertical and horizontal separation, which provides the opportunity to
introduce competition. Yarrow (1986)79 argues that competition and managerial accountability are
25
more important than privatisation per se, in promoting economic efficiency and this position was
later supported by Caves (1990)80.
Horizontal unbundling is the creation of two or more economic entities from a single area of
economic activity.
Horizontal unbundling serves to dilute market power of the incumbent
enterprise and eventually the barriers faced by new entrants to the market. It also reduces the
burden of oversight by regulators. Where unbundling is carried out on a geographical basis, a
location monopoly is created as with electricity distribution and water systems, however, the
opportunity for yardstick competition between firms is created. The optimal number of entities
will depend in part on economies of scale in the relevant activity and the density and the size of the
market. Density of network connections has a profound effect on unit costs in distribution
systems. Roberts81 explains the importance of density as follows:
“A change in the quantity of electricity supplied by a firm will have different impact
on cost depending on whether the output is supplied to existing customers or to an
increased number of customers. Significant reduction in ray average cost result
from increasing output to existing customers, while no substantial savings occur
when servicing an increased number of customers”.
Separation into several horizontal units also does not of itself lead to competition. A competitive
framework, however, offers important advantages over monopoly. There is the need to introduce
new institutions to facilitate competition. In the 1990s we have seen new market and trading
innovations in the electricity market. A bulk electricity exchange market has emerged providing
for rivalry and incentives to firms for cost reduction and to gain market share. Within the
wholesale market where prices are determined by constant bidding, inefficient plant may remain
idle at a given demand level. There is therefore, the incentive to reduce cost to increase market
share. Maximising the benefits from generation will, however, require pricing policies, which
accurately reflect transmission congestion and the cost of generation at different peak times.
Efficiency gains from competition manifest at two levels, over the short run and over the long run.
In the short run there will be increased utilisation of excess capacity from superior operation and
maintenance of existing plants, from increased labour productivity, and in some cases, from better
allocation of generation across plants with different costs. In the longer term competition
facilitates better investment decisions regarding the amount, mix and speed of construction of new
26
plant. Allowing competition in the electricity utility industry does, however, brings tension in that
the lowering of prices may lead to stranded costs82.
The dynamics of international events and the resolution of economic problems in developing
countries call for profound new policy approaches to the electricity and utility sector. The nation
state economy, whereby governments largely control the forces of economic progress within its
borders no longer applies in the new millennium. Globalisation has been exerting greater pressure
for international competition and more and more governments are recognising that electric utility
can no longer be allowed to operate with prices, which are substantially higher than those
confronting their international competitors.
Electricity Industry Structural Models
Various writers have advanced different approaches to models of electricity industry restructuring.
Invariably the models reflect the different approaches to the trading arrangements adopted the
degree of physical restructuring undertaken or the level of competition accommodated. Joskow
(1997)
83
identifies a two-structure model, consisting of a “portfolio manager model” and a
“customer choice model”, essentially based on the trading arrangements. For Joskow under the
former:
“the local distribution utility retains its traditional obligation to supply customers
in its de facto exclusive franchise areas with bundled retail service, at regulated
prices, but relies on competitive procurement mechanism to buy electricity from
the lowest cost suppliers in competitive wholesale markets rather than building new
generating facilities”.
It was intended to accommodate the entry and growth of IPPs, while allowing the incumbent
utility to retain end users as captive customers. It does not require major physical restructuring of
the industry. There is still a major oversight role retained for the regulator. In addition to
regulating retail prices, the regulator may be required to supervise the incumbent utility’s
competitive procurement of new generating capacity.
In the customer choice approach or “retail wheeling” Joskow explains that:
27
“retail customers can access the wholesale market directly by purchasing
unbundled distribution and transmission services from their local utility.
Individual customers take on the obligation to arrange their own generating service
supplies with independent competing electricity suppliers”.
Under this model, generators can sell energy in a competitive spot market as well as through longterm bilateral contracts with intermediary traders or direct with retail consumers. The local
distributor or incumbent utility is required to grant open access to the distribution system and in
return charge prices determined by the regulator for “wire services” and for metering.
An
independent network operator may be required to operate the transmission system, which in turn
is also required to provide open access to the transmission wires at regulated wire service price and
be responsible for system control and dispatch. At a minimum, financial unbundling of the
incumbent utilities transmission and distribution system is required, however, because there is
likely to be self-dealing and conflicts of interest, vertical unbundling of transmission and
distribution is preferable.
In terms of transmission pricing, Joskow84 refers also to two models, a tradable physical rights
model and a nodal pricing model. Under the tradable rights formula the available transmission
capacity (ATC) is determined using power flow computer models based on a variety of system
conditions and reliability. ATC is essentially the capacity a specific transmission interface has to
accommodate generator schedules for 24 hours 365 days a year, with high probability. The rights
to use the ATC over a “contract path” from a set of injection points to one or more injection
points on the network are then traded to potential buyers. If the demand to use an interface rises
beyond the capacity of ATC at the preferred schedules, the price for the fixed quantity of rights to
use that interface will rise to balance supply with demand.
The major problem encountered with this approach is that it is difficult to define a full set of
contingent delivery and receipt of property rights from one point to the other given the nature of
electricity. The property rights model, however, is said to afford maximum freedom of individual
suppliers to structure transactions and minimises the role of the network operator, as the network
operator is not required to participate in the bulk electricity trading transactions or in determining
market prices for energy. The independent operator’s role is limited to maintaining the physical
28
integrity of the system, enforcing transmission rights rules, managing conflict, scheduling
generation and actual capacity of the network and measuring and settling imbalances.
In the nodal pricing model the network operator is required to run a set of day-ahead and hourahead auction markets for bulk electricity, along with ancillary services and uses the bids submitted
to derive a “least cost” merit order generator dispatch schedule that matches demand and supply
and which defines market clearing prices at each supply and demand node on the network,
consistent with operating constraints. On the demand side customers articulate their willingness to
pay for electricity, which includes willingness to contract or expand their use at different times as
price varies. Node pricing is said to be superior to tradable rights in one respect, in that it solves
the externality problem that arises when congestion of the transmission system becomes important
and hence provides for efficient allocation of scarce transmission capacity. The nodal pricing
approach calls for a more active and central role for the network operator in the energy market,
when compared to the tradable rights approach.
Resale of capacity rights on a non-discriminatory basis to enable competition in network facilities
such as transmission system maybe theoretically possible, but in practice it has been found to be
difficult to define, adjust and enforce such access or capacity rights in a manner that would
facilitate competition in power systems. Power flows through a network according the path of
least resistance, with the result that what capacity is used or unused at any moment in any part of
the power system is a function of all the physical flows throughout the system and not a function
of bargaining or individual transmission decisions.
Rather than adopt tradable property rights as a basis for transmission pricing most systems have
resorted to central dispatch that optimises the flows instantaneously matching supply with demand.
The effect of this arrangement is that winning bidders will always have their supplies dispatched in
a non-discriminatory basis and, therefore, eliminate the need to compensate holders of capacity
rights for the effects of power flows, or available capacity.
A related problem is who should be responsible for transmission investments to increase
transmission capacity? In transmission supply the problem of “free rider” arises. There are two
questions which must be addressed, who should identify the expansion opportunities and who
29
should pay? Broadly there have been two suggestions, either to rely primarily on all the private
parties (or group of the parties) to propose and pay for upgrades and investments or alternatively
require the network operator to identify the needed investments and share the costs amongst those
who are required to use the expansion. The public policy direction often taken has been to delegate
the responsibility to identify the expansion or upgrade capacity needs to the systems operator as
well as the construction activity, with the requirement for the associated costs to be recovered
from all network users. There is, however, the need to guard against over-investment or underinvestment in an unbundled transmission system.
Tenenbaum, Lock and Barker (1992) 85 writing two years after the radical industry restructuring in
England and Wales and the introduction of one of the first bulk electricity exchange markets,
recognized a four model basic industry structure; classified as Models One, Two, Three and Four.
Under Model One, the industry is characterised by the traditional horizontal and vertical industry
structure, either privately owned and regulated by cost of service rate of return regulation or if
publicly owned, normally with self-regulation and usually serving a well defined or exclusive
franchise region or the nation as a whole. This structure does not provide for competition, nor are
there sufficient incentives for efficiency enhancing behaviour. It is based on the concept that the
electricity industry is a natural monopoly with economies of scale and scope.
Under Model Two, the integrated and horizontal industry structure is usually retained; however,
competitive procurement of new generation capacity is introduced. In essence the monopoly
status of generation is removed and this sector of the industry is liberalised, allowing for
incremental or entry competition through independent power producers.
In the model two structure some of the traditional risks; construction risk, non-fuel operating risks
and reliability risks remain with the IPP or are off loaded at a cost to some other party, with the
purchasing company assuming the demand and fuel price risks. While the seller or IPP is exempted
from regulation the purchase of new capacity requires independent supervision to ensure that
purchases are made on a transparent and competitive basis. The transmission and distribution
sectors in the model two-industry structure continue to require heavy-handed regulation.
30
Model two adopts contracts, which substitute for integration of generation and transmission within
the single utility however contracts create transaction costs. Tenenbaum et. al.86 in their 1989 raise
the matter as follows:
“The issues, then, is one of vertical integration: is it more efficient for generation
and transmission and distribution to be under one ownership? Economic theory
gives no definitive answer nor has there been any empirical study that directly
addresses this question for the electricity industry”.
The general view, however, and especially since the UK experiences of the 1990s is that it is more
efficient to unbundle the integrated utility so as to guard against market power.
Model Three involves the development of a wholesale electricity market, whereby distributors and
traders are allowed to buy bulk or high voltage electricity as a separately traded product from
distant generators. It is very difficult, however, to regulate against discriminatory behaviour when
the integrated utility runs the transmission system. In order to address this problem separate
ownership of the system operation is required. One of the mechanisms considered in the USA is
for the transmission system to be operated by an independent entity under contract.
It still raises the question as to whether the system’s operator can be truly independent, while
owned by the integrated utility or by regional distributors as the incentive to exercise market power
remains. Therefore, there is a strong case for functional unbundling over operational unbundling.
It eliminates the regulatory cost of enforcing behavioural rules.
Under Model Four, functional separation of the industry into generation transmission, distribution
and retail sectors is introduced along with the imposition of common carrier conditions on the
distribution and transmission systems. Further separation of supply from distribution wire services
allows for increased competition at the retail level.
Hunt and Shuttleworth (1996) 87 also recognize a four-model industry structure, based on varying
degrees of monopoly, competition and customer choice as afforded under each structure and state
that:
31
“From the point of view of competition in product market there are really only four
fundamentally different ways of structuring the industry although there are many
possible variations of each”.
The four industry structures are classified as monopoly, purchasing agency, wholesale competition
and retail competition models. There are many similarities between the characteristics of each of
the structural models presented by both groups of writers.
The Wholesale Bulk Electricity Markets
The development of bulk electricity wholesale markets has been one of the major new innovations
that have been transforming the electricity industry. The wholesale market for bulk electricity is
also central to the development of a competitive retail market as demonstrated in New Zealand in
1993.
New Zealand tried to develop a competitive retail market before a functioning bulk
wholesale market and the result proved to be failure.
The critical design issue in developing a bulk electricity market resolves around the creation of an
electricity industry in which the generating sector is at the same time effectively competitive and
efficiently integrated with the monopoly transmission sector and the system co-ordination
function, whilst providing deterrence against the exercise of market power. The strong vertical
relationship between generation and transmission, despite physical unbundling makes it impossible
for a decentralised market to manage physical electricity efficiently. There is, therefore, the need
for a centralised market clearing process, analogous to those used in commodity and financial
markets, to collect offers to buy and sell at various prices, determine market clearing prices for a
specified period, give delivery instructions to sellers whose offers have been accepted and settle
payments among traders. Ruff88 states that:
“The only practical way to organise such markets in physical electricity is to
integrate them with central dispatch, pooling and economy trading process - the
process that utilities use now individually and in pools to manage their own
trading”.
A system operator is, therefore required, whose function is to collect cost and demand data,
determines and offers least cost dispatches and issues dispatch instructions. The market
32
mechanism seeks to ensure that the vertical integration of generation and transmission, which is
vital to ensure integrity of the system and electricity equilibrium in the sense of supply and demand
balance, is maintained at every node in the network. Since random supply and demand shocks can
happen very suddenly, faster than traders could conceivably respond to price signals, equilibrium
requires central control. A fully decentralised market transactional system cannot meet the
technological needs for continuous equilibrium. The most important requirement, therefore, for
an efficient bulk electricity market, both in terms of achieving economically efficient outcomes and
maintaining the security of the system, is that of ensuring effective energy balancing. How energy
is balanced and who carries out the balancing is critical to operational and economic efficiencies of
the system.
Energy balancing is closely related to whether despatching is centrally coordinated and is associated
with mandatory or compulsory requirements as well as to whether participants are able to selfdispatch and energy markets are voluntary. Two types of bulk electricity market designs have,
therefore, emerged; centralised (gross) and often mandatory power pool, based on the experiences
of England and Wales, and the balancing trade or (net) power pool based on the experiences of the
Nordic countries which provides for bilateral contracting between participants in the market.
The main difference between the two market designs is the importance assigned to the spot market
and the dispatch process. The mandatory power pool attaches more importance to the spot market
and requires all trades to be compulsory and carried out through the pool, whilst the bilateral
trading and balancing market design allows unregulated parties to organise their own decisions.
Two schools of thought have developed and there is very strong support for each of the two
designs.
Ruff 199289, Hogan 199290 , Hogan 199491 for example argue that the only practical way to
internalise the real-time network externalities that otherwise make competition in electricity
markets unacceptably inefficient and unrealisable is the power pool. The economic argument for a
single mandatory pool is that it is considered to be efficient. A centralised dispatch process ensures
that physical constraints permitting, the lowest cost available plant is always dispatched based on
the principle of economic merit order. Without integration of the spot market with dispatch in
33
real-time these commentators argue it will not be possible to internalise the externalities in the
operation of electricity grids and competition will be weakened.
The proponents of the bilateral trading and balancing market concept do not accept this thesis and
emphasise the danger of having a monopolist that controls dispatch and whose first priority is that
of a systems reliability implementing market. For the bilateral traders the role of the systems
operator is to implement the orders received from market participants and to preserve systems
reliability. A multiplicity of entities are therefore, involved in scheduling output to follow load. In
the view of the bilateral traders, an efficient market should reflect more than the good intentions
and benefits of central dispatching and should be more like any other commodity market,
reflecting demand side processes and should also offer consumers’ choices. Bilateral trading and
balancing market provide for contractual freedom and commercially negotiated prices and this
should ensure that prices track costs, as generators seek out purchases for their power, suppliers
and consumers seek the most competitive terms from generators and traders enter markets,
therefore, increasing market liquidity. For the proponents of net pool, consumers’ choice and
freedom are the critical issues. Both sides, however, have come to accept the need for an
independent systems operator, whose function is that of coordination of the transmission grid
operation activities.
The transmission wire business and the grid control process may also be structured into two
distinct areas of operation to be handled by two separate entities. In one model the transmission
operator is only required to provide transportation wire and related services and is neutral to the
market (does not trade in bulk electricity). The functions of systems control, market operation and
settlement payment arrangements are assigned to another entity. In the second approach the
transmission operator is required to perform all the above listed functions. The former approach
allows the transmission operator to concentrate on its core function, which is very important for
system supply, and minimises the opportunity to exercise market power or the opportunity to be
engaged in discriminatory behaviour.
The method of price discovery in the spot market also can either be cost based, as is the case with
Chile which has developed to be popular in a number of the newly reforming Latin American
markets or price based as was the case with the initial England and Wales market. In cost based
34
pricing the properties of the firm’s cost function are used to set prices. Cost based pricing generally
ignores social welfare considerations and even if they are market clearing, they may send incorrect
signals about incremental costs of production and incorrect incentives to the firm.
The cost base model, popularised in Latin America is derived from the generators actual or
estimated costs and the dispatching procedures represent an extension of the pre-reform merit
order procedures. The advantage of a cost based system, provided generators do not disguise their
costs, is that it ensures efficient dispatch, makes it difficult for generators to exercise market power
and is relatively easier to implement.
European power markets, however, have not favoured cost based approaches and maintain that it
provides weak incentives for efficiency. Instead, Europeans typically have opted for a price based
spot market price discovery system of England and Wales origin. In the price-based system the
systems marginal cost (SMC) determines the spot market price. The marginal cost of the bidder,
which clears the market in a given period, sets the system-selling price for that period.
Conclusions
The different structural models and market designs, which Tenenbaum et al and Hirst and
Shuttleworth described are characterised by different ownership arrangements, different levels of
industry integration and a variety of different features in their trading arrangements. The defining
features, which distinguish the respective structural options which have been advanced by the
different writers, are that under Model One traders and consumers are denied choice. With Model
Two, choice is afforded to the single purchaser and competition essentially is for incremental
capacity. With Model Three, choice is extended to the distributors and other traders and
competition is extended from competition for the market to product market competition for bulk
supplies. Under Model Four choice, is further extended to retailers and all end users, with full
competition throughout the electricity production and supply chain.
What is apparent is that the electricity supply industry that has emerged in the 1990s has been
developing through four distinct phases or four distinct structural models of operation. It remains
35
to define these phases more explicitly, determine whether the transformations of the individual
markets follow any particular pattern, if there are variations in the transformation process and if so,
what are these variations and what accounts for the differences?
The two main conclusions that can be drawn from the preceding review are that in addition to
major technological developments, utility economics has fundamentally changed since the 1990s, a
change which is having major effects on society. For over one hundred years utility regulation,
especially the United States brand has had as its central objective the prevention of new entrants to
markets and the preservation of the monopoly status quo. Originating in Chile in the 1980s and
expressly advanced in the United Kingdom in the 1990s, utility regulation no longer seeks to
inhibit or prevent entry to the once traditionally recognised natural monopoly industries. A more
forceful and dynamic objective of utility regulation is to facilitate competition in the segments of
the industry where competition is possible and practical. The public policy implication of this
development is far reaching, in that in one and the same industry, public policy will have to address
market liberalisation, whilst at the same time addressing economic regulation.
Secondly, economies of scale are less of a determining factor as to the industry structure. In terms
of public policy governments now have the choice of several options as to the industry structure,
which can be accommodated. This choice revolves around the degree of competition that is seen
to be desirable or can be politically accommodated.
36
End Notes
1. Electricity networks are not switched networks like telephone or railways, where a supplier
makes a physical delivery of a particular product at point “A” and is then physically
transported to a specific customer at point “B”.
2. Douglas Gegax and Kennnth Nowotny, “Competition and the Electric Utility Industry: An
Evaluation”, Yale Journal of Regulation, Vol. 10, No. 1 (Winter 1993), p.71.
3. Paul L. Joskow and Richard Schmalensee, Markets for Power: An Analysis of Electric
Utility Deregulation, Cambridge, MIT Press (1983), pp 59-77.
4. William J. Baumol, “On the Proper Cost Tests for Natural Monopoly in a Multi-Product
Industry” American Economic Review, Vol. 67 (1977), p.809.
5. William J. Baumol, John C. Panzar and Robert D. Willig, Contestable Markets and the
Theory of Industry Structure, San Diego, CA. Harcourt Brace Jovanovich (1982), p.170.
6. Gegax and Nowotny, op.cit. p. 67
7. Ibid., p.67.
8. Michael Klien, “Competition in Network Industries”, Washington, D.C., World Bank,
Policy Research Working Paper, No. 159 (1996), p.4.
9. Baumol, Panzer and Willig, op.cit, p. 815
10. External cost or externalities refer to costs and benefits expected or which arises from third
parties to a transaction.
11. Internalised cost or internalities refer to costs and benefits experienced from economic
activities that are not accounted for in terms of trade.
12. Oliver E. Williamson, “The Transaction-cost Economics: The Governance of Contractual
Relations”, Journal of Law and Economics, Vol.22 (1979), p.234.
13. Paul L. Jaskow, “Restructuring, Competition and Regulatory Reform in the US Electricity
Sector”, Journal of Economic Perspectives, Vol. 11, No. 3 (Summer 1997), p. 122.
14. M.E. Beesley and S.C. Littlechild, “Privatisation, Principles, Problems and Priorities”, in
Privatisation, Regulation and Deregulation, ed., M.E. Beesely, London, Routledge
(1997), p.30.
15. Paul L. Joskow, “The Evolution of Independent Power Sector and Competitive
Procurement of New Generating Capacity”, Research in Law and Economics, Vol. 13
(1991)), p.64. PURPA’s decision that US utilities were to be required to buy bulk electricity
from renewable and co-generation sources led to the entry of new players; qualifying
37
facilitates and independent power producers to the industry for the first time. PURPA’s
decision, however, was based more on the desire to reduce dependence on imported fuel
oil and encourage renewable energy sources as part of a wider environmental policy
initiative, rather than a policy initiative to restructure the industry.
16. IPPs were not restricted to fuel efficiency targets. Technically they are public utilities under
the Federal Energy Act; however, their regulatory reporting requirements have been
waived, giving them considerable flexibility.
17. Mathew White, “Power Struggles: Explaining Deregulatory Reforms in Electricity
Markets”, Brookings Papers: Micro-economic Activities (1996), p.215.
18. The impact of CCGG technology on the electricity industry is almost as profound as the
impact of the new telecommunication technologies; wireless, fibre optics and satellite
transmission on the telecommunications industry. The single product telephone natural
monopoly industry has been replaced by a competitive multi-product industry. The cost of
entry and minimum scale operation has been significantly lowered.
19. J.D. Glen, Private Sector Electricity in Developing Countries – Supply and Demand,
Washington D.C., IFC Working Paper No.15 (1992), p.8
20. William Baumol, “Contestable Markets: An Uprising in the Theory of
Structure”, American Economic Review, Vol. 72, No. 1 (1982), p. 3.
Industrial
21. Bernard Tenenbaum, Reinier Lock and James R. Barker, Electricity, Privatisation:
Structural, Competitive and Regulatory Options, , Oxford, Butterworth Heinemann
(1992), p.13. Transmission is typically distinguished from the “Wires business” of
distribution on a somewhat arbitrary basis that of the voltage level of the transmission of
power. The transmission wires tend to refer to the high voltage transportation lines, with
the distribution wires being considered as the low voltage lines to the end users.
22. Paul L. Joskow, “Regulatory Failure, Regulatory Reform and Structural Change, in
Electrical Power Industry”, Brookings Paper: Micro-Economic Activities (1989) ,
p.142.
23. John Vickers and George Yarrow, Privatisation: an Economic Analysis, Cambridge,
Mass.MIT Press (1988), p.300. Vickers and Yarrow further state that even if the
economics of replication and co-location are accepted there is little evidence to support
minimum efficient scale of 50000 MW, the England & Wales system being 52400 MW in
1987. The continued success of smaller companies in countries such as the Nordic with
more fragmented bulk electricity markets are evidence that the single firm argument was
never entirely valid.
24. L.R. Christensen and William H. Greene, “Economies of Scale in US Electric Power
Generation”, Journal of Political Economy, Vol. 84 (1976), p.655.
38
25. S.E. Atkinson and Robert Halvorsen, “Parametric Efficiency Tests: The Economies of
Scale and Input Demand in US Electric Power Generation”, International Economics
Review (1984), Vol. 25 p.647,
26. World Bank, World Bank Development Report 1994: Infrastructure
Development, New York, Oxford University Press, (1994), p.116,
For
27. Louis De A’lessi, “The Economics of Property Rights: A Review of the Evidence”,
Research in Law and Economics, Vol. 2 (1980), pp.1-47.
28. Armen A., Alchain, “Some Economics of Property Rights”, 11 Politico, Vol. 30 (1965),
pp.816-29.
29. Harold Demsetz, “Some Aspects of Property Rights, Journal of Law and Economics,
Vol. 7 (1966), pp.61-70.
30. Eirik Furubotn and Svetozar Pejovich, “Property Rights and Economic Theory: A Survey
of Recent Literature”, Journal of Economic Literature, Vol. 10, No.4 (1972), pp.11371162.
31. Ray Rees, “The Theory of Principal Agents”, Bulletin of Economic Research, Vol. 37,
No. 1 (January 1985), Part 1 and Part 2, pp.1-26 and pp.75-95.
32. Michael C. Jensen and William H. Meckling, “The Theory of the Firm: Managerial
Behaviour, Agency Costs and Ownership Structure”, Journal of Financial Economics,
Vol. 3. No. 4 (1976), pp. 305-360.
33. V. Aharoni, The Evaluation and Management of State Owned Enterprises,
Cambridge, Mass, Ballinger (1986).
34. Dieter Bös, Public Enterprise Economics: Theory and Application, New York,
North-Holland (1986).
35. David Parker and Stephen Martin, Assessing the Impact of Privatisation on Company
Efficiency, London, Centre for the Study of Regulated Industries (1996).
36. Williamson, op.cit., pp.233-262.
37. Douglas C. North, The Structure and Change in Economic History, New York,
Norton (1981).
38. G. Tullock, The Politics of Bureaucracy, Washington, Public Affairs Press (1965).
39. William Niskanen, Bureaucracy and Representative Government, Chicago, Aldine
Atherton (1971).
39
40. J.M. Buchanan, et.al., The Economics of Politics, London, Institute of Economic
Affairs, Readings No. 18 (1978).
41. W.C. Mitchell, Government As It Is, London, Institute of Economic Affairs, Hobart
Paper No. 109 (1998).
42. Principal and agency theory states that social and political life can be understood as a series
of contracts in which one party, the principal enters into contract with another party the
agent. The agent agrees to perform various functions for the principal; in exchange the
principal agrees to reward the agent. In private firms managers are said to be the agent,
acting on behalf of the shareholders, the principal. The shareholder or principal needs to
provide incentives for the agent to maximise the welfare of the principal. The theory also
assumes individuals are rational, self-interested and are utility maximisers. Incentives are
said to be stronger in private firms, than in public firms, partly because of the problem of
defining the principal.
43. Beesley and Littlechild, op.cit, pp.28-29.
44. Property rights deal with the allocation of contractual rights (cost and benefits) among
participants in a transaction. There is greater incentive to the individual to maximise
welfare under individual property rights than under common property rights.
45. Public choice claims that all human behaviour is dominated by self-interest, i.e. rational
utility maximises, and accordingly politicians and bureaucrats will peruse their own interest
at the expense of the common good of the wider public. Politicians and bureaucrats are
sometimes accused of capturing the regulatory process against the interest of the powerful
utility suppliers, against the interests of the wider consuming public.
46. Wolfgang Friedmann, Public and Private Enterprise in Mixed Economies. London,
Stephens and Sons (1974), p.382.
47. Scot E. Atkinson and Robert Halvorson, “The Relative Efficiency of Public and Private
Firms in a Regulated Environment: The Case of US Electric Utilities”, Journal of Public
Economics, Vol. 1, No. 29 (1986) pp.281-294.
48. Anthony Boardman and Aidan Vining, “Ownership and Performance in Competitive
Environments: A Comparison of Private, Mixed, and State Owned Enterprises”, Journal
of Law and Economics, Vol. 32 (1989) pp.1-33
49. Mathew Bishop and John Kay, “Privatisation in the United Kingdom: Lessons from
Experiences”, World Development Report 1989, Washington, D.C. (1989), pp.643-657
50. Mary Shirley and John Nellis, Public Enterprise Reform: The Lessons of Experience,
Washington. D.C., World Bank (1991). p.6
51. John Goodman and Gary Loveman, “Does Privatisation Serve Public Interest,” Harvard
Business Review, Boston, (November/December 1992), pp. 26-38.
40
52. Ahmed Galal, Leroy Jones, Pankaj Tandon and Ingo Vogelsong, Welfare Consequences
of Selling Public Enterprises: An Emperical Analysis, Oxford University Press (1994).
Pp 3-6 .
53. Sam Peltzman, “Pricing in Public and Private Enterprises: Electric Utilities in the United
States”, Journal of Law and Economics, Vol. 14 (1971), p 112.
54. William Megginson, Robert Nash and Mathias Van Randenborgh”, The Financial and
Operating Performance of Newly Privatised Firms: An International Emperial Analysis”,
The Journal of Finance, Vol.49, No.2 (1994), p. 448
55. World Bank, 1994, op. cit., p. 27
56. Beesley and Littlechild, op. cit., p.28
57. Michael Pollitt, Ownership and Performance in Electric Utilities, Oxford University
Press (1995), p. 185
58. G. Price and T.G. Weyman-Jones, Malmquist Indices of Productivity Changes in the
UK Gas Industry Before and After Privatisation, Loughborough, Loughborough
University Economics Research Paper, No. 93 (1993), p.12.
59. Subal C. Kumbhakar and Lennart Hjalmarsson, Relative Performance of Public and
Private Ownership in Swedish Electricity Retail Distribution 1970-1990, Gothenburg,
Sweden, Gothenburg University Working Paper (1994) p.12
60. Lennart Hjalmarsson and Ann Veirderpass, “Efficiency and Ownership in Swedish
Electricity Retail Distribution”, Journal of Productivity Analysis, Vol. 3, (1992 a and
1992 b) p. 21
61. Thomas J. Dilorenzo and Ralph Robinson, “Managerial Objectives Subject to Political
Market Constraints: Electric Utilities in the US”, Quarterly Review of Economics and
Business, Vol.22, No. 2 (1982),
62. R. Fare, S. Gosskopf and J. Logan, “The Relative Performance of Publicly Owned and
Privately Owned Electric Utilities”, Journal of Public Economics, Vol. 1, No. 26 (1985),
pp 89-106.
63. Leland G. Neuberg “Two Issues in Municipal Ownership of Electric Power Distribution
Systems”, Bell Journal of Economics, Vol. 8, No.1 (1977), pp. 303 – 323.
64. Thomas G. Moore, “The Effectiveness of Regulation of Electricity Utility Prices”,
Southern Economic Journal, Vol. 36, No. 4 (1970), pp. 365-375.
41
65. Daniel R. Hollas and Stanley Stansell, “An Examination of the Effect of Ownership Form
on Price Efficiency: Proprietary, Cooperative and Municipal Electric Utilities”, Southern
Economic Journal, Vol. 54 , No. 1 (1987) p.349
66. John Vickers and George Yarrow, “The Economic Perspective of Privatisation”, Journal
of Economic Perspectives, Vol. 5, No. 2 (1991), p.117
67. Boardman and Vining, op. cit., pp. 1-33
68. Beesley and Littlechild, op. cit., p. 28
69. UNCTAD, Competition and Public Utility, Geneva, UNCTAD (1997), p.8.
70. OECD, The Application of Competition Policy to the Electricity Sector, Paris,
OECD (1997), p. 140
71. George Stigler, “The Theory of Economic Regulation”, Bell Journal of Economics and
Management Science, Vol. 2 (1971) pp.3-12. The “Public Interest” or “Consumer
Protection” hypothesis states that the goal of regulation is to pursue the general good of
society see Richard Posner, “Theories of Economic Regulation”, Bell Journal of
Economics and Management Sciences, Vol.5 (1974) pp.335-358. This view has been
challenged by the “Capture School” which states that regulation is simple an arena in which
special interests contend to trade power for their own narrow interests, see Sam Peltzman,
“Towards a More General Theory of Regulation”, Journal of Law and Economics,
Vol.19, No.2 (1976), pp.211-239.
72. Beesley and Littlechild, op. cit., p.72.
73. Harvey Averch and Leyland L. Johnson, “Behaviour of the Firm under Regulatory
Constraint”, American Economic Review, Vol. 52 (1962), pp 1052 – 1069.
74. D, P. Baron and D. Besanko, “Regulation, Asymmetric Information and Auditing”, Rand
Journal of Economics, Vol. 13 (1984), pp. 447-470.
75. Harvey Leibenstien, “Allocative Efficiency Vs X-Efficiency”, American Economic
Review, Vol. 56 (1966), pp 392 – 415.
76. Thomas Wyman – Jones, “Problems of Yardstick Regulation in Electricity Distribution,”
in The Regulatory Challenge, eds., Mathew Bishop, John Kay and Colin Mayer, Oxford
University Press (1995)., pp 423-442.
77. Harold Demsetz, “Why Regulate Utilities”, Journal of Law and Economics, Vol. II
(1968), pp 59.
42
78. George Yarrow, “Privatisation. Restructuring and Regulatory: Reform in Electricity
Supply”, in Privatisation and Economic Performance, eds., Mathew Bishop, John Kay
and Colin Mayer, Oxford University Press (1994). ,pp. 65
79. George Yarrow, “Privatisation in Theory and Practice”, Economic Policy, Vol. 2 (1986),
pp 324-364.
80. Richard Caves, “Lessons From Privatisation in Britain: State Enterprise Behaviour, Public
Choice and Corporate Governance”, Journal of Economic Behaviour and
Organization, Vol.1. No. 13 (1990), pp. 145 – 169.
81. Mark Roberts, “Economies of Density and Size in the Production and Delivery of Electric
Power”, Journal of Land Economics. Vol. 62 (1986), p. 362. See also Salvanes G. Kjell
and Sigve Tjotta, Cost Differences in Electricity Distribution Industry, Bargen
University of Oslo (1990). Returns to network density covers the economics of increasing
production by increasing the amount of kWh produced when network is held fixed.
82. Gregory Sidak and Daniel Spulber, Deregulatory Takings and Regulatory Contract:
Competitive Transformation of Network Industries in the US, Cambridge University
Press (1997), p.29, Stranded costs are prior investments which turns out differently from
expected or where regulators or the state have been party to utilities building excess
capacity, sometimes with wrong technology. In unregulated markets the case of stranded
cost does not arise, as it would simply be another business risk. It recovers outlays
required by a regulator or state, which cannot be recouped under competitive condition.
83. Joskow, 1997, op. cit., p. 127.
84. Ibid., p. 130.
85. Tenenbaum, Lock and Barker, op. cit., p.9.
86. Ibid., p. 32.
87. Sally Hunt and Graham Shuttleworth, Competition and Choice in Electricity, New
York, John Wiley and Sons (1996), p. 21.
88. Larry E. Ruff, “Stop Wheeling and Start Dealing: The Transmission Dilemma” in
Electricity Transmission Pricing and Technology, eds., Michael Enhorn and Ralph
Saggidi, Netherlands, Kluwer Publishers (1994), p.4.
89. Larry Ruff, Competitive Electricity Markets: Economic, Legal and Practical
Implications, International Association of Energy Economics Workshop. Toures, France
(1992), p.8.
90. William Hogan, “Contract Networks For Electricity Power Transmission”, Journal of
Regulatory Economics, Vol. 4, No. 3 (1992), p. 215
43
91. William Hogan, “A Wholesale Pool Spot Market Must be Administered by the
Independent System Operator: Avoiding the Separation Fallacy”, Electricity Journal
(June 1994), pp.26-48.
44
Chapter 2
A Four Phase Development Model for Electricity Markets
Four Phase Development Model
In this section a model consisting of four phases of development, including the traditional franchise
monopoly phase is presented. The basic argument of this thesis is that both technological and
market pressures are forcing a movement away from the natural monopoly, vertically and
horizontally integrated utility structure to new structures which allow for increased levels of
competition and private ownership.
The new structures tend to fall into three phases of development; the purchasing agent phase, the
bulk wholesale electricity market phase and the retail competition or consumer choice phase. These
phases will provide the template to evaluate developments in electricity markets, which have moved
away or are moving away from the franchised monopoly phase. In the latter sections, the cases of
selected countries that have or have been trying to move away from the franchise monopoly phase
are presented.
The aim is to evaluate the extent to which the developments in these countries are characterised by
the features exhibited by the three new stages of development, which have been presented, and to
identify the forces, which account for any variation along the development path. Is there evidence to
support the view that emerging electricity markets are required to go through these three phases of
development?
The discussion will also focus on the factors, which constrain the development of the electricity
market, especially smaller markets from moving from one phase to the next and clarify under what
circumstance is it possible to make the change without going through all the three stages
sequentially.
Structural changes and development in the electricity industry can be seen as a form of institutional
development, wherein an industry structure responds to competitive pressures. The indusry,
45
therefore, moves from one stage to the next over time to respond to competitive pressures, which
emerge in the system.
The Case Study Method as the Research Strategy
Reliance has been placed on the case study method as the chief investigative technique.
The case method (or multiple case studies as used in this investigation) is a distinctive form of empirical
enquiry that is extensively used in the social sciences–sociology, political sciences and anthropology, as
well as practice oriented fields such as urban planning, social work and public policy. It is a frequent
mode of thesis and dissertation research in all these disciplines and fields, Robert Yin (1981b) .The case
study as a research tool, should be distinguished from the case study as a teaching device popularised in
the fields of business, law and medicine.
It is a method of inquiry that investigates a contemporary phenomenon within the real life context,
especially when the boundaries between the phenomenon and the context are not clearly evident. It
allows the investigator to retain the holistic and meaningful characteristics of real life events such as
institutional and organisational changes. It allows for exploratory, descriptive and explanatory
evaluations. Unlike the survey method, the case method copes with technically distinct situations in
which there are many variables of interest than a particularly set of data points and as a result relies on
multiple sources of evidences which can combine the survey method as well.
The survey method can deal with context and phenomena; however, its carries certain limitations. In
survey design one constantly struggles to limit the number of variables to fall safely within a number of
respondents that can be analysed and to allow for mathematical manipulation of the data. The case
method is the preferred method when there is the need to understand complex social phenomena and
when examining contemporary events. It allows for observation of the events being studied and
interviews of persons involved in the events. Its unique advantage is that of its ability to deal with a
variety of evidence. The case can be a mix of quantitative and qualitative evidence as is the situation with
this study. The contrast between the qualitative and quantitative evidence does not distinguish the
various research strategies.
The selection of countries was not intended to reflect a random approach as in the survey method. The
selection is based on the need to demonstrate certain observations. The multiple case methods also
46
allow the investigator to make comparison and to draw conclusion from more than one context. The
UK was selected because it is made up of three distinct systems and each system presented different
strategies of reforms. The England and Wales system was the first to introduce radical restructuring.
Bolivia was selected because the argument in the early 1990s was that radical unbundling was not
possible in small system the size of 665 MW. The thesis was that economies of scale is not exhausted in
small systems and therefore moving through the competitive transformation process was more suited
for countries with large systems and mature markets
Jamaica on the other hand was selected because the policy makers rejected the thesis that small systems
could be unbundled without serious cost penalties. The view then was that the benefits from
competition would not be sufficient to compensate for the additional transaction costs and
diseconomies. The three Sub-Saharan countries were selected because they have all carried out extensive
reforms within the franchised monopoly phase without measurable success and as a result they have
declared their intentions to introduce higher levels of competition and under go radical unbundling. It is
therefore important to determine if there are lessons from the other case countries that could inform the
policy choices of these African governments.
In collecting the evidence visits were made to each country and quantitative and qualitative data
collected from privatisation units, regulatory agencies and the relevant public utilities. Additionally, in
the case of the African countries, it was possible to interview and collect data from public officials who
attended a series of workshops on utilities reform, which was held for African public officials by
Commonwealth Secretariat over the period 1999 to 2001. Evidence was therefore gathered from
documents, interviews based on guided questionnaires rather than structured queries, as well as
observations.
The unit of analysis adopted for the investigation is that of the electrical industry supply system. The
task then was to see to what extent the model explains the transformation through the four distinct
phases from the empirical evidences.
47
Model One Stage - Franchised Monopoly Phase
As the utilities under the pre-1980 environment were seen to be natural monopolies, there was the
fear that such firms would abuse their monopoly power and extort rents or monopoly profits from
the consumer who had no choice in the market. There was also the belief that every citizen has a
right to certain basic services and electricity was regarded as one such essential service that it was
unacceptable to provide supplies on the basis of profit and individual ability to pay: hence the public
policy of universal services for the utility industries. Most governments concluded that in such a
situation the state would be better disposed to protect consumer interests, resulting in wide spread
state ownership of the vertically integrated monopoly utility, consisting of generation, transmission,
distribution and retailing, all typically falling under one enterprise supported by self-regulation.
Electricity supply systems pre -1990 presents two structural variations. Fig. 3 below presents the
traditional vertically and horizontally integrated franchised industry publicly or privately owned,
which dominated the system after the 1950s.
.
Fig. 3
Franchised Monopoly Model Traditional Vertically Integrated Electric Utility
Generation
Retail
Customers
Coordination
Transmission
Reliability
Distribution
Dispatch
Source.See Note 2, p.102
Essentially, there have been two variations of franchised monopoly structure. In some markets, only
one single vertically and horizontally integrated utility is permitted, whilst in other markets there has
been a variation involving a “franchised multiple distribution system”. In this instance one
franchised vertically integrated Generation and Transmission Company provides bulk power, as is
the case of South Africa, New Zealand and England and Wales in pre-reform days.
The vertically integrated generation and transmission company is accompanied by multiple
franchised distribution enterprises, each operating in an exclusive zone and buys bulk power at bulk
48
tariff, fixed by an independent regulator or the state. In some markets like Bolivia and South Africa,
the integrated generation and distribution company is also permitted to own franchised distribution
businesses, either vertically integrated or as subsidiary companies. This franchised multiple
distribution structure is shown in Fig. 4 below. The pattern of electricity and financial flows under
phase one is shown in Fig. 5 below.
America and a few other countries such as certain Caribbean Islands up to the 1960s presented a
different ownership model, consisting of private ownership of the utility with independent
regulation to curb the monopolistic and rent seeking tendencies of the franchised integrated
utility. The defining feature at this stage of development is that of one single franchised
monopoly company dominating the market in a given area. In return for the monopoly status, a
universal service obligation is imposed, whereby the utility is required to provide energy to
everyone in the service area at a regulated tariff. Where the monopoly is privately owned
considerable problems of regulation are encountered.
Fig. 4
Franchised Multiple Distribution Structure
G&T
Generation
Transmission
Reliability
Dispatch
Coordination
Distribution
Distribution
Distribution
Retail Customers
Retail Customers
Retail Customers
49
Fig 5
Franchised Monopoly ( Phase I-Model One )
Integrated Industry Structure
G
G
G
G
G
G
G
Transmission
Distribution
Financial
Electricity
Examples
France EdF, Some
USA Investor
Owned Electricity
Utility,
•
Jamaica
Supply
C
C
C
C
C
C
C
Source, Note 2 Fig.4 and Fig. 5, p.102
Where countries or regions have interconnected systems, marginal trading sometimes prevailed,
more as a back-up arrangement. Prices reflected the assumption of reciprocal trading and were not
intended to cover full cost of operation. Essentially, the price for “wheeling across” a utility
transmission system is based on variable cost with fixed cost borne by the selling utilities franchised
or captive customers. Under the franchised monopoly model the technology is dominated by
economies of size and scope with the result that large vertically integrated plants and horizontally
structured systems provided for lower cost of production. At this stage of development, neither
retailers nor final customers are allowed a choice as to source of supply.
This integrated monopoly, (especially when operated by private investors) creates the need for costly
regulatory structures to control monopoly power. Such regulations up to 1980 have essentially been
based on cost of service rate of return, as has been practiced widely in the USA. The US regulators;
the Public Utility Commissions, have established a tariff formula based on a test year, the period of
time under examination. Rates are then set using the historic test year, adjusted for known and
50
measurable changes. The process yields an adjusted test year cost of service that is meant to be a
predictor of a company’s revenue needs during the period rates will be effective2.
RR = E + d + T = [r(Y– D)]
Where
RR
=
Revenue requirement, or total revenues.
d
=
Annual depreciation expenses.
T
=
Taxes
E
=
Allowable expenses
Y
=
Original book value of plant in services.
D
=
Accumulated depreciation.
Note: Y-D = a net rate base.
r
=
Weighted average cost of capital.
Rates
=
RR/Volume of Sales
A less rigid formula has been used in many other countries; however, the principle reflects a cost of
service rate of return formula3. Rates are also determined annually creating the need for annual
reviews.
The overall objective is to set economically efficient prices, which should to the greatest extent
possible, reflect long run marginal cost of service, while enabling the utility a reasonable opportunity
to recover its legitimate cost of providing such services, including a rate of return on investment. A
problem faced by economic regulators is that historic cost incorporated by the utility to recover its
rates may only bear passing resemblance to forward – looking long-run marginal costs; (LRMC).
The reconciliation of the need to cover historic costs with the desire to set economically efficient
prices and to meet other objectives of regulation, such as fair price and universal service, requires
judgement and arbitrary decisions.
Marginal cost of service is expected to be the cost incurred to provide an additional unit of
consumption at a particular time and represents the cost to society to satisfy that incremental
demand. The nature of a monopolist, however, is that he will seek to set price above marginal cost,
which is in large measure an historic average cost. Setting prices strictly to equal marginal cost is
therefore, a problematic exercise and may be too high or too low depending on the quality of cost
information available (the information asymmetry problem) to the regulator.
Rate of return
51
regulation has produced perverse affects. Averch-Johnson states that rate of return regulation leads
to over capitalisation (gold plating) or the Averch-Johnson (1962) 4 effects.
Under the franchised utility model, operation of the electricity system often carries with it several
policy goals. These policy goals often reflect macro-economic and social development objectives,
such as to deliver low cost services to particular classes of customers. The net effect is crosssubsidisation which encourages inefficient consumption by subsidised customers, discourages
consumption by some users and distorts the pricing and rate structure, resulting in unfavourable
economic consequences, such as weak credit worthiness and reduction in the utility’s ability to
attract financing without cross-guarantees.
France today presents the best example of a country, which has remained at the model one stage and
has been reluctant to change, other than meet the minimum requirements of the European Union
(EU) recent directive5. Electricitè de France (EdF) up to 2001 was a one hundred percent publicly
owned (vertically and horizontally integrated) firm, with almost complete monopoly at all levels of
the production and supply chain. France has only initiated limited reforms and has shown no
willingness to privatise EdF, or even to sell a minority stake. There is still strong public support
amongst French citizens for a publicly owned and nationally integrated firm, providing public
service that is reliable and reasonably priced. EdF prices and quality of service compares favourably
with prices in other EU countries and the firm does not rely on public subsidy.
French historical commitment to a vertically and horizontally integrated system is partly due to
technological consideration; over 80% of generated capacity comes from nuclear power plants with
only 15% hydro-electric6.
Nuclear and hydroelectric technologies continue to benefit from
economies of scale and scope. There are also economies of coordination between nuclear and
hydroelectric plants. Nuclear power systems also present special problems. The low valuation, high
cost of decommissioning and increased risk associated with private operation, makes it difficult to
sell state owned nuclear plants. This, however, is becoming less so with improved efficiencies and
safer operation of the newer plants. Opportunities for privatisation have therefore improved. French
policy of uniform pricing with built in cross-subsidies, adds another factor, which will make it
difficult to introduce direct competition.
52
With a continued commitment to nuclear power, France will entertain only limited structural
changes to EdF. This is likely to involve access provision to the transmission and distribution system
and accounting ring fencing. The question, however, still remains as to how the French will
reconcile independent regulation with the continued desire for parliamentary control over utility
pricing. Again it can be seen that external pressure, is at play and it is this pressure in one form or
another which brings about changes from the franchised monopoly stage.
The American system although normally considered to be one of private investor owned utilities
with independent regulation does display more than one type of institutional arrangement.
Munasinghe and Sanghvi (1989)7 state that:
“contrary to commonly held views, the electric utility industry in the US is not
homogenously organised solely along the lines of private ownership and public
regulation, whereas investor owned utilities are dominant factor in the market, about
a fourth of the market is organised along the lines of public ownership”.
In 1989 there were a total of 3,456 systems in the US with 783,000 MW of capacity. Private
ownership represented 77% of generation capacity, serving 73 million of the 96 million connected
customers. The other systems are municipally or state owned, totalling 2200 with only 9% of
generation capacity as well as over 1000 co-operatives8. Typically all the municipal and co-operative
systems were distribution enterprises, buying power mainly in a wholesale bulk power market or
through long term power purchase contracts from the investor owned utilities.
Move Away from the Franchised Monopoly Phase
The development, which led to the move away from the franchised monopoly phase, was pointed
out in Chapter One to have started in 19789. Between 1985 and 1994 Qualifying Facilities and
Independent Power Producers’ (QF/IPP) generation accounted for an average of 39% of all new
capacity in the US. QF/IPP accounted for 43000 MW or 6% of US capacity in 1994 with a further
66000 MW under development in 1994. QF/IPP has offered US utilities a clear alternative for
acquiring new capacity10.
53
Despite these competitive market initiatives the 1992 Energy Policy Act of the USA limits FERC,
from issuing orders requiring a state utility to transport (retail wheeling) electricity to retail
customers. Again it is competitive pressure essentially the smaller and efficient CCGT plants that
have been fuelling the liberalisation movement in the electricity market in the USA. The
significantly reduced sunk cost associated with CCGT allows for several new entrants to the
generation sector. The generation market through “all-source” competitive procurement has,
therefore, become highly contestable in the USA.
A second feature, which has given impetus to change from the franchised monopoly structure, has
been the movement away from state ownership to private ownership. The popular experience of
the state controlled power sector has been high cost of production and in most developing countries
the experience has also been low levels of accessibility by householders. Under the traditional state
owned franchised monopoly electric utility structure there are no economic incentives to reduce cost
or to provide improved quality to the consumer. A change to private ownership on the other hand
provides the incentive for efficiency and the opportunity to subject the industry to the discipline of
product and financial markets. Privatisation also increases access to capital markets, thereby
removing one of the major constraints that have plagued publicly owned systems in developing
countries.
The state owned franchised monopoly utility also presents certain problems from being in the public
sector. Many countries in the 1970s and 1980s experienced considerable inflationary pressures. In
order to control inflation, governments were forced to introduce (often mandated by the
international lending agencies) monetary constraints on the utility with the result that the margin
between revenue and cost, already unbalanced in the electricity sector from under pricing to
favoured groups such as rural and household customers, over-manning, political patronage, theft of
electricity, and high levels of un-collectables is further squeezed and prices fall further below
properly accounted average economic costs, bringing on financial crisis in the electricity sector. The
electric utilities particularly in developing countries invariably recovered less than 60% of power
costs from revenues.
Newbery (1999)11, states that:
54
“Performance (public electric utilities in developing countries) was frequently
unimpressive, particularly in the high inflation period after the oil shocks of 1970s.
Prices were normally below long run marginal cost often despite excess demand, so
that investment could not be adequately financed out of profits as in many developed
countries. The average real power tariffs declined to below 4USc/kWh (1986
constant $) for 60 World Bank countries in 1989, while the rate of return on revalued
net fixed assets also declined to below 4% for a sample of 360 firms. Actual financial
rates of returns for 57 World Bank countries was well below the 10% rate of return
taken as the test discount rate by international agencies –-under pricing electricity resulted in heavy fiscal burden estimated at US$90 billion
annually or about 7% of total government revenues in developing countries, larger
than the annual power investment of US$80 billion”.
Similarly, Newbery and Greene (1996)12 found that in the UK the rate of return earned by the
Central Electricity Generating Board (CEGB) between 1948 and 1990
(the period between
nationalisation and privatisation) was less than 3%, although the test rate of return for the period
varied between 8-10%.
Further the accounting and financial systems of these utilities also came to be influenced by the
practices, which prevail in the public sector. Government budgeting in the public sector for example
is based on annual rounds of allocation and a utility dependent on the central budget for new and
replacement investment capital finds it difficult to undertake proper capital budgeting.
Many state owned utilities and their respective governments under the franchised monopoly phase
have sought to bring about improvements to the sector while maintaining state ownership by
adopting several private sector management techniques and management tools. Cordukes (1990)13
noted that the reforms in African countries started with the introduction of an affermage
arrangement in Cote d’Ivoire in 1990 and later in Senegal with a management performance contract.
These reforms often involve, increased levels of commercialisation, where the legal status of the
enterprise is changed from a government department to a statutory corporation or joint stock
company.
Increased autonomy is then provided to the management of the company, and
commercial objectives replace public interest objectives. Management performance contracts are
sometimes introduced with clear commercial objectives, reflected in a memorandum of
understandings or framework agreements, providing for a more structured relationship between the
enterprise and the state as to each party’s responsibilities. Government’s sometimes going further
55
and contract out management to an outside private sector firm, under some form of performance
based management contract.
In addition, welfare grounded economic concepts in the form of long-run marginal cost pricing, test
rate of discounts in line with low risk industries and hard budgets are further introduced to the
utilities. Rate rebalancing involving the elimination of cross-subsidies and concepts of peak and
capacity pricing are also adopted to provide for more relevant pricing practices. Several British
White Papers14 in 1961, 1967 and 1978, for example, sought to establish the basis of applying
marginal cost pricing to public utilities.
These measures often bring about some level of performance improvements; however, they have
proven to be unsustainable. They ignore essential questions of incentives and motivation and the
problem of public control, which still prevails over public finance. Hard budgets for example
address the symptoms of the problems, without addressing incentives for cost reduction and
prudent capital investment. A consequential effect is that the utility is starved of investment funds
with further adverse effects on plant availability. With persistent shortage of investment capital,
governments are forced to find other solutions to address the problems. In recent years the solution
has been to invite private investors to finance new capacity. This puts pressure on the system to
move to the next stage; the purchasing agency phase. Besant-Jones15 maintains that:
“private financing of power investments in a competitive market is feasible in a sound
business environment ------------ Power sector reform can yield huge productivity gains
particularly through dynamic efficiency gain under competitive pressure.”
Model Two Stage- The Purchasing Agent Phase
Under the purchasing agent phase the existing vertically integrated generation, transmission and
Distribution Company may continue to be owned by the existing state or private franchised
incumbent, with most or all of the new generation capacity to be added by IPPs. The IPPs contract
with the incumbent utility as a single purchaser in the form of power purchase agreements for new
capacity. The incumbent utility then resells the bulk power acquired from the IPP, along with its
own generated power to captive distributors.
56
The IPPs typically develop new generation on a project finance basis with highly leveraged
financing, involving very little equity (often below 20%). Bank finance, therefore, provides most of
the capital. As the Banks need to minimise their risks, various forms of guarantees have to be
provided by the single purchaser often including sovereign guarantees of the state. Where countries
have introduced the single purchaser phase without the required legislative framework, country and
regulatory risks will be perceived to be very high and the cost of the project will be high, as well as
the level of risk the state will be required to undertake. As long as the power sector remains strongly
dependent on political decisions, private investment in the sector will be perceived as very risky,
especially by foreign private investors. Although many IPP projects require sovereign guarantees to
mitigate these risks, experiences in the last few years of default on PPAs have reduced the value of
such sovereign guarantees.
The purchasing agent era marks the second phase of institutional development in the electricity
supply system; that of private generation for new capacity as independent power producers. Access
to the transmission and distribution wire, (except where bypass for the large customers is permitted)
is restricted, as generators must sell through the single purchasing agent. The purchasing agent
continues to maintain monopoly power over the network facilities and over sales to the final
consumer.
The defining feature of the second phase of development is one firm dominates the
market as a monopoly seller and monopsony buyer of bulk electricity.
There are a number of variations of the single purchaser model. Under one arrangement the single
purchaser acts as an active trader in the market, and is the sole purchaser and the sole seller, taking
responsibility for receipts and payments and the associated risks. Under another arrangement, the
single purchaser operates as a neutral agent, essentially as a facilitator and aggregator, with
contractual commitments and payments flows taking place directly between the generators and
distributors and other traders. A third variation is to allow for competition in the large end user
market. These large end users and or distributors are then permitted to enter into bilateral contracts
and purchase direct from generators and in so doing bypass the single purchaser or the franchised
vertically integrated incumbent utility. Under these circumstances, open access to the transmission
and distributions systems is required. Where other distributors are allowed to bypass the single
purchaser and contact directly with generators, the arrangement is then described as the principal
agent variation.
57
The transmission company may be separated out as the single purchaser, and organised as an active
participant in the market or as a neutral participant. If the transmission company as an active single
purchaser buys and sells in the market it is likely to be faced with liabilities far greater than its own
wires business. Generators will, therefore, seek cross-guarantees from the state in respect of such
payment risks.
The advantages of the active single purchaser model is that it permits load
aggregation and economies of scale in contracting, provides for a single bulk transfer price and the
trading arrangements are simpler. The active single purchaser limits the development of further
competition in the sector, especially opening of the market at the retail end. It also centralises
payment risks in one firm. A distribution company that fails to collect from its customers or has
high non-technical losses exposes the single purchaser to very high risks, without the single
purchaser being able to do anything directly to reduce the losses. As the sole purchaser, there are
also problems of independence and transparency and the sole purchaser may be vulnerable to
political pressure and corruption.
Where the single purchaser is neutral, he buys as a representative of the distribution companies (or
end users where this is allowed). In effect he acts as a load aggregator and performs a go-between
role (generators and distributors) in public tenders and contracting. Payment obligations and flows
are directly between the generators and the distributors. The advantages are that this arrangement
incorporates the knowledge of the distribution companies in the contracting process. As with the
active single purchaser it also facilitates load aggregation and a single bulk electricity price. The
trading rules remain simple; however, additional rules are required to define the limits of the rights
and responsibilities of the single purchaser and the distributors. The problems of transparency
although not eliminated is reduced.
In the Panamanian principal/purchaser arrangement the distributors are allowed to buy up to 15%
of their market needs directly from generators.
The advantage of the principal/purchaser
arrangement is that competitive pressures can be brought to bear upon the principal purchaser.
Where by-pass of the distributive system of the integrated incumbent utility is granted to large end
users then competitive pressures are also placed on the incumbent utility in respect of this liberalised
market segment. Alternatively, the transmission and distribution segments may be unbundled from
generation and incorporated as a single business to operate as the monopsony purchaser/principal
58
purchaser. The advantage of unbundling the integrated incumbent utility and separating
transmission from generation and distribution is that it facilitates a higher degree of competition in
later phases of the reform.
The important feature at this phase is that new capacity is subject to competitive bidding;
competition for market and additional capacity is acquired through long-term power purchase
agreement. Additionally, retail customers continue to remain captive to the integrated utility or the
franchised distributors, creating the need for significant levels of regulatory intervention.
Fig. 6 below shows the industry structure for the vertically integrated single utility, as the single
purchaser, whilst Fig. 7 shows the structure with the vertically integrated transmission and
distribution company, as the single purchaser with a horizontally unbundled generating sector. Fig. 8
shows the structure where transmission is vertically unbundled from generation and distribution and
with the transmission agency operating as the single purchaser. It is possible to establish only one
generating company and one distribution company upon separation, however, if the intention is to
increase competition, then generation and distribution should also be horizontally unbundled to
reduce market power, monopoly of information and problems of self-dealing.
Fig. 9 shows the electricity flows under the active single purchaser (vertically integrated utility),
whilst Fig. 10 shows the financial flows.
Fig 6
Purchasing Agent Model (a) US System after Liberalisation
Wholesale
Consumers
Distribution
Independent
Private
Investor
Owned
Wheeling
Transmission
Generation
IPP
IPP
Qualifying
Facilities
IPP
59
Fig.7
T&D as Single Purchaser (Horizontally Unbundled Generation)
Genco
Genco
Genco
Transmission
Distribution
Captive
Customer
Captive
Customer
Captive
Customer
Captive
Customer
Source: Fig 6 and 7 see Note 2, p.102
Fig. 8
Transco as Single Purchaser (Horizontally Unbundled Gencos and Discos
With Large Customer Bypass)
Genco
Genco
Genco
Transco
Disco
Captive
Customer
Disco
Captive
Customer
Disco
Free
Customer
60
Fig. 9
Single Purchaser (Phase Two) Industry Structure (electricity flows)
G
G
G
G
G
Transmission
G
G
Single Buyer
Disco
Disco
Disco
Supply
Supply
Supply
C
C
Northern
Ireland after
1990 reform
C
C
C
C
C
Source:Fig 8 and 9 see Note21 Page 102
Fig. 10
Single Purchaser (Phase 2-Model Two)
Industry Structure (Financial Flows)
G
G
G
G
G
Transmission
G
G
Single
Disco
Disco
Disco
Supply
Supply
Supply
C
Source: Note 2. p.102
C
C
C
C
C
C
61
Maintaining the vertically integrated utility as the single purchaser presents considerable problems
involving self-dealing and market power. Market power is the ability of the firm to earn economic
profits in the long run without inducing entry and the ability to raise prices above competitively
determined levels. Market share concentration and entry conditions are necessary but not sufficient
conditions of market power, there must be high probability of abuse of such power in the industry16.
The initial reforms should therefore, involve the vertical separation of transmission from generation
and distribution. The single purchaser model requires clear policies with respect of risk allocation,
and clear and enforceable contracts with a credit worthy purchaser.
If enforceability and credit worthiness are in doubt alternative forms of credit guarantees will be
needed, either in the form of sovereign guarantees with the state or cross-guarantees from other
credit-worthy sources. Risk must be allocated between the incumbent utility and the IPP developers
on the basis that the party that can most efficiently deal with risk or reduce it should bear such risk17.
The single purchaser phase requires continued heavy handed regulation over quality of services and
retail tariff. In addition, the regulator takes on a new role, that of creating the competitive conditions
for the provision of new capacity to the system. Where bypass is allowed, regulatory intervention
will also be needed to establish and ensure non-discriminatory access to the distribution and
transmission lines. A continued requirement for the single purchaser phase is that of integrated
resource planning to form the basis on which to evaluate future competitive bids and to provide a
framework for potential investors.
Bulk electricity prices offered by IPPs will generally reflect the cost of risk accepted by the IPP. The
more stable and predicable the market conditions the lower the prices. The principal risks are
currency payment and political, management and technology risks. IPPs receive payments in local
currency, yet many of the costs; such as fuel and capital are in foreign currency. The financial
strength of the single purchaser may be weak, especially where there are major problems with
collectables, creating the risk of default on payments. Many countries are politically unstable, and
experience frequent or sudden change of government, resulting in changes to the market rules.
Developers or strategic investors of IPP companies normally only take a minority equity stake in the
company and this increases the risk of management oversight.
62
Finally, the technology selected may not perform as originally expected. In general the greater the
risks borne by IPPs the higher the bulk electricity prices therefore if governments need lower prices,
then risk reduction through some form of sovereign guarantee from the state or cross-guarantee
from an international financial institution will be needed. IPP plants are usually implemented on the
basis of non-recourse financing18; the financing strength of the power purchase agreement is able to
show that the cash flows from the contract can meet all debt payments, hence the long term nature
of the contract; 10-15 years for CCGT plants and 25-30 years for hydro-plants. The length of the
plant’s life determines the expected payback period for the investment, with shorter repayable period
for CCGT plants.
Power purchase agreements have increasingly become more complex overtime19, in an attempt to
deal with all the many contingencies, such as providing for the IPP plants to be used more
efficiently, to provide for more flexibility as with a two part pricing system or provide for buyout
provisions or provisions which allow the purchaser to terminate the contract within a specific date
or to allow the debt/equity to take over more of the risks. Gardner and Maine (2000)20 state that:
“There are a growing number of examples where IPP merchant power plants are being
constructed without long-term contracts. In these cases IPPs who have sufficient
confidence in the economic, financial and operation of the electricity spot market or the
strength of retail competition will finance plants based on expected cash flows from
direct sales to retail customers to meet the debt repayment”.
This development is relatively recent and is unlikely to be an option available to developing
countries, because of their very poor risk ratings on international financial markets.
A problem faced by several developing countries with a small electricity market, is that they have
taken on board a number of IPPs in the mid-1990s in order to avoid radical structural changes to
the electricity industry and the introduction of retail price rebalancing, which are essential elements
of the reform process, for fear of adverse public reaction. The single purchaser for the PPAs is often
the existing inefficient integrated state owned utility. Both the utility and the portfolio ministry,
often do not possess the commercial skills and procurement experiences required in the
63
sophisticated negotiations involved in the development of the new contracts, with the net effect that
the utilities, on the basis of political pressure are forced to sign high priced or poorly designed PPAs
with elaborate payment guarantees that the Treasury can ill-afford21. An example of such a project is
the first PPA agreement in Tanzania. This contract eventually ended up at international arbitration
in order to resolve the dispute over the tariff, which should be paid by the utility to the developer.
Countries that fail to restructure and introduce IPPs into the system to co-exist with the
inefficient integrated utility not only create a number of problems22 but such countries may have
forfeited the option of a well structured single purchaser enabling environment which would
allow it to move to a more competitive bulk electricity market at a later stage. For efficient
production under the single purchaser phase, the appropriate trading protocols, and legislative
instruments will of necessity need to be developed and implemented, covering such matters as
competitive bidding and evaluation process, regulatory oversight of the incumbent utility’s
purchasing decisions, entrenchment of property rights and introduction of an independent
regulatory agency.
The single purchaser model trading arrangement normally involves contracts of “take and pay”
nature. These are contracts for sale of energy availability and other generation services from an
independent power producer and the obligation to pay remains even if the plant is not dispatched.
In earlier stages of contract development the energy price was based on the average cost of the
IPPs operation as it relates to a predetermined output or on the basis of the utility’s avoided cost.
If the IPP achieved this level of output its cost would be covered and profits earned. The
establishment of IPPs’ prices based on rolled in average cost (X/kWh), however, is an inefficient
way to structure the contractual arrangement. Where bidding for new capacity by IPPs for
example are through total embedded cost as in “take and pay” contracts, inefficient operations
will be encouraged as once entry takes place the plant is effectively fixed and there is no further
competitive pressure for the duration of the contract.
A more efficient pricing mechanism was later developed which limited the energy price to the
variable cost of the IPPs operation, combined with an availability charge where variable cost
represents fuel and other variable operating charges. The introduction of two-part pricing system
64
with a variable element provides an opportunity for the energy (or variable) price to play a key
element in economic dispatch and for competition to be improved23. With a system of economic
dispatch, IPPs with the lower variable costs are dispatched in order of merit and in so doing an
element of product market competition can be introduced. Two-part pricing also provides the
opportunity to ensure that the price components reflect underlying cost of the technology being
purchased. Hydro-plants display high fixed cost component and low variable component, whilst
CCGT plants display higher variable cost component to fixed cost.
Energy charges can be “one price” or different prices for different volumes. It may for example
separate start-up cost from “on-load” costs. It can also be fixed by a formula, which takes into
consideration the cost of fuel and the thermal efficiency of the plant. Fuel prices may then be
indexed to an external factor.
The availability payment in the two part pricing system is usually set to cover the capital and other
fixed costs not covered by the energy charge. These costs are incurred whether the plant operates or
not. Capacity charge is not normally subjected to escalation clauses. It is paid so as to have the plant
available if called upon to dispatch and is important to meet mid-merit and peak demand. A target
level of availability in terms of capacity is set for the year or for each hour in the year with a fixed
annual payment to be paid if the target output is achieved.
Adding incentives and penalties can include further sophistication. Other services may also be
procured such as reserve, reactive power, and emergency generation or production above normal
level. Often these are calculated as lump sum payments for willingness to perform each of the
respective service. Under the purchasing agent arrangement the distribution companies buy bulk
power at preset wholesale prices, established by a regulator. The regulator also sets the price to the
final customer or retail price. The IPPs under the purchasing agent phase are insulated from
technology and to a large extent market risks, hence there is less incentive for innovation. The
purchasing agent takes most of the market risks.
Newbery (1999)24 states that:
65
“the recent Asia financial crisis demonstrated the unsuitability of PPAs. East Asia
attracted US$80 billion in the power sector between 1994-1998, over half the total by
developing countries and substantially ahead of the only other major destination, Latin
America with $53 billion. In 1996, 68% of incremental power sector investments in
East Asia were financed by private capital and three quarters of the investment was in
greenfield projects, mostly new generating plants. In contrast most of the investment
in Latin America was for the purchase of divested publicly owned assets, with only onethird for financing new Greenfield capacity. Reforming countries in Latin America
restructured and unbundled their ESI’s and created electricity markets. In contrast,
East Asian countries invited private capital into generation through IPPs and
negligible restructuring and reform”.
The financial crisis of 1991 significantly impacted on the East Asian countries exchange rates and
their GDP growth rates and in turn the demand for electricity. The collapse of some of the
currencies resulted in a doubling in the domestic cost of electricity under the PPAs. The fall in
demand also meant some of the electricity was not then needed, however, the utilities were under
contract to meet the capacity payments. As the various East Asian governments were reluctant to
pass on the increased cost in higher prices for fear of adverse public reaction, the financial crisis was
transferred to the power sector. In Philippines the foreign debt of the state owned utility increased
to more than 20% of the national debt25, creating strong pressure to default on payment or
renegotiate the IPPs, and this further amplified the loss of confidence of foreign investors in the
country.
This form of private investment is equivalent to expensive foreign debt borrowed by government.
When embarked on a large-scale basis by a developing country, it disguises the extent of the foreign
debt exposure (the true cost is concealed in the PPAs). PPAs carry very high interest rates because
of their higher risks and private source of financing, compared to the lower World Bank (and in the
case of most African countries the much lower IDA interest rates) and softer payment terms, which
has been the typical form of financing expansion for state utilities under the franchised monopoly
phase. Introduction of IPPs, therefore, does not address the underlying problems of the electricity
sector.
66
The extent to which private investment from IPPs with the implicit debt incorporated in the
capacity payment and which is seen to offer a solution to the investment problems of developing
countries is now subject to a lot of questioning and as argued by Newbery (1999)26 the single
purchaser model serves to misallocate risks between the foreign investor and the domestic state
owned utility and is a poor substitute to traditional forms of financing electricity investments from
multi-national sources. It is also a poor substitute for competitive industry reforms.
There is no doubt that the single purchaser model offers certain advantages. It allows for certain
public policy objectives to be achieved, such as universal service obligation. It allows for continued
central planning of the system, and for competitive entry of potential investments from the private
sector to meet increased expansion needs, whilst it reduces funding requirement from the state and
can be structured as a transitional phase to increased levels of competition.
Its disadvantages are that investment is not market led, there is misallocation of risk between the
IPP and the domestic utility as shown in the East Asian experiences in 1998 and this could lead to
stranded costs, with the results that consumers or tax payers are required to meet the cost of
inappropriate investment decisions. There is still supply monopoly, choice is still restricted as the
distributors remain captive to the single purchaser and retail consumers remain captive to the
distributors.
Model Three Stage- Bulk Electricity Market Phase
Over time, the purchasing agent phase arrangement comes under pressure, from distributors who
seek to obtain direct access to the generators through open access to the transmission system. Open
access to the transmission network creates the requirement for new trading arrangements for bulk
electricity, and these become the defining features of the bulk electricity market phase. Distributors,
however, continue to maintain monopoly of supply to final customers in their service areas,
although a few large consumers may be allowed to bypass the distributors and buy in the wholesale
market or contract directly with generators. Most final consumers, (particularly household
consumers) however, continue to be denied choice in selecting the services needed.
67
The bulk electricity market structure imposes a requirement for transmission to be unbundled from
both generation and distribution, and for separate ownership structures at each of the three vertical
stages. Power purchase agreements are replaced by bulk power contracts (BPC) in which the
contracts simply hedge price risk. BPC are different from PPA in that a PPA specifies the particular
generating plant in question which is to supply the power, whereas a BPC specifies the node on the
network where power will be delivered and allows the seller to choose any availably source of
supply. This gives the seller more flexibility as he can sell the lowest cost source of power to meet a
given demand. He could choose not to supply from his own plant and source supply from the spot
market if the spot market is lower. It gives the supplier the option of “make or buy decisions”.
Accounting and operational separation are, however, feasible options but must be supported by
heavy-handed regulation. In accounting separation, separate accounts are required for the network
activities, which are then ring fenced. In operational separation, whilst physical unbundling takes
place, ownership remains unchanged, as is the case in the US where the transmission systems
continue to be owned by the investor utilities, however, transmission is separately organised as an
operator to provide the transmission services. PPAs can also be used under wholesale and retail
competition phase. A wholesaler or aggregator is, however, needed to combine a number of PPAs
with spot market purchases in order to assemble the volume of electricity required to service the
wholesale or retail market.
The trading arrangements under the bulk electricity market phase calls for an independent systems
operator (ISO), to carry the responsibility of keeping the frequency and voltage of the transmission
stable. The systems operation function can be combined with the functions involved in the
transmission of wires services as one organisation. Alternatively a separate organisation, a load
dispatch centre may be introduced to execute the systems control, and market administration
functions.
In order to ensure non-discriminatory behaviour international best practices now suggest that that
the transmission operator should be made neutral to the system and not normally be allowed to
trade in the bulk power market, in which case the transmission operator’s role is limited to that of
providing wire services and the execution of dispatch based on instructions received at a price
determined by the regulator. In the UK the dispatcher, transmission wire services and market
68
operator’s functions are all integrated into one firm, the National Grid Company. There is however,
the concern of self-dealing with integration of the three functions.
Hogan27 points out that: “the systems operator must be independent of the existing utilities and
other sellers and buyers in the market”. This requires ownership separation between generators
and transmission operators. Should the transmission company own generation, it is likely to favour
dispatch of its own generation over competitive plants to the detriment of suppliers and customers.
The privileged generators also will be under much less pressure to reduce cost and may not be the
least-cost source of dispatch.
In Victoria, Australia the market operator and the dispatcher’s
functions are integrated28. The bulk electricity market model is shown in Figure 11. Fig. 12 shows
the electricity flows and Fig. 13 shows the financial flows.
The level of regulation in this phase is much less than under the two previous phases, in effect the
nature of regulation changes with the emphasis being to ensure that market institutions, regulation
and market structures are introduced which provide for the greatest level of competition and the
greatest level of customer choice, including prices, service quality as well as provide for consumer
protection.
Economic regulation of the generation sector or for wholesale electricity is more to ensure that there
are transparent non-discriminatory rules and to control market power and reintegration rather than
that of price regulation. A market mechanism is developed to provide for price discovery. In the
self-regulated exchange, ownership of generation by the transmission company, as was the case
initially in Chile in the 1980s, makes the threat of entry less effective in holding down prices.
69
Fig. 11
Electricity Exchange Market Model
UK System Immediately after Privatisation
Reliability
Coordination
Power Pool
Generation
Company
N
A
T
I
O
N
A
L
Generation
Company
D
Captive
Consumers
D
D
Generation
Company
Captive
Consumers
D
G
R
I
D
French
System
Generation
Large
Consumers
free
D
Transmission
Distribution
Consumers
Source Note 2 p.102
Fig.12
Electricity Wholesale Market (Phase 3-Model
Three) Industry Structure (electricity flows)
G
G
G
G
G
C
Disco
Disco
Disco
Supply
Supply
Supply
C
C
G
Wholesale
Market
Transmission
Large
Customers
G
C
C
C
England &Wales
(Post 1990)
Argentina
(after1993)
Bolivia (After1996)
C
70
Source: Note 2,p.102
Fig.13
Electricity Wholesale Market (Phase 3- Mode Three)
Industry Structure (financial flows)
G
G
G
G
G
G
Wholesale
Market
Transmission
Large
Customers
C
G
Disco
Disco
Disco
Supply
Supply
Supply
Supply
C
C
C
C
C
C
Source: Note 2, Source p.102
The network characteristic also makes it difficult to provide transmission and distribution wire
services on a competitive basis. Invariable there is one transmission system, however the
transmission can be made neutral to the market. The distribution system at the same time can be
horizontally unbundled into regional companies to provide for yardstick competition.
The network element, the transmission segment and the distribution wires business remains a
natural monopoly, and the only competitive opportunity available is that of by-pass competition
involving the imposition of common carrier conditions on the transmission system. There is
therefore, the need for the unbundling of the competitive generation segment.
Preferably the generation business should be separated from the remaining core network element
and privatised. Generators are then in a better position to compete for the bulk electricity market.
71
The regulator is also in a better position to focus more attention on the network areas and to ensure
open access, competitive market conditions, and guard against the abuse of market power.
Continued integration provides a better environment for the utility to abuse its market power, to
impose its will on the market and to derive benefits from the control of valued resources; the
network assets and information.
Producers of generated electricity have a natural tendency to exercise market power or to engage in
collusive or gaming behaviour. Firms will exercise market power to reduce transaction costs. The
forces of vertical integration between generation and transmission remain strong, despite legal
instruments, which mandate physical separation. The desire for vertical integration and or long-term
contracts is therefore, a response to market risks and the need to reduce costs.
The introduction of a competitive bulk electricity market overcomes two problems associated with
both the franchised monopoly and single purchaser phases. It provides incentives for efficiency and
a mechanism for adequate but not excessive investment finance. A competitive bulk electricity
market forces firms to pursue initiatives which lead to cost reduction. It also ensures that expansion
reflects long run marginal costs, whenever investment is needed.
A series of fundamental and irreversible reforms to the industry structure and relationship must be
undertaken to introduce a competitive bulk electricity market29. Phases One and Two structures are
generally found to be inappropriate for such a market. The opportunity for free entry of private
ownership and investments into the sector must be made mandatory and cost reflective tariffs must
be introduced.
While a bulk electricity market is superior to that of the single purchaser arrangement in terms of the
superior price signals that it provides, it is often not the initial reform priorities in small developing
markets of Sub-Saharan African and many developing countries, starting from a base of low
accessibility (below 10%), pervasive under pricing, gross overstaffing, excessive cross-subsidisation,
widespread political and corrupt interference in operations and high levels of commercial losses,
involving theft of electricity or the high incidence of failure to make payments for electricity
supplied.
72
Markets also cannot operate unless there is reliable excess capacity in the system, which is a feature
absent in many developing countries’ electricity markets. New legislative frameworks, which support
private capital and property rights, are needed as well as new independent regulatory institutions that
have the confidence of private investors. Sub-Saharan Africa and many developing countries have
very low regulatory endowment and the culture of independent regulation is absent and both act as
major constraints to the introduction of power markets in these countries.
In sequencing the reform, it is necessary first to separate out the network monopoly of distribution
from the rest of the system and subject this sector to cost reflective tariffs. Second, the network
monopoly of transmission should be separated from generation to create the conditions for
regulated open access by third parties. Finally the horizontal unbundling of the generation sector
should be undertaken to create large enough numbers of competing generating companies to avoid
the problem of market power in the bulk electricity market. The importance of starting with
distribution is that commercial sustainability and viability must first be demonstrated at this end of
the market to provide the confidence of investment in transmission and generation.
Some countries have expressed preference for the transmission system to be retained under public
ownership. In such a situation, there will be the need to separate out the transmission wire service
function from the systems and market operation functions. Foreign investors are not likely to be
attracted to a system where the market is controlled by a state owned company. The case for initial
ownership of the transmission company is that this aspect of the industry previously was never
subject to any market arrangements, therefore, it is very difficult to value the business for sale. A
case in point was in the UK where the National Grid Company was valued at £2.3 billion in 1990
(the implied value of 1996 prices was £2.7 billon). In 1996 when the private owners floated the
shares on the stock market, the yield was £4.5 billion30.
Performa accounts of the unbundled transmission company are no substitutive for a number of
years of trading and valuation based on such revenue streams. Ownership of the transmission
company in developing countries could also present expansion problems, especially where
significant levels of investments are needed initially to reduce transmission constraints. Transmission
is capital intensive and developing countries may still find it difficult to raise the initial capital for
expansion, which is crucial to attract private investors to the sector.
73
In restructuring the generation sector the practice has developed of providing a set of vesting
contracts (3-7 years and more likely 5-7 years in developing countries) to be held between the new
privately owned generators and retail suppliers or between generators31. Vesting contracts provide
revenue certainty and reduce financial exposure during the transitional period, which may arise from
the veracity of spot markets or poorly designed markets. These contracts, also serve to limit
discretion of inexperienced regulators in the initial and uncertain years of the reform.
If the proportion of PPAs is significant, then these PPAs will need to be renegotiated to confirm to
more sensible distribution of risks. These contractual changes will be purely financial in nature, and
payment will not be contingent on dispatch of underlying plants. The difference between the capital
value of the new contracts and the original debt is a measure of the size of the stranded costs. The
stranded cost will need to be addressed: initially they will need to be taken over by the state or
alternatively the state will need to provide cross-guarantees.
The competitive bulk electricity market phase does not eliminate monopoly in the distribution and
retail supply end of the industry. The monopoly retail market (or non-liberalised retail market) will
need to be licensed with the obligation to supply all captive consumers in the respective franchise
areas.
Bulk Electricity Market Design Options
The bulk electricity market can be organised as either a power exchange or pool, with associated
markets for ancillary services. Sufficient numbers of generators will be needed or alternatively face
sufficiently strong threat of potential entry from new entrants so that they are unable to exercise
market power in the bulk electricity market. Suppliers and market participants should be free to buy
in the bulk electricity market or sign contracts with generators and sell to eligible customers and be
required to pay the cost of transporting electricity over the transmission system and for distribution
line services.
Two types of market arrangements; the centralised gross and often mandatory pool and the bilateral
contracts and balancing spot market or net pool are illustrated below. Fig. 14 below depicts the
74
centralised power pool, whilst Fig. 15 depicts the net pool. Australia, New Zealand, England and
Wales (pre-2000) and Spain adopted centralised markets, whilst Norway, Sweden, Finland and
England and Wales (post of 2000) adopted the net pool. Wholesale power markets, as shown earlier
are either cost based or price based as to the form of price discovery system. The price-based
system has found widespread support in the power markets of Latin America.
The design features of the transmission system also vary in respect of the institutional arrangements,
ownership structure, extent of dis-aggregation of transmission charges and the structure of
incentives provided to secure new investments and expansion of the system.
In Panama, Guatemala, El Salvador, Peru and New Zealand the transmission entity is structured, in
the form of a joint stock company, wholly owned by government. In Colombia, ownership is in the
hands of a joint public-private company, whereas in Argentina (7 transmission companies) Chile,
Bolivia and England and Wales, ownership is in the private sector.
The method of divestiture of transmission companies also varies. In Argentina, Brazil, Bolivia, Chile
and Peru divestiture is brought about by a long-term concession contract. Alternatively divestiture
may take the form of sale of assets or sale of shares as in the case of England and Wales. A third
approach is government ownership of the transmission assets, accompanied by an operating lease to
a private specialist investor and operator of the transmission business.
Balancing power market mechanisms can become extremely sophisticated, hence Besant-Jones and
Tenenbaum (2000)32 have suggested a simple balancing arrangement as an alternative to the more
sophisticated procedures. This procedure provides for large consumers and distributors to enter
into bilateral contracts with a generator for most of their needs and then engage one of the
generating companies or systems operators to meet the moment of moment fluctuation in demand.
Balancing is then performed by a contracted agent and not by a balancing spot market.
75
Fig. 14
Bulk Electricity-Mandatory Power Pool Design
Genco
Genco
Genco
Pool Price
Transmission
tariff
GROSS P OO L
Disco
Disco
Disco
Disco
Large
users
Source: Note 2, p. 102
Fig 15
Fig 15
Bulk Electricity-Balancing
Market
DesignMarket Design
Bulk ElectricityBalancing
Genco
Genco
Genco
Transmission
Tariff;
RESIDUAL
POOL
Balancing Price
Disco
Source: Note 2, p.102
Disco
Disco
Disco
Large
Users
76
An inherent problem of electricity markets as seen earlier is that the exercise of market power and
the opportunity to exercise market power tends to be more pronounced during peak periods. If
there are a small number of generators having discretionary power, the incentive for opportunistic
behaviour to boost price will be strong. Firms will seek to maximise profits and constrain
competitive behaviour, either from collusion or gaming the market. In constraining truly competitive
conditions generators can increase prices and extort rents. If the firm behaves as a Cournot
oligopolist33 that firm will bid into the market (especially during peak demand period) and will
assume that the quantity bid by the other, will be the same as it was in the last similar period and as a
consequence, the firm can assume that the remainder of the market demand curve is there to be
exploited. The firm will, therefore, bid like a monopolist for that segment of the demand curve. If all
firms behave the same way there will be an equilibrium price, higher than the price that will prevail
under truly competitive bidding. Market design must, therefore, recognise this characteristic of an
electricity supply system and should seek to minimise the exercise of market power. Holburn and
Spiller (2000)34 state that:
“Market power allegations have emerged as an anticipated major policy concern in
many jurisdictions that have implemented competitive wholesale markets over the last
decade”.
In the design of power markets, a number of approaches have been adopted. Some auction rules
have become very complicated, that they lead to gaming of the market, for example the situation in
the UK where generation firms were able to withhold capacity from the market in order to drive up
the spot market prices. Some Latin American markets such as Chile and Bolivia require bids to be
based on audited marginal costs and the construction of elaborate system of rewarding fixed costs.
This may be desirable in smaller markets or as transitional arrangements until the competitiveness in
the market is more effectively established. Market power can also be reduced by encouraging or
requiring plants to be contracted, for then the benefits of manipulating the wholesale price can only
be obtained from the un-contracted segment of the market.
Governance Structure of Power Pools and Exchange Markets
Electricity pools, whether central mandatory or balancing trade net pools require a governance
structure to ensure that self-regulation of the market is transparent and eliminates self-dealing,
77
conflicts of interest and abuse of market power. Four basic models have been developed; a multiclass stakeholder board, a non-stakeholder board, a single class board and not for profit enterprise,
not affiliated with market participants35. The type of governance structure adopted, to some extent
will be influenced by the ownership structure of the transmission system; publicly owned, as in New
Zealand, privately owned as in Bolivia or jointly owned by a class of participants, as was the earlier
case of the England and Wales pool, as well as to whether transmission is a neutral agent, providing
only wire services and market operations and systems control is assigned to another entity. In the
markets of England and Wales, Colombia and Panama the transmission company is an active agent,
in the markets of Argentina, Bolivia, Chile, Guatemala the transmission is a neutral participant and a
separate agency or Independent Systems Operator performs the system and market operations
function.
In a multi-class board, most or all of the market traders, including consumers are represented on the
pool’s governing board. It fails to achieve independence if one class has veto powers. The nonstakeholder board members are prohibited from having conflicting interest with market participants.
The non-stakeholder board is the dominant model in the USA. A non-stakeholder board, however,
may become too detached, with no strong incentives for efficiency. In a single class board, one class
controls decision-making where the pool is effectively a club of generators as is the case in Chile.
The non-profit association or a single for profit organisation model not affiliated to market
participants helps to ensure neutrality and minimises conflicts with respect to insider influence.
In much the same way as no typical ownership structure has developed for the transmission system,
no typical ownership and governance structure has developed for the management of the centralised
pool or the balancing power exchange. Whatever the structure, the regulator needs to ensure that
the pool is independent of special interest and should have the power to vet market rules to ensure
transparency and guard against discriminatory rules and the exercise of market power.
Design features in electricity markets are constantly evolving. Several factors influence choice of
design features and these differ from market to market or from one country to another. There is,
however, a trend towards market based solutions, both for bulk energy prices and for transmission
services over administered arrangements. There is also a movement towards bilateral contracting and
self-balancing markets as this option gives greater choice to participants and greater flexibility in
78
trading mechanisms and contractual forms. With advances in telecommunication and computer
technology, several of the markets are also moving towards real time operation36.
The theory that electricity generation is no longer a natural monopoly and therefore, can be
subjected to full-competition without the need for regulation when the transmission function is
unbundled from generation as required in the bulk electricity market phase does not remove the
requirement for co-ordination which itself is inconsistent with competitive behaviour and each firm
acting independently in the market. The regulatory requirement merely changes to providing the
framework for a transparent market operation and to enable the market to cope with market power,
which seems to recur even, when generators’ market share is as low as 10%.
The principal advantages of a market for bulk power market are that it decentralises responsibility;
expansion of new capacity is market led, it meets demand for more customer choice and
competition and ensures efficiency enhancing behaviour, leading to productive and allocative
efficiencies. In small markets it may not be possible to create sufficient generation companies to
avoid market power and gaming of the market and this serves to frustrate competition.
Additionally, governments also loose certain level of control over the industry, as it is not easy to
accommodate social objectives. Often power markets present the problem of stranded cost and
there is no easy solution to this problem. Balancing bulk electricity markets with bilateral contracting
also provides for the economies of self-interest and the discipline of competition for further
efficiencies. In theory no major disadvantage is associated with wholesale electricity markets. In
reality the biggest problem is the level of knowledge required and the software and communication
tools needed to implement the market arrangement.
Model Four Stage - Retail Competition or Customer Choice Phase
Model Four Phase or the customer choice model, forms the final phase that has emerged to-date. At
this phase most final customers are allowed to choose their suppliers with the result that
competition is provided at all three levels; new capacity, bulk electricity and at the retail level.
Trading arrangements and access arrangements become more complex, in that access to the
distribution network is required in addition to access to the transmission wires. In the customer
79
choice model a final separation is required, that of separation of the merchant function of supply
from the distribution wire business.
Figure 16 below illustrates the customer choice model or open network structure. In the bulk
electricity market phase, the low voltage distribution wires are normally integrated with the supply
function. Fig. 17 and 18 show the electricity and financial flows under the customer choice phase.
During this phase of development, retailing becomes a separate function, distinct from the low
voltage wires. Both generation and retail supply markets are then open to full competition.
Generation must also be separated from transmission and distribution. Both the generation and
retail segments can then operate in the competitive part of the market. Restrictions on cross
ownership between generation and retail may not be necessary. The focus of regulation should then
be on the natural monopoly segments of transmission and distribution.
In the customer choice phase the pool operator does not take ownership of the power or take any
market risk. The pool operator is really an auctioneer, as the trading is done between the generators
and retailers or consumers. Extensive bilateral trading across the network is also facilitated.
Although the volume of spot trade may be very small, the spot market is critical to the system.
Fig. 16
Consumer Choice Structure
(Open Network Structure)
Genco 1
Disco
1
Consumer
captive
Consumer
Free
Genco 2
Generation
Disco
2
Free
Consumer
Consumer
captive
Distribution
Consumers
80
Source: Note 2, p.102
Under customer choice, phase metering of all customers becomes essential, as each customer must
be metered half-hourly or hourly to show how much each individual customer takes from each
retailer over the settlement period. In the absence of metering, profiling is sometimes adopted.
Profiling involves the establishment or categorisation of the demand pattern of each consumer. The
use of revenue grade meters can be seen by consumers to be relatively expensive when compared to
the expected returns and can act as a barrier to the extension of competition at the retail stage. New
Zealand initially adopted profiling to overcome the cost problem of retail metering.
Consumer’s desire for choice and the general conclusion that in the bulk electricity market
arrangement generators have failed to pass on costs savings to the retail consumers and this has
fuelled pressures for the extension of competition to the retail market. Generators have failed to
pass on the benefits of productive efficiency.
Actual consumer choice in the power sector is often limited however despite this restriction
pressures for more consumer freedom have been increasing in mature markets. In the United States
for instance several states have been implementing reforms over the last three years to facilitate the
wheeling of power over the incumbents utility company’s distribution lines to allow consumers to
choose their power suppliers or more accurately to switch from one retailer to another retailer.
Change of retailer does not imply a change of the physical network; the new supplier merely takes
over the physical system from the displaced retailer. New Zealand has also recently introduced new
regulations extending the benefits of retail competition to all consumers. The same forces, which
have transformend the telecommunications sector, are now driving the transformation process in
the electricity sector.
In the case of electricity the pressure derives from large consumers seeking more cost competitive
rates by negotiating bilateral contracts with independent power producers. Governments also often
set special lower rates for low-income groups with the result that medium sized residential
consumers find themselves subsidising both industrial and low-income consumers. These
consumers then seek a fair framework and demand freedom to choose suppliers. The reduction in
81
optimal size of plants has in itself also encouraged large consumers to generate their own power,
giving rise to a new type of power company; self-generators.
These forces have combined to increase the desire of consumers to manage and understand their
power purchases. This trend is expected to continue over the next ten years.
Fig. 17
Retail Competition (Phase 4 – Model Four)
Industry Structure (Electricity Flows)
G
G
G
G
G
Disco
C
Disco
C
G
Wholesale
Market
Transmission
Large
Customers
G
Supply
C
C
Supply
82
In the bulk electricity market phase discrimination continues against the domestic and
household consumers. Medium sized domestic and household consumers are also
called upon to subsidise low-income consumers. Beato and Fuente (1999)38 state that:
“Consumers have become aware of the implications of cross-subsidy
practices. Until recently despite the fact that electricity is a top consumption
item, consumers have had little say on the purchase of electricity and no
price information”.
In the bulk electricity market phase discrimination continues against the domestic and
household consumers. Medium sized domestic and household consumers are also
called upon to subsidise low-income consumers. Beato and Fuente (1999)38 state that:
“Consumers have become aware of the implications of cross-subsidy
practices. Until recently despite the fact that electricity is a top consumption
item, consumers have had little say on the purchase of electricity and no
price information”.
83
FIG. 18
Retail Competition (Phase 4 – Model Four)
Industry Structure (Financial Flows)
G
G
G
G
Disco
G
Disco
C
G
Wholesale
Market
Transmission
Large
Customers
G
C
Supply
C
Supply
C
Source: Fig.17 and 18 see Note 2, p.102
In Europe variations in electricity cost is so wide, they cannot be accounted for purely from
differences in fuel costs. Consumers are also questioning the huge stranded cost bill of the
franchised monopoly37. In the bulk electricity market phase discrimination continues against the
domestic and household consumers. Medium sized domestic and household consumers are also
called upon to subsidise low-income consumers. Beato and Fuente (1999)38 state that:
“Consumers have become aware of the implications of cross-subsidy practices. Until
recently despite the fact that electricity is a top consumption item, consumers have had
little say on the purchase of electricity and no price information”.
If subsidy policy is to be adopted then a more transparent mechanism of cross-subsidy will need to
be developed to pursue such public policy goals.
The newer smaller CCGT plants, which are more mobile and can be connected into existing
transmission systems, make it possible to use more substations to conduct the flow of high voltage
energy from more generating plants to smaller groups of electricity users. Their easier integration
84
into the transmission network facilitates the sale of electricity between newer entrant generators and
final consumers.
Finally, the development of smart metering and the lowering of metering costs and communication
systems also serve to facilitate the introduction of retail competition to the mass of household
consumers, once considered captive to the franchised distributors. In retail markets metering by time
of use is no longer a way of promoting competition. Metering becomes a commercial necessity.
Each consumer needs to be metered according to settlement periods. Power prices typically change
in very short time spans in competitive markets, therefore, it is necessary to know how much of
each competing retailers’ supplies is used in each period in order to be able to bill the right customer
and settle the right account balances. The development of smart metering has permitted the rapid
expansion of retail competition to the full market. Household consumers annual consumption of
electricity is however relatively small and the capital cost of acquiring smart meters may, be such that
it takes a long payback period for the benefits of competition to offset the costs of acquiring meters.
Distributors continue to be franchised in area markets, however, the services that they are allowed to
provide is restricted to the network lines or transportation of low voltage electricity. The newly
unbundled distributor, as part of the franchise rights given is required to provide open and nondiscriminatory access to facilitate the transportation of both retailers’ and consumers’ electricity.
The consumer choice phase provides the final act in the separation of network services (which
remain a natural monopoly) from energy services. It provides the opportunity to open both the up
stream generating and the down-stream retailing segments of the market to competition. Retailers
and consumers, in addition to buying from the power markets are free to also contract long term
direct with generators. Hence, large supermarkets contract with generators and offer lower price
retail electricity to their customers in order to strengthen supermarket patronage.
In the design of retail markets, two vertical issues emerge; separation of generation from retail and
separation of distribution services from retail services. The unbundling of the distribution lines
business from retailing reduces the potential for self-dealing and conflicts of interest. Allowing
distribution line operators to perform the retailing function also provides the opportunity for the
85
distribution businesses to cross-subsidise their retail business and to discriminate between classes of
consumers.
The opportunity to unbundle distribution is very high. Retailing is a merchant function and this
function does not have to be provided by the owner of the distribution lines business. Distribution
lines business is said to display economies of density rather than economies of scale. Large electricity
distribution firms do not necessarily lead to a more efficient industry in terms of cost efficiency.
Unit cost of distributing a given kilowatt hour to end users will differ, depending on structure of
customers in terms of density of connection. Higher densities lead to lower costs. Other factors,
which may affect costs, are topography, climate, load mix of energy and peak loading within a given
area.
Weak gains have been identified with increases in size, with size being considered as
geographic area, network size; number of customers or of sales volume.
Vertical integration of the retail and generating services in the competitive parts of the market is no
longer a serious market failure issue and is therefore permissible.
Because retailing, as an
independent activity is a high risk and low return business, vertical integration is sometimes
permitted between generating and retailing. Control of the retail market by generators, however,
could affect market contestability and hamper effective competition.
While welfare economics and competitive considerations call for ownership separation, in practice
the level of separation permitted varies from market to market. Historical reasons may work against
full separation. Consumers may resent the shift from their traditional supplier or fear increased
costs. Vertical separation of retail and distribution lines business has been a very recent
development, mostly taking place since 1998. Countries that have liberalised their retail markets are,
Norway 1991; New Zealand, 1993-1994; England and Wales, 1990-1999; Finland, 1995-1997;
Victoria- Australia, 1994-1998; Spain, scheduled for 1997 to 2007, and California 1998. In most of
these countries a transition period is provided whereby sectors of the market are deregulated in
phases with segmentation determined according to the size of customer demand. The defining
feature of the consumer choice phase is the opportunity for all consumers; large and small to switch
patronage and the opportunity for independent retailers to enter the market.
86
Competitive Transformation of the Electric Utility Industry
The market failure features of the electricity industry resulted in the exclusion of electricity from
competitive markets for much of the post war years. For most countries state ownership or private
ownership with public regulation provided the institutional mechanisms to resolve the conflict of
interests between the private and public good.
The policies of shifting to private ownership and liberalisation of markets, which have emerged
globally since the mid-1990s, have been resulting in new entrants to electricity markets and increased
competition. For most of the industries under state ownership, it was possible to sustain
competition by mere abandonment of the statutory monopolies and subjecting the newly privatised
or commercialised companies to the competition legislation. In the case of the electricity industry, it
was not sufficient merely to discontinue exclusive franchise rights and allow for the private delivery
of electricity services. Abandonment of exclusive franchise rights had to be supplemented with
vertical and horizontal dis-integration in order to facilitate the introduction of competition.
Providing for and sustaining competition in the utility industry such as electricity is a complex
process, beyond the capacity of traditional competition laws. The introduction of competition in the
electricity industry has essentially been technology driven with the competitive pressure being
exerted mainly by combined cycle gas turbine technology and smart metering.
In this context competition is defined as a state where sellers are powerless to set prices either from
the number of players in the market or from, the threat of entry but must respond to market forces
and not merely rivalry in markets. Competition seeks to ensure the most efficient allocation of
resources to satisfy a given demand. Competition is not a simple a concept, which deals with ethical
values. Sioshansi and Morgan (1999)39 state that:
“among the discernable features of competitive markets is that they be truly
competitive, self-regulating and resulting in efficient outcomes. In reality some
policing and monitoring is always necessary to make sure the participants are not
resorting to illegal means to manipulate prices or influence outcomes”.
The different elements of the production and supply chain display different degree of market failure.
It is therefore necessary to distinguish the types of competition applicable to the different elements
and the linkages between the stages in the production and supply chain and the degree of dis-
87
integration needed to maximise production efficiency. It is possible to obtain important productive
efficiency gains from competition in bulk electricity market, since the greater share of costs is at this
end of the production chain.
As is shown earlier, competition can be introduced in the electricity industry through competing
production or competing networks, from common carrier arrangements and yardstick measures, by
private supply and through wholesale competition, as well as through retail or border competition40.
It is however very difficult to provide for competing transmission and distribution lines business
because of the high fixed sunk cost and economies of scale which is associated with transmission
and to a lesser degree with distributions lines. Although it is difficult to provide for competing
transmission lines it is not impossible, as there are competing transmission lines in the Nordic
countries.
The simplest form of competition in the electricity market is that of competition to provide
incremental capacity or competition, which comes with the single purchaser, phase and which
involves the competitive procurement of new generation.
Competition forces the bidders to
providing the minimum cost for the incremental capacity. This form of competition, (Baumol
competition) or competition for the market, is distinguished from product market competition or
competition in the market which is facilitated by power pools and bulk electricity exchanges. Once
the contract is awarded, under a single purchaser arrangement, further competition during the life of
the contract is more or less ruled out.
It is possible, however, to unbundled supply costs into capacity cost and energy cost, and provide
product market competition for the energy cost component by subjection of the latter component
to economic merit order dispatch, in that for any demand over a given time period the lowest energy
cost operator is dispatched first.
In thermal plants energy cost can be a significant element,
providing opportunity for major efficiency gains.
Competitive tendering also requires the
incumbent to test his own production costs against the market and this helps the regulator to
overcome some of the information asymmetry problems.
It may not be possible to move to retail competition in many developing country markets for
several years. Yardstick competition, however, provides a mechanism for the reduction of market
88
power. Yardstick competition can be promoted by three methods. First, the price a firm may
charge can be based on the cost of a typical set of firms in the industry or a notional model firm.
Secondly, benchmarking of companies against one another to estimate efficiency is possible.
Benchmarking allows for the establishment of price caps, based on the cost structure of the model
or typical set of firms. Adopting sophisticated statistical techniques, which also take into account
differences in the companies operating environment, may also be used to set indicators. Thirdly,
competition can be facilitated by information disclosure requirements, which mandate public
presentation of the firm’s cost and performance data so that consumers are presented with market
information to make comparison. Unbundling and information disclosure provide the opportunity
for consumers to compare each locational monopolist’s costs. In Europe variations in electricity cost
is so wide, they cannot be accounted for purely from differences in fuel costs. Consumers are also
questioning the huge stranded cost bill of the franchised monopoly40.
.
The final form of competition is financial and capital market competition. Once the electricity
enterprise is privatised, sets of owners and managers can compete to take over the assets and
licences of the incumbent electric utility. Capital market pressure can play a significant role in
enforcing efficiency, provided this is not frustrated by pre-emptive rights clauses or some arbitrary
limit on share ownership. Beesley and Littlechild (1997) contend that capital market competition is a
powerful efficiency driving feature41.
The introduction of competition to the electricity industry requires a transitional period of managed
competition or a competitive transformation period. Paradoxically, liberalisation of the network
market often results in increased regulatory intervention to secure competitive outcomes. Sidak and
Spulber (1997)42 state that: “Regulators are concerned with achieving competition “fairly”, yet
markets are known for their efficiency properties, rather than the equity of their outcome”. It
is therefore, important that regulators use an operational definition of fairness that does not attempt
to specify outcomes. In the competitive transitional phase, regulators should ensure that incumbent
burdens are dismantled or shared evenly across market participants as in the case of meeting
universal service obligation.
89
It is important to identify non-commercial obligations and unbundled these from the commercial
business. The incumbent and the new entrants may then be required to compete to supply the noncommercial services and the cost shared across all entrants. Secondly, regulators should not seek to
pick winners in terms of technology, services or market institutions. Such a situation arises for
example when the regulator specifies the type of technology, which should be used to meet
customer demand. Regulators should refrain from market intervention that favours particular
competitors and should dismantle regulation if a demonstrably competitive alternative exists.
Liberalisation of electricity markets also creates the problem of a dichotomous regulatory
environment during the market transformation phase, with the industry specific regulator being
called upon to monitor the natural monopoly elements and the competition agency to monitor
contestable elements. With the integrated electricity monopoly structure, there was no opportunity
to engage in anti-competitive conduct. There was also no one to enter into agreements, which could
be restrictive, or to behave in a manner that would lessen competition in the market for the relevant
services. When the potentially contestable element is opened up to competition, the question of
access to the network requires regulation to ensure the incumbent refrains from acting in a manner
that would be disadvantageous to rivals in the competitive sector or to exercise market power.
Ordinary competition rules are often insufficient to control market dominance in network industries
with the result that increasingly since the mid 1980s the electricity industry regulators have also been
given specific mandate to enforce competition rules.
This new environment creates the potential for jurisdictional conflicts as the utility industry
regulatory rules may conflict with the rules of the competition agency. Additionally, the rules of the
competition agency may be so wide that it allows the competition regulator to challenge price fixing
decisions of the utility regulator. There is also opportunity for conflicts of rules between the two
regulators in respect of merger control matters. Unless the responsibilities between the two agencies
are clearly defined and the boundaries delineated, it will then be left to the courts to interpret the
language of the respective legislation and this could be long drawn out and expensive43. There is
therefore the need also to provide for exemptions or establish legislative rules, which provide for
primacy of one of the legislative instruments in a given situation. An alternative solution is to grant
concurrent powers to both agencies.
Concurrency, however, may create duplication without
resolving the problem, as is the case where competition authority and the sectoral regulators take a
90
different position on a given matter. This problem has developed in the UK with the introduction of
the 1998 Competition Act, which has provided for concurrency.
With the introduction of competition and the application of competition law it may be argued that
the electricity industry regulator is rendered unnecessary as the institutional instrument to remedying
abuse of market power. The notion of electric utility industry regulation has traditionally been based
on the premise that there is absence of competition. The question has therefore emerged as to
whether general competition law should replace economic regulation. Prosser44 has, however,
argued that it is not possible during the market transformation stage to do without industry specific
regulatory rules and leave matters to the market and ordinary competition law, as even in the New
Zealand situation where competition law is used, the threat of regulation and the right of the
minister to fix prices remains.
The opportunity to create competition in the electricity market is now substantial. The global
situation is such that there is an uprising of competition, even in small electricity markets.
Competition ensures that there is rivalry to meet consumers need, resulting in lower prices, better
quality, wider variety of products, and more optimal investments. Resources are also used more
productively.
It is not so much perfect competition, which is important, but the threat of
competition or the threat of regulation.
91
Fig. 19
Four-Phase Electricity Industry Restructuring Models
Increased Private
Ownership
Distribution as a common
carrier Open Access
Transmission
Common Carrier Open
Access
Increased Level of
Unbundling
Unbundling (vertically &
Holizontally)
Liberalisation
Single Integrated
utility (State or
Private)
Model 1
Monopoly
(Partial Cost
Pool)
FRANCE
Model 2
-Generation in
Entry
Competition
-Power Purchase
Agreements
-Single Buyer
JAMAICA
IRELAND
Model 3
-Wholesale
Competition
-Bulk Power
Exchange
-Spot Price
-Futures
Model 4
-Retail Competition
-Large User
Contract
UK
ARGENTINA
VICTORIA,
AUSTRALIA
BOLIVIA
Source: Note 2, p. 102
The process of competitive transformation in further illustrated by Fig. 19 above, which shows that
as the industry moves from one phase to the next, there is increased competition, and increased
levels of vertical and horizontal unbundling.
92
Increased levels of unbundling provides for a higher degree of private sector participation and
ownership. While private ownership introduces incentives for higher levels of efficiencies and the
discipline of hard budgets, it is competition facilitated by new technology, which delivers lower
prices to consumers, and greater operating efficiencies.
While ownership and a competitive environment are important for an efficient electricity market,
ownership and a competitive environment per se are not enough. A competitive framework must
be supported by rules to prohibit or restrict anti-competitive behaviour, and to guard against firms
reintegrating to benefit from monopoly power. Competition addresses the three major causes of
poor public enterprise performance. It removes shelter provided by monopoly, more importantly it
minimises political interferences that distort the objective operation of the company and it resolves
the property rights issue. Competition in those sectors of the industry, that no longer carries natural
monopoly characteristics, also minimises regulatory oversight and regulatory costs and reduces the
incidence of regulatory capture.
The general picture which has emerged over the last 10 years has been one in which the industry
structure adopted has followed a move away from the traditional Franchise Monopoly Phase. There
have been three distinct structures: Purchasing Agent; Bulk Electricity Market and that of Retail
Competition. There appears to be no requirement that an industry has to progressively move from
one stage to the next. Some countries have opted for radical restructuring and have moved directly
to the bulk electricity market. In other situations gradualist approaches have been preferred.
The competitive transformation of the electricity industry and the stage that a country adopts at the
point of reform are not only dependent on technological factors, competitive transformation
depends also on political constraints and the extent to which efficient regulatory regimes can be
structured and applied. In developing countries competitive transformation is restricted by crosssubsidisation, an unstable market environment and an inappropriate regulatory regime. Foreign
investors will be reluctant to invest in markets, which are perceived to carry high risks and will
demand long-term power purchase agreements in order to compensate for the high risks. In
developed markets competitive transformation is restricted more by stranded cost.
93
Technological factors therefore, set the boundaries as to how far competition can be taken in any
given country; however, it is political factors such as stranded cost, cross-subsidisation, an unstable
market environment and the regulatory regime, which will determine the pace of market
transformation in an individual country.
Selection of Case Countries
A number of countries that have reformed and privatised their electricity markets since 1990 will be
illustrated as case countries to see to what extent these countries conform to the four phase model
and development process outlined above. The cases are, the England and Wales and the rest of the
UK reforms which commenced in 1989; the Jamaican reforms which commenced in 1990; the
Bolivian reforms which were carried out after 1995, and Sub-Saharan Africa, inclusive of three
selected countries, (Ghana, Cote d’Ivoire and Tanzania) that have since 1996 introduced policies to
provide for significantly increased levels of competition in their electricity markets.
The UK has been selected as it is in first case of radical reforms, involving the separation of
generation from transmission and introduction of statutory requirement on the regulator to
encourage competition in the sector. Jamaica’s relevance is that the policy makers came to the
conclusion that radical restructuring involving horizontal and vertical disintegration was more a
policy option for large electricity markets, and because of this view Jamaica proceeded to privatise
the monopoly electric utility as a vertically and horizontally integrated company in 2001.
Bolivia with a less developed economy and with an electricity market similar to the size of Jamaica
(under 650 MW) rejected the market size constraint and introduced radical disintegration and full
privatisation of the sector. The three African countries have all tried various degrees of reforms
within the framework of state ownership and a franchise monopoly structure and have found that
the improvements are not sustainable and have decided to radically reform their small electricity
markets, (mostly under 1000 MW) into a disaggregated and competitive structures. There is,
therefore, the question as to whether the Bolivian reforms offer a template or road map for these
countries.
94
End Notes
1. Yin, R.K (1981b). The Case Study as a Serious Research Strategy, Knowledge: Creation. Diffusion,
Utilization, vol.3, 97-114
2. Figures 3 to 19 present illustrations developed by the author to portray the various industry and
market structures. Several writers have provided illustrations of these changing industry
structures, however, the trend has been to focus on the traditional organisational relationships. A
new dimension is that in the three new phases of development, illustrations are also provided of
the electricity and financial flows. For organisation illustrations see Hunt and Shuttleworth,
op.cit., Chapter 3-7, and Carole Hicks, Regulation of UK Electricity Industry, Centre for
Study of Regulated Industries, London (1998).
3. Once the cost of service and the capital for the test year is determined a rate of return is
established. The cost of service and the calculated returns then form the tariff for the next
period. A criticism of this formula is that it is a cost plus approach, inflationary, and does not
provide incentives for the utility to be efficient. It worked reasonably well in periods of low
inflation.
4. In some countries the rate of return is fixed in the contract. Benchmark rates are sometimes
established. The utility is allowed levels of profits, which falls within the benchmark as adopted
in Jamaica.
5. Harvey Averch and Leyland L. Johnson, “Behaviour of The Firm under Regulatory Constraint”,
American Economic Review, Vol. 52 (December 1962), pp.1052-1069. Averch and Johnson
state that the rate of return formula as applied by US utility regulators leads to the employment
of more capital (gold plating) than would be optimal. The rate of return constraint gives the
firm an incentive to employ more capital than is normally needed.
6. The EU directive states that from 1999-2003 the share of the electricity market open to
competition shall grow from 25% to 33% and by 2003 must apply to all end users above 9 GWh
per year. The directive also calls for transparent and non-discriminatory access to EdF’s
transmission system.
7. Nocolas Curien and Claude Henry, “Liberalisation and Regulation of Public Service in France”,
in Regulatory Review 1998/99, ed., Peter Vass, Bath, England, Centre for the Study of
Regulated Industries (1998), p.125.
8. Mohan Munasinghe and Arun Sanghvi, Recent Developments in US Power Sector and
Their Relevance for the Developing Countries, Washington D.C., World Bank (1989), p.3.
9. Ibid; p.7.
10. John Wippen, Private Power Experience in the US, Washington, D.C., J. Makowski
Associates, unpublished (1991), p.3. A total of 21500 MW (or 33%) of total additional
power capacity, which came on stream between 1985-1990, were PURPA capacity.
95
11. Leboeuf, Lamb, Greene and MacRae, Competition, Structural Change and Regulatory
Reform in the US Electricity Industry, London, Centre for the Study of Regulated Industries
(1994), p.22.
12. David M. Newbery, Issues and Options for Restructuring the ESI, Washington, D.C.,
World Bank (June 1999), p.5.
13. David M. Newbery and Richard Greene, “Regulating, Public Ownership and Privatisation of
English Electricity Industry,” in International Comparisons of Electricity Regulation, ed.,
Richard Gilbert and Edward P. Kahn, Cambridge University Press (1996), pp.25-81.
14. David A. Cordukes, A Review of Regulation of the Power Sectors in Developing Countries,
Washington, D.C., World Bank. Working Paper Energy Series, 22 (1990), p.13. Cordukes
found that the predominant organisational form in 22 developing countries in 1990 to be that
of the publicly owned and controlled corporation. Many of these were nationalised after
independence and were permitted to operate as monopolies. In most Sub-Saharan African
countries the single public corporation operates the vertically integrated system.
15. British Treasury, The Financial and Economic Obligation of Nationalised Industries,
London, HMSO, (1961), Nationalised Industries: A Review of Economic and Financial
Objectives, London, HMSO, (1967); and Nationalised Industries, London, HMSO (1978).
The 1961 White Paper broke with the Morrissonian model of nationalised industries being run
on commercial lines only to break even one year after the other. The paper put forward an
economic framework with financial targets with pricing policies to meet these targets. The 1967
Paper increased the economic controls, setting out detailed pricing and investment policies
requiring prices to be set at long run marginal cost and investment policies, to be evaluated in
terms of test rates and net present values. Prices were to be subjected to review by the Prices
and Income Board. The 1978 Paper completed the shift to full commercialisation. Financial
targets became the primary instrument of control. A rate of return was to be earned on capital.
The National Economic Development Report Office reported in 1976, that the economic and
financial regulatory framework that had been developed had failed, blatant political manipulation
and intervention was still to be found and that the industries were being used to promote macroeconomic policies. The Morrissonian ideal of “arms length” public corporations managed
independently proved unworkable and detailed direct regulation after the 1970s also failed.
16. John E. Besant-Jones, The England and Wales Electricity Model: Option for Developing
Countries, Washington, D.C., World Bank Notes (1995), p.2,
17. Kenneth W. Costello and Kenneth Rose, “Some Fundamental Questions and Market Power: No
Easy Answers for State Utility Regulators”, Electricity Journal, (July 1998), p.75.
18. Gardiner Maine and Montpelier Vermont, Best Practices Guide: Implementing Power
Sector Reform, Washington, D.C., USAID/Institute of International Education, Regulatory
Assistance Project Report (2000), p.12.
96
19. World Bank and USAID, Submission and Evaluation of Proposal for Private Power
Generation Projects in Developing Countries, Washington, D.C., Occasional Paper No.2
(April 1994), p.22. IPP project involves the formation of a private company or joint venture,
to plan and finance the business on a non-recourse basis, design contracts and operate the
power plant. Lenders look to the projects cash flow for repayment of the principal and
interest and returns on investment and to the assets as collateral in the event of default. The
new company typically does not have any other assets or credit standing. The right to use
project cash flows to meet debt service is normally structured in the PPA.
20. Several variations of IPPs have emerged. Initially IPPs were of the PURPA type where the
investor owned utility was forced to buy power from IPPs at the utilities avoided cost. The
IPP framework was then exported to South East Asia as Build-Own-Transfer (BOT)
involving competitively bid tariff, followed by the “tolling IPP”, with a supply driven PPA in
which the tolling agreement is with the fuel supplier. The supplier makes the decision when
to sell gas, generate electricity or do nothing at all. This supplier pays a capacity fee to the
plant and receives a power price netback from the plant. An example is Enron Sutten Bridge
Plant in the UK. A fourth version is “hedged IPP”, here the plant sells into the grid and
receives the spot price which varies half-hourly, (based on systems marginal price), however,
the IPP enters into a financial agreement, contract of difference (CFD) as in the UK with the
purchaser, whereby both agree to share the price risks. An alternative is to link the fuel price
with the electricity spot market price as in the case of the AES Barry and Enfield plants in
England. Hedged IPPs tend to be for short period, 4 to 5 years compared to “BOT IPPs” for
15 years. Additionally variations may involve still a further shifting of risks away from the
purchaser to the equity or debt holders or both. “Merchant IPP” is at the end of this risk
profile. In a pure Merchant IPP, there are no purchase contracts. Because of the associated
risks project financing is difficult. This is so because of the highly leveraged nature of the
transaction selling into a commodity market.
21. Gardiner and Maine, op.cit., p.13.
22. John E. Besant-Jones and Bernard Tenenbaum, California Power Crisis: Lessons For
Developing Countries, Washington, D.C., ESMAP (2000), p. 14.
23. Elliot Roseman and Anil Molhatra, “Dynamics of Independent Power – IPPs Seed-to-Bottom
Reform”, in Private Sector Special Edition, Washington, D.C., World Bank (1996), p.37.
24. World Bank/USAID, op. cit., p.79, provides an illustration on Virginia Power’s private
power procurement contract with the use of bids involving capacity and energy charges as
early as 1988.
25. Newbery, op.cit., p.12.
26. World Bank, Energy After the Financial Crisis, Washington, D.C. (1999), p.20.
27. Newbery, op.cit., p.13.
97
28. William W. Hogan, “A Wholesale Spot Market Must be Administered by an Independent System
Operator, Avoiding the Separation Fallacy”, Electricity Journal, (June 1994) p.36.
29. Industry Commission, Energy Generation and Distribution, Vol. 11. Report, Canberra,
Australia (May 1991), p.116. Australia contends that market operation and the dispatch
functions go well together because of the benefit of sharing information. Australian policy
makers also contend that the skills required for market operations are different from those
required from transmission operations.
30. South Africa’s Eskom has advanced the idea of a bulk electricity market with horizontally
disintegrated state owned enterprises. This is still inappropriate as in this arrangement the
state owned firms would not be subject to financial market competition. The problems of
public control and the opportunity for political interventions also are not resolved. New
Zealand tried this approach and had to abandon it after five years as the experience was that
competition was inhibited.
31. Newbery, op.cit., p.20.
32. Vesting contracts for example were provided in the Northern Ireland restructuring in 1992. see
Brian Lunn, Northern Ireland Electricity Markets, unpublished (2000).
33. Besant-Jones and Tenenbaum, op.cit., p.12.
34. Daniel Spulber, Regulation and Markets, Cambridge, Mass. MIT Press (1989), p.371.
35. Guy L.F. Holburn and Pablo Spiller, Institutional or Structural: Sequencing Strategies for
Reforming the Electricity Industry, Berkeley: University of California, Walter Hass School
of Business (November 2000), p. 13.
36. James Barker, Bernard Tenenbaum and Fiona Woolf, Governance and Regulation of Power
Pool and System Operation: An International Comparison, Washington, D.C., World Bank
Technical Paper, No. 382 (1997).
37. Office of Gas and Electricity Market, The New Electricity Trading Arrangements, London,
OFGEM (1999), P.43.
38. Paulina Beato and Carmen Fuente, Retail Competition in Electricity, Washington, D.C.,
Inter-American Development Bank (1999), p.3.
39. Ibid., p.4.
40. Fereidoon Sioshansi and Cheryl Morgan, “Where Function Follows Form: International
Comparisons of Restructured Electricity Markets”, Electricity Journal (April 1999), p.26.
41. Border competition is also possible where retailers bordering supply zones are allowed to
cross the border and supply to customers in the incumbents franchised supply zone.
98
42. Michael E. Beesley and Stephen, C. Littlechild, “Privatisation, Principles, Problems and
Practices”, In Privatisation, Regulation and Deregulation, ed., M.E. Beesley, London,
Institute of Economic Affairs, Routledge (1997), p.28.
43. J. Gregory Sidak and Daniel Spulber, “Deregulation and Managed Competition in Network
Industries”, Yale Journal of Regulation, Vol. 15. No. 1 (Winter 1999), p .118.
44. OECD “Relationship Between Competition and Regulatory Authority”, Journal of
Competition Law and Policy, Vol. 1, No. 6 (1999), p.196.
45. Tony Prosser, Law and the Regulators, Oxford: Clarendon Press, p.270.
99
Chapter 3
A Formula For Radical Reform:
The British Industry Structure
Introduction
The restructuring, privatisation and regulation of the UK system, especially England and Wales
(E&W) in the first half of the 1990s followed a radically new path. It was the first of the UK public
utilities to involve significant major restructuring in order to promote competition in those sectors,
which from an economic point of view were no longer characterised with natural monopoly
features.
British electricity reform has been instructive from the point of view of five major innovative
approaches. Some of these approaches, although credited to the British were not novel concepts.
Millan (2001)1 noted that although the English claimed that their competitive system was the first in
the world, the Chilean model had been in effect for over a decade when the England and Wales
system was established.
The concept of promoting competition in a utility industry as against the tradition established by
United States of maintaining the utility as an integrated monopoly was not a UK innovation. Britain
merely built on the approach, and for the first time made the promotion of competition a statutory
duty of the regulator.
The second and most radical change introduced in the E&W system was that of vertical separation
of generation from transmission and providing for ownership and operation of the transmission
network to be carried out by an entity that is separate from the owners of the generators and
distributors2. In the traditional US utilities, regulation for the most part, suppressed competition.
With the new approach, the industry was to be vertically separated into the four elements of the
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production and distribution chain; generation, transmission, distribution and supply. Supply
competition, however, was to be phased over a period of 8 years. Generation and supply at the start
of the reform combined to account for 70% of industry costs. Both these sectors were to be the
subject of horizontal unbundling so as to accommodate competition. This reflected a clear departure
from the US model of the vertically and horizontally integrated private investor owned electricity
utility, which up to the 1990s was the dominant industry structure for privately owned electricity
utilities.
Third, the UK policymakers at the time of privatisation rejected the US rate of return, rate base, cost
of service system of economic regulation and instead adopted the concept of incentive regulation or
price base regulation for franchised services through caps on average revenue, based on the thinking
of the Austrian School of Economists3. The underlying thesis of the Austrian School was that utility
industries do not have to be operated as monopolies. Pure cases of long term natural monopoly
were considered to be of the rarest occurrence. Utility monopolies persist only if they are buttressed
by public authority. The new style UK regulation challenged the notion that utility industries have to
be operated as monopolies, and explicitly sought to encourage new entry and competition, where
competition was possible thereby seeking to minimise the disadvantages identified by Hayek and
Friedman with regulated monopolies. The real challenge was to maximise the scope for competition.
The new UK approach focused on price rather than profit, as had been the case with US style
regulation up to 1990, hence the “RPI-X” formula. This new approach provided for the monopoly
operated utility to raise prices for its services, by the economy-wide rate of inflation, adjusted for an
efficiency factor. The formula incorporated the UK retail price index (RPI) and an incentive term
called “X” factor, with the expectation that “X” would be a positive number and that the cost of
the utility service would therefore fall in real terms to the consumer. This approach was expected to
remove the need for technical judgment on the part of the regulator to provide strong incentives to
the utility to reduce cost, as it was expected to share in the benefits of the efficiency improvements
without the fear of profit “claw back”, inherent in the US system of annual rate hearings. As the
reviews would be over a longer time period, a more predictable environment would be provided,
when compared to annual rate reviews carried out in US systems.
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Fourth, the UK electricity reform provides experiences of more than one approach to restructuring,
in that there are three separate systems: E&W, Scottish and Northern Ireland and each system was
subjected to different levels of unbundling and different degrees of competition were introduced.
Unbundling raises an important question. Does the disintegrated or unbundled structure always
minimise electricity supply costs or whether disintegration results in increased transaction costs and
loss of economies of scope and scale, which eventually outweighs the competitive gains of
disintegration? The different approaches pursued in the UK to some extent provide an empirical
answer to this question.
Fifth, a new price base market mechanism, an electricity wholesale power market replaced the
informal load-scheduling mechanism based on merit ordering of power plants by marginal operating
cost that the incumbent state owned utility previously used. The new system; essentially a power
pool was the main innovative market mechanism introduced to facilitate competition in the
generation sector. The wholesale power pool, which is virtually a spot market for bulk power,
introduced the commodity exchange market concept to bulk electricity supply4. Generators are paid
the pool purchase price for electricity supplied into the pool, whilst traders and large users pay a
pool-selling price for electricity taken from it. The pool serves to provide for the close coordination
needed between generation and transmission, which previously was facilitated by vertical integration.
Coordination by contracts alone would have ended up approximating the integrated structure that
had been rejected. Pools previously existed in the US; however, they operated at the margin, mainly
facilitating exchange of surplus power between investor owned utilities.
There was no empirical evidence then that the separation of transmission from generation being
associated with effective competitive markets. Yarrow (19895 also questioned whether such
separation would more likely create efficient and competitive solutions. Yarrow further argued that
generation and transmission were naturally monopolistic or at least naturally duopolistic and that
there were still strong vertical economies between the two segments, and it is these features, which
historically had kept the electricity industry out of competitive markets.
Primeaux (1989)6 had, however, in a 1960 study indicated that there was empirical evidence to the
existence of competition in electric supply in a number of cities in the United States. Primeaux
claimed that cost data collected from these cities with two or more competing electricity supply
102
companies , failed to support the widely held natural monopoly theory of electric utility. In fact
cities with competing firms were found to present lower cost.
Although Chile had sought to introduce a competitive market before the British, transmission was
not operationally separated from the main generator at the time of creating the first electricity
market. Littlechild (1999)7 further stated that apart from not knowing at the time of the existence of
the Chilean experiment, it would not have helped politically, with the reputation of the Allende
dictatorship administration.
Although the UK reforms appear to have been extremely radical, in practice they were less so. The
UK policy makers faced a series of conflicting objectives. On the one hand, there was the desire to
create an economically optimal structure and not to repeat the monopolistic structures of the earlier
telephone and gas industry privatisations. On the other hand, there was the need to balance this
against a number of political objectives, such as to protect nuclear power and to offer financially
attractive companies to the financial market. Additionally, there was also the overriding objective of
the Conservative administration to secure a successful flotation within a tight time frame, influenced
mainly by electoral consideration.
There were two other objectives of the Conservative administration. First there was the desire to
break the stranglehold on power of the trade unions, which historically were able to exert
tremendous political power in industries like electricity and coal, which were not subject to
competition. Second there was the desire to create a share-owning democracy that would markedly
reverse socialism and state ownership.
Despite the unbundling of generation, essentially a duopoly was created. Further, no restructuring
of the distribution and supply market was undertaken as the incumbent twelve distributing Area
Boards were retained with most of their monopoly privileges. Government’s competition policy
initially concentrated on new entrants to the generation market and in the case of the supply market,
on second tier suppliers. The natural monopoly transmission system, although vertically separated
out from generation was partially re-integrated with the distribution sector, as the twelve incumbent
distributors became joint equity owners of the new transmission company. The supply of electricity
from the Scottish companies and French EdF to the generation market was permitted as a part of
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the wider industry liberalisation policy and was expected to provide added competition for the bulk
electricity market; however, the Scottish system was allowed to remain with its vertically integrated
structure.
1980s Political and Economic Thinking on Electricity Privatisation
In order to obtain a better understanding as to the final shape of the industry, which emerged, it is
important to revisit the political and economic circumstances, which surrounded the industry in the
period to 1990. This is important from the perspective of developing countries seeking to fashion
their restructuring programmes based on the UK model.
At the time of privatisation the system was plagued with over-capacity and economic motivation for
reform was driven primarily by the desire to reduce cost. For most developing countries, with levels
of electricity penetration of under 20% and especially in Sub-Saharan Africa where penetration levels
are under 10%, the overriding driving force will of necessity have to be that of rapid expansion of
penetration. The thinking as to what was then possible, significantly affected the policy options
contemplated and it would be incorrect in hindsight to be extra critical based upon today’s
knowledge or technological developments, which were perfected after the 1980s.
At the time the privatisation debate came up in Parliament, Tony Blair, then Opposition Spokesman
on energy was critical of Michael Heseltine, then Energy Minister, and not only pledged to reinstate
electricity as a public service on a Labour administration return to power, he also claimed that
privatisation would not only lead to increased prices but that, the case presented that privatisation
would give consumers choice at the point of consumption had not been substantiated. Heseltine
responded by stating that the only way to give consumer choice at the point of consumption was to
run two cables in every home.8 How to provide competition in the small consumers’ market,
without the uneconomic provision of multiple lines on each street and into each home was yet to be
resolved.
There was a strong view that unbundling and privatising of electricity could not be done and the
exercise was one of political fantasy. Vertical unbundling of electricity and creation of competition
in retail supply was not only a novel economic concept, in contrast to generation; there was
104
profound scepticism as to its practical outcome in retail supply. It was felt that only very large
customers such as the British industrial firm, ICI would want to buy electricity direct from
generators.
Unbundling of the Central Electricity Generation Board (CEGB) was strongly resisted by the
chairman and management of the company. Their argument was that a vertically and horizontally
integrated generation and transmission company was needed to ensure adequate supply capacity and
security of supply and that reform following the single buyer arrangement in which CEGB
contracted with independent power producers for additional capacity at regulated charges would
have been sufficient in terms of the changes that were needed. This, however, was not seen by the
policy makers to meet the requirements for a competitive electricity market. A variation of the
single buyer model was also advanced. This variation called for the regional distributing companies
to be permitted to enter into long-term contracts with individual stations and to pay a capacity
charge to cover fixed costs and an energy charge to cover the avoidable cost of generation. The
suggestion was also rejected on the grounds that the creation of a market with these individual
contracts with their two part tariffs would be far too complex.
Although the electricity privatisation was pledged in the 1987 Conservative Election Manifesto, no
details had been provided. The first blue print came in the February 1988 Government White Paper
on Electricity Privatisation9
which intimated that the existing twelve distribution companies in
E&W were to be incorporated as limited liability companies and sold intact and that the Central
Electricity Generating Board, the generation and transmission enterprise, was to be disintegrated
into three companies. The desire to protect nuclear electricity seemed to be the main rationale for
such a duopoly structure in the generation market. In order to accommodate the nuclear power
plants the privatisation programme provided for the creation of two generating companies (more or
less the initial uncompetitive structure adopted in New Zealand and Chile); National Power and
PowerGen.
National Power was to own all the nuclear plants, in addition to approximately one half share of the
fossil fuel plants. PowerGen was to absorb the remaining fossil fuel plants. A Power Pool was
advanced as the main price setting mechanism for bulk electricity, supported by contracts of limited
term outside the Pool. The Pool was to involve a “double sided” pool structure. Additionally, the
105
high voltage transmission and grid system was to be hived off and operated as an independent
company.
Government soon discovered that the financial market was sceptical of the proposed arrangements.
The massive liabilities for spent fuel disposal and decommissioning, as well as the short remaining
operating life of the Magnox nuclear plants presented unacceptable commercial risks, with the result
that these had to be withdrawn from the privatisation programme in July 1989. The high rate of
return required by private finance for the advanced gas-cooled reactors (AGR), also made these
nuclear plants uncompetitive. Nuclear generation was a practical proposition so long as it was
publicly subsidised. The policy was therefore, amended to provide for the privatisation of National
Power without the nuclear plants. A new enterprise, Nuclear Electric, was to be created to own the
nuclear plants and to continue operation as a state owned enterprise. With a political commitment to
nuclear electricity, government found a face saving solution by imposing a 10% fuel levy on all
electricity sales and this was to provide 40% to 50% of Nuclear Electric annual revenues in the initial
years. The result of the commitment to nuclear was that these plants were mandated “must run
plants”. The nuclear sector was to be excluded from bidding into the Power Pool. Fortunately, the
European Commission imposed a requirement for the fuel levy to be phased out by 1998. British
consumers, however, were required to shoulder the stranded costs of the nuclear assets during the
early years following privatisation.
In the autumn of 1989 the double sided pool structure which was to involve both generators and
power purchasers bidding into the exchange also had to be abandoned in favour of a “single sided”
pool structure involving bids only from generators. It was discovered late in 1989 that the complex
computer software needed for a double sided pool could not be completed in time for vesting day,
March 1990 when the Pool was to come into operation. This development led to removal of the
requirement for purchasers placing bids into the Pool at the prices at which they were prepared to
buy and made the price mechanism a market clearing system for generated electricity. The basic
principle of a market-clearing price is that there are sufficient independent bidders in the Pool so
that the chance of anyone firm influencing the price is negligible. The assumption in this particular
instance was that Bertrand duopolies would deliver such competition.
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Writing just prior to the publishing of the Government White Paper, Vickers and Yarrow (1988)10
identified four restructuring options as being available to the policy makers; continued vertical
integration of the Central Electricity Generating Board )11, unbundling CEGB into a number of
regionally integrated generation and transmission companies, vertical separation of transmission and
generation and horizontal unbundling into several generators, vertical reintegration of distribution
with generation and transmission and separation into a number of fully vertically integrated regional
companies. Since the twelve Area Boards, the regional distributors were already vertically separated;
reintegration was more or less ruled out. Vickers and Yarrow did not see privatisation of the
distribution as sufficient condition for competition. The advantage of privatisation of the
distribution companies is that they would be less likely to collude with the generators, and there
would be more incentive to shop around for lower cost sources of bulk electricity supply.
What was seen to be more important was the regulatory structure, which was to be put into place
for the distribution companies following privatisation. Despite emphasising the importance of
regulation to secure efficiency enhancing outcomes, the US style rate of return regulation was also
advanced by Vickers and Yarrow as the method of price regulation for the distribution companies,
as against the incentive price-cap regulation earlier introduced for telecommunications, on the
grounds that the general public interest guidelines introduced in the periodic rate reviews would be a
potential source of investor uncertainty, with the potential for under-investment in the distribution
sector.
Continuation of the vertically integrated CEGB, as well as creation of regional monopolies, either as
vertically integrated transmission and generation firms or as fully vertically integrated generation,
transmission and distribution companies all presented serious market power problems as well as
problems of non-discriminatory access and barriers to entry that would have required heavy handed
regulation. Vickers and Yarrow came down in favour of vertical separation of generation from
transmission and several horizontally separated generators. The number of generation companies,
however, was not seen to be critical as long as free entry was possible, as the market would provide
its own correction. However, in the case of transmission Vickers and Yarrow concluded that:12:
“We believe that, if a separate transmission firm is to be established, there is a strong
case for independent ownership (possibly public) and control of the resulting entity.
The independence of this firm from the generation and distribution companies
107
would assist the development of a more competitive market in bulk electricity and
public ownership might be the best way of dealing with the considerable market
power that the firm would possess -----Again we would warn against excessive reliance on structural remedies alone.
Whatever structural option is chosen, it is likely to be the conduct of regulatory
policy that will have the most significant effect on industrial performance.
With the exclusion of the eight older Magnox nuclear plants Henney (1987)13 argued for four or five
privatised generation firms. Statistical studies of US generation system also seem to have supported
the case that ten viable generating companies could have been created from CEGB14.
Veljanovski (1980)15 also called for horizontal unbundling into several competing generators and felt
that the CEGB’s 38 fossil-fuel power stations (all the generation sets in excess of 100 MW)
presented an opportunity to create eight unbundled companies, with average capacity of 6000 MW,
which was seen to have been large enough to maintain scale economies in operation.
The smaller Scottish system of 10000 MW capacity and 5600 MW peak demand, including 800 MW
of exports to England and Wales in 1990, presented very different problems. The South of Scotland
Electricity Board (SSEB) was 50% nuclear and North Scotland Hydro-Electric Board (NSHEB) was
mostly hydroelectric. The different plant mix and the several routes with low densities in terms of
end user connection called for a different solution. The substantial excess capacity also presented
very little opportunity for new entrants; hence the case for radical restructuring of the Scottish
system at the beginning of the 1990s was then seen to be weak. The considered options were to
leave the integrated structure or to separate the industry into one generation and Transmission
Company and several distribution companies. Either option, however, was seen to create the need
for heavy-handed regulation.
Northern Ireland, the much smaller system of less than 2000 MW capacity and 1500 MW peak
demand and with a thin route distribution structure was seen to present limited options, much the
same as in Scotland. When economies of scale consideration are taken into account major structural
reforms of the Scottish and Northern Ireland systems, were ruled out by the policy makers and the
analysts.
108
The Pre-privatisation Structure
Public electricity supply in the UK goes back to 1881, when a private firm, Siemens began operation
of a small hydroelectric generating plant in Godalming, Surrey. Between 1881 and the entry of state
ownership in the 1940s the system was based around a structure of small scale, local, private or
municipal undertakings, each operating in a particular area. Private firms were more common in the
distribution sector. The Weir Committee Report16 of 1925 identified six hundred separate electricity
supply undertakings, operating from four hundred generating plants. A 1919 Electricity Act served
for the first time to introduce regulatory oversight through an Electricity Commission. State
intervention came at the national level with the Electricity (Supply) Act of 1921, which mandated the
establishment of a Central Electricity Board to construct and operate a national system of
interconnected generation plants.
As a result of this Act the state came to dominate the generation market; however, in the inter-war
years the private sector continued to play an important operational role in the distribution sector.
The Electricity Act of 1947 brought about full nationalisation of the electricity supply system. This
Act mandated the establishment of the British Electricity Authority (BEA) in England and Wales
and Southern Scotland to own and operate generation plants and to supply bulk electricity. BEA
operated 12900 MW of capacity through 297 power stations in 1947.
At the time of nationalisation there were 569 distribution undertakings, with two thirds connected to
the national grid. These undertakings were later consolidated into 14 Area Boards and constituted as
statutory bodies, responsible for distribution and supply in exclusive or franchise zones. Twelve of
the boards covered franchise areas in England and Wales and two in Southern Scotland.
In 1943, the North Scotland Hydro-Electric Board was established to promote both public
electricity and economic development, followed by the establishment of the South of Scotland
Electricity Board in 1955. The two Scottish Boards came to operate as vertically and horizontally
integrated generation, transmission and distribution enterprises. In Northern Ireland a vertically
integrated generation, transmission and distribution public enterprise; Northern Ireland Electricity
(NIE) was established in 1972 and in 1975 a 300 MW interconnector linked the Northern Ireland
system with the Republic of Ireland.
109
In England and Wales, the 1957 amendment of the Electricity Act further mandated clear separation
of generation and bulk electricity supply functions from the distribution and retail supply activities.
The Act provided for the creation of the Central Electricity Generating Board (CEGB) with its
responsibilities restricted to power generation, national grid operation and construction. At the same
time the Area Boards were restricted to distribution and retail supply. The amendment also provided
for Electricity Council, with a supervisory role over the entire industry.
The earlier British
Electricity Authority operated as a highly centralised system, especially over industry policy and the
finances of the Area Boards. Earlier, the 1954 Electricity Reorganisation (Scotland) Act had reduced
the Area Boards to twelve and provided for the two Scottish Area Boards to be restructured into the
two vertically integrated utilities.
The system was supplemented by self-generators and by small imports from the state owned
Electricite de France (EdF) and this system remained intact up to 1990. The CEGB they provided
95% of the power needs, with the small self-generators and EdF the rest. After 1957 the Area
Boards were given the right to enter the generation market. However, few did so and only at the
level of small-scale operation.
By the late 1960s a number of problems, which worked against efficient operation of the system,
began to be identified. The industry was not seen to be commercially driven and did not regard itself
as having customers. Its monopoly power in product market translated into disproportionate
bargaining power of the unions, allowing workers to extract wage rate increases greater than their
annual increases in productivity. As the industry did not operate in a competitive market and did not
face takeover threats, there was very little incentive to stimulate efficiency enhancing behaviour.
The politicising of the industry’s decision-making resulted in uncertainty as to whether commercial
objectives should take priority over political and public service objectives. Investment and pricing
decisions came to be influenced excessively by short-term considerations.
Added to this the
government operated an industrial policy over the years which involved electricity providing massive
cross-subsidies to prop up the coal and nuclear industries. Electricity was required to take all the
supply of coal produced, regardless of the economics of other fuel sources.
110
A succession of Government White Papers in 1961, 1967 and 1978 on the nationalised industries, as
commented on by Heald (1980)17 and which dealt with financial targets and the relationships of the
enterprises with government did not bring any lasting solutions. The new price targets called for
rates of return on averaged capital employed of 2.7% pre-tax (real) and 5% on new investment. In
the 1980s, restrictive cash budgets were introduced with the requirements for the industry to reduce
controllable unit costs per kWh by factors varying from 4.25% to 6.1%.
Well intentioned statements which called for prices to be based on long run marginal cost and to
adopt test rates of discount similar to those used for low risk private investment, however, were
more often than not overridden by political considerations. More so, there were practical difficulties
in the application of these economic concepts in the monopoly utility industries.
These decision rules may have reduced the industry’s ability to extract monopoly profits, but
reflected cost plus pricing principles and therefore, provided minimum incentives to CEGB to act
efficiently, especially where it had monopoly of information. In the main these policies were
abandoned by the Thatcher administration in the 1980s and electricity prices were increased as part
of the government’s macro-economic policy objective to reduce government’s short-term
borrowings. Electricity prices had shown a decline in real rates in the 1980s. In the domestic sector,
real prices of electricity had declined steadily in the period up to publication of the 1988 White
Paper.18.
Prices in the immediate pre-privatisation years were rebalanced so as to make prices closer to relative
costs of supply and generally increased as part of the process of making the companies more
attractive for floatation. Prices of bulk electricity rose substantially relative to prices of other
industrial fuels. This was partly because of the removal of some of the cross-subsidies to industry.
Total capacity in 1987 was 63869 MW, with 79% supply coming from fossil fuel sources. Maximum
demand was 52000 MW, with E&W accounting for 87.5%, Scotland 10% and Northern Ireland
2.5%. The total transmission and distribution lines in England and Wales amounted to 390,000
miles, connecting 24,754 customers. Over 2% of GNP was accounted for by the industry. The
structure of industry costs in the pre-privatisation period typically consisted of fuel 42%, generation
29%, and transmission 6%, distribution 19% and retail supply 4%. Any significant economic
efficiency gains had to come from the generation end of the market.
111
Table 1 below shows the other main characteristics of the industry in the UK in 1989. Fossil fuel
accounted for 79% of fuel source, nuclear 10% and hydro 6%. Natural gas as a fuel source hardly
existed. Additionally, there were 24.7 million customers, of which 22.4 million were small domestic
household users. Figure 20 shows the pre-privatised England and Wales industry structure of a
vertical integrated generation and transmission company and 12 regional distributors; Area Boards,
as well as linkages through two interconnections respectively to Scotland and France.
Table 1
Characteristics of the UK System
In the 1980s
Capacity by Fuel
Source
Capacity
MW
Fossil Fuel
Nuclear
Hydro &
Pumped Storage
Single Cycle Gas
Turbine and Diesel
Total
Source:
Consumer Category
Number
Thousands
%
50263
6519
4085
79
10
6
Domestic
Farm
Industrial/commercial
22,383,000
863,000
2,103,000
3001
5
Other
5,000
63.869
100
Total
24,754.000
John Cheshire, “UK Electricity Supply Under Public Ownership”, (The British Electricity
Experiment, Privatisation; The Record, The Issues, The Lesson, ed., John Surrey,
London (1996) p.16.
In the later part of the 1980s the Thatcher administration became concerned about a number of the
inefficient features, which had emerged in the industry. CEGB had come to exercise too much
power over generation station investment decisions as well as over distribution prices. As part of a
policy of liberalisation an Energy Act was introduced in 1983 providing for the liberalisation of the
energy market. The Act sought to reduce the barriers of entry faced by private operators and to
break the monopoly of the CEGB on the generation market and in so doing provided for Area
Boards to purchase bulk electricity from private generators at rates published as Private Purchase
Tariff (PPT), calculated to yield only normal rates of return on capital employed and for the CEGB
and the Area Boards to provide open access to the transmission and distribution lines.
112
Liberalisation, however, had little effect. The policy sought to create competition for new capacity,
whilst preserving
Fig. 20
Pre-Privatisation England and Wales Industry Structure (1987)
CEGB
Area Boards
Domestic
Consumers
Area Boards
Genco
Transco
Area Boards
Scotland
Industrial &
Commercial
Consumers
Some Large
Consumers
EdF
(France)
Integrated
Generation and
Transmission
Source:
(12 Area Boards)
Distribution and
Supply
Large and
Small
Consumers
John Vickers and George Yarrow, “The British Electricity Experiment”, Economic Policy
(April 1991), p.191
113
the centralised control. CEGB predictably responded to removal of its monopoly power by
introduction of artificially high prices, which served to impede new entrants.
The Private Purchase Tariff was not only based on the Area Boards’ avoidable costs but also on the
bulk supply tariff (BST) of CEGB. The response of CEGB to the threat of competition from
private providers was to restructure BST in a way that made it unprofitable for private providers of
bulk electricity to enter the market. The raising of the non-avoidable cost component of BST,
through the introduction of a new system charge and a non-marginal energy charge had the effect of
increasing the fixed charges in BST from 1% of total revenue generated from Bulk Supply Tariff in
1983/84 to over 20% in 1987/89. The increase in the unavoidable cost component of BST
effectively reduced the average price paid to private generators to well below the average cost paid
by the Area Boards for CEGB bulk electricity. Competition failed to emerge, not so much that the
principle was wrong but because government allowed the dominant player to set the terms of
wholesale price and PPT.
The policy sought to create competition for new capacity, whilst
preserving the centralised controls. CEGB predictably responded to removal of its monopoly power
by introducing artificial cost barriers to new competition.
The Thatcher administration then concluded that the operation of the power supply system did not
have to be determined by ownership. State ownership had resulted in too much interference in the
day-to-day running of the industry and industry managers were denied the freedom and economic
incentives to make commercial decisions. Government up to that time intervened in the
appointment of all the board members, approved all major investment expenditures, approved
borrowing requirements and controlled the retail prices of the Area Boards.
Government’s restructuring policies, which were announced in the 1988 White Paper, were enacted
in a new Electricity Act of 1989. This Act provided for vertical and horizontal unbundling of
generation from transmission, and the liberalisation of the generation market in England and Wales.
Liberalisation of generation meant that new independent power producers were free to enter the
market to provide bulk power supplies. Government’s new policy called for the creation of a
competitive electricity industry. These policy changes were expected to relieve government of the
financial burden of the industry and in the process provide for wider public share ownership.
114
The newly established generating companies were to be privatised. The unbundled transmission line
and grid system was to be restructured as the National Grid Company (NGC) to be jointly owned
and controlled by the 12 regional distribution monopolies (RECs). The National Grid Company was
to maintain a central role in planning and coordination and was to be responsible for the dispatch
function. The merit order system of dispatching was to be maintained with the cheaper plants being
the first to be dispatched to meet a given demand. Generating companies were to be prohibited
from cross-ownership with the transmission company so as to avoid future control of the
transmission system by companies owning power stations. The National Grid, however, was to be
allowed to own the pumped storage stations. The policy changes meant that the generating
companies were to face competition for new capacity as well as competition at existing demand for
the first time, that of product market competition.
The changes also provided for the twelve English and Welsh Area Boards to be incorporated as
joint stock companies and privatised. NGC was to operate in future on the basis of contracts as
against the command and control relationship, which prevailed under CEGB.
Distribution
companies were to be allowed to contract for electricity with the NGC or directly with existing or
new generating companies for generating capacities. The statutory obligation to supply was to be
removed from generating companies and placed on the distribution companies. New generating
plants were to be introduced into the system through competitive tenders. The RECs were to be
allowed to meet capacity needs from importation, purchase from existing generators or from
contracting with new independent power producers. They were also to be given the right to own
generating stations when this did not create local monopolies in their respective franchised areas and
in this respect were allowed to generate up to 15% of their own power needs, subsequently
increased to 25%.
Integration of generation with distribution, however, creates a potential self-dealing conflict in the
wholesale power market model as the distributing companies which have captive customers and
have the opportunity to pass these higher costs will display very little interest in cost minimisation
and will procure its self-generated power. Where there is competition in the retail market and the
opportunity to pass on higher costs is reduced, this problem is more or less eliminated. Competition
in the retail market allows customers to choose other retailers.
115
Adjacent distribution companies were also to be allowed to compete on the border (border
competition) to supply large users. Large users were to be allowed to by-pass the distributor and
contract directly with generators. Both the transmission system and the distribution lines were to be
mandated as common carrier and in so doing provide free and open access to their systems. Tariffs
were to be developed to reflect common carriage charges, which in turn were to reflect user costs.
The transmission and distribution systems, being in large part natural monopolies were to be
regulated by an electricity industry specific regulator; the Director General of Electricity Supply
(DGES). This industry regulator was to replace the Electricity Council, which was to be abolished.
The old rate of return-cost of service system for rate determination was to be abandoned and
replaced by incentive or price cap regulation in the form of RPI-X in the transmission and
distribution sectors.
The industry was expected to operate efficiently so that consumers could benefit from improved
performances. The monopoly aspect of distributing companies; the lines business was to be “ring
fenced” from retail supply with separate accounts to be produced for each of the separate business
activities. Distributors were to operate under specific licences called public electricity licences, (PES)
and the DGES to be responsible for licence enforcement, price and service quality regulation, and
regulation of open access to the transmission and distribution systems and to ensure protection of
consumer interest.
In Scotland, SSHEB and SSEB were to be replaced by two newly incorporated joint stock
companies; Hydro-electric (HE) and Scottish Power (SP) respectively, however, the Scottish nuclear
stations were to be horizontally unbundled into a new company; Scottish Nuclear (SN). The vertical
and horizontal integration of the Scottish two utilities were to remain unchanged.
In the case of Northern Ireland, the generating stations were to be vertically and horizontally
unbundled and privatised as three separate companies through trade sale. Transmission, distribution
and supply activities of the Northern Ireland, system were to be incorporated as a single joint stock
company; Northern Ireland Electricity (NIE) and floated on the stock exchange.
116
Restructuring the England and Wales Electricity System
Government had received considerable criticism in respect of the earlier monopolistic structure
created for privatised telecommunications and gas companies and a genuine attempt was made to
provide for more competition in post-privatised electricity. Gas was in fact privatised without
restructuring, resulting in a change from a publicly owned franchised monopoly to a privately owned
franchised monopoly. Despite the more fragmented structure, when compared to the earlier cases of
telecommunications and gas, government’s policy towards electricity continued to follow
organisational conservatism as manifested in the earlier utilities privatisation19.
Robinson, (1989)20, stated that:
“ the privatisation programme of the last few years demonstrated the inevitability of
illiberal schemes for major industries. From the point of view of public choice
theory, there will always be an irresistible combination of powerful forces in favour of
retaining big monopoly where corporations are earmarked for transfer from the state
to the private sector. Pressure groups; the management of the corporation, the
unions, the city and political forces in the Treasury will successfully resist genuine
competition and only token gesture will be made in the direction of effective
competition. Moreover, the social benefits of increased competition is not only
intangible their realisation tend to be long-term”.
Vertical and horizontal separation of the different stages of electricity production raises a number of
problems, such as market power, transactional costs and scale economy issues. Transaction cost
occurs when electricity as a product is transferred across technologically separate interfaces or
hierarchies. Transaction cost that, arises is the cost of operating the new electricity market systems
and covers price discovery, search for information, negotiation and contracting costs and policing
and enforcement costs. The more the number of separate interfaces the higher the quantum of the
transaction costs. Economising in transaction costs is a motivating force for viable modes of
contracting and an important feature in guiding restructuring and organisational design of the
electricity sector.
117
Within the vertically and horizontally integrated firm, marketing and organisational costs are
internalised and reduced, not eliminated, as the firm does not have to make a series of contracts with
other agents of production interfaces. When there are transfers over several separately owned
interfaces, a series of contracts replaces internal coordination and in the case of electricity the firms
have to agree to obey the directives of a central control agent; the system operator, within certain
limits. The competitive forces released by competition must therefore, result in savings and benefits
to counter balance the increased transaction costs and losses from diseconomies. In the case of
separation of transmission from generation, because of the strong vertical relationship and vertical
economies and the unique characteristics of an electricity product, several problems will arise. In
fact vertical disintegration is being imposed precisely over the two sector interfaces where vertical
coordination is crucial. Complete deregulation of the bulk electricity market is unlikely to be realised
in the near future; therefore, there will be the need for some measure of light-handed regulation.
In terms of vertical and horizontal reforms in the distribution and retail supply sectors, there were
no structural changes introduced, as the pre-existing twelve regional enterprises were privatised
intact. Structural separation of distribution lines business from the more competitive retail supply
business was ruled out in favour of the weaker accounting separation. Supply was separated
vertically in the accounting sense; however, vertical ownership and control in the organisational
sense was maintained.
Allowing distribution companies, however, to perform retailing, reduces market competition,
because distribution companies are in a position to subsidise their retail customers by imposing
higher tariffs on the monopoly lines business, larger than cost justifies. Integration also allows the
distribution company to discriminate between classes of consumers21. Accounting separation
partially addresses the problem.
Each REC, however, was given special public electricity supply licences, setting out its rights and
obligations relating to supplies for designated customers within its designated area. These licences
gave the REC monopoly rights to certain parts of the market. The only innovation in the retail
supply sector was the introduction of second tier licences, which were given to the RECs and other
suppliers and which allowed holders of such licences to sell to any customer in the competitive or
118
liberalised market, including the REC’s domestic market. Second tier licences were given not only to
the RECs but also to the generating companies and a number of new suppliers.
Competition in the retail market was to be phased, and was first to involve liberalisation of large
consumer market (consumers with a maximum demand of 1 MW and over) in 1990, to be followed
by medium sized consumer market (consumers with maximum demand of over 100 kilowatt hours)
in 1994 and finally choice was to be given to the small domestic consumer market (consumers with
peak demand of under 100 kW) in 1998. In order to participate in the liberalised market customers
had to install a half-hour metering system with on-line communication facilities. The large customer
market was required to have these meters from 1990, whilst the medium sized customer market was
given an option up to 1998. Small customers desirous of participating in the liberalised market were
also required to install half-hour metering or they could opt to stay with their REC, without the
obligation to install half-hour metering. RECs were required to sell to captive customers at regulated
prices in their designated areas and were prohibited from cross-subsidisation. As full competition
progressed, the distinction between public electricity suppliers and second tier suppliers are expected
to disappear. An important development in the small user market has been the widespread use of
pre-payment meters.
Economy of scale is not a serious factor with electricity distribution. Economies arise more from
intensity of customer distribution, rather than number of customers and the total turnover in a given
area. Several more distribution companies could have been accommodated when one considers that
the average size of distribution companies in New Zealand was 50,000. Increased number of
companies would have provided the opportunity for increased yardstick competition. The rigid time
scale set for privatisation and the need to ensure the attractiveness of the proposed sales to private
investors, however, dictated government’s privatisation of the distribution companies in their
existing form. Creation of new distribution companies and vertical separation of distribution from
supply and creation of new supply companies would have facilitated more competition; however,
the establishment of new supply companies would have been time consuming. It was also concluded
that floatation of these new companies with no track record on the stock market would have been
far too risky.
119
An important vertical structural issue relates to the extent to which the RECs were permitted to
generate power for own use. Options ranged from partial exclusion from the generation business to
that of compulsory competitive tendering and or regulator’s audit of procurement of new capacity.
The option selected for England and Wales was that of partial vertical integration and this arose
from the fact that the RECs were allowed initially to source up to 15% of power needs from own
generation. Many RECs in the so called “dash for gas” quickly came close to filling their quota 22.
With joint ownership of the transmission company by the twelve RECs, other vertical issues were
raised.
This partial integration of transmission and distribution did not follow any logical reasoning, either
from the position of history, or economics. There are no serious economies of scope to be gained
from linking transmission with distribution and vertical integration is not necessary for technical
reasons. In order to reduce the risk that the RECs would manipulate the policies of the National
Grid Company (NGC) to serve their own interest, severe restrictions were placed on the extent to
which the RECs could influence the policies of NGC. Again the desire to make the privatisation
packages for the distribution companies attractive to investors seems to have motivated this
arrangement.
Further structural issues are raised in respect of the presence of the transmission operator in the
generation market. NGC was allowed to own the two hydroelectric pumped storage generating
plants located in Wales. Whilst the size was less than 2000 MW, they were strategic with regards to
the efficient operation of the system. These plants not only played a key role in assuring system
stability, they were able later to set pool prices in 1994 by 15% of the time.
The UK model of restructuring the electricity supply industry has had a major influence on other
reforming countries, however, no single preferred model has emerged internationally as to the best
ownership and governance structure of the transmission operator as well as to the functions this
entity should perform. There is a clear trend, however, in favour of more open access and neutrality
and a move away from any vertical integrated relationship with
generation or distribution.
Separation of the monopoly transmission lines business and system operation functions from the
companies selling electricity, either in bulk or in retail form is necessary to remove concerns relating
to possible self-dealing and discriminatory behaviour.
120
Arguments have been advanced for the transmission company to remain publicly owned as is the
situation in New Zealand. In Bolivia as we shall see later, ownership of transmission was transferred
to a private operator in the form of a long term concession. The argument for initial public
ownership of the transmission company is that it leaves government more options in terms of later
reforms and the level of competition, which can be introduced into the system23. This, however,
does not establish the need for government to operate the system. Management and operation can
be contracted out to private providers who are specialist in delivering transmission services.
Valuation and pricing of the transmission grid is extremely difficult, as traditionally this component
of the electricity system has been shielded from exposure to external markets. The result is that at
the time the 12 RECs were given joint ownership of NGC the company was valued at £1 billion.
Within five years the NGC was sold at a value substantially higher than its original privatisation sales
price.
In the England and Wales reform the NGC was entrusted with the function of systems operation,
with responsibility for dispatching of generators and maintenance of system stability, as well as
overall physical maintenance and investment in the system. In this regard, it was permitted to
purchase standby power from generators to maintain security of the grid. NGC also coordinates the
daily operation of the market, drawing up the merit order schedule and calling plants on the grid as
well as administering the pool settlement (financial outcomes) between generators and traders.
Additionally, it coordinates transfer across transmission links involving the French and Scottish
interconnectors. The conduct of these activities is governed by general agreements between the
generating companies, the RECs and other traders and forms the pool’s market rules. Finally, NGC
was given a specific mandate to facilitate competition in the electricity supply system.
In addition to separating out transmission into the National Grid Company in April 1990, the
generation assets of CEGB were restructured into three new companies. The fossil fired-plants
(mainly coal fired) were divided into two companies; National Power and PowerGen with the
nuclear assets going to Nuclear Electric. A limited amount of the hydro-plants went to National
Power and PowerGen and the greater part of the pumped storage as indicated earlier going as First
Hydro to NGC. Additionally, the liberalisation of the bulk electricity market also allowed for entry
121
of new plants, as well as facilitating competition from Scotland and France through the two
interconnectors.
The share of the thermal capacity at unbundling was National Power 65% and PowerGen 35%.
The original privatisation plan, which called for a duopoly with all the nuclear plants going to
National Power, would have given that company 67% and PowerGen 33%. The overall market
share of generation capacity in 1990 was National Power, 51%, PowerGen 31%, Nuclear Electric
14% and First Hydro 4%. National Power was allocated 40 power stations with 29486 MW
capacity, PowerGen 23 stations with 19802 MW capacities, Nuclear Electric 12, nuclear stations with
7963 MW and First Hydro was allocated 2000 MW pumped storage capacity. The installed capacity
in the England and Wales market was just over 59000 MW with peak demand of 49000 MW.
The net effect was an asymmetric duopoly structure, motivated by the desire to package the plants
with the more attractive non-nuclear system. With the decision to separate out the nuclear capacity
and retain nuclear in the public sector the option of resorting to a larger number of generating
companies was rejected with the result of another missed opportunity in creating a more competitive
structure. Again the rationale seems to be the politically motivated timetable to complete the
privatisation before the 1991 election. The logistical difficulties related to the development of a more
fragmented industry structure it was feared would have risked a delay in the sale. A disintegrated
structure also would have been less attractive to investors.
This duopoly structure gave considerable market power to the two thermal generating incumbents
and this is over and above being incumbents with monopoly of information on generation.
Although the price elasticity of demand for electricity is low, given the homogeneous nature of the
product the price elasticity for the product for any generator is very high. Within a duopoly
structure, therefore, there is a strong incentive to take advantage of the inelastic industry demand
curve by suppressing competition either through collusion or gaming behaviour.
Government relied on competitive transformation of the industry on a policy involving free entry to
the generation market. The initial structure was considered to be of transient importance. The
Schumpeterian (1976)24 gale of creative destruction in due course would compete away any
monopoly profits of the incumbents and correct the imperfect initial industry structure.
122
Government, however, was to impose a number of restrictions on the competitive transformation
process by imposing the fossil fuel levy or tax on electricity purchases. The bulk of this charge was,
however, discontinued in 1996. Most of the cross-subsidy after 1996 went to the other renewable
energy sources. It was also possible to eliminate the entire non-fossil fuel obligation in 1998, mainly
as a result of efficiency and operating performance improvements, which were made by the nuclear
stations. The levy declined from 10% at vesting to 0.9% in 1998. Market restriction was also created
from mandating the RECs to buy specified amounts of non-fossil fuel every year until 1998. An
interesting development from this energy policy has been the rise of wind power from virtually
nothing in 1990 to 700 MW in 1999.
In the inter-war years use of natural gas in power stations was defacto banned and was only
allowed after the discovery of North Sea gas in the mid-1960s. Although constraint on fuel use was
relaxed in 1990 for National Power and PowerGen, diversification move were hampered from
government’s insistence that the two companies sign contracts with British Coal for the first three
years of privatisation, up to March 1993. In this period, the requirement was for 70 million tonnes a
year, reducing to 65 million. The contracts were further extended for four years from 1993 to 1998,
however, subsequently the quantities were reduced to 40 million tonnes and then to 30 million.
On critical examination, the radical restructuring thesis therefore, does not stand up to scrutiny. The
development of a competitive optimal structure had to contend with more powerful political factors
such as creating financially secure companies sufficiently attractive to the city financiers and
potential shareholders and the need to protect the nuclear and the coal industry.
Privatisation Programme
The two non-nuclear power companies and the 12 regional distribution and supply companies were
privatised by public floatation. All the shares of the RECs were sold in December 1990 for £5.1
billion. Included in the sale of the RECs was the sale of NGC. Only 60% of the generating
companies’ shares were offered and sold in March 1991 and the shares fetched £5.7b. Scottish
Power and Hydroelectric were sold in June 1991 for £ 2.8 billion and the Northern Ireland
123
Distribution and Transmission Company, NIE in June 1993 for £ 418 million. Table 2 below sets
out the financial proceeds of the privatisation programme between 1990 and 1996
Table 2
Electricity Privatisation Programme 1990 – 1996: Sales Proceeds
Companies
Date
RECs
PowerGen
National
Power
PowerGen
National
Power
Scottish
Power
Hydro
Electric
NIE
British Energy
Total
Dec. 90
Mar. 91
Mar. 91
100
60
60
CapitaliCost of
sation
Sale
£
£
Billion
Million
2.40
7.7
191
1.75
3.5
79
1.75
Mar. 95
Mar. 95
40
100
5.22
4.86
June 91
100
2.40
June 91
100
2.40
June 93
July 96
-
100
100
-
2.20
2.03
-
Source:
%
Share
Sold
Share
Price
£
Equity
proceeds
£
Billion
5.1
Debt
Repay
£
Billion
2.8
2.17
0.8
-
57
3.6
-
2.9
98
2.8
0.6
0.362
1.4
-
31.5
32.0
488.5
0.418
1.4
15.48
(0.7M)
0.6
4.87
Carole Hicks, 1998, Regulation of UK Electricity Industry, London, Centre For The
Study of Regulated Industries (1998), p. 11.
The remaining 40% of the PowerGen and National Power were sold in March 1995 for £10.8
billion. Most of the shares in British Energy, the commercially viable part of the nuclear generating
facilities was sold in 1996 for £1.4 billion. Trade sale of the Northern Ireland generating stations in
1992 also fetched £356 million. Overall sales proceeds amounted to £15.48 million.
Ownership of the National Grid Company was subsequently removed from the RECs. The
company’s shares were floated on the stock market in 1995 as National Grid Group (NGG). The
pumped storage plant as First Hydro was also unbundled in 1995 and ownership transferred to
Edison Mission Energy, an American owned company by trade sale.
Almost all the new owners of the privatised companies were required to take over debt obligations
from the previous state owned enterprises. Included in the balance sheet of the twelve RECs were
124
debts amounting to £2.8 billion, with repayment obligations imposed on the part of the new owners
over a period of 18 years. In the case of the privatised fossil fuel companies, the debt obligation
transferred was only £800 million, with requirement for repayment in three instalments; April 1991,
March 1998, and March 2005. In the case of the Scottish companies new debt amounting to £600
million was created and was to be repaid in varying instalments by 2005. A total of £417 million of
the Scottish Utilities debt were completely written-off, as well as the outstanding corporation tax
losses arising out of unused capital allowances and amounting to £505 million. A total of £70
million in debt was taken over by the new owners of British Energy, whilst £600 million was
retained in the balance sheet of the privatised company with instalment payment obligation up to
2016. A total of £700 million of inherited debt in British Energy was also converted to share capital
with the remaining £445 million being written off.
The treatment of the state owned utility enterprise debt has presented major problems for
developing countries in their privatisation programme. It is clear from the policy adopted that the
British Government sought to maximise cash flows. With a high proportion of households already
connected to the system and having access to electricity, there was less pressure for new capital to
expand the system as was the case later in Bolivia. In the British privatisation the sales proceeds
went to the Treasury, whereas in Bolivia the sales proceeds, in most cases went to the company to
expand the system.
In the divestiture of utilities and essential services governments have sought to retain some measure
of control following upon privatisation of the public enterprises. Many countries have opted to sell
minority shareholding to a strategic investor with a management contract, giving the strategic
investor management and operational control of the company. In the British case, in almost all
instances, the entire shareholdings of the companies were sold to private portfolio investors. Britain
had the option of a well-established stock market and therefore, stock market flotation was widely
used to dispose of the utilities. In many developing countries stock markets do not exist and even
where they do, their absorptive capacities are thin. Britain also introduced a new special share
arrangement, which came to be known as the “Golden Share”, and which limited the voting rights
of the private shareholders in special circumstances. The Golden Share more or less carried reserved
rights conditions, requiring agreement of the Government in respect of clearly stated circumstances.
125
The Golden Share gave the UK Government the power to veto changes to the share structure
where one person or entity sought to acquire 15% or more of the voting rights, or to vary the voting
rights of any of the existing shares or to issue new shares with voting rights different from those of
the ordinary shareholders of the company. Except for the NGG the Golden Shares in the privatised
companies were all redeemable.
Those in the distributing companies were redeemed in March of 1995, whilst those in the two
generating companies were redeemed in 2000. In the case of NIE and the two Scottish companies
these shares were redeemed in 1998 and in the case of British Energy they are eligible to be
redeemed in 2006.
The restriction on the size of the share ownership not only served to limit the scope for reintegration and restoration of monopoly operation it also served to restrict competition in the
market for corporate control. It has become a practice in privatisation contracts to limit crossownership between generation and distribution companies, as well as between the generation and
the distribution companies on the one side and the transmission company on the other.
The 1996 Articles of Association of NGG initially prohibited any Pool member, electricity licence
holder, or member of a distributing group from having an interest of 1% or more in the voting
rights of NGG. Restrictions were also imposed prohibiting NGG from holding a generation or
electricity supply licence and from any Pool member of an electricity licence holder from being a
Director of NGG.
Post-Privatisation Changes to the Industry Structure
Given the imperfect market structure at privatisation, the regulator was left with no option but to
intervene into the market to facilitate a more optimal structure.
First, he mandated the
discontinuance of the REC’s joint ownership of the NGC in 1996. The regulator regarded this
relationship as potentially anti-competitive and inappropriate in that its independence could be
compromised. There was, however, no evidence of exploitation. Second, the regulator regarded the
vertical relationship of NGC with the pumped storage generation plants as carrying a conflict of
interest as NGC was a competitor in the non-base load bulk electricity market and therefore,
126
requested unbundling of the pumped storage generating capacity in 1995. This led the system being
incorporated as First Hydro and divestiture to Mission Energy in January 1996 for £680m.
The Regulator also became concerned about the duopoly non-nuclear generating market and the
market power of the two players to determine pool prices. A voluntary agreement was reached to
sell 6000 MW of their coal fired plants to competitors by March 1996. In the autumn of 1995
PowerGen sold 2000 MW to Eastern Electric (now TXU Europe). A year earlier Eastern Electric
was taken over by the Hanson Group. In April 1996 National Power sold 4000 MW of plant
capacity also to the Hanson Group. The 6000 MW capacity involved 5 coal fired plants and were
disposed of under 99-year leases. Further transfer of approximately 8000 MW of generation plants
from PowerGen and National Power were also affected in 1999. PowerGen sold 4000 MW to
Edison Mission Energy and National Power sold 4000 MW to AES. A further 2000 MW was sold to
British Energy. PowerGen also sold 2000 MW of capacity to London Electricity/EdF in October
2000.
Competition in the generation market emerged from several sources. The number of Pool members
has increased from the original 22 in 1990/91 to 95 in 1999/00. This has reflected increased
competition in both generation and supply. Of the 95 Pool members in 2000, 43 were sole
generators, 13 were generators, which were also suppliers, and 39 were suppliers.
The two incumbent duopolies have seen their market share as shown in Table 3 declined from
73.9% in 1990/91 to under 17.8% by November 2000. New entrants mainly combined cycle gas
turbine independent generators have seen their market share rise from 17% to 56.7% in the same
period.
127
Table 3
Output by Market Share-Percentages
National Power
PowerGen
British Energy
BNFL
TXU Europe
Interconnectors
AES
Others
Total
Total Output TWh
Source:
1990/91
1994/95
1998/99
1999/00
45.5
28.4
17.4
7.0
1.7
100.0
268041
33.8
26.0
22.3
8.7
9.2
100.0
274037
21.0
17.7
17.1
8.0
7.7
7.5
21.0
100.0
295114
14.0
14.9
14.8
6.8
5.5
8.3
5.7
30.1
100.0
297550
Nov.
2000
11.0
6.8
15.2
4.1
5.4
6.2
8.3
43.0
100
na
Electricity Association, Electricity Industry Review, No. 5, London, (January 2001), p.41
Three relatively large new players emerged, Edison Mission, Eastern/TXU and AES and they have
come to account for more than 20% of output. Nuclear companies, BNFL and British Energy have
marginally increased their combined market share from 17.4% to 19.3%.
In terms of installed capacity the two incumbents’ share has declined to 22.8%, with the three large
new players accounting for 27.2% of capacity in 2000/01. (See table 4). Market forces and regulatory
intervention have significantly reduced market power and eliminated the duopolistic market
structure imposed on the industry at privatisation.
128
Table 4
Installed Capacity in England and Wales in 2000/01
Company
International Power /Innogy
PowerGen
British Energy
TXU Europe
Edison Mission
AES
BNFL
London Electricity
NRG
Scottish Interconnectors
French Interconnectors
Other Producers
Total Capacity
Own Generation from Distributors
Connected System
Capacity MW
8336
8102
9330
6757
6349
4873
2869
2809
1059
1200
1988
12511
66183
% Share of
Capacity
12.6
12.2
14.1
10.2
9.6
7.4
4.3
4.2
1.6
1.8
3.0
18.9
100.0
4400
-
not
Source: Electricity Association, Electricity Industry Review, No. 5, London, (January 2001), p.35.
The increasing dependence on gas resulted in concerns by government about the security of the
electricity supply system and this led to further government intervention in 1998 when a moratorium
was imposed on construction of new gas-fired plants of significant sizes. Potential investors for
larger gas-fired plants (small combined heat and power plants were excluded) had to obtain new
consent permits. Government not only halted the “dash for gas” episode: a complete review of all
fuel sources was initiated.
Despite the progressive reduction in market shares of National Power and PowerGen, the
Regulator, the Office of Gas and Electricity Markets (Ofgem) continued to be concerned about
market power from the two companies and the limited price competition in the pool price setting.
Although the market share of the CCGT/IPP operators had increased to 25% in 1999 they were
able to set prices for only 3% of the time, compared to 86% of the time by National Power,
PowerGen and Eastern.
129
The Regulator felt compelled to intervene once more into the generation market in October 1999
and published proposals to introduce a new set of licence requirements called Market Abuse Licence
Conditions. These conditions provided that the licensee shall not engage in conduct, whether alone
or in collusion which amounts to an abuse of a position of substantial market power in the
determination of wholesale electricity prices under the relevant trading arrangements. Firms were
therefore, prohibited from restrictive business practices such as collusive price bidding strategies,
withholding capacity of supply and manipulation of market rules. The licences were to be issued to
the seven major generators.
Five of the generating companies consented to the conditions in April 2000 and the other two large
players; British Energy and AES refused to sign the consent licences on the grounds that the
Competition Act already provided the Regulator with adequate powers to deal with market abuse
and as a result the dispute was referred to the Competition Commission. The Commission, however,
handed down a decision in favour of the two operators and Ofgem had to remove the market abuse
conditions from the licences of those generators that had earlier accepted the conditions.
The need for special regulatory rules to control restrictive business and anti-competitive practices,
despite the Fair Trade Practices Act, the Pool Rules and the Financial Services Regulation, highlights
the particular characteristics of electricity, that of non-storability of the product, limited short term
demand side responsiveness and the need to match demand with supply instantaneously. Whereas
traditional criteria for market power by competition regulators have been a market share of over
25%, the UK electricity industry specific regulator was finding that market share of 10% resulted in
market power sufficient to influence price setting in the Pool.
The most important structural change, however which has emerged since 1990, is that of
liberalisation of entry to the generation market. This has led to natural gas becoming the preferred
fuel for new power plants in the UK. Between 1990/91 and 2000/01, 21735 MW of new CCGT
generating capacity had been commissioned in England and Wales. Co-generation capacity also
emerged as an important player and more than doubled by 1998/99, reaching 3,700 MW. There
were four further co-generation schemes under construction in 2000, amounting to 500 MW of
capacity.
130
Table 5
Percentage Share of
New CCGT Capacity Commissioned 1990 – 2000
Generators
PowerGen
National Power
IPPs
Total
Capacity
MW
3040
3200
15495
21735
%
14.0
14.7
71.3
100.0
Source: Electricity Association, Electricity Industry Review, No. 5, London, (2001), p.34.
There was 1875 MW of capacity under construction in 2000/01
The share of ownership of the new CCGT capacity is shown in Table 5 above. Over 71.3% of the
new CCGT capacity came from players other than the two incumbents. CCGT plants accounted
for the greater proportion of new capacity despite the bias in favour of coal through the coal
contracts. The incumbents between them had installed only 6240 MW of CCGT capacity and this
compares to the 15195 MW installed by the IPPs. There have been major changes overall in fuel
source. By 2000/01 the percentage share of generation capacity in the Pool taken up by natural gas
had increased from less than 1.0% to 30.4%, at the same time coal saw its share decline from 64.6%
in 1990/91 to 32.7% in 2000/01.
The short construction time of 2 to 3 years for CCGT, compared to coal at 6 to 8 years allows for
greater flexibility in the decision on new stations. Their modular construction and their lower
construction costs, which significantly reduce financial exposure, make CCGT plants ideal for fixed
turnkey contracts provided by equipment suppliers.
The new combined cycle gas plants also offer environmental advantages over fossil-fuel plants as
they consume 27% less fuel, emit 58% less carbon dioxide, emit no sulphur dioxide, and 80% less
nitrogen oxides for each unit of electricity produced and the capital cost is 50% less for each MW of
capacity.
131
Table 6
Fuel Use Changes: Percentage Share 2000/01
Fuel Use
Coal
Nuclear
Gas
OCGT/Oil
Other
Total
Major Power Producers
Maximum Demand
% Share of Market
1990/91
2000/01
64.6
32.7
23.6
14.3
0.7
30.4
9.4
10.5
1.7
12.1
100
100.00
73000 MW
66183 MW
53400 MW
56300 MW
Source: Electricity Association, Electricity Industry Review, No. 5,
London, (January 2001), p. 34.
The IPPs had to buy most of the natural gas they need for operation from the British Gas monopoly
and the terms were 15 year supply contracts at prices indexed to the general level of inflation. In
turn the entire output of the IPPs was contracted to the RECs with 15 year “take and pay”
contracts, and with full “pass through” of the gas purchase costs. The REC developed this vertical
relationship with the IPPs because of their desire to diversify supply sources from the two
incumbents and to avoid dependence on the duopoly market structure created at privatisation.
Because of these “take and pay” contracts and the relatively high minimum bills the IPPs found a
large element of their gas purchase cost fixed. Thus the marginal cost of gas to them is close to zero,
creating a powerful incentive to ensure total dispatch into the Pool to secure base load operation.
The use of a single system marginal price for bulk electricity sales was also found to unduly favour
natural gas-fired and nuclear fuel base-load generators. This pricing mechanism allows base-load
generators to offer zero prices in order to guarantee full dispatch because they know that they will
receive the pool price regardless and this has worked to the disadvantage of the coal-fired
generators.
132
The market structure has, therefore, led to channelling of competition into areas where it least
affects the incumbents and has had less impact on wholesale prices. The incumbents, therefore,
found themselves competing with each other for the critical part of the load curve; the mid-merit
and peak load which operates with mid-merit (higher) variable cost.
PowerGen and National Power have, however, been critical of a system which restricted them in the
earlier part of the 1990s to compete only in one segment of the market (60%) and which excluded
them from the base-load market25. They complained that the IPPs with “take and pay” contracts are
operating in a risk free environment.
Nuclear Power has a very large share of the wholesale market. Nuclear Power also operates as a
“must run” generator, with the result that even if the two incumbents offer power at zero prices,
Nuclear Power would still be dispatched. This condition arises from the inflexibility of nuclear
plants. At the same time, the Scottish companies have the privilege of sending power into the
England and Wales system with no reciprocal rights of access to the Scottish system by the
incumbents. Scottish Power had also benefited from cross-subsidy through the non-fossil fuel levy.
A further disadvantage to the two fossil-fuel incumbents resulted from the waiver of the fossil-fuel
levy that the French system enjoyed through EdF. This meant that EdF obtained some £5 per
megawatt hour above the maximum price permitted through the Pool price undertaking. EdF share
of the market has varied from 4% to 6.0%. This subsidy was worth £95 million in 1991-92 to the
French consumers.
At privatisation government sought to maintain its protection of the coal mining industry, although,
at much reduced levels, after 1993. These agreements were based on the ability of the RECs to
“pass-through” the additional cost to the consumers. The introduction of increased competition at
the small consumer market end of the system from 1998, effectively removed this ability of the
RECs to pass-through this cost and the continuation of this cross-subsidy to the coal industry.
In its argument for review of the Pool trading arrangement in 1997, the Government claimed that
the Pool price mechanism distorted the choice of energy sourcing and that the use of a single system
marginal price for all bulk electricity sales, unfairly favoured gas-fired and nuclear base-load
133
generators, which is a point the two incumbents with large coal plants had been making from 1993.
Shuttleworth (1999)26 however, claimed:
“that the government failed to show exactly how the pricing method hampered coal
and why coal plants could not secure their output by adopting “take and pay”
contracts as the gas-fired plants have done”.
The incentive to build gas-fired plants is more a factor of their lower cost, whilst the incentive to run
them depends on the form of contract. Reforming the pricing rules of the bulk electricity market is
unlikely to change these factors or change the fuel sourcing relationship in favour of coal.
In their continued support of the coal-fired plants, both Government and the Regulator strongly
advocated divestment of coal plants by the two incumbents to curtail their market power. With the
elimination of market power, the government argued that there would be a reduction in spot prices
and this would eliminate the incentives for construction of gas-fired plants. If anything the
moratorium on gas created a temporary scarcity for capacity and allowed the incumbents to attract
higher prices for the disposal of coal plants after 1998.
Government did not outline any clear ownership and merger policy at privatisation and only
permitted the market for corporate control to operate after March 1995 when the golden share
control mechanism was allowed to lapse and the removal of the restriction limiting a single voting
entity from holding 15% of the voting rights in the distribution companies was lifted. The Golden
Shares in National Power and PowerGen were only redeemed in October 2000.
The lifting of the restriction in the autumn of 1995, not only ushered in a flurry of takeover bids
some friendly; some contested; both the ownership and industry structure came in for considerable
changes. Six of the initial takeovers took place without reference to the Monopolies and Mergers
Commission (MMC), whilst Government referred the bids of the two incumbent generators to the
MMC, with the result that these two bids were subsequently disallowed27.
In the two-year period following 1995 alone, eleven of the regional distributing companies came to
be owned by shareholding interests other than the investor groups at privatisation. Three of the
134
companies diversified into water supply and gas distribution and supply, making them multi-utilities,
whilst eleven by 1999 had invested (and used up most of their 15% quota) in CCGT plants. Eight of
the twelve firms were taken over by American interests and one by a Scottish company..
Government initially blocked the reintegration attempts of the two incumbent generators with retail
supply, the reason being that competition had not sufficiently developed. Vertical reintegration in
principle had, however, not been ruled out. Scottish Power had been allowed to merge with
Manweb in 1995 and Eastern one of the large regional distributors was allowed to acquire generating
capacity that the two incumbents were forced to sell. After 1997 PowerGen, one of the two
incumbent generators was allowed to acquire East Midlands Electricity and National Power now
Innogy Holdings, the second of the two incumbents was allowed also to acquire the supply business
of Midlands Electricity on condition of further plant disposals.
In 1999 British Energy, the nuclear generator also entered the takeover market and acquired the
retail supply business of SWALEC, previously part of the Welsh water and electricity company;
Hyder only to sell SWALEC six months later to Scottish and Southern Electric. EdF the French
electricity utility also entered the market and acquired London Electricity and SWEB supply
business, creating a new group that of LE Group. In 1998 Scottish Hydro also merged with
Southern Electric. Edison Mission by 1999 had developed to be a major generator with interests in
hydro, coal and gas plants. Because of these takeovers the Regulator’s pre-occupation with price
control widened to cover the battle for corporate control and re-integration
This increased forward vertical integration has also coincided with the liberalisation of the small
consumer end of the retail supply market. Kennedy (1996)28 in his analysis of the relationship of
industrial structures of the electricity industry in England and Wales concluded that ‘vertical
mergers in the electricity would not necessarily be welfare reducing and might actually be
welfare improving’.
Vertical mergers he argued could be tolerated so long as there was
competition in the generation end of the market. The ownership relationships of the various
companies at the end of 2001 are shown in Table 7 below.
135
Table 7
Summary of who owns whom – 2000 (Intermediate holding companies have been omitted
for clarity)
Parent’s Owner
Investor-owned (USA)
%
100
Parent
American
Electric Power
British Energy
Brutish Nuclear
Fuels
Edison
International
Elctricit de
France
%
100
Subsidiary
SEEBOARD
Publicly quoted (UK)
British Government (UK)
100
100
--100
--BNFL Magnox Generation
Investor owned (USA)
100
100
100
GPU Inc***
100
Edison Mission
Energy
LE Group (London Electricity
and
SWEB supply)
GPU Power UK (formerly
Midlands Electricity,
distribution)
French Government (France)
100
Investor owned (USA) may
have third columns 3times
and 5columns 4or5 times.
Publicly quoted (UK)
100
Innogy Holdings
100
100
100
94.75
Publicly quoted (UK)
100
Privately owned (USA) incl.
Berkshire Hathaway
100
Publicly quoted (UK)
Parent’s Owner
Investor owned (USA)
100
%
100
Publicly quoted (UK)
100
Publicly quoted (UK
Investor owned (USA)
100
100
Investor owned (USA)
100
International
Power
MidAmerican
Energy
Holdings
PowerGen UK
Parent
PP&L
Resources with
Southern
Company
49%**
Scottish and
Southern
Energy
Scottish Power
Southern
Company** with
PP&L
Resources 51%
Texas Utilities
---
**
100
100
100
United Utilities
Viridian Group
Xcel Energy
---
100
Northern Electric
100
%
51
East Midlands Electricity
Subsidiary
Western Power Distribution
(formerly SWEB and SWALEC
distribution)
100
Merger of Scottish HydroElectric and Southern Electric
SWALEC (supply)
Maweb
Western Power Distribution
(formerly SWEB and SWALEC
distribution)
100
100
51
100
100
Public quoted (UK
Public quoted (UK)
Investor owned (USA)
MEB (supply, now branded as
power)
Yorkshire Electricity
100
100
5.25
TXU Europe (formerly Energy
Group and Eastern Electricity).
In Turn owns:
Norweb Energy (supply).
Norweb (distribution)
Northern Ireland Electricity
Yorkshire Electricity
In the USA, Southern Company has sold 19.7% of Mirant Corporation (formerly Southern Energy),
which holds a 49% share of Western Power Distribution, in an initial public offering and intends to
sell the remaining shares in April 2001.
136
***
In the USA, GPU Inc merged with First Energy.
Source: Electricity Association
There have also been major structural changes in the nuclear sector of the industry. Following the
electricity industry restructuring in 1990 the five AGRs and the PWR of Size-well of 4750 MW were
separated out from the seven older Magnox reactors of 3225 MW to form Nuclear Electric. Sizewell B PWR plant came on stream in 1994, adding 1188 MW of new capacity to the nuclear sector.
Two years later the Magnox plants were incorporated as Magnox Electric and became a subsidiary
of Nuclear Electric.
In April 1996, the two Scottish and five English AGRs, along with the Size-well PWRs were
restructured as two separate subsidiaries (Nuclear Electric and Scottish Nuclear) under British
Energy. That same year the operations of the two national nuclear systems were further merged into
one operational group within British Energy and privatised.
Robinson, (1996)29, concluded that in horizontally integrating the English and Scottish nuclear plants
into one company in anticipation of privatisation, there was another failure to seize the opportunity
to enhance competition and rivalry in the generation sector. The nuclear plants could have been
restructured into two companies of more equal size, as was the preferred position of the Regulator.
Their geographical constraints could then have been discontinued and the plants privatised to
become formidable competitors to the two incumbents in the Pool and contract markets.
Government again allowed consideration such as attractiveness of the divestiture package to
potential investors to override the requirements for a competitive market structure.
British Energy with its seven AGRs and PWR plants was publicly quoted in 1996.
In January of
1998 the small time-limited Magnox Company – Magnox Electric was transferred to British Nuclear
Fuel Limited, (BNFL) to be retained in the state sector. BNFL has been operating two Magnox
plants for weapons production for several years. The end result is that a duopoly market structure
was created also for the nuclear generation market, consisting of one small state owned company
and one larger privately controlled company.
137
British Energy’s nuclear plants have seen an overall increase in their productivity of 75% since the
introduction of the reforms in 1990. With the introduction of private ownership in the nuclear
sector the restrictions on diversification and geographical market sharing were later removed and the
company has been allowed to integrate forward into the retail sector as well as to invest into coalfired operation.
For the future Magnox Electric, because of its associated high operating and decommissioning costs
will be precluded from competing in the market for bulk power. Inevitably, Magnox Electric will
continue to operate in the state sector as price-taker and as “must run” plants, contributing nothing
to competition until their eventual closure. Effectively they are stranded assets with the consumer
and the general public having to meet the higher operating and decommissioning cost.
Although British Energy has been in the private sector since 2002, given the inflexibility of nuclear
plants they will continue to benefit from “must run” status and in so doing also continue to be a
price-taker, with minimum direct contribution to competition in the Pool. With the loss of income,
however, from the discontinuance of the fuel levy, British Energy now has a stronger incentive to
compete in the contracts market and reduce its exposure to the Pool price through Contracts of
Difference.
In order to increase its competitive position it has already commenced diversification from nuclear,
and in 2001 owned 1960 MW coal-fired plant capacity, which it acquired, from one of the
incumbents. Contracts for base-load power as is provided by nuclear plants command relatively
lower price when compared with power for mid-merit and peak-load plants. Further diversification
into CCGT plants more likely from purchases from the REC owned IPPs, would improve its
competitive position. With the end of the franchised small customer market in 1998 some RECs
have decided not to remain in the generation market.
Without a guaranteed consumer market, RECs find it more advantageous to reduce their long-term
supply exposure and increase the proportion of power off-take from the power exchange.
Integrating into the supply business has also served to strengthen the British Energy market position
in the electricity supply industry. British Energy is, however, approaching 20% share of the bulk
138
electricity market: therefore, the Regulator will doubtless become concerned about its increasing
size, especially as the Regulator’s preference has been for two competing private nuclear firms.
The Scottish and Northern Ireland Electricity Reform
In the case of Scotland and Northern Ireland, the reforms involved even more conservatism. In fact
different structural approaches were introduced for the two smaller systems and at the time reflected
classical industrial organisational issues of optimal vertical integration and disintegration.
The
question was which model of industrial structure, given issues of economies of scale and transaction
costs, leads to lower cost to consumers and higher levels of efficiencies?
Newbery (1995)30 concluded that:
“The restructuring options are determined by the size of the electricity market and
the fuel mix, hence it is more appropriate for small and especially isolated and
geographically compact systems to consider retaining vertical integration to final
consumers”.
The policy in Scotland before the reform was to build large plants based on the rationale of
economies of scale, hence very few large stations made up the system. Government’s position at
privatisation was that the relatively small system; one eighth that of England and Wales, serving large
areas of sparsely populated regions and with vertical integration being considered successful, there
was a strong case to maintain the existing vertical structure and rely on competition between two
privatised vertically integrated companies for the liberalised consumer market and indirect
competition by comparison to ensure efficiency gains.
A disintegrated and more competitive
structure would have made it more difficult to maintain a cross-subsidy policy to rural areas. The
Scottish people also provided strong political opposition to the UK type reforms.
In the final structure adopted for Scotland in 1990 two vertically and horizontally integrated joint
stock companies, Scottish Power (SP) and Hydro-Electricity (HE), now Southern Energy replaced
SSEB and NSHER. The existing two nuclear gas-cooled plants, built by SSEB were initially
transferred to a new state owned company, Scottish Nuclear as shown earlier. Scottish Nuclear first
139
became a subsidiary of UK Nuclear Electric in 1996, only to be merged as one operating unit in
British Electric that same year and now forms part of privatised British Electric.
SP and HE were given composite public electricity supply licences covering generation,
transmission, distribution and retail supply for their designated region. However, vertical accounting
separation of the four distinct businesses was mandated. The licences imposed a specific limit on
what could be charged for generation. The licencing system also provided for the entry of second
tier suppliers, allowing reciprocal competition in each others designated area for the liberalised large
end user market (1MW and over) involving 500 end users and for other generators to contract with
large end users making use of the two companies’ transmission and distribution systems. This was to
be carried out on a non-discriminatory basis with the settlement balances between generators and
purchasers settled on the basis of the E&W pool prices. Both companies were also allowed to hold
second tier licences, giving them the rights to operate in E&W and more recently in the Northern
Ireland markets.
The transmission system of the two companies form an integrated system, and Scottish Power is in
turn interconnected with E&W, originally by a 850 MW connector, but subsequently upgraded to
1600 MW. A 250 MW submarine cable connector was later developed, and linked the west coast of
Scotland to Northern Ireland in 2000.
In order to provide each company with a balanced mix of power plants a complex series of
restructuring contracts, aimed at providing diversification of fuel source for each company was
introduced. Under these contracts, HE was required to take a given output from SE’s coal firedplants, and in return SE was required to take a given output from HE’s hydro-plants. In addition to
these restructuring power contracts, HE was required to enter into coal supply contracts to run to
2004 and SE hydro agreements, which run to 2039. Both companies were also required to enter
into 15 year power supply contracts with Scottish Nuclear, under which all the nuclear capacity is
supplied to HE and SE in the ratio of 25.1: 74.9 respectively, and these contracts are “must run”
plants, with the effect that payment obligations accrue whether or not they are dispatched. Both
non-nuclear companies had considerable excess capacity at privatisation and as a result entry to the
Scottish generation market was initially prohibited. The entry of independent power producers was
140
not permitted until the latter part of 1990s; hence there have been only marginal changes to the
structure since privatisation.
At the time of privatisation, 1990/91, the market shares for electricity supplied were respectively,
Scottish Nuclear 36%, Scottish Power 44%, and Hydro Electric 20%.
Installed capacity has
increased marginally from 1990 to 10,333 MW in 1999, with market shares respectively being,
Scottish Nuclear/British Energy 22.3%, Scottish Power 34%, and Scottish and Southern Energy
(former Hydro-Electric) 44.7%31.
Coal as a fuel source had come to account for 35% capacity, nuclear 27% hydro 19%, gas and oil
18% and renewable 1.0% in 2000. Up until 1996/87 both HP and HE held 85% of the small
domestic household and medium sized markets and 86% of the large industrial market (1 MW
market). The medium sized 100 kW, market and over was also liberalised in 1995, a year after the
UK market to bring 50% of supply into the liberalised market. Both companies also held the greater
portion of the second tier market. In 1998/99, second tier suppliers, other than the two incumbents
had only developed to account for 21% of the large industrial market, compared to 80% in the
E&W market, where second tier supplies had come to account for 80% of the market32.
Unlike in the UK, where the two incumbents experienced progressive decline in output in the first
five years up to 1994/95, the Scottish generators experienced an increase of 28%. With opportunity
for export to England and Wales, exports increased from 5% to 20% of output.
Interestingly, the system size is more or less the same size as that of New Zealand. While New
Zealand with similar outlying thin distribution areas disintegrated its structure and introduced both
wholesale and retail competition, the Scottish market was retained as a franchised monopoly system.
Maintenance of the vertically and horizontally integrated franchised utility, the weak interconnector
system, control over access to their interconnector by the incumbents, the restrictive vesting
contracts in both power supply and fuel supply, as well as the initial entry restrictions to the
generation market have severely frustrated competition in the Scottish market, with the net effect
that prices for domestic consumers which were lower in England and Wales in 1990, have
developed to be significantly higher in Scotland by 2000. Similarly, the regulated wholesale bulk
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electricity prices have also developed to be significantly higher in Scotland. The Scottish operations
were also subjected to the same price cap tariff control formula of RPI-X
With the gradual decline in the importance of the restructuring contracts, the expansion of the
capacity of the interconnectors, the recent opportunity for IPP entry in the generation market, the
European Commission’s liberalisation directives and the 1999/2000 liberalisation of the small
domestic household market, Scotland can expect to progressively experience increased levels of
competition in both the generation and retail supply market segments after 2000.
Northern Ireland is the much smallest of the three markets in terms of size, being just over 2,000
MW in 2000 and more comparable to the size of electricity markets in the lesser developing
countries. In 1990 Northern Irelands installed capacity was about 1600 MW. Although the market
size was less than 20% of that of Scotland, the level of vertical and horizontal disintegration
introduced was much higher. This indicates that size, therefore, was not the only influencing factor
in the Scottish case.
Northern Ireland opted for the model two phase of market development, that of the single buyer
model. The rationale being that radical unbundling, as in the case of the UK was not a practical
solution. There were concerns about the size of the market, the abuse of market power in a small
market, excess capacity, lumpiness of investment in a small market with a few large generators, and
lower density ( as was the case with Scotland ) on the distribution system.
Restructuring and privatisation was initiated in 1992, two years after the commencement of the
exercise in E&W. The single vertically and horizontally integrated publicly owned Northern Ireland
Electricity (NIE) enterprise, which owned and operated four power stations, with total capacity of
2,300 MW, was vertically unbundled with generation separated from the transmission and
distribution network sector.
Generation was further unbundled into four power companies;
Ballylumford which was sold to British Gas, and operates as Premier Power; Kilroot and Belfast
West, both of which were acquired by Nigen, a joint venture project of AES Corporation of the
USA and Tractrabel SA of Belgium and Coolkeeragh which was the subject of a management
buyout, supported by a group of portfolio investors.
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The network system was restructured as a vertically integrated transmission, distribution and retail
supply company and floated on the stock market in 1993. NIE was restricted on privatisation to
own no more than 5 MW of non-fossil fuel generating capacity. In 1998 NIE was taken over and
became a subsidiary of Veridian Group. Market shares in 1999/2000 were respectively, Premier
Power 52%; Nigen 33.7% and Coolkeeragh 14.3%, with a total capacity of 2,072 MW. Northern
Ireland’s population in 1990 was is just under 1.7 million and compares to 5.1 million for Scotland
and 50 million for England and Wales.
NIE was required to establish a purchasing agency, Power Procurement Business (PPB), to act as
the single buyer for all electricity produced and publicly supplied. All three generating companies
were compelled to sell into NIE. Accounting separation was also mandated for the separate
businesses, transmission, distribution, PPB and retail supply. This structure was seen as transitional
to a more competitive system for bulk electricity, which was scheduled to come on stream by 1998,
being the date for the earliest cancellation of the existing power purchase agreements. The PPAs
were expected to run to the end of their remaining existing life, with the earlier ones due to expire
between 1997 to 1999, and with the most recent PPA due to expire in 2024.
The PPAs were all based on two part pricing, involving capacity or availability charges and energy
charges, with the capacity element subject to “take and pay” conditions. Many of the PPAs,
however, contracted on vesting, carried clauses which allowed the Regulator to cancel them before
their expiry dates providing some flexibility for the introduction of the competitive bulk electricity
market in 1998.
NIE was given the only public electricity supply licence at vesting. Since then second tier suppliers
have been allowed to sell in the liberalised or large end user market. NIE had initially been
interconnected to the Republic of Ireland. The interconnector was destroyed in 1973, but was
restored and reactivated in 1995. Additionally, a 65 Km 250 MW interconnector now links NIE
with Scotland. The interconnectors which links NIE with the Electricity Supply Board of the Irish
Republic has enabled the two countries to share spinning reserve and to trade when the marginal
cost of either system is different from the other. There is also a half hour difference in the evening
peak of the two systems.
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A regulatory framework involving a single regulator was established for the electricity and gas
industries and a Director General of Electricity and Gas and an Office of Electricity and Gas were
established. The pricing structure consisting of availability payments and energy payments resulted
in more than 50% coming from availability payments. Increased levels of investments, in effect
increased efficiencies resulted in higher availability charges.
The introduction of a viable competitive market for the relatively small Northern Ireland electricity
market, however, has proven to be an illusive objective, with the result that the highly monopolistic
structure, which prevailed over the period, had come to deliver over priced bulk power. The real
price per kWh increased by 2% between 1990 and 1996, compared to a real price decline of 11.6%
in the England and Wales market and this is despite important efficiency gains by the generators33.
The reason for this state of affairs is that of lack of sufficient competition in the market and more
than generous price increases by the Regulator. NIE’s electricity prices were 23% higher than the
England and Wales prices in 1996 and by 1998 the difference had widened to 42% because of the
lack of competition in the generation market and the protected long-term contracts market. In July
2000, 26% of the market in generation and supply was opened up to users with annual capacity of
2.5 GWh. Both Scotland and Northern Ireland have seen significant increase in natural gas as fuel
source from conversion of oil stations.
The electricity market Directive of the European Union, which is an authorisation procedure by
which new entrant generators may enter the bulk electricity market, came into operation in 1999.
Not only are eligible customers (2.5 GWh and over)) able to buy from suppliers and hence the
generator of choice, suppliers are also able to buy from generators in the other markets of the EU.
NIE has responded to the Directive by auctioning off some of its excess capacity to second tier
suppliers and by 2001 some 334 MW contracted at privatisation were released as virtual independent
power producers.
Competition is also expected to improve from the upgrading of the
Scottish/Northern Ireland interconnector to 1,400 MW by 2002. With the upgrading of these twointerconnectors, capacity will amount to 80% of the Northern Ireland peak demand, compared to
fewer than 10% in the UK34. Interconnected capacity is, therefore, expected to have a major impact
on competition in the two Irish markets.
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The British reforms of the 1990s, merely transferred monopoly rights from the public to the
privately operated NIE, with the net effect that prices in Northern Ireland have been driven to
become one of the highest in Western Europe. With the EU market liberalisation Directive,
Northern Ireland can now expect to see more intensive competition and prices driven down to
levels converging to England and Wales, especially after 2003 when the existing set of IPPs under
construction come on stream and the new England and Wales Trading Agreement comes into
operation35. These developments are having the effect of radically changing a small system into a
Scottish/Irish market; eight times the size of Northern Ireland.
Bulk Electricity Market – The Pool
Electricity system as explained earlier is characterized with strong vertical economies especially
between generation and transmission. Under the vertically integrated franchised monopoly structure
the traditional way of dealing with this relationship has been internalisation. With disintegration,
which follows from unbundling, a solution had to be found to address the issue of coordination.
The solution of the British has been a contractual approach to the externality problem, represented
by compulsory pooling agreements. In this way, participants in the system seek to coordinate their
behaviour contractually, rather than through the command and control model as under the
franchised vertically integrated system. The contractual approach opens the system to horizontally
independent generating companies, competing for bulk electricity supply. There is, however, a
paradox. Competition in the market requires participating firms to behave independently, whereas
the pool arrangement implies explicitly or implicitly, collusion through the various interutility or
interface agreements.
In one measure, inter-firm coordination is needed to counteract the
internalities associated with the electricity system’s disequilibrium (but not inter-firm cooperation or
collusion to counteract competitive profit maximising behaviour), hence Joskow and Schmalensee
(1993)36 state that the power pool creates strong tensions between cooperation and competition.
The Pool allows price competition and diminishes some of the problems of long term contracting;
however, as with the situation with the single buyer model, it introduces poor risk profiles through
the volatility of spot prices, which is inevitable.
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The Pool, therefore, is the main area in the restructured electricity system where competition was
expected to take place. As explained earlier, the original intention was to have a “two sided” market,
with generators placing offers of minimum prices for supply and suppliers and large end users
placing bids of maximum price for purchases. As pointed out earlier, also the double sided pool had
to be abandoned six months before vesting day because of problems with the computer software;
the result was that the traditional CEGB dispatching software had to be adopted and its limitation
was that it could only accommodate a “one sided” Pool, with only generators placing bids into the
market.37
The Pool required all generators exporting 50 MW on the system to hold a generators licence and to
bid its output via what is in effect an open commodity market. Initially, the argument was that
contracted power did not need to bid into the Pool to operate; it was feared, however, that such
contracted power would work to force spot power off the system, especially where transmission
capacity is tight. The pool was therefore, made compulsory for all licensed generators wishing to
trade in the new electricity market.
The Pool, which is an unincorporated association of members, decides how the market is operated
and how the rules should change. No detailed direct regulatory powers were given to the regulator;
the DGE, and what regulatory powers existed took the form of imposition of obligations on
licensed generators wishing to participate in the wholesale electricity market and the instrument for
this is the Pool and Settlement Agreement38. The Regulator’s role is limited essentially to that of
being the final arbiter in cases of disputes and rule changes and his decision is binding. Governance
is facilitated through a ten member Executive Committee; five representing generators and five
representing suppliers. The National Grid Company, which owns the transmission system, has
several roles. It is the systems operator (dispatcher of power), the market operator (calculates the
prices) and the settlement payment administrator.
Each generating unit is required to declare by 10.00 hours each day, its availability the next day,
together with the price at which it is prepared to generate for each and every half hour time slot. The
units are then called to generate, or dispatched by the systems operator, the National Grid Company
in ascending order of price or economic merit order. At the same time, all suppliers are required to
submit demand estimates at each transmission supply point (or node) from which they intend to
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draw power, also for each and every half hour of the following day. NGC is in effect the agent of
the Pool and carries a feature of centralisation of all transmission activities. In New Zealand the
transmission lines business (transport of high voltage electricity) was separated and made neutral to
the new system to reduce market power and a separate “not for profit” organisation was established
to handle market operation and settlement administration.
NGC then runs a computer plant-scheduling programme, which seeks to minimise systems
generating costs over the next day in terms of the price bids. At this stage transmission constraints
are ignored. The most expensive unit dispatched in each half hour, clears the market and in principle
sets the system marginal price (SMP). The SMP covers the average starting up cost and its no-load
price, plus its incremental price of running for the clearing plant. All generators including the
clearing generator then receive the clearing price (a uniform price) and not their bid price. This price
is calculated on the basis of a revised unconstrained schedule. The system is therefore, not the
typical auction market of “pay as you bid”.
Additionally, there is another feature of the pricing structure, designed to provide an incentive for
having generating capacity available whether or not it is dispatched. The capacity element is given
by LOLP x [(VOLL – max (SMP)] where LOLP is the loss of load probability, the risk that demand
will exceed capacity and VOLL is the value of lost load, which is set administratively (and indexed to
inflation) to reflect the cost of demand exceeding supply. VOLL is intended to be a measure of the
economic cost of not supplying. LOLP is the probability that the amount of power bid will prove
insufficient39. The combination of the SMP and the capacity charge gives the pool purchase price
(PPP) and this is calculated a day ahead and published every day in the UK Financial Times (a daily
newspaper). PPP = SMP + LOLP (VOLL – SMP).
All companies buying from the Pool pay a pool-selling price (PSP) for their metered demand, which
is adjusted to take account for average transmission losses in each half hour. This additional variable
is known as “uplift” and incorporates charges for ancillary services, which are needed to ensure that
the system remains, balanced and secure. The uplift was originally charged out to all consumers
responsible for constraining on more expensive plants, rather than to the transmission operator.
Subsequently following an enquiry the uplift was allocated between the consumers and the
transmission company.
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If a generator offers a price that is too high it may not be dispatched and if it is too low it may be
dispatched at times when the spot price is below its real cost. Therefore, there is a price risk that in
any single half hour time slot when the plant is running that the market price may be higher or lower
than expected. The generator can never be sure what price will clear the market. There is also a
quality risk in that variation in market conditions may affect the output of the generator. Changes in
spot price in some time periods may require the generating plant to run for more or fewer hours
than expected. There is also a fuel cost risk and this lies largely outside the control of the generator.
Fuel price risk is the variation in the cost of source fuel and could have the effect of changing the
number of hours the plant runs, the net revenue earned and its variable cost. The final risk is
availability risks and like fuel price is outside the control of the generator. Even if the generator has a
good idea of the pattern of demand and knows the fuel price, there is no guarantee that the
generator will be available when it is required to be dispatched and in so doing miss the opportunity
for production.
An important feature of the spot market price is that it is exogenous to the generators’ cost, and this
provides a strong incentive to increase productive efficiencies and reduce cost in the short run and
in so doing maximise profits. Over the long run the sum total of such cost reduction allows the
generator to bid lower prices and hence lower system marginal cost (SMC), which when passed
through the market should translate into savings to consumers at lower prices, i.e. allocative
efficiencies.
The net effect of the almost real-time pricing has been price volatility, sometimes by as much as a
ratio of 3:1 over the course of the day and still further volatility in peak periods. These “spikes” in
prices have been a cause of concern and is not welcomed by either buyers or sellers.
In order to minimise the effects of the volatility in the spot prices, participants in the market enter
into short and long-term contracts, thereby making the resultant capacity and energy prices more
predictable. These agreements are known as “Contracts of Differences (CfDs)” and typically
involved a “strike” price (an agreed price per kWh) for a specified quantity over a specified period of
time. If the spot price is below the strike price for any half hour the buyer (supplier) pays the
generator the difference and conversely if the strike price is below the spot price the seller
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(generator) pays the difference to the supplier. All contracts must go through the Pool, hence the
CfDs are therefore financial instruments with the objective of hedging risks and does not affect the
physical transfer of electricity. CfD’s are usually fixed time contracts and are expected to reflect
expectations in the spot market price. In addition to the CfDs, a small market developed during the
final years of the Pool’s operation for foreword trades.
Littlechild (1998)40 claimed that with the introduction of the Pool, competition was facilitated in the
bulk electricity market at several levels. First, the opportunity for product market competition was
presented between the Bertrand duopolies at the mid-merit level (60% of the bulk electricity
market). Second, the interconnectors (imported energy) were able to operate their connectors at full
capacity, most of the time reflecting an increase in their output by about two thirds (market share
increased from 3.5% to 7.5%). Third, the nuclear plants increased their output by 75%, from
increased efficiencies and new capacity. Fourth, entry competition was intensified. New entrants’
fuel-efficient plants, often in joint venture partnership with the regional distributors, progressively
came to account for the greater portion of sales. Three additional large players had emerged by 2000;
Eastern TXU, AES and Edison Mission. By November 2000, AES had come to set Pool prices
32% of the time. At the same time PowerGen and International Power/Innogy’s influence on price
setting had significantly declined and when combined they were only able to set prices 25% of the
time. Fifth, the two incumbent coal fired generators, not only disposed of 18000 MW of their coal
facilities but in addition 11000 MW of coal fired and 4200 MW of oil fired, being inefficient plants
were closed and in part replaced by fuel efficient CCGT plants. By 2000 the original duopolistic
market structure had been dismantled. Littlechild’s analysis further showed that the Herfindahl
market concentration index, which is a measure of competitive activity, had increased twofold41.
Although it was envisaged that most trade in the exchange would take place through the pool spot
price, in practice over 90% of electricity sales came to be purchased under contract at fixed prices.
As with financial and commodity contracts, trade in electricity contracts came to take a variety of
forms, from bilateral negotiation between parties to trade in transparent markets with independent
traders. Government determined the initial vesting contract structure. These contracts from the
early 1990s covered most of the output supplied to the franchised or captive customers. In addition
to the vesting power contracts there were “back to back” coal contracts between the two coal fired
generators and British Coal.
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These contracts were introduced to provide a certain degree of predictability in the transitional
phase of the market development, and to cushion the effects on the coal industry. The vesting
power contract prices were, however, above the pool price and the coal contract prices were also
well above the international prices for coal. This not only facilitated the continued cross-subsidy to
the coal industry, as these costs were passed on to the captive customers, there was a distributional
transfer in favour of the shareholders of the two duopolies at the expense of the consumers.
Voluntary contracts or CfDs supplemented these vesting contracts. As outlined earlier they were
designed primarily to hedge price risks. Voluntary contracts typically varied from one week to one
year, but could be for a particular time of day or for periods lasting several years. They were
expected to shadow the spot market prices.
The Government’s decision to restrict consent on the building of new gas fired power plants only
served to restrict new CCGT entrants to the market. Government’s position is that distortion in
pool prices has disadvantaged coal, although no conclusive evidence had been introduced to support
this position. The restriction as stated earlier merely served to increase the disposal prices of the
coal fired plants in 1999/2000.
The UK electricity market has been criticised as being biased to favour base load plants and as a
result most new plants, which came on stream after 1990 were built to run base load energy, as the
structure of prices in the market made this market solution the most profitable. The new CCGT
lower operating cost plants more or less created a situation in which the older and less fuel-efficient
coal fired plants became mid-merit plants. However, as more and more coal fired plants are retired
from the system and gas fired plant capacity is increased, its share of the market will increase to the
point where gas fired plants will also have to operate in the mid-merit market segment.
Both the CCGT plants and the nuclear plants came to monopolise the base load market. With the
nuclear plants as “must run” plants, and the CCGT plants carrying 15 year take and pay contracts,
their marginal cost was almost zero, with the effect that they were able to bid into the Pool at prices
close to zero, knowing that they would be paid at the higher pool clearing prices. A number of
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merchant-IPP plants have, however, started emerging with more equitable risk sharing provisions,
the effect of this is that the scope for competition will be further enhanced.
Additional anti-competitive features were either built into the system or emerged later and these
features came to distort the market. A major problem has been that the Bertrand duopolies have
been able to exert considerable market power and influence prices in the Pool, almost over the
entire life of its operation. The average SMP and PSP steadily increased in real terms from 1990/91
to 1993/94. This reflected the market power of the duopolies and the artificiality of the pool price in
the early years, which in turn reflected the influence of the vesting contracts. In the first year there
was a 22% increase in SMP, partly from the higher uplift and capacity charges. Further increases in
the level of capacity payments, as well as an increase in the ratio of peak to off-peak prices were also
experienced. Littlechild (2000)42 commented that:
“the two duopolists were able to increase average pool prices for several years from
2.5p/kWh (3.9 US cents) in 1990/91 to 3.15p/kWh (about 5.2 US cents) in 1993/94
(December 1999 prices). In the first year or two, this increase may have reflected an
attempt by generators to redress an artificially low pool price. ------------However, the ability to secure repeated price increases demonstrated the significant
market power of the major generators”.
In 1993 the duopolies were able to set the pool price 90% of the time43. This led the Regulator to
intervene by threatening to invoke a reference to the MMC. The result was a voluntary undertaking
by the two incumbent generators not to bid a price into the Pool that would be fixed above a price
cap. The price cap specified a time-weighted level of 2.4 p/kWh and a demand weighted price of
2.55 p/kWh (both in October 1993).
The price cap agreement was also associated with a voluntary agreement as stated earlier, whereby
the two incumbent generators also agreed to divest 15% of their coal-fired capacity. The price cap
lasted for the period 1994/95 and 1995/96 and was imposed to give the market an opportunity to
increase its level of competitiveness. The result was that between 1993/94 and 1995/96 there was a
reduction in the average SMP.
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Fig. 21
Source: Richard Green, “Markets For Electricity in Europe” Oxford Review of Economic Policy,
Vol. 17, No.3 (Autumn 2001), p.333.
The effects of the price cap, competitive pressures from new entrant CCGT plants and
improvements implant efficiencies temporally resulted in a decrease in prices. In fact prices declined
over the period between 1993/94 and 1996/97 from 3.15p/kWh to2.8p/kWk, (or 4.2 US cents)
Despite the reduction in market share of the two incumbents to less than 50% in 1998, SMP in the
Pool was still established 66.6% of the time by the two incumbent generators. Pool prices were still
10-20% above the prices of the latest natural gas fired entry plant. Figure 21 above shows the
movement of the price components over the life of the pool, 1990/91 to 2000/01. Despite the
reduction in fuel cost by over 50% and the substantial reduction in staffing levels and improvements
in plant efficiencies, Pool prices were higher in 2000/01 than at vesting.
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Critique and Changes to the Pool After 2000
In summary the following criticisms have been levelled against the Pool:
First, the pattern of prices in the Pool did not show any significant decline in the initial five years
and this is despite the limited growth in demand, excess supply, and 50% fall in coal prices. To the
extent that prices were been higher than that which would have prevailed in a competitive market,
an incentive was provided for excessive entry and this has favoured natural gas over coal as a fuel
source. The gas industry, therefore, benefited at the expense of coal.
Second, bids into the Pool have not been reflective of cost. Movements in bulk electricity prices
have not fallen in line with reduction in costs. Wholesale spot prices have remained largely
unchanged whereas fuel cost and capital cost of generation have each fallen by over 50%. The Pool
has also been prone to price spikes.
It is common practice of analysts to compare pool price over the decade and to imply that there has
been no reduction in the effective price of bulk electricity. The effective price of bulk electricity is
set by interplay of contracts and the average prices from the Pool. The contract prices at vesting
were well above Pool prices in 1990/91. There has however been a reduction in the differential
between contract and pool prices since 1990/91, with the net effect being an appreciable decline
over the decade of prices in the Pool. Despite this decline these prices were still above the average
price of new entrants to the market during the period under review 44.
Third, the Pool trading arrangement facilitated the exercise of significant market power, with the net
effect that there have been distributional transfers in favour of shareholders at the expense of
consumers. Despite the fact that there is much less market concentration, pool prices were still
exposed to manipulation. Pool prices have not been a good signal of marginal cost, because of the
market power of the duopolies during most of the 1990s.
In a normal competitive market, supply and demand interact to set prices. In the “one sided” pool
arrangement a uniform market clearing prices is established, with the result that buyers have little or
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no opportunity to exercise bargaining power to bring pressure on prices. In other words, the system
provided limited or no demand side pressure on prices. Lack of demand side bidding stifles the
development of the market and had the effect of a one sided market.
The complexity of the price discovery process made it difficult for traders to understand how
electricity prices are likely to behave and the fact that most trade came to be carried out through
contracts, where prices are not public, leads to questioning of the transparency claim. The structure
of bids were intended to reflect the underlying cost of the thermal plants; instead bids have tended
to deviate from cost and more than anything have reflected commercial objectives. The complexity
also encouraged gaming of the market to the advantage of the duopolies.
Fourth, LOLP is of limited value as a short-term signal to encourage generation or demand
participation to respond to rapidly changing conditions, as a change in availability of a plant has to
last for 8 consecutive days before it had an effect on LOLP. The capacity payments have tended to
provide a means for generators to manipulate price, rather than to act as a signal for new investment
in capacity. The level of payments can be increased sharply by withholding capacity.
Fifth, the price setting arrangement has inhibited the development of a derivatives market and
reduced liquidity in the contracts market. This has resulted in very high margins on financial
contracts at further cost to consumers.
Sixth, the Pool governance structure has been considered to be too inflexible and consumer’s
influence has been negligible. The Regulator had no power to initiate changes to pool rules, even
when circumstances dictated such changes. The rules were designed to protect the minority interest
against the majority. Potential changes were against the interest of some players; hence it was
difficult to change the rules.
Seventh, the compulsory nature and heavily centralised pool tends to reduce the freedom of
participants’ commercial activities in the market.
The arguments advanced by supporters of the Pool are that it has fulfilled its original objectives. In
the first place there was always enough generation capacity to meet demand. There was never any
shortage of capacity. Second, the market during its 10 year life of operation provided a stable
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commercial environment and this has acted as an incentive for new investments and the
introduction of new technologies. Third, with the new entrants there has been increased competition
in the bulk electricity market. Fourth, increased competition and the application of new technologies
have lead to reduced production cost. Fifth, there has been increased diversification of fuel sources.
Sixth, the major reductions in staffing levels, which took place, resulted in increased efficiency and
increased productivity. Most important, the Pool facilitated the introduction and development of
competition in retail supply market with the ultimate outcome of significant reductions on preprivatisation prices, amounting to over 35% in real terms over the decade of the 1990s and this has
benefited all consumers.
Despite the view in some quarters, that changes could be made to the Pool to overcome its main
shortcomings, such as reform of the governance structure to allow the option of trading outside the
Pool, the Office and Gas and Electricity Markets in (1999)45 reported that::
“There is no simple way to modify the Pool to overcome its weaknesses, any worth
while reforms would require the removal of compulsory membership, the
introduction of firm offers, the incorporation of demand – side and implementation
of “pay-as-bid” pricing. These are very substantial changes and would, for example,
necessitate the introduction a balancing mechanism”.
There were also new developments internationally in electricity market arrangements, which came
into being after the introduction of the UK Pool. These developments OFGEM stated followed
market based solutions for all elements of the electricity trading arrangement, and for market based
solutions to ensure the security of supply, rather than administered arrangements and in so doing,
provided greater choice and flexibility in trading mechanisms and contractual forms.
The decision was, therefore, taken by the UK Government to replace the Pool with a bilateral
contracts market, a balancing spot market, along with a series of futures markets and with less
emphasis on central direction of the systems operator. The objective being to provide for more
competitive pressure in the exchange, more choices, eliminate a uniform price set by one single
marginal generating plant; encourage development of better risk management skills and provide
more scope for competition in the retail supply market .
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The programme of work to implement the new trading arrangements, (NETA) started in 2000,
being a feature of the Utility Act of 2000. The new trading arrangement for bulk electricity which
eventually came into being in 2000, provided for a series of markets involving forward markets,
allowing bilateral trade ahead of time, at prices bilaterally negotiated between individual traders and
brokers; a short-term power market which operates 31/2 hours before real time, and a balancing
market.
In the last 31/2 hours before real time operation, NGC the transmission operator runs a balancing
mechanism to ensure stability of the system. Bids and offers are accepted, either to increase
generation or reduce consumption. Each accepted trade is paid its own bid or offer, instead of the
single uniform marginal cost price as practiced under the Pool. The balancing mechanism is also
adopted to resolve transmission constraints. A system of tradable access rights has been proposed to
deal with congestion on the line and would involve generators paying for rights in an exporting area,
but could be paid for them in an importing area.
In the bilateral contracts market, traders will be able to enter into commitments well in advance and
in so doing give traders greater opportunity to hedge price risks. It is also possible to sign contracts
in the short-term market or delay trading until the short-term market opens.
Traders are required to notify a new agency Elexon, of their electricity contracts, which are
compared between their metered demand and output. Where there are imbalances between these
contracted positions and their metered positions, these then have to be “cashed out” at punitive
prices. Companies needing to purchase power have to pay the system buy price (SBP), which is the
average of the price that NGC paid to buy power in the Balancing Market. Companies needing to
sell power do so at the system sell price (SSP), which is the average of the prices NGC receives for
selling power in the balancing market46.
The verdict was still out at the beginning of 2002 as to whether moving from uniform pricing to
bilateral trading would have the effect of reducing the market power of generators to manipulate
prices. NETA, however, has already led to a significant increase in trading; whether this is good or
bad remains to be seen. What is clear, however, is that the unbundled structure and the associated
competitive bulk electricity market has ushered in a fundamentally new industry for the electricity
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supply system and this is now replicating itself globally in both developed mature markets and in
weaker developing markets. Newbery (2000)47 states that in 1997 over 51 countries from 61 studied
had been reforming their markets and with vertical separation in place or planned for 27 of the
countries.
The English model of structural reforms, involving vertical and horizontal unbundling and which is
the second of the two first generation reform models, Chile being the other, has provided the
template for reforms in both mature markets and developing countries.
157
End Notes
1. Jaime Millan, The Second Generation of Power Exchanges: Lessons from Latin America,
Washington, D.C., Inter American Development Bank (2001), p.3.
2. John E. Besant-Jones, The England and Wales Electricity Model – Option or Warning For
Developing Countries, Washington, D.C., World Bank (1996), p.1.
3. Steve Thomas, “The Privatisation of the Electricity Supply Industry”, in The British
Electricity Experiment, Privatisation: The Record, the Issues, the Lessons, ed., John
Survey, London, Earthscan Publishers (1996), p.48. Michael Beesley and Stephen Littlechild, the
architects of UK style utility regulation inspired by the thinking of the Austrian school of
economists developed the concept of incentive regulation, whereby monopoly utilities are
allowed to raise prices by the general rate of inflation, adjusted for an efficiency factor.
4. Richard Green and David Newbery, “Competition in the British Electricity Spot Market”,
Journal of Political Economy, Vol. 100, No.5 (1992), p.930.
5. George Yarrow, “Does Ownership Matter”, in Privatisation and Competition, A Market
Prospectus, ed., Cento Veljanovski, London, Institute of Economic Affairs (1989), p.53.
6. Walter J. Primeaux, “Electricity Supply: And the End of Natural Monopoly, in Privatisation
and Competition, a Market Prospectus , ed., Cento Veljanovski, London Institute of
Economic Affairs (1989), p.13.
7. Stephen C. Littlechild, Privatisation, Competition and Regulation, London, Institute of
Economic Affairs, Occasional Paper 100 (1999), p.23.
8. Graham Ward, Power to the People: a Decade of UK Electricity Privatisation, London,
PriwaterhouseCoopers (1998), p.2.
9. Department of Trade and Industry, White Paper: Privatising Electricity: The Government
Proposal For Privatisation of Electricity in England and Wales, London, HMSO (February
1998).
10. John Vickers and George Yarrow, Privatisation: Economic Analysis, London MIT Press,
(1988).
11. CEGB was the state owned integrated generation and transmission company.
12. Vickers and Yarrow, op.cit. p.311.
13. Alex Henney, Private Power: Restructuring the Electricity Industry, London Centre For
Policy Studies, Policy Studies, No. 83 (1987).
158
14. Thomas G. Weyman-Jones, “Regulating the Privatised Electric Utilities in the UK”, in The
Political Economy of Privatisation, ed., Thomas Clarke and Christos Pitelis, London,
Routledge (1993), p.100.
15. Cento Veljanovski, “Privatisation Monopoly Money or Competition”, in Privatisation and
Competition: A Market Prospectus, ed., Cento Valjenovski, London, Institute of Economic
Affairs (1989), p.34.
16. HMSO, The Report of the Committee to Review the National Problem of The Supply of
Electricity, London, The Wier Committee, (1925).
17. David Heald, “The Economic and Financial Control of UK Nationalised Industries”,
Economic Journal, Vol.90, No. 338 (1980)
18. George Yarrow, “Privatisation, Restructuring and Regulation: Reform in Electricity”,
Privatisation and Economic Analysis, ed., Mathew Bishop, John Kay and Colin Mayer,
Oxford University Press (1994), p.81,
19. Ibid, p.68.
20. Colin Robinson, “Privatising the Energy Industries”, in Privatisation and Competition, a
Market Prospectus, ed., Cento Veljanovski, London, Institute of Economic Affairs (1989),
p.114.
21. Pauline Beato and Carmen Fuente, Rail Competition in Electricity, Washington, Inter
American Development Bank (1999), p.9.
22. Steve Thomas, “The Development of Competition”, in The British Electricity Experiment,
Privatisation, the Record, the Issues, the Lessons, London, Earthscan (1997), p.50.
23. David Newbery, Guidelines for Private Sector Involvement in Electricity Supply Industry
in Eastern Europe, Cambridge University, Department of Economics (1996), p.19.
24. Joseph Schumpeter, Capitalism, Socialism and Democracy (5th Edition) London, Allen and
Unwin (1976).
25. Michael Reidy, “Privatisation, Regulation and Electricity Market”, in The British Utility
Regulation: Principles, Experience and Reform, Oxford University Press, (1995), p.127.
26. Graham Shuttleworth, “The Electricity Industry 1997 – 1998”, in Regulatory Review 1998/99,
Bath: England, Center For The Study of Regulated Industries, (1999), p.6.
27. Peter Boulding, Whither Regulation? Current Developments in Regulated Industries,
London, Center for the Study of Regulated Industries (1997), p.16.
28. David Kennedy, Vertical Structure of The English Electricity Industry, London: Centre For
the Study of Regulated Industries, Technical Report 6 (1996), p.14.
159
29. Colin Robinson, “Profit, Discovery and the Role of Entry: Case of the Electricity”, in
Regulating Utilities: Time For a Change? ed., Michael Beesley, London, Institute of
Economic Affairs (1996, p.135.
30. Newbery, op.cit. p.8.
31. Electricity Association, The UK Electricity System, London (1999).
32. Stephen Littlechild, “Generation and Supply of Electricity: The British Experience”, in
Competition in Regulated Industries, ed., Dieter Helm and Tim Jenkinson, London, Center
For the Study of Regulated Industries (1998), p.209.
33. Mathew Webb and Michael Bell, Reform Cases in Electricity: The UK Experience, Dar es
Salaam, Tanzania, Tanzania Electric Utility Seminar (2000), p.9.
34. Douglas Mclldoon, “Liberated by Brussels: Cross-Border Electricity Market in Ireland”, in
Regulatory Review, 2000/2001. ed., Peter Vass, Bath England, Center for the Study of
Regulated Industry (2001), p.33.
35. The Coolkeeragh Plant for example in its search for higher efficiencies embarked on conversion
of its oil fired plants into a 400 MW CCGT plant. The competitive pressures have provided
strong incentives towards more efficient plants and the lowering of production costs.
36. Paul Joskow and Richard Schmalensee, The Markets for Power: An analysis of Electric
Utility deregulation, Cambridge, Mass, MIT Press (1993).
37. David Newbery and Richard Green, “Regulation, Public Ownership and Privatisation of English
Electricity Industry”, International Comparison of Electricity Regulation, ed., Richard
Gilbert and Alfred Kahn, Cambridge University Press (1998), p.61.
38. George Yarrow, 1994, op.cit.
39. Steve Thomas, op.cit. p.80.
40. Littlechild (1998), op.cit, p.194.
41. Ibid. p.196.
42. Littlechild (2000), op.cit. p.16.
43. Green and Newbery (1998), op.cit. p.90.
44. Littlechild (2000), op.cit, p.16. The two incumbent generators; National Power and PowerGen,
along with Eastern, accounted for the setting of prices by over 85% of the times in 1998.
45. Office of Gas and Electricity, The New Electricity Trading Arrangements, London (July
1999), p.30.
160
46. Richard Green, “Markets For Electricity in Europe”, Oxford Review of Economic Policy ,
Vol.17, No. 3 (2001), p.341.
47. David Newbery, Privatisation, Restructuring and Regulation in Network Industries,
Cambridge, Mass, MIT (2000), p.200.
161
Chapter 4
British Electric Utility Regulatory Reform
The Case against Rate of Return Regulation
Regulatory reform was never a part of the Thatcher administration’s privatisation programme. The
first set of industries, which were privatised steel, automobiles and oil were expected to face either
domestic or international competition, hence it was felt that expansion of the role of the Office of
Fair Trading (OFT) would have been sufficient to address market power issues arising from a
changed industrial structure, OFT, however, declined to take on the responsibility. When the
realisation dawned on the policy makers that the likely outcome of privatisation was that of an
unregulated utility, several policy makers and academics tracked across the Atlantic to the US, the
only country with a substantial history of independent regulation of privately owned utilities, seeking
insights from US experiences. In fact up until the 1980s, American academics more or less exercised
a monopoly on regulatory thought. Public Utilities Commission (Public Service Commission) the
name given to the 49 state regulatory bodies had become synonymous with the more generic term of
regulatory agency.
The British also realised that if public utilities were to be successfully privately financed, regulation,
which credibly satisfies the demands of both consumers and investors, was needed. If investors are
fearful for the security of future returns, then it is unlikely that they would come up with the
unprecedented levels of capital needed to finance and modernise the utilities. Earlier experiences in
Britain as shown by Foreman-Peck and Millward (1994)
1
in the case of National Telephone
2
Company and Spiller and Sampson (1994) in the case of Jamaica Telephone Company in the 1960s,
clearly demonstrated that privately owned utilities will refuse to provide the needed investments if
adequate guarantees on returns are not provided, especially when nearing the end of the franchise
period.
For the American’s, the regulatory process was seen to be that of ensuring a balance between public
interest and the interest of the investor. Public interest arose from the characteristics of natural
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monopoly, information asymmetry and destructive competition. The regulator’s primary duty,
therefore, was to protect the public interest, whilst providing the investor with a “fair” rate of return.
US regulators had for over 100 years adopted cost of service, rate of return regulation (ROR) as the
formula for establishing tariffs, with the institutional framework being that of a quasi-judicial
commission, following procedures, which involved open public hearings3.
Alan Walters, Mrs.
Thatcher’s economic advisor was highly critical of the US approach to regulation, especially on the
grounds that it was a form of taxation, with poor incentives for the utilities to operate efficiently and
with a tendency to encourage capital-intensive solutions4. ROR regulation it was argued encouraged
capital-intensive solutions when the rate of returns exceed the cost of capital (gold plating), the
Averch and Johnson effect. It also results in allocative distortion when prices are set above average
costs and not marginal costs. It is seen to be cost-plus pricing, as it seeks to recover total embedded
cost, inflationary and does not provide incentives to the utility to reduce cost.
The regulatory system in the US was developed to protect the interest of the investor against the
interest of the public, Kolko (1965)5. Stigler (1971)6 argued that the system had been captured by the
investor group. Munasinghe and Sanghvi (1989) 7 pointed out that the system came to protect the
status quo and was a primary bottleneck to achieving significant efficiency gains in the US power
industry. Distortion also tends to arise from the process whereby revenue requirements from new
investments are front loaded, with the result that immediately following completion of a large base
load electric plant and its incorporation into the rate base, tariffs rise sharply. Rates, therefore, tend
to be high when capacity is substantially in excess of demand and visa versa, contrary to efficient
pricing.
The tribunal type open public hearing and the use of legal procedures, creating the need for each
participant to engage lawyers to argue and support every decision, as if in a court of law served to
create an adversarial process. The system had become too unresponsive to changes and unduly
restrictive, where a departure from tradition is necessitated by technological changes or changes in
the market, as has been the situations with the rapid developments in the telecommunication and
electric utilities.
Baldwin and C. McCrudden (1987)8 stated that:
163
“that although it is reasonable to expect trial type procedures to produce durable
standards where issues do recur it is unrealistic to expect this when most cases are
highly individual in character”.
Decisions often were the result of compromises between conflicting interests on the Commission,
which often lost sight of the broader public interest issues. Overall, the US style regulatory decisionmaking process is lengthy, and costly, rate decisions on average taking 12 months, is resource
intensive; a highly skilled body of economists, financial experts and lawyers are required and the
process is very expensive. Investment in US utilities is relatively risk free, because of the legally
enforceable guarantees.
The American regulatory system, however, offers an important advantage in that it provides for
effective constraints against opportunistic behaviour on the part of the regulator or the state. It
therefore, reduces regulatory risks and provides strong
incentives for large sums of needed
investment. It also provides for regulatory commitment; a guarantee that the investors immobile
assets and sunk cost will not be expropriated (prices being set below marginal cost). Because of the
long durability, non-transferability and asset specificity of much of electricity and other utility assets,
the bargaining advantage for lower prices shifts to those whose interest it is to demand lower prices
once the investment has been made.
If the regulator or the government set prices at
unremunerative levels the value of the investor’s assets is reduced and the investment is defacto
expropriated.
Regulatory commitment requires the respect for property rights and for prices to cover variable cost
to ensure adequate production and that the return paid on capital is positive. This then calls for
credible restraint against regulatory opportunism, which is all too familiar a problem in emerging and
liberalising utilities markets. The regulator’s discretion must be constrained and the power of the
government must be constrained from changing the regulatory framework through changes to the
law, once the investments have been made. The problem of regulatory commitment is central to the
design of new regulatory frameworks, and especially where there is an absence of a culture of
independent regulation. The regulatory challenge for new and liberalising utility markets, therefore,
centres on the creation of a credible framework, which satisfies the needs of the producer, the
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consumer and the state. The state’s interest is to ensure adequate supply and security to meet
economic and social development goals.
In the case of America, the very strong regulatory contract derived from the constitution, which
provides investors with various safeguards, for the protection of property rights; additionally, the
well developed body of administrative law (the 1945 Administrative Act) prescribes the general rules
of practice and procedures of agencies in relation to their conduct and the process by which
decisions are made and challenged. Much of US regulation has been a response to investor owned
utilities abusing their monopoly power at the expense of consumers. The remedy by the
independent judiciary in the US has been to allow the utility to charge a price which just covers the
cost of service and provides a “fair” rate of return upon the “value” of “employed assets” A series
of land mark court decisions, or judicial precedents defines, “fair” rate of return, “value”, and
“employed capital” and provides procedural fairness in the allocation of risks.
British Approach to Utility Regulation
Professor Stephen Littlechild, a Professor of Applied Economics at Aston University, England, the
first electricity regulator, was commissioned in the early 1980s to develop the regulatory framework
for the first privatised utility that of the telephone industry . He was the architect of the new British
approach. Littlechild (1983)98 rejected the fundamental notion upon which US Utility regulation is
based and challenged the approach that the utility industries have to be monopolies. Littlechild’s
(2000)10 new regulatory structure departed radically from the US approach and in his view regulators
should seek to:
“promote competition where competition seems possible to do so, thereby seeking
to maximise the disadvantages identified by Hayek and Friedman with regulated
industries”.
Littlechild sought to confine regulation to the non-competitive core of the utility industry, that of
the network and to leave competition to restrain prices in the competitive sector thus providing
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incentives and avoiding the complexity of the US system. Where competition did not exist public
regulation would ensure that privatisation did not simply mean replacement of private monopolies.
The long-term challenge posed by British approach to regulation from the point of view of public
policy was how to convert much of the nationalised utilities into a private, competitive and
unregulated industry. This is in sharp contrast to the US approach, where regulation has operated to
suppress competition. Regulation in Littlechild’s (1999)11 view was to be temporary and was to
remain until competition emerged. In the case of electricity, competition in supply was an entirely
new concept, although Chile had already introduced a rudimentary form. Littlechild’s solution was
to adopt the earlier precedent of telecommunications regulation, which provided for the right to free
access to the network segments or the natural monopoly elements of the industry. In his view the
primary role of the regulator, therefore, was to facilitate the competitive transformation process. The
1989 Electricity Act, for the first time established the statutory duty on the part of the regulator to
facilitate competition. This is in contrast to the US where the duty of the regulator is to prevent
entry to the industry and hence suppress competition.
The traditional economic concern with monopolies has been that of allocative inefficiency, arising
from the monopolist rent seeking behaviour of restricting output below competitive levels and
charging high tariffs and in so doing reducing welfare benefits to society. The unconstrained
monopolist also has an incentive to engage in price discrimination and charge users “up to their
willingness to pay”; and increase the rents that can be captured12. The unconstrained monopolist,
however, can charge well above their long run marginal costs of supply, thereby extracting a
significant proportion of consumer surplus as economic rent that is profits beyond those, which
would be required to induce the given level of output. Regulation of prices in its simplest form,
therefore, is reduced to that of allocating rents between producers and consumers, how to ensure
the producer receives a “fair” return on investment, whilst protecting consumers against “unfair”
prices. It is not only consumers that have an interest in the allocation of rents, government itself,
also has a strong interest. Government faces strong incentives to allocate rents in a way that
maximises its utility. Powerful pressures come from populist outcry to intervene in pricing and
investment decisions to achieve distributional and other social and political goals.
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When government intervenes through cross-subsidies and divorces prices from long run costs, such
as mandating uniform pricing or establishing universal service obligations, the allocation of
resources are distorted. In a competitive market it is not possible to maintain cross-subsidy policies.
Competition or the threat of competition from potential new entrants creates a powerful disciplinary
pressure on incumbents in the market. It is the possibility to use the threat of potential competition,
which led New Zealand to avoid the introduction of specific industry regulatory laws for the
privatised utilities.
In electricity, competition can be extended to the retail sector, allowing retail wheeling or the
transport of low voltage electricity across the wires of the franchised
utility operator.
Competition not only eliminates concerns about monopoly pricing, its spurs
productive efficiency – short term or static efficiency and long term or dynamic efficiency13. Firms
operating under cost of service, rate of return regulation or as public enterprises have very few
incentives to be efficient. Under pubic interest theory private ownership and ROR regulation and
public ownership are essentially one and the same in their effects; they do not provide incentives for
efficient behaviour
The British policy makers in their decision to depart from the well tried and tested US system of
regulation needed to ensure that the new system, not only provided incentives for allocative and
productive efficiencies, but also provided for regulatory commitment (Williamson 200114.) In the
development of an electricity regulatory framework the policy makers followed essentially the same
structure and procedural arrangements adopted for the earlier privatised telecommunications, gas
and water utilities. Each industry, including electricity was allocated its own regulatory agency,
instead of the US multi-sector cross-sectoral approach. Instead of a collegiate body as the decisionmaking authority, a single individual, a Director General was appointed, supported by an Office.
Although the Office is technically within the Government, the regulator is not a civil servant and
does not take directions from the portfolio minister, except in clearly stated circumstances laid down
in the law; hence the view that the regulatory system is independent15. Kay (1996)16 stated that:
“ it is preferable to give discretion and autonomy to an informed individual capable
of balancing conflicting duties and interest rather than for prescription of detailed
rules through a Commission”.
167
Prosser (1997)17 argues that the expertise of these new regulators gave them their legitimacy”.
Young (2001)18 states that :
“to the regulated firms the regulator represents the government and consumers, to the
government they are ostensibly an independent go between and to the consumers and
the public they are referees responsible for establishing a fair deal from the utilities”.
In Britain the regulators are recognised as experts with considerable discretion to bargain with
participants. The procedures are very informal with no requirements for court style hearings and the
emphasis is on co-operation rather than legal confrontation in open hearings. The role of the court
is more or less limited in the regulatory process to instances of judicial review, whereas in the
American situation the courts play an important role in the appeals process. Finally, instead of profit
controls, the British adopted price regulation in order to provide incentives for the utilities to
operate efficiently.
The Acts under which the various utilities were privatised specify the duties and powers of the
regulator and the roles of other parties; the sector Minister, OFT, the Monopolies and Mergers
Commission (Now the Competition Commission) and the environmental agencies. These powers
have over the last 15 years been tested and clarified in various rulings. The process has also been
evolutionary and reflects a balance between a well-defined regulatory contract, setting out precisely
the nature and scope of regulation, whilst at the same time allowing the system to adopt and grow as
necessary. It has been a balance between the advantages of regulatory certainty and the associated
risks of allowing the system to respond to a changed environment.
The regulatory legal framework consists of the privatisation legislation, which sets out the powers of
the regulator, reserving certain powers for the portfolio minister. It provides for individual licences
to be granted to the operators in the regulated industries. The licence sets out in more detail the
relationship between the regulator and the operator. The privatisation legislation imposes a set of
primary duties on the regulator, requiring the regulator to ensure that supply meets reasonable
demand, that suppliers should be able to finance the provision of the services they are called on to
supply and to promote competition. Supplementing these primary duties are secondary ones, calling
for the protection of the interest of consumers, promoting efficiency and economy, safety, research
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and development, protecting the environment and to give consideration to the sick, elderly, disabled,
and rural consumers. Various aspects of competition policy also apply, with both the Director
General of the OFT and the Competition Commission (formerly the Monopolies and Mergers
Commission) also having jurisdiction in certain circumstances, making the structure extremely
complex. These duties reflect a combination of economic and social obligations often mutually
incompatible. The regulatory duties are not ranked, leaving the regulator with substantial levels of
discretion. Wider aims such as public interests, as with the US system, are not mentioned.
The portfolio ministers generally issue the licences, which are more prescriptive in terms of the
conditions of service and duties. In some instances the power to issue licences is delegated to the
regulator.
In the case of electricity, licences are required for the generating companies, the
transmission operator, independent power producers, and in the case of the distribution sector,
public electricity supply (first tier) and second tier licences are required. The public electricity supply
(PES) licence creates an obligation on the part of the distribution companies to secure bulk power
from the most economic source and it restricts own generation, so as to prevent re-integration.
The transmission licence regulates the National Grid Company, the transmission owner and
provides for non-discriminatory access to the grid, and for the operator to schedule power stations
in order of the lowest bid, as well as to run a settlement system. Generators, NGC and the Pool
Administrator are required to sign a pooling and settlement agreement containing the relevant
contractual obligations under which bulk electricity is dispatched and paid. Except for generation,
control is placed on the average level of prices. There is also prohibition against cross-subsidy, a
requirement for non-discrimination and set of conditions which seeks to ensure security of supply.
Licences are for 25 years with an option for extension for a further 10 years and can be modified in
certain circumstances upon agreement between the regulator and the regulated firm, subject to veto
by the portfolio minister or upon reference to the Competition Commission. The licences are also
revocable after due notice or on grounds of serious misconduct or failure to perform.
The structure of legislation and licences was introduced to address a relatively unique feature of the
British parliamentary system. Its un-written constitution, guarantees the sovereignty of Parliament,
which theoretically, allows Parliament to enact and repeal laws as it deems fit. The unwritten nature
169
of the British constitution based upon given and accepted conventions, perceptively, fails to provide
the legislative certainty ordinarily guaranteed by written constitutions of other countries such as the
USA. The Primary legislation on its own is therefore vulnerable to opportunism and provides weak
regulatory commitment. The licenses are legally enforceable instruments and the courts will uphold
property rights, hence the licence provides what can be described as the regulatory contract. This
regulatory commitment is reinforced in the licence and complements the statutory requirement on
the regulator to ensure that the utility can finance their licensed activities.
Although the regulator is said to be independent, in point of fact this is not entirely true. Apart
from sharing some of the regulatory powers with the portfolio minister, this minister often has the
power to issue the licences. In most instances, the responsible minister (including establishing the
initial price controls) issues the initial licences. The responsible minister also appoints the regulator
and technically the regulator accounts through this minister. There are also powers of intervention in
certain circumstances, such as in takeover and mergers cases, power to veto modification by
agreement and power of reference to the Competition Commission.
RPI – X Regulation
The major departure of the electricity regulatory framework from the earlier three privatised utilities
is that for the first time the provision was made for the statutory obligation on the part of the
regulator to promote competition in respect of the generation and retail supply. The network sector
(transmission and distribution lines business), the natural monopoly segments were to be regulated.
At one and the same time the regulator was required to discharge the functions of industry specific
regulator, whilst at the same time police competition in generation and supply. Prossor (1997)19
states that Littlechild, as electricity regulator saw his job as follows:
“to provide competition where feasible and sensible to do so, bearing in mind that it
was not possible at the time of privatisation to move by a single step from stateowned monopoly to privately owned fully competitive industry. My task in part is
therefore to help complete the transition, not merely to monitor competition but to
actively promote it”.
For Rees and Vickers (1994)20 the most important aspect of the new regulatory framework was
regulation through price control, introduced as RPI-X, and requiring the average price charged to
170
fall each year by a factor “X” percent in real terms. In its basic form RPI-X requires that the price
index for a defined basket of the firms regulated products and services should increase by no more
than the rate of inflation, minus ”X” percent per annum for a period of years. The price of the
regulated basket must fall (or rise if X is plus) in real terms each year. In the case of electricity the
formula was varied to provide for cost pass-through for input factors that were outside the control
of the regulated firm. The formula then became RPI-X+Y with “Y” being the cost pass-through
component.
RPI-X is less vulnerable to cost plus inefficiency and over capitalisation. The company has the right
to share efficiency gains during the regulatory period and this provides the incentive for productive
efficiency21. It is also possible to pass on some of the expected efficiency improvements to
consumers when determining the level of X at the review period, therefore providing for allocative
efficiency. Prices not only tend to be lower than under rate of return regulation, it allows the
company the flexibility to adjust to the most optimal price structure, within the basket to market
conditions, whilst prices outside the basket are left to the forces of competition. It is seen to be a
simple formula to operate; however, over the years it has become more complex. It is more
transparent and better focused on parameters of greatest concern to consumers with price
information exogenous to the regulated firm.
The problem of information asymmetry is
significantly reduced and the incidence of regulatory capture minimised. The regulatory burden and
cost is significantly reduced, as the regulator’s role in the annual price changes is limited to checking
that the price increase is in line with the formula. It also overcomes some of the regulatory
commitment problem, to the extent that the regulatory law limits regulatory discretion between price
reviews. RPX-X is also seen to be less interventionist with less need for the regulator to probe into
the firm’s day to day affairs.
In setting the annual value of X, the government was largely concerned with the marketability of the
shares of the companies; however, in the periodic reviews the determination of the value of X
becomes the decision of the regulator. More and more the regulators have been focusing attention
on both the rate of profitability over the previous period and the rate of return on capital on the
succeeding review period, exposing RPI-X to the criticism that it is rate of return regulation every
five years. The same set of information needed to determine the value of capital and the cost of
171
capital in rate of return regulation are needed, with the result that the regulator is faced with the
same information asymmetry problems as under rate of return regulation.
Additionally, the formula lends itself to yardstick competition where the regulator sets a price based
on the average cost of a group of potential producers or an ideal producer. Each of the regulated
firms has the incentive to produce below the average unit cost of the group or the ideal firm to make
additional profit.
Rationale for Excluding Generation from Regulation
Generation was excluded from economic regulation on the theory that the two thermal generators
would compete fiercely as Bertrand oligopolists and in so doing secure efficient pricing.
Additionally, with entry into generation by the new CCGT players made comparatively easy from
the modest scale and cost of entry and especially through the 15-year power purchase contracts, the
market was made contestable.
Vertical separation of generation from transmission and horizontal unbundling of generation,
however, raises the question as to whether unbundling is sufficient to exclude the necessity of
regulating generation. This unbundling question is even more relevant when one considers that a
number of economists, Henney (1987)22 and Helm (1988)23 had not only argued for several
competing generators to reduce market power, but for the regulation of all the sectors. Vickers and
Yarrow (1988)24 and Green and Newbery (1992)25 did not see the number of generators at start as
critical, so long as entry was free. Vickers and Yarrow also felt that all the sectors should, however,
have been regulated. Green and Newbery did not see the duopoly structure as a serious entry
problem; however, they expressed concern over the duopolies ability to exercise considerable market
power without collusion by offering a supply schedule that is considerably above variable cost and
to exploit the constraints on the transmission network, depending on the degree of market power in
the regional sub-markets, and this is in addition to being able to support these strategies by outright
collusion.
The scope for the exercise of market power was seriously underestimated, based on the
misconception that Bertrand competition is sufficiently competitive in a highly concentrated market.
172
This misconception was fully borne out by subsequent experiences and the resultant inefficiencies
thrown up from the less than optimal structure at start. Government at the time had the option of
giving the regulator the power to impose a price ceiling in the competitive sectors in the hope that
competition would hold prices below the ceiling or subject the matter to competition law as is the
case in New Zealand or provide for reference to the competition regulator. The British chose the
latter solution. There was concern that direct regulatory powers to secure desired outcome would
serve to keep out competitive entry and threaten the competitive transformation process over the
long term.
Because of weak regulatory controls, however, the Regulator was forced to fight a running battle
with the two incumbent duopolies. In 1994 when the regulator was faced with high and
unpredictable pool prices and lack of transparency in the market, he was forced to intervene and
impose an unofficial price cap, as well as to secure voluntary agreements for the disposal by the two
duopolies of 15% of their generating capacity. This was made possible by the threat of reference to
the Competition Commission. The regional distributors also responded to the duopolies’ market
power by building their own CCGT generators.
It was therefore more the credible threat of entry, which restrained prices. This however, came at
the cost of high and volatile prices and the fact that important cost savings by generators were not
passed on to the consumers until after 1995/96. There is therefore the question as to whether the
absence of regulation was worth the inefficiencies and the extra cost of excess capacity and
inefficient entry. We have seen earlier that by 2000 the duopoly structure had disappeared, with new
entrants supplying more than 40% of the market. The absence of regulatory power to intervene
more directly when it was apparent that the bulk electricity market was not competitive could be
considered to be a policy error. Direct regulatory powers, however, should be limited to powers to
impose structural remedies and not to impose price controls.
Transmission Price Regulation
In the restructuring and privatisation of network industries, access and access pricing have
developed to be the most contentious regulatory issues. In the single buyer model, where the
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integrated utility owns the network and at the same time competes in the delivery of services in the
upstream and down stream markets, there is a clear case for very tight regulation.
The main problem of the vertically separated transmission system is that the coordination and
vertical economies might be lost from separation. It may be cheaper, for example to pay more to
locate new generation capacity near high demand zones at the expense of building extra
transmission lines.
The question as to how to price transmission services and how to decentralise decisions in respect
to generation location and investments in an unbundled transmission structure tends to be of the
utmost importance. Liberalisation of the generation market is not by itself sufficient to maximise
welfare. Competitive generators and retail suppliers must have free and non-discriminatory access to
the transmission wires. A transmission operator particularly, one with centralised responsibility for
all transmission services, possesses market power and the potential for opportunistic behaviour, for
example, vertical bias in favour of some users. In the Chilean attempts to create a competitive
market in the 1980s, the transmission system remained integrated with ENDASA, the largest
generator and this presented serious entry problems. It was not until 1993 that the transmission
assets in Chile were spun off into Transelec.
In the case of the England and Wales market, because of the dense transmission system and excess
generation capacity, which existed at restructuring, the problems of transmission bottlenecks and
constraints were more or less ignored. In the cases of countries like Australia and Argentina, with
distant networks or developing countries with weak and sparse networks and where the system is
prone to bottlenecks, transmission pricing to ensure efficient outcome becomes critical.
From a normative point of view transmission price should at least pay for the marginal cost created
by users. Nodal pricing best reflects this principle, which allows for optimal dispatch throughout the
system. Nodal pricing is a system of marginal cost pricing where differences in prices of each node
reflect two sets of costs incurred; congestion cost and losses. However, these costs only account for
about one third of transmission cost. The fixed cost must therefore be recovered by other
mechanisms. If short run efficiency is the objective, then Ramsey two part pricing provides for
optimal allocation of resources where the transmission operator has to balance its budget. Ramsey
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two part pricing allows for the fixed costs, of the infrastructure to be allocated to all the users,
otherwise large users will bypass the system and leave the smaller captive users with the burden of
the fixed cost.
Nodal pricing, however, allows for the exercise of market power when the system is ‘constrained-on’
and reduces market power when the system is ‘constrained-off’. Its attraction is that it defines the
value of transmission links connecting adjacent nodes and apparently provides a solution to two
problems, how to signal where consumers and generators should locate and how to decide when
and where to build additional capacity.
Instead of nodal pricing, a single integrated market as the benchmark with contracted rights to the
transmission system was adopted for the English and Wales electricity market. The system provided
for a single countrywide transmission price with provision for station specific adjustment. In a
situation where transmission constraints prevented merit order dispatch at power stations they are
compensated for by the difference between SMP less the station bid price. Power stations that bid
above SMP and are required to run, are paid their bid price. The extra cost was recovered initially
from all consumers and not just those constraining the system. Later connection and end use
charges were regionally differentiated so that both suppliers and generators took transmission cost
into account. Costs were distributed on the basis of the retailers’ peak demand and for generators on
the basis of their capacity and output in the ratio of 75:25.
The system adopted was seen to be simple to operate, eliminating the multiplicity of nodal prices. It
however, had the disadvantage that it provided incentives to exploit any capacity constraint by the
duopolies in manipulating bids offered.
In setting the price control regime, a two part pricing mechanism was adopted consisting of new
connection charges for individual users and as use-of-system service charges, with the latter covering
system service charges and infrastructure charges, inclusive of zonal differentiation. The cost for
new connection (as well as the cost for the French and Scottish connectors) is determined on the
basis of rate of return, whilst the use of system charges, together with existing connected users, are
the subject of the price cap regulation of RPI-X.
175
The price cap applies for the average charges and incorporates a correction factor to adjust for
forecasting errors. The X factor provided at vesting was set at zero. In the first price review, which
was carried out after three years, X factor, was tightened to minus 3% and lasted for the period
1993-1997. In the case of the second price review effective from April 1997-2001 the cap was
further tightened through a one off reduction of 20%, followed by the X factor being relaxed to
minus 1.5%, and accompanied by a one off reduction of 12%.
Between 1989/90 and 1993/94 the numbers employed in the transmission system fell from 6442 to
5125 as shown in Table 8 below. Over the decade of the 1990’s manpower reduction have been
estimated at 33.3%26. Operating cost, net of depreciation was reduced by an average of 40% over the
first price review period. The rate of return earned by the NGC as shown in Table 9 in 1990/91 was
4.9%, this increased to 6.7% in 1994/95 and experienced a marginal decline to 5% in 1996/97. This
compares with rates of return in the generation sector for the respective three periods of 4.0%, 9.5%
and 11.0%. Generation experienced significant increases in profitability over the first seven years,
whilst profitability in transmission, more or less stabilised after an initial increase.
Table 8
Changes in the Electricity System
Workforce
Sector
Total RECs
Generators
Transmission
Total ESI
1989/90
82,478
40,822
6,442
129,742
Source: Electricity Association, Annual Report
1993/94
71,473
22,465
5,125
99,125
% Decrease
per sector
-13.5
-45.0
-30.5
-24.0
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Table 9
Profitability of ESI after Privatisation
Sector
Generation
Transmission
Distribution
Rate of Return, %
1990/91
4.0
4.9
6.5
1994/95
9.6
6.7
9.2
1996/97
11.0
5.0
8.0
Source: David Parker, “Public Utilities: Lessons from the UK”, International Institute of Administrative
Sciences, Vol. 65, No. 1 (1999), p.124. Figures for distribution are on weighted averages.
Distribution Price Regulation
In the case of the distribution sector price controls in 1990 for eleven of the regional distributing
companies (excluding London) took the form of the X factor being plus rather than minus and the
controls were set at different figures for different companies, varying from zero to plus 2.5% in real
terms for each year. X was set to provide for an increase in this sector to take account of underinvestment when the enterprises were under public ownership.
It soon became apparent that government at vesting had seriously under-estimated the scope for
cost reduction and the exercise of location market power. The effect of this initial liberal price
control was that profits of the RECs progressively increased each year. Over 85% of RECs profits
came from the distribution lines business, with the rest from retail supply. Pressure for an earlier
review, than the review date of 1995 began to emerge from as early as 1992. The Regulator,
however, resisted the pressure for a mid-term review and argued that unplanned intervention would
be a breach of the regulatory commitment and would lead to a negative impact on incentives for
future investments. The Regulator also resisted pressures to shorten the review period from five
years to three years, the reason being that a shorter period would not provide sufficiently strong
incentives for efficiencies in the distribution sector.
The review which took place in 1994 was a long drawn out exercise and the price cap established by
the Regulator which was set in August 1994 called for one off reductions, ranging from 11% to 17%
and for an X factor of minus 2% to take effect from April 1995 to 2000, implying a reduction on a
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typical domestic fuel bill of 8% to 17.5%. For the purpose of the reduction, the distribution
companies were grouped into three categories. All the England and Wales RECs accepted the
proposals; however, one of the Scottish firms, Hydroelectric called for a reference of the proposed
changes to the MMC. The expectation also had been for a much harsher review, involving one off
reductions of up to 30% and for an X factor of minus 4%27. The relatively lenient review resulted in
share prices of RECs outperforming the stock market all summer of 1994. It was felt that as the
companies carried very little debt, and that as no major investments were required in the near future,
very little commercial risk was involved.
An unexpected development in the market in December of 1994 changed the environment and led
to questioning of the controls. The criticism was that they were not demanding. Trafalgar House, a
non-electricity company made a hostile bid for Northern Electric. In its vigorous defence, Northern
Electric offered £500 million in inducements to its shareholders to remain loyal, and promised cuts
in costs, special payments of £5 per shareholder, increased gearing and subsequent increases in
dividend payments in future years.
The formal consultations for the review were due to end by 11 March 1995, however, much to the
surprise of the City of London, the companies and even consumers, the Regulator announced that
in view of the new information which came to light, he intended to consider further tightening of
the controls. Share prices of the RECs immediately fell by 10-15%.
In his final decision, the Regulator stated that the charges set for the first year 1995-96 would stand
but for the further four years, new controls would be imposed. These consisted of the X factor
being tightened to minus 3% and further one off cuts of 10% to 13%, effective from April 1997.
The Regulator had also adopted the asset valuation method used by the MMC in the Scottish Hydro
referral case 28 and this more or less made a successful referral by the RECs unlikely.
The effect of this development was to demonstrate that RPI-X is not as trouble free as initially
presented. Secondly the problem of information asymmetry which price cap regulation was claimed
to have resolved remains problematical. Regulated firms have a monopoly on information and will
only release information when is it seen to be in their interest. Third the fact that the Regulator was
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able to change the price controls announced earlier and the informal nature of the procedures
adopted shows that RPI-X regulation is relatively weak on regulatory commitment.
Fourth in setting the X factor, the Regulator has had to resort to much the same sophisticated
financial models of the business, calling for much of the same information as with rate of return
regulation, such as the key parameters covering the cost of capital, rates of return and value of assets
and for the regulated firm to earn no more than the normal rate of return. Fifth the Regulator
himself admitted that there is a steep learning curve to be experienced with any new regulatory
regime, which is in effect admittance that there were errors in the earlier judgement. One good
outcome is that even when there is no product market competition to assist the Regulator, the
market for corporate control helps to partially fill this gap.
In 1999, the Regulator published new price controls for distribution, involving a one off reduction
of 25% from April 2000 (of which an average of 8% was transferred to retail supply) followed by an
X factor of minus 3% for the five-year review period.
As at 2001 there were 12 licensed regional distributors in England and Wales, 2 in Scotland and one
in Northern Ireland. Table 10 below shows the characteristics of the sector by number of
customers, turnover and unit sales. There is wide variation in their sizes and customer densities.
Table 10
Characteristics of Distribution - 2001
Company
1. East Midland Electric
2. London Electric
3. Manweb
4. Midland Electricity
5. Northern Electric
6. Norweb
7. SEEBOARD
8. Southern Electric
9. SWALEC
10. TXU Europe
11. Western Power
Distribution
Number of
Customers
000’s
2415
2060
1432
2275
1536
2239
2122
2699
989
3261
1344
% Share
of
Customer
s
Turnover
£M
355
370
240
362
236
346
283
417
199
249
442
Units
Distributed
GWh
17700
16500
12000
17200
10600
15500
NA
18900
9100
NA
8400
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12. Yorkshire Electric
England and Wales Total
13. Scottish Hydro
14. Scottish Electric
Great Britain Total
15. Northern Ireland
Electricity
UK Grand Total
2061
24433
659
2059
27151
681
27832
100
319
3818
169
343
4330
NA
15300
4400
14000
4400
NA
Source: Electricity Association, Electricity Review, No. 5, London (January 2001), p. 57.
Since 1989/90 the distribution sector has benefited from investments of £12 billion. Over the same
period and particularly during the first five years after vesting there has been continued shedding of
labour. Improvements in productivity, however, have been smaller than in generation and
transmission. The reduction in the workforce in the four years after 1989/90 was 13.5% as shown
earlier in Table 9 above, compared to the industry’s average of 24.1%.
Since 1996 there has also been widespread withdrawal of the regional distributors from the retail
business, most of which has been divested to other generators, and to other utilities, giving rise to
multi-utility operators. The multi-utility operators seek to capitalise on the economies of retailing gas
and electricity or electricity and water.
The RECs have also seen improvements in their profitability, with rates of return rising from 6.5%
in 1990/91 to 9/2% in 1994/95. The tightening of the cap by the Regulator after 1995/96, however,
has resulted in a marginal decline in profitability, which has stabilised at around 8.0%.
With the improved profitability the RECs were able to pay off their debt obligation taken over at
privatisation and in addition have been able to pay relatively high dividends and high executive
salaries, leading to criticism and pressure for the Regulator to intervene.
Regulating the Competitive Transformation of the Retail Market
Although the retail business was declared potentially competitive in 1989 the policy framework for
competitive transformation process called for regulation and liberalisation to be effected in the
industry simultaneously. The retail business was segmented into three markets and competition was
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to be phased, starting with the first segment, the large industrial consumers (demand in excess of 1
MW) in 1990, followed by the medium sized users (demand in excess of 100 kW and below 1 MW)
in 1994. The small domestic and small business consumers’ segment (less than 100 kW) was to be
liberalised in April 1998.
The non-liberalised market was to be subject of the RPI-X price control and these controls were to
remain in force up to liberalisation in 1998. The pricing formula was adjusted to RPI-X+Y revenue
yield control, with the “Y” factor being input cost-pass through of five elements; energy,
transmission, pool administration and distribution costs and the fossil-fuel levy and are the cost
drivers for which the retail suppliers have no control over and account for 95% of total systems
cost. The portion controlled by the supply cap, represents the value added, at 5% of system cost.
The controls, which operated over the first review period to March 1994, regulated the maximum
charge per unit of electricity supplied in both the franchised and non-franchise markets. The
revenue applied to a constant term plus an allowance per customer served and an allowance per unit
sold. The constant term varied between RECs, with the allowance per customer served, and per unit
sold being uniform across RECs. The costs were distributed 75% for the number of customer
served and 25% for the number of kilowatts sold. Additionally, there was a supplementary price
control, which expired in March 1995.
For the first price review period, X was set at zero. The first review in 1994 resulted in new
controls. X was tightened to minus 2% and lasted until 1998. For the two-year period after April
1998, prices were subjected to a fixed maximum, and were designed to protect the small consumers
during the transitional phase of liberalisation compared with the previous controls where the RECs
were able to pass through the input costs. This new control applied to all “designated customers,
users who consumed 12000 kWh per year or identified as domestic customers”, under the PES
licence. Over the two-year period the average real reduction was estimated to be 9%.
Further price controls were also proposed for the two year period to April 200229. These controls
were to apply for all but the direct debit customers and took the form also of a cap on final prices in
the first year, based on RPI-X and applied to two basic domestic tariff blocks. PES’s were
encouraged to reduce prices if generation prices fell with the introduction of the New Electricity
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Trading Arrangements (NETA). In the second year of the control, the maximum prices were
expected to fall by 2.1% and 5.8% for the respective two tariff blocks.
In 1990 the large consumer market segment amounted to 28% of the retail market and numbered
5000 customers, whilst the medium sized segment, which was to be liberalised in 1994 numbered
45,000 customers and accounted for 16% of the market, with the result that 44% of the market was
offered choice by 1994. The remaining 54%, the small domestic customer market, estimated to be
23 million users in 1990 was scheduled to liberalised in April 1998, but was postponed to September
1998 due to the difficulties encountered with the application of the computer software and the sheer
logistical problems presented by offering choice to 26 million new customers. The application of the
liberalisation itself was phased. The first four RECs commenced in September 1998, the second
group in December 1998, the third group in April 1999 and with the entire programme completed
by June 1999.
There are important economies of scale, which work in favour of the large, and medium sized
consumers in exercising choice. Bonner (1996)30 shows that for a small domestic householder in
1994 with a typical annual bill of £400, the costs breakdown in percentage term was as follows;
distribution 25%, retail supply 6% and transmission and generation as well as the levy 70%. This is
in contrast to the large consumers, where the percentage breakdown was distribution 15%, supply
0.5% and generation transmission and the levy 84.5%. The marginal benefit to the large consumer is
much greater than the small consumer, therefore, the marginal cost, becomes a critical factor in
exercising choice. The transaction cost to the small consumer may be perceived to be greater than
the marginal benefit from switching.
By May 1999, 5% of small household consumers had exercised choice and at the end of 2000, 6
million or 25% had exercised choice31. In 1996, 37% of the large and medium sized consumers had
exercised choice. The percentages increased to 80% for large consumers and 58% for medium sized
consumers by the end of 200032.
In terms of the second tier market, the PES themselves have accounted for 66% of the large
consumer segment, 48% of medium sized consumers and 83% for the small consumer segment. In
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2001 there were 27 million consumers, with the consumer base growing at 1% per annum and
demand by 1.3%.
Between 1989 and 1994, electricity prices on average real terms fell by 10%. The liberalised
customers saw a real price reduction of 20%. Nominal prices increased from 7.74 pence/kWh in
1990 to reach 8.91 pence/kWh by 1992, declining to 7.74 pence/kWh, by 2000, reflecting a real
decline of 36% over the 10-year period. For the large consumer group the real decline varied from
27% to 33%. The real reductions in prices are shown in Figure 22 for the various market segments.
The reductions were less for the very large industrial group and this resulted from the elimination of
the subsidies, which were available to the very large consumers prior to privatisation.
Figure 22
183
Source: Stephen Littlechild, Privatisation, Competition and Regulation in the British Electricity
Industry, with Implications for Developing Countries, World Bank/UNDP ESMDP Report, (2000),
p.33.
The retail market has been experiencing increased levels of consolidation since 1998 the result of
several mergers, some leading to multi-utility providers. The multi-utility market has been growing as
retailers seek economies of scale from realigning electricity and gas or water and electricity in there
merchandising packages.
Green and McDaniel (1998)33 predicted that the benefits of introducing competition in the small
consumers’ market will result from three effects; further reductions in electricity costs, as retailers
will no longer be able to pass on input costs to customers especially generation cost from their IPP
associates, increased services and a fall in industry profit margins, where they exist above
competitive levels.
Changes to UK Regulation
Despite the relative success of British style regulation, it was characterised by a number of
deficiencies and these have attracted strong criticisms. The single decision maker is said to lead to
personalisation of regulation and a disproportionate effect on regulatory outcomes. Further this
system provided a weak institutional memory, as replacement of the single individual decision maker
at a given time was likely to lead to discontinuity. There is the risk also that the single individual
could be more readily subjected to undue political pressure.
The process is less open, and in the case of electricity regulation there was very little involvement of
consumers in the process. Overall the system lacked transparency in that there was no obligation on
the part of the regulators to give reasons for tier decisions. The industry specific regulatory
framework leads to a multiplicity of regulatory agencies, is relatively expensive and can lead to
regulators adopting different approaches to common methodological issues. Several regulatory
agencies give rise to regulatory arbitrage.
184
In many instances X is set quite arbitrarily, as no one knows how much efficiencies had developed in
the publicly owned utilities prior to privatisation to be able to determine how much improved
productivity is obtainable from X. In the UK, X was set very loosely, providing for the utilities to
earn excessive profits in the initial years. There is no certainty that the starting tariff levels are the
correct levels on which to base the subsequent reductions. In most instances, tariff rebalancing is
needed as was the case in the UK in the years just prior to privatisation. In developing countries
with extremely high levels of cross-subsidies and where rates do not reflect long-run marginal cost,
tariff increases to the subsidised domestic householders may be needed initially rather than tariff
reduction. This can be quite an unpopular political decision to take and implement.
If price cap regulation is set in reference to actual cost incurred by the firm concerned, it is almost
identical to ROR regulation. The increased need for information at price reviews particularly in
relation to cost of capital, rates of return and value of assets results in the criticism that it is ROR
every five years and gives rise to some of the same information asymmetry problems as in ROR
regulation. Paradoxically, the more successful the regulated firm in reducing cost beyond what was
anticipated by the Regulator the more customer dissatisfaction is engendered and criticism that
regulation may have failed. Public pressures then build up for the Regulator or the state to claw
back some of the benefits as was exemplified in the UK with the imposition of the windfall tax on
the regulated utilities by the new Labour government in the later half of the 1990s. This could dilute
some of the incentives which price cap regulation is said to provide to investors.
Following from the various complaints, Government published in 1998 a set of consultation
documents outlining proposals for future reforms34. An essential principle incorporated in the
consultation documents was a movement away from regulation of services (as services were
becoming competitive in several of the utilities), to regulation of the network. This reflects a further
fundamental change in the British approach to regulation and is based on the underlying principle
that competition is the best regulator. This principle was subsequently incorporated in the
Competition Act of 1998 and the Utilities Act of 2000.
The Utilities Act amends the 1986 Gas Act and the 1989 Electricity Act and provides for one
regulatory regime for both industries, in effect recognising the growing convergence between both
industries since privatisation. The Act also provides for the unbundling of distribution and retail
185
supply into separate legal entities, establishment of a New Electricity Trading Arrangement, for
additional protection and involvement of consumers in regulatory affairs and for improved
transparency, consistency and predictability of the regulatory process.
A new corporate body; the Gas and Electricity Market Authority (GEMA) with a Board of at least
three members replaced the two Director Generals of both Gas and Electricity. The Authority is
supported with an Office of Gas and Electricity Regulation (Ofgem). It will be required to consult
more widely, to provide a foreword programme with key objectives and to publish reasons for key
decisions. Its pricing objective will be to protect the interest of consumers.
Further changes empower the Authority with the mandate to grant licences, establish procedures for
licence changes and effect licence modification without further primary legislation or ministerial
approval. Instead of individual and unique licences for each operator, class licences with standard
conditions are to be issued to ensure that all holders of a particular licence type are subject to the
same conditions and to allow for collective modification. Government, however, issues the initial
standard licence, with the Authority carrying powers of modification, subject only to veto powers by
the Competition Commission.
Provisions have also been made to impose mandatory penalties subject to a maximum limited to
10% of the firm’s turnover. The PES licence, which covered both distribution lines business and
retail supply, is to be discontinued and separate licences to be issued for distribution and supply.
Although distribution and supply will be separate legal entities, common ownership is not precluded.
The concept of the PES ceased to apply as of April 2001 and the duty to supply is replaced by a duty
to connect. Distribution licence will carry a duty to facilitate competition in generation and supply
with non-discriminatory terms of access, as well as to provide non-discriminatory terms for services
relating to metering, until full competition in metering develops. The licence for distribution will
continue to be issued for a defined geographical area and will coincide with the existing PES
boundaries and referred to as distribution services area (DSA).
Retail licences, however, will not necessarily carry geographical restrictions and can be issued for all
of Great Britain, for a particular region or for a class of customers. The distinction between first tier
and second tier licences are to be removed, as well as tariff supply conditions and replaced by
186
commercial contracts between supplier and customers. The changes also downgrade the duty of the
Regulator to promote competition and give more importance to protection of consumers, interests.
Ofgem came into operation in 1999 and work on separation of licences (distribution lines business
from retail supply) began in 1999. Work on the licence amendments commenced in 2000. The
Competition Act on the other hand confers new powers on the utility regulators, giving them
concurrent jurisdiction in respect of competition matters. A Competition Commission also replaced
the Monopolies and Mergers Commission. This new Commission will also operate as the appeals
body for the Office of Fair Trading and the individual industry regulatory agencies. A special panel
of the Competition Commission has been established to hear appeals from the electricity industry.
Under the new law, regulators will be required to institute procedures to determine when markets
move from pre-competitive to fully competitive, to establish clear sets of procedures on the
regulatory decision making process, as well as procedures on the regulatory methodologies to be
adopted. Government, however, decided that despite the criticisms made against RPI-X price
control, there was no justification for any substantial changes to the formula.
The Verdict
Over the 10 year period following privatisation, costs have fallen significantly in the generation
sector in England and Wales; however, the fall in fuel costs in real terms in the first five years have
been more dramatic than the fall in prices. The result is that the margin between fuel costs and bulk
electricity prices widened.
There were also significant improvements in efficiencies in transmission and distribution, but less
dramatic than in generation. As bulk electricity prices did not fall nearly as fast as the decline in
input costs, the privatised company’s experienced sharp increases in profitability, especially over the
first five years. Combined profits of the industry rose from £2.0 billion in 1991/92 to £3.5 billion in
187
1995/96 and rates of return rose from 3% in 1990/91 to 11% in 1995/96. Share prices of the
thermal generators tripled between floatation and 1995 and out performed the stock market by
100%35. Shareholders who bought the shares of the six electricity companies at vesting day earned
annual average returns of 40% by 199636. Shareholders of the privatised companies gained
immensely.
The pressures from competition, following from vertical and horizontal unbundling provided
increased incentives for efficiency improvements and cost reduction. Considerable improvements
were obtained in labour productivity. Reduction of labour in the generation sector was over 45%
and overall for the ESI 24% for the first five years after vesting. In the coal industry the indirect
impact was dramatic. An industry, which employed over 250,000 in the mid-1980s, had declined to
no more than 10,000 workers by the early 1990s. The improvements came with a cost to both
labour and the nuclear industry. Plans to build more nuclear plants by 1996 were shelved, more or
less permanently. The competitive pressures which were felt in the fuel industry and which led to the
lowering of fuel prices came from replacing expensive and environmentally expensive coal and
nuclear plants with cheaper and cleaner CCGT plants. The environmental benefits have resulted in a
reduction in acid rain and CO2 emission.
Consumers in the retail market, however, failed to see important benefits until after 1995/96. The
idea of Bertrand competition to supply electricity at efficient prices to consumers failed to
materialise. Market power of the incumbent fossil fuel duopolies was regularly abused, necessitating
constant vigilance of the Regulator. The result was that the improvements in productive efficiencies
and lower costs did not translate into reduced consumer prices or ; allocative efficiencies.
Newbery and Pollitt (1997)37 constructed various counterfactuals about what might have happened
without restructuring and with continued state monopoly operation and concluded that there was an
overall net benefit in the first five years after vesting, which when converted to permanent savings;
the unit cost to consumers amounted to a reduction of 3.2% to 7.5%, depending on the
assumptions factored into the model. The distribution of the benefits, however, has been skewed
towards the investors and stockholders who benefited from high profits and higher dividend
payments.
188
Despite the sizable restructuring costs involved in the reforms and privatisation, the revenues from
the sale of the companies, the increased tax flows and the fact that the Treasury no longer had to
finance capital costs for the industry, also meant that government obtained appreciable benefits.
Consumers, however, did not experience net benefits in the initial five years. Consumers began to
see real benefits after 1996 and with full competition in retail supply after 1998. Green and
McDaniel (1998)38 predicted three likely outcomes; further lowering of retail prices to consumers,
reduced margins to the retailers, and improved quality of service.
The British experience also shows that competition and restructuring of the electricity supply
industry can take several forms. In Scotland, competition was expected to take place between the
two vertically integrated franchised monopoly utilities. Pollitt (1998)39 concluded that whilst the
reforms generated some beneficial effects in the nuclear industry in efficiency gains, there were very
few discernable effects on efficiency improvements and productivity growth in the two integrated
utilities. The Scottish companies were not only protected from product market competition, entry to
the market was restricted until after 1998 and the market for corporate control was closed with the
permanent incorporation of the “golden share”. Rather than lower real prices, consumers
experienced increased real prices and consumer prices, which were lower than in E&W in 1990,
were higher in 1999.
In Northern Ireland where generation was vertically and horizontally unbundled and increased levels
of competition accommodated in the generation sector, the reforms provided strong incentives to
cut cost in the generation sector, especially from the conversion of expensive oil fired plants to
CCGT plants. With a vertically integrated transmission and distribution utility operator and with
competition in the large consumer market segment coming on stream after 1994, whilst that of the
medium sized consumer (over 2.5 GWh consumption per annum) coming after 2000, very little of
the efficiency gains have been passed to consumers. Pollitt (1997)40 showed that in the case of
Northern Ireland, unit cost fell by 14% between 1991/92 and 1995/96, whilst retail prices increased
faster than the rate of inflation. In 1996 the average level of prices in Northern Ireland was 23%
above the average levels in E&W.
The empirical evidence from the application of the three British models of restructuring is that the
vertically operated privately owned and regulated utility is the least effective in bringing about
189
efficiency and welfare gains. Vertical integration as was applicable in Scotland muted the incentives
for efficiency. Vertical and horizontal unbundling of generation as was applicable in Northern
Ireland and the single buyer trading arrangement that formed the Northern Ireland structure
provided for increased incentives for efficient investments in generation. Despite regulation of
vertically integrated transmission and distribution in Northern Ireland, very little of the gains were
passed on to consumers. The single buyer model is, however, superior to the fully integrated
franchised monopoly operator.
In the case of the E&W experiences with full disintegration,
competition in the bulk electricity market, full competition in retail supply in 1999 and competition
in the market for corporate control, significant gains were made in both productive and allocative
efficiencies. Further gains from lower prices to consumers are also expected, now that competition
has taken a strong hold in both generation and retail supply.
Restructuring and exposing the privately owned utilities to competition, where competition is
possible, and providing for incentive type regulation from price-caps, offer powerful incentives for
improvements in economic efficiencies and welfare gains. The disintegrated privately operated ESI,
operating under competitive conditions in generating and retail supply, and incentive regulation over
the core network natural monopoly is superior to both privately owned with rate of return and cost
of service regulation and publicly owned monopoly with self-regulation. Opening the industry to
competition has resulted in new owners, new technologies, and new structures. In fact none of the
original regional electricity companies has survived in its original form.
Ownership in a few
instances has changed three times.
The British privatisation experiences seem also to have resolved the question as to the superiority of
privately owned utilities versus publicly owned utilities. It was shown in Chapter 1, that since 1970,
several studies carried out by various analysts, have examined the comparative financial
performances, labour productivity and total factor productivity of publicly owned and privately
owned utilities. Most of these studies found no strong evidence to support the thesis that privately
owned utilities are superior to public utility enterprises in terms of economic efficiency.
This general conclusion is not surprising, as most of the privately owned utilities prior to 1990 were
integrated monopolies regulated by the rate of return methodology. Privately owned monopoly
utilities with ROR regulation carry important similarities with publicly owned monopoly utilities.
190
Under both institutional arrangements the incentives for efficiency improvements and cost
reduction are extremely weak. Restructuring exposes the privately owned electricity supply industry
to competition and offers greater incentives for cost reduction and efficiency improvements than
rate of return regulated privately owned or publicly owned utilities. Interest group theory of
regulation points out that similar characteristics are to be found with privately owned rate of return
regulated and publicly owned monopolies. Such firms will pursue economic rents and such rents will
be distributed between the various interest groups in proportion to their bargaining power (Noll
1989) 41. The redistribution effects are x-inefficiencies and dead weight losses.
In both privately owned and regulated monopolies, and publicly owned utilities, the consumer bears
the risk of investment. Even with a bulk electricity market, with cost pass-through, the captive
consumers bear the investment risks. A change to full retail competition, dramatically changes the
risk balance, in that once consumers are free to change patronage, retailers will no longer be able to
enter into long-term contracts knowing that they can pass the increased cost to consumers. Retail
competition will result in more equitable distribution of risks between generators, retailers and
consumers.
These developments have led Littlechild (2000)42 to state that:
“The principles of private ownership, competitive markets and independent
regulation (England and Wales) have worked well. The British electricity industry is
now more efficient and innovative………………
All groups of consumers have benefited significantly in terms of lower prices and
better quality of service. The benefits of introducing competition already outweigh
the costs and more benefits are to come”.
In conclusion it would appear that the British experiences not only signalled the end of the vertically
integrated state owned franchised monopoly as the dominant institutional form for the operation of
utilities, it has also signalled the end of vertically integrated privately owned franchised monopoly
utilities regulated by rate of return regulation. Whilst the circumstances for developing countries are
different from those of a more mature market as that of England and Wales, the same principles of
public polices would appear to be applicable. With appropriate adaptations especially for markets of
less than 1000 MW, the policy of structural disintegration, competition where competition is
191
possible and independent regulation where market failure continues, appears to be the right public
policy for developing countries.
Privatisation and deregulation has also created a condition for the rise of the ‘regulatory state’ to
replace the ‘development state’ of the past. Privatisation has not in fact led to a reduction of state
intervention; there may be a decline in public ownership as is the case in Britain. However the state
has transformed its role by replacing public ownership form of intervention with regulatory form of
intervention. Regulation has become the new border between the state and the battleground for
ideas as to how the economy is to be managed.
192
End Notes
1.
J. Foreman-Peck and R. Millward, Public and Private Ownership of British Industry
1820 – 1990, Oxford; Clarendon Press (1994). pp.107 and 167.
2.
Pablo Spiller and Cezley Sampson, Regulation, Institutions and Commitment; The
Jamaican Telecommunications Sector, Washington, D.C., World Bank Policy Research
Working Paper No. 1362 (1994) p.18.
3.
The public utilities commission (or public service commission as they are known in some
states) was first exported across the Atlantic, being derived from the Canal and Railway
Regulatory Commissions of the mid 1850’s.
4.
David M. Newbery, Privatisation, Restructuring and Regulation of Network
Industries, Cambridge, Mass, MIT. (2000) p.50.
5.
George Kolko, Railroads and Regulation, 1877 to 1916, Princeton University Press
(1965).
6.
George Stigler, “The Theory of Economic Regulation” Bell Journal of Economics and
Management Science, Vol. 2, No.1 (1971).
7.
Mohan Munasinge and Arun Sanghvi, Recent Developments in US Power Sector and
Their Relevance to Developing Countries, Washington, World Bank, Working Paper
Energy Series No. 12 (1989), p.14.
8.
Robert Baldwin and C McCrudden, Regulation and Public Law, London (1987), p. 170.
9.
S.C. Littlechild, Regulation of British Telecommunications Profitability, London,
HMSO (1983).
10.
S.C. Littlechild, Privatisation, Competition and Regulation in the British Electricity
Industry With Implications for Developing Countries, Joint UNDP/World Bank
ESMAP, Washington, D.C. (February 2000). p. 14
11.
Ibid. p. 23.
12.
In principle a profit maximising monopolist could engage in perfect discrimination and
charge each user up to their willingness to pay, Ramsey pricing, with the result that there
would be no loss to society.
13.
A firm achieves technical efficiency when it minimises production cost of supplying any
given output and achieves input price efficiency when it minimises inputs purchased for any
given output; it purchases inputs optimally and produce at the optimal production level.
Static efficiency relates to efficiency gains with existing technology, production process or
193
products; a movement on the production frontier. Dynamic efficiency relates to efficiency
improvements over time and results from new technology, new products or new production
process; a shifting of the production frontier outwards or a change to the slope of the
production trajectory. Firms which are allocatively and technically efficient are said to be Xefficient, these firms, irrespective of their dominant positions in final markets act to keep
cost as low as possible. It is possible for firms which face no competition to appear not to
make excessive profits, yet to have inefficiently high cost and high prices, or X-inefficient,
conversely firms which are X-efficient may make excessive profit yet have low cost and low
prices.
14.
Brian Williamson, “UK: Incentive Regulation, International Best Practices”, in Regulatory
Review 2000/01, eds., Peter Vass, Bath, Centre for the Study of Regulated Industries
(2001), p. 272.
15.
Constitutional interpretation has the independent regulatory agencies in the UK as a separate
institution from the respective sector ministry, see Lake Airways VS Department of Trade
1997, where the Court ruled against the right of the Minister to give guidance to the Civil
Aviation Authority. The Court stated that guidance could supplement the CAA statutory
objectives it could not replace them. In issuing pre-emptory instruction to the CAA, the
Court also ruled that it constituted directions, rather than guidance. Custom and practice of
UK unwritten constitution is that portfolio ministers do not interfere in the affairs of
independent regulatory agencies.
16.
John Kay, “The Future of UK Utility Regulation” in Regulating Utilities: Time For a
Change? eds., M.E. Beesley, et.al. London, Institute of Economic Association (1996), p. 52.
17.
Tony Prosser, Law and Regulators, Oxford, Clarendon Press (1997), p. 16.
18.
Alison Young, “The Politics of Regulation: Privatised Utilities in Britain”, London,
Pelgrave (2001), p. 26.
Prossor, op. cit., p. 158
19.
20.
Ray Rees and John Vickers, “RPI-X Price Cap Regulation”, in Regulatory Reform:
Economic Analyses and British Experiences, eds., Mark Armstrong, Simon Cowan and
John Vickers, Cambridge, MIT Press (1994), p. 166.
21.
John Vickers and George Yarrow, “Regulation: Regulation of Privatised Firms in Britain”
European Economic Review, Vol. 32, (1998), p. 468.
22.
Alex Henney, “Private
Power: Restructuring the Electricity Industry”, Policy Study,
Centre For Policy Studies, No. 83 (1987).
23.
Dieter Helm, “Regulating the Electricity Supply Industry”, Institute of Fiscal Studies,
Fiscal Study No. 9 (August 1988).
24.
Vickers and Yarrow, (1998), op. cit.
194
25.
Richard Green and David Newbery “Competition in the British Electricity Spot Market”,
Journal of Political Economy, Vol. 100, No. 5 (1992).
26.
Littlechild, (2000), op. cit.
27.
Times of London, 12 August 1994.
28.
MMC concluded that the regulator had placed too high a value on the companies’ assets and
that the companies should have absorbed the redundancy payments and not added on.
29.
Ivan Adams, “Electricity Supply: The Second Tier Market”, in Energy – Transition or
Maturity? Review of the Current Policy and Development, ed., Carole Hicks, London,
Centre for the Study of Regulated Industries (1996), p. 61.
30.
John Bonner, “Electricity Distribution, Review-Outcome and Response”, in Energy –
Transition or Maturity? A Review of Current Policy and Development, eds., Carole
Hicks, Centre for the Study of Regulated Industries, London (1996), 16.
31.
Littlechild (2000), op., cit.
32.
Ivan Adams, op.cit. p.61.
33.
Richard Green and Tango McDaniel, “Competition in Electricity Supply: Will “1998” Be
Worth It?” Fiscal Studies, Vol.19, (1998).
34.
Department of Trade and Industry, A Fair Deal for Consumers: Modernising the
Framework for Utility Regulation, London, HMSO, CM3898 (1998a); Department of
Trade and Industry, Review of the Energy Sources for Power Generation: Consultation
Document, London, HMSO, (1998b); Department of Trade and Industry, A Fair Deal for
Consumers: Modernising the Framework for Utility Regulation: The Response to
Consultation, London (1998c).
35.
David Newbery and Richard Green, “ Regulating Public Ownership and Privatisation of
English Electricity Industry”, in International Comparison of Electricity Regulation”,
eds., Richard Gilbert and Alfred Kahn, Cambridge University Press, (1996), p. 100.
36.
David Parker, Privatisation in Regulated Industries, Bath, Centre for the Study of
Regulated Industries, Occasional Paper No. 4 (1997), p. 34.
37.
David Newbery and Michael Pollitt, “The Restructuring and Privatisation of Britain’s CEGB
– Was It Worth It? The Journal of Industrial Economics, Vol. 45, No. 3 (1997).
38.
Green and McDaniel, op.cit., p.291.
39.
Michael Pollitt, The Restructuring and Privatisation of Electricity Supply Industry in
Northern Ireland- Will It Be Worth It? Cambridge University, Department of
Economics, Mimo (February 1997), p.7.
195
40.
Michael Pollitt, The Restructuring and Privatisation of Electricity Supply Industry in
Scotland, Cambridge University, Department of Economics, Mimo (June 1998).
41.
Roger Noll, “The Politics of Regulation” in Handbook of Industrial Organisation, ed., R.
Schmalensee and R. Willig, Amsterdam, Elsevier Vol.2, (1989), Ch.22.
42.
Littlechild (2000), op.cit. p.51.
196
Chapter 5
Ownership, Regulation, Liberalisation and Privatisation in the Electricity Utility; the
Jamaican Case
The Early Years
Jamaica’s electric utility history, presents an interesting case to review institutional structures from
the several regulatory regimes, industry structures and ownership structures, which have prevailed
over the last fifty years. Electricity services were introduced in Jamaica in the 1892 by a private firm,
Jamaica Electric Light and Power Company1. West India Electric Company (WIEC) came into
operation and built one of the first hydroelectric plants in the world at the Bog Walk Gorge, St.
Catherine. The company obtained a licence to supply light and power to Spanish Town and parts of
St. Andrew. In 1907 WIEC leased the property and business of the Jamaica Light and Power
Company Limited (JLPCL), successors to Jamaica Electric Light and Power Company.
The Jamaica Public Services Company (JPSCo) came into being in 1923 when the Canadian based
JPSCo purchased the assets of WIEC, including the tramway system and expanded power capacity
by installing a coal burning power plant in Kingston2. While the financing for JPSCo came from
Canada, the US firm, Stone and Webster Inc, provided management expertise3. Stone and Webster
eventually came to own 20% of JPSCo. At the time of acquisition in 1925 the total connected
customers amounted to 3958 and this increased to 16000 by 1960.
Over the years, JPSCo acquired the several small power companies, which had been given separate
licences, with the last to be acquired being the Savana-La-Mar firm in 1977. JPSCo found itself
from the several acquisitions with over 26 licences for different areas, often with different standards.
Most of these had to be renewed annually, and the uncertainty created by the annual renewals made
it difficult for the company to obtain long term financing. As a condition of a World Bank loan in
1966, Government eventually provided JPSCo with a 25-year exclusive licence for the entire island
(the All Island Licence). Between 1959 and 1963 the company carried out a frequency conversion
programme, which facilitated the standardisation of supply, and uniform electricity rates Island wide.
197
In the 1960s JPSCo’s stocks were listed on the newly formed Kingston Stock Exchange as well as on
the London Stock Exchange and this listing continued until 1974 when government acquired almost
all of the outstanding shares then held by private investors. Following from a dispute with the
overseas equity owners, Government earlier in 1971 had purchased the stocks of Stone and Webster
amounting to 20% of the company’s equity. With compulsory acquisition of the rest of the
company’s shares in 1974, the end of the first chapter that of 82 years of private ownership of the
electricity industry, came to an end.
The system of private ownership and independent regulation of utilities is often presented solely as
an American experience. Jamaica also developed a system of private ownership of the utilities and
independent regulation; however, the regulatory regime up to 1966 took a different form from the
US system of Public Utility Commission.
The regulatory structure prior to 1966 provided for the establishment of three-member ad hoc Rate
Boards, appointed by the Colonial Governor of Jamaica4. The decisions of the Rate Boards could
be appealed to the Courts and eventually to the Privy Council in London. Unlike the Jamaica
Telephone Company, which operated under a 40-year licence granted in 1925, JPSCo had to seek
annual renewal of its licences.
Rate Boards were constituted or appointed for each review. They therefore lacked institutional
memory, as there was no permanent member of staff. The Boards resorted to the use of ad hoc
consultants, who were paid by the company, but selected by the Board to review the accounts of the
company pursuant to an application for a rate increase. The Rate Boards suffered from serious
structural information asymmetry vis-à-vis the utility companies. Additionally, the absence of a
transparent and independent system of financing the Boards compromised their independence. The
system of licence and contract with ultimate appeal to the courts, however, served the colonial
period reasonable, well in an environment of low inflation. In between rate reviews the companies
operated with little or no government interference and the eight percent real rate of return which
was allowed, could also be considered adequate in an environment when the real interest rate was in
single digits5.
198
The regulatory stability of the colonial days came to an end in 1955 when a socialist administration
under the crown colony rule came to power and announced a policy of industrialisation based on
the Puerto Rican model. Electricity was treated as an item of luxury up to 1955, despite the fact that
there had been continued decline in prices since 1923. JPSCo was also able to maintain healthy
profit returns over the years. Electricity rates had also been frozen by legislation in the early 1950s,
the company being accused of trying to raise development capital from rate increases.
As part of the industrialisation policy the socialist administration sought expansion of capacity by
JPSCo to meet its development goals. JPSCo responded by declaring that their debenture holders
and the company’s financial structure precluded expansion unless rates were increased. The annual
renewal of the licences also provided for considerable uncertainty as the company was required to
provide capital to develop the services even though there were no assurances that it would be given
the permission to operate for more than one year or that the rate provided would allow it to raise
new capital. The outcome was a protracted dispute where the commercial objectives of the
transnational company came in sharp conflict with the development goals of the local
administration. The dispute persisted for the life of the administration up to1962; however, new
legislation; the Electricity Development Act 1958, was introduced and this led to the establishment
of the Electricity Authority to generate electricity and interconnect with the utility’s system or to
interconnect with other privately owned generating systems. The other Act governing the sector was
the 1890 Electricity Lighting Act, establishing the Licencing regime for the supply of electricity. The
1890 Act permitted self-generation. Both the bauxite and sugar industries took advantage of this
right to the extent that the installed capacity of the self-generators in 1960 was larger than the
capacity of the utility company.
Jamaica became independent in 1962 and the new Jamaica Labour Party (JLP) administration, which
came to power, continued the dialogue with JPSCo for another three years up to 1965 in an effort to
resolve the impasse. JPSCo eventually agreed to accept a new all-island exclusive franchise and for
the company to be regulated by an American style public utilities commission. Although the
agreement did not provide for any immediate rate increase, government agreed to guarantee a World
Bank loan to the company to meet the cost of an agreed expansion programme.
199
The Jamaica Public Utility Commission Act (JPUC) of 1965 gave the portfolio minister the authority
to licence any enterprise to generate and supply electricity for public use. At the same time under
the Electricity Development Act of 1958 the same Minister had the authority to own, operate and
develop electricity. It was through the Electricity Authority, that the government used as the vehicle
to acquire the shares in the JPSCo between 1971 and 1974, and this gave the state 99% ownership of
JPSCo. The Electricity Authority also owned the shares in the Rural Electrification Programme
Company Ltd, which was established in the 1960s.
An important element of the institutional structure of the Jamaican utility system has therefore, been
that of a joint stock company with previous listing on stock exchanges, as distinct from the
institutional form of a government department or statutory corporation. Jamaica differed from many
of the other Commonwealth countries, such as New Zealand and Australia where the utilities have
traditionally been developed and owned by government. The company had operated under a
commercialised regime all its life; there was therefore, no need for corporatisation or
commercialisation prior to privatisation, as was the case in New Zealand and several Sub-Saharan
African countries. All that was needed to change ownership from public to private was sale of the
shares to private interests. No new legislation was needed and therefore the Jamaican Government
did not require from Parliament any mandate to divest the company.
Private Franchised Monopoly and the Failure of Public Utility Commission Style Regulation
In the period coming up to the nationalisation of the telephone and electric
utilities, both
enterprises had refused to increase investments to meet the national development objectives and this
became a critical issue to the government of the newly independent country that was trying to force
the pace of economic development6.
With the introduction of the JPUC Act, the existing system of common law and licence was replaced
for the first time with a legislative regulatory framework. JPUC employed a permanent secretariat
and the Commission’s board members held their appointment on the basis of tenure. This facilitated
the development of independence, institutional memory and addressed some of the problems of
information asymmetry. The 25-year licence awarded by JPUC in 1976 incorporated provision for
renewal and this provided a more stable investment environment for the company7. A new public
200
policy enshrined in the licences was that of increased local ownership. The Jamaican public was to
hold a larger portion of the company’s shares, with limits placed on the holdings of any one
individual. Minimum rates of return as practiced under the Rate Board system of rate determination
was replaced by “fair rate of return” on the utilities rate base.
Considerable regulatory independence was provided for in the new regulatory structure. JPUC was
created as a statutory authority; however its decision was subject to judicial review by the Supreme
Courts. It was given a very wide mandate. In respect of the electricity industry both the Act and the
licence gave the Commission decision-making powers over the equity structure of the utility.
Additionally, the Commission had to satisfy itself that the ownership structure was in the best
interest of Jamaicans. The new licence also made provisions for the regulated utility to carry out
programmes of development as prescribed in the licence and such further programmes as might be
agreed with the regulator within the existing rate structure. Expansion programmes, therefore, had
to be developed in consultation with the Commission. Service standards and utility rates were
determined by the Commission and were to provide the company with a reasonable rate of return
on equity after meeting all expenses, including depreciation and debt charges and earn a limited
return on equity. The Commission also had regulatory powers over construction standards as they
related to new facilities, as well as over the system of regulatory accounts to be maintained by the
utilities. These were to be in the form prescribed by the Federal Power Commission of the USA.
This provision was to address the problem where the company was able to increase its rate base by
revaluation of its assets in 1951 and 1961 in order to increase its returns8. The Commission carried
regulatory powers over disputes between the utility and its consumers and finally it was a statutory
requirement to ensure that due regard was given to the needs of the country for expanded electric
services.
These were radical and fundamental new regulatory innovations, especially for a country embarking
on self-government for the first time. Swaby (1981)9 stated that the new regulatory structure:
“indicated that the government wished to attempt to exercise regulatory control over
the privately owned utilities in a manner based on the North American precedents,
combining the powers of the Federal Power Commission and the Securities and
Exchange Commission in a manner subject to interpretation against a large body of
law and practice built up in the USA”.
201
The Commission operated until 1975. During its life the major issue, faced was applications for rate
increases. The JPUC Act required that ratemaking be handled through quasi-judicial public hearings,
which were not a feature of the English and Commonwealth jurisprudence. The company was also
required to provide development and financing plans as part of its submission for a rate increase.
At the time of granting of the licence in June 1966, the Stone and Webster Company was the holder
of the largest block of shares. The Board of JPSCo was also made up of mostly non-resident
directors. JPSCo until then was a subsidiary of the company registered in Canada. Under the new
licence, the company not only had to seek local registration, the majority of its Board of Directors
also had to be Jamaican citizens as part of a public policy of localisation of management.
The first application to the JPUC was made in 1969; however, the application was postponed after a
preliminary hearing. The application was resubmitted in 1970 and the hearing lasted to the end of
1970 when the application for rate increase was rejected. A second rate application was made in
1972 and on this occasion, JPSCo was successful in obtaining a 25% rate increase, the first rate
increase for several years. The duration of the proceedings, however, went beyond the anticipated
six months stated in the law. With the sharp rise in oil prices in the early 1970s JPSCo was allowed
changes to the fuel adjustment clause, and this change provided for amendment to the method of
calculation .As a result the 60-day period for adjustment was reduced to a 30-day period. This was
followed by a third rate increase application in 1974 when a 39% rise was approved. Between 1970
and 1975 the cost of electricity went up from 1.48 Jamaican cents per kWh to 6.70 cents per kWh
for residential consumers. In 1975 industrial users paid 4.5 cents per kWh.
The introduction of the JPUC brought into play the American style public hearing procedures.
Learned Counsels represented both JPSCo and the Secretariat of the Commission. One of the
immediate consequences was an adversarial relationship with sharp areas of conflicts between the
utilities and JPUC. Conflicts developed with respect to the definition of the rate base, the accounting
procedures adopted, the determination of cost of capital and the procurement practices of the two
utility companies.
202
Whereas, the US utilities under a rate of return price fixing regime, were required to show their
assets at original costs, ignoring all revaluation – JPSCo’s management carried out periodic
revaluation at current replacement cost and this allowed the firm to inflate the value of its equity to
support higher dividend payments10. The Secretariat levelled charges against JPSCo’s management of
improper asset accounting, the use of transfer pricing, and the practice of waiting for demand to
clearly establish itself11. The result of this quasi-judicial process was that Jamaica’s utility regulation
came to be characterised by lengthy and costly rate hearings12.
The World Bank in its review of the regime came to the conclusion that American style regulation
was inappropriate for Jamaica and that the system had proved to be a failure. The Bank (1997)13
stated that:
“Jamaica lacked the other institutions needed to make such a system workable.
Whereas the US system has a variety of constraints on regulatory discretion
(including well-developed rules of administrative process and constitutional
protection of property rights, Jamaica had no checks and balances on Commission
decision, the result was the price controls became progressively more punitive to the
point that in 1975 Jamaica’s largest telecommunications operator was relieved to sell
its assets to the government”.
The shareholders of JPSCo were also more than willing to sell their shares to the state when
government decided in 1974 to acquire the outstanding stocks remaining in private hands. This
development more or less marked an act of regulatory expropriation. Regulation of the vertically
integrated utility in Jamaica has therefore proven to be a difficult exercise.
State Ownership and Government Failure
Under the socialist ideology, several arguments were advanced in support of state ownership of
utilities in Jamaica. Firstly, industries such as electric utilities, which are natural monopolies having
opportunities for economies of scale should be operated by one vertically integrated firm. As these
enterprises formed the “commanding heights” of the economy it was considered preferable by the
government to have the state own and operate such firms, because of the inability of private firms to
address the wider social and development objectives of society. The energy sector,
telecommunications, water and airports were considered essential services and could not, it was
claimed, be left to the “hidden hands” of the market. Secondly, the small size of Jamaica’s domestic
203
capital market and the reluctance of domestic investors to invest in low yield long gestation
investment it was argued led inevitably to foreign direct control. Thirdly, the agenda of the
transnationally owned utility and the objectives of the state often came into sharp conflict as the
transnational objectives frequently lacked developmental vision.
Jones (1974)14 states that:
“Whenever the state involves itself in the economy, it immediately signals some
motivation to engage in activities of production, accumulation and the creation or
maintenance of conditions for these processes. The general motivation is always
related to strategy, to structure and to some potential political conflict. As such the
motivation has an ideological content ------socialist oriented regimes of the Commonwealth Caribbean (e.g. Jamaica and
Guyana) rationalise the public enterprise strategy on the basis of their socio-political
ideological outlook”.
Brown (1981)15 also points out that one argument in favour of public ownership is that:
“it reflects in large measure the greater responsibility for accelerating economic
development which was assumed by the state as a consequence of political
independence”.
Although Jamaica in the 1960s had imported the 1940 British Labour administration policy of public
ownership of economic activities, the policy was never pursued on ideological grounds until the
1970s. The replacement of private ownership with public ownership, especially of the monopoly
utilities came to be seen as the most effective policy to secure the efficient operation of the industry,
whilst at the same time serving the public interest. As with the UK experiences no formula was
developed to resolve the inherent conflict of the two objectives.
With state ownership of both utilities, the decision was taken in 1975 to transfer the powers of
regulation from the JPUC to the portfolio minister, the reasoning being that there was no
requirement for an independent government appointed agency to regulate the operations of a
publicly owned company. Although the JPUC Act remained on the books up to the passing of the
multi-sector regulatory Act in 1995, no Commissioners were appointed and hence the Commission
became dormant. During the period 1975 to 1995 the powers of regulation remained under direct
control of the utilities sector minister. At one and the same time, this Minister was responsible for
204
protecting investors’ interests, carrying out shareholder monitoring, whilst controlling monopoly
power of the utility and protecting consumers’ interests. The only independent source of addressing
consumers’ concerns against the bureaucracy of the state and the monopoly of utility was through
the Office of the Utilities Ombudsman and his authority was limited to conciliation, as he had no
powers over the utilities or the sector minister.
With the change to public ownership a new all-inland licence was issued to the company in 1975.
This new licence provided for the portfolio minister with responsibility for the utility to be the
industry regulator. A number of other changes to the licence were also made. The provision
regarding shares being made available to citizens of Jamaica was omitted. An 8% return on rate
base, which was part of a 1974 amendment, was subsequently eliminated. In fact all the provisions
relating to rate base and rate of return were removed and prices were no longer subjected to any
limitations. Despite the removal of the 8% rule, determination of rates, however, came to be guided
by the 8% return per annum on revalued plant rule, being a World Bank condition on its loans to
JPSCo.
The licence granted after 1975, therefore, moved away from the American rate base system of rate
making through public hearings, and gave considerable flexibility and authority to the portfolio
minister. Although the Ministry of Public Utilities established an Advisory and Monitoring Unit to
review and advice on utility tariffs and investment, the basic issue of regulation during this period
was that consumers became concerned that their interest was no longer taken into consideration,
and this triggered regular protests. The Minister came to be seen to protect the interest of the
investor at the expense of the consumers.
Over the period the utilities were never allowed to operate as autonomous commercial firms and
effectively became an arm of government itself, with high levels of ministerial intervention in
pricing, investments, employment, wage determination and procurement. In much the same way as
in the UK in the post-war years, the long-term commercial interest of the enterprises was
subordinated for broader short-term political and macro-economic objectives.
State ownership of the electric utility and ministerial regulation between 1974 and 1992, when the
decision was taken to liberalise the new
generation market, did not resolve the problem of
205
providing efficient utility services. The loss making, which resulted was not only due to subsidy
pricing policies but also to poor management, poor maintenance of the system and dis-investment.
The pricing policy of the Peoples National Party (PNP) administration which required the utility to
meet only operating cost and contribute 30% of its capital needs, effectively reflected crosssubsidisation by tax payers. In 1994 the PNP administration had also introduced a direct subsidy to
JPSCo to ease the burden of the rapid escalation in oil prices. Even with the subsidy, the 1974 price
increases of 39% were followed by a 42% increase in 197616.
In order to cope with the adverse financial impact from the rapid escalation in oil prices on JPSCo,
as well as the negative impact from the decline in the exchange rate, electricity prices had been
separated into a fuel clause element and a rate base element, with automatic monthly adjustments for
the fuel clause being passed on to consumers in their monthly bills. With the automatic increases
from the fuel clause consumers experienced sharp increases in electricity tariffs in Jamaican dollars.
The industry’s monopoly in product market facilitated trade union opportunism in that the unions
were able to secure wage increases, which could not be justified, by increases in productivity. For
example, in 1976 wage increases awarded to JSPCo workers averaged 71%, whilst that of the urban
transportation utility averaged 90%17. The size of the fiscal deficit and the foreign exchange burden
at the time was such that they served to freeze major upgrading and expansion plans of the utilities.
The JLP administration, which managed the economy for most of the 1980s, reversed the subsidy
pricing policy under pressure from the multilateral lending agencies with a new policy, which
required the utility, and other public enterprises to earn 8% real return. The 8% return came to form
one of the World Bank loan conditions in the structural adjustment programme. With the sharp
devaluation of the Jamaican dollar from J$1.78 to J$5.13 against the United States dollar in 1984,
electricity prices experienced two further sharp increases, first by 40% in January 1984 and then 54%
in May that same year18.
While theoretical reasons have been advanced to support the case for privatisation more than
anything else, however, it has been the large sums of capital needed to meet the expansion and
upgrading of the utilities and infrastructure services, telecommunications, water, airports, and
electricity, which forced the Jamaican bureaucracy to accept deregulation and privatisation, rather
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than any belief in the inherent superiority of private capital and competitive markets. The decision to
encourage the introduction of IPPs into the generation sector in the early 1990s was not based on a
policy intended to provide for increased competition in the industry, but was based primarily on the
need to secure capital for the development of the generation sector.
State capitalism had provided major economic power to a group who in the past were
disenfranchised from the “halls of power” and this group (chairmen and board members of the
public enterprises) was not predisposed to see this power disappear without offering strong
resistance. Some of the managers had come to reward themselves with compensation packages,
which at times became an embarrassment to the administration in power as was the case reported at
the National Investment Bank of Jamaica in 2001 and which led to the resignation of two senior
public sector managers.
Utility capacity studies in early 1990 indicated that US$257 million of capital expenditure was needed
over the five year period up to 1997. This investment was needed to meet increased demand and
replacement of obsolete plant, as well as to ensure that the utilities did not become bottlenecks in
the system, constraining future economic growth. The total estimated new capacity projected for
the 10-year period to 2000 was 1052 MW. In the first five years the projection was for 440 MW of
which 230 MW or 50% was to meet requirements for replacements of old and obsolete plants. The
overall capital projection was US$1 billion for the 10 years19. With serious restrictions imposed by
the Treasury and with a very weak financial structure, the option of the utilities competing in the
private commercial markets for capital was not a practical one.
Industry Structure and Deregulation of Generation
At the time deregulation was considered in 1990, the industry consisted of a single vertically
integrated publicly owned utility, with 443 MW of installed capacity. Approximately, 68% was steam
powered; 25% diesel/gas turbines and 5% (24 MW) hydro. Peak demand in 1990 was 325 MW,
giving a reserve margin of 35%.
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Private operators, mainly the mining and sugar companies generated electricity for their use and had
an additional installed capacity of 265 MW20. Small exchanges of power took place between JPSCo
and those private operators, which were connected to the national grid. Generation accounted for
approximately 70 per cent of system costs. Fuel in turn accounted for 60 per cent of generation
cost. Fuel was supplied to JPSCo under the San José Accord, a bilateral agreement with Mexico and
Venezuela. This Accord provided Jamaica trading concessions on its fuel oil purchases and the
agreement has been in place since the end of the 1970s.
The transmission system consisted in 1990 of 170 circuit miles (272 km) of 138 Kv lines and 445
circuit miles (712 km) of 69 Kv lines, while the primary distribution system consisted of 7000 miles
(11200 km) of distribution lines. The Rural Electrification Programme Company Limited (REP)
provided subsidised distribution and connection to rural areas and formed part of a programme
introduced in the late 1960s to increase the percentage share of homes then connected to the
electricity system from 20 per cent to more socially accepted levels.
There were 305000 connected customers in 1990, increasing from 116, 000 in 1970. For the year
1990, the level of access to electricity was estimated at 50%. In the 1970s the historical growth in
demand was a modest 3.3%, followed by 2.2% to year 1985 and increasing to 6.1% by 199021.
For successive governments, prices were held down for most of the period between 1965 and 1974,
(a period of private ownership). JPSCo was therefore, forced to operate at a loss. Although intended
as part of a policy to redistribute income to the poor, the main beneficiaries from this cross-subsidy
policy were the middle classes, the main users of electricity. For the period 1974 to 1980 the period
of public monopoly ownership, the financial performance of JPSCo was inconsistent, with profits in
some years and losses in other years (majority years being loss). JPSCo, with its inadequate source of
income had to rely on the government for almost all its capital needs during this period. With
inadequate funds and under-maintenance in the system, efficiency fell sharply and was accompanied
by load shedding, frequent intermittent power outages and irregular voltages. Systems losses varied
between 17% and 22% and over 50% of this was non-technical loss.
There were no increases in the tariff over the period 1985 to 1990 apart from the fuel clause
adjustment, with the result that the financial performance of JPSCo up to 1990 continued to present
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a poor state of affairs. A 37% increase in the basic tariff was granted in 1990 with the result that
prices came to reflect long run marginal cost. The previous tariff setting system, which was based
on declining block structure did not reflect marginal cost and was abandoned following a major
tariff review in 1989. Electricity prices for residential householders in 1990, after the increases,
amounted to just under US¢14/kWh with bulk electricity rates of US¢7.5/kWh.
At the time of the first utility privatisation, that of telecommunications in 1985, no consideration
was given to new entrants and the introduction of competitive forces in the industry. In fact,
government went on to vertically integrate the two telecommunications operating companies; one in
international telecommunications and the other serving the domestic market, as a single monopoly,
in addition to providing the new owners with a 49-year exclusive license. This decision and the
method of privatisation came in for considerable criticism from the public and the media in the
period 1989-91, with the result that government was forced to give more attention to the industry
structure when the state came to consider the electric utility deregulation and privatisation.
Changes in Jamaica’s electricity sector commenced with deregulation in early 1992 with the World
Bank energy sector deregulation and privatisation project. Entry into the generation sector was
relaxed, allowing for the initial purchase of 130 MW of new generating capacity from independently
owned private power producers. The bilateral funding agencies, World Bank, Inter-American
Development Bank and International Finance Corporation provided over US$200 million in the
form of credit to facilitate entry by the IPPs. The introduction of IPPs into the system followed a
course of competitive bids and 20-year “take and pay” contracts, backed by Government of Jamaica
guarantees. In effect at this point Jamaica had graduated from the single state owned franchised
monopoly to the single purchaser phase.
Three plants came on stream between 1993 and 1996: a twenty year contract for a US$103 million
72 MW medium speed diesel plant next door to the main JPSCo power station at Old Harbour, and
developed by Jamaica Energy Partners Ltd., (JEP) a locally registered company of Wartsila Power
Development Inc.; a twenty-year contract for US$144 million 60 MW low speed diesel plant at
Rockfort, Kingston and owned by Jamaica Private Power Ltd., (JPPL) a joint venture of Mohawk
Power Company, International Energy Finance Ltd and US Energy Corporation and a 3-year
contract for a US$30 million 42 MW turbine plant at Bogue, St. James developed by Kenetech
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Energy System. Inc22. Kenetech later sold 99% of its investments to another US based investor
Quixx Corporation. All the contracts went to overseas syndicates; mostly American interests. The
large auto-generators such as the sugar factories and the cement plant that produced supplies in
excess of their own demand were also allowed for the first time to sell bulk electricity to JPSCo.
Problems with the Introduction of the Single Purchaser Model
Following the decision to encourage private financing of electric supply in order to relieve the
government of the burden of financing the sector’s needs, a number of measures were taken to
remove some of the barriers which were seen to inhibit the flow of private capital into the sector.
The most critical of the problems were insufficient security to safeguard foreign direct investments,
the limited size of the domestic market and the absence of a legislative framework for the evaluation
of projects and the independent regulation of the sector. The introduction of the Office of Utilities
Authority Act (OUR) in 1995 and the decision of the Government to provide sovereign guarantees
were two of such measures.
In developing the IPP transaction the government faced four key issues. First, there was a
requirement to delegate authority to provide for a non-resident private commercial entity to make
withdrawals from a World Bank loan to the letter of credit bank. Government eventually concluded
that granting the authority was the only practical solution.
Second, there was the requirement of guaranteeing JPSCo’s payment obligations to the IPP and the
continuance of the guarantee after privatisation. Government found it easy to accept the guarantee
requirement up to the time of privatisation of JPSCo. The period after privatisation presented a
problem. Eventually it was agreed that a clause providing indemnification be included in any future
sale agreement of JPSCo as a counter-guarantee of these obligations.
Third, the requirement was raised for the project company to pay penalties to JSPCo for failure to
supply at a rate equivalent to the economic cost of the loss of capacity. Such a clause made the cost
of the likely penalty to be applied several times the value of the IPP. This requirement was
eliminated as none of the bidders were prepared to undertake this obligation.
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The fourth issue was the question of the price to be included in the PPA for the sale of bulk power
from the IPPs to JSPCo. In the determination of bulk electricity tariff, comparisons have been made
by the Jamaican bureaucrats between JPSCo’s cost of production for generation voltage and the
charges required for bulk electricity from the IPPs. The JPPL’s plant at Rockfort charged US
cents7.10/kWh, whilst the charge for JEP’s Old Harbour plant was US¢8.35/kWh, compared to
JPSC’s, reported generation production cost of US¢7.3/kWh23. The government failed to take into
account that JPSCo’s average unit cost, as stated are sunk cost with arbitrary method of cost
allocation, reflecting historical accounting, with almost fully depreciated assets and with highly
subsidised capital. It was, therefore, incorrect to adopt this method of accounting as the basis for
cost comparison.
Government also provided financial guarantees to JPSCo’s debts, most of which were obtained at
non-commercial rates. In fact JPSCo financing, most of which came from multilateral sources,
carried much lower rates than commercial market rates, at the time varying between 2% and 7%.
Debt finance, which was used to finance the greater portion of IPP investments, varied at the time
between 11% and 13% in the private financial market.
Government financing through the
multilateral agencies to JPSCo was provided at interest costed at 6% to 8%, a difference of
approximately 5% from the IPP debt financing cost. Over the years JPSCo had declared virtually no
dividend to the state; therefore, its equity cost (a subsidy) was zero, whereas the equity returns,
taking Jamaica’s risk profile would have been of the order of 25%. When Jamaica went to the private
bond market in the latter part of the 1990s it had to pay interest rates of 11% to 13%.
It is the unit cost of production that JPSCo would have incurred for the same generation capacity at
commercial market rates of interest that is relevant - the utilities avoided cost. In the USA the
standard procedure then adopted for such evaluation has been that of long run average cost of new
investment of capacity as would be constituted by the utility. The general principle applied by the
US
Federal Energy Regulatory Commissions in 1980 required that the price the utility was
obligated to buy from a qualifying power production facility should reflect the
utility’s avoided
costs (the avoided cost principle) by purchasing from an independent supplier, compared to the best
alternative available24. This determines the reservation price. In the USA the prospective utility
tenders for a solicitation for a fixed amount of additional capacity and selects a winner through
competitive bidding or negotiates with a pre-qualified pool of applicants.
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It was also incorrect to make the comparison with the World Bank’s 8% return target rate. The fixed
assets would more or less approximate to both the debt and equity employed by the IPP and
because the cost of debt obtained by government for JPSCo is usually lower than the cost of equity,
the return on net fixed assets will be significantly less than on equity returns.
The purchase price of electricity from the IPPs reflected two-part pricing, consisting of a base
element and an energy element with an indexation formula for the base element. The base element
allows for “cost pass-through” as cost increases or cost savings which are beyond the direct control
of the power supplier, such as fuel-oil is automatically passed to JPSCo. At the same time, the
energy element ensures that additional cost resulting from poor performances of the IPPs is not
passed to the buyer and in turn the seller takes the benefit of good performances. The net effect is
that there is no specific rate of return guaranteed; the level of efficiency therefore ultimately
determines the supplier’s rate of return over a given period. This, however, was projected to be
between 20% and 25% on equity, which were typical for private power projects in the 1990s.
Private power purchase through a long-term contract resulted in competition for new capacity and
allowed the Jamaican system to take the first step to a more competitive industry structure.
Government, however, could have allowed for common carrier status to the vertically integrated
JPSCo transmission and distribution lines so that large-end users could procure electricity from any
willing seller. This bypass policy would have provided increased levels of competition that JPSCo
would have had to contend with in the market. Although the electricity network remains a natural
monopoly, transportation of transmission and distribution voltages could have been opened to the
market through non-discriminatory interconnection policies.
The Case for Unbundling the Utility
In 1991 Coopers and Lybrand of the UK was contracted to consider the most appropriate structure
for privatisation of JPSCo and the most appropriate regulatory arrangements for the industry. The
consultant’s recommendations, which were presented in 1993, called for unbundling of the industry
into a fully competitive generation sector and a regulated transmission and distribution monopoly.
Coopers and Lybrand (1993) 25 recommendations were stated as follows:
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“Following from our considerations, analysis and discussion with JPSCo, we have
concluded that a single operating company (Genco) should be formed which would
own all JPSCo’s existing generating plant, together with the proposed gas turbine at
Hunts Bay, with the remaining assets grouped as a Transmission and Distribution
Company (T&D), responsible for transmission and distribution and supply on an all
Island basis”.
Coopers and Lybrand’s rationale for the vertical separation of generation without horizontal
unbundling of generation was that liberalisation and entry into the generation market would have
been sufficient to eliminate the future monopoly of a privatised Genco, as their projection was that
70% of the generation upon liberalisation would be supplied by IPPs and co-generators and this
would be so even if the incumbent Genco was allowed to bid for incremental capacity.
The creation of a single Genco it was argued would have created less disturbance to the status quo,
would have resulted in less transaction cost, minimised the level of disruption to management, (a
group which was fearful of the privatisation), would have provided for a more financially attractive
package to take to the market and would have preserved economies of scale in the industry. These
advantages, it was argued outweighed the disadvantage of market power from a single enterprise.
The longer term advantages of a competitive structure and the overall benefit to consumers would
appear not to be seen to have been important. What was more important was to offer an attractive
package to the capital market and placate the management group.
The consultants also came to the conclusion that there were no overriding reasons for the T&D
Company to own any generating capacity. Additionally, a new multi-sector utilities regulatory
agency, the Office of Utility Regulation, was to be established by statute, headed by a single Director
General (DGUR), modelled on the UK system, and effectively rejecting the multi-member
commission structure of the previous US style Public Utilities Commission. In order to ensure the
independence of the DGUR, he was to be appointed by the Prime Minister, after consultation with
the leader of the opposition, and the grounds for dismissal were to be strictly limited to
misbehaviour or incompetence. As well as the legislation to establish the OUR, specific industry
legislation was also prescribed for the electricity and other utility sectors to empower the DGUR to
licence and fully regulate each sector and in so doing remove all requirements for ministerial
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licencing and regulation and reduce the role of ministerial intervention to one of establishing broad
industry policies.
The relationship between the Genco and the T&D was to be on the basis of long-term power
purchase contracts with the T&D acting as the single purchaser of all generated electricity from the
new Genco and the independent IPPs, with dispatching on economic merit order basis.
Additionally, the T&D was also to be responsible for retailing electricity to final consumers. The
new legislation was to provide for competitive procurement and independent evaluation of new
capacity.
A transitional period, up to the point of privatisation was to be provided during which the Genco
and the T&D Company would be established as separate and independent businesses, to facilitate
shadow operation prior to privatisation. External separation and vesting was targeted for April 1994.
In this new structure the role of the DGUR would be to approve least cost development plans by
the T&D Company, approve the PPAs between the T&D and the generating companies, monitor
the competitive bidding process, monitor tariff levels in the PPAs, establish tariff for retail electricity
and monitor and enforce licence conditions.
JPSCo, however, engaged its own consultant; Price Waterhouse Utility Economics and Financial
Consultants Group (PW) of Washington, USA in the 1990s to comment on the most appropriate
industry structure for its privatisation. Price Waterhouse conclusions were even more conservative
than those of Coopers and Lybrand. In their conclusion PwC (1994) 26 stated:
“based on our experience with other electric systems throughout the world, as well as
the literature on this subject, the market for generation in Jamaica seems too thin to
develop competition that would eliminate the need for regulation. Furthermore,
numerous studies have shown that the minimum unit size for achieving economies
of scale in electricity generation is approximately 400 MW. If a number of firms were
to compete to generate electricity, the market share would be small and the resulting
sizes will be well below the optimal size -------- Competitive generation is not an
attractive alternative for Jamaica”.
Price Waterhouse not only argued for sale of shares of the existing JPSCo to a broad based public,
with a single strategic investor being offered 51% of JPSCo’s shares, they also argued for continued
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government equity participation, the justification for the latter being that the Government’s equity
ownership would ensure that the Government’s social objectives were met. Privatisation of the
single integrated JPSCo, it was further argued would be politically and administratively easier as this
simplified the sale transaction; planning synergies in the present integrated structure would be lost
from unbundling, and the privatisation process would progress with much difficulty if the sale was
for more than one unit. PW in its analysis, however, was clearly using electricity economics which
were inappropriate and which was derived from conditions of the 1980s. They had clearly ignored
the development of combined cycle gas turbine technology, which was well on the way to changing
the economics of electricity generation markets. Reference to US experience was clearly irrelevant
to Jamaica.
With strong persuasion from the management and bureaucrats of the various ministries at a Policy
Retreat on 26th January 1995, the policy makers rejected the Coopers & Lybrand’s recommendations
and abandoned the strategy of restructuring before privatisation. The positions advanced by the
bureaucrats were that the precedent set for electricity industry restructuring was derived from
developed countries with large energy markets where economies of scale opportunities may have
been exhausted and that competition offered efficiency gains that more than offset the benefits of
the loss of internalisation and additional transaction cost.
These gains were said not to be
appropriate for small developing countries with small utility markets of less than 1000 MW. The
arguments developed by Price Waterhouse, that of reduction in benefits from economies of scale,
attractiveness of the integrated utility to credible foreign investors, ease of privatisation and
increased risks from a vertically separated transmission and distribution company, were also
presented at the retreat by the bureaucrats and especially by the JSPCo’s management to support the
case for retention of the single vertically integrated company.
The transition from public to private operation was also stated as requiring higher rates of return
and it was not seen that the elimination of X-inefficiency from full private operation of generation
would deliver higher rates of efficiency; therefore, the consumer it was argued would be required to
pay higher prices for electricity.
The higher electricity rates it was claimed would result in
government having to face political problems with consumers. The proceeds, which the state would
attract from the sale, it was further argued, would not be related to a fair value of the assets. Instead,
the price would be based on the investor’s perception of the net cash flow from the acquisition of
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the business. A faster sales process was also claimed to be possible with sale of the integrated
company to a single strategic investor. Government would, therefore, have difficulty explaining the
lower expected sales proceeds to the electorate.
Further the bureaucrats argued that the small (T&D) Company would not be attractive to potential
investors and that even if divestment of the unbundled generation system were to take place, the
T&D company should not be precluded from future entry to the generation market as it could face
future problems should the privately held companies fail to honour their contracts. Alternatively, it
was argued that the privately held generating companies could collude to hold the T&D Company to
ransom and endanger the security of the system. There is no empirical evidence to support these
claims. In deciding on the appropriate privatisation policies, government was led into accepting the
short-term consideration of maximisation of sales price over an industry structure that would have
delivered competitive prices and ultimately superior services to the consumer over the long term.
The Coopers & Lybrand consultants at the time were not by any means suggesting radical industry
restructuring as was the earlier case of the UK. It merely sought to introduce a supportive
environment for entry competition at the generation end and provide for open access to the
transmission and distribution network, with the ultimate beneficiaries being the consumers of
electricity. The arguments provided by the bureaucrats were not based on any rigorous economic
analysis or empirical evidence and in the main were based on historical notions of electricity
economics.
It is a well-known position that bureaucrats and the managers of public enterprises who derive their
power and prestige from state capitalism will resist efforts to unbundle industries and to expose
them to competition. Given the opportunity, they will argue either for the enterprise to continue as a
state monopoly or be transferred as a private monopoly. It was these same arguments that the utility
managers had earlier offered and which led to the privatisation of the telecommunications industry
as a single vertically integrated monopoly at undeniable future cost to the Jamaican consumer. The
British utility managers had posted the same dire warnings about unbundling the England and Wales
electricity system and the economic consequences of doing so during the UK electricity industry
privatisation27. The only additional twist in Jamaica’s case was that the small market size of the
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Jamaican economy was put forward to strengthen the claim against unbundling of the vertically
integrated system.
Competition is the best-known mechanism to maximise consumer benefits and limit monopoly
power. The effects of the new technologies are not only evident in telecommunications; they are
also equally applicable to the electricity utility. Bolivia, with a lower per capita income of under
US$800 (1996), compared to Jamaica at US$2000 and with a small electricity market of the same size
as Jamaica, 600 MW, demonstrated in 1995 that a small system can be restructured into several
competing firms, without any significant increased costs from loss of scale economies or punitive
levels of transaction costs (see page 292)
Should the publicly integrated utility be allowed to enter the market for generation, there would be
the need for an independent authority to consider and evaluate bids for new capacity. There was the
suggestion that the repowering of the Old Harbour and the Hunts Bay plants should also take place
under the framework of competitive bids with JPSCo bidding against the competition. JPSCo
management at the time did not welcome this suggestion and opposed competitive tendering for the
repowering work.
If JPSCo were to be involved in generation, IPPs would always be suspicious of the integrated
utility’s administration of the power purchase contract. There would be too much scope for
opportunistic and discriminatory behaviour on the part of JPSCo. Integration also complicates
regulation. If JPSCo were to bid for new generating capacity the question, as to how this would be
financed would continue to arise. Most of the soft loan financing opportunities from the World
Bank and the Inter-American Development Bank then was being sharply reduced. The policies of
the two Banks at the time also called for generation activities to be financed from the private capital
market and both agencies for the first time were in the process of structuring new approaches so
that private companies could benefit directly from their financing windows.
Once generation is separated from the T&D Company then the question of the system security
arises. It is inevitable that the total size of the system to be operated and maintained by the IPPs will
have to be such that it provides reserve margins for emergencies and peak demand, as well as
providing for load balancing. The question of security of the system can be addressed in the power
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purchase contracts. In fact there may be some advantage in having several operators at the
generation end, so that in an instances of industrial dispute in one of the IPPs, Island wide
disruption of electricity may be averted
The argument that splitting up the vertically integrated electric utility might involve sacrificing
economies of scale, and that separation would bring increased production and transaction costs
which will offset the gains of competition, is at best of dubious merit, since the existing structure
itself resulted from political and administrative arrangements. The policy makers failed to have taken
their decision based on the options, which from a long-term perspective would have delivered the
lowest possible prices, relieve the state of the responsibility for financing or guaranteeing the risks
associated with investment in the generation sector and provide consumers with reliable electricity
supply.
The decision reflected a classic public choice theory case which points out that beneficiary interest
groups in capturing the decision making process and being rational utility maximisers will ensure
that their special interest prevails over the wider public interests. None of the lessons from the
operation of the privately owned and integrated electric utility especially as a foreign owned entity in
the period between 1960 and 1974 seemed to have been taken into consideration by the decision
makers. The transfer pricing practices, the conflicts which developed between national objectives
and the transnational’s objectives and the abuse of market power on the part of the foreign owned
utility operator, seemed to have been buried with history. The decision also reflected the mistrust of
the socialist disposed bureaucrats with competition and the hidden hands of the market. The
bureaucrats continued to feel that they could succeed where the market has failed.
Much of JPSCo’s life after 1950 as an integrated monopoly has been one of inefficient operation,
prolonged periods of power outages and under-maintenance.
JPSCo performances in terms of
transmission and distribution line losses at levels varying between 17% to 20% for most of the
1970s and 1980s, compares very unfavourable, to figures of under 10 to 12% in developed
countries28. These losses result from illegal connection, unmetered use, theft and inefficient
transmission and distribution systems and can be eliminated by good management practices. In fact
line losses increased from 13 per cent in the early 1970s to 20 percent in the late 1980s and declined
to 17% by 1996.
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Jamaica’s electricity tariff and line losses compare very unfavourably with that of Bolivia in 1996.
The average retail tariff in 1996 was US¢4.50/kWh in Trinidad and Tobago, an oil producing
country29 and under US¢7.0 kWh in Bolivia. Line losses in Bolivia were also under 12%. Failure to
effect separation is, therefore, another Jamaican case of “missed opportunity” of introducing an
appropriate industry structure in the Island’s utilities before privatisation.
Aborted Privatisation
In 1995 government, eventually through the direction of the National Investment Bank of Jamaica
(NIBJ) and a specifically created Enterprise Team, initiated privatisation of the vertically integrated
JPSCo. An internal NIBJ memorandum stated that the objectives of privatization were as follows:
a)
Sell at least 51 per cent of the company’s ordinary shares;
b)
Relieve the budget from the financial burden of upgrading and financing expansion
of services;
c)
Give the enterprise a higher capability to attract domestic and foreign direct
investment;
d)
Optimise returns from the sale;
e)
Secure the lowest possible price for electricity to consumers, consistent with available
commercial financing and the establishment of the systems reliability at its
economically efficient level.
As some of these objectives are conflicting, it was inevitable that the final decision-making would be
fraught with difficulties. Advertisements for pre-qualification were issued nationally and
internationally week July 23-29, 1995. Fourteen submissions were received. Subsequent to the
receipt of these proposals the Divestiture Enterprise Team which was established by government
pre-qualified five applicants. On 6th November 1995, all five applicants were supplied with copies of
the “Request for Proposal” with a deadline for 5th January 1996 for their responses. Applicants were
advised that the selection of the successful bid was to be based on attractiveness of the offer price
for the shares, the attractiveness of the development plan, the level of commitment to Jamaica and
commitment to establishing linkages with local industries, the technical and managerial competence
of the bidder to operate electric utility, and the level of technology transfer and local staff
development anticipated. At the close on 5th January 1996 two proposals were received from
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Houston Industries Energy and Southern Electric International both of the USA. Some of the prequalification conditions acted as a disincentive to attracting investors.
During the negotiating process, which followed, government had sought to obtain a counterguarantee relating to the JPSCo’s loans, already guaranteed by the state in relation to the
Independent Power Producers projects. Both bidders failed to provide the appropriate counterguarantees. In subsequent negotiations, both bidders stated that a counter-guarantee by their
principals carried a price, which would either have to be passed through the rate to consumers, or
deducted from the offer price. This requirement was seen by government to be a “deal breaker” as
future IPP investors would also be seeking government guarantees. Without this guarantee the
government would continue to bear much of the risks in investments, which it held no equity
interest. The problem, however, is that the highly leveraged financing regime of the IPPs makes
these guarantees essential. Both proposals failed to provide the parent cross-guarantee to the
government’s counter-guarantees, which were provided to the existing IPP operators. Without a
parent cross-guarantee or the government counter-guarantee it would have been difficult to ensure
competitive procurement of new capacity.
Both bidders’ offer price for the shares was also lower than the government’s reserve price. While
the sale of a fully integrated company may seem comparatively more attractive in terms of
privatisation income to government, there is always complication in determining the value of the
business. Investors are not interested in the current sunk cost of JPSCo. It will be the net present
value of the future cash flows over a given period, which will determine sale price. Other methods
have been used, including using the net asset value and the operating cash flow, together with an
assessment of the market, as well as asset value, the profits earned and the stock market share value.
In the case of utilities, there are three critical elements to be addressed: the expected price, future
demand and the scale of future investment. Market valuation is difficult to achieve in developing
countries like Jamaica where capital markets are thin.30 Investors are interested in the potential
income-earning capacity of an ongoing business and not in the asset values on its own or either in
historical cost valuation or physical valuation. Valuation becomes more important when there is only
one bidder. In a competitive bid situation, the bid price is the market price.
220
The price of the shares based on discounted value rests on a whole range of assumptions, most
critical of which are the rate of growth of future demand and future tariff obtainable from the utility
regulatory agency. The bidders would have pursued a worst-case scenario, contemplating higher
risks in the analysis than the assessment by the government bureaucrats, particularly where there is a
questionable track record of the regulatory system. These problems have always raised controversy
in the privatisation valuation process in developing countries.
Investors in utilities in developing countries prefer to lock in a specific rate of return into the
bidding contract in order to reduce exposure to risk of regulatory expropriation31. Of the three
options available for tariff regulation; rate of return regulation, price cap and negotiated contract,
price-cap regulation is being used more and more as the preferred option. Coopers and Lybrand also
recommended price cap regulation, as this is seen to be less costly and less time-consuming to
operationalize and has the added advantage in providing incentives for more efficiency when
compared to rate or return regulation. A major advantage of price regulation from the point of view
of the regulatory process is that the JPSCo price would no longer be related to its internal cost of
production. There would, therefore be less opportunity of JPSCo as a vertical integrated utility to
influence its prices.
Although the recommendation for a new regulatory structure was advanced as early as 1991, up to
1995 government had failed to establish an independent regulatory regime for the utilities to replace
the Public Utilities Commission. It even appeared at one stage that the emergence of a transparent
independent regulator was doubtful and in absence of regulation by contract, investors would
inevitably perceive a high risk in a situation where the new regulatory regime carried no track record.
In such an environment investors will evaluate income flows under the worst-case scenario and this
in turn is likely to give a lower offer price than the government’s reserve price. A regulatory regime,
which provides for a high level of ministerial and political intervention, will also raise concerns about
regulatory expropriation. Where the regulatory capacity is inadequate or subject to political
interference, a negotiated concession (regulation by contract) may be used, which is likely to be
more attractive to the foreign investor, than relying on legislation and discretionary decision of a
new regulator.
221
In the end government opted for a multi-sector industry regulator, to regulate the utilities and
transport sectors. The structure also provided for a single regulatory decision maker, a Director
General. Jamaica and the Caribbean in their adoption of multi-sector agencies have been pioneers
from a developing country perspective. Unlike the UK, where each industry carried its own
regulator, Jamaica has opted for a single regulatory agency to regulate the utilities and transport
industries. Jamaica chose the multi-sector structure as it was seen to be less costly to operate,
provides for more consistency in the regulatory decisions, and ensures that a certain distance is
developed between the regulatory agency and individual sector ministries. Five or six industry
regulators in a small country with a small market would have resulted in a doubling of regulatory
costs on the consumers and would have presented serious funding and staffing problems, most
likely leading to an unsustainable regulatory regime. Up-to 2000, government had failed to introduce
the electricity industry specific regulatory legislation, which was needed to provide the detailed
regulatory framework for the industry32.
The uncertainties as to the regulatory regime would have influenced the price
proposals of the
bidders. The price proposals of both bidders failed to reflect appreciable improvements (lower tariff)
on the existing JPSCo rates to consumers. This was to be expected in the short term, as JPSCo
costs of capital as shown earlier are heavily subsidised. One would, however, expect that Xefficiency would follow from private management and superior technology which, in the long run,
should allow the privatised utility to obtain higher levels of output from existing resources and
hence lower long-run average cost.
Government was faced with the decision to accept one of the bids or to reject both offers. There
was never any enthusiasm on the part of utility managers and the ministry bureaucrats to transfer
JPSCo to the private sector. State capitalism is still preferred by many from this group, because it
offers them greater economic power and personal benefits than would accrue to them under private
ownership and control. The short timetable which was set for the privatisation also appeared to have
been inadequate to resolve the complex issues thrown up in the negotiations.
Public Ownership with Internal Management Performance Contract
222
Government eventually announced in Parliament on 22nd October 1995 that it had decided not to
pursue privatisation of JPSCo at that time. The reasons given were that the offer price was too low;
the bidders proposed retail prices were too high, that the bidders were not willing to relieve the
government of its IPP counter-guarantee commitments and unacceptable dividend policy. The
privatisation was, therefore, aborted. JPSCo was to continue to operate as a vertically integrated
utility, except that the relationship with government was to be put on more “arms-length” basis.
Government also announced that it would seek to re-list JPSCo shares on the stock market. If this
were to have taken place there would have had to be at least a 20 per cent floatation of the state’s
equity on the Kingston Stock Market. JPSCo historical financial performance, combined with
continued state control, certainly would not have provided the appropriate incentives for a
successful floatation of 20% of the company’s equity.
The Prime Minister, in making the statement, did not elaborate on the new procedures for a more
commercial and “arms length” relationship. Interestingly, in 1960 when the railway was made a
statutory body, a commercial and “arms length” relationship was also mandated by the
administration of the day. This did not, however, prevent political and bureaucratic intervention. In
subsequent years, political intervention in railway management eventually led to the collapse of the
Jamaica Railway Corporation, and in the early 1980s it ceased to operate.
The application of private sector operating principles with the chief executive officer having an
“arms length” relationship through an internal management performance contract with the sector
minister, which became the main instrument for governance up to then, full privatisation has been
the model introduced in New Zealand for many social and economic services and is the approach
Jamaica adopted immediately after the decision was taken not to go the route of immediate
privatisation. Jamaica’s situation, however, differs from New Zealand’s; therefore the same results
could not have been expected in Jamaica. Historically, New Zealand operated many of its utilities as
departmental enterprises, i.e. they were not separated from the central civil service. Jamaica moved
to the joint stock company form as the institutional structure for several of the utilities from as early
as the 1960s. This institutional structure provides the opportunity for the greatest managerial
autonomy for the management of state enterprise. Government in theory could also have exposed
JPSCo to the threat of takeover and possible liquidation as it did with the Jamaica Omnibus Service
223
Company Limited in the latter part of the 1980s33 so as to put more pressure on management for
efficiency enhancing behaviour.
Internal management performance contract sets out a procedure for establishing clearly specified
objectives for the chief executive officer and the public corporation on the one hand and the
objectives of sector minister and the ministry on the other hand. The management performance
agreement provided for an average tariff mechanism to hold tariff constant in US dollar terms for
three years to 31 March 2000, explicit financial and non-financial targets, regulated operating and
performance standards and for JPSCo to operate in a manner to enable it to finance its expansion
overtime and pay annual dividends to its shareholders mainly government.
Unless these are legislated with checks and balances there will be violation of these agreements if left
solely to ministerial discretion. As JPSCo continued to fall under the Public Accounts Act detailed
intervention in management by the Ministry of Finance, was still likely and there was no suggestion
at the time to exempt JPSCo from this Act. An internal performance contract was eventually
signed in 1997; however, the contracting party was not the sector ministry but the privatisation
agency, the National Investment Bank of Jamaica. This arrangement had a significant advantage
over the traditional structure in that it provided for a neutral and more credible agent to monitor the
agreement.
Kerf and Smith (1996)34, however, stated that:
“in response to growing appreciation of the problems of the traditional public
enterprise model, many governments in Africa and elsewhere have attempted to
improve the performance of state-owned enterprises through performance contracts
with public managers or corporation. These reforms have attempted to give greater
emphasis to commercial principles and provide a degree of insulation from shortterm political influences -----------.
In the vast majority of cases, however, performance agreements have had a poor
record of sustaining reforms. In Ghana and Senegal for example, government
reneged on their commitments to, inter alia, increase tariffs and promptly pay bills of
government and other state owned enterprise.
Problems stem from the conflicting objectives, which the government is tempted to
pursue under these arrangements. There is a growing realisation that combining
within government the roles of owner, regulator and operator is a poor institutional
structure for attempting to operate on commercial principles. In most cases,
224
governments will find it difficult to implement the range of internal and external
disciplines on which the effectiveness of corporate entity depends”.
Experiences of the UK in respect of commercialisation, “arms length” relationships and
performance related operation in the 1960s also proved to be a failure. There are two major
problems with performance contracts. Firstly, the workers are major players in the efficiency matrix
and they are not bound by the agreements as shown by Kerf and Smith. Secondly, it is difficult to
enforce the obligations, especially those commitments made by government because the framework
agreement or memorandum of understanding is not usually a legally binding document.
The UK and other countries’ attempt to develop an institutional framework, which allowed for
progressive improvements in efficiency by state capitalism more than anything else, resulted in a
failure to provide strong incentives to the industry and their boards. At another level, it has been a
failure to recognise the fundamental principal and agent problem in public enterprises. It is unlikely
therefore, that Jamaica would have found the formula to resolve these problems any more than the
UK over the long run or for that matter find a solution that would reduce the temptation to use
utilities to serve political and macro-economic ends.
Jamaica incorrectly concluded that a competitive industry structure is inappropriate as the efficiencyenhancing route for their traditional natural monopolies and went ahead and invited private capital
including foreign investors into the vertically and horizontally integrated electric utility. Foreign
investors are unlikely to be attracted as minority partners without a management contract;
government was forced to reconsider the policy of public floatation of 20% of JPSCo’s equity
through the Kingston Stock Market. In pursuing this strategy government made the same mistake as
it did in privatising the telecommunications utility as a vertically and horizontally integrated
company. This once again will be a missed opportunity35 as once private capital comes on board;
government will not be able to take up any future opportunity for unbundling which will surely
present itself, either from technological or commercial developments, without transgressing on
property rights. In which case government will either have to pay compensation or face expensive
litigation without any guarantee that its position will prevail in the end36.
225
Most of the improvements to the reliability of supply over the five-year period up to 1998/99 seem
to have emerged as a result of the new capacity brought on by the IPPs. In this period, JPSCo’s
power purchases from private generators, IPPs and auto-generators increased from less than 1.0%
to over 30%. If this trend continues with the introduction of additional IPPs and power purchase
agreements for the 160 MW of additional capacity needed over the medium term, nearly 50% of
capacity will in future come from private sources and Jamaica will have locked itself into an industry
structure of that of a single purchaser model which offers the least efficiency enhancing
opportunities and the least opportunity to move to a competitive electricity market. The cost of
capital from IPP investment will in itself also lead to higher cost of electricity when compared to the
lower cost of capital JPSCo obtains from the softer multilateral financial market. IPP type capital
investment carries very little risk to the investor and Jamaican taxpayers carry this risk through
guarantees, which the government has had to provide and will have to continue to provide to attract
such investments.
Table 11 shows that sales growth in GWh has averaged about 6.5% per annum, over the period
1994/95 to 1998/99. For the four year period up to 1997/98 JPSCo showed after tax losses. The
year 1998/99, however, showed a profit of US$12.1m, with a return on equity of 13.6% and return
on assets of 10%. The most significant point, however, has been the dramatic increase in bulk power
purchases after 1994/95, increasing from 4% to 30% in 1997/98 and declining to 23% in 1998/99.
Without the introduction of the IPPs, Jamaica’s state owned electric utility would not have been able
to meet the increased demand and mostly likely its financial position would have shown an
unhealthier picture during this period.
226
Table 11
Pre and Post-Management Performance Contract Results
Jamaica, JPSCo
Annual Revenues and Profitability
Pre-Post Performance Contract
After Tax Profit
(US$)
Tax Paid (US$)
Dividend Paid
(US$
Return on Equity
Return on Asset
Sales Turnover
(US$)
Sales GWh
Proportion of
Bulk Electricity
Supplies from
IPPs (%)
Percentage
increase (GWh)
Post-Performance
Contract
1997/98
1998/99
1994/95
1995/96
1996/97
-7,013
-1,602
-45,537
-56,823
12,122
5.1
4.6
4.7
4.7
4.6
-1.6%
0.9%
228,797,146
-0.2%
0.9%
241,648,452
-19.0%
-7.1%
287,531,307
-33.1%
-9.4%
292,814,893
13.6%
10.1%
311,260,230
1,890
2,037
2,147
2,334
2,476
4%
20%
24%
30%
23%
7.4
5.4
8.7
6.1
Source: Jamaica Public Service Company
Table 12 shows that the number of employees in the generation sector fell from 390 to 310 over the
period, a decline of 20%. At the same time the number of employees in distribution and sales
remained relatively stable over the pre and post-performance management contract periods. The
decline in the number of employees in generation commenced during the pre-management
performance contract period, therefore, the improvement could not be attributable to the effect of
the internal management performance contract. Total employees declined from 2113 in 1994/95 to
2039 in 1996/97. The numbers of employees for each of the two post-management performance
contract years were higher than the year preceding the introduction of the contract. Productivity
(kWh generated per employee) commenced its decline also in the pre-performance management
contract period and continued up to the first year of the changes. However, in the second year, the
productivity level was higher than the level achieved in 1994/95. Customers per employee at the
same time showed progressive improvements over the five-year period, rising from 176 to 216.
227
Table 12
Jamaica – JPSCo
Number of Employees/Labour Productivity and Number of Customers
Pre-Performance Contract
1994/95 1995/96 1996/97
Post-Performance
Contract
1997/98
1998/99
Features
Number of Employees in
Generation and Transmission
Number of Employees in
Distribution and Sales of JPS
Employees in Central
Administration of JPS
Total number of Employees
KWh Generated per Employee
Number of Customers
Customers per Employee
Proportion of Household
Connected Access (%)
Amount of Bulk Electricity
bought from IPPs (GWh)
Total Number of Household
Connected
390
357
324
321
310
1,254
1.281
1,268
1,298
1,251
469
477
447
475
514
2,113
1,064,28
9
371,755
176
53%
2,085
941,263
2,039
951,077
2,094
940.537
2,075
1,102,598
390,367
187
55%
404,984
199
57%
430,364
206
60%
448,783
216
62%
693
851
645
488
85
330,162
346,823
360,067
381,817
398,387
Source: Jamaica Public Service Company
As shown in Table 13, technical and non-technical losses from transmission and distribution showed
marginal improvements in the two post-performance management contract years, however, at
16.9% in 1998/99, it was still above the 13% level recorded in the 1970s. Technical line losses were
relatively stable, varying from 10.5% to 11%, while non-technical losses varied from 6.4% to 6.7%.
Access to electricity also showed progressive increases over the five-year period, increasing from
53% to 62%. Access to electricity is very high compared to developing country standards and while
it is much higher than most African countries and comparable to South Africa it is substantially
below the level of Mauritius, another small island economy. Jamaica with a population of 2.6 million
has 465,000 connected customers in 2000 and this is marginally more than the 450,000 connected in
Tanzania with a population of 31 million and is significantly more than the 140,000 connected
customers in Uganda with population of 18 million.
228
Table 13
Energy Losses – Jamaica - JPSCo
Pre-Performance Contract
Losses (%)
94/95
95/96
96/87
1.8
9.1
10.9
10.9
6.7
97/98
1.8
8.8
10.6
106
6.5
98/99
1.8
8.7
10.5
10.5
6.4
17.3
16.0
17.6
17.1
16.9
Transmission Loss (%)
Distribution Loss (%)
TOTAL (%)
Technical Losses (%)
Non-Technical Loss (%)
TOTAL (%)
Post-Performance
Contract
Note 1 – Breakdown of energy losses prior to 1996/97 is not available.
Source: Jamaica Public Service Company
JPSCo’s retail sales price was US10.5 ¢/kWh for industrial users in 1994/95 and 13.6 cents for
household consumers as shown in Table 14. Retail prices for both household and industrial
consumers declined in 1995/96, respectively reflecting a decline of 11% and 12%. In 1996/97
prices reflected marginal increases.
Thereafter prices remained relatively stable for the two
management contract years. When one accounts for inflation, consumers seem to have benefited
from the relatively stable prices over the five-year period.
JPSCo’s bulk purchase prices from the IPPs was US 9.2¢/kWh in 1995/96, rising to 11 cents in
1996/97 before falling to 9 cents in the two post-management contract years. These changes,
however, seem to have reflected the cost escalators in the power purchase agreements. JPSCo’s
overall retail prices are very high when taken at the international level. JPSCo and the IPPs, however,
produce almost all their generated power from imported fuel oil and do not have access to natural
gas and significant levels of hydro-sources, which have been important benefits to the Bolivian and
Trinidad and Tobago systems. It would appear that once a decision is taken to privatise, significant
forces come in to play leading to appreciable improvements in performance. Once the pressures to
privatise are relaxed, the forces for improved performances also seem to weaken.
229
Table 14
JAMAICA - JPSCo
Pre and Post Performance Management Contract Results
Bulk Power and Industrial and Consumer Retail Prices
Electricity
US Cents per KWh
JPSCO Retail Prices
Average Bulk Power
Price JPS buys from
IPPs US Cent Per
KWh
Pre-Performance Contract
1995/96
1996/97
Indu House
Indus House
strial hold
trial
hold
9.2
12.1
8.0
10.6
11.0
13.6
Pre-Performance Contract
1997/98
1998/99
Indus House
Indus House
trial
hold
trial
hold
10.2
9.0
13.7
10.4
13.1
9.0
Source: Jamaica Public Service Company
Between 1999 and early 2001, the performance of the electricity supply system in Jamaica fell off
sharply with recurrence of regular outages, irregular voltages and load shedding. Some of the
problems were due to lower levels of equipment availability from the IPPs and problems with the
aged plants due for replacement
Government also was unable to provide the foreign currency to meet the cost of the high
maintenance bills, fund the cost of imported fuel and meet the investment needs so that adequate
reserve margins could be provided at all time in the system. JPSCo also failed to provide the
indicative investment plans to the Office of Utility Regulation to form the basis of competitive
procurement of new capacity. The need for additional capacity to come on stream in the period
1998 to 2002 (over and above the capacity of the three IPPs which came on stream between 1994
and 1996) was forecasted in the 1990 World Bank ESMAP Report. That report emphasised the fact
that 50% of the additional capacity would have been needed to replace the older units which were
expensive to operate and prone to sudden failure. Apart from two co-generators, which provided
additional capacity of 23 MW during 1998, no new capacity was expected to come on stream before
2003. The result was that reserve margins fell to 21%. With prolonged outages at one of the large
power plants at Hunts Bay and major plant failure of one of the IPP Company, the reserve margin
230
was insufficient to avoid the recurrence of major island wide power outages in the later part of 2000
and throughout 2001.
JPSCo’s Annual Report showed that the company’s financial performance declined further in
1999/2000. Operating and maintenance cost increased by 36%, mainly from a 90% increase in oil
prices and 28% increase in the price of IPP purchased power, whilst operating revenues increased by
only 28%. Operating revenues increased mainly from 48% increase in fuel component of the tariff.
The non-fuel component remained unchanged from 19991.
Demand on the system in 2000 was 521 MW, increasing at 6.5% per annum. Installed capacity was
656 MW of which 25% was provided by four private companies, JEP providing 74.2 MW; JPPC
providing 61.3 MW; Jamalcoa providing 11.1 MW and Jamaica Boilers, another 12.1 MW to make a
total of 158.6 MW.
The country’s financial situation, especially the country’s balance of payment also continued to
deteriorate with the result that the budget for the financial year 2000/01 had to be financed by
privatisation proceeds amounting to J$7.2 billion. JPSCo was the last major enterprise that could
make a substantial privatisation income contribution.
The Final Act of Privatisation
With over US$300 million of additional investment for the 160 MW which was needed by 2003 and
the investments for technical improvements in plant efficiency, the Prime Minister was left with no
option but to offer the company for sale (despite vigorous opposition by the Minister of Mining an
Energy) for a second time to a strategic investor and to abandon the previous policy of floatation of
20% of the company’s shares on the local stock exchange. The recommendation to privatise came
from a recommendation made by Planning Institute of Jamaica one of the agencies falling under the
control of Ministry of Finance. In selling JPSCo the opportunity was provided to reduce the public
debt by US$ 120 million.
Because of the pressure to obtain additional resources Government again dismissed the
restructuring and unbundling option, despite the interest shown by some of the potential investors
231
in acquiring only the generation facilities on the grounds that the sale of the vertically integrated
JPSCo was the best option to ensure even development of the power sector and adequate and
reliable power supply of electricity at all times. This decision again reflected a distrust of the market
and a failure to take the consumers interest fully into account.
Instead of competitive international tender (this was ruled out because of the time constraints) the
Government settled for what was in effect a negotiated sale. Invitations for Expression of Interest
were sent to four selected companies including the two previously short-listed for the first
privatisation exercise. Houston Energy one of the original bidders declared that they were no longer
interested in the Caribbean. Two of the others receiving the Expression of Interest, Duke Power
and Enron Corporation expressed interest only in the generation facilities and this is one of the new
realities of the global electricity industry, specialisation of investment. Government was, therefore,
left to negotiate with one company, Southern Energy Inc of Atlanta Georgia. On the 21 September
2000 the Prime Minister announced that Government had signed a Memorandum of Understanding
for the sale of majority interest in the restructured JPSCo.
The final state sale agreement in March 2001 provided for the following:
•
Southern Electric’s Subsidiary, Mirant JPSCo (Barbados) SRL to acquire 80% of JPSCo’s
shares for US$201 million and assume US$120 of debt, with the government to provide
counter guarantee for this debt for a further 12 months after closing.
•
Southern to commit itself to US$500 million investments in additional generating capacity
over a period of 10 years after closing.
•
Government’s 19.9% remaining equity interest to be entitled to annual dividends. (The
public already held 0.01% for JPSCo’s shares).
•
Mirant, to make available up to 5% of its voting stocks to employees and to commence
action to list the company on the local stock exchange immediately after the end of the first
three years.
•
Government of Jamaica to assume responsibility for J$9.9 billion of JPSCo’s debt of which
J$4.7 is directly on the Government books and the balance of J$5.2 on JPSCo’s books but
guaranteed by Government at average interest rate of 6.6%.
232
•
The company to be relieved from GCT tax (value added tax) and import duties on capital
expenditure for the first 10 years.
•
Government’s 20% shareholding to give entitlement to three Board members and the
remaining six Board members to come from the strategic investor.
•
In the first three years neither party to be allowed to transfer any portion of its equity and
for the Government to be allowed to assume operation of the company if the buyer ceases
to operate all or any substantial portion of the electricity system and to have rights of first
refusal in respect of Mirant shares: of the 242 properties owned by JPSCo, only 106 to form
apart of the deal. There was to be no redundancy in the short-term.
•
A new 20 year exclusive all island electricity licence was awarded in March 2001 by
Government, essentially under the terms of the then existing licence, except that the terms
do not provide for any guaranteed rate of return. In respect of the right to additional
generation capacity, exclusivity was provided for up to 3 years after closing, thereafter (1
April 2004) new generation capacity is to be acquired on the basis of competitive tendering.
The new owners are permitted to continue with the vertically integrated structure with
exclusive rights to the transmission, distribution and all of the retail market.
•
The company under the licence conditions, gave an undertaking not to abuse its position of
market power and for tariff to be fixed by the OUR. The two part pricing structure was to
remain, with the non-fuel component subject to review every five years and the fuel
component to be recalculated each month based on an indexation formula.
JPSCo, under oversight of the electricity regulator is to be responsible for the management of the
tendering process for all new generation capacity, despite the fact that the company is expected to be
one of the bidders. In proceeding to sell JPSCo as a vertically integrated company, Government
choose the single buyer trading arrangement and replaced a public monopoly with a private
monopoly as all consumers were denied choice of supply. The opportunity to graduate to a
wholesale electricity market phase at a later date was precluded under the 20-year exclusive franchise
granted to the foreign operator for the transmission and distribution market segments and failure to
liberalise the large consumer market segment. At least Government should have insisted upon
operational unbundling of the generation business. Additionally the transmission business should
have included a condition mandating accounting ring fencing from generation and distribution, with
233
a separate transmission licence from the distribution and retail supply licence. The granting of a
three-year exclusivity for new generation capacity also served to delay the introduction of
competition for new capacity. The decisions in fact were made in the interest of short-term gains;
providing revenues to the Treasury against the longer-term interest of a competitive market
delivering more efficient services to consumers. Had the Government provided for liberalisation of
the large consumer market after a transitional period of say five years (possibly users with demand
exceeding 1 MW) and for equal and non- discriminatory access to the network natural monopoly
segment of the industry the longer term consumers’ interest would have been better served. In this
way, an element of competition could have been introduced at the retail end of the market during
the life of the current franchise. Government’s failure to consider the consumers’ interest went
further by removing the actions and behaviour of JPSCo from the jurisdiction of Fair Trading
Competition Commission.
There is no guarantee that the level of investments stated will be made. It has been found from
international experiences that it is extremely difficult to enforce capital programmes in the postprivatisation periods. The commitment not to abuse market power should have been accompanied
by specific anticompetitive rules to determine abuse, with penalties specified for such abusive
conduct. The British experience has shown that one of the critical problems in a post-privatisation
period has been that of abuse of market power. Government could easily have provided for bypass
of the transmission and distribution network operator, so that large industrial and commercial
consumers could go direct to the generators and buy bulk electricity.
The responsibilities for developing the least cost plan, as well as the forecasting of future demand
should have been returned to the ministry with portfolio responsibility for energy. Additionally,
management of the procurement process should have been assigned to a neutral agency, such as the
National Investment Bank of Jamaica where such expertise lie and not to JPSCo or the OUR. The
role of the Office of Utility Regulation should have been limited to the establishment and regulation
of the procurement proceedures. The OUR’s role should have been restricted more to the
traditional regulatory responsibility that of addressing the problem of market power and not in the
selection of entrants to the market.
234
There is a conflict of interest on the part of JPSCo’s involvement in managing the procurement
process. Competitive tendering can contribute to a reduction in the cost of generation, when
compared to bilateral negotiations between the incumbent single buyer and a selected company and
also offers the attraction of rapid entry without the need for drastic restructuring of the industry.
What Jamaica has done is to graft the procurement process onto the vertically integrated and
unreformed electricity supply industry. The disadvantage of this arrangement is considerable. JPSCo
has a strong incentive and opportunity to select bids from its own generation facilities or bias the
competition to favour its own interests. It has been well known that incumbent monopoly utility
operators are loath to face the test of competition, which may reveal the high cost of current
operations, and are well placed to disfavour attempts at entry by loading unreasonable conditions on
entrants.
Even if JPSCo genuinely opens up to competition in the bulk electricity market and if corruption
can be prevented from biasing the outcome the new entrant will be selling to a monopsonist and will
need strong assurances against ex post opportunism. Jamaica experienced these problems with Cable
and Wireless during the liberalisation of the telephone market in the 1990s. It is unlikely JPSCo will
behave any different from Cable and Wireless in accommodating the opening of the market for bulk
power. In adopting these arrangements the Government has placed considerable regulatory
responsibilities on the embryonic regulatory agency and missed an oppertunity of using competition
to reduce the regulatory burden.
Summary and Conclusion
In the period up to 1963, the industry structure consisted of several small privately owned systems,
each company operating in a prescribed franchise area and with relatively little government
regulation. Between 1923 and 1966, JPSCo, the company based originally in Kingston the capital
city, acquired all the other privately operated electricity systems other than the self-generators. In
1966 JPSCo came to acquire a licence for the entire island and at that point operated as a vertically
and horizontally franchised monopoly for the entire country.
Private ownership came to an end in 1974 when the government nationalised the company with the
Government taking ownership of 99% of the company’s stock. The Jamaican experience shows
235
that even under the Phase One or franchised monopoly stage of development, institutional changes
continued to take place. Ownership of the integrated monopoly electricity utility over the period of
the early 19970s changed from private monopoly to public monopoly. Direct interventionist
ministerial management gave way to a more autonomous relationship in the form of internal
performance management contract in the 1995. The regulatory regime first changed from rate
boards to a public utility commission in 1965, followed by a further change to ministerial regulation
in 1975. Ministerial regulation lasted up to 2001 despite the introduction of the Office of Utility
Regulation in 1995. The role of the Office during this period was purely advisory.
The single integrated franchised monopoly phase came to an end shortly after 1993, following
government’s decision to liberalise the generation market and to allow independent power producers
into the generation market segment. With the entry of the first IPPs into the market after 1994, the
vertically integrated JPSCo came to operate as the sole purchasing agent for bulk electricity. Jamaica
then entered the second phase of development that of the purchasing agent phase. The regulatory
regime experienced its fourth period of change. New legislation was introduced in 1995 establishing
a multi-sector regulator, headed by a single Director General outside the hierarchical structure of the
sector ministry.
In 1998, the regulatory portfolio was transferred from the utilities sector minister; the Minister of
Public Utilities and Transport to the Minister of Industry and Technology. The result of this change
was that both competition regulation and utility industry regulation came under one ministerial
portfolio. The three utilities, covering water, electricity and telecommunications were assigned to
separate portfolio ministers. In order to give the new regulator powers over
electricity and the
other utility industries, the OUR Act was further amended in early 2000. Amongst a number of
changes made to the Act were legal recognition of the new reporting relationship, which was
administratively established in 1998, and extension of the regulatory remit of the OUR to cover the
utility service providers which were in existence prior to the Act, such as electricity and water.
JPSCo continued to operate as a vertically integrated state owned enterprise with monopoly over
the transmission and distribution market. Although the generation market has seen new entrants,
and although the new capacity which will be needed to come on stream over the next six years will
most likely be IPPs, JPSCo as a vertically integrated privately owned firm ( after 2001) will continue
236
to maintain monopsony power over the bulk electricity purchases and monopoly over distribution
and retail supply.
In 1996 the Jamaican Government discontinued its official credit relationship with the IMF after 20
years of stabilisation and structural agreements. With the departure of the IMF, the external pressure
to privatise was removed and as a result government has been slow in completing the rest of the
privatisation and public enterprise reform programme and seems to have drifted back to favour the
strategic development role of public enterprises. Government has had to inject huge amounts of
public funds to prop up Air Jamaica, a public/private sector joint venture, with the justification of
maintaining a national airline. The national budget, therefore, continued to face pressure from the
competing demands of education, security and health on the one side and the financial demands of
continued state involvement in utilities and transport operations on the other side.
The decision to eventually privatise JPSCo in 2001 was forced on the government from financial
circumstances, despite the fact that a policy of privatisation had been announced from the early
1990s. In privatising JPSCo as a vertically and horizontally integrated enterprise, Jamaica has
exchanged a public monopoly for a private monopoly, accompanied by public regulation at a time
when many developing countries have been looking at the introduction of increased competition in
the wholesale bulk electricity and retail sectors of the market.
The decision not to privatise JPSCo in the form of a disintegrated set of businesses is another case
of missed opportunity to secure a competitive industry structure following upon privatisation and
will prove to be a costly decision to the detriment of the Jamaica consumers. It will be more
difficult also to regulate the vertically integrated private utility and extremely difficult to unbundle in
future. In adopting what is essentially a purchasing agent model, where the vertically integrated
incumbent electric utility operates as the a sole purchaser of bulk power and as a supply monopolist
over the transmission, distribution and supply system, Jamaica seems to have opted for the least
efficient of the new industry structures that have been developing in the electricity industry since the
late 1980s.
Whilst in the early 1990s, it was questionable whether a small electricity market under 1000 MW
could be effectively unbundled to allow for an increased competitive structure this was certainly not
237
the case in 2001. Small markets such as Bolivia, El Salvador and Panama have since 1995
successfully unbundled their systems and in so doing have provided for a more competitive
framework, without experiencing any serious cost penalties in the initial years.
In contrast to Jamaica, the very small Uganda system in 2000 decided to place the emphasis on
competition in electricity supply to promote efficiencies. Uganda Electricity Board (UEB) Owens
Fall generating facilities have been vertically unbundled and offered for concessioning through two
separate power purchase agreements. The new Bujangali hydro-plant (under construction) is being
carried out also under separate IPP/PPA arrangements. Transmission has been separated out as the
single buyer, initially to remain under public ownership. New transmission capacity, however, is to
be developed, owned and operated by the private sector. UEB’s distribution business has been
vertically unbundled into a single distribution company and is to be divested through long-term
concession. The reform plans also call for the liberalisation of the large end user market and for
transmission and distribution to be mandated to provide non-discriminatory and third party access
to the network system.
The total installed capacity of UEB at restructuring was 180 MW, just over 25% of the system size
of JPSCo. The number of connected customers was 148,000, about 25% that of Jamaica and with
70% of these customers located in Kampala and Entebbe area. The bulk of the electricity over 72%
is consumed by 12% of the population. Less than 5% of Uganda’s population of 18 million was
connected to UEB system. Technical and non-technical losses of UEB exceeded 30% of the
electricity billed, collections were received from less than 50% of customers and over 50% of
accounts payable remained due for more than one year38. In its tariff rebalancing exercise, which has
preceded the privatisation, the Ugandan Government increased domestic tariff by 50%.39
Because of the very small system size, Uganda has settled on the single buyer phase with third party
access; however, unlike Jamaica, the vertically integrated UEB has been vertically unbundled into
three companies; generating, transmission and distribution with the generation and distribution
companies to be divested through long-term concession. Six firms have expressed interest in buying
the generating company whilst three firms have expressed interest in the distribution companies.
This demonstrates that international interests also exist for small facilities.
238
Secondly, even if the option is for the integrated utility to operate as the single purchaser, the
legislative framework for competitive procurement of incremental capacity should have been laid
out from 1995. Although a multi-sector regulatory agency was established in 1995, government took
a long time to specify clearly the role of the regulator in regulating the incumbent utility industry
providers of water, telecommunications and electricity. This created a lot of uncertainty and would
have impacted negatively on the first attempt to privatise JPSCo. Potential bidders more likely would
have perceived high regulatory risks in such an environment and hence the reason for the additional
sovereign guarantees sought when the government went out for tenders in the first instance.
Third, the process was too drawn out. This has been a major problem in privatisation in developing
countries. The process of resolving the interest of the contending forces leads to delays and
compromises and very often the optimal solution is rejected at higher cost to the country and
consumers. What was needed for the privatisation exercise was a clearly defined time frame,
certainly with duration of less than ten years. Bolivia for example, established a time frame of 5 years
for the privatisation of the main utilities.
Fourth, internal management performance contracts can be appropriate as a transitional internal
privatisation option to improve the commercial aspects of the enterprise in the period up to
privatisation; it has not proven from experience to be a solution to bring about sustainable longterm improvements. Management performance contracts still leave the problem of investment
financing unresolved. This was certainly the case in Jamaica in 1999 and this is what led to the
forced privatisation transaction.
Fifth, the managers of the enterprise and the public bureaucrats who stand to benefit from the
publicly owned utility will oppose privatisation and competitive market operations. At one point the
bureaucrats argued that while there may be a general case for private ownership and competition in
the utilities, this did not mean that such a framework was appropriate for Jamaica. In effect the
Jamaican situation was being advanced as a special case, which need not conform to the new
developments. The fall off in performance of the system after 1999 showed that it is questionable
whether there is any special case to the new imperatives of the 1990s.
239
Sixth, developing countries like Tanzania and Ghana that are in the process of abandoning state
ownership for private operators (especially foreign) and independent regulation would be well
advised to learn from Jamaica’s experiences of private ownership and regulation of the vertically
integrated monopoly utility in the period prior to 1975. A private monopoly is not an effective
solution to a public monopoly. Private operation also brings with it new tensions and conflicts. The
traditional American approach of a Public Utility Commission with quasi-judicial public hearings
and incorporating rate of return rate base tariff formula has also been shown to be inappropriate for
developing countries where the culture of independent regulation is absent and regulatory
institutional endowment is low.
Finally, developing countries also need to develop better capabilities in the selection of external
consultants to advice on the restructuring and privatisation process. The Jamaican situation shows
that external consultants will invariably opt for recommendations based on the experiences of their
own country, rather than on a systematic assessment of international experiences and what is needed
for the local environment. This was clearly the case of the Price Waterhouse consultancy in 1995.
240
End Notes
1.
Jamaica Public Service Co. Ltd., A History of Electric Power in Jamaica, Kingston
(undated), p.1.
2.
E.C. William, Jamaica Public Service Ltd: A History of Its Origins and Development,
1923-1978, JPSCo (unpublished 1993), p.16.
3.
Raphael A. Swaby, “The Rationale For State Ownership of Public Utilities in Jamaica”,
Social and Economic Studies, UWI, Special Issue, Public Sector in the Commonwealth
Caribbean, Vol. 30, No. 1 (March 1981), p.82.
4.
The telephone utility, which was, incorporated in the 1980s as a private company and which
remained in private hands until 1973 was also regulated by the rate board system.
5.
Pablo Spiller and Cezley Sampson, Regulation, Institutions and Commitment: The
Jamaican Telecommunications Sector, World Bank, Policy Research Working Paper
No.1362 (1994), and p.18.
6.
The Jamaica Telephone Company’s 40-year licence was also due to come to an end in the
period immediately preceding independence in 1962. An interesting development prior to
the expiration of the licence is the “end game” in which the firm and the government
embarked on opportunistic actions to improve their bargaining position in the period
immediately prior to renewal or granting of a new licence. The period of uncertainty was
heightened further as the method of valuation of the company’s assets was not clearly
specified in the licences. The company’s resorted to revaluation of their assets in order to
increase the asset base on which the rate of return was calculated. In the case of JPSCo the
company increased asset valuation by J$4 million, see Swaby, op.cit. p.85.
7.
Jamaica Telephone Company received its licence in 1965; however, this was amended in
1966 to accommodate the JPUC Act.
8.
JPSCo was now required to use book values at original cost and the values were to be at
1953, with additions at cost and with the applicable depreciation rate.
9.
Swaby op.cit. p.86.
10.
L.A. Swaby, “Some Problems of Public Utility Regulation by Statutory Boards: the Jamaican
Omnibus Case ”, Social and Economic Studies , UWI, Vol.23, No. 2 (1974), p.252.
11.
Swaby, op.cit. P.88. Plants were shown not to be taken at the original 1953, (book value) and
assets which were obsolete or written off were still carried in the accounts. JPSCo was
paying Stone and Webster 20% of the cost of the capital project in respect of the Old
Harbour power plant as consulting fees. The Commission’s calculation of the rate base was
significantly less than that claimed by JPSCo. The rate of return on rate base was 8.4%
against the 7.4% submitted in the application and the rate of return on equity was 13.5%.
JPSCo had claimed that they needed 13 to 16% returns on equity.
241
12.
G.E. Mills, “Public Policy and Private Enterprise in Commonwealth Caribbean”, Social and
Economic Studies, UWI, Vol.10, No. 2 (1974), p.231, also 1990, in G.E.Mills ed. A
Reader in Public Policy and Administration , ISER, Mona ,Jamaica , pp. 145-70
13.
World Bank, Development Report – 1997: The State in a Changing World, Oxford
University Press (1997), p.70.
14.
Edwin Jones, “Role of the State in Public Enterprise” Social and Economic Studies,
UWI, Special Issue, Public Sector Issues in Commonwealth Caribbean, Vol.30, No. 1 (March
1981), p.17.
15.
Adlith Brown, “Issues in Public Enterprise” Social and Economic Studies, UWI, Special
Issue, Public Sector Issues in Commonwealth Caribbean, UWI, Vol. 30, No. 1 (March 1981),
p.2.
16.
Adlith Brown and Helen McBain, “The Public Sector in Jamaica”, Social and Economic
Study, UWI, Studies in Caribbean Public Enterprise (1993), Vol 1 , p.101.
17.
Ibid. p.95.
18.
Cezley Sampson, Strategic Marketing Cases: Jamaica Public Service Company,
Kingston, University of the West Indies, Mona Institute of Business (1986), p.20.
19.
Earle Richards, Overview of Private Sector Role in Jamaica Energy/Power Sector,
Jamaica Public Service Company Abstract, (unpublished 1991), p.3.
20.
World Bank, Jamaica Energy Sector, Strategy and Investment Planning Study,
Washington, D.C., ESMAP, Vol. 1, Main Report (August 1992), p.55.
21.
Ibid, p.52.
22.
Basil Sutherland, Financing Jamaica’s Rockfort Independent Power Project: A Review
of Experience for Future Projects, Washington, D.C., World Bank (1998), p.23.
23.
National Investment Bank of Jamaica, Privatisation of JPSCo: Issues Affecting the
Privatisation of JPSCo (unpublished, February 1995), Appendix 1, p.3.
24.
Paul Joskow, “The Evolution of Independent Power Sector and Competitive Procurement
of New Generating Capacity”, Research in Law and Economics (1991), p.70.
25.
Coopers and Lybrand, Jamaica Power Sector Regulatory Framework and Privatisation,
Phase Two Report, Kingston, Jamaica (1993), Section 205.
26.
Price Waterhouse Utility Economics and Financial Consultancy Group, Options for
Privatisation and Regulation of JPSCo, Washington (1994), p.17.
242
27.
Colin Robinson, “Profit Discovery, Rate of Entry: The Case of Electricity” in Regulating
Utilities: Time for a Change, eds., M.E. Beesley, London Institute of Economic Affairs,
Reading, No.44 (1996), p.112.
28.
W. Glen, Private Sector in Electricity in Developing Countries, Supply and Demand,
Washington, DC., International Finance Corporation, Working Paper, No. 15, (1991), p.15.
29.
Jamaica Public Service, Annual Report, 1995-96, Kingston (1996), p.39.
30.
UNCTAD, Design, Implementation and Results of Privatisation Programmes:
Review of National Experiences, New York, United Nations (1994), p.21.
31.
Cable and Wireless purchase of the telecommunications utility is 1985 is a case in point
where the tariff formula is structured around the rate of return and was set at 17.5% to 22%
on revalued assets, after tax.
32.
The Telecommunications industry regulatory legislation was introduced in 2000, finally
setting out the powers of the OUR to regulate the telecommunications sector
33.
Jamaica Omnibus Services Company Ltd., the Kingston urban passenger service provider
was wound up and private providers took over the provision of public passenger services in
Kingston.
34.
Michael Kerf and Warrick Smith, Privatising Africa’s Infrastructure: Promise and
Challenge, Washington, D.C., World Bank Technical Paper, No. 337 (1996), p.5.
35.
Pablo Spiller and Cezley Sampson, “Telecommunications Regulation in Jamaica”, in
Regulations, Institutions and Commitments: Comparative Studies in
Telecommunications, eds., Brian Levy and Pablo Spiller, Cambridge University Press
(1996), p.37.
36.
Government of Jamaica has had to pursue protracted and expensive negotiations with Cable
and Wireless Jamaica Ltd., to terminate the 49-year exclusivity, which apparently was
provided in the 1985 telecommunications licences. This matter was resolved in 2000 when a
more liberalised cellular market regime was agreed upon and additional cellular operators
were allowed to enter the telecommunications market.
37.
JPSCo, Annual Report 1999-2000 (April 2000), p.5.
38.
Uganda Government, Power Sector Restructuring and Privatisation: New Strategic
and Implementation Plan, Uganda (June 1999), p.2.
39.
Uganda increased power tariff by 70% to US 10.8 c/kWh in 2001 as part of preparation for
privatisation. The rates, however, was reduced to 8.5 US 8. 5 c/kWh following from protest
from Parliamentarians. The rate were rebalanced and increased to eliminate cross-subsidies
and government subsidies. Uganda is almost 100% hydro-based.
243
Chapter 6
Radical Restructuring and Privatisation of
Small Electric Utility Market: The Case of Bolivia
Introduction:
Bolivia restructuring of electricity presents a number of interesting developments. Up to 1995, the
World Bank commentators were still expressing reservations as to the efficacy of vertical and
horizontal unbundling of small electricity systems in order to create competition. Writing in the
Banks Occasional Paper series Bacon1 came to the conclusion that:
“even when it is possible to introduce limited competition in generation and achieve
some benefits, the cost of vertical separation may be so high as to offset the gains
from competition”.
Up until 995 unbundling and dis-integration of electricity markets had been confined to systems of
over 3000 MW, with Chile being the smallest market to have unbundled its system.
Besant-Jones2, another Bank commentator further stated that:
establishing of competition in markets such as through a price based pool and the
functioning of autonomous regulatory agencies as with the England and Wales
model has only limited long-term relevance for many developing countries, because
of several reasons”
.
Most importantly, they were seen to be too small, being less than 1000 MW. In addition, to the
small size, the operation of a competitive pool based on spot market pricing was not only seen to be
beyond the capabilities for all but the most advanced developing countries, there was concern that
liberalisation of the generation market would present too high a risk for the attraction of significant
levels of foreign direct investments.
One year after these pronouncements, Bolivia with two vertically integrated small systems, of total
installed capacity of 616 MW, unbundled into 12 operating entities and dispelled the myth that
significant levels of competition was not obtainable in small systems. These views continued to
reflect the economies of scale thesis, which had prevailed during the post war years. These views
244
also came to have had a determining influence when the Jamaican policy makers decided not to
unbundle the Jamaican electricity system (700 MW) in 1995.
In 1990, Bolivia a land locked country was one of Latin American’s poorest countries, with a small
under developed economy; population of 7.5 million people, and land area of 1,098,581 square
kilometres (424164 square miles), about the combined size of France and Spain. Approximately 58%
of the population lives in the rural areas, compared to 9% in Argentina. Native Americans and
people of mixed ancestry make up 78% of the population, compared to less than 10% in Argentina.
Average household consists of 4.36 persons. The largest city La Paz has a population of 1.2 million,
compared to Buenos Aires with 15.0 million.
Total GDP in 1994 was US$6.2 billion. Per capita income was estimated of US$ 920 or 12% of
that of Argentina. This level of development is much closer to that of Sub-Saharan Africa. Between
1987 and 1994 GDP growth rates averaged 4% and this was preceded by a seven-year period where
GDP fell by an annual average of 2.5%. Hyper-inflation measured by the CPI Index reached
28,000% in 1984.3 Bolivia’s economic situation in 1995 was that of a crisis of unprecedented
proportions, brought about by years of socialist economic policies. In 1984 Bolivia defaulted on its
foreign debt obligation.
The restructuring started in 1985 with the Paz Estenssoro administration which came into power
introducing one of the most austere economic shock packages ever implemented in Latin America,
which marked a dramatic shift from stateism to that of a free market economy. The reform
programme combined comprehensive structural reforms with tight monetary and fiscal policies. The
austere economic stabilisation programme quickly brought inflation under control and by 1990 it
was down to 18%, reaching the single digit of 9% by 1995. In 1998 the inflation rate had fallen to
4.0%. Foreign commercial debt, which was US$680 million, had virtually been eliminated.4 Bolivia
presents one of the first truly textbook restructuring programmes to have been introduced in the
Americas in recent years.
The fundamental objective of the reforms, which had started in 1985, was to change the economic
system from a state capitalist economy to a private market economy. The basic principles of the
new policies were that market forces were required to determine prices and there was to be a single
245
real and flexible foreign exchange rate. Most importantly, the government concluded that the
domestic capital market was not only underdeveloped, but also was insufficient, and at best could
only support a small proportion of its citizens with a reasonable standard of living.
Bolivia’s privatisation policies which formed an integral part of the market reforms were therefore
motivated by the desire to attract foreign capital, to expand the level of access to basic utility services
and to develop the country’s rich natural resources, especially that of natural gas. As a landlocked
country it saw the opportunity of exporting electricity and natural gas to its neighbours, especially
Argentina and Brazil, and in so doing, significantly extending its domestic market. Fundamental to
the reform was the entrenchment of property rights in new legislation. A major restructuring of the
public sector and state enterprises was also introduced in 1993, involving the transfer to the private
sector the function as a producer in order for the Government to concentrate on policy formulation,
social development and regulation.
The principal laws, which helped to transform the state enterprises, were the Privatisation,
Capitalisation, Regulatory and Investment Acts. The latter promoted the protection of foreign and
domestic investments. The 1994 Law for sectoral regulation (SIRESE) provided the regulatory
framework for the major utilities, while the electricity, telecommunications, and hydrocarbon laws
dealt with the industry specific structure in each instance. Instead of seeing privatisation as a means
of obtaining additional income for the Treasury as in the case of Argentina and Jamaica, for the
Bolivians, it was a means of attracting new investments to expand accessibility of electricity to the
citizens. A critical component of the institutional reform of the state companies in 1994 was the
establishment of a Ministry of Capitalisation and a privatisation office. Although the IMF, the
World Bank and the Inter-American Development Bank exerted a lot of influence towards these
reforms in the early years of the 1990s, by 1994 they were also promoted with conviction by the new
administration.
Bolivia’s divestiture of state owned utilities and infrastructure firms took three different forms;
capitalisation, outright privatisation though trade sale of shares and concession contracts. Long
distance telecommunications was the first divestiture transaction to come under the capitalisation
programme followed by electricity generation, hydrocarbons, airline and the railways.
246
Airports, water and sewerage were disposed of by the concession route, while electricity
transmission and distribution were fully privatised though the route of trade sale of shares.
Divestiture over the post-1993 period also included enterprises in the manufacturing, mining and
tourism sectors, and the programme was accompanied by major reforms of both the tax system and
the pension system. Outright privatisation of 49 business units over the period 1993-1997 brought
in an income of US$97.5 million, while the capitalisation programme resulted in new equity inflows
of US$1.67 billion by 1998 and covered investments in the hydrocarbons, telecommunication,
electricity and transport sectors.5
The capitalisation process, involved the state entering into partnership with foreign private investors,
the contribution of the state being the value of the enterprise to be privatised and that of the
investor being the capital to be introduced. The formula took the form of sale of new shares to
private investors; equal to 50% of the stock in each enterprise6. This was accompanied by handing
over full management control to the strategic investors with an obligation to use the capital as
investment for the privatised company. Instead of the sales proceeds going to the Treasury, the
funds were ploughed back into the company to improve efficiency and quality of service and to
expand production. Government was relieved of the burden of financing expansion of these capitalintensive industries and at the same time the enterprise on divestiture had access to immediate cash,
without having to take on increased debt portfolio. The remaining 50% of the shares held by the
state were subsequently transferred to privately managed pension funds. The pension fund managers
are required to administer the resources of the fund for the benefit of the population at large 7.
The capitalisation process can be summarised as follows:
(a)
Raising new shares up to 50% of the enterprise stocks were made the subject of public
tender, usually to a strategic investor. The strategic investor is required to enter into a
capitalisation and share subscription agreement between the Generator, the Government
and other investors.
(b)
All the privatisation transaction agreements which the investor is required to sign on taking
ownership are agreed to between the pre-qualified bidders and the government before final
tendering with the result that the final evaluation of the bids are based on only one variable;
the proposed purchase price of the shares.
247
(c)
The valuation of the assets of the enterprises was carried out on the basis of book value.
There is no need for any other valuation, since the bid price is the market price of the assets.
If the market value of the bidders turns out to be higher than the book value this makes it
easier for the government to sell the divestiture programme as a financial success.
(d)
A new company, (or mixed corporation) is then established in which the state and the
workers own all the shares. This is followed by a fresh issue of shares by the new company
to the new investors.
(e)
An offer for international public tender is issued, and this involves bidding for the block of
new shares. The bidder offering the highest sum for the 50% block of shares becomes the
new owner operator. The shareholding is then transferred to the new investor, along with a
contract of administration (management contract). The administration contract is an
agreement between the strategic investor the other shareholders and the government,
granting management control to the strategic investor, subject to certain controls in the
share subscription agreement.
(f)
The shares corresponding to the state’s interest were initially deposited with a Bahamasbased Citi-trust, which acted as a trustee and temporary custodian. The shares were later
transferred to the National Pension Fund.
(g)
The strategic partner then delivers the cash value of the shares purchased to the company
and the money is deposited overseas under strict conditions and only released to meet the
capital expansion programme.
A new company was established in respect of the privatisation of each generation
business and in exchange for buying one share in the new company at a nominal
value of US$20, the workers were offered the option to acquire an additional block
of shares at the original purchase price.8 Upon capitalisation by the new investor, the workers
benefited from real capital gains on their investment.
Bolivia also ensured that both the new legislation and the regulatory framework were in place (like
Argentina) before the implementation of the privatisation process. In the case of electricity sector,
four pieces of legislation central to the divestiture of the electricity industry were introduced and
they were as follows: the 1994 Capitalisation Law, the 1994 Regulatory Framework Law (SERESE)
the 1995 Electricity Law and the 1995 Electricity Regulation.
248
In the development of the electricity framework law, Bolivia made sure that it benefited from the
experiences of other countries that had introduced major restructuring and privatisation of their
electricity industries. In particular extensive studies were made of the restructuring and regulatory
regimes in England and Wales, Chile and Argentina. The guiding principles of the Electricity Laws
are neutrality of the regulatory process, transparency of actions, flexibility of the system, incentives
for efficiency, improvements to product quality and continuity.
The Structure of the Industry before Unbundling
Prior to privatisation of generation in 1995, the electricity sector comprised of Empresa Nacional de
Electricidad S.A. (ENDE), principally a state owned generation and transmission company selling
bulk electricity, although it had some end consumers. In addition to the public electric utility
company there was one privately owned vertically integrated company; Compania Boliviana de
Energia Electrica – (COBEE) as well as a number of private distributors and generators (the latter
were mainly mining companies) supplemented by a number of isolated entities supplying electricity
to rural and isolated areas, unconnected to the main network. These isolated entities used mainly
diesel fuel and were either owned by municipalities or cooperatives.
COBEE, the private company generated 34% of Bolivia’s power in 1992. It held 95% of the shares
in a distribution company; Empresa de Luz Fuerza Electrica de Oruro S.A. (ELFEO), with private
shareholders owning the other 5%, in addition to its vertically integrated La Paz distribution
division. COBEE distributed electricity to 228,000 customers in 1994. It was formed in 1925 and
had its stocks originally quoted on the New York Stock Exchange.9
The company operated 13 power stations, all powered by run of the river hydro-plants on the
Zongo and Migullas rivers, with 142.2 MW capacity, representing 21% of the Siestema
Interconnectodo Nationol (SIN) capacity and generating 774.6 GWh of electricity or 30% of the
SIN’s product . Nine of the plants operated in the La Paz division, having a maximum capacity of
112.5 MW and four with a maximum capacity of 19 MW, serve its Oruro division. Plans were also
in place to increase capacity by 61 MW in the Zongo Valley.10
249
The company also operated transmission lines, linking its plants and distribution facilities. COBEE’s
forty-year licence with La Paz Municipality expired in September 1990, however, a new national
licence was proclaimed by Presidential decree in 1994.
COBEE also purchased substantial
quantities of electricity from ENDE for its distribution subsidiary and in return sold bulk power to
ENDE in the off peak periods.
From the early 1990s until 1994 Leucodia National Corporation (LNC) was the principal
shareholder. In 1994 LNC sold its shareholding to Liberty Power and Congentrix Bolivia Inc; a
wholly owned subsidiary of Congentrix Energy of the USA. In addition to ENDE’s and COBEE’s
distribution interest, there were three other distribution companies operating mainly outside the La
Paz area to make a total of five distribution companies.
ENDE the state owned company was formed in 1962 to rationalise the chaotic situation, which
existed prior to the 1970s. ENDE commenced operation with the 27MW Corani plant. At that time
the electricity sector was in the hands of a number of small municipalities. The formation of ENDE
involved the centralisation of publicly held assets as against nationalisation or the take over of
private assets, which was the experience in other Latin American countries at that time.
It was formed as a limited liability company and not as a statutory corporation, with its shares being
held by the government and two state companies. Government directly held 84.6%, the state mining
company, Corporacion Minera de Bolivia – COMIBOL held 3.9% and the state oil company;
Yacimientos Petroliferos Fiscales Bolivianos (YPFB) held 11.5%. All the shares were transferred
directly to government prior to the formation of the new generation companies. ENDE also owned
2359 km of transmission and sub-transmission lines of 230 KV and 25 kV. Although the company
was not vertically integrated with distribution facilities, it held significant equity interest in Empresa
de Luz y Fuerza Electrica de Cochabamba S.A (ELFEC), Cooperativa Electrica de Sucre S.A
(CESSA) and Servicios Electricos Potosi S.A (SEPSA). Its total revenues in 1994 amounted to US$
72.2m from sales of 1768 GWh of electricity.11
Its mandate was to provide electricity to all the areas, which were not then served by the private
companies. ENDE, unlike many Latin American public enterprises was able to escape political
interference in its management, as the World Bank, which had funded its formation, had imposed a
250
condition that the Bank had to approve the appointment of the Managing Director for the first
fifteen years. It was also able to develop a cadre of professional and efficient managers. The
company carried out substantial investments in its operations in its early years. Financing for most of
its pre-divestiture expansion came from the World Bank and the Inter-American Development Bank
and during this period it had developed a very good credit record.
In 1994 the company’s generation plant capacity was 461.2 MW, and this formed 75.0% of the
interconnected system, as shown in Table 15 and 16. Of the 1687 GWh of electricity generated in
1994, ENDE accounted for 59% compared to COBEE’s 31%.
Table 15
ENDE Generating Plant Capacity – 1994
Company
Corani
(Hydro)
Guaracachi (Thermal)
Valle Hermoso
(Thermal)
Total
Capacity
(kW)
126.0
186.5
148.5
461.2
Production
(GWh)
Projected (MW)
485
765
438
70
110
63
1687
243
Source: Ministry of Capitalisation and Investment,
Generation Briefing Memorandum, Bolivia (1995) p.9
The Government in 1970 significantly reduced ENDE’s debt with the injection of US$107m of
capital.12 The capital was introduced in order to strengthen the company’s balance sheet, following
its financial weakening from the hyper–inflation years. Its average tariff in 1990 was US3.6¢/kWh.
Bolivia’s 1994 per capita consumption of electricity of 320 kWh compared unfavourably with the
regional average of 1100 kWh and the level of access was 64%.13 Its consumption level ranked
among the three lowest in Latin America and the Caribbean. Return on assets in respect of ENDE’s
investments in the 1990s was very low, being 5%. This low rate of return resulted from the very
large past investments on hydro-plants.
251
Table 16
Bolivia, Installed Generation Capacity in 1994
Company/Plant
ENDE
Corani
Guaracachi
Valle Hermoso
Total ENDE
COBEE
Hydro
Others
Total
Capacity
MW
Percent
126.0
186.5
148.7
461.2
20.5
30.3
24.2
75.0
142.2
11.5
23.1
1.9
614.9
100.0
Source: Ministry of Capitalisation and Investment,
Generation Briefing Memorandum, Bolivia (1995) p.12.
Up to the time of privatisation the industry structure, which had emerged, was that of a duopoly
between of two vertically integrated systems, each firmly entrenched in its respective geographical
area. There was virtually no competition between the two companies. Overall, the regulatory
process, which had developed, proved to be ineffective and was directed more by political
considerations rather than economic factors. Prices were invariably fixed on the basis of political
consideration. An outcome of this regulatory process was the lack of competition and efficiency at
the distribution stage. The process provided no incentives to encourage private investments
The Restructuring Programme
Most advisors opposed the implementation of radical vertical and horizontal unbundling within the
Bolivian electricity systems because of its size and the fact that it was considered to be one of the
most efficient systems in the region. One advisor however recommended restructuring into three
vertically integrated companies each to operate as a monopolist in each of the three main population
centres. Others proposed the continuation of the two integrated utilities within the framework of a
single purchaser regime, with competition to come from new IPP entrants to the market.14 ENDE
would remain a vertically integrated state owned utility and under this model would act as the single
purchaser of bulk power from the IPPs. Despite these views, the policy makers concluded that the
252
existence of efficient companies within the industry, provided opportunity to proceed with the
reform. Efficient companies it was argued would make the industry more attractive to private
investors not only to buy the companies but also to expand the system. It was also the strong view
that competition and private investment would further enhance the efficiency of the companies.
The overriding factor, which influenced the government to ignore the external advisors and adopt a
radical restructuring approach, was the need for capital to fund the large future electricity
investments and at the same time meet the investment requirements of health, education and
national security.15 Radical restructuring, involving vertical and horizontal unbundling of the two
systems were eventually selected as the option to follow.
ENDE’s generation system was
unbundled in 1995 into three companies; Corani S.A., Valle Hermoso S.A., and Guaracahi S.A. Its
transmission system was also separated out into new business units, with 168 employees and
restructured into a single interconnected system.
Transportadora de Electricidad S.A. (TDE) was incorporated in 1997 with responsiblity for
maintaining and operating the interconnected transmission system. TDE was then linked to the
COBEE generating plants in the Zongo and Miguilla basins, the Corani hydro-plant in the Corani
basin, as well as to the two thermal generating plants of Valle Hermoso and Guaracachi. The main
thermal plants were located near the main natural gas production fields in the Eastern region.
The interconnected system spanned approximately 700 km, running north to south and 600 kV
running west to east, inclusive of four substations. Of the total network of 1818 km, 722 consisted
of 230 kV lines, 897 kV formed 115 kV lines and 199 kV formed 69 kV lines. A further 1117 mm
of 155 kV lines was nearing completion in 1997 and was to be transferred to the new system on
commissioning. In addition to the 19 substations there was a fairly modern load dispatch centre.
The transmission system made up less than 6% of the overall retail price of electricity, however, it is
capital intensive and accounted for 20% of the assets of the overall system. In addition to the
integrated system there were a number of isolated systems, which accounted for less than 20% of
installed capacity and for less than 14% of electricity production in 1996.16
In accordance with the 1994 Electricity Law, COBEE was required to divest its interest in
distribution; Electricidad de La Paz S.A. (ELECTROPAZ) and ELFEO. Of the three major
253
distribution companies, which were not controlled by ENDE and COBEE, two were organised as
cooperatives, and they were Cooperativa Rural de Electricidad (CRE) in Santo Cruz, and CESSA in
the Surce region. Additionally, there was the publicly owned SEPSA in the Potosi area. COBEE
held 67% of the stocks in ELFEO, whilst the municipalities held 28% and the remaining 5% going
to 200 small private shareholders. Following from the restructuring six independent distribution
companies emerged and these were designated as public service companies.17
The Divestiture Programme
ENDE’s generating facilities were divested through the capitalisation formula, with the
distinguishing feature being that the sales proceeds remained in the company to finance future
investments. A new set of shares was issued to strategic investors for the three horizontally
unbundled generating businesses. The Government’s share of the new company was distributed to
the Bolivian people via the special pension fund to realise 100% private ownership. In leaving the
proceeds in the company, Government was able to solve the shortage of cash for working capital
and investments. In the new structure the strategic investor owns 50%, whilst the Pension Fund
holds 50%.
In June 1994, 32 firms were pre-qualified from the various inquiries for the three ENDE generating
companies. Subsequently, ten of these firms submitted their proposals and six was selected (see
Table 17 below) to submit financial offers for the 50% equity interest in each of the three
companies.
254
Table 17
Generation Companies in the SIN in 1996
Name
Corani
Cap
acity
MW
126
19
Guaracachi
217
32
Valle
Hermoso
180
27
COBEE
144
21
Others
Total SIN
CT
674
7
10
0
Isolated
system
82
Other
Generators
104
Total Est
860
Source:
%
Electrici
ty GWh
Generat
ed
536
19
1008
33
423
15
Hydro/Thermal
865
30
Hydro
17
2849
1
10
0
Operator
Dominion
Energy
Energy
Initiatives
Constellation
Energy/Odgen
Power
NRG /
Vattenfall
COMIBOL
Type
Hydro (Run of
River)
Thermal (Gas
Turbine)
Thermal (Gas
Turbine)
%
192
(30
Hydro
162
Thermal)
(94 H)
(169 T)
246
3287
Ministry of Capitalisation and Investment,
Information Memorandum, Bolivia (1995) p.40.
The six firms were Energy Industries Inc., Dominican Energy Inc., Energy Trade and Finance
Corporation, AES Americas Inc., Constellation Energy and Enron Energy. Eventually the
companies were divested to three of the groups. Empresa Electrica Corani (Corani), essentially a
hydroelectric company of 126 MW, commenced operation with US$335.0 million worth of
expansion projects. This project was expected to double capacity from 450 GWh to 900 GWh and
involves three new water capture schemes. All four pre-qualified bidders placed a bid for this
system and the winning bidder was Dominion Energy; a Virginia power company from the USA.
The bid price was US$58.8 million.
255
Empresa Electrica Guaracachi (Guaracachi) Company consisted of a 162 MW gas fired plant at
Santo Cruz, a 35 MW plant at Sucre and a 14 MW plant at Potosi. Four offers were received for this
company and the winning bidder was Energy Industries, a company controlled by EPU
International of the Jersey Central Power and Light group. Within a year Guaracachi embarked on a
$30 million project expansion, representing the greater portion of the US$47 million brought in by
the strategic investor.
Empresa Electrica Valle Hermoso (Valle Hermoso) consisted of the Cochabamba thermal plants
amounting to 87 MW. The winning bidder was a Consortium of the Baltimore based Constellation
Energy and the Baltimore Gas and Electric Company of Maryland, both of the USA. The owners
also inherited a project which was 20% completed; consisting of two 54 MW, gas turbine plants in
the Chapare region, and estimated to cost US$54 million on completion. Constellation Energy paid
US$33.0 million for its 50% share of the equity.
In the case of COBEE, NRC Energy of Northern States Power Group of Minnesota and Vattenfall,
the Swedish state owned company acquired 95% of its equity in 1996 for US$ 185 million. The new
owners also embarked on major expansion, involving a 64 MW hydroelectric plant at a cost of
US$105 million in the Zongo Valley.
In December 1996 the installed capacity of the generation system reached 860 MW Installed hydroplants represented 32% of capacity and 46% of production output.
A number of the auto-
generators also formed part of the SIN. The two largest plants were held by an oil and gas company
and a mining company and amounted to 30 MW combined capacity.18
The transmission company’s divestiture followed the more traditional form, that of a trade sale; the
prospective investors were required to bid for at least 51% of the equity of the company. The
successful bidder was to be given an indefinite licence as distinct from a concession19 to provide
electricity transmission services in the integrated system and was required to maintain a minimum
shareholding of 26% for a predetermined number of years, with responsibility for future
transmission investments.
256
For each extension, a separate licence was required and the regulator was given the right to call a
tender if agreement could not be reached between the participants in the SIN and TDE. The
strategic investor paid US$39.9 million for 99% equity interest in TDE, in addition to taking over a
further US$12.9 million of ENDE’s old debt. The transmission operator was restricted from owning
equity in either generation or distribution and distribution and generation operators were restricted
from holding equity interest in TDE. In the first 12 months of operation (in 1996) actual revenues
amounted to US$10.5 million from electricity sales of 2817 GWh.
The six large distributors
accounted for 94% of volume and this representing 80% of transmission revenues.
On the establishment of the three new generation companies; the employees (491) were encouraged
to buy shares in the new company up to the value of their severance entitlement. Workers were
required to make a down payment of 5% cash, with the balance payable over a period of 13 months
from closing of sale with the strategic investors. Over 90% of the workers subscribed for their full
allotment. The actual divestiture involved little or no retrenchment. In fact in the case of Guaracachi
12 new workers were taken on, in addition to the 72 transferred from ENDE.
The distribution divestitures in contrast took the form of a concession. Approximately 95% of
ENDE’s 67% equity interest in the Cochabamba distribution company, ELFEC was sold in 1996 to
a Chilean utility company, ENEL at a price of US$50 million. ENEL also took over US$22.5 million
of debt. ELFEC’s four hundred and eleven employees in 1994 were reduced to 313 by 1996, mostly
through natural separation. The employees took up the remaining 5% of the equity. The company
provided electricity to 70% of households in the Cochabamba area. Its gross revenue or the first full
year following divestiture was US$30 million.20
COBEE the private operator also divested its equity interest in its La Paz distribution company;
ELECTROPAZ, along with 95% equity interest in ELFEO to Iberdrola; a Spanish electricity utility
operator. Table 18 shows the structure of distribution following restructuring and divestiture.
257
Table 18
Electricity Demand by Distribution within the SIN – 1996
Distributor
ELECTROPAZ
CRE
ELFEC
ELFEO
CESSA
SEPSA
Non Regulated
Others
Total
Source:
Principal
Owner
Iberdrola
Co-op
EMEL
Iberdrola
Coop/state
State
Private
Electricity
Demand
GWh
866
842
444
159
93
68
208
33
2713
%
32
32
16
6
3
3
8
1
100
Customers
No.
245,000
153,000
156,000
34,000
29,000
24,000
(small)
5000
646,000
%
34
31
17
6
3
3
5
1
100
Ministry of Capitalisation and Investment,
Information Memorandum, Bolivia (1997) p.46.
There were 646,000 customers, with ELECTROPAZ and CRE, the two largest each respectively
accounting for 34% and 32% of customer base. CESSA and SEPSA respectively had 29,000 and
24,000 customers, each with less than 6% of customer base. Up to 1999 the shares held by the state
in SESPA and CESSA had not been divested. Within the isolated system there were two additional
distribution companies with combined customer base of fewer than 35,000.
Table 19 shows the distribution of equity interest following privatisation, whilst Table 20 shows the
divestiture revenues. The strategic investors for the three generating companies were required to
take over debts amounting to US$141.1 million and the issue of new equity brought in US$139.7,
whilst the sale of shares of ENDE’s transmission and distribution interest realised US$90.0 million.
Strategic investors also acquired 96% of COBEE’s interest in ELFEO and the entire 100% stock of
ELECTROPAZ.
258
Table 19 Bolivia
Post-Privatisation Distribution of Share Ownership
Electricity Companies
Generation Companies
• Corani
• Valle Hermoso
• Guaracachi
Transmission Company
(TDE)
Distribution Companies
• ELFEC
• ELFEO
•
CESSA1
•
SEPSA1
•
CRE2
• ELECTROPAZ
1.
2
Strategic
Investor
%
Employ
ee
%
50
50
50
96
Pension
Fund
%
2.0
0.7
0.5
96
96
100
47.0
49.3
49.5
Oth
er
%
Tota
l
%
1
100
100
100
100
4
4
100
100
100
The Privatisation was in process up to 1999– CESSA 60% private 40% state,
SEPSA 100% state,
Cooperative own by the users.
Source: Compiled from information supplied by SIRESE
Since restructuring, a number of new generating projects have also come on stream or are scheduled
for commissioning by the year 2002. The most important of these is the ambitious Electrobol
project, with a proposed investment of US$600 million. The plant is expected to export most of its
power to the southwest state of Mayo in Brazil.
259
Table 20
Bolivia
Revenues from Divestiture
ENDE
Transmission - TDE
Distribution ELFEC
Generation:
• Corani
• Guaracachi
• Valle
Hermoso
Total
Strategic Investor
Capitalisation Income
Equity
US$ Cash
Taken
Paid
Debts
Taken Over Bid
No
(US$ M)
.
Method of
Sale
99
95
39,991,196
50,300,000
12,000,000
22,533,559
1
4
Privatisation
Privatisation
50
50
50
58,796,000
47,131,000
33,921,100
57,425,466
35,759,501
13,393,509
5
6
3
Capitalisation
Capitalisation
Capitalisation
-
230,139,926
141,102,035
-
Source: Compiled from information supplied by SIRESE
Bolivia Bulk Wholesale Electricity Market
The Bolivian electricity market reflects many of the characteristics of the Chilean model, except it
has added some of the rigorous set of processes adopted by Argentina. The bulk electricity exchange
market, like Chile is that of a cost based “gross pool”, whereby plants are dispatched in merit order,
based on the system’s marginal cost, which essentially covers the cost of fuel and non-fuel variable
cost. In addition to the energy node prices, which are calculated by the Load Dispatch Committee
on a semi-annual basis (no later than 24 April and 25 October) for each node in the SIN, generators
are able to commit firm capacity to the market and obtain a capacity payment, adopted from the
Argentine and England and Wales experiences.
The price discovery mechanism follows the nodal pricing principle. Node prices21 are made up of
three components; base peak capacity prices, energy prices, capacity and energy loss factors and
transmission payments. The node prices for the capacity and energy are indexed on a monthly basis
260
to reflect changes in various domestic and international components, including the Consumer Price
Index (CPI).
The market is a “gross pool” because all trades of electricity must occur through the spot market,
however, parties may establish contracts but these are financial contracts to hedge risks associated
with future prices. The operation started with optimum economic dispatching based on seasonally
audited generation costs and water availability information. Recently the system has allowed for a
seasonal bidding procedure.
In effect the model is a seasonal electricity exchange market, rather than a daily pool. The process
of dispatching is carried out by selecting plants in economic merit order, that are bid up to the point
at which demand is satisfied. At this point the market clears. In general the pool dispatches first the
run of the river hydropower, then the cheap CCGT plant, then the hydro- storage plants and finally
the expensive gas turbines. The Pool controls operations and records the prices and energy trades
between generators, as well as payments by users to the owners of the network. Although schedules
are made yearly, monthly, weekly and daily, final dispatch occurs within real time and the whole
tariff regime is based upon the system actual hourly spot prices.
In order to minimise price fluctuations, distributors are required to buy 80% of their anticipated
demand through three-year contracts, with 20% of transactions to be made on the spot market.
However, the system in the main has up to 2000 delivered spot prices that were above node prices.
At the same time distributors prefer to sign contracts at node prices, since that is what is allowed in
the cost pass through to end use retail customers, whilst generators prefer to sell at spot prices as
this offers higher revenues than contract revenues. The net effect is that 100% of Bolivia’s
transactions are being made on spot prices, with the four generators competing for sales. This
situation may change as more excess capacity builds up into the system and generators come to
appreciate the benefit long-term contracts.
In order to ensure transparency a national load dispatch committee; Committee National de
Despacho de Cargo (CNDC) was established in 1995, with responsibility for the rules of the market
involving both contract and spot prices and the rules relating to rights and duties of the agents
operating in the market. In addition to planning and operating the load dispatch functions it also
261
calculates the payments to be made by all the agents operating in the market. The Committee is
made up of one representative from each of the following groups; generation, transmission,
distribution and large users, with the electricity regulator appointing one member who acts as the
Chairman. The operating unit of CNDC is a non-profit association of all the agents of the market,
which instructs the generating companies as to the timing and volume of dispatch of their respective
plants. The load dispatch centre is owned by TDE, which is paid a fee by CNDC for owning and
maintaining the centre. This relationship is governed by an agreement. Fig. 23 shows the
organisational structure of CNDC. The separation of ownership of the load dispatch centre from
control of the centre is critical to transparency.
Within the market, distributors are allowed to contract directly with any generator for bulk supply,
alternatively they may source supply for bulk power from the spot market. Large end users (those
with annual consumption of 1000 kilowatt hours) are also allowed to buy direct from the spot
market or to effect direct contracts with generators. In order to facilitate trade by large end-users,
open access conditions are imposed on the distribution and transmission systems. The liberalisation
of the large end user market, however, was suspended for five years to 2001 (except for those large
end users who traditionally held contracts with generators, being mainly the mining companies).
These large end users accounted for less than 10% of volume in 1995.
In operation of the market CNDC effects a valuation of energy delivered and capacity confirmed by
generator in the spot market. The price of energy is the SRMC of the system and in the absence of
any constraint, this is the marginal cost of the most expensive plant in operation in that particular
hour and which clears the market. CNDC also determines the firm capacity for each generating unit,
which constitutes an estimate of the capacity of each plant that would be required at peak demand in
a dry year.
262
Fig. 23
CNDC Organisational Structure
Gencos
Electricity
Regulator
Chairman
Discos
Liberalised
End Users
TDE
Transco
CNDC Board
(Supervisory)
Operating Unit
(Management)
Dispatch
Instructions
Load
Dispatch
Information
Centre
Feed Back
(Operations)
Source: Ministry of Capitalisation and Investment
Information Memorandum, Bolivia, (1997) p. 16.
The firm capacity is remunerated on the basis of unit cost calculated as an annuity of investment and
fixed cost operating, and maintenance costs of standard plants suitable to provide peak capacity. The
unit cost is increased by a reserve margin, necessary to maintain an adequate availability of peak
capacity in the system. Firm capacity confirmed is remunerated irrespective of dispatch. CNDC
calculates the energy and monetary balances resulting from operation, taking into account the output
of generators, the demand of distributors and liberalised end users and the transactions covered by
term contracts.
As a result of these balances, CNDC informs each of the trading agents of their financial
obligations or receipts with results from operation of the market over a specified period. CNDC acts
as the coordinator for the pool into which all dispatched generators deliver all their output at the
SRMC and for which all distributors withdraw their energy requirements to satisfy their contractual
obligations.
263
The Regulatory Framework
Bolivia like Argentina introduced the industry’s regulatory framework before restructuring and
privatisation. The Sectoral Regulatory Law (SIRESE) was introduced in 1994 and provided the
basic framework for the regulation of the activities of telecommunications, electricity, hydrocarbons,
transport and water. The first superintendent was appointed towards the end of 1995.22
SIRESE is an innovative model that draws from the advantages of main regulatory trends. The
structure established is neither a multi-sector agency, as is found in Jamaica nor a unisectoral body as
is the situation in Argentina, but a hybrid of the two models.23 The structure provides for
independence and autonomy, continuity and regulatory commitment and benefits from both the
specialisation of a unisectoral model and sharing of cost and specialised human resources from the
multi-sectoral model.
At one level there is a General Superintendent, which does not directly exercise routine regulatory
functions and does not have a hierarchic authority, but provides a set of rules aimed at supporting
and strengthening SIRESE as a whole. Its main functions are to act as a second level appeals body
and to supervise the regulatory functions of the sector superintendences, issuing opinions on the
efficiency and effectiveness of their performances. The General Superintendent also coordinates
operations to ensure consistency within the system. The SIRESE law provides for the promotion of
competition in the utilities and transport industries where competition is possible as a fundamental
objective and for regulation to correct market failures where applicable.
At the other level are the sectoral superintendences (of which electricity is one of five such sectors)
which have full autonomy to exercise the regulatory functions in their respective sectors. At the
same time the five superintendencies operate within a common framework. The functions of the
sectoral superintendents are to enforce the sectoral law and the industry specific rules. They carry
regulatory powers over licencing, tariffs, technical safety and operating standards, anti-trust matters,
and consumer protection matters, in addition to ensuring compliance. In the case of electricity, the
superintendent was first appointed in 1996. Superintendents have been appointed for hydrocarbon,
utility water, telecommunications and transport.
264
The General Superintendent and the five superintendents are all appointed by the President of the
Republic from a list of three candidates (for each position) and must be confirmed by two thirds of
the Senate. They exercise their functions for a period of five years and cannot be dismissed, except
in the event of non-compliance of their duties. Candidates must have a university degree and ten
years professional experience.
SIRESE is funded from a levy, imposed on the industry and this further serves to facilitate its
independence. The sectoral ministries are also prohibited from any direct involvement in the dayto-day regulatory decision-making process. The executive arm of government is restricted to the
establishment of the policies and regulatory rules. SIRESE has no rule making powers; the result is
that very detailed sector legislations are provided. The decisions of the General Superintendent, on
appeal can further be challenged in the court; however, the court has no power to change the
regulators substantive decisions and is limited to
ultra-vires decisions.
The electricity law also provides the regulatory framework for the operations of the electricity
exchange market and empowers the superintendent with regulatory powers over the natural
monopoly transmission and distribution sectors. The real challenge of the regulatory process is to
promote competition in a market with so few players. As more and more independent generators
enter the market, the competitive environment should, however, improve.
Regulation of Transmission
In addition to requiring a licence from the regulator, transmission as a natural monopoly is regulated
by SIRESE in terms of technical, safety and reliability standards and prices. The transmission
operator is restricted from holding equity interest in both generation and distribution and is neutral
to the system in that it does not trade in energy or take any interest in the supply of energy. The
regulator also ensures that the transmission operator provides open and non-discriminatory access
to agents in the use of the system.
265
Transmission losses in 1995 and 1996 were 2.5% and 2.6% respectively. In 1995 the system
experienced interruptions, with a total average interruption being (TAI) 43.3 minutes and of this
52% was attributable to transmission faults. TAI is the expected value of the total interruption for
the average consumer for a specified period of time expressed in minutes. Failure to meet standards
of reliability and safety attracts penalties.
Transmission pricing also follows a two-part structure, based on capacity charge and energy charge.
Transmission prices are determined on the basis of a formula; TCT = T0LL + T1 where TCT
equals total cost of transmission and T1 equals tariff income.
The Electricity Law specifies that maximum transmission revenues will be equivalent to total
transmission costs. These costs comprise recovery of investment costs and operating, maintenance
and administration costs for an Economically Adopted Transmission System (EATS). The
annualised investment cost is based on an annuity methodology and is calculated on the basis of an
asset life of 30 years and the discount rate specified in the Law. The recovery of operating,
maintenance and administration costs cannot exceed 2% of the value of the EATS.
The
transmission company or owner of the Trunk Interconnected System is required to appoint an
independent consultant, every four years and this appointment is subject to being approved by the
SE.
The consultant’s brief is to review the EATS, its replacement value and the level of operating,
maintenance and administration costs. The findings of the report are the basis for the transmission
tariffs, including their indexation, for the following four-year period. On a six monthly basis the SE
approves the transmission payment to be made by each agent in the SIN as well as the relevant
indexation formula and the conditions for use of the transmission facilities.
Transmission revenue is made up of two components; a tariff income and transmission toll charge.
The tariff income is the difference between (i) the total value of energy and maximum capacity
withdrawn from the transmission system and (ii) the total value of the energy and maximum capacity
injected into the system with values determined at the respective SRMC. This is estimated by the
CNDC in respect of the following 12 months. The transmission toll in aggregate is the difference
between the total revenue of the transmission system and the tariff income outlined above. It is
266
calculated on the basis of the projected tariff income and the use of the transmission system made
by each participant in the SIN and is expressed as a fixed charge per kW of maximum capacity
demand (in the case of consumers) or firm capacity connected (in the case of generators) at each
node.
The transmission toll is attributed either to generators or consumers in accordance with the Area of
Influence Criteria. The Area of Influence of a generator is the line of the SIN in which transmission
of energy is increased when energy supplied by such generator displaces that of the marginal plant
located at the reference node. Similarly, the Area of Influence of a Consumer reflects those lines
where transmission increases as a consequence of the increase of supply in the reference node to
satisfy an increase in demand in the consumer’s node.
Expansion of the transmission system can only be undertaken upon the approval of the CNDC and
the Superintendent Energy. Returns to the TDE on new expansion have to be agreed between the
other agents (but not all) in the SIN.
Regulation of Distribution Prices
The maximum electricity price that distributors can charge their regulated consumers is subject to
price regulation. The base tariffs are calculated taking into account the following:
•
The cost of operating, maintenance and administration costs, interest charges, electricity
purchases, taxes and other charges levied on distribution concessionaires; depreciation
and return on equity. The maximum price at which electricity purchases can be passed
through to regulated consumers is the relevant node price. The SE has the right to
disallow any cost which it believes to be excessive or that do not reflect the appropriate
level of operating efficiency or are unrelated to the distribution of electricity;
•
The distributor’s forecasts of electricity sales to its consumers;
•
The distributor’s projected revenue in respect of the sale and transportation of electricity,
the use and maintenance of elements of services and any other revenues it may obtain.
The tariff structure described above reflects the technical characteristics of the supply and
consumption of electricity of each distribution company. The base tariffs are indexed and adjusted
267
monthly. The indexation formula comprises two components: The first component reflects
variations in the distributor’s costs and is calculated as variations in price indices, less any efficiency
factor to be established by the SE. The second component reflects variations in the distributors’
purchase costs of electricity and any variations in taxes or levies.
The SE approves the maximum price of electricity for supply to the regulated consumers of each
distribution company for periods of four years. The tariffs and the indexation formulae are also
subject to major price reviews every four years. However, the SE may revise the base tariffs in the
event that there is a significant variation between actual electricity sales and the forecast electricity
sales used in establishing the base tariffs.
The rate of return on equity used in establishing the base tariff is the arithmetic average over the last
three years of the equity rate of return of the companies listed on the New York Stock Exchange
and forming part of the Dow Jones Index of Public Utilities. In 2000 the rate was set at 10% real.
The SE regulates the financial costs to be recognised as part of the operating costs of the distributor.
The prices invoiced to the distributors and large users, however, are prices determined by the Load
Dispatch Committee and is based on six month forecasted prices.
Distributors and un-regulated customers are also allowed to enter into electricity supply
contracts. Such contracts serve the purpose of providing an assured revenue stream to the
generator, while hedging price risks of distributors. Electricity supply contracts are also allowed
between two generators. Generators are therefore, able to buy and sell electricity between each
other to enable them to discharge their contractual obligations in the manner that is most
profitable.
The original method adopted more or less involved a cost plus approach to pricing, resulting in
spurious items being included in the asset base, which was passed on to the end user in the tariff. A
major change subsequently, was introduced to the cost plus approach with the incorporation of
price cap or RPI-X methodology. A second change has been to incorporate the rate of return to be
on equity rather than assets. These changes provided the introduction of more incentives to
distributors to increase efficiencies and reduce costs as they are allowed to keep their efficiency
268
savings within the four-year interval to the next review. After every four years a new tariff structure
is approved.
Outcome
Between 1996 and 2001 over US$500 million of new capital has flowed into the electricity system
for expansion. Since the restructuring, a number of new privately funded projects have come on
stream without the benefit of any government guarantees. The accessibility of rural households to
electricity has gone up from 14% to 19% over the period, whilst overall accessibility has gone up
from 64% to 70%. A social security system has been provided for all Bolivians. In real terms all the
distribution companies have shown increased prices since the privatisation of the companies in 1997
as shown in Table 21
Table 21
Bolivia -Average Real Retail Tariff (in 1997 US¢/kWh)
Company
Electopaz
CRE
ELFEC
CESSA
SEPSA
ELFE0
Pre-divestiture
1994
1995
6.20
6.19
6.64
6.67
7.14
7.15
6.29
6.24
7.45
7.03
6.56
6.50
1996
5.99
6.69
6.84
6.44
6.92
6.24
Post divestiture
1997
1998
6.39
6.57
7.01
7.32
7.05
7.57
6.98
9.01
6.92
8.24
6.31
7.68
Source: Gonzelo Chavez Alvarez, The Electricity Sector in Bolivia, Second Draft; 2001
In 1998 nominal tariff varied between US¢6.79/kWh and US¢7.33 kWh compared to US¢6.01/kWh
and US¢ 6.95/kWh in 1996. In 1995, the average price of bulk electricity from COBEE was
US$36.7/MWh and for ENDEE the bulk price was US$ 37/MW. In 1998 the bulk prices had
increased marginally to US$ 39.5/MWh, an average increase of 7% over the 3 year period. Prices in
the bulk electricity market have shown much smaller increases than in the retail market.
269
When compared to the pre-privatisation period the divested new companies, both in generation and
distribution have displayed significant increases in profitability after 1996 as shown in Table 22. The
taxes paid by the companies before 1995 were negligible. The taxes paid by the industry increased
to over US$ 12 million by 1997. The transmission company, TDE also increased its profit from US$
2.9 million in 1997 to US$ 3.8 million in 1997.
Table 22
Bolivia -Profitability Return on Equity Percentages (After Taxation)
Company
ENDE
COBEE
CORANI
Valle
Hermoso
Guracachi
Distribution
Electropaz
CRE
ELFEC
CESSA
SEPSA
ELFEO
1994
0.75
-
1995
0.63
-
1996
18.6
11.9
4.5
1997
11.1
12.2
3.6
1998
7.2
7.2
4.8
-
-
6.3
3.6
5.6
-
-
12.4
5.4
8.9
6.4
-36.6
-0.3
11.1
6.0
10.1
4.6
6.8
12.4
10.9
6.8
9.1
8.4
6.5
16.9
Source: Gonzelo Chavez Alvarez, The Electricity Sector in Bolivia, Second Draft; 2001
The profitability (before tax) of the overall industry in 1994 was US$ 5.1 million. In 1997 the
industry profits had increased to US$ 48 million. The general picture has been one of increased
profitability and increased revenues to the Treasury. There is also the added benefit in that
government is no longer required to fund capital expansion costs in the industry. All the companies
have increased their productivity since 1996 when compared to the pre-privatised year, as shown in
Table 23. Companies have either shed labour or increased output from the same number of workers
employed, or both. In 1994, there were 2500 workers in the electricity supply industry. The trend
has been for a decline in the overall employment levels.
270
Table 23
Bolivia –
Labour Productivity, GWh per Employee
Company
ENDE
COBEE
CORANI
Valle Hermoso
Guracachi
Distribution
Electropaz
CRE
ELFEC
CESSA
SEPSA
ELFEO
1994
3.14
-
1995
3.12
-
1996
3.0
8.4
7.3
14.4
1997
3.0
10.6
11.5
11.7
1998
3.1
3.1
9.1
13.9
2.07
1.55
1.27
0.74
0.67
0.92
2.85
1.77
1.43
0.83
0.71
2.09
3.11
1.86
2.13
NA
0.87
2.68
Source: Gonzela Chavez Alvarez, The Electricity Sector in Bolivia, Second Draft; 2001
Table 24 shows that during the period 1994 to 1999 the number of customers served increased by
an annual average of 8%, slightly higher than the average growth in the first five years of the 1990s
Table 24
Bolivia -Number of Customers by Distribution Companies
Company
Electropaz
ELFEC
CRE
ELFEO
SEPSA
CESSA
Total
1996
238
169
164
36
26
31
665
1997
230
177
177
37
27
33
703
1998
263
197
192
39
29
36
757
1999
279
208
207
41
31
38
804
Source: Gonzela Chavez Alvarez, The Electricity Sector in Bolivia, Second Draft; 2001
Alvarez (2001)24 estimated that between 1996 and 1999 the total amount of capital investment
executed in the generation and transmission sectors was US$ 245 million and in the distribution
sector, US$ 156 million to give a total executed investment of US$ 401 million. Installed capacity
271
went up from 670 MW in 1996 to 730 MW in 1999, whereas maximum demand increased from 544
MW to 622 MW over the same period, giving a reserve margin of 17%, a decline from 24% over the
previous period.
Energy losses for the transmission system as seen in Table 25 above fell from 5.34% in 1994 to
2.67% in 1997, an improvement of 50%. Energy losses for the six distribution companies varied
from 8.9% for ELFEC to 12.3% for ELECTROPAZ. ELECTROPAZ, ELFEO, and SEPSA all
showed reduced energy losses between the pre and post-privatisation periods, whilst ELFEC and
CRE showed marginal increases.
It is still too early to fully evaluate the results of the liberalisation and privatisation; however, certain
trends began to emerge after 1996. In the national economy, private investment overtook public
investment. In 1998 private investments had reached 74.4%, with foreign direct investments
amounting to 63.3% of total investments.25 More than half, 66.5% of the foreign investment comes
from the new corporatized companies and a significant proportion of this investment went into
electricity and natural gas sectors.
The indications are that in the Bolivian example there were gains from privatisation in terms of
higher levels of investments, improved product quality, improved benefits to the employees,
improved technical efficiencies and improved fiscal benefits to the Treasury. Whether these gains
from privatisation compensated for the negative distributional impact of higher retail prices and
reduction in employment is another question. In the case of prices, the regulator’s role is to ensure
that the efficiency gains from privatisation are fully realised and contributes to improvements in
income distribution.
272
Table 25
Bolivia -Energy Losses: Percentage
Companies
PreRestructuring/Divestiture
1993
1994
1995
Distribution1
Electopaz
CRE
ELFEC
ELFEO
CESSA
SESPA
Transmission2
Company (TDE)
1
2
13.69
7.51
8.12
12.82
8.98
14.18
4.72
12.50
6.67
8.60
11.45
8.77
14.85
5.34
11.92
8.64
9.33
11.44
9.83
11.23
4.78
PostRestructuring/Divest
1996 1997
1998
8.68 10.5
7.71 8.68
8.82 7.71
12.10 10.80
9.64 9.51
9.88 10.4
3.7 2.67
12.3
9.8
8.9
10.3
9.9
9.4
N/A
For each distribution company pre and post-divestiture losses
Transmission post-divestiture
Source: Compiled from information supplied by SIRESE
There are a few important distinctions between the Jamaican electricity market and that of Bolivia.
In the former, one vertically state owned firm had operated since 1972, whereas in the latter, despite
the size of the market being under 600 MW a duopoly existed between the integrated state utility
company and an integrated privately held electric utility. Jamaica has been dependent on imported
fuel for over 95% of energy source, whereas Bolivia has access to domestic hydropower and natural
gas.
Bolivia had over six distribution companies in operation at the time of privatisation, compared to
the single integrated distribution company in Jamaica. Bolivia had a fairly efficient electric utility
system up to the time of privatisation with a tariff to consumers, less than 50% of tariff to
consumers in Jamaica. Both countries had prior experience in the regulation of the electric utility
markets. Jamaica divested a system with similar installed capacity and similar levels of accessibility as
a vertically and horizontally integrated monopoly, whilst Bolivia took the route of radical unbundling
and the introduction of competition in bulk wholesale electricity market. Bolivia went to Phase
Three level of development. Jamaica, however, through the single purchaser model was prepared to
273
settle for competition for new capacity, or Phase Two level of development, without third party
access.
The World Bank ESMAP 2000 Report26 stated that:
“The competitive model chosen by Bolivia is a hybrid of a “wholesale” and “limited”
retail models, generation, transmission and distribution are unbundled but
distribution covers both low voltage grid and final sales of supply. The market was
closed to new entrants up until the end of 1999.
ESMAP27 went on to state that:
“Bolivia has chosen a “hybrid” system: it wants to enhance competition but at the
same time stabilise prices through a “regulated” contracts system. A pool oriented
system might be more robust” and a better solution. Hydro-plants are volatile by
nature and trying to hide this will mean that the “natural” risks are hidden”.
Bolivia in providing for competition at the bulk electricity market stage and limited competition at
the retail market in the form of bypass which allowed large users to go direct to generators ensured
that competitive pressures were introduced to the wholesale and retail markets
Lessons Learnt
The most important lesson from the Bolivian experience has been to demonstrate that the minimum
scale of generation plants has fallen significantly; this means that several small hydroelectric and
natural gas plants can operate in a relatively open and competitive bulk electricity market. The
capacities of each of the post–privatised companies were less than 230 MW.
The Bolivian restructuring and privatisation of a small electricity market has provided a number of
other lessons, both from the point of view of public utility economics and public policy. The thesis
which states that it is only in large and advanced electricity market that it is possible to carry out
radical dis-integration and introduce high degrees of product market competition is no longer valid.
Bolivia by introducing a well designed power market incorporating a cost based system of price
discovery has demonstrated that it is possible to radically unbundle small electricity markets, below
1000 MW and introduce a high degree of competition and that the dis-benefits from increased
274
transaction costs, and loss of economies of scale are more than compensated for by the benefits of
competition.
It is, therefore, possible to introduce commodity exchange markets for bulk electricity and move
directly from Phase One to Phase Three level of development without going through Phase Two,
the Single Purchaser Phase. Power markets are not only practical in small electricity markets; with
carefully constructed market design; such markets can work fairly efficiently without the serious
negative effects which may arise from the exercise of market power by the small number of
generators.
Holburn and Spiller28 also came to the conclusion that:
“in addition to the organization of transmission, governments have several options to
reform the generation sectors, chief among these is decision to create a competitive
wholesale generation market, where sellers bid against each other to supply electricity
on a continuous basis with prices determined by market-making mechanism. Although
the introduction of wholesale markets have in general been perceived as a desirable
policy goal, questions have been raised about the feasibility of implementing radical
reforms in smaller countries where, it is agreed only a small number of generation
companies can be supported leading to an oligopolistic situation”.
By entrenching the independence of the regulatory agency in the legislation the Bolivian experience
shows that it is possible to develop independent and credible utility regulatory structures and regime
in the poorer developing country environment. The importance of independence of market
operation and regulation from the political institutions is clearly reflected in the institutional design
of SIRESEE.
The executive arm of government is not represented on the Load Dispatch Committee,
the operator of the power market, as is the case in Argentina and Chile. The legislature mandated a
clear separation for the regulatory decision making process from the executive arm of government.
Not only are there transparent procedures established for the appointment of regulators, they
cannot be dismissed by the executive branch unless a court finds that they are not carrying out their
duties according to law. Appointments require confirmation by the legislature and this decision it is
not left to the discretion of a minister, which is a feature common to most developing country
regulatory regimes. In both Kenya and Tanzania the regulators were dismissed summarily without
any due process of law.
275
Holburn and Spiller29 further state that:
“designing regulatory institutions that are flexible enough to make balanced policy
decisions in response to unanticipated events, but that they are also rigid enough to
insulate policy from political pressures is a difficult task”
The Bolivian privatisation experience shows that it is not only the industrial structure, which is
important, also of fundamental importance is the regulatory governance structure. Bolivia provides
an example where a credible regulatory governance structure has been created with the capacity to
handle inappropriate political pressures and opportunistic behaviour.
Finally, there is also a widely held perception that within the distribution sector, scale economies are
such that horizontal fragmentation leads to increased distribution costs and encourages inefficient
investment decisions. Economies of scale in distribution are driven by economies of densities,
implying that the minimum scale distribution company can be very small and that the degree of
fragmentation can be large. This is supported by the experiences of Norway with over 24030 and
New Zealand with over forty.31 Again the Bolivian experience supports the thesis that economies of
scale is not the significant factor in restructuring the distribution sector but economies of densities,
hence the variation in sizes of the distribution companies from a 25000 to 240000 customers base,
without any serious cost penalties to the smaller firms.
276
End Notes
1.
Robert Bacon, “Restructuring the Power Sector: The Case of Small Systems” in Private
Sector Infrastructure, Washington, D.C., World Bank, Special Edition (1996), p.86
2.
John E. Besant-Jones, “The England and Wales Electricity Model: Option for Developing
Countries” in Private Sector Infrastructure, Washington, D.C., World Bank (1996), p.47.
3.
Salomon Brothers, Information Memorandum – Capitalisation of YPFB, Bolivia,
Ministry of Capitalisation and Investment (1997), p.22.
4.
Ministry of Capitalistion and Investment, Capitalisation Slides, The Bolivian Economy
(1998)
5.
Ministry of Capitalisation and Investment, Capitalisation Slides, The Bolivian
Privatisation (1998)
6.
Richard Bauer and Sally Bowen, From State Capitalism to Capitalisation: The Bolivian
Formula, Chile, McGraw Hill (1997), p.25.
7.
Capitalisation contemplates cooperation between the Bolivian citizens and strategic
partners who bring fresh capital into the state owned industries. An important component
of the reform was the creation of a new private pension system to replace the near
bankrupt state pension, allowing Bolivian citizens shareholdings in the privatised
industries.
8.
In order to comply with Bolivian commercial law for each capitalisation a notional company,
Sociedad Anonima Mista (SAM) was set up once the privatisation procedure and the prequalification of potential bidders was underway. This was necessary so that the SAM could
issue shares. The law requires that there must be private shareholders alongside the state and
the solution was to convince the workers to purchase shares prior to privatisation. In
exchange for one share at US$20 (nominal) the workers were offered an option on later
purchases at the same fixed price.
9.
Ministry of Capitalisation and Investment (1997), Generation Briefing Memorandum,
Bolivia (1995), p.34
10.
Ibid, p.35
11.
Ibid, p.36
12.
ESMAP, Bolivia Power Generation and Transmission, Washington, D.C., World Bank
(January 1993), p.20
13.
Ministry of Capitalisation and Investment, Generation Briefing Memorandum, op. cit.,
p.35
277
14.
ESMAP, Introducing Competition in the Electricity Supply Industry in Developing
Countries: Lessons from Bolivia, Washington D.C., Joint UNDP/World Bank Study
(August 2000), p.7
15.
The Government no longer had the option of financing the utilities through multilateral
sources, as both the World Bank and the Inter-American Development Bank stated that they
were no longer willing to finance the investment cost of the utilities.
16.
Ministry of Capitalisation and Investment, Transmission Information Memorandum,
Bolivia (1997) p.42
17.
Public service companies have a legal obligation to provide utility services within their
franchise areas.
18.
Ministry of Capitalisation and Investment, Capitalisation Slides, The Privatisation
Results (1998)
19.
According to Bolivian law, a concession is defined as a public service, which imposes a legal
obligation on the concessionaire to provide public service on request. Concessions,
therefore, apply only to the distribution, operators. The transmission and generation
operators were given licences.
20.
Ministry of Capitalisation and Investments, Transmission Information Memorandum,
op.cit p.44
21.
They are equal to the marginal costs of meeting peak power (kW) and energy (kWh) demand
at each point or node in delivery to the distribution network. Marginal costs are estimated
for a generator/transmission power system economically adapted to the demand.
22.
Jose Antonio Criales and Warrick Smith, Bolivia Regulatory Reforms: Defining the
State’s Role, Seminar on Bolivia’s Capitalisation Programme, Washington, D.C., World
Bank (1997), p.2.
23.
SIRESE, Sectoral Regulation System, Bolivia (1997), p.9
24.
Gonzola Chavez Alvarez, The Electricity Sector in Bolivia, Second Draft, (unpublished
2001)
25.
SIRESE, Sectoral Regulation in Bolivia (1998), p.9
26.
ESMAP, 2000, op.cit., p.10
27.
Ibid, p.18
278
28.
Guy L.F. Holburn and Pablo Spiller, Institutional or Structural: Sequencing Strategies
for Reforming the Electricity Industry, Berkeley, University of California, Hass Business
School (November 2000), p.8.
29.
Ibid., p.11
30.
L. Hjalmarsson and A. Veiderpass, “Efficiency and Ownership in Swedish Electricity
Retail Distribution”, Journal of Productivity Analysis (1997 a), Vol. 3, p.21
31.
New Zealand Institute of Economic Research, Electricity Lines Business Performance,
Ministry of Commerce , Wellington (200), p.15
279
Chapter 7
Sub-Saharan Africa Electricity Reforms: Three Country Case Studies
Macro-economic and Market Background
In order to understand the problems and process of electricity reform efforts in Sub-Saharan Africa
(SSA), it is necessary to consider the reform agenda within the framework of development policies,
which prevailed in the region after the post-war years. The problems of Sub-Saharan Africa’s
electricity systems are not unique to the developing world; it is the extremity of the problems, and
their levels of convergence, which give special urgency to the Africa situation.
The three SSA countries selected along with South Africa have indicated their intentions to
introduce radical reforms involving unbundling and introduction of competition. These countries
have not only declared their intentions; they are well advanced in the implementation process. South
Africa is excluded because it is a very large and fairly well developed system and typically does not
display the characteristics of SSA systems. Cote d’ Ivoire was the first SSA country to introduce the
single purchaser /IPP model. Ghana is the first to declare its intention to move to a power market
and Tanzania, having decided first to privatise on the basis of selling the vertically integrated utility,
as was adopted by Jamaica, has now decided to vertically and horizontally unbundle its small 600
MW system.
Africa’s total primary consumption of energy amounts to less than 3% of world consumption, yet
Africa is blessed with 15% of world hydropower potential1.
Countries such as Angola,
Mozambique, Zimbabwe, Zambia, Kenya, Namibia, South Africa and Tanzania are resource rich in
terms of sources for power generation; hydro, coal, and geothermal or natural gas2. Despite this rich
resource base, access to electricity in SSA countries is amongst the lowest in the world. In rural
areas access to electricity is less than 2%3. The net effect is that the vast majority of people are
denied access to electricity. Energy use per capita in 1995 averaged 238 Kg; compared to per capita
of 5518 Kg in high-income countries.
280
Most of the countries in varying degrees share the same demographic and economic characteristics
as shown in Table 26 for the selected case countries. For 26 SSA countries average per capita
income in 1994 was US$305, amongst the lowest in the world. The rapid rate of growth in
population and the combination of low per capita income means that very high levels of sustained
GDP growth rates are needed to impact significantly on living standards. In fact there has been a
reversal of living standard in several SSA countries.
GDP growth rates for the 26 SSA countries in the decade 1970-1980 grew at 5.5%, and stagnated
until 1995, before plummeting to extremely low levels for the period up to 1995 as shown on Table
26. Growth rates at an annual average of the order of 6% are needed to significantly raise the level
of aggregate demand. In several countries, over 60% of the population lives in rural areas; this
feature imposes serious cost penalties in expanding access. Most countries possess two are three
large urban centres and outside of these centres, population is often thinly scattered and this makes
it uneconomic to extend transmission and distribution lines. In fact in rural areas access to electricity
is often less than 1%.
Almost all the countries experienced huge budget deficits and crippling external debt burden. The
high levels of fiscal imbalance and high levels of external debt, severely constrain the level of
domestic capital available to maintain and expand the sector. Most of the countries have seen
dramatic declines in their exchange rates and this not only raises the cost of imported capital goods
needed for industry, the cost of debt when factored into an electricity tariff puts the service beyond
the reach of all but a small elite group. Governments have been reluctant to pass on cost increases
to domestic users, which result from a decline in exchange rate and from increased fuel prices.
.
281
Table 26
Macro-Economic Characteristics of Case Countries
Characterises
Tanzania
Area (km2)
Size Population (Million) 1994
Population Growth Rate 198394 (%)
Population Density, 1994
(person p/(km2)
Rural Population, 1993 (% of
Total)
GDP 1994 (billion US$)
GDP Per Capita 1994 (US$)
GDP Per Capita Growth Rate
1989-94 (%)
Average Inflation, 1994 (CPI
p.a.)
External Debt (% of GNP),
1992/93
Cote
d’Ivoire
Ghana
Bolivia
945,000
28.1
3.1
322,463
13.7
3.6
239,000
16.9
3.2
2,150,000
7.2
2.2
30
43
71
3.0
77
58
65
41
1.6
60
0.1
10.5
665
-4.0
6.1
380
0.9
4.7
585
1.9
24.5
32
24.5
7.9
303.8
228.0
65.5
74.3
Source: Luis Gutierrez, “How do Sub-Saharan African Utilities compare”, in Power Sector Reform
and Efficiency Improvement in Sub-Saharan Africa, Joint UNDP/World Bank,
Washington. D.C. (June 1996) pp 61-63.
For many of the SSA countries production costs are very high combined with very high tariffs. The
tariffs shown in Table 27 are typical of SSA countries other than those bordering on to South Africa
Peak demand for most of the markets is under 1000 MW with installed capacity around or under
1500 MW in 2000 as shown in Table 28. Most of the system sizes are much smaller than those
found in Asia and Latin America and except for Ghana are about the size of Bolivia. The fact that
capacity may have doubled over the last two decades, the base that they have had to develop from is
very small.
The systems are overwhelmingly hydro-based. An important advantage of hydro is that fuel cost is
effectively free and operations and maintenance costs are much lower than for thermal plants.
Capital cost is, however, much higher and the construction period much longer; consequently the
payback period is much longer, often over 25 years.
282
Table 27
Electricity Systems Characteristics
(Year 1993/1994)
Characterises
Installed capacity (MW)
Reserve margin (%)
Peak load (MW)
Hydro (% of Total)
Thermal (% of Total)
T&D losses,( % of net generated)
Customers per employee
Residential, (as % of Total)
MWh generation per employee
% of population with Access
Energy consumption per annum (kg.
oil equivalent)
Number of customers
Demand growth rate (%)
Sales revenue (US$ Million)
Avg. tariff market excluding rates
(US¢/kWh)
Rate of return (%)
Employees (1994)
Tanzania
Cote
d’Ivoire
Ghana
Bolivia
516
71.7
301
84.0
16.0
18.0
34
240
6.0
34.0
918
142.3
382
57.6
42.4
16.3
160
41.6
957
21.0
109
1,187
0.25
1,190
99.3
0.7
17.8
126
34.0
1,918
20.0
96
646
28.0
504
52.1
37.9
11.4
314.0
35.0
1,283
56.4
309
255,070
7.6
116
8.0
481,912
3.8
641
30.1
400,000
1.5
132
3.2
549,700
6.0
225
8.4
-5.7
7457
NA
3182
6.0
3182
5.2
-
Source: Louis Gutierrez, “How do Sub-Saharan African Utilities Compare” in Power Sector Reform and Efficiency
Improvements in Sub-Saharan Africa, Joint UNDB/World Bank, Washington, D.C., (June 1991) pp.61-63.
Only around three countries currently produce more than their domestic needs. Intra-country trade
in electricity with these countries offers good potential to reduce production cost in high cost
producing countries. Except for a few major hydro-plants and some coal plants in South Africa,
plant sizes are relatively very small; on average below 75 MW. In many instances power is generated
at a few relatively remote sites, effectively giving rise to long transmission lines and higher
transmission losses and transportation costs.
Between 1971 and 1989 electricity production increased at an annual average rate of 6.3% in Africa
as a whole, compared to 3.3% in OECD countries, a rate, which exceeds GDP growth rates over
the same period. Despite this growth, use of electricity has remained essentially an urban experience
and outside of the reach of the greater proportion of the population, and especially those in the rural
areas where the level of household access to electricity has been less than 2%
283
Table 28
Economic Characteristics: Decade of the 1980s and 1990s
Characteristics
Tanzania
GDP 1998 (US$ billion)
Inflation 1980-90 (%)
Inflation 1990-98 (%)
Real GDP Growth 1980-90 (%)
Real GDP Growth 1990-98 (%)
FDI 1998 Flows (US$ Million)
External Debt (US$ billion)
GDP Per Capita (US$)
Per Capita (kWh)
Access (%)
Installed Capacity (MW)
Peak Demand (MW) 2000
Source:
7.2
30.7
23.7
2.9
2.8
190
7.8
210
52
7
863*
450
Cote
Ghana
Africa
d’Ivoire
11.0
7.2
5.8
47.4
15.9
7.8
28.6
25.8
-0.4
2.1
2.8
3.4
4.3
2.5
174
255
17.7
6.3
690
390
174
318
25
25
1300
1512
NA
1070
-
African Development Bank, African Development Report 1999; Infrastructure
Development in Africa, Oxford University Press (1999) pp 199-218.
The challenge for the future is formidable, and raises the question as to whether SSA countries’ state
owned monopoly electric utilities could rise to this challenge. Schramm states that4:
“electricity demand in developing countries is likely to grow at more than 6% per annum
over the next few decades, compared to little over 1% in the developed world. This will
require huge investments for which capital will not be available if the power sector in the
countries continue to perform badly as they do now - - - - - - - - - - - - steps can be taken
now to reduce both capital needs and environmental impacts by more than one half if
operational performance of the power sector in these countries could be improved and
brought up to standards prevailing in the developed world.”
Hadjimichael, Nowak, Sharer and Tahari5 of the IMF came to the conclusion that:
the adjustment experience of Sub-Saharan Africa has demonstrated that to achieve
gains in real per capita GDP, expansion in private savings and investment are still
too low in relation to GDP to finance a satisfactory and sustainable expansion in
output (of which electricity, is key, my inclusion) - - - - - - - Accordingly, public policies need to be aimed at creating an environment conducive
to private sector development”.
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The Rationale for Public Ownership of Electric Utility in Africa
The rationale for public ownership of the electric and other utility enterprises by the SSA countries
came about from programmatic and ideological considerations. There was the faith that the state
could succeed where markets appeared to fail.6 The public ownership model has failed because
political considerations have been allowed to supersede economic consideration. Ownership of the
electric utility was deemed to be central to national sovereignty. The utilities were therefore,
constituted with national responsibilities with the central objective being that of economic
development.
This is in contrast to the United States where the central objective is that of commercial profits. In
many of the African countries, the privately owned electric companies were nationalised as part of
taking control of the commanding heights of the economy. There was also the belief that the supply
technology, being a natural monopoly required an interventionist government approach. Although
electricity supply is a private good and not a public good it however, exhibits strong public interest
characteristics7.
The official international financial agencies, the IMF, World Bank, regional development banks and
the main bilateral funding agencies equally accepted the strategic role assigned to the electric and
other utilities in the process of economic development in the years up to 1980. In fact many of the
state owned power projects were initiated and financed by these agencies. Of the Bank’s total
US$16.5 billion of funding to developing countries for completed projects,; the 26 SSA countries
received 7%8.
Electric utilities therefore, came to be operated either as departments of power ministries or as
statutory corporations with limited autonomy. The pre-dominant institutional arrangement for the
electric utility has been that of the statutory or publicly owned organization, operated as a vertically
and horizontally integrated monopoly.
Kenya provided the exception, with a structure that
historically has been one of joint public/private ownership. Cote d’Ivoire, while publicly owned,
provided for private operation through a concession type contract since 1991. In South Africa and
Namibia, ownership is distributed between the central government and the municipalities with the
municipalities mainly owning distribution companies. In Zambia the private sector has been allowed
to own and operate the transmission and distribution network.
285
Following the global economic crisis of 1995, there has been questioning of the traditional
development model. For most of the people in the rural areas of Sub-Saharan Africa, this policy has
failed to provide one of the most basic services and the prospect of receiving supply in the near
future has become more distant and unlikely each year. Even for the small urban minority with
access to electricity, the experiences of indifferent and poor services and sustained and frequent
power outages made them impatient with the power utility performance.
The World Bank experiences have been that the overall improvements in institutional development
of the utilities have been modest, economic rates of return inadequate, typically below 10% and with
a few exceptions improvements in operating efficiencies have been marginal.
Generally, the
subsidised tariff, which was designed for low income and rural consumers mostly, found its way to
existing middle and high-income earners.
An analysis of the electric power utilities must therefore, reflect this historical setting. This
traditional policy approach, however, did deliver a certain amount of growth. Between 1970 and
1985 the installed capacity of SSA countries increased by 270% and many of the projects
implemented came to symbolise success of the emerging nations, such as the Owns Fall Hydroscheme in Uganda.
The overwhelming picture, however, which emerged regarding state owned power utility markets at
the beginning of the 1990s, was that of low productive efficiency and poor allocative efficiency. This
poor state of affairs reflects itself in the areas of technical, economic, and financial performance and
managerial, institutional and regulatory deficiencies.
Financial, Economic and Technical Performances
One of the more serious problems experienced in SSA countries in the period up to the early 1990s
was that of inadequate and poor revenue collection. The effect of weak revenue collection is that the
enterprises have been unable to meet either the economic objective of economic efficiency, recovery
of long run marginal costs or financial objectives, cost recovery with average revenue being equal to
average cost.
286
Over the period 1979 to 1988 developing countries average tariffs fell by 32%9 in real terms, partly
because of the high rates of inflation experienced and partly because of the reluctance of
governments to charge tariffs, which sought to recover long run marginal cost (LRMC). In eleven of
the SSA countries average tariff remained below US¢5/kWh in 1993.
In general in SSA countries, except for Kenya and more recently Cote d’Ivoire10, the proportion of
cost recovered from tariff revenues has been under 50% of costs. The net effect is that rates of
return on assets have generally been low or negative.
Very common in SSA countries has been the practice of providing subsidy or cross-subsidies from
industrial users to all consumers, instead of using lifeline tariffs, and this typically benefits middle
and high-income households, as they are the ones, that tend to be connected, and the ones to use
more power11. The target group for the subsidy, the poor, do not benefit from the subsidy.
Poor revenue collection results from inadequate accounting and billing practices, poor meter reading
and poorly maintained and inaccurate meters (or the absence of meters), poor record keeping and
non-payment of bills. Illegal connection, fraudulent billing and theft of electricity have been found
to be widespread. In addition to commercial losses, technical losses often exceed 15% compared to
developed countries where technical losses are under 7%. Many governments have been unwilling
to pass on higher costs to consumers as well as to apply penalties to delinquent customers.
In the small systems in SSA countries and especially those with hydro as the dominant fuel source,
the reserve margins required have typically been established at very high levels, owing to variation in
weather patterns and poor maintenance standards. The high levels of installed capacity which have
had to be maintained, result in over-investment for the given load requirement. Although installed
capacity is generally higher than peak demand, equipment downtime is often in excess of 30%,
leading to inadequate capacities at times and failure to meet existing demand of customers.
Weak transmission and distribution lines which typically characterise many of the systems. This leads
to poor product quality; wide variation in voltage levels and sharp drops in voltages. Such variation
and sharp drops in voltages resulted in damages to customers’ equipment, both household and
287
industrial. Industrial, commercial and private users have had to install backup power systems and
standby generators.
The general picture of most state owned companies is that they are loss makers, having to rely on
public funds for both working and investment capital. Very few systems have been able to provide
self-financing of their investment needs. In general they have had to depend on IDA /World Bank
financing for most of their capital investment. Productivity levels are typically very low. The World
Bank’s median for customers per employee in 1994 was 104, whilst for developed countries the
median was over 20012.
Institutional, Managerial and Regulatory Failures
Almost all SSA countries have been characterised by institutional and managerial weakness and
regulatory failures. Girod and Percebois13 state that:
Except for a few countries, the organisation of most of Africa’s power..………..has
taken a common form since the beginning of the 1970s involving establishment of
national enterprises, in a situation of monopoly (de facto or by law) in charge of
ensuring a public electricity services, vertical integration of the three segments of
production, transport and distribution within one enterprise with supervision and the
function of regulating ensured by the public ministries (tariff definitions, choice of
investments, financing modalities, and appointment of managers).
The establishment of power utilities as vertically and horizontally integrated state owned monopolies
has meant that their operations have not been exposed to competition. There is a lack of autonomy
of management, in that management does not have control over day-to-day operations or over
decisions on prices, wages, employment, investments, technologies and budgets.
Many power utilities are over-staffed because SSA governments use them to create public sector
jobs. Employment practices are very rarely carried out on a competitive basis, with the result that
the firm ends up with inappropriate skills’ levels. There is very little orientation of the enterprises to
recognise and meet consumers’ needs. Users are unable to express their preferences or
dissatisfaction through choice and market signals cannot be relied on to provide information about
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demand. Regulation is enforced through self-regulation or highly intrusive ministerial regulatory
practices.
Regulatory reform, involving the creation of independent regulatory regimes, transparent processes
and professional staff, and regulation to support the market rather than to replace the market,
remains one of the major challenges.
A sample survey of thirteen SSA countries by the researcher in 1998 showed that economic
regulation is typically effected through the parent ministries. Table 29 shows that only Ghana and
South Africa from the sample of thirteen countries had introduced independent regulatory agencies
by 1998.
Table 29
Regulatory Regime in Selected
SSA Countries
Countries
South Africa
Mauritius
Botswana
Gambia
Mozambique
Ghana
Kenya
Uganda
Cote d’Ivoire
Tanzania
Namibia
Malawi
Lesotho
Decisions Over Tariff &
Licences
Regulator
Ministry
Ministry
Ministry
Ministry
Regulator
Ministry
Ministry
Ministry
Ministry
Ministry
Ministry
Ministry
Source: Compiled from Sample Survey by Researcher, 1998
Kerf and Smith14 have found from their survey that:
“in response to the growing problems being experienced with the traditional public
enterprise model, many Governments in Africa and elsewhere have been attempting to
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improve performance of state-owned enterprise. These reforms attempt to give greater
emphasis to commercial principles and provide a greater degree of insulation from short
term political influences ---countries around the world are retreating from the public
enterprise model in all sectors.”
The overriding factors influencing the reform agenda in SSA countries, however, have been the need
to reduce the fiscal deficit and the pressures of the IMF and the World Bank through their
stabilisation and structural loan policies. SSA African countries have very rarely been receptive to the
introduction of the market economy and a reduction of the role of the state in productive activities.
The Role of the Donor Agencies
It is unlikely that there would have been reforms without the instigation for changes by the donor
agencies and especially the World Bank and IMF. Since the mid-1990s the World Bank, the regional
development banks and many of the donor agencies have stated that the power and other utility
sectors can support financing from the private financial markets, and that their concessionary
financing will be directed more towards education, health and very basic infrastructure.
A shift in policy direction took place in 1993 when the Bank reduced its emphasis on project loans
and redirected its programmes towards commercialisation of the enterprises, provision of
independent and transparent regulation and increased participation of the private sector in the
delivery of electricity supplies.
The principal mechanism for support by the IMF and World Bank has been through the various
stabilisation and structural adjustment programmes.
The IMF and World Bank credits have
specifically been supporting reforms, including providing technical assistance, institutional capacity
development and advice in building consensus. Since the early 1990s the two agencies have
introduced effectiveness conditions tied to their programmes. These conditions lay down specified
outcomes or performance benchmarks which must be achieved in order for the individual
government to benefit from specified tranche releases, as balance of payment support.
The donor agencies, however, can be faulted for a number of failures as in the case of Kenya and
Ghana where the governments were initially coerced into accepting reforms that they did not
290
understand or that they did not fully accept.15
The time frame established for programme
implementation, often failed to take into consideration the complications of the power sector or its
institutional capacity constraints as well as the political sensitivity surrounding ownership, as is the
case with Tanzania.
The Challenge of Attracting Foreign Direct Investment
There can be little doubt that the biggest challenge faced by SSA countries in their quest to expand
access of electricity and improve product quality is that of attracting private capital and especially
foreign direct investment. Kerf and Smith16 observed that:
“During the last decade” of the 1990s, investment both foreign and domestic, fell to
dramatically low levels and Africa’s share of FDI flowing to developing countries also
fell from 16% in 1970s to 3.5% in 1990s. With investments typically large and immobile,
prices tending to be political and revenues usually denominated in local currency,
investors demand substantial evidence of government commitment to regulatory and
other undertakings.
The challenge of attracting large flows of foreign private capital is often greater than many SSA
governments have come to realise. First, political instability in the region fosters suspicion as to the
credibility of many governments to long-term commitments. Second, the low per capita income,
often below US$ 500 and a background of high levels of non-payment, raise concern as to whether
consumers can pay market related tariffs, based on financing from the private international financial
market. Third, prices are not only politically sensitive they are denominated in domestic currencies
and as such revenues are exposed to unstable currencies.
Fourth, domestic capital markets are thin with low capital absorptive capacities and very little
opportunity in mobilising significant levels of local capital for joint venture partners. Historical rates
of return of less than 5% on revalued assets are also unattractive. Fifth, African governments will
not only have to be less politically sensitive to private ownership of the power and other utilities,
they will need to provide credible evidence that independent regulatory structures will be developed
and allowed to operate free from political interferences. Gutierrez17 observed that from a survey of
21 African countries,
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“the investment needs for the period 1995 – 2005 is US$ 18 billion, based on a conservative
demand forecast of 3.5% per annum”.
It is clear that the funding required will be substantial and beyond the capacity of most governments.
They will need to introduce what must be seen as radically new policies, involving cost recovery,
new industry structures, hands off approaches to management and operation, higher levels of private
ownership and the insulation of pricing decisions from political considerations. Both the
international financial agencies and individual governments will need to take responsibility for and
write off most of the debt obligations which were created from inappropriate investment decisions
of the past, as it is unlikely that at privatisation the private sector would be willing to take over these
liabilities.
The first phase of the reform efforts, which commenced in the 1980s, sought to address the
problems of poor financial and operational performances and some of the institutional and
managerial weaknesses. The second phase, which commenced after 1994, provided for some
relaxation of entry restrictions into the electricity generation market and the introduction of IPPs.
In many respects, the single purchaser phase came about because the donor agencies, especially the
World Bank came to the conclusion it was not sufficient to effect changes within the existing
institutional framework and industrial structure.
Fundamental changes to the traditional state owned franchise monopoly model was needed as the
earlier changes to management techniques and rules had proven to be insufficient to secure
sustainable improvements. It is with this realisation that the conditions of the Bank shifted from
measures designed to provide for better technologies and commercialisation of the state owned
enterprises to focus on liberalisation of markets, private participation and the introduction of
independent regulatory structures.
In the first phase of reform several governments introduced internal management performance
contracts. Many of these, however, were superseded by external management contracts. External
contracts are typically introduced at the stage of crisis. The experiences of these performance
contracts, however, have not been encouraging.
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The World Bank18 eventually concluded that:
“In the vast majority of cases, however, performance agreements have had a poor record
of sustaining reforms. In Ghana and Senegal, for example, governments reneged on
their commitments to inter alia, increase tariff and promptly pay bills of government and
other state owned enterprises -------Problems stems from conflicting objectives which governments are tempted to pursue
under these types of arrangements. There is a growing realisation that combining
government role of owner, regulator and operator is a poor institutional structure for
attempting to operate on commercial principles”.
In principle internal performance contracts are not legally enforceable. The realisation was that
deeper reforms were needed requiring the termination of the monopoly or franchise rights of the
state-owned enterprise in areas where competition is obtainable, as is the case with the generation
sector and the introduction of private operators in the form of independent power producers.
SSA countries responded to the reform agenda in the second phase by expanding the rate entry of
independent power producers into the generation market, and concessioning out public enterprise
operations. These approaches have been popular as they preserve much of the status quo, do not
require the state to give up ownership of existing operations and resolve some of the problems of
finance for new capacity. Partial liberalisation and partial privatisation of some services, however, do
not allow for sustainable performance improvements. Profound transformation, involving vertical
and horizontal unbundling of generation, transmission and distribution, the introduction of
competition for bulk electricity, and increased levels of private ownership are needed.
Figure 24 presents the reform framework in SSA countries.
293
Figure 24
SSA Restructuring Framework
State-owned Vertically Integrated
Franchised Monopoly
Single Purchaser or Entry Competition
in Generation
Introduction of Independent Power
Producers (IPPs) through 15 – 25 years
Power Purchase Agreement
Government
Department
Statutory
Corporation
Commercialisation
Management
Contracts
Liberalisation of market for entry by cogenerators
Joint Stock
Company
Concession
Bypass for large consumers or
liberalisation of large consumer market
Joint Public/
Private
company
Fully Private
Company
Industry structure, either continued
vertically integrated state monopoly as
single purchaser or vertical unbundling of
transmission and distribution with the
T&D company as the single purchaser or
alternatively separation of transmission as
single purchaser
Source: Adapted from Ikhupuleng Dube, “Introduction to the Zimbabwean Power
Sector” in Reforming the Power Sector in Africa, eds, M.R. Bhagavan, London, Zed Books
(1998), p. 244.
Several governments have also sought to separate regulatory responsibilities from the operating
company and the portfolio ministry so as to enhance transparency and independence in monitoring
the competitive procurement of new capacity and in determining tariff. In the franchised monopoly
era, governments through liberalisation have allowed limited entry of foreign investments to the
utility industry; however, without a new legislative framework, uncertainties develop as to the rules
of entry and the process of awarding concessions and licences to private operators. It is, therefore,
important that along with liberalisation, rules are established setting out the scope of private
participation and the process that will be adopted. Rules need to be established and enforced as to
294
the regulatory process. An important concern of private investors is the level of discretion to be
allowed the new cadre of regulators, especially in the formative years of the regulatory process.
The new regulatory framework requires pricing and other economic decisions to be divorced from
political consideration. The requirement that a regulatory decision making process be divorced from
the political and administrative bureaucracy and devolved to an independent agency is not only new
to SSA countries, it is a radical step to make and presents a major challenge to the African
administrative environment.
As an initial step in the process of regulatory reform many governments have taken the first step,
that of establishing the regulatory agency outside the traditional structure of the civil service and the
ministry hierarchy. However, the regulatory reforms so far introduced do not go far enough, as in
most instances the newly established agency operates only in an advisory capacity, rather than as a
decision maker. A concurrent requirement of establishing competitive power markets is the need
for an independent regulator and transparent processes, not only to safeguard independent and nondiscriminatory operation of the market, but also to ensure independent regulation of the monopoly
transmission and distribution network.
Up until 1995 reforms, which provided for private ownership of the power sector, governments and
the wider public generally resisted structural unbundling and the introduction of competition. The
solutions, which then emerged often, reflected a compromise between internal and competing
forces, resulting in what was seen as politically acceptable. At the forefront of the opposition to
private ownership and vertical unbundling have been public sector managers, unions and workers,
sector ministry bureaucrats and particular parliamentarians.
Because the process has had to be negotiated, reflecting political realities the reforms have been
slow, often with uncertainties as to their outcomes. South Africa for example announced that it
would introduce private ownership and vertical unbundling from as early as 1988; up to 2001;
Eskom the state owned electric utility remains a vertically integrated generation, transmission and
distribution company. The pace of the reform has been much slower than in other regions such as
East Asia and Latin America, often with missed opportunities. Under pressure from the loan
295
conditions embodied in the structural agreements, governments often proceed to implement the
reforms under hurried conditions, resulting in less than optimal outcomes.
Even though many SSA governments have come to accept the rationale for change to more radical
solutions, many have failed whole-heartedly to embrace the process of change. For many there is
still suspicion as to the long term viability of an economic system based on competition and the
guiding hand of the market, as well as to the capacity of the private sector to work for the national
goal, over the limited focus of profitability and shareholder value for the few. Pressure to maintain
historical privileges and uncertainty as to the outcomes have led to guarded adoption of the new
market based approach. African governments often state that the priority needs of domestic
electricity system is to increase accessibility from the current very low levels as against cost
reduction, which has been the motivating force in mature electricity markets.
More and more governments, however, have come to accept the failure of the state owned
development model. The recent reform efforts have also coincided with technological developments
and new market concepts, providing governments with more options in respect of reform
approaches.
Cote d’Ivoire Reforms
Cote d’Ivoire a francophone country is located in West Africa and borders Ghana, Liberia, Mali and
Burkina Faso. The population in 1998 was 15 million with per capita GDP of US$690. Inflation
rate averaged 3.4% during the period 1990 and 1998, with real GDP growth rate of 3.4%. Real GDP
growth rate in the period, 1980-90 showed
–0.4. %. The country had a relatively stable political
climate until 2000.
The installed capacity of the system in 2000 was 1300 MW with 55% hydro and 45% thermal. The
total number of connected customers was 525,000, giving 25% of population with access to
electricity. Over the period 1952 to 1990, the franchised monopoly model prevailed, with one
vertically and horizontally integrated generation, transmission, and distribution company; Energie
Electrigue Cote d’Ivoire (EECI).
EECI carried responsibility for all investments and rural
electrification and also engaged in the export of power to its neighbours. In 1994 the ownership
structure was 92.3% state, 4.7% CFD, 1.3% EdF and 1.3% small private shareholders. EdF
296
originally held 15%, however, this decreased progressively by agreement. The company is structured
on a limited liability basis.
By 1990, the company’s operations and finances had reached crisis level.
Accumulated debt
amounted to US$350 million, with the company fast running out of cash19. The problems faced were
poorly designed hydro-plants, poor maintenance, low equipment availability, poor levels of revenue
collection and transmission and distribution losses in excess of 20%, regular and frequent power
outages, poor quality supply and a catalogue of management errors.
The Government of Cote d’Ivoire was one of the first countries in Africa to initiate reform of its
power sector. The reforms have been carried out in two phases.
The initial reforms in 1991
involved the granting of an “Affermage Contract”, essentially an exclusive operating lease to a
consortium of two French companies, the Bouygues Group20 and EdF to take over operation and
management of the power system.
A new limited liability company; Compagnie Ivoirienne d’Electricite (CIE) was formed with
ownership structured as follows: State with 20%, SAUR and EdF 51%21, local private interest 24%
and employees 5%. As part of the reforms the system was unbundled horizontally, with the state
retaining ownership of the assets and responsibility for major capital investments and CIE accepting
operational responsibilities, including investments for working capital. EECI was established as an
asset holding company (as the Ministry of Finance continued to fund its capital investments),
overseeing the concession contract, planning future investments and supervising major equipment
overhaul and expansion projects on behalf of the state. CIE responsibilities included metering and
invoicing customers in its own name, daily operation and routine maintenance of the facilities and in
return it paid pays a fee to the state and EECI for the exclusive concession rights.
Regulation of CIE was effectively by contract between CIE and EECI, rates were however,
determined by the Government. The contract provided for a rate fixing mechanism, which allowed
a rate of return of 20% and also included an indexation formula. The formula took into account
cost as follows: CIE operating cost 35% to 40%, fuel cost 45% to 50% and investment 5% to 10%.
The operation of the system also provided penalties for non-performance. This approach to the
297
reforms enabled government to continue to retain ownership, whilst the operations and
management were subject to competitive tender, private operation and commercial management.
The Government also removed the exclusivity for power generation in 1990 and allowed
independent power producers entry to the sector. The first IPP licences were awarded in December
1992, one of the first in Sub-Sahara Africa, and programmed for commissioning between 1996 and
1998. The Power Purchase Agreement was on the basis of a “Take and Pay Contract” and all power
had to be sold to CIE, being the single purchaser.
The PPA was eventually signed between the Government and a new consortium22; Compagnie
Ivoireinne d’ Production de Electricite, (CIPREL) jointly owned by SAUR and EdF (in the ratio of
65:35). The first set of power plants of 99 MW came on stream in 1995, followed by a further 66
MW in 1996 and the final 110 MW in 1997, providing for a total of 275 MW of new capacity.
A second IPP licence was awarded in 1997, with commissioning phased over 1999 – 2000 and
required the licensee, CINERGY to build a set of thermal power plants on the basis of a Build Own
Operate and Transfer agreement (BOOT). The BOOT contract was to be for 23 years. The joint
venture partners are Swiss based Asea Brown Boveri, (ABB), Industrial Promotion Services, an
affiliate of the Aga Khan Fund and EdF. The project also benefited from US$30 million of IDA
credit.
As part of the institutional reforms, the Ivorian Government in 1994 created a National Electricity
Fund (FNEE), under the oversight of the Ministries of Energy and Finance with responsibility for
financing capital investments, servicing of debt and supervising regular payment by CIE of its fees
to government. EECI roles were therefore, reduced to being that of engineering consultancy, and
with continued responsibility also for planning and the execution of capital projects23.
Between 1990 and 1995 the number of customers went up from 440,000 to 480,000. Average
outages dropped from 50 hours per customer per year to 13 hours. Billing anomalies fell from 15%
to 3%, and collection rate increased from 50% to 98.5%24. In the first year of operation, CIE earned
a profit of US$2.5 million. Over the same period transmission and distribution losses fell, installed
capacity increased to 1004 MW. Between 1993 and 1998 system loss fell from 20% to 17%.25
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Access increased from 18% to 25% and workers were receiving much higher wages. Natural gas
replaced fuel oil, allowing for foreign exchange savings. Exports to Ghana, Togo, Benin and
Burkina Faso were now possible. Although the reforms did bring about several improvements a
number of problems surfaced.
Apart from the arrangements being too complex, there was lack of clarity regarding responsibility
for major maintenance and investments in the distribution system and in tariff setting. Problems
also developed with respect to the regulatory framework, as this activity involved some six different
state organisations, each with a different role in the power sector, hence there were problems of
coordination, duplication of effort, with no one state organisation having any real power over the
concessionaire. When performance targets were not met each side blamed the other. Non-payment
of bills by public users continued as a problem, however, on a reduced scale.
The second period of reform was instituted in 1998 after a review of the operations of the industry
was carried out. The decision was taken that the sector was to be opened up to further competition
after the expiration of the lease contract in 2005; generation plants were to be unbundled and
privatised. Distribution was also to be vertically and horizontally unbundled to provide for multiple
distribution companies. In the period up to 2005 the single purchaser model was to continue to
operate. Government also declared its intention to discontinue regulation by contract.
In the period between 1998 and 2000 the institutional structure was simplified into three public
bodies and EECI and FNEE were liquidated. One of the new bodies; I’Autorite Nationale de
Regulation du Secteur de I’Electricite (ANARE) operates as the industry regulator and carries the
responsibilities for economic regulation, issuance and renewal of licences, enforcement of licence
conditions, and regulation of service standards. In respect of setting tariff and granting of licences,
however, ANARE powers, are limited to an advisory role.
The Board of ANARE is made up essentially from government officials. As part of the new
structure the role of the Ministry of Energy is restricted to that of formulating and implementing
general policies for the industry, carrying out indicative planning and ensuring that investments are
technically sound. The executive, however, is still responsible for determination of rates, subject to
the terms of the contract.
299
There has been criticism of the new reform measures. ANARE has been created by decree and not
by statute and does not operate as an independent agency. Government still retains powers over
rate fixing. ANARE also does not have an independent source of finance and must depend on the
Treasury for annual subvention.
No mechanism has been established for participation by
consumers in the regulatory decision making process. Tariff continues to be set on cost-plus rate of
return basis with no incentive for efficient operation by the private operators.
The single purchaser system while an important improvement, only allows entry competition and
does not provide for competition in bulk electricity supply or competition in the large end user
market; hence, there is no pressure on bulk tariff and bulk suppliers to reduce cost. In 2001
Government announced that it intended to introduce a power market after 2005, however the
transitional arrangements necessary to move from a single purchaser phase were not been stated.
Although the Ivorian experiences have been regularly cited as a model to the rest of Africa, Girod
and Percebois26 state that:
“Many operators consider that a separate infrastructure firm, set up through an
operations contracting arrangement represents no more than an empty shell, which
cannot really invest because its fees are insufficient; further it may be preferable to opt
for the pure concession formula, however, this is more difficult to accept given
nationalist sentiment but economically more efficient”.
The Ivorian reforms essentially reflect the reform agenda adopted in France. France has been
reluctant to separate transmission from generation and allow the market to determine tariff. The
French have been the principal foreign investors in the former French colonies of Africa .
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The Reforms in Ghana
At independence in 1957 Ghana had one of the highest per capita income levels in Sub-Saharan
Africa, however, by 1993 Ghana’s economy had virtually collapsed. Average real GDP growth
during the period 1980 to 1990 was 2.3%, increasing to 4.3% during the period 1990 to 1998. GDP
in 1998 was US$7.1 billion. Inflation levels in the two periods respectively were 47% and 28.4%:
Per Capita income in 1997 was US$370.
Ghana has carried out one of the most thorough adjustment programmes in SSA27. As a result the
average annual increase in real GDP increased from 2.3% in the period 1980-1990 to 4.3% in the
period 1991 - 1998. Ghana discontinued the socialist and controlled economic model of
development in the early 1990s and aggressively embarked on a market-based approach with strong
support from the IMF and World Bank. As regards the state owned enterprises the reform agenda
first focused on commercialisation and the exposure of the enterprises, to hard budgets. The
divestiture, however, did not get off the ground until 1994 when foreign investor participation in the
Ghana Stock Exchange was allowed for the first time.
The installed capacity of electricity in 2000 was 1652 MW, increasing from 1032 MW in 1998. The
system consists of 1072 MW hydro-plants, made up of the 912 MW Akosombi station and the 160
MW Kpong station28, in addition to 550 MW of thermal capacity. Peak supply, however, is about
870 MW, while peak consumption is 1070 MW, giving a shortfall of 200 MW, made up mainly from
imports from Cote d’Ivoire. Imports in 1998 amounted to 18% of demand. Access to electricity
also increased from 20% in 1994 to 25% in 1998. Per capita consumption of electricity is 255 kWh.
Large industrial users consume 40% of output in Ghana, presenting a different consumption pattern
when compared to the other two case study countries.
The Volta River Authority (VRA), founded in 1961 operated as a vertically and horizontally
integrated state owned utility up to the early 1990s, providing the only source for generated power.
VRA owned 94% of national generation capacity with the remainder belonging to two large mining
and aluminium owner operators. VRA sold bulk power to two state owned distribution utilities; the
Electricity Corporation of Ghana (ECG) founded in 1967, and operating as a transmission and
distribution monopoly in the South of the country and Northern Electricity Department (NED), a
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subsidiary of VRA operating with similar monopoly rights to the North of the country. VRA also
sold directly to large users and at that time exported to Togo and Benin. In 1989 as part of the
government’s reform effort VRA’s operation was placed under a management performance
contract.
In 1994 ECG entered into an external management performance contract with a joint venture
interest, involving SAUR and EdF for the handling of the firm’s customer service activities.
Reforms introduced in the early 1990s, terminated VRAs monopoly on generated power and VRA
has since been required to compete with private power producers. Generators are also allowed to
trade amongst themselves, sell to intermediaries, to major consumers or sell directly to the two
distributing operations. With the liberalisation of the generation market, a number of IPPs were
awarded power purchase agreements in the latter part of the 1990s. The first set of PPAs went to
the Tokoradi Power Complex. The complex has been designed for installed capacity of 660 MW of
two CCGT plants each of 330MW. The investment is owned 50% by VRA and 50% by CMS
Energy of Michigan USA. A number of other PPAs were also awarded; however, construction of
some of these facilities was never initiated. Government was also developing a 125 MW power
barge, which was to be installed at Efasu in the western region, and the intention was to privatise
this facility by a long-term operating lease.
In 1998 Ghana went through a major power crisis due to the low reservoir levels in the two existing
hydro-facilities, Akasombo and Kpong. As a short-term measure two power purchase contracts,
with duration of 18-24 months were signed; one with a UK firm Aggreko Plc., and the other to
Cummins Power Generation Plc, each for 30 MW additional capacities. Both came on stream after
2000.
Despite earlier liberalisation of generation, Ghana has not been able to meet its power needs. The
previous administration announced further reforms calling for a move away from what is a single
purchaser model to introduce vertical and horizontal restructuring of the industry, as well as to
provide for the introduction of product market competition in bulk power supplies.
Under the new reform measures, VRA’s transmission system is to be unbundled and incorporated,
as a fully state owned National Grid Company (NGC). NGC is to be given a licence to operate as
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an electricity transmission operator.
In this capacity NGC will only be required to provide
transmission wire services and will not participate in the trading of bulk power. The distribution
assets of ECG and VRA are to be horizontally unbundled into five regional distribution companies.
Government is expected to sell 51% of the equity in each of the five companies to strategic private
investors and to retain 49%.
A wholesale power market is to be established providing for a bilateral contracts market and a
balancing spot market. The contracts market will provide for agreements for physical capacity
between generators on one side and large users, distribution companies and intermediary traders on
the other side. The market for large end users (over 5 MW) is to be liberalised, enabling these users
to enter the power market or contract directly with generators for their supplies.
An independent entity, a Market Administrator and Systems Operator (MA and SO) is to be
established to carry out the market administration and systems operations functions, operate the
price discovery system, determine dispatch instructions, and manage the settlement arrangements.
The MA & SO is to carry a three-member governance board, made up of one representative from
the regulator, one from the Energy Commission and an industry representative. Essentially, Ghana
has opted for a non-stakeholder board to supervise the power market operation; however, the board
required to supervise the electricity market is to include two public officials out of a membership of
three. This could be seen to involve too much public involvement in the liberalised market
operation.
Government also introduced a Public Utility Act in 1997, providing for the establishment of a multisector utilities regulatory agency based on the state regulatory system in the USA to regulate the
energy and water sectors. Telecommunication has a separate industry regulator. The new agency,
Ghana Public Utilities Regulatory Commission (PURC) was established in 1998 as an independent
authority. Theoretically it is supposed to be free from ministerial control and direction.
Administratively, PURC comes under the umbrella of the Office of the President, with the
Chairman accountable directly to the Office of the President. PURC consists of a board of nine,
with stakeholder representatives from labour, industry and commerce and domestic consumers, as
well as four professionals selected as independent experts and appointed by the President. It is to be
funded and eventually self-financed from a levy, imposed on the industry. Its statutory legal powers
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are to grant licences, regulate tariff and standards, promote competition, provide for protection of
consumers’ interest and advise the Government on industry policies. The Board of the Commission
is supported by a professional secretariat with a full-time Director.
An additional institution
established under the Public Utilities Act is that of an Energy Commission to act as an advisory
body to the Ministry of Mines and Energy and to co-ordinate energy policies.
The changes with respect to the new industry structure and market arrangements are to be
implemented over a transitional period of five years, 2000 to 2005. A new administration however
came into power in 2001 and has delayed the implementation, while carrying out a review of the
existing policies29. Ghana also intends to play a leading role in the development of the proposed
West African Power Pool.
Ghana is one of the first SSA countries to declare its intention to establish a power market for bulk
supplies; however, the Government involvement as joint venture partner in the generation and
distribution companies is likely to circumscribe the competitiveness of the market. It is very difficult
to see how a competitive market structure will be able to develop when Government owns the
major generation company and that state company is also a 50% shareholder in the main thermal
company. Additionally, transmission is to be fully owned by government and the five proposed
distribution companies are to be 49% owned by the state. The combination of rate of return
regulation, based on the US system, continued major state ownership at all phases of the ESI and
expansion of private power by long term power purchase agreements will not provide the necessary
competitive pressures for improved efficiencies and lowering of cost. All indications are that these
reforms are not well thought out and that effective competition is unlikely to develop. The major
problem is that Government is still reluctant to devolve itself of ownership of the industry despite
its stated public policy of the private sector being the engine of growth, reflecting continued mistrust
of private ownership and the market in the essential utilities.
Ghana estimates that the capital requirement for the system over the 5 year period will exceed US$1
billion dollars. It is unlikely that the state will be able to finance its share of investments to be able
to hold on to 49% of equity in the respective companies selling of shares on the domestic stock
market or experience a reduction in its equity holding is a likely consequence .
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The Tanzanian Power Sector Reforms
The Tanzania electricity sector displays one of the most extreme case of poor performance of a state
owned electric utility. The period 1960 to 1980 saw serious decline in economic performance with
the result that by the mid-1980s, the Tanzanian economy was at a state of collapse. GDP in 1998
was US$7.8 billion and although the Tanzanian population of 32 million is slightly larger than
Kenya, its economy is only about 75% the size of that of Kenya.
Up until the 1990s, Tanzania followed an extreme socialist model with the state owning most assets
and responsible for all development. Over 400 state enterprises came into existence. Over the two
periods, 1980-1990 and 1990-1998 real GDP growth was 2.9% and 2.8% respectively. Tanzania is
one of the poorest countries in the World, with per capita income in 1997 of US$210. The country’s
external debt reached US$7.8 billion in 1998 and the country had come to exist mainly from donor
support and food aid.
In 1990, the socialist policies were reversed and Tanzania with strong support from the World Bank,
the IMF and a group of donor agencies led by the Scandinavian countries, set about major reform of
the economy. The reform is attempting to reduce the state’s role in production and in regulating
economic activities and is placing more emphasis on macro-economic stability and fiscal prudence.
The market based approach; with the private sector assigned the principal role to drive the
production process, formed the foundation of the policy shift.
The macro-economic fundamentals between 1995 and 2000 have been positive. Real GDP growth
has averaged just over 4% per annum, inflation fell from 21% in 1996 to 5.9% in 200030 and the
exchange rate has more or less stabilised. The state owned enterprises have been a major drag on
the fiscal budget31 ; a result reforming this sector via privatisation and introduction of competition
became a central platform of the reforms.
The installed capacity of the Tanzania interconnected electricity system amounted to 712 MW in
2000. An additional 28 MW formed the isolated system. The system is dominated by hydro, with
installed capacity of 555 MW, the balance of 167MW being thermal. Additional capacity of 100 MW
of thermal power was due to be operationalised in early 2002. Peak demand in 2000 was 440 MW,
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in principle giving a substantial reserve margin of around 80%32. The hydrological situation,
however, is such that variation in the hydro-generation can result in 40% lowering of available
capacity over the average level. There have been three periods of drought, resulting in major load
shedding since the 1990s, the most recent being in2000, when 16 hour daily power cuts became
common. Power outages continue as a regular experience despite the addition of 75 MW of thermal
capacity in 1995 and 180 MW hydro-capacities in 2000. Less than 7% of the population has access
to electricity and in the rural areas access is less than 1%.
The Tanzania Electricity Supply Company (TANESCO) has been the sole vertically and horizontally
integrated electricity supplier on the mainland and supplies bulk electricity to Zanzibar. There are
two small private producers and both supply bulk power, amounting to a combined capacity of 5
MW to the grid. Tanzania also imports power each year via cross-border connections with Uganda
and Zambia, amounting to 8 MW and 5 MW respectively.
Electricity production in Tanzania started in 1908 when the Germans established a plant to supply
the railway workshop. In 1920, the British administration established an electricity department
under the direction of the General Manager of Tanganyika Railway to provide supplies to the public.
By 1931 two private companies emerged and were each given separate licences; one of 60 years and
the other of 80 years. Government in 1964, however, nationalised the private operators and merged
the existing electricity interests into a new entity, TANESCO as a limited liability company with the
Government as the sole shareholder. TANESCO operates under a 55 year licence awarded in 1957.
TANESCO has been run at the subordination of the Government with relatively little autonomy.
The system of pricing has over the years reflected excessive subsidisation. In terms of tariff policy
the company is allowed to increase prices by 5% each year. Increases above 5% and up to 10%
require the approval of the sector ministry and over 10% that of the Cabinet.
TANESCO’s tariff has over the years failed to recover cost. In the early 1990s the tariff fell from
US¢11.31/kWh to ¢4.32/kWh, before increasing to ¢9.38/kWh in 199433, mainly because
government failed to pass on increased cost resulting from devaluation and inflation. Residential
consumers which account for 60% of total sales in 2000 were supplied at rates which were 40% to
50% below long run marginal cost, and Zanzibar its largest customer amounting to 5% of sales, paid
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rates which were less the 50% of LRMC. Industrial customers were required to cross-subsidise
residential customers and in doing so pay more than 40% above LRMC34.
Government and the World Bank responded to the weak technical and financial performance of
TANESCO initially by seeking to improve the system’s technical and administrative capabilities. A
series of World Bank projects, funded under IDA’s concessionary credits sought to modernise the
plants, increase capacity and improve the management and technical operating capabilities. A
performance management contract was introduced in 1996 and an attempt was made to raise prices
to LRMC. Government responded with further reform measures in 1996, discontinued
TANESCO’s monopoly for generated power and under hurried and non-competitive conditions,
(sole source negotiation) awarded a power purchase agreement to a Malaysian consortium,
Independent Power Tanzania Ltd (IPTL).
Construction of the IPTL 100 MW facility was
completed in 1998, but up to October 2001 the plant had not been commissioned due to a dispute,
which developed over the bulk tariff. The matter went to arbitration and the arbitrators ruling in
December 2000 disallowed US$38 million of capital charges, which was to be recovered as capacity
charges.
Investment was originally estimated at US$90 million, but on completion the IPP declared costs of
US$150 million. The contract called for a slow speed diesel; however, a medium speed diesel was
installed. Typical cost of medium speed diesel was of the order of US$850/kW to US$900/kW,
compared to the project cost at US$1700/kW. TANESCO and Government are required to bear all
IPTL’s significant risks associated with this project, including cost overruns, taxation and inflation.
The open ended sovereign guarantees provided mean that Government will have to meet the
stranded costs incorporated in the high capacity charges. The introduction of IPTL into the system
will result in a 20% average increase in tariff, which at over US¢10/kWh is already one of the highest
in Africa.
Government also entered into a second agreement in 1997 to convert 112.5 MW of TANESCO’s
diesel turbine capacity to natural gas as part of a gas to electricity project, involving extraction of
natural gas from Songo Songo Island and transporting via a 25 km marine and a 217km land
pipeline to the Dar es Salaam Ubungo Plant. The project is expected to cost US$285 million.
Equity is equivalent to US$72 million. The lead partner is AES Americas Inc., and the consortium of
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financiers includes the World Bank, European Investment Bank, and the Commonwealth
Development Corporation. Government’s very small equity position (less than 5%) is to be held
through TANESCO and one other state agency. The contract is structured as a Build Own and
Operate (BOO) instrument , and the duration of the PPA is 20 years. With the IPTL court case this
project also ran into problems and has since been renegotiated to include the existing partners with
the new date for commissioning being 2003, the gas development cost, however, is included in the
capacity charge and the result is a relatively high unit charge.
TANESCO, however, remains the sole supplier to end users, as the IPPs are required to sell all bulk
electricity to the vertically integrated utility. Although there are 400,000 connected household users,
over 50% are based in Dar es Salaam the main urban centre. The rural areas rely on wood and
charcoal to meet their energy needs.
The company has continued to experience inefficient operation and poor financial performances,
despite charging an average tariff of US¢10/kWh. Its system losses have been estimated at 25% to
35%, with over 50% coming from illegal connection, incorrect billing and corrupt sales practices.
The company has been recovering revenues from less than 60% of power produced and receivables
amount to over 6 months revenues at times. Government and public enterprises account for over
75% of receivables, and Zanzibar its largest customer with 5% of sales, has failed to pay its bills
which are being invoiced at under US¢3/kWh.35
The company’s debt equity ratio in 2000 was 90% and this crippling debt burden means that
government has had to meet most of the company’s long-term debt servicing obligations to the
donor agencies. The company is over-manned and needs to shed 30% of its work force. Its
productivity levels are very poor, less than 57 customers per employee in the year 2000. Generation
outages reached 1130 hours in 1995 and have fluctuated widely over subsequent years.
TANESCO’s annual revenues in 1997 amounted to US$174 million, and for the first time for
several years the company posted a profit of US$5.6 million. The losses, however, continued after
1999. The company’s poor financial performance has become a major concern of both the
Government and the World Bank.36
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These developments led to a decision by Government in 1998, to privatise 51% of the vertically
integrated company. The researcher as lead advisor on public enterprise reform to the Government
was able, however, to influence the authorities to revisit this decision, and a new policy was
announced in October 1999 calling for vertical and horizontal unbundling, the introduction of a
bulk electricity market and increased levels of competition in the electricity supply system.
The Government faces difficulty in implementing this new policy, since it has already committed
212 MW of capacity of a system with 440 MW peak demand to 20 year PPAs and a portion of the
capacity charges reflect stranded cost. The question arises as to how much competition will be
possible in such a situation. The new policy direction, in addition to vertical separation calls for
horizontal unbundling of generation, into three companies, two hydro and one thermal, two regional
distribution companies, separation of social electricity from commercial electricity and the
establishment of an independent multi-sector regulatory agency. There is to be one single
transmission operator, preferably with its assets owned by Government and leased to an investor for
private operation. In order to facilitate increased competition in the electricity supply system, third
party access is being considered for the transmission and distribution sectors, with bypass for large
end users. The new policy calls for private investors to play the leading role in providing future
investments and in the operation of the industry. There is still, however, pressures from special
interest groups for Government to maintain major equity ownership in the generation and
distribution companies targeted for sale.
A multi-sector regulatory Act was passed in April 2001 and an Energy and Water Utility Regulatory
Authority is to be established in 2002.
Separate industry legislation is also scheduled for
introduction in 2003.
Over the period 1998-2000 TANESCO’s operating and financial performance has, however,
deteriorated to an alarming level. Government has, therefore decided as an interim measure to
award a two-year management performance contract to a private management firm from March
2002. At the end of the two-year period the unbundled generating and distribution businesses are to
be privatised.
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Tanzania will not be able to attract merchant plant type investors. At the other extreme long term
PPAs for the entire production will need to be avoided. The solution would, therefore, seem to be
to allow distribution companies to acquire part of their power needs through direct contract from
the generating companies; including the assignment of the TANESCO’s PPAs, and for a balancing
or spot market to operate to facilitate the integration of transmission with generation.
The
expectation is that a contracts market will operate in the initial years gradually leading to bilateral
contracting and a balancing spot market.
In order to introduce competition in bulk the electricity market, considerable changes will be
required to the institutional structure, technical system, especially in the load dispatch centre and
telecommunication system. New water rights legislation will be required and the future role of the
Government, especially in allowing for independent operation of the market and the regulatory
regime, will need to be assured.
The financial structure of the industry also presents a major problem in respect of the very high
capacity payments of the two PPAs, which are in effect expensive foreign debt financing, and when
rolled into the cost structure leads to unacceptably high average tariff. These challenges, which
Tanzania faces, have yet to be successfully overcome in any SSA country.
Regional Interconnection Opportunities
The Southern African Power Pool (SAPP) provides the first formalised market for cross-border
electricity trading. Regional electricity trading provides an opportunity to reduce power systems
cost. The opportunity to reduce costs arises from the mis-match between countries which have
economic hydro-resources and South Africa’s excess fossil-fuel capacity and the countries with the
greatest load or the opportunity to replace high cost thermal production as is currently the case with
Botswana, Namibia and Zimbabwe.
Constraint to trade arises from physical, political and market factors. Currently interconnection is at
the level of the sub-regions; East Africa, Central Africa, West Africa and Southern Africa. A
number of studies such as the Tanzanian/Zambian Transmission and the SAPP Interconnection
studies are underway exploring the feasibility for wider interconnection in the SAPP system. Most
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trade at present is carried out at the border and transmission prices tend to reflect marginal cost of
the exporting country, covering transmission losses and contribution to fixed cost, rather than
LRMC. Overall prices are low.
The existing structure of SAPP is that of a loose pool and builds incrementally on the existing
structure of electricity trade in the region, based on long term contracts. SAPP protocol which came
into being in 1995 and which involves 12 countries provides a framework for such contracts and
seeks to complement them with an additional framework for spot trading.
The larger SAPP market provides the best opportunity over the short term for a power market to
develop to meet the lower cost electricity needs of the high cost producers like Tanzania and Ghana.
Countries like Botswana, Namibia and Swaziland that are interconnected into the SAPP Pool and
have emphasised developments in transmission and distribution benefit from costs of under
US¢/3.5 kWh. A factor, which will aid the process is the increased willingness of SSAP member
states to discontinue a policy of self-sufficiency in generation and to depend on their bulk power
needs from cheaper neighbouring states.
SAPP member states also need to cooperate and develop common legal and regulatory framework.
In fact a regional regulator for the network sector of each country would be strong incentive to
foreign investors. IPP faced with the opportunity for multiple purchasers would have greater
confidence in its ability to sell to several large industries with strong balance sheets and therefore,
minimise requirements for sovereign guarantees to be given by the respective governments.
Conclusion and Policy Implications
The experiences of the three case countries and the rest of the SSA are that to date they have
conformed to the first two phases of the development model that of the state owned franchised
monopoly and single purchaser phase. The three case countries and the most of the rest of SSA
countries have moved away from a single franchised state monopoly in generation by liberalising the
generation market and allowing entry of new IPP plants into the generation sector.
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In the post-independence period the power sector formed a central policy tool of the state
development model. The state owned franchise monopoly came to be entrenched as the industry
structure in all the countries. Many of the problems of the sector have, therefore, been a part of the
wider problem of management of the economy. The initial response of governments has been to
seek solutions, which involved continued state ownership and maintenance of the vertically
integrated utility. Policies, which are pursued to improve the performance of the sector in isolation
of macro-economic policies, however, have not been sustainable. State operated power utilities, even
where they have been exposed to commercial principles and hard budget constraints have often
failed to provide for sustainable improvements in performance, as is clearly demonstrated in
Tanzania. In order to avoid financial collapse of the system, the Government has had to bring in a
private external management contractor in anticipation of restructuring and privatisation.
While independent power production through a power purchase agreement provides the
opportunity for the mobilisation of private capital and private sector participation as is seen in Cote
d Ivories and also evidenced in Kenya, it does not provide the full answer. Weak local capital
markets, lack of potentially strong domestic partners, imperfect legislation, especially in areas of
water rights, property rights and regulatory frameworks, as well as weak court systems and antiprivate sector sentiments, still persist. IPP/PPA arrangements should be seen as a short to medium
term solution; hence, it is important not to set too long a term for such contracts. Governments in
their reform programme should separate transmission from generation and the opportunity should
be taken to link prices to the market or else the opportunity for product market and retail
competition will be put off indefinitely.
IPP/PPA with take and pay commitments may come to impose serious problems in terms of future
external debt obligations, should economic recession set in and demand is not realised and the take
and pay foreign obligation has to be met, as experienced by the East Asian countries in the period
after the financial shocks of 1998.
The question therefore, arises can the systems of SSA countries, given their characteristics of being
highly hydro-based with small markets graduate to a competitive power market or Phase Three level
of development? An important development working in the favour of these countries is the
emergence of new technology, which has reduced the minimum scale plant size, especially for
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thermal systems. Most SSA generation plants are below 75 MW; however, today’s technology
provides for minimum scale plant size of as low as 30 to 40 MW.
Lending institutions in the region such as the ADB, however, as late as 1999, have expressed
scepticism as to how far the structural options and competition can be taken by SSA countries in
reforming their system.
The ADB36 in 1999 states that:
“In comparison with the telecommunication sector the electric power sector does not
present scope for segmentation of services --------.
Dictated by such characteristics the only segment that has opened up for private
participation thus far in Africa is the generation segment of the industry. And even
then, there is still debate about whether the preponderance of small scale power
generation by private users is more efficient than large scale production”.
The view that public ownership or the franchised state owned electric utility monopoly is strategic
politically and economically to economic development has proven from the experiences of SSA
countries to be flawed. Centralised control by Government not only fail to bring about efficient
results, it severely limits the amount of investment capital available to the sector.37 Despite the
disastrous experiences of state ownership and operation all three case study countries are still not
convinced that the state should withdraw from the sector in place of full private ownership and
operation. There has been reluctance on the part of many political leaders to leave such a key sector
of the economy to the hidden hands of the market. Additionally, there is also the fear that the
market will not respond to the needs of the rural economy and the poor.
Can the Bolivian experiences provide a road map for the reform of the three case countries?
Bolivia shares most of the macro-economic and systems characteristics of SSA countries; except
that when Bolivia entered the reform phase it had a more efficiently operated electrical supply
system. Since Bolivia, other small markets such as Panama and El Salvador have introduced
radical power market reforms. In fact El Salvador envisions going beyond the structural option
of a bulk electricity market and embrace retail competition or Phase Four level of development.
The track records of these smaller third generation reformers are not yet well established and the
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existing information is
inadequate for us to arrive at any definitive conclusions. However,
changes in the industry technology, economic theory and the growing body of examples, clearly
suggest that radical reform is an appropriate structural reform option to pursue for small electricity
systems.
In terms of future policies governments must be prepared to limit their role in the industry to policy
matters, to allow competition in the sector of the market where competition is obtainable and
provide legislative framework, which allows for independent and transparent regulation. At the heart
of the problem is the willingness of governments to remove themselves from interfering in the price
setting decision-making process and to allow the private sector to take responsibility for investment
and ownership of the industry.
SSA countries will not be able to fund the capital needs, variously estimated at US$ 20 billion that
will be needed over the next 10 years for the electricity sector from public finance. Without
independent regulatory regimes, free from political intervention in economic regulation, these
countries will not attract the high levels of private capital that will be needed. Governments of the
region will need to provide the legislative framework and the market rules and not be directly
involved as an active participant in market operation.
A regional power market as shown earlier through SAPP offers an alternative option to pursue a
competitive bulk electricity market structure.
Again in terms of policy implication, individual
governments will need to discontinue policies, which call for self-sufficiency of power generation.
The SAPP region had a capacity of over 68000 MW and peak demand of just over 35000 MW in
2000; there is therefore, excess capacity to accommodate regional trading. Prices have, however,
continued to be established below long-run marginal cost of operation. A fully working regional
power market would lead to prices which reflect LRMC and although this would be of the order of
US ¢4/kWh to ¢5/kWh, this is significantly lower than the cost of production of bulk power in high
producing countries where costs have been estimated to be as high as US ¢8/kWh.
Irrespective of the restructuring option chosen, the evidence clearly shows that the period since the
mid-1990s has marked the end of an era for the sole vertically integrated franchised state owned or
franchised multiple distribution electric utility in Sub-Saharan countries. The future directions will be
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one of increased levels of competition and increased levels of private ownership and operation of
electric utilities.
End Notes
1. World Bank, World Development Report 1999 Knowledge For Development, Washington,
D.C. (1999)
2. Sub-Saharan Africa has 8% of the hydropower potential and 6.2% of the world’s natural gas
potential.
3. Kevin Morgan, Electricity Supply Industry Restructuring and Regulatory Development in
South Africa, Sub-Saharan Power Conference, Midrand, South Africa (February 1999), p.3.
4. Gunter Schramm, “Issues and Problems in Power Sector of Developing Countries”, Energy
Policy (July 1993), p.735.
5. M.T. Hadjimichael, M. Nowak, R.S. Sharer and A. Tahari, Adjustment for Growth: The African
Experience, Washington. D.C., IMF Occasional Paper Series (October 1996), p.1.
6. G.E. Mills, Public Enterprise in Commonwealth Caribbean with Particular Reference to
Jamaica and Trinidad, Kingston, Jamaica, UWI. (1995), P.5.
7. “Private goods” can be defined as those that are rival (consumption by one reduces
consumption available to other users) and excludable (users can be prevented from consuming
its output). In contrast, “public goods” are neither rival nor excludable.
8. World Bank, Lending for Electric Power in Sub-Saharan Africa, Washington, D.C., (1995),
p.13.
9. See Schramm (1993), average tariff from a sample of sixty developing countries fell from
US¢3.78 kWh in 1988, a reduction of 32% in real terms. Average tariff in 1988 was 4.46 ¢/kWh
compared to average US¢8.07/kWh in-developed countries.
10. After the first set of reforms was introduced in Cote d’Ivoire in 1991.
11. Alan Townsend, “Energy Access; Energy Demand and Information Deficit”, in Energy
Services for the World Poor, Washington. D.C., World Bank (2000), p.11.
12. Luis Gutierrez, “How do Sub-Saharan Africa Utilities Compare”, in Power Sector Reform and
Efficiency: Improvements in Sub-Saharan Africa, Washington, D.C., Joint UNDP/World
Bank ESMAP (1996), p.53.
13. Jacques Girod and Jacques Percebois, “Reforms in the Sub-Saharan African Power Industries”,
Energy Policy, Vol. 26, No. 1. (1998), p.28.
315
14. Michel Kerf and Warrick Smith, Privatising Africa’s Infrastructure: Promise and Challenge,
Washington. D.C., World Bank Technical Paper Series, No. 337 (1996), p.5.
15. Oliver White and Anita Bhatia, Privatisation in Africa, Washington. D.C., World Bank (1998),
p.123.
16. Kerf and Smith, op.cit. p.21.
17. Gutierrez, op. cit., p.57
18. Kerf and Smith, op.cit. p.5.
19. Ibid, p.16.
20. The Bouygues Group through its subsidiary SAUR International was already involved in water
distribution in Abidjan. The contract was for 15 years, lasting from 25 October 1990 to 2005.
21. SAUR owned 33% and EdF 18%. SAUR and EdF formed a holding company: Societe,
Internationale de Services Publics: with ratio of stake holding 65:36. EdF also hold 35% of Saur.
22. The original PPA was with a consortium, Compagnie des Energies Nouvelles de la Cote
d’Ivoire, however, it was suspended in 1994 and replaced by the CIPREL project using newly
discovered oil and natural gas.
23. Jacques Girod and Jacques Percebois, “The Electric Power Sector in SSA: Current Institutional
Reforms,” in Power Sector Reform and Eficiency: Improvements in Sub-Saharan Africa,
Washington, D.C., Joint UNDP/World Bank ESMAP (1996), p.99.
24. Infrastructure Development in Africa, Oxford University Press (1999), p.147.
25. Allexon Chiwaya, “Malawi Power Sector”, in Reforming the Power Sector in
Africa, ed., M.R. Bhagavan, London, Zed Books (1998), p.46.
26 Girod and Percebois, op.cit. p.100.
27. Ajay Chhibber and Nemat Shafik, “The Inflationary Consequences of
Devaluation with Parallel Markets: The Case of Ghana”, in Economic Reform in SubSaharan Africa, eds., Ajay Chhibber and Stanley Fisher, Washington, D.C., IMF (1991), p. 39.
28. Although the installed capacity of the two hydro-plants is 1072 MW, the firm
capacity is more like 670 MW due to variation in the water levels in the reservoir resulting from
variation in rainfall pattern.
29. Ministry of Energy “Energy for Poverty Alleviation and Economic Growth:
Policy Framework, Procurements and Projects”, Ghana, (2002).
30. Economist Intelligence Unit, Tanzania Country Report, London (August 2000),
p.6.
316
31. World Bank, Adjustment in Africa; Reform, Results and the Road Ahead,
Oxford University Press (1994), p. 101.
32. Stig H. Moberg, The Tanzania Power Sector, Swedish International
Development Agency, Tanzania, (2001) p.12.
33. M.R. Bhagavan, Reforming the Power Sector in Africa. London, Zed Books
(1998), p.92.
34. Stig H. Moberg, op.cit. p.16.
35. Deloitte & Touche, Financial Review of Performance in Tanzania, Internal Tenesco Report
(2001), p. 32.
36. ADB, Op.cit. p.144
37. World Bank Aid Memorie Tanzania Project Development No. 6, World Bank, Washington D.C.
(2001) ,p 8
317
Chapter 8
Analysis and Conclusion
Global Trends in Electricity Sector Reforms
Since 1990 there has been a global trend towards liberalisation and disintegration of the electricity
supply industry. Pollitt (1997)1 states that the electricity industry has been undergoing liberalisation
in 51 out of 62 countries he studied, with privatisation in 30, and vertical separation in place or
planned in 27 countries. Izaguirre (1998)2 on the basis of World Bank’s data states that 70 countries
have involved the private sector in their electricity supply industry between 1990-1999, with total
investments of US$110 billion.
This transformation is being fuelled by technological developments, which have eliminated aspects
of the economies of scale characteristic, which traditionally persisted in certain sectors of the
industry. The developments have radically changed electric utility economics for the foreseeable
future. Both the empirical argument and the theoretical evidence presented in the case countries,
strongly support the thesis that the industry is experiencing a process of competitive transformation,
during which the electricity industry is moving away from the vertically integrated franchise
monopoly structure, public or privately owned and which has persisted for most of the post- war
years, towards one which offers consumers more choice in sourcing their energy needs. In this
process of change three distinct phases have been identified, that of the purchasing agent, the bulk
electricity market and retail competition.
The Structural Options
Some countries have tried to introduce reforms within the framework of the vertically franchised
state owned monopoly structure. Invariably this has taken the route of internal privatisation or the
introduction of private sector methods of operation, whilst retaining public ownership. The SSA
countries, Jamaica and the UK reflected this experience. Whilst initial improvements are realisable
they are not sustainable. The introduction of new methods and procedures of operation have been
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insufficient to significantly improve economic performances that are sustainable. This was clearly
brought out in the Jamaican experiences between 1998 and 2000.
The structural reforms introduced in Scotland provide an example where the vertically integrated
monopoly structure was retained and two privately owned and vertically integrated monopolies were
created, accompanied by pubic regulation. The expectation was that yardstick competition would
have been sufficient to provide incentives to the private monopolist to perform efficiently. The
reforms also permitted trading amongst the two monopolists (across an interconnector), third party
access was allowed and the large consumer market segment liberalised. There were, however, serious
entry barriers to the competitive sector, no new independent power producers entered the
generation sector between1990 to 1998. Up to 1996 the second tier retail market had grown to
amount to less than 6% of the overall retail market and most of this development came from the
two incumbents trading as second tier suppliers in each other’s market. It proved extremely difficult
for the regulator to prevent each of the vertically integrated monopolists from exploiting sensitive
information of third parties to further their own interest.
The opportunity for competition for corporate control of the two incumbents was also frustrated by
the golden share conditions incorporated in the two companies’ articles of association. The Scottish
reforms sought to recognise horizontal and vertical economies and to accommodate non- economic
goals. The net effect has been that the Scottish electricity tariff, which was the lowest in the UK in
1990, developed to be the highest by 2000. Littlechild (1996)3, the electricity regulator at that time
expressed scepticism as to whether such a structure was conducive to competition and remarked
that the Scottish structure was anomalous to changes taking place at the global level.
Scotland has since had to conform to the European electricity competition directives and as a result
several changes are under consideration, including integration into the E&W market, interconnector
trading and the establishment of an independent systems operator so as to provide for a more
transparent and competitive environment.
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Purchasing Agent as a Reform Option
The reforms in Jamaica, Northern Ireland, Cote d’Ivoire, Ghana and Tanzania reflect the policy
choice of countries that have opted for the purchasing agent phase of development. At this stage,
the critical changes have been liberalisation of the generation sector and introduction of competition
for new capacity, with competing generators given the right to sell to a single or principal buyer. In
the pure purchasing agent model, third party access is not permitted; hence all consumers remain
captive buyers. Modifications are sometimes introduced, providing for bypass for very large
industrial consumers to contract directly with generators.
At this phase of development, the critical structural issue is whether generation is separated from
transmission. Separation has the advantage that it reduces the problem of self-dealing and internal
conflicts of interest. Where third party access and bypass are allowed for large industrial consumers,
additional competitive pressure is introduced on the incumbent to improve its performance.
The structural relationship of transmission and distribution is not critical at this stage. Northern
Ireland and Kenya in their restructuring kept transmission and distribution integrated. However, if
retail competition is the long term objective, transmission should be unbundled from distribution so
as to reduce the problem of market power.
Sub-Saharan Africa, East Asia and the European Union reforms have adopted the purchasing agent
model. The motivation is that it relieves the national budget of the responsibility for capital to
expand the industry and involves less structural upheaval. To a large extent, the status quo can be
maintained as the state can continue to retain ownership of the incumbent integrated utility. Many
SSA countries are still fearful of the uncertainties of free market and private ownership and often
face intensive pressure from a coalition of interest groups (labour, management and the churches) to
retain state control.
The EU has also adopted the principal agent model except that bypass of the network has been
mandated to allow up to 33% of end users (eligible consumers)4 choice in sourcing their supply. The
French have significantly influenced the European Union’s policies. France has been reluctant to
disintegrate its electricity utility and provide for private operation. The Principal agency model as a
form of restructuring is considered a likely option where economies of scale is still strong and
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opportunity for competition is weak or non-existent and where the monopoly structure is still
considered the most efficient arrangement. This is said to apply to the French dominated nuclear
system.5 Economies of scale are still obtainable with large nuclear plants. Uganda has also opted for
a purchasing agent model because the hydroelectric Owens Falls power complex dominates the
relatively small system of less than 200 MW.
France like Scotland has had to introduce reforms recently to meet the European Union electricity
competition directives. In 2000 France introduced legislation designed to restructure the ESI. The
changes call for accounting, operational and management separation of transmission from EdF’s
generation business into a new division, questionnaire du reseau public de transport (GRD) as well
as and accounting and operational separation of distribution from transmission. The separated
distribution business and 170 non-nationalised distributers were designated as qestionnaire des
reseaux de distribution (GRDS). The Act also provides for the establishment of an independent
industry specific regulator, Commission de regulation de I'electricite. (CRE)6 The regulator is
empowered to regulate third party access, interconnection and the system operator.
In the principal agency phase the regulatory responsibility resolves itself around preventing the
natural monopoly network sector from leveraging its market power for its own interest and ensuring
competitive procurement of new capacity. If generation, transmission and distribution are vertically
integrated, regulation is required to guard against self-dealing and conflicts of interest. In the case of
France, CRE’s power is limited to references to the Conseil de la Concurence.
The purchasing agent structure is superior to that of the vertically integrated franchise monopoly
model in that it reduces the regulatory burden. A certain amount of capital market pressure is
introduced into the industry and the opportunity for inter-utility competition is enhanced where
generation is vertically and horizontally unbundled. The structure also provides incentives for more
efficient levels of investment in capacity and this was demonstrated by the experiences of the
Northern Ireland system where inefficient oil plants were replaced with cheaper natural gas plants.
Its major problem is that the structure does not readily accommodate retail competition should the
decision be taken at a later date to provide for choice for all consumers. If third party access is
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permitted for the large industrial users, then the small household domestic consumers are left to
shoulder any stranded cost, which may have resulted from the poorly designed power purchase
agreements. For those countries that have introduced a disproportionate amount of power purchase
agreements with elaborate sovereign guarantees incorporated in the PPA’s, there is the risk that the
national budget may have to shoulder the foreign capacity charge obligation should there be
economic recession and the forecasted demand fail to materialise.
Bulk Electricity Markets as a Reform Option
In the third phase of market transformation, that of the bulk electricity market, competition
amongst horizontally unbundled generators is introduced, as was the case in England and Wales in
1990 and Bolivia in 1996.
In both cases the reforms did not have to progress through the
purchasing agent phase. Instead radical unbundling was introduced, with the structure being
transformed from the franchised monopoly stage to the bulk electricity market model. The bulk
electricity market arrangement adopts most of the principles of commodity markets, however,
electricity inter-changeability is not as simple as other commodities, such as gold or oil as it cannot
be stored for later use. One shipment of electricity at one point in time is not a perfect substitute for
another shipment at a different point in time. This makes it difficult for arbitrage in electricity as is
possible with other commodities. There are strong vertical economies between generation and
transmission, despite physical unbundling, and the need for system balance sets up a contradiction
between the requirement for central coordination and the individual action needed for competition.
Market power cannot therefore be entirely eliminated.
Bulk electricity markets entails bilateral contracting between generators and multiple local
distributors, supported by a centralised pool, as was the case of E&W market (during the first 10
years) and the Bolivian market or a balancing spot market which provides for settlement balancing
between contracted amounts and physical flows, as is the current E&W and Scandinavian markets.
The local distributors, in addition to paying for energy and related services are also required to pay a
wheeling charge for use of the network.
The important structural decision revolves around the separation of transmission from generation
and the creation of horizontally unbundled independent generation companies. If transmission is
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integrated with generation as was the case in Chile up to 1993 or if transmission is jointly owned by
the generators as is the case in USA where in some states the investor owned utilities have separated
out transmission into a jointly owned not-for- profit company or if transmission is jointly owned by
the distributors as was the case in E&W up to 1996, the problem of leveraging market power and
self- dealing arises, requiring stringent regulatory oversight. There is also the need to separate
generation from the distribution lines business and to avoid distribution companies owning
significant levels of generating capacity as this provides strong incentives for the distributors to
favour their generating arm although this may not be the least cost plant when dispatching.
There is a lessening of the regulatory burden at this phase of transformation in that the need to set
bulk energy tariff is eliminated; however, the regulator should be given the powers to approve the
rules for the market and any future changes to such rules as well as to monitor the operation of the
market to guard against abuse of market power. The main regulatory effort can then be structured to
concentrate on the natural monopoly network so as to prevent this sector from charging monopoly
prices. Where there are only a few players in the generation market as is often the case in small
emerging markets, the opportunity to exercise market power is significantly increased. Because of
the duopoly structure, which was created in the E&W market in1990, the problem of market power
persisted for most of the ten-year life of the Pool.
The bulk electricity market phase introduces product market competition, provides incentives for
productive efficiencies and for distributors to rationalise their businesses into more efficiently
organised enterprises. Market and technology risks are restructured and are more equitably
distributed and the electricity industry becomes less vulnerable to the errors of central planning.
Power markets also create distributional problems in favour of shareholders and investors. Without
competition at the retail level there is no guarantee there will be allocative efficiencies. Regulators
have only marginal power to correct this problem since the regulator controls less than 30% of
system cost.
On the negative side, transaction costs are significantly increased from the several market
agreements and technology risks. The cost of capital becomes much higher as the industry now has
to secure its finances from the commercial financial market. The introduction of a bulk electricity
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market also raises the problem as to how to deal with the stranded capacity charges. In Tanzania it
was estimated that the tariff would need to be increased by 20% (or US¢2 /kWh) to accommodate
the stranded cost of the two IPPs. This raises the question as to whether the users should meet the
burden of the stranded costs or whether this should be borne by the general taxpayers. In the UK a
levy of 10% was introduced during the first 6 years to meet this cost whereas in the US the
regulators have tended to pass it on through the retail tariff. Distributional problems are also raised
if one segment of the end user market is liberalised and the household captive users are required to
underwrite all the stranded costs.
It is possible to move from a franchised monopoly stage to a bulk electricity market, however, in
most developing countries electricity markets are not sufficiently mature to accommodate such a
radical change and they need to go through a transitional period of a 5 to 7 years before
transforming to a commodity market, as was the case in Panama and as was contemplated for
Northern Ireland.
The Main Sub-options under Bulk Electricity Markets
The objectives of electricity markets like all other commodity markets are to provide for transparent
transactions, to facilitate price formulation, provide maximum incentive for efficient production and
provide incentives needed for additional capacity. Despite these common objectives, international
experiences have been that of wide variation in the design of electricity markets. The questions as to
whether markets should be compulsorily organised or whether price discovery should be pricebased or cost-based have still to be resolved. The transmission system also can be designed to take
on several different roles.
The introduction of a two-sided balancing spot market with balancing contracts in the England and
Wales market in 20017, for example, intensified the controversy as to whether a single-sided, one
price mandatory auction market is less effective in providing for competition than a voluntary twosided discriminatory price auction market. Both single-sided and discriminatory price auction
markets are commonly used in financial and other commodity markets.
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In England and Wales, operation of the single-sided pool and the particular characteristics of the
market resulted in widespread exercise of market power, particularly close to real time when the
system was constrained. This problem persisted even after a significant reduction in market
concentration and when there was no single generator with market share of more than 20%. The
expectation therefore has been that the two-sided auction market would significantly reduce the
scope for the exercise of market power.
For Trebilcock and Gal (1999)8 a two-sided market provides better discipline over market power
than a one-sided auction market. In sharp contrast, Harbord and McCoy (2002)9 state that “neither
theory or empirical evidence tells us that discriminatory price auctions perform better than
uniform price auctions” .In Harbord and McCoy’s view, the new England and Wales market is
severely flawed in that the design increases, rather than reduces the opportunity for market power.
When the trading arrangements were put into experimental test in 1999, one clever trader, writing
specious quantities and prices in the balancing market fictionally made millions of pounds in a
matter of days to the embarrassment of the designers. Norway was the first country to adopt the
bilateral contracting, and voluntary spot market; however, the system unlike in the UK and Chile did
not have a history of centralised system operation. Several small municipally owned hydro-plants
provide over 60% of generation in Norway, and bilateral contracting was found to be more
appropriate for this structure.
In the case of cost-based versus price-based mechanisms for price discovery, Millan (2001)10 points
out that Latin America has by and large opted for cost-based and this is in sharp contrast to the
Europeans, where the priced- based mechanism has been preferred. The characteristic of hydropower systems in many Latin American countries and a history of cost-based dispatching by merit
order of hydro plants, seem to have influenced the Latin American policymakers towards a costbased power market.
The supporting arguments for the use of a cost- based price discovery mechanism, especially in
small electricity systems are that it ensures efficient dispatch and if generators are honest about their
cost it reduces the opportunity to exercise market power (which is critical in concentrated small
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systems). It is less sophisticated, easier and less costly to implement and it can evolve to a price
based system as the market matures. In the early phase of small concentrated markets, there are
usually insufficient bidders to secure effective competition.
Policy makers also encounter a range of options as to the role of the transmission operator as well as
the ownership of the transmission system. In the England and Wales market all the functions are
centralised under the privately owned National Grid Company. In New Zealand, the transmission
owner (a state owned company) is neutral to the system and does not trade in bulk electricity.
Systems and market operations are competitively tendered to the private operators. There are strong
arguments for government to initially own the transmission system following restructuring as it is
very difficult to value transmission assets for sale. The view however, is that management and
operation should be franchised to private operators as this gives more confidence to private
investors to enter the market. When the transmission operator is neutral to the system, market
power and conflicts of interest are also reduced.
These differences in organising power markets have led Sioshansi and Morgan (1999)11 to conclude
that “the choice of market structure comes down to an ideological preference or a
compromise for either economic efficiency or customer choice”. There are however, good
reasons for the diversity of designs. No two countries start from the same point or have the same
physical features.
Market size, fuel mix and ownership structure vary from market to market. In
developed markets, restructuring is often motivated by the desire to introduce competition and to
make markets more efficient, more service orientated and for services to be delivered at lower
prices. In most developing countries with weak infrastructure, low accessibility to electricity and
chronic financial shortages, the need to reform is driven by the desire to attract foreign direct
investment.
Retail Competition as a Reform Option
The final phase of transformation is that of retail competition. The England and Wales, New
Zealand and Nordic markets have since 2000 come closest to this structure. At the final phase,
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choice is allowed to all end users to source electricity supplies from competing generators. Product
market competition is extended from bulk supplies to retail supply or low voltage energy.
Most important of the reform measures is that of liberalisation and access to distribution lines by
both industrial and small domestic household consumers, as was introduced in England and Wales
during the period 1999 to 2000. Competition is also encouraged through entry of retailers and other
intermediary traders. Retailers and other intermediaries’ contract with generators supported by a
bulk electricity spot market, with payments made for wheeling across the transmission as well as the
distribution wires.
Separation of the merchant retail function from the distribution lines business, creation of local
distribution companies and encouragement of multiple retailers, form the most important structural
decisions to be contemplated. Both the retailing of energy and the related services can be made to
operate under competitive markets. The requirement to unbundle the network natural monopoly
distribution lines from the competitive merchant retail section is central to reducing the opportunity
for abuse of market power, self-dealing and conflict of interest.
Minor changes are also required to regulation to meet the regulatory requirements under the retail
competition phase. The regulator is no longer required to fix prices for low voltage electricity; the
price fixing function is restricted to the network natural monopoly transmission and distribution line
business. The regulator also takes on the increased role of guarding the consumer from anticompetitive practices. Where there is vertical integration of the distribution line business with the
retail supply there will be the need for greater regulatory effort. New Zealand has mandated vertical
separation of distribution lines from retail supply and distribution companies had to decide which of
the two businesses they intended to eventually operate in. This has been supported by strict
information disclosure rules on the line business operators.
In the UK, although vertical separation into independent legal entities was mandated between the
two sectors, cross ownership was not excluded. In some markets only vertical accounting separation
is prescribed. Retail supply is often seen to be a low margin business and it is sometimes argued that
with stand-alone operation the business may not be attractive to investors, hence the decision to
impose only accounting separation.
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Increased transaction costs are associated with retail competition. For the small household domestic
user, the transaction and trading costs of each component of the final product may outweigh the
benefits of choice. There is also the problem of identification of responsibility by the consumer for
poor services when the distributor and retailer are separate. In most if not all cases, the introduction
of retail competition has been phased. In the England and Wales case it took nine years, 1990 to
1999. Phasing has been found to be necessary because of the complexity of introducing millions of
users to competition.12 It is also not possible to achieve effective retail competition without a bulk
electricity market. New Zealand tried to liberalise the retail market in 1992, however, there was no
incentive by end users to change source of supply. Argentina, Chile, Norway, Spain and Victoria,
Australia have all been transitioning to the retail competition phase.
Main Lessons Learnt
As the industry moves from one phase to the next, increased levels of competitive pressure are
exerted in the market, higher levels of disintegration are experienced and private participation and
ownership expand at the expense of public ownership. Whilst privatisation is a necessary condition
for the realisation of economic efficiency, the empirical evidence, as demonstrated in the England
and Wales and Scottish reforms is that privatisation alone is not a sufficient condition. The greater
the extent of private ownership the greater opportunity there is for competition. A completely
unbundled industry would be one in which the four stages of the production and supply chain are
under different ownership and there is no cross-ownership between each sector. This may not be
completely possible. Markets, however, which fail to adopt structural separation and substitute
accounting ring fencing or management separation, provide more opportunities for the exercise of
market power and an increase in the regulatory burden.
Although in the Scottish reforms independent regulation was introduced, the evidence also is that
regulation is not a substitute for competition and is inevitably inefficient and should be confined to
the natural monopoly network sectors. Regulatory institutions provide the opportunity for
bargaining by interest groups and the misallocation of resources. Policymakers therefore should seek
to minimise the opportunity for inefficient bargaining over rents by reducing the number and power
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of interested parties who participate in the regulatory process. If the agency for example is not
independent of the portfolio ministry the more likely its decision will be subjected to bargaining by
politicians and represented interest groups.
Several studies in the past have shown that there is very little evidence to support the position that
privately owned monopoly utilities are superior in terms of economic efficiency to publicly owned
utilities. Privately owned utilities however, in the past have not been exposed to competition, being
then the subject of public regulation. The result is that there is no incentive for both publicly owned
and privately owned and regulated electric utilities to find least cost solutions and reduce cost. Under
both institutional arrangements, interest groups seek to relocate returns in socially undesirable ways.
The gains to be redistributed are monopoly rents and such gains will be distributed in proportion to
the strength of the bargaining power of the groups. The England and Wales and the Scottish
reforms clearly demonstrate that for superior economic performance, private ownership of the
industry has to be accompanied by competition.
The changes in the electricity utility have merely expanded what started in the telecommunications
utility in the mid 1980s and is helping to shift the boundaries between the state and markets, as well
as the boundaries between public and private ownership and between political control, exercised
through public regulation or public ownership and market forces. The central idea is that market
forces are superior to hierarchical bureaucratic control as a way of managing economic institutions.
In the USA where traditionally most of the network monopolies were private investor owned
utilities, the changes have been one of liberalisation of markets and decentralisation of the industry
structure. Decentralisation and liberalisation, unlike privatisation, which is about ownership is more
about subjecting the utilities to market forces and competition and providing more powerful
incentives for economic efficiencies.
Liberalisation of network utilities, however, also redistributes rents and raises regulatory concerns in
managing the interface between the regulated network and the competitive sectors. Liberalisation
has not entirely resolved the problem of market power. In fact new market power issues have
emerged from the ability of the network sector to leverage its monopoly power into the competitive
parts, as well as in the potentially competitive generation and retail supply sectors. The result is that
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ordinary competition law as adopted by New Zealand is not only insufficient but also very expensive
in dealing with market power issues.
The development of the electricity industry was through private ownership and free markets. It is
during the period between 1930 and 1990, the conventional wisdom and the accepted view of utility
economics was that electricity and other network utility should be organised as vertically integrated
franchised monopolies. This structure, while it did deliver expansion and increased levels of service
to society by 1990 serious concerns emerged as to the efficient operation of the industry in both
developed and developing economies.
The Rise of the Regulatory State
The market as an agent in creating economic growth is a relatively new thinking in most developing
countries as well as Western Europe. Under liberalisation and privatisation the expectation was that
regulation would be temporary and that there would be contraction in the size of the state. In
abandoning public ownership however Britain found it necessary to follow the Americans and
introduce independent regulation of prices and to expand the scope of the competition agency.
Experiences have been that market concepts when applied on their own were not sufficient to
generate economic growth. Market concepts must also be accompanied by institutional changes.
Feigenbaum, Henig and Hammit13 state that those changes are:
“intended to establish the legal and regulatory framework within which market
transactions can be protected and enforced”
Privatisation and liberalisation have therefore led to an increase in regulation Veljanoveski14 states
that:
“it would be unrealistic to assume that the state will confine itself to a minimalist
level of intervention designed solely to protect consumers and enforce competition,
sectoral interest will result in the regulatory role expanding well beyond what is
needed to ensure efficient production.”
330
Giandomenico Majone15 noted that statutory regulation by independent agencies outside the
hierarchical control or oversight by central administration and referred to as American style
regulation has in fact accelerated with privatisation.
In fact Majone16 further states that:
“Privatisation and liberalisation seem to have created the conditions for the rise of
the regulatory state to replace the dirigiste state of the past. The reliance is now on
regulation rather than public ownership, planning and control. Regulation has
become the new border between the state and the economy and the battle ground
for ideas as to how the economy should be run”
The regulatory state is said to have replaced the welfare and development state. The regulatory state
attempts to increase the allocative efficiency of markets by correcting
various market failures;
natural monopoly, information asymmetry and externalities or failure of the market to deliver public
goods.
Mascarenhas17 has argued that:
‘the cure to the crisis of capitalist economies is not a question of replacing the state
with the market. The role of the state as a political agent will continue to be
significant, whilst its role as an economic agent will continue to decline. The
remedy lies in altering the balance in the relationship between the state and the
market and not as is claimed by neo-liberals rolling back the state’
It is not the existence of the state that privatisation and the expansion of markets have brought into
question but the function of the state. In Britain the regulatory industry is said to be one of the
fastest growing industries. From virtually no regulatory agencies in Sub-Saharan Africa in 1990, by
2001 there were well over 36 such agencies.
Conclusions
The changes and developments which have been taking place, have since the 1990s been providing
governments with a range of policy options as to industry structure, market mechanism, and
regulatory frameworks. Governments are now in a better position in adopting public policies to take
into consideration economic and institutional constraints and resource endowment in the design of
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their electricity supply industry. The flexibility is not only at the level of the industry structure but
also over a range of sub-options.
Where governments from a fear of the operation of free enterprise adopt vertical and horizontal
separation but retain high levels of common ownership across sectors, as contemplated in South
Africa and Ghana, then there will be severe hindrance to the competitive process. It will be difficult
to provide for competition in an unbundled government owned utility structure, although this may
be possible where several municipally owned utilities could compete on a national market as in
Norway. The global tendency therefore has been for structural reforms and the introduction of
increased levels of competition in the ESI to be accompanied by privatisation.
Optimal structure in the generation market is important but not critical to the competitive
transformation process so long as the opportunity for free entry exists as shown in the case of the
England and Wales market. The experience in the E&W market did not support the assumption that
Bertrand competition is a sufficient condition to drive down cost. It is much more difficult to
sustain competition in the electricity industry and especially in small electricity markets. The greater
the number of players, given market size constraints, the less opportunity there will be for market
power and conversely the smaller the number of players the greater the opportunity presented for
the exercise of market power as firms will seek to constrain competition either from collusion or
gaming the market.
It is also much easier to introduce the right structure before privatisation rather than to use
regulation to create competition after privatisation. Jamaica will find it a major challenge to create
competition in its electricity supply industry following the conclusion of the initial three-year
exclusivity period for new generation capacity. The creation of an efficient industry is not just a
question of private ownership. Private ownership with public regulation is hardly superior to public
ownership and self-regulation as the UK experience demonstrates. In both these two institutional
arrangements the incentives for efficiencies are very weak and the opportunity to capture the system
for the benefit of special interests is very high. It is the introduction of competition in the
competitive parts of the industry, which brings about productive and allocative efficiencies.
332
The policy approach of private ownership and competitive markets for the sectors where
competition is possible and independent incentives based regulation for the natural monopoly
network sector, offers far greater benefits to consumers, when compared to integrated publicly
owned or integrated privately owned utilities with public regulation. The important consideration in
addressing a competitive electricity market is that of reducing market power. Structural reforms
alone are not enough. There must be free entry to the competitive sections of the market and
transparent and independent regulation to constrain the monopoly network segments. The
regulatory effort has been moving away from regulating services to regulating the network.
Structural changes however bring an important benefit it reduces the regulatory burden and
regulatory costs.
Technology has made it possible to disintegrate the industry and for a policy of competitive entry
and increased competitive market operation. The effects of the technological developments and the
application of new trading arrangements including the application of the principles of commodity
market have put an end to the vertically integrated franchised monopoly as the dominant
institutional and structural arrangement in the industry; the end of the franchised monopoly era and
have fuelled an uprising of competition in the utility electricity industry. Amongst the reluctant
reformers are France and Scotland, leaving Jamaica in an anomalous position to the global trends.
The reforms in the small markets such as Bolivia in 1995 have silenced the view that restructuring,
involving unbundling and the introduction of competition should be reserved only for countries
with large and mature markets. The same basic economic principles, which apply to these markets,
also apply to the developing markets.
Each country, however, should consider its particular
requirements and circumstances and introduce the appropriate measures within the overall
framework of an unbundled and privately operated electricity supply industry.
End Notes
333
1.
M.G. Pollitt, The Restructuring and Privatisation of Electricity Supply Industry in
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2.
K. Izaguirre, “Private Participation in the Electricity Sector – Recent Trends; Private Sector
(December 1998), p. 5.
3.
S. Littlechild, “Privatisation, Competition and Regulation in Scottish Electricity Industry”,
Scottish Journal of Political Economy, Vol.43, No.1 (1996), p.14
4.
Eligible consumers have been classified as those with annual consumption of 16 GWh. In
2003 this is will be reduced to 9 GWh. EdF lost 45 industrial customers with operations
covering 60 sites during the period following liberalisation in 1998 and up to 2000. Most of
these customers switched to Spanish or German suppliers. This accounted for only 3% of
EdF’s market share
5.
Over 75% of the French ESI system is nuclear powered and as late as 2001 two plants, each
of 1450 MW was brought into operation. EdF, the state owned incumbent which
traditionally has been vertically integrated accounts for 90% of generated power and 95% of
the distribution market, with the remaining 5% distributed by some 170 small independent
distributors, mostly municipally owned.
6.
M. Marquis, Introducing Free Markets and Competition to the Electricity in Europe.
England, Wisdom House (2001) p.144
7.
In a voluntary two-sided auction market, bidders pay or receive what they bid or offer for
each unit, bought or sold, whereas in a single-sided mandatory auction market a single bid,
that of the marginally accepted bid clears the market and all dispatched generators receive
the marginal price (systems marginal price) irrespective of their bid.
8.
Michael J. Trebilcock and Michael S. Gal, “Market Power in Electricity Industry
Restructuring”, World Competition, Vol. 22, No.1 (1999), p. 159
9.
David Harbord and Chris McCoy, “Miss-Designing the UK Electricity Market”, European
Competition Law Review, Vol. 21 (2000), p. 359
10.
Jaime Millan, The Second Generation of Power Exchange: Lessons for Latin America,
Washington, D.C., IADB (2000), p. 4, also in Second–Generation Reforms in
Infrastructure Services, , eds, Federico Basanes and R. Willig, IADB (2002), p. 268
11.
Fereidoon P. Sioshansi and Cheryl Morgan, Where Function Follows Form: International
Comparison of Restructured Electricity Markets, Electricity Journal (April 1999) p.23
12.
The technology of smart metering and the sophisticated telecommunication system had not
been developed in 1990. New Zealand tried to introduce retail competition in the early
1990s and had to resort to profiling which was not a success.
334
13.
Feigenbaum, J. Henig and C. Hammit, Shrinking the State: the Political
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Cento Veljanoski and Mark Bentley, Selling the State: Privatisation in
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Giandomenico Majone, ‘Rise of the Regulatory State in Europe’ in Reader in
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Giandomenico Majone, Regulating Europe, London and New York, Routledge (1996)
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R. Mascarenhas, Government in the Economy in Australia and New Zealand: the
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