DOE/EIA

Distribution Category XX-XXX

Electricity Reform Abroad

and U.S. Investment

September 1997

Energy Information Administration

Office of Energy Markets and End Use

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the Energy Information Administration, the independent

statistical and analytical agency within the Department of Energy. The information

contained herein should not be construed as advocating or reflecting any policy position

of the Department of Energy or any other organization.
ii Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Contacts

This report was prepared in the Office of Energy Markets (202/586-1445). Kathy L. Washington performed the

and End Use of the Energy Information Administration, formatting and desktop publishing efforts for this report.

U.S. Department of Energy, under the general direction of Specific technical information concerning this report may

W. Calvin Kilgore. General questions concerning the be obtained from Kevin Lillis (202/586-1395) or Jon

content of the report may be referred to Mark E. Rasmussen (202/586-1449). The following authors conRodekohr, Director of the Energy Markets and Con- tributed to this report: Neal Davis (Chapter 4), Susanne

tingency Information Division (202/586-1130), and Mary Johnson (Chapter 3), Kevin Lillis (Executive Summary,

E. Northup, Chief of the Financial Analysis Branch Chapters 1 and 2), and Jon Rasmussen (Chapter 1).
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment iii

Contents

Executive Summary ......................................................................................v

1. Electricity Reform Abroad: Experiments in Argentina, Australia, and the United Kingdom ................... 3

The Characteristics of Individual Country Reforms ...................................................... 3

The Characteristics of Investing Companies ............................................................. 6

2. Electricity Restructuring, and Privatization in the United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

 The Structure of UK Electricity Prior to Privatization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

The England and Wales Power Pool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

RPI-X: Price Caps Versus Rate of Return Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

The Sale of UK Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Electricity Investment Activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Electricity’s Relationship to UK Natural Gas Privatization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Privatized Electricity: A Performance Appraisal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

3 . Electricity Reform and Privatization in Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Creation of the National Electricity Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Implementation–The National Electricity Code . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Buying Electricity in the National Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Electricity Reform at the State and Territory Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Reforms in Price Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Privatization and Reform Outcomes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

4. The Transformation of Argentina’s Electricity Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

An Historical Perspective for Argentine Privatization Efforts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Changes in Legislation and International Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

The Industry Restructuring and Privatization Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

The Creation of a Competitive Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Resulting Foreign Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Appendices

A. U.S. Electric Utility Companies Not Investing in Argentina, Australia and the United Kingdom . . . . . . . . . . 85

B. Electricity Reform Milestones in Argentina, Australia, and the United Kingdom . . . . . . . . . . . . . . . . . . . . . . . 89

C. Review of Argentine Electricity Privatization Investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

Tables

1. U.S. Utilities with Foreign Investments .................................................................. 7

2. Share of UK Electricity Generation for the Fiscal Years 1990-2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

3. Regional Electricity Distribution Companies in the United Kingdom Ranked by Electricity Distributed,

Fiscal Year 1994/1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

4. The Incremental Deregulation of the End-User Electricity Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

5. Non-Franchise Market Shares in England and Wales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

6. Share of Component of Electricity Costs for Different Classes of End Users . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

7. The UK’s Office of Energy Regulation RPI-X Price Controls, and Review Periods . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
iv Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Tables (continued)

8. Recent Merger and Acquisition Activity in UK Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

9. Major UK Regional Natural Gas Pipeline Privatizations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

10. Major Foreign Equity Investments in UK Independent Power Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

11. Employment in the UK Electricity Industry, Selected Years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

12. Net Income for UK Electricity Generation Companies, Selected Years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

13. The Initial Regulation of Electricity Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

14. Australian Electricity Profile: Consumption By Class of Customer and Population in 1995 . . . . . . . . . . . . . . . . . . . . 41

15. Australian Electricity Consumption, Generation, Imports, and Capacity by State and Territory, 1995 . . . . . . . . . . 42

16. Australian Electricity Generation Fuel Usage in 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

17. Australian Electric Utility Privatization-Related Mergers and Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

18. The Australian Electricity Supply Industry Infrastructure Operators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

19. Net Production of Argentine Electricity by Independent and Public Producers, 1985-1995 . . . . . . . . . . . . . . . . . . . . 64

20. Argentine Electricity Privatization-Related Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

A1. U.S. Electric Utility Companies Net Investing in Argentina, Australia, and the United Kingdom . . . . . . . . . . . . . . 87

B1. Electricity Reform Milestones in Argentina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

B2. Electricity Reform Milestones in Australia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

B3. Electricity Reform Milestones in the United Kingdom . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

C1. Foreign Companies with Investments in Argentina’s Electricity Industry, as of 1997 . . . . . . . . . . . . . . . . . . . . . . . . 104

C2. Organization of Argentina’s Federal Electricity Industry, 1991 and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

C3. Organization of Argentina’s Provincial Electricity Industry, 1991 and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 110

C4. Argentine Power Generators Built Since 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

Illustrations

ES1. U.S. Direct Investment Position in Overseas Utilities ......................................................v

ES2. U.S. Direct Investment Position in Australian and UK Other Industries ......................................v

ES3. An Example of the Transformation of a National Electricity Industry to a Restructured Industry Along

Functional Lines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii

1. Market-to-Book Ratio for Foreign Investing Electric Utilities and Other Electric Utilities, 1987-1996 ............. 7

2. Regional Distribution of Sales for Foreign Investing Electric Utilities and Other Electric Utilities, 1995 .......... 7

3. Dividend Payout Ratio of Foreign Investing Electric Utilities and Other Electric Utilities, 1987-1996 ............ 8

4. Return on Equity of Foreign Investing Electric Utilities and Other Electric Utilities, 1987-1996 .................. 8

5. Structure of the UK Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

6. UK Electricity Industry Fuel Use, 1988-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

7. Index of UK Electricity Prices, 1988-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

8. Fuel Price Index for UK Electric Utilities, 1988-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

9. Australian National Electricity Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

10. Victoria’s Wholesale Electricity Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

11. New South Wales’ Wholesale Electricity Market . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

12. Total Direct Investment in Australia, Selected Years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

13. U.S. Direct Investment Position in Australia, 1988-1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

14. Argentine Federal Electricity Restructuring of Conventional Power Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

15. Argentine Federal Electricity Restructuring of Power Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

16. Argentine Electricity Restructuring of Power Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

17. Argentine Electricity Restructuring of the Federal Nuclear Agency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

18. Total U.S. Direct Foreign Investment in Argentina, Selected Years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

19. Ownership of Argentine Electricity Assets, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

20. Argentine Electricity Sales Volume Market Shares, 1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
1988 1989 1990 1991 1992 1993 1994 1995 1996

0

2

4

6

8

10

12

1991 1992 1993 1994 1995 1996

0

1

2

3

4

5

6

7 Australia

United Kingdom

Energy Information Administration/ Electricity Reform Abroad and U.S. Investment v

Figure ES1. U.S. Direct Investment Position in

Overseas Utilities

Note: These utilities include, in addition to electricity, natural gas

distribution and sanitary services. However, the sharp upward climb

in these investments during the years 1994 through 1996 is almost

entirely due to overseas electric utility investments by U.S.

companies.

Source: U.S. Department of Commerce, Bureau of Economic

Analysis, Survey of Current Business, (Washington, DC), August,

1990-1997.

Figure ES2. U.S. Direct Investment Position in

Australian and UK Other Industries

Note: The Commerce Department's “Other Industry” category

includes several other industries in addition to electricity. However, the rapid growth in this overall industry category in 1994

through 1996 is affected most predominantly by U.S. company invesments in Australian and UK electric utilities.

Source: U.S. Department of Commerce, Bureau of Economic

Analysis, Survey of Current Business ( Washington, DC), August,

1993-1997.

Executive Summary

Over the past decade a number of nations have re- box entitled “Two Methods of Calculating Foreign Investstructured their electricity industries. Several nations ment” in Chapter 1). The predominant share of this

have also significantly reduced the government’s role in investment has been directed at the United Kingdom and

the ownership and management of domestic electricity Australian electricity industries (Figure ES2). The investindustries—both at the state and at the national level. The ment expenditures of U.S. companies in the electricity

Energy Information Administration selected Argentina, industries of the United Kingdom and Australia alone far

Australia, and the United Kingdom (UK) for this study exceed all U.S. overseas electricity investment in the rest

partly because of the extent to which these nations have of the world combined. Electric utilities from the United

undergone electricity reforms but also because of the States have also been the most prominent foreign invesmajor role that U.S. companies have played as investors in tors in the recently-privatized Argentine electricity

these nations’ reformed and privatized electricity sectors. companies—although the dollar value of investment in

 Understanding how Argentina, Australia, and the United Argentina’s electricity industry has been smaller relative

Kingdom each addressed the issues of primary impor- to the investment dollars flowing to Australia and the

tance to their country’s electricity sector reform may be United Kingdom.

informative to those who will fashion the structure of

similar reforms in the United States. This understanding

may be all the more important because of the experiences

that U.S. electric companies will have gained from their

investments in these countries.

Since the early 1990's, investment in overseas electricity

assets has been a rapidly growing target of U.S.

companies’ foreign investment (see Figure ES1, and the

In Argentina, Australia, and the United Kingdom, electricity reform has involved a combination of the following

issues:

• an unbundling of electricity assets;

• the creation of electricity pools;

• the creation of independent system operators;
vi Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

• the privatization of electricity assets through sale or

public auction;

• the deregulation of electricity and the implementation of a more restrained form of regulation where

regulation was retained;

• the adoption of price cap regulation and movement

away from rate-of-return regulation;

• the realization of a competitive market in generation;

• the separation of the “wires” function of distribution

from the “marketing” function;

• the gradual introduction of competition in electricity

marketing; 

• an opening up of domestic electricity assets to

foreign investment; and

• determination of the degree of recovery of stranded

costs.

In each of the three case study countries, issues surrounding electric industry restructuring, competitive electricity

pools, privatization, deregulation, and stranded costs are

unique to each country’s electricity reform experience.

However, there are often more commonalities than differences, particularly in the case of Australia and the

United Kingdom. In all three countries, electricity reform

involved a greater opening to foreign investment in

electricity.

In Argentina, Australia, and the United Kingdom, electricity restructuring and privatization were carried out in

an atmosphere of general economy-wide restructuring

and privatization. In all three countries, a primary goal

motivating electricity reform was to achieve lower electricity costs for consumers through encouraging efficiency

improvements in the electricity industry. Reduced costs Although Australian reforms borrowed heavily from the

were also to serve the purpose of improving the efficiency UK experience, there have been several notable distincof the overall economy. In all three countries, raising tions. In contrast to reform in the United Kingdom,

revenues for the treasury to reduce public borrowings was electricity reform in Australia was undertaken several

another overriding motive. In Argentina, obtaining badly years later and at both the state and national levels. In

needed capital for electricity infrastructure improvement general, several of the Australian state governments

and expansion was an additional motivating factor for re- restructured their electricity industries in a fashion similar

form and privatization. to the United Kingdom: separating generation, transIn order to explain more fully how Argentina, Australia, However, although Australia’s reform efforts are more

and the United Kingdom each proceeded with the recent (and therefore more difficult to appraise), it

transformation of their electricity industries, these issues appears that Australia may have avoided the kind of

are discussed in detail (on a country-by-country basis) in public concerns that have occurred in the United

the individual chapters of this report. However, the Kingdom over a lack of competition in electricity generahighlights of how each country chose to deal with these tion. Victoria, the second most populous of the Australian

issues can be summarized as follows. states—but with a population less than one-fifth that of

Industry Restructuring

Figure ES3 depicts a hypothetical “model” of what a

national electric utility restructuring might look like.

Figure ES3 shows an electricity industry as a single

nationalized entity prior to the restructuring. The restructuring involved the separation of all electricity industry

functions along separate lines of business (i.e., generation,

transmission, distribution, and marketing) into newly

created organizations. It should be stressed that Figure

ES3 is a much simplified (and not entirely representative)

model of restructurings that have taken place in several

nations. Figure ES3 is more illustrative of the United

Kingdom experience—where the electricity industry prior

to restructuring was owned and managed primarily by

the central government. In contrast, in Australia statewide electricity restructuring largely preceded nation

wide reforms and was predominate. Argentina is also

distinct in that Argentina’s restructuring involved a widescale consolidation of electricity operations.

In the United Kingdom, electricity reform initially involved the complete restructuring (unbundling) of the

industry along segmental lines: electricity generation,

transmission, distribution, and marketing all became

separate operations. Prior to privatization, the United

Kingdom created two large power generation companies,

one national transmission company, and twelve regional

generation companies. A newly-evolving electricity

marketing segment was to be gradually developed, where

sales, brokerage, and billing operations each became a

separate function. In its restructuring, however, the

United Kingdom created an industry that from its infancy

was dominated by the two large generation companies

whose predominant market share—and predominant role

in the electricity pool—has often given rise to concerns

over whether generation was adequately competitive.

mission, distribution, and supply into different operations.
Old Structure

Generation

Transmission

Distribution

Captive

Franchised 

Customers

New Structure

Generator A Generator B Generator C

Transmission

Company

Distribution

Company A

Distribution

Company B

Distribution

Company C

Distribution

Company D

Marketing

Company A

Marketing

Company B

Marketing

Company C

Marketing

Company D

End 

User

End 

User

End 

User

End 

User

End 

User

End 

User

End 

User

Energy Information Administration/ Electricity Reform Abroad and U.S. Investment vii

Figure ES3. An Example of the Transformation of a National Electricity Industry to a Restructured Industry

Along Functional Lines.

Note: The above examples do not represent any particular nation's electricity industry (either before or after restructuring). This diagram serves as

a simplified model of what a generic restructuring might involve. Real examples are generally more complex. The manner in which Argentina, Australia,

and the United Kingdom were restructured is explained in subsequent chapters.

the UK—attempted to create more competition in

generation through the creation of five generation companies. Various Australian governments have also

encouraged the development of an independent electricity

marketing function, thus as in the United Kingdom

allowing customers to bypass traditional distribution

companies.

In Argentina, as in the United Kingdom, restructuring was

primarily a central-government-led operation. The Argentine government unbundled generation operations from

transmission and distribution. Electricity marketing,

however, was not separated out as a distinct business

company or operation. However, due to the dispersed

population concentrations in Argentina, several regional

transmission companies were created. The regional

companies act as spurs connecting otherwise isolated

areas to the main electricity grids.

Competitive Electricity Pools

All three countries created national electricity pools. The

United Kingdom was first to create a national electricity

pool, which has been in operation since 1990. The UK

electricity pool is operated by the National Grid Company, which is also responsible for electricity transmission. The UK pool has generally operated efficiently,

although concerns have been raised over its tendency to

produce price volatility and an unfair playing field

between electricity suppliers (again, primarily the two

now-privatized dominant generation companies) and

electricity consumers. A secondary market, called a contract for differences market, has evolved in the United

Kingdom. This secondary market allows participants to

hedge a large fraction of their pool purchases.

In Australia, the National Electricity Pool was largely

based on the UK model, but with some noteworthy
viii Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

 variations. The Australian National Pool is a fairly recent The Argentine central government also employed an

operation, having started in May 1997. (Preceding the auction to transfer ownership of the national governcreation of the national pool, a couple of Australian state ment’s holdings in electricity companies to the private

governments created their own electricity pools and these sector. Interestingly, in the Argentine auction, bidders

have been in operation for several years.) The Australian were required to submit levels of service standards they

National Pool is operated by an independent system op- were committing to meet along with bid prices. Again,

erator, the central-government-owned National Electricity U.S. companies were the dominant foreign investors in

Market Management Company, which is separate from Argentine electricity.

any transmission operation. As in the United Kingdom,

pool price volatility has been an important concern in

Australia, and a contract for differences market has been

created to manage this risk. However, due to the relatively large number of generators participating in the

supply end of the business, less concern has been raised

over a lack of competitiveness.

In Argentina, a national electricity pool was also based

upon the UK model. Pool operations began in 1992, and

pool prices have been considerably beneath the comparable wholesale price of electricity existing prior to the

commencement of pool operations. Again in contrast to

the United Kingdom, no generator in Argentina is allowed

to control more than ten percent of the system’s generation capacity. Further, in Argentina an independent 1

system operator operates the pool.

Asset Privatizations

In the United Kingdom, widespread privatizations of via the application of price ceilings. Price-cap regulation

electricity assets followed shortly after the restructuring. is a marked contrast to the rate of return regulation

These privatizations were achieved through public auc- employed in the United States. In terms of encouraging

tions. Eventually, virtually the entire UK electricity efficiency, price-cap regulation appears to have been

industry was privatized with the exception of some rela- successful in all three nations but has become a highly

tively old nuclear generation plants. Much controversy controversial matter with regard to whether it promotes

surrounded the sale of UK electricity assets. With the equity and fairness for consumers.

exception of the sale of nuclear assets, UK electricity

auctions were oversubscribed, leading to allegations that

the government had not obtained a fair value in the sale

of public goods. Further, energy companies from the

United States were eventually to acquire roughly one half

of all UK electricity assets.

In Australia, only the state of Victoria has gone nearly as (mostly those related to coal) and the disposition of

far as the United Kingdom in its privatization efforts. stranded costs (mainly nuclear-related) greatly comOther Australian state governments were either slower to plicated efforts at electricity privatization. The UK

privatize or decided to retain ownership while reducing electricity industry had long sustained the UK coal

control over their electricity industries. During the initial industry through its purchases of domestic coal at highly

public auction of Victoria’s electricity assets, U.S. com- inflated prices. As both industries became privatized and

panies purchased controlling interests in all five of the deregulated, these subsidies were severely reduced. The

privatized regional distribution companies and three of stranded costs associated with nuclear power investment

the five generation companies. Sizable premiums over in the United Kingdom represent the difference in the

book value were paid in all cases, an indication of the book value of nuclear power facilities and the market

relatively high value U.S. companies placed on these value of these facilities. In contrast to the situation in the

takeover targets. United States, where the issue of who should bear the

Deregulation

All three governments employed a less intrusive form of

regulatory authority than that which had existed in the

past. The United Kingdom’s electricity reform efforts

embraced two fairly radical departures from previous

electricity regulation. One involved the nature of the

regulator. One of the first acts of electricity reform created

a national electricity body, the Office of Electricity Regulation (OFFER). In order to reduce regulatory costs and

allow industry more discretion in investment and operational matters, the OFFER was lightly staffed and was

headed only by a single individual (not a commission).

Similar institutions were adopted in Argentina and

Australia.

A novel form of price-cap regulation was adopted in the

United Kingdom and emulated in Argentina and

Australia. Price-cap regulation attempts to restrain costs

Energy Subsidies and

Stranded Costs

In the United Kingdom, the issue of energy subsidies
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment ix

burden of stranded costs associated with nuclear power world standards) and never having developed a nuclear

investments is between rate payers and shareholders, in power industry. In Argentina, much as in the United

the UK (where, prior to privatization, all nuclear genera- Kingdom, part of the failure to successfully privatize the

ting assets were owned by the national government), the federal government’s nuclear plants stemmed from the

issue of allocating the burden of stranded costs was issue of stranded costs. However, unlike the United

between rate payers and tax payers. In the end, both Kingdom, Argentina has had to resolve stranded costs

parties paid: tax payers through the government’s associated with past investments in hydroelectric power

auctioning off nuclear electricity assets at heavily as well. Even though the marginal costs of operating

discounted prices; and rate payers, through a nuclear Argentina’s two large binational (i.e., jointly held with

surcharge attached to electricity bills. Paraguay and Uruguay) hydroelectric facilities are low,

In Australia, stranded costs were largely unimportant due to recover the large capital costs associated with these

to Australia’s having a very competitive coal industry (by facilities because of their large construction cost overruns.

it is doubtful that the Argentine government will be able
x Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

“Reshaping Power Markets: Lessons from South America,” The Electricity Journal (March 1996), p. 65. 1

Endnotes
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 3

1. Electricity Reform Abroad: Experiments in

Argentina, Australia, and the United Kingdom

Over the past few years, several nations have initiated The electricity reform and privatization experiences

electricity industry reform and privatization efforts. reviewed in this report may offer some insight as to how

Argentina, Australia, and the United Kingdom (UK) are the U.S. electricity industry might develop as a result of

among those countries at the forefront of such efforts. recent domestic reform efforts and deregulation at both 1

Reforms undertaken in these three countries are especially the state and national levels.

important because they have in many ways become

models for reforms carried out elsewhere. From the

perspective of the United States (and other countries

considering electricity reform), these three nations are

often viewed as laboratories in which the efficacy of

particular electricity reform policy choices are being

tested. For this reason, we have referred to these reforms

as “experiments.” In reality, however, these reforms

represent firm policy measures adopted by the countries

involved.

This report reviews and analyzes the recent electricity

reforms in these countries in an attempt to better understand how different models of privatization and reform

have worked in practice. (For a more general discussion

of some of the factors underlying the recent worldwide

trend toward industry privatization, see the box entitled

“Why Privatize?”) 

This report also analyzes the motivations of the U.S.

companies who have invested in the electricity industries

of Argentina, Australia, and the UK. These countries have

become the largest targets of U.S. foreign investment in

electricity. American electricity investment in the newlyprivatized electricity industries of Australia and the UK

far exceeds all other U.S. electricity investment abroad.

Companies from the United States were also the largest

investors in Argentina’s recently-privatized electric utility

industry.

This report utilized two calculations of foreign investment. One is the foreign direct investment series produced

by the U.S. Department of Commerce. The other is based

on transactions (compiled from the financial press) in

Argentine, Australian, and U.K. electric utilities. For a

comparative discussion on both methods, see the box

entitled “Two Methods of Calculating Foreign Investment.”

The Characteristics of Individual

Country Reforms

To a large extent, Argentina’s and Australia’s electricity

reforms were guided by reforms undertaken earlier by

other countries: Australia benefitted from the United

Kingdom reform efforts, and Argentina benefitted from

the UK, and from Chile’s reform initiatives. However, the

particular electricity reforms in the three case-study countries were also guided by each country’s unique governmental structures and institutions, and by such characteristics as demographics, economic and political environments, and resource availability. These factors are

discussed briefly below and in more detail in the chapters

devoted to each of these countries.

A unitary, centralized form of government exists in the

United Kingdom. Governmental authority originates in

the crown. At the time that the United Kingdom embarked upon electricity reform, all policy decisions were

made at the national level. Electricity reform in the United

Kingdom was therefore carried out entirely by the ruling

(conservative) political party, which placed a strong

emphasis on aggressively privatizing electricity—as well

as several other major industries.

In contrast, both Argentina and Australia have a federalist

form of government (similar to that in the United States)

which is more oriented to regional, or state authority. In 2

contrast to the United Kingdom (but, again, very similar

to reform efforts in the United States), electricity reform

efforts in Argentina and Australia have had both a

national and a state component. 

Electricity reform in Australia was initially carried out by

separate state governments with different ruling political
4 Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Why Privatize?

Privatization has in part been driven by the increasing globalization of the world economy. Several decades of rapid growth in

international trade and investment have made competitiveness in international trade an essential factor in a nation’s ability to create

jobs, raise real wages, and generate wealth.

For many nations, privatization has become the only effective method of raising investment capital on favorable terms. High levels

of past public sector borrowing have saddled many nations with large levels of debt. As a consequence, these nations have had

little recourse but to sell state assets to reduce debt and to generate revenue.

Various businesses besides electricity have been privatized. Indeed, the largest privatization to date has been the sale of

Japanese Telecom for $73 billion. In the United Kingdom public housing has been privatized and, in the United States, many

municipal services, such as waste disposal, have been privatized. 

Although privatization efforts differ substantially from country to country, there is a strong common economic rationale underlying

the various decisions to privatize state energy resources. In general, nations have privatized state-owned electricity industries to

achieve one or more of several objectives. These objectives include: 1) raising revenue for the state; 2) raising investment capital

for the industry or company being privatized; 3) reducing government’s role in the economy; 4) promoting wider share ownership;

5) increasing efficiency; 6) introducing greater competition; and 7) exposing firms to market discipline. a

Privatization is closely connected with the development of the international energy company—a company whose focus is becoming

both more global and more multi-purpose. Until recently, outside of the world’s few major integrated oil companies, only a handful

of energy companies were considered multinational. Currently, in addition to the scores of petroleum companies that can now

be classified as multinational, the scope of many coal companies, petroleum pipeline companies, electric utilities, and power

generation equipment and construction companies has become increasingly global. Through consolidations, mergers,

acquisitions, and strategic alliances, the world’s energy companies have become both more integrated and more multinational.

Oil and gas companies have become electricity companies; domestic regional electric utilities have become multinational electricity

companies; electricity distribution companies have become generation companies; and generation companies have become

distribution and transmission companies. 

 

 The objectives of privatization listed above appeared in “Privatization: Learning from the UK Experience” (London, UK), Price a

Waterhouse, 1989. However, objective number two, “to raise investment capital for the privatized industry or company,” was added

by the authors of this report.

parties, resulting in significant variations among the The form of government existing in each of these nations

states. For instance, reform in the state of Victoria has, in also determined which level of government would

general, emphasized privatization of electricity, while achieve the largest financial gains from privatization. In

corporatization has been emphasized in the other states. Australia, state governments were able to erase large 3

Further, each Australian state has restructured its elec- deficits through the sell-off of electricity assets. In

tricity industry to a different extent, and each state has Argentina and the United Kingdom, it was the national

permitted a different degree of foreign investment. As a government that took in the receipts from such sales. 

result of the variety of state-implemented reforms,

Australia’s movement towards a national electricity A commitment to free market economics is also a relamarket has been more complicated than that of the United tively more recent development in Argentina than in

Kingdom. A national electricity pool began in May 1997, Australia and the United Kingdom. In the latter two 4

although the states initially participating were concen- nations, this commitment was not only made earlier, but

trated in the southeastern portion of the country. has generally strengthened in recent years. Argentina’s

Argentina’s constitution (based upon the U.S. constitu- past industry nationalizations) continue to taint it with a

tion) resulted in a federalist form of government very reputation as a relatively high-risk investment country.

similar to that of the United States. However, the federal Argentina’s current political instability also casts doubt

government in Argentina has been a more forceful upon the durability of its reforms and its creditworthiness.

catalyst in advancing electricity reform than the Federal Further, Argentina is different from Australia and the

government in the United States. United Kingdom in that Argentina is a developing nation

former heavy state hand in the national economy (and its
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 5

Two Methods of Calculating Foreign Investment

This report employed two methods to calculate U.S. companies’ investments in foreign electricity. Both methods have their

advantages and disadvantages. Figure ES1 is based upon foreign direct investment data reported by the U.S. Department of a

Commerce. Foreign direct investment (FDI) data has several benefits--one of which is to provide a historical perspective for recent

overseas investments in overseas utilities. In 1996, the U.S. Department of Commerce reported that the U.S. foreign direct

investment position in all overseas utilities totaled $10.3 billion. The use of a consistent statistical time series--such as the FDI

data--allows the reader to see (as shown in Figure ES1) that the total electricity investment value has grown considerably in recent

years.

However, as with most statistical data series, the foreign direct investment data have some limitations. For instance, these data

combine other smaller utility investments (natural gas, sewage, and water) with electric utility investments, and do not provide

country-specific detail. Also, the FDI data currently run through the year 1996, and, due to a reporting lag, may not include some

of the largest and most recent transactions. Further, FDI data measures net financial flows between parent and foreign

subsidiaries, and industry classifications of foreign-affiliated companies could ascribe some electricity investment activity to nonelectricity industries. Therefore, although the FDI data are useful for a time-series perspective, the factors just discussed may b

complicate the interpretation of FDI statistics, and the absence of 1997 transactions may cause the FDI data to underestimate c 

total U.S. electricity investment.

For these reasons, the individual country chapters of this report (chapters 2, 3, and 4) employ a different and more detailed method

of calculating U.S. company investment in foreign electricity. This method involves a review of individual company foreign

electricity investment transactions reported in the financial press, and avoids some of the limitations of the DIA statistics; but, it is

not without its own problems. In some cases, transaction data can overstate the extent of U.S. company investment. For instance,

where individual transactions involve a consortium of U.S. and foreign companies, and the U.S. is the lead investor (but specific

company investment shares are unknown), the entire investment’s value may be counted as the value of the U.S. company’s

investment. Also, transaction data often report investment commitments, instead of actual expenditures. Nonetheless, the

transaction compilation data (including transactions occurring in 1997) show that, since 1993, U.S. companies have committed

over $44 billion to the purchase of electric utility assets in Argentina, Australia, and the United Kingdom (UK) alone. The UK leads

as a target of U.S. company investment with over $25 billion committed thus far. Australia follows with a little under $15 billion in

commitments, and Argentina with roughly $4 billion. (For greater detail on U.S. company committed investments in Argentina,

Australia, and the UK’s electric utility industries, see chapters 2, 3, and 4.)

 

 The U.S. Department of Commerce, the agency which collects data on FDI, measures FDI as the book value of foreign direct a

investors’ equity interest in and net outstanding loans to their U.S. affiliates. The Department of Commerce defines a U.S. affiliate

as a U.S. business enterprise in which one foreign direct investor owns 10 percent or more of the voting securities or the

equivalent.

 For example, a large repayment in the reporting year to a parent company of debt incurred in an earlier acquisition can reduce b

FDI, even though FDI-related acquisition activity may have increased substantially in the reporting year.

cFor example, a highly diversified company’s overseas’ investments in electric utilities might be registered under its primary

standard industrial code (SIC) classification, which may be wholly unrelated to electricity.

where past investment in electricity has been insufficient. electricity sector. Since 1995, U.S.-based companies have

In contrast to the situation in Australia and the United acquired eight out of twelve recently-privatized electricity

Kingdom, electricity is expected to be a growth industry distribution companies in the United Kingdom. In the

in Argentina, although funding such growth may be aggregate, the value of these acquisitions was roughly $15

beyond the capabilities of the domestic capital market. As billion. In the Australian state of Victoria, all five of the

a consequence, while attracting foreign investment has recently-privatized electricity distribution companies

been a less important factor in electricity reform and were purchased by U.S. companies. Moreover, U.S.-based

privatization in Australia and the United Kingdom, it has companies have purchased shares in three of five

been a high priority in Argentina. recently-privatized Victorian electricity generation comSince the implementation of electricity reform, Australia largest foreign investors in electricity.

and the United Kingdom have both experienced a surge

in foreign investment in their electricity sectors. Despite For other reasons, Argentina is probably the most

its higher-risk profile, Argentina has also experienced a anomalous of the three countries. Both Australia and the

considerable increase in foreign investment in the United Kingdom are included among the world’s

panies. In Argentina, U.S. companies have also been the
6 Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

industrialized (or post-industrialized) economies. In both electricity prices prior to privatization were within the

nations, electricity is a mature industry and future growth bounds of the electricity prices of other industrialized

in electricity consumption is expected to trail Gross countries. The overall financial performance of the elecDomestic Product growth rates. Both countries have well- tricity industries in each of the three countries has genestablished capital markets and both countries had, prior erally improved subsequent to reform and privatization.

to privatization, invested ample funds in their electricity

industries. No country has embarked upon a more ambitious and

Another important distinction between the three countries

concerns stranded costs. In Argentina and the United 5

Kingdom, the issue of stranded costs (mostly those related

to nuclear investments) greatly complicated electricity

reform. In Australia (which shunned nuclear power from

the beginning), stranded costs were not an issue.

Australia also had a relative advantage in that its coal

industry is highly efficient by world standards. In

contrast, sustaining an uneconomic coal industry became

another source of stranded costs in the United Kingdom.

Different demographic and geographic characteristics

have also influenced the structure of the electricity industries in Argentina, Australia, and the United Kingdom.

Population density in the United Kingdom is fairly high

and relatively concentrated in dispersed urban areas, a

fact which more readily allows for the establishment of a

national transmission grid (which the United Kingdom

had even prior to its current era of electricity reform). In

Australia, population density is in general sparse, with the

exception of the southeastern portion of the country. As

a result, the establishment of an operational Australian

national grid in 1997 in its initial phase was limited

geographically to the southeastern portion of the continent. Currently, only New South Wales, Victoria, South

Australia, and the Australian Capital Territory are interconnected. Historically, there has been little interstate

trade in electricity. Argentina is similar to Australia in

that its overall population density is low, but there is a

high population concentration in a relatively small area.

In Argentina, one third of the nation’s 13 million people

reside in the Buenos Aires area. As a result, the development of an Argentine national grid has been piecemeal

and is still incomplete.

In all three countries, greater economic efficiencies in

electricity supply were important privatization goals.

Productivity was seen as being especially important in

Argentina, given that it had a particularly inefficient

electricity industry. In retrospect, however, the massive

reduction of the Australian and UK electricity industry

workforce in recent years (which occurred at the same

time as electricity production rose) indicates that the

electricity industries of these countries were substantially

overstaffed. Since the implementation of reform and

privatization measures, electricity prices in all three

countries have either declined or have lagged behind

overall inflation, even though both Australian and UK

6

extensive program of electricity privatization and reform

than the United Kingdom. In Argentina, state-wide

reform has clearly lagged reform at the national level, and

the degree to which electricity assets have been privatized

has not been as extensive as in the United Kingdom. In

contrast, reform in Australia has been more ambitious in

the state of Victoria and less ambitious in the other states

and at the national level. Nonetheless, all three countries

have opened their electricity industries to foreign

investors. Further, in all three countries, U.S.-based electric utilities have been the most prominent among foreign

investors. In particular, a handful of U.S. utilities have

been especially aggressive in investing in recently-privatized electricity companies in Argentina, Australia, and

the United Kingdom. In several cases, the same U.S.-

based utility has invested in electric utilities in two of the

three countries.

The Characteristics of

Investing Companies

The Energy Policy Act (EPAct), passed in 1992, liberalized

the rules governing U.S. utility investment in electricity

assets abroad. Somewhat over 20 U.S. companies, nearly

all publicly-traded electric utilities, have acquired assets

in either Argentina, Australia, or the United Kingdom in

recent years. However, a large majority of publiclytraded electric utilities have chosen not to invest abroad.

Insights as to the motivations for foreign investments in

electricity can be gained by contrasting the characteristics

of U.S. electricity companies investing abroad with other

U.S. electric utilities.

The companies with electricity investments in Argentina,

Australia, and the United Kingdom, through 1996, are

listed in Table 1. This group of companies was compared

to the group of all other publicly-traded companies classified as electric utilities (86 in number) (Appendix A). 7

Overall, the U.S. electricity companies that have invested

in foreign electricity assets in Argentina, Australia, and

the United Kingdom appear to have followed a strategy

of more rapid corporate growth compared to other electric

utilities. Based on net fixed assets (the value on companies’ balance sheets of property, plant, and equipment

adjusted for depreciation), foreign investing utilities grew

at a 2.7-percent annual rate from 1987 through 1992
Northeast Midwest Southeast Southwest Pacific

0

10

20

30

40

Percent

 Foreign Investors Others

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

30

35

40

45

50

Dividend Payout Ratio (percent)

Foreign Investors

Others

Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 7

Table 1. U.S. Utilities With Foreign Investments

U.S. Utility

American Electric Power

Calenergy Inc.

Central & South West Corp

Cinergy Corp

CMS Energy Corp

Dominion Resources Inc

Duke Power Co.

Edison International

Enron Corp

Entergy Corp

GPU Inc

Houston Industries

Northeast Utilities

Northern States Power

PacfiCorp

PG&E Corp

Public Service of Colorado

Southern Company

Southwestern Public SVC Co

Texas Utilities

 Source: Standard and Poors Compustat, July 1997.

Figure 1. Regional Distribution of Sales for

Foreign Investing Electric Utilities and

Other Electric Utilities, 1995

 Source: Standard and Poors, Compustat.

Figure 2. Dividend Payout Ratio of Foreign

Investing Electric Utilities and Other

Electric Utilities, 1987-1996

 Note: Dividend Payout Ratio = Cash Dividends as a Percent of

Cash Flow.

 Source: Standard and Poors Compustat.

(the year EPAct was passed), and at a 3.4- percent rate

since then. Other electric utilities, overall, grew at annual 8

rates of 1.5 percent and 1.0 percent over the same periods,

respectively. Unfortunately, data limitations prevent an

assessment of the role of foreign investment in the growth

in assets.9

The higher growth rates of electric utilities investing

abroad reflect the higher growth rates of the domestic

areas they serve. Over 50 percent of the sales of the

foreign investing group are based in the more rapidly

growing states of the Pacific Coast and Southwest (Figure

1). By contrast, over 70 percent of the total sales of other

electric utilities were in the slower growing Northeast and Despite the relatively smaller dividend payout, shareMidwest areas. holders appear to have increasingly favored the electric

Until recently, growth in the asset base of the foreign measure that tends to reflect investors’ views of a

investing group appeared to come at the expense of company’s earnings prospects is the market-to-book ratio.

dividend payouts to shareholders. Figure 2 shows that The market-to-book ratio is the market value of a

until 1990, the share of cash flow from operations company’s common shares divided by stockholders’

(sometimes called internal cash flow) paid out as divi- equity. Stockholders’ equity is assets minus liabilities as

dends averaged less than 40 percent compared to over 45 carried on a company’s balance sheet and represents the

percent for other electrical utilities overall. However, book value of ownership in the company. As stated in a

since 1991, dividend payout for both groups has declined, popular finance textbook, “the ratio of market-to-book

so that by 1996 both groups were allocating about 36 value...will be a good measure of the value created by the

percent of cash flow to dividends. firm for its shareholders because it equals the present

utilities that have invested abroad (Figure 3). A useful

10
1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

0

20

40

60

80

100

120

140

160

Percent

 Foreign Investors Others

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

7

8

9

10

11

12

Return on Equity (percent)

Foreign Investors

Others

0

8 Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Figure 3. Market-to-Book Ratio for Foreign

Investing Electric Utilities and Other

Electric Utilities, 1987-1996

 Note: Market-to-Book Ratio = Market Value of Common Shares

as a Percent of Stockholders' Equity.

 Source: Standard and Poors Compustat.

Figure 4. Return on Equity of Foreign Investing

Electric Utilities and Other Electric

Utilities, 1987-1996

 Note: Return on Equity = Net Income as a Percent of

Stockholders' Equity.

 Source: Standard and Poors Compustat.

value of the dollars that stockholders receive for each Although corporate growth may have reduced dividend

dollar they invest in the business.” payout to shareholders, investors overall appear to favor

Figure 3 shows the market-to-book ratios for the two strategies of other electric utilities.

groups of U.S. electricity companies (those that invested

abroad, and those that did not) over the 10-year period

1987 to 1996. In 1987, the year in which stock prices

crashed, the market value of each of the groups was only

88 percent of book value. Since then, the difference in the

market-to-book ratio between the foreign investing group

and other U.S. electric utilities has widened. The percent

difference increased sharply in 1992, from 6 percent in

1991 to 12 percent, and in 1995 and 1996 the difference

grew to 15 percent.

This latter pattern appears, at least in part, to reflect investors’ heightened economic expectations for what turned

out to be the companies that invested in electricity assets

in Argentina, Australia, and the United Kingdom. There

are at least two reasons for this view. First, the difference

in profitability of the two groups generally narrowed after

1991. Figure 4 presents an often-used measure of realized

profitability, i.e., return on equity (the ratio of net income

to stockholders’ equity), for the two groups of companies.

Although the foreign investing group’s return on equity

was noticeably greater in the 1987-to-1991 period, the

difference in the market-to-book ratio grew most in the

1992-to-1996 period when the difference in return on

equity between them and the other U.S. electric utilities

virtually disappeared. That is, investors’ expectations of

differences in future profitability, as reflected in the

market-to-book ratios, were growing even as the differences in current profitability were shrinking. Second,

although the market-to-book ratio for electric utilities in

total fell somewhat after 1993, the difference between the

foreign investing group and the other U.S. electric utilities

was at a maximum in 1995 and 1996, the years of peak

investment in electricity assets abroad, thus far.

In summary, the U.S. electricity companies investing in

electricity assets made available through privatization in

Argentina, Australia, and the United Kingdom have

pursued a strategy of corporate growth, compared with

other U.S. electric utilities overall. The foreign investing

group had a history of corporate growth prior to the

passage of EPAct in 1992 and have since continued to

grow, at least in part, through investment abroad.11

the strategies of the foreign investors compared with the
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 9

In an earlier Energy Information Administration report, entitled: Privatization and the Globalization of Energy Markets, EIA presented from a global 1

perspective an analysis of energy privatizations developments by country and by energy sector. This study included a section on regional reform and

privatization of electricity markets. This current report takes a more detailed look at three countries where electricity reform and privatization have been at

the forefront of such efforts globally. 

The Commonwealth of Australia, consists of six states and two territories. 2

Corporatization, as defined in Sally Hunt and Graham Shuttleworth’s “Competition and Choice in Electricity,” as “the formal and legal move from direct 3

government control to a legal corporation with separate management. This may be a government-owned corporation.”

However, an interesting byproduct of state-based reform effort is that it has induced a form of policy competition between states and a sort of follow-the- 4

leader type of reform. For instance, during the initial period of nationwide electricity reform, the most populous Australian state, New South Wales, was

opposed to fully privatizing its electricity sector, but later eventually became resigned to do so as it became clear that this would enhance New South Wales

electricity industries’ ability to compete in a national market with privatized electricity companies. 

Stranded costs are frequently defined as the value of unamortized investments in electricity assets that could not be recovered in a competitive marketplace 5

or the difference between market value and book value of these assets

In all three countries, some of the decline in electricity prices can be traced to lower fuel costs. However, a portion of the price decline can also be 6

attributable to the substantial non-fuel operating cost reductions made by these industries subsequent to their reform. 

The data are taken from filings of Form 10-K with The Securities and Exchange Commission as compiled by Compustat, a service of Standard & Poors. 7

Compustat, Standard and Poors (1997). 8

Only 6 of 20 companies separately reported domestic and foreign assets in 1996. 9

Alan C. Shapiro, Modern Corporate Finance (New York: Macmillan Publishing Company, 1990), p. 335. 10

Compustat, Standard and Poors (1997). 11

Endnotes
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 13

2. Electricity Restructuring, and

Privatization in the United Kingdom

The United Kingdom (UK) offers an interesting case study functional lines. Guiding the government’s restructuring

into the process of electricity industry restructuring, priva- was the idea that electricity generation and marketing

tization, and regulatory reform. The United Kingdom was could be made competitive industries, while transmission

one of the first nations to embark upon widespread and distribution needed to be treated as natural monoprivatization of its electric utilities. Although a growing polies for the indefinite future. Regulation would

number of nations have privatized their electricity indus- therefore gradually be withdrawn for the former segments

tries since (or are currently undertaking such efforts), the but remain for the latter. For the still regulated segments,

UK’s electricity privatization reform efforts have been a new form of regulation (based on a price cap) was introamong the world’s most ambitious and path breaking. duced—along with a new regulatory authority, the Office

Several other nations have subsequently followed their of Energy Regulation (OFFER). On Vesting Day (April 1,

example, using the UK experience as a policy guide in 1990) a newly-created electricity industry emerged.

their own electricity restructuring, privatization, and

regulatory reform efforts. In particular, Argentina and The creation of a national wholesale electricity pool was

Australia have adopted variations of the UK model (as another important area where the United Kingdom

will be discussed in Chapters 3 and 4). charted new ground in electricity reform. As in the United

Electricity privatization in the United Kingdom has reform in the United Kingdom was how to allocate the

occurred in the larger context of the privatization of much financial burdens associated with stranded costs. (For a

of the formerly state-owned UK industries and the discussion on stranded costs associated with electricity in

diminution of the central government’s role in the the United Kingdom, see the box entitled “Nuclear Power

national economy. The overall privatization of industry and the Issue of Stranded Costs.”) Stranded costs in the

was initiated shortly after a conservative government United Kingdom resulted largely from earlier investments

came to power in the United Kingdom in 1979 under the in nuclear power and an overhang of high-priced coal

leadership of Margaret Thatcher. A primary aim of the contracts. 

new administration was to reduce government’s role in

the economy. This goal has clearly been achieved. The Although UK electricity reforms are not yet a decade old,

share of employment accounted for by state-owned some general assessments can be made regarding their

industries fell from 7 percent of total UK employment performance. In terms of efficiency, the reform of the

prior to privatization to less than 2 percent currently. electric industry in the United Kingdom is generally 1

Partly due to the fact that the electricity industry strongly is markedly more efficient than it was prior to prireflects the features of a natural monopoly, electricity was vatization. However, where issues of fairness and equity

among the last and more controversial privatizations. are concerned, the industry reforms have been conBritish Aerospace was the first large industry to be auc- troversial. The new system has been criticized for unfairly

tioned off in 1981, followed by Cables and Wireless (1981), and disproportionately benefiting industry shareholders

and by British Telecommunications (1984). Soon after- and corporate executives over taxpayers, rate payers, and

wards, British Gas (1986), British Airways (1987), British electricity industry employees. The auction of electricity

Steel (1988), and British water utilities (1989) were priva- assets to the general public was criticized for failing to

tized. More recently, British Coal was privatized in 1995, obtain the full value of the assets offered for the treasury.

and British Rail in 1996. As of 1995, the United Kingdom Further, a large share of the industry’s efficiency gains

has raised over $95 billion through privatization. was realized through massive workforce reductions. The 2

Electricity privatization and reform got off to a relatively were awarded substantial pay raises in the midst of these

late start in the United Kingdom, having its origins in the workforce reductions added to the controversy.

passage of the UK’s Electricity Act of 1989. The industry Although electricity prices have generally trailed inflation

was initially restructured by the government along in the intervening years since electricity reforms were

3

4

States, a major complication surrounding electricity

viewed as a success. By any measure, the current industry

fact that the heads of the newly-privatized companies

5
14 Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Nuclear Power and the Issue of Stranded Costs

The United Kingdom was one of the first countries to employ nuclear power in electricity generation. The first nuclear power plant,

the Calder Hall unit, was connected to the national electricity grid in 1956. In 1995, nuclear power accounted for 26 percent of all

electricity generated in the United Kingdom. 

As in the United States, most of the UK electric utility industry’s stranded costs stem from past investments in nuclear energy. This

is largely due to large cost overruns in the construction of nuclear facilities and to unforeseen spent-fuel reprocessing and disposal

liabilities, as well as decommissioning costs. Unlike the United States, however, British nuclear power—up to the time of 1

privatization—had always been publicly owned. Hence, the issue in the United Kingdom of who should bear the burden of

stranded costs was between rate payers or tax payers. In contrast, in the United States, the issue of allocating the burden of

nuclear energy stranded costs is between rate payers and share holders. Stranded costs are frequently defined as the value of

unamortized investments in electricity assets that could not be recovered in a competitive marketplace, or the difference between

the market value and the book value of these assets.

In part, the UK public underwrote a share of the nuclear industry’s stranded costs the moment it became apparent that the market

value of nuclear assets was far less than their book value. The original UK privatization plan intended to couple nuclear power

plants with the thermal power assets of National Power (which was later to become a privately-owned generation company in the

United Kingdom), and then to auction off the company to the public. However, as nuclear power’s high cost structure, spent-fuel

reprocessing and disposal liabilities, and decommissioning costs became more apparent, the financial viability of nuclear plants

became questionable. Plants build three additional nuclear power plants also raised concerns over the future liabilities of the

nuclear power industry. In November of 1989, the UK government announced that the auction of nuclear power assets would be

put on hold, and all new construction of nuclear power plants was canceled. In order to sustain the industry until it could be

eventually privatized, the government specified quantities of nuclear electricity that each of the regional electricity distribution

companies were required to purchase. In 1990, a non-fossil fuel levy of 10 percent of total electricity revenue was put in place.

This levy, used to reimburse the regional electricity distribution companies for their purchases of nuclear electricity at above market

rates, was to last until 1998. Ninety-one percent of the levy was allotted to nuclear and 9 percent to renewables (such as wind

power and biomass). The levy in essence placed a portion of the nuclear industry’s stranded costs onto electricity consumers.

The permanency of this subsidy, however, was in doubt a factor that continued to jeopardize the nuclear power industry’s viability

with investors.

Subsequently, the British government decided that only the country’s most advanced nuclear power reactors could be privatized

successfully. These included five advanced gas-cooled reactors in England, two advanced gas-cooled reactors in Scotland, and

one pressurized water reactor in England. Older reactors, using what is known as Magnox technology, were to be retained by the

UK government as a public corporation and operated by British Nuclear Fuel, a state-owned nuclear fuel cycle and waste disposal

company. When nuclear power was finally auctioned in July 1996 (creating the company British Energy), the $2.2 billion raised

during the auction equaled only the approximate cost of just one of the company’s most recently completed nuclear power plants.

The remaining costs-—the stranded costs—stayed with the government. When British Energy was privatized, its share of the nonfossil fuel levy payment was also terminated. As a result, the overall levy assessment on electricity consumers was dropped from

10 percent to 3.7 percent. 

In 1995, British Energy accounted for 18 percent of the UK’s electricity supply (British Nuclear Fuel accounted for the remaining

8 percent of electricity supplied by nuclear power). Unlike other electricity privatization underwriting, there was no windfall to 2

investors in the sell off of British Energy. In the first day of trading, British Energy share prices fell 10 percent. 3

 

Other stranded costs include the long-term coal contracts entered into by UK electric utilities. These are discussed in the box 1

entitled: “The Demise of the UK Coal Industry and the Dash to Gas.”

UK Electricity Association, Electricity Industry Review (January 1997), p. 33. 2

”Investors Burn Fingers in Nuclear Sell-off,” The Guardian (July 16, 1997), p. 3. 3

implemented in 1990, electricity consumers have often felt Privatization of electricity in the United Kingdom did not

less well treated than industry shareholders, who have occur all at once. It evolved. The following sections

realized profits well beyond those reported for UK describe important developments and trends in the UK

industry in general over the same period of time. electricity industry—from its fruition in the last century,
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 15

through the period of nationalization, and up to the during the 1970's, the ruling labor party put pressure on

current period of industry restructuring, regulatory the electricity industry to restrain prices in order to reduce

reform, and privatization. The problems encountered general inflation. During the 1980's, after the conservative

during the period of nationalization are discussed first, party took power, the industry was urged to increase

followed by a discussion of what has transpired since prices in order to reduce public borrowings. Several

recent reforms were undertaken. currency crises and two oil price shocks encouraged the

The Structure of UK Electricity

Prior to Privatization

The central government’s role in electricity has grown industry—which by the early 1990's had grown vastly

gradually since the industry’s beginning in the latter part inefficient by world standards. Beginning in 1957, in an

of the nineteenth century. The Electricity Lighting Act attempt to support the coal industry, utilities were

(1882) allowed the central government to break up streets continually pressured to purchase set quantities of British

for laying of electrical cable. The national government coal. Eventually, a more formalized arrangement emerged

established an Electricity Generation Board in 1926 whose whereby utilities were required to purchase set amounts

mission was to construct a national transmission grid, to from the nationalized coal industry at predetermined

coordinate the transmission of electricity across the coun- prices. Since electric utilities were required to pay above

try, and to establish a set of common technological world prices for British-produced coal, electricity prices

standards. became excessively high, and the British coal industry in 6

In 1947, the electricity industry—along with several other its survival. 

“key” industries—was nationalized by the UK’s post-war

labor government. All segments of the industry became Another major policy goal of the UK government since the

government owned and operated. So the newly- 1950's was the promotion of nuclear power as a secure

nationalized electricity company comprised most of the and economical source of electricity. Nuclear power has

country’s generation capacity, the national grid, as well as also generally been a target of large government-imposed

the 12 semi-autonomous regional distribution boards in subsidies, again underwritten by the electric utility

England and Wales, two vertically-integrated companies industry. As elsewhere in the world, when the United

in Scotland, and one vertically-integrated company in Kingdom embarked upon its nuclear power program,

Northern Ireland. nuclear power was perceived as an economically viable

The role of central government in electricity was extended security. In reality, nuclear power’s full costs have far

further with the Electricity Act of 1957. This act estab- exceeded the costs of non-nuclear forms of electricity

lished a Central Electricity Generating Board (CEGB) generation.

whose responsibilities included control over the operation 

of electricity generation and transmission facilities and all In the 1960's and 1970's, several attempts by the governrelated investment decisions. The twelve regional elec- ment at reforming the electricity industry were made.

tricity boards remained semi-autonomous. An Electricity However, due to both a lack of commitment and to

Council acted as a form of regulator. The council con- political turnover, these efforts largely proved unsucsisted of three representatives of the CEGB, the twelve cessful. By the 1970's, the United Kingdom experienced

regional Area Board Chairmen, and six independent several economic setbacks, many of which were attributed

members, appointed by the presiding governing Mini- to an excessive state role in the economy. A growing

ster. The regulatory method used employed an inexact disappointment with the general quality of services 7

and controversial measure of long-run marginal cost in provided by nationalized companies, along with the

order to construct a bulk supply tariff, the price charged nationalized companies’ growing financial difficulties,

to the distribution companies by the CEGB. greatly diminished UK public perception of the viability

Between 1947 and 1990—the period of nationalization— owned companies approached financial insolvency

the two major competing national ruling political parties involving several costly government bailouts.

pursued various and often conflicting energy policies.

Often electricity policy directives were guided by some The election of the Thatcher government in 1979 marked

overriding macroeconomic objective. For example, a major watershed in British politics and economic policy. 8

electric industry to rely more heavily on domestic coal

(and not imported crude oil) and to further the development of nuclear power. 

A major UK government policy goal for roughly forty

years has been the sustenance of the national coal

essence became dependent on the electricity industry for

form of energy and as a means of achieving energy

of several state-run industries. At the time, many state-
National Electricity Grid and Pool

Regional 

Electricity

Companies

Generators/

Suppliers

Other

Licensed

Suppliers

Generators/

Suppliers

Other

Licensed

Suppliers

Small Users (<100kW)

Franchise Market, Till 1998

National 

Power Powergen Independent

Generators

Magnox

Electric Others

Electricity

de

France

Scotish 

Hydro

Electric

Large Users (>100kW)

Non-Franchise Market Small Users

(<100 kW)

Large Users

(> 100 kW)

British 

Energy

Scottish

 Nuclear

Nuclear

Energy

Scottish

Power

British Energy

England & Wales Scotland

16 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Figure 5. Structure of the UK Electric Power Industry

 Source: Department of Trade and Industry, Digest of United Kingdom Energy Statistics, 1996.

Privatization became an important element in the independent power sector did not occur until several

Thatcher government’s overall economic program. Pri- years later. Initially, the low rates of return that the CEGB

vatization of nationalized industries was intended to allowed incumbent power producers discouraged entry of

achieve several goals. Foremost among them were to new producers. Further, the 1983 Electricity Act did not

reduce the central government’s role in economic decision entirely remove the unfair access to the grid that inmaking; to force privatized companies to become more cumbent power producers had over new entrants. The

accountable to owners; to increase net state revenue evolution of a UK independent power production

through asset sales and divestiture of fiscally draining industry—along with the complete transformation of the

state enterprises; and to encourage the creation of a share- UK electricity industry as a whole—would await passage

holder society through widespread stock ownership. of an omnibus piece of electricity legislation which

The Electricity Act of 1983

One of the first acts of electricity reform by the Thatcher

government was passage of the Electricity Act of 1983.

Similar to the Public Utility Regulatory Policy Act (1978)

and the Energy Policy Act (1992) passed in the United

States, the Electricity Act of 1983 was designed to encourage the growth of independent power producers. It

was meant to remove barriers to entry to non-utility

generators and to provide independent producers of

electricity open access to the national grid. Prior to the

1983 act, entry to the industry was prohibited. The Act

required the Central Electricity Generation Board to purchase electricity from private producers at avoided costs,

that is, at a price equal to the costs the board would have

incurred to produce the same quantity of electricity itself.

The Electricity Act of 1983 was a relatively minor first step

toward privatizing and deregulating electricity in the

United Kingdom. The establishment of a sizable

9

10

followed six years later.

The Electricity Act of 1989

Restructuring. In July of 1989, the UK Electricity Act of

1989 was signed into law. One of the most important

elements of privatization involved the restructuring of the

industry prior to its sale. Initially, the former Central

Electricity Generating Board was restructured into four

separate organizations: two power producers, a transmission company, and a distribution network consisting

of the twelve regional electricity companies (RECs)

created out of the twelve former regional area boards.11

All segments were to initially remain under government

ownership, and privatization was to proceed in stages.

The current structure of the UK electricity industry

resulted from this process and is depicted in Figure 5.12

The Central Generating Board’s non-nuclear power units

were assigned to two companies, National Power and

PowerGen, both slated to be privatized. National Power
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 17

Table 2. Share of UK Electricity Generation for

Fiscal Years 1990-2001

(Percent)

Company(s) 1990/1991 1995/1996 2000/2001

National 

 Power . . . . 46 31 21

PowerGen . 28 23 17

Nuclear 

 Electric . . . 17 22 24

Independents 1 14 21

Others . . . . 8 10 17

 Note: The data for 1990/1991, 1995/1996, and 2000/2001

correspond to the United Kingdom’s fiscal year, which ends on

March 31 of each year.

 Source: Electricity Industry Review, Electricity Association,

London, England (January 1997).

The Electricity Industries in Scotland and Northern Ireland

Electric industry reform was much more modest in Scotland and Northern Ireland than in England and Wales.

 In Scotland there are three main electricity companies: Scottish Power, Hydro Electric, and Scottish Nuclear. Scottish Power and

Hydro Electric are integrated companies supplying generation, transmission, distribution, and marketing services. Scottish Nuclear

is the Scottish subsidiary of British Energy. Although Scottish Power and Hydro Electric are vertically integrated, the privatized

companies are required to operate each of their different segments independently with no cross subsidization. 

A representative of OFFER—the British Office of Electricity Regulation—serves as regulator to the Scottish Electric system and

a productivity/performance-based price cap is applied to all segments of the industry.

Northern Ireland operates its newly-privatized electricity industry in a manner similar to the manner in which Scotland operates its

electricity industry. Prior to privatization, the vertically-integrated national utility company, Northern Ireland Electricity, provided

generation, transmission, and distribution services. During the privatization of Northern Ireland Electricity, the company’s four

generation units were separately sold off to private energy companies and to employees. The remaining transmission and

distribution portion of Northern Ireland Electricity was sold to shareholders intact in 1993. The regulator in Northern Ireland

(OFREG) is similar to OFFER. The OFREG regulates generation by using a merit order dispatch operation, where system marginal

price becomes the price of the most expensive unit needed to be brought on line in order to meet demand. At the present, the

creation of an electricity pool is being considered.

was the larger of the two generation companies and to be a separation between the wires (distribution) side of

accounted for 46 percent of electricity supplied in England the RECs’ business (which was to be continually reguand Wales in the 1990/1991 fiscal year time period (Table lated) and the marketing function of the RECs (which was

2). At the time, PowerGen accounted for 28 percent of to be gradually deregulated). The RECs were also the first 13

generation output. segment auctioned off to the public by the UK govern- 14

Ownership of the national grid was initially transferred to

the RECs upon their privatization. However, in December

1995, the RECs were required by the UK government to

divest their shares in the national grid, at which time it

became a separate publicly-traded company, the National

Grid Company.

The twelve regional electricity distribution companies

initially created out of the former Regional Area Boards

underwent more changes. In regulatory matters there was

ment. These were sold in December of 1990. 

Shares in the two power generation companies (National

Power and PowerGen) were sold to the public soon afterward, in March of 1991.

Northern Ireland and Scotland’s electricity industries

were restructured at about the same time as the industries

in England and Wales. However, Northern Ireland and

Scotland, taken together, account for only about 12

percent of the UK electricity market. (For a discussion on

the Scottish and Northern Ireland electricity restructuring,

see the box entitled: “The Electricity Industries in Scotland

and Northern Ireland.”)

In general, references to the UK electricity model in this

report address recent electricity developments in England

and Wales. A segmental description of reform and privatization of UK electricity follows.

Generation. In the United Kingdom, generation was

deemed an area where regulation was needed least of all

and where a competitive market could develop most

successfully. The only formal restrictions placed on the

newly-created private sector power companies was that

National Power and PowerGen sell their electricity to a

national wholesale pool. (For a discussion on the workings

of the power pool, see the section entitled: “The England

and Wales Power Pool.”) 
18 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

No specific price regulation was initially intended for Manweb. Apparently, due to Scottish Power’s

generation, as the pool was intended to produce market- geographical location, its acquisition of Manweb posed

based pricing. However, although OFFER’s mandate was less of a threat to competition than the takeover attempts

not to set pool prices, it had considerable influence over occurring in England proper. The other acquisition

National Power and PowerGen through its authority to involved Hanson’s purchase of generation assets from

refer cases involving monopolistic behavior to the National Power and PowerGen, shortly following

Monopoly and Mergers Commission (MMC). Concerns Hanson’s purchase of another REC, the Eastern Group.

over whether the generation business was sufficiently

competitive and was behaving as a duopoly caused An important means of leverage the government retained

OFFER to intervene several times after privatization. over the electricity industry after privatization was 15

In December 1993, a sharp increase in electricity pool generation companies and the twelve RECs. Since Vesting

prices prompted OFFER to reduce market concentration Day (April 1, 1990), the government had restricted any

in electricity supply by negotiating an agreement with single private entity’s ownership in the two generation

National Power and PowerGen whereby the two com- companies and the twelve RECs to a maximum stake of 15

panies would use their best efforts to sell off 6000 percent. For the RECs, the government’s “golden share”

megawatts of generating capacity—roughly 15 percent of expired in March of 1995. The government’s “golden

the companies’ combined capacity and 9 percent of total share” in the generation companies was extended in

UK electricity generation capacity. This objective was met March of 1991, and in May of 1996 the government

by both companies during the following year. Further, in indicated that it would retain its “golden share” in the two

February of 1994, OFFER proposed a cap on pool prices power generation companies indefinitely. 

which was implemented for the 1994/1996 fiscal year

time period, again due to concerns that the two generators

exercised undue influence in electricity supply. 

In late 1995, due to an eruption of mergers and acquisitions (discussed later in this chapter), the government

intervened again to prevent integration in the electricity

industry. The government’s primary concern was the

growing vertical industry concentration between domestic

generation and distribution companies. The two power

generation companies had each mounted takeover

attempts of two regional electric utilities. 

In the fall of 1995, National Power placed a bid for

Southern Electric (a REC), and PowerGen placed a bid for

Midlands Electricity (another REC). The Minister of

Trade, however, announced that both deals would be

referred to the MMC. When the MMC later approved the

two deals, the Minister of Trade decided to block them

anyway, announcing that, although he didn’t find vertical

integrations “inherently objectionable,” he was concerned

that “structural change could have an effect on the

development of competition in the industry.” At the 16

time, the Minister of Trade had the backing of OFFER.17

The Minister of Trade further stated that vertical

integration between generators and distributors might

pose “significant detriments to competitions.” The 18

disapproval of the National Power and PowerGen

takeover bids had the effect of aborting another potential

takeover, this time of National Power by Southern

Company, a U.S. electric utility. 

Two other acquisitions (both involving a REC and a

power company) went undeterred by the regulators. One

of these involved Scottish Power’s 1995 acquisition of

19

exercised through its “golden share” in the two power

Transmission. In contrast to generation, the UK’s transmission system was considered a natural monopoly (as

was distribution, which is discussed below). With the

breakup of the CEGB, all transmission assets fell under the

ownership of the National Grid Company (NGC). The

twelve RECs assumed ownership of the NGC, although

safeguards were put in place to restrict the RECs’

influence over managing the grid. In addition to providing electricity transportation services throughout

England and Wales, the NGC also supported the mechanism from which electricity supply and demand were

balanced: the England and Wales Electricity Pool (“the

pool”). 

The pool requires that electric power generators whose

capacity exceeds 100 megawatts are required to submit

their generation units to dispatch by the NGC. The UK

adopted a form of price cap regulation for transmission

services known as RPI-X. RPI-X essentially imposed

periodic price reviews and price caps based on changes in

the overall rate of inflation (as measured by the retail

price index (RPI)) less expected future productivity gains

(the X). (For a review of RPI-X regulatory rate reform, see

the section entitled: “RPI-X: Price Caps versus Rate of

Return Regulation.”) Initially, the NGC owned some

generation capacity. However, in 1995, the regulator

required the NGC to sell off its two hydroelectric pumped

storage generation assets over concerns that vertical

integration in generation and transmission hindered

competition. The NGC sold its generation assets to

Mission Energy (a subsidiary of Edison International,

which also owns Southern California Edison) in January

of 1996. Further competition-related concerns encouraged

the regulator to require the RECs to sell off their shares in
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 19

Table 3. Regional Electricity Distribution

Companies in the United Kingdom

Ranked by Electricity Distributed,

Fiscal Year 1994/1995

Company

Electricity Distributed

(GWh)

Eastern Group ........... 29,898

Southern Electric ......... 26,808

Midlands Electricity ....... 24,709

East Midlands Electricity . . . 24,156

Yorkshire Electricity ....... 22,631

NORWEB ............... 22,076

London Electricity ........ 19,666

Manweb ................ 18,485

SEEBOARD ............. 17,655

Northern Electric ......... 14,950

SWEB .................. 12,979

SWALEC ............... 11,164

 In the United Kingdom, costs associated with the a

privatized, deregulated electricity industry are often

expressed in budgetary time periods (i.e., April 1 to April 1

fiscal years) and not calender year time periods. Thus,

1994/1995 is April 1, 1994 to April 1, 1995.

 Source: Department of Trade and Industry, Digest of

United Kingdom Energy Statistics (1996) p. 98.

the NGC in December of 1995, thus making the NGC a Since privatization, the distribution companies have been

separate company under the new name, National Energy allowed to acquire generation assets with the restriction

Group PLC. that no REC generation facilities account for more than 15

Distribution. Since privatization, electricity distribution

in England and Wales has been managed by the twelve

RECs (Table 3). The wires (distribution) side of the RECs’

business was to be regulated indefinitely. The marketing

side of the industry was to be deregulated gradually.

The distribution side of the RECs’ business was also to be company unaffiliated with their local REC. As of 1996, 39

regulated through an RPI-X form of price regulation. The second-tier suppliers have entered the market. These

franchised marketing portions of the RECs’ business second-tier suppliers include several RECs operating 20

segments were to be regulated in a similar fashion, albeit outside of their franchised distribution territories, as well

with a different productivity factor (“X”) and a different as the newly-created electricity marketing units of the two

regulatory time frame. On Vesting Day, the government privatized generation companies, National Power and

provided the RECs with price caps ranging from a high of PowerGen. Due to concerns relating to maintaining

zero to a negative “X” of 2.5 percent. Negative “X” (that competition, however, the generators (as well as the RECs)

is, an apparent allowance for annual rates of productivity were required to establish separate marketing units.

decreases of X percent) factors were chosen in order to

provide the industry with sufficient future cash flow in It appears that deregulation has given rise to greater

part to meet projected future investment needs and also to competition in the marketing end of the electricity market.

increase the attractiveness of the companies to the In the aftermath of the opening up of the industrial

investment community during their upcoming public market to competition, the newly-formed second tier

auction. The initial regulatory timeframe was set at the suppliers have made substantial inroads into what had

fiscal year 1990/1995 time period. been a captive market for the RECs. Since Vesting, the

percent of their individual electricity sales. This action

was taken in order to introduce more competition in

generation. Allowing individual RECs to produce their

own electric power led to a surge in REC investment in

independent power producers, whose preferred method

of generation was the combined cycle natural gas turbine.

(For a discussion on natural gas and electric power

developments in the United Kingdom, see the section

“Natural Gas Privatization in the United Kingdom.”) The

RECs are, however, required to separate, in an accounting

way (or by a “ring fence” as it is termed in the United

Kingdom), their marketing business from their distribution business. 

Marketing. As stated earlier, the marketing segment of

the electricity industry along with generation was

considered to be potentially competitive. However, marketing (unlike generation where market-based prices are

set in the electricity pool) is being gradually deregulated.

On Vesting Day, large users of electricity (the newlycreated non-franchised market) were allowed to choose

their marketers, as opposed to being required to purchase

electricity from their REC. This group—the large

users—consisted largely of a relatively small number of

industrial companies (Table 4). The RECs were allowed 21

to retain their franchise in the mid-user market (the small

industrial and commercial companies) until April 1994.22

The RECs must compete for the remaining franchised

consumers (primarily residential users) in April of 1998. 23

The Electricity Act of 1989 thus encouraged competition

in marketing by opening the large-user portion of this end

of the electricity business to new entrants. While the RECs

still had captive rights to all other consumers, large users

were free to purchase electricity services from their local

RECs’ newly created marketing segment, or from a second

tier marketing company, i.e., a newly-created marketing
20 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Table 4. The Incremental Deregulation of the End-User Electricity Market

Customer Date of Deregulation Number of Customers Percent of Demand

Large Industrial ................... April 1990 5,000 30

Small Industrial/Commercial ......... April 1994 45,000 20

Residential ....................... April 1998 22,000,000 50

 Source: Steve Thomas, “The Development of Competition, ”The British Electricity Privatization Experiment, Privatization: The

Record, the Issues, the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 69.

Table 5. Non-Franchise Market Shares in England and Wales

Percent of Electricity Supplied

Large Industrial Small Industrial/Commercial

Electricity Supplier 1990/1991 1994/1995 1995/1996 1994/1995 1995/1996

RECs ( First Tier) . . . . . . 57 37 31 70 57

Second Tier . . . . . . . . . . 43 63 69 30 43

 Total ............... 100 100 100 100 100 

 Note: The data correspond to the United Kingdom’s fiscal year, which ends on March 31.

 Source: Electricity Industry Review, Electricity Association, (London, England, January 1997).

Table 6. Share of Component of Electricity Costs for Different Classes of End Users

Customer Profile

Generation

Costs

Transmission

Costs

Distribution

Costs

Marketing

Costs Total

Large Industrial . . . . . . . . . . . 77 5 17 1 100

Small 

Industrial/Commercial . . . . . . 66 6 24 4 100

Residential . . . . . . . . . . . . . . . 58 5 29 8 100

 Source: Mike Parker, “Competition: the Continuing Issues, ” The British Electricity Privatization Experiment, Privatization: The

Record, the Issues, the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 217.

second-tier companies have seen their share of the large service standards were placed on the industry by OFFER

industrial market climb from 43 percent in the 1990/1991 during the initial privatization phase. These standards

period to 69 percent in the 1995/1996 period (Table 5). were later tightened in 1993 and 1994. RECs are required

This occurred despite the fact that marketing costs for the to offer various special services to the elderly and

large industrial customers are very small relative to the disabled. Service standards also were directed to bill

costs of generation (Table 6). Newly-formed marketing payment, meter reading, and speedy responses to

companies have also made substantial gains in the 100 complaints.

kilowatts to 1 megawatt market. In the mid-range commercial and small industrial company market, the second- It is not clear whether the second-tier marketing comtier companies’ share has risen from 30 percent in the panies will be as successful at encroaching on the RECs’

1994/1995 fiscal year time period to 43 percent in the share of the residential market as they were in the large1995/1996 fiscal year time period. to-mid-level user market. Even though marketing costs to

Another area of continued regulation of the retail electri- account for a relatively large portion of their overall

city business in the United Kingdom concerned services electricity bill, the residential market is expected to be a

standards. Although services provided by the electric more difficult market to break into. This is largely due to

industry in the United Kingdom were generally con- the high estimated costs (such as in advertising) which

sidered reliable even prior to reform, higher quality of would need to be incurred to encourage small consumers

residential users (unlike industrial and commercial users)
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 21

to switch suppliers. With unbundled electricity rates, attempts to measure the “extent to which generators are

different classes of consumers face different price prepared to invest in additional capacity in excess of the

schedules. For instance, industrial users have a tendency actual maximum on the system.” The LOLP simply

to face a cost structure where the share of generation costs measures the probability that supply will be insufficient

relative to total costs far exceed that of smaller users. In to meet demand at a particular point in time.

contrast, residential and mid-level users face disproportionately higher distribution and marketing costs. The The LOLP changes over the course of the year and the

transmission cost portion of final electricity bills tend to be course of the day. The closer demand is to scheduled

uniform across all classes of consumers. supply, the higher the LOLP and therefore the higher the

The England and Wales Power Pool

In order to balance electricity supply and demand, the UK

government instituted a power pool to act as a clearinghouse between suppliers of electricity (generators) and

wholesale consumers of electricity (primarily the regional

electricity distribution companies). The pool is open to all

generators and consumers wishing to participate. 

Those electric power generators whose capacity exceeds

100 megawatts are required to submit their generation

units to dispatch by the National Grid Company (NGC).

The NGC manages and operates the pool with an independent facility that attempts to balance supply and

demand with an auction which roughly operates in the

following manner. In the power pool every day is broken

up into forty-eight half-hour segments. The system

manager forecasts demand for each half-hour segment.

Twenty-four hours in advance, generators submit bids for

the various levels of power they are willing to supply at

various prices and for various periods, for each half-hour

period of the following day. The system manager then

ranks these bids from least to most expensive. The system

manager also calculates the minimum amount of generating capacity needed to meet demand projections. A merit

order dispatch schedule is created whereby the cheapest

generation units are selected first and supply is capped

when enough generation units are selected into the system

to cause generation capacity to be sufficient to supply one

unit of energy over and above the forecasted demand.24

The pool purchase price for all suppliers becomes the

highest price bid by the last generation facility needed to

accommodate the last unit of demand. This balancing

activity is an attempt to arrive at the electricity generation

industry’s marginal cost, or the system marginal price

(SMP).

The price actually paid to generators also includes a

financial incentive for maintaining some additional (peak

load) generation capacity in the event that demand exceeds consumption forecasts. This capacity payment

equals the value of lost load (VOLL) times the loss of load

probability (LOLP). The VOLL attempts to measure the

system cost of not producing enough electricity to meet

peak load. Another way of looking at VOLL is that it

25

capacity payment. The price paid to electricity suppliers

is the pool input price (PIP), which equals SMP + (VOLL

* LOLP). The price paid by purchasers is the pool output

price (POP), which equals the PIP plus an uplift charge,

calculated to cover certain ancillary functions, such as

reserve plant availability, forecasting errors, transmission

constraints, and marginal plant adjustments.26

In practice, electricity prices in the England and Wales

electricity pool have proven to be very volatile and subject

to possible manipulation. Over time there have been

several allegations that, due to their dominant position in

the pool, National Power and PowerGen have been able

to manipulate pool prices. According to these allega- 27,28

tions, ownership of some relatively high-cost marginal

plants have enabled the two dominant utilities to attempt

to ensure that these units are offered up to the pool in

such a way that they determine the SMP. The fact that

both companies were once the same company suggests

that each possesses an intimate understanding of the

other’s cost structure. 

Thus, as a means of controlling price volatility, a hedging

market has developed. This market (called the contract for

differences market [CfD]) allows for bilateral contracts to

be negotiated between generators and consumers.29

The CfD evolved from contractual relations imposed on

the industry by the UK government at Vesting Day (April

1, 1990). At the time, the two recently-privatized UK

generation companies (National Power and PowerGen)

were encumbered with contracts to purchase high-price

British coal. In order to prevent other electricity generation companies (such as the recently-created independent

power-producing companies) from capitalizing on this

disadvantage, the regional electricity companies were

required to purchase power from the two primary

generation companies. 

In the CfD market, generators and electricity purchasers

can hedge pool prices by committing to a contract with an

agreed-upon price, (the strike price). The strike price, for

instance, may be set at an average of expected daily pool

prices. If the strike price turns out to be higher than the

daily average pool price, then the generator pays the

purchaser the difference. Conversely, if the strike price

turns out lower than the daily average pool price, the
22 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

electricity purchaser reimburses the generator for the Price-cap regulation has been the common means of

difference. In reality the CfD market uses a variety of regulation for the recently privatized industries in the

different hedging contracts. Contracts for differences are United Kingdom. For several reasons, rate-of-return

purely financial contracts; however, in terms of hedging regulation was rejected in the United Kingdom. For one,

pool prices, they cover more than 90 percent of the obtaining detailed industry data was deemed an exceselectricity traded in the pool. Nonetheless, pool prices sively expensive effort that would require a large bureau- 30

have still continued to be a source of controversy. cratic structure. Further, it was felt that regulators would

In February of 1994, in response to a sharp run up in pool information the regulator obtained from the regulated

prices in April of 1993, OFFER issued its first report on industry was always incomplete relative to the inforpool pricing activity. The report called for a two-year mation possessed by the industry, leaving the regulator in

price cap and required National Power and PowerGen to an inferior negotiating position relative to that of the

sell off 6000 megawatts of generation capacity. Since industry. Moreover, as stated earlier, rate-of-return

February of 1994, OFFER has issued five reports on pool regulation offered insufficient incentives for the utilities

pricing. themselves to reduce costs aggressively. 31

RPI-X: Price Caps Versus

Rate-of-Return Regulation

Price-cap regulation is generally viewed as a relatively

recent form of regulation, and is most frequently associated with the ongoing regulatory reform and privatization

in the United Kingdom. In contrast, rate-of-return regulation is the most commonly used form of utility regulation

in the United States, and has been in use for decades.

Both forms of regulation, however, attempt to accomplish

the same goal: to reduce the power of natural mono- In essence, RPI-X employs price caps which allow indivipolies to restrain output, raise prices, and realize supra dual utilities (or companies) discretion over all investment 32

normal profits. In theory, the way the two regulatory and operating decisions. In contrast to rate-of-return remethods accomplishes these goals differs considerably. In gulation, utilities in the United Kingdom realize all gains

practice, however, the methods have tended to converge. from efficiencies achieved beyond the established benchRate-of-return regulation is also called cost-of-service lation has not only been employed in the electricity sector

regulation in that it essentially allows companies to pass but also has been applied to the recently privatized telethrough those costs which are deemed necessary by the communications, natural gas, and water industries. For

supervising regulatory body to ensure that an adequate expository purposes, a generalized form of RPI-X pricelevel of service is provided to end users. During periodic cap regulation works the following way:

regulatory reviews, expenditures that are deemed appropriate by the regulatory body are added to the rate base. Let us suppose t is our base year and p are electricity

In order that appropriate levels of capital investment are prices in the base year. The RPI in RPI-X regulation

undertaken, supervising regulatory bodies (in the United represents the change in the retail price index in the

States, these are generally State public utility com- United Kingdom and is a measurement similar to the

missions) estimate appropriate rates of return for the Consumer Price Index (CPI) in the United States. X is

regulated utility, based in part on the cost of capital to the generally considered to be a productivity factor, which

utility. could be positive if the industry is expected to operate

Rate-of-return regulation has both its virtues and its declines are expected. The productivity factor, X, is

weaknesses. Rate-of-return regulation allows represen- based upon past performance and projected analysis of

tation of the public in matters regarding utility price future productivity gains. A third variable (let’s call it K)

setting, rates of return, and investment so that utilities could be added to the equation to account for all costs

cannot restrain supply and realize monopoly profits. over which a regulated company had no control (exoHowever, rate-of-return regulation offers utilities few genous costs), allowing, for instance, an electricity

financial incentives to aggressively restrain or reduce company to directly pass through all costs related to

operating costs. changes in energy prices (making our new equation, 33

always suffer from a disadvantage, given that any

To avoid these problems, the United Kingdom adopted

what was felt to be a hands off, less-bureaucratic, regulatory method based upon price caps and periodic

reviews. This new form of regulation often goes by the

name of RPI-X. RPI-X regulation is also often called

“performance-based regulation” in that it seeks to achieve

economic efficiency through altering the incentive structure of the industry.

How RPI-X Works in Theory

mark up until the next regulatory review. RPI-X regut

more efficiently in the future, or negative if efficiency 34

35
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 23

Table 7. The UK’s Office of Energy Regulation RPI-X Price Controls, and Review Periods 

Activity

Pricing

Method

Regulatory

Period Price Index

Segment

Regulated Unregulated

Generation .................. Pool NA NA None All

Transmission

Initial Control Period ........... RPI-X 4/90—4/93 RPI-0 All NA

Second Control Period ......... RPI-X 4/93—-4/97 RPI-3 All NA

Third Control Period ........... RPI-X 4/97—4/01 RPI-4 All NA

Distribution

Initial Control Period ........... RPI-X 4/90—4/95 Various RPI+X All NA

See Table 14. 

Interim Control Period .......... RPI-X 4/95—4/96 Various RPI-X All NA

Second Control Period ......... RPI-X 4/95—/00 RPI-3 All

Supply 

Initial Control Period ........... RPI-X 4/90—4/94 RPI-0 <1MW>100kW >1MW

<100kW

Second Control Period ......... RPI-X 4/94—4/98 RPI-2 <100kW <1MW>100kW

<100kW

Third Control Period ........... RPI-X 4/98—4/02 None None None

 NA = Not Available.

 Source: Electricity Association, Electricity Industry Review (January 1997).

assuming efficiency gains, RPI-X+K). Thus, maximum The chosen base price in the United Kingdom was directly

prices one year hence (P ) should equal: p = p + RPI- related to the asset value at the beginning of the initial t+1 t+1 t

X+K. regulatory period. The selected productivity factors

RPI-X regulation employs a multi-year review cycle. In transmission companies assigned an initial X of zero. For

the United Kingdom, depending on the industry being the twelve distribution companies, various X’s were

regulated, the review cycle has typically been from 3 to 5 applied, varying from zero to a positive top rate of plus

years. This allows companies to realize the benefits of 2.5. The franchised supply companies were assigned an

their cost reduction efforts over a set period of time, or initial X of zero. The regulatory cycles for the three

until the next review cycle comes due. Upon completion regulated industries have varied from 3 to 5 years.

of the regulatory cycle, the regulator conducts a new

review and redetermines new benchmarks both for the

initial set of prices and for projected future productivity

gains. The regulator is then able to pass on some of the

benefits of the realized efficiency gains to consumers.

In England and Wales, RPI-X regulation has been applied

only to those segments of the industry still deemed natural monopolies (or not ready for complete competition).

These segments are basically the wires (electricity transmission and distribution) portion of the business (Table 7).

RPI-X is not applied to the generation of electricity, a

sector in which the price setting mechanism is the national

electricity pool. RPI-X is also currently being applied to

electricity marketing for residential users (although this

market is scheduled for deregulation in 1998). Prices in

the other segments of the industry, generation and nonfranchised marketing are in general freely determined in

the marketplace.

tended to vary across segments of the industry, with the

How RPI-X Worked in Practice in the UK

RPI-X is supposed to provide utilities with a stronger

incentive to reduce costs than rate-of-return regulation

because the utilities themselves realize all the value of the

cost reductions made beyond the benchmark. The other 36

supposed advantage of RPI-X regulation is that it is also

designed to reduce regulatory costs and provide a disincentive for the regulated to engage in costly activities

designed to influence the regulator (an activity called

regulatory capture). The visibility of a single national 37

regulator may also provide for more accessible public

scrutiny of regulatory decisions.

However, RPI-X regulation has some clear shortcomings,

both theoretical and practical. One problem is calculation

of the appropriate initial level of prices. In the United

Kingdom, this proved particularly difficult because the
24 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

government was also attempting to maximize the value of However, in the United Kingdom, the flotation was also

these companies for a successful initial public offering. conducted to further yet another goal—shareholder deLower future electricity prices would have meant lower mocracy. Certain shares were reserved for small UK

immediate gains to the treasury during the public auction shareholders in order to induce more widespread ownerof electricity industry assets. ship of industry among social classes. Restrictions on

A second problem involves estimating future productivity zation) were also employed to allow the national governgains. In practice, this has proven to be a rather ment to retain some influence over future corporate

problematic process in the United Kingdom. In order to governance.

achieve the desired allocation of the future benefits

achieved through realizing greater industry efficiency Another government goal during the flotation was to

gains, the regulator would still need detailed knowledge achieve a timely sale since privatization lacked a clear naof the industry and future market developments in order tional consensus and a change in government might lead

to come up with a suitable initial price and projected to its reversal. The conservative government was deterfuture productivity gains. In addition, X would represent mined to complete the privatization process as soon as

not expected future productivity gains, but rather some possible in order to discourage any future successor labor

theoretical cutoff rate for electric utilities to have an government from slowing down or reversing the process.

incentive to surpass in order to retain all of the cost The performance of earlier sales of major UK industries

reductions benefits that accrue beyond X. also influenced the method of electricity industry sell off.

Thus far, in terms of economic efficiency, RPI-X has been British Petroleum, had been viewed as less than a

a clear success. In the United Kingdom, the RPI-X success.

regulatory approach has induced cost reductions well

beyond expectations. Electricity companies have been An overriding issue in the privatization of electric utilities

able to greatly reduce operating costs in large part in the UK concerns the tradeoff between equity and

through substantial work force reductions. As intended, efficiency. Whereas economic efficiency in electric power

the electricity industry has benefited financially because generation is relatively easy to define in theory, achieving

these cost reductions have made substantial contributions social equity through privatization becomes a somewhat

to the bottom line results. However, substantial contro- subjective, but clearly not trivial matter, in privatization’s

versy has surrounded the new form of electricity regula- perceived success and public support. In the United

tion. In particular, some dissatisfaction has arisen over Kingdom, much political controversy surrounded the

whether the efficiency gains (the economic rents) have initial public auction of the electric distribution combeen equitably distributed between the industry’s panies. Again, this related to whether the treasury obstakeholders, i.e., investors, labor, and consumers. As a tained fair value for the companies sold. 

result of this controversy, several of the basic tenets of

RPI-X pricing have become suspect. Privatization got underway in late 1990. The RECs were

The Sale of UK Electricity

A controversial element in the privatization process

concerns the means by which the transfer of public ownership and control to private ownership and control is

carried out. In the United Kingdom, public flotations 38

were used to transfer ownership of electricity industry

assets. These flotations involved several objectives, one of

which was to raise money for the treasury and improve

the financial position of the national government. Maximizing treasury revenue through competitive sales does

much to assure taxpayers that fair value was obtained in

the sale of public assets. In general, full market value is

realized most quickly in markets that are highly liquid;

hence, there was a strong emphasis on market

breadth—i.e., opening the auction to the most bidders. As

a consequence, foreign investors were allowed to bid for

a limited number of shares. 

ownership (especially during the early stages of privatiSome earlier company sales, notably British Gas and

39

the first segment of the industry to be sold in December of

1990 with their shares being sold for $11.6 billion. Fifty- 40

five percent of the shares sold went to individual

investors, 30 percent to institutional investors, and 15

percent to foreign investors.

Interestingly, the UK government did not set out on the

price discovery path via a direct auction of shares in the

restructured electricity industry. Nearly a half-year prior

to the flotation of the RECs, the UK government canvased

major institutional investors to help determine the value

of the assets to be sold. Later, the government conducted

an effort to solicit retail customers through a massive

advertising campaign costing $23 million. Wider share

ownership was also a major goal in the sell off of the

electricity industry. Favorable payment terms were

offered to household investors.

The RECs were finally sold at a fixed price of $3.40 per

share which was calculated to provide investors with an
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 25

8.4-percent dividend yield. On Vesting Day shares of the sales stood at 49 percent, and foreign investors’ shares at

RECs soon began trading on the London stock exchange 23 percent (10 percent of the foreign share went to

and the values of these shares rose sharply. Although it is investors from continental Europe, 6 percent to Japan, 5

common in initial public offerings of privately-owned percent to the U.S., and 2 percent to Canada).

companies for underwriters to underprice shares somewhat, the value of the RECs’ share appreciation far

exceeded that of average share appreciation of the initial

public offerings of privately-owned companies.

There are several possible reasons why this might have

happened. One is that the government and its underwriters simply grossly underestimated the RECs’ value.

The government could have approached the price

discovery process via a staged auction of the RECs’ shares.

Another is that the government intentionally understated

the RECs’ value in order to dramatize the success of the

initial public offering. (In fact, Labor has accused the

government of intentionally underpricing the RECs’ value

for the benefit of investors over tax payers.) There is also

the possibility that the government priced the RECs at a

substantial discount to preclude the possibility that any

future Labor government would try to renationalize these

companies.

The investing public generally viewed the government’s

calculation of appropriated share price as highly undervalued and commitments to purchase shares exceeded

share availability by a factor of ten. The degree to which

the sale was oversubscribed had several implications. The

first was that the flotation was handily carried out. There

were, however, some problems associated with the degree

to which the flotation was oversubscribed. Most investors

did not obtain as many shares as they had bid for and

several investors received none. Further, the large runup

in share prices after trading began gave rise to accusations

that the government did not obtain fair value in the sale of

public assets and that investors left out of the flotation

were subsequently deprived from benefiting from the

windfall.

Soon after the RECs’ sale, the UK government sold shares

in the two generation companies. Sixty percent of the two

power companies shares were sold in March of 1991. (The

government’s 40-percent stake was sold in March of 1993).

Shares of National Power and PowerGen were packaged

together in the sale so that winning bidders received in the

minimum 62 shares of National Power and 38 shares of

PowerGen per 100-share tranches. The proportion of 41

shares to be made available to institutional investors was

initially set at 52 percent. However, during the sale, a

mechanism went into play which reduced the maximum

institutional share to 28 percent of the available supply.

Investors from the United States were prominent among

the foreign participants. An estimated $1 billion in shares

were sold to U.S. investors. In the end, individual

investors’ shares of the National Power and PowerGen

The UK government conducted the initial public offering

of the generation companies, National Power and

PowerGen, differently from that of the RECs. First of all,

the government set the dividend yield at a rate

significantly below the rate on the RECs. Secondly, only

a portion of the companies—60 percent—were sold off

during the initial public offering. Thirdly, an auction of

sorts was held to order to achieve greater price discovery

and treasury revenue.

Institutions were required to submit bids for a portion of

the shares set aside from the initial sale. Those submitting

the higher bids were awarded a priority in the second

round of bidding where there were no rules (i.e., a real

auction). Sixteen percent of the generator’s final tranch of

shares was reserved for a tender offer which took place on

the first day of trading. Discount prices were offered to

small shareholders.

The sale was oversubscribed by a factor of 6 and share

prices rose 37 percent during the first day of trading.

Although the level to which the generator’s initial public

offering was oversubscribed was large, due to the lower

dividend yield it was roughly half the level to which the

RECs were oversubscribed.

The fact that the sale of the generation companies and the

RECs was so oversubscribed (and that share prices surged

in their first day of trading) suggested to some that these

companies were underpriced by the government. While

investor enthusiasm was heralded by the conservative

government as an indicator of the auction’s success, the

Labor Party accused the conservative government of not

obtaining a fair value in the sale of public assets.

The National Grid Company (NGC) was initially privatized in December of 1990, at the same time as the

RECs. The NGC became a separate company in December

of 1995. Unlike shares in earlier privatizations, shares in

the National Grid Company (NGC) were not sold but

were distributed to shareholders in the twelve RECs. 

When the NGC was subsequently divested in December

of 1995, the UK government paid greater attention to the

issue of public equity, giving consumers a 50-pound

rebate from the proceeds of the flotation. The generation 42

units of the NGC were then sold off in January of 1996.

Neither National Power or PowerGen were allowed to bid

on the generation units. None of the five newly-created 43

generation subsidiaries of the regional distribution companies were allowed to have more than a 1-percent stake

in the newly-privatized NGC.
26 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Table 8. Recent Merger and Acquisition Activity in UK Electricity

(Million Dollars)

Regional Electricity Companies Acquirer/Merger Partner

Year of

Acquisition

Value

Billion Dollars

East Midlands Electricity ......... Dominion Resources (U.S.) 1996 $2.2 

London Electricity .............. Entergy (U.S.) 1996 $2.7 

Yorkshire Electricity ............. American Electric Power & PS Colorado (U.S.) 1997 $2.4 

Northern Electric ............... Calenergy (U.S.) 1996 $1.5 

Eastern Group ................ Hanson (UK) /Pacific Corp. (U.S.) a b 1995/1997 $9.6 

Southern Electric .............. c

Midlands Electricity ............. General Pubic Utilities & Cinergy (U.S.) 1996 $2.6 

Manweb ...................... Scottish Power (UK) 1995 $2.7 

SWEB ........................ Southern Company (U.S.) 1995 $1.7 

SEEBOARD ................... Central and South West (U.S.) 1995 $2.5 

NORWEB ..................... North West Water (UK) 1995 $2.7 

SWALEC ..................... Welsh Water (UK) 1996 $1.3 

 Hanson split up its various businesses in 1997. Hanson’s various energy operations were consolidated into the company the a

Energy Group PLC. The Energy Group was purchased by PacifiCorp, of Portland, Oregon, in 1997.

 The Pacific Corp. planned acquisition of Eastern Group has been referred by the UK government to the Monopoly and Mergers b

Commission for review.

 Southern Electric is the only company not to have been taken over by or merged with another company since being privatized. c

 Sources: European Power, McGraw-Hill’s Independent Power Report, and The Financial Times, various issues.

Throughout the public flotations of electricity industry

assets, the government held onto at least a partial share of

each company being privatized. The UK government

share was not seen as ownership per se, but rather a

restriction on any individual party’s ability to obtain more

than a 15-percent share in any privatized company. Thus,

the government’s “golden share” was clearly a deterrent

to the occurrence of any radical change in the ownership

structure of the electricity industry too soon after privatization. The “golden share” allowed the government

to exercise some residual control over corporate governance of the industry. It also restricted the degree to

which any other party could obtain corporate control over

any company and in essence determined that initial

investment in any company would be of a portfolio

nature.

As previously discussed, the government’s “golden share”

of the RECs expired in March of 1995 and was followed

by a spree of mergers and acquisitions among generation

companies and distribution companies. Due to concerns

that a similar development might take place with

electricity generation, the Department of Trade and Since the expiration of the government’s “golden share,”

Industry announced in May of 1996 that it would retain its all of the twelve UK distribution companies and one

share in National Power and PowerGen indefinitely. power company have been takeover targets (Table 8). 44

Electricity Investment Activity

Mergers and Acquisitions 

and U.S. Investors

As noted earlier, prior to privatization the UK government

restructured the electricity industry; after privatization,

the market undertook a restructuring. Foreign investors

played an important role in this second round of industry

restructuring. Soon after the UK government’s “golden

share” in the regional electricity companies expired in

March 1995, the RECs became a prime takeover target.

Eventually, eleven of the twelve RECs were merged with

or acquired by other companies. In the fall of 1995, both

recently-privatized power generation companies, along

with Scottish Power, placed bids on the recentlyprivatized distribution companies. There was also widescale integration and cross investment in electricity, natural gas supply, water supply, and telecommunications.

Electric utility companies from the United States were the

most aggressive bidders for the RECs.
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 27

Between the middle of 1995 and early 1997, U.S. utilities

have acquired eight of the twelve privatized regional

electricity companies. Upon settlement, the value of these

transactions will exceed $25 billion. British companies

have also been aggressive bidders. Four of the remaining

six RECs have also been successfully merged with or

acquired by UK-based companies. 

Although OFFER has generally not interfered with most

acquisitions involving the RECs, those involving vertical

integration with power generation assets have been controversial. As previously mentioned, in early 1996, there

were several attempted generation acquisitions which

were in the end rejected by the British government, largely due to concerns over the impacts vertical integration

would have on competition. 

In October 1995, National Power PLC attempted a takeover of Southern Electric PLC, the second largest regional

distribution company in the United Kingdom, for $4.4

billion. In turn, at the same time, National Power was

reported to be an $18-billion takeover target of the U.S.-

based Southern Company, which had just earlier purchased South Western Electricity. In September 1995,

PowerGen, the other major generation company, had

mounted a takeover attempt of Midlands Electricity.

However, the British government blocked the proposed

merger of National Power and Southern Electric (as well

as the purchase of Midlands Electricity by PowerGen),

due to concerns about competition. In July 1995, Scottish

Power placed a $2.7-billion bid for Manweb (a REC).

Scottish Power, however, was not prevented in its

takeover of Manweb, suggesting that cross-border vertical

integration raised less of a regulatory concern. 

Had the Southern Company/National Power merger and

the National Power/Southern Electric acquisition gone

through, a U.S. utility would have become the largest

power generation company as well as the largest distribution company in the United Kingdom. Southern

Company would have then owned two of the twelve regional distribution companies (with neighboring territories) along with the largest generation company.

As privatization of UK electricity has unfolded, natural

gas transport, distribution, and marketing have also become investment targets of several of the newly-privatized electricity companies (both generators and distributors). Five of the twelve regional distribution companies, along with National Power, have also acquired

telecommunications subsidiaries. Both NORWEB and 45

South Wales Electricity were acquired or merged with

local water power utilities with whom they shared service

territories. More importantly, all of the privatized RECs

and generation companies have obtained natural gas

supply operations.

Overseas UK Electricity Industry Investment

Privatization of electricity in the United Kingdom led to a

surge in foreign investment activity in Britain. Similarly,

privatization freed UK electricity companies to invest

abroad. Led by the two leading power companies, the

newly-privatized UK electricity companies have recently

undertaken several large overseas investments. In 1996,

National Power and PowerGen ranked second and third

among the world’s largest independent power producers.46

In Australia, a consortium led by National Power purchased a 1,600-megawatt coal-fired power plant and

adjacent coal mine from the state of Victoria for $1.8

billion. Similarly, a consortium led by PowerGen pur- 47

chased Australia’s Yallourn Energy in Victoria, whose

assets consisted of a 1,450-megawatt coal-fired generation

facility and adjacent coal mine, also for $1.8 billion.48

British Energy also bid on a Victorian power plant (the

2,000-megawatt Loy Yang plant) but later withdrew from

the bidding. Similarly, Scottish Power dropped out of the

bidding for a regional distribution company in Victoria.

National Power has also purchased or built electricity

facilities in the United States, Portugal, and Pakistan. In

its 1995 Annual Report, National Power stated that the

company is pursuing electricity investments in Turkey,

China, and India.49

Meanwhile, PowerGen invested in a 1,220-megawatt coalfired generation facility in Paiton, Indonesia, and a 665-

megawatt plant in Gujarat, India. PowerGen reports pursuing investment opportunities in India, Thailand, the

Philippines, Latin America, and the Middle East.50

PowerGen has also made several recent European investments, including a 900-megawatt coal-fired plant in

Sckopau, Germany, a 990-megawatt gas-fired station in

Portugal, and it has purchased a Hungarian electricity

distribution company.

To a more limited extent, the National Grid Company and

some of the regional electricity companies have also

invested abroad. The NGC purchased part of an electricity transmission system in in Argentina and is developing a transmission line in Pakistan. Several RECs have 51

also invested abroad. The Energy Group purchased

Citizens Power, of Boston, Massachusetts, for $120

million. Midlands Electricity, another REC, is investing 52

in a natural gas-fired 500-megawatt power plant in

Ereglisi, Turkey. SEEBOARD, yet another REC, won a

contract to refurbish Orissa, India’s distribution system,

and Norweb purchased shares in a regional distribution

system in Argentina.
1988 1989 1990 1991 1992 1993 1994 1995

0

10

20

30

40

50

60

Coal

Nuclear Power

Natural Gas

Oil

Other Fuels

Million Tonnes of Oil Equivalent

28 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Figure 6. UK Electricity Industry Fuel Use,

1988-1995

 Source: Department of Trade and Industry, 1993-1996.

Electricity’s Relationship to UK 

Natural Gas Privatization 

Natural gas has played an important and growing role in alternative sources of marketing. The initial group conUK electricity (Figure 6). Between 1989 and 1995, coal sisted largely of Britain’s industrial users of natural gas.

production in the United Kingdom fell by half, while In August 1992, users of natural gas in excess of 2,500

natural gas production increased 74 percent. Britain’s terms (primarily commercial demand) were allowed to

move away from coal-fired electric power towards natural bypass British Gas in favor of other suppliers. Both

gas power is the result of rapidly changing prospects for actions greatly diminished British Gas’ share in the market

both of these UK industries. The closure of uneconomic for industrial and commercial uses. The final stage of

coal mines in the United Kingdom coincides with increas- privatization, which began in 1995 with the enactment of

ingly available natural gas supplies that have come the Gas Act of 1995, is currently being implemented. 

onstream in the North Sea. Improvements in the efficiencies of combined cycle natural gas turbines used in The Gas Act of 1995 set out the framework for competition

electricity generation provided added demand. Environ- in the residential gas market. Following passage of the

mental concerns and pollution abatement laws have also Act, the UK initiated a free market experiment in natural

promoted the switch to gas because coal burning has long gas distribution by allowing a half-million residential and

been a major contributor to air pollution in the United small business consumers in three southwestern counties

Kingdom. (For a discussion on the switch from coal to to choose their natural gas suppliers. Previously, the sole

natural gas, see the section entitled: “The Demise of the supplier of natural gas to these markets had been British

UK Coal Industry and the Dash to Gas.”) Gas. This pilot program is intended to provide a testing

The privatization and deregulation of the UK natural gas

industry has also led to the increase in the use of natural

gas in electricity generation. Shortly after passage of the

Natural Gas Act of 1986, the UK government sold British

Gas. Up until 1986, British Gas dominated natural gas

transmission, distribution, and marketing. In addition to

privatization, the Natural Gas Act of 1986 required that

British Gas’ transmission pipelines provide open access

for all sellers of gas. The Natural Gas Act also created the

Office of Gas (OFGAS), an industry “watchdog” similar to

OFFER. Since passage of the act, a substantial number of

new suppliers have entered the industry, creating

heightened competition.

As in the case of electricity, natural gas marketing in the

United Kingdom has been undergoing deregulation in

stages. In late 1986, the first stage involved allowing large

users of natural gas (over 25,000 terms a year) to seek 53

ground for the eventual deregulation of the entire natural

gas market in the United Kingdom, scheduled to take

place in 1998. As of April of 1996, OFGAS had licensed

ten companies to market natural gas in the pilot area. 

The nature of these companies’ operations suggests how

dramatically the natural gas industry in the UK is

evolving. Included in the ten companies awarded licenses

are several U.S. electric utilities, as well as petroleum

companies from the United States, Norway, the United

Kingdom, and France (Table 9). These companies also

include some of the UK’s recently-privatized regional

electrical companies and PowerGen, one of the two

recently-privatized power generation companies.

The petroleum companies entering the UK’s newlyopened natural gas distribution business all have substantial North Sea natural gas operations. The primary

purpose of obtaining these licenses is to integrate their

upstream North Sea operations with the downstream UK

residential natural gas market. Amerada Hess, Amoco,

Conoco (DuPont), Phillips, and Texaco of the United

States; Statoil and Norsk Hydro of Norway; and TOTAL

of France, have all obtained licenses or conditional

licenses to market natural gas in the newly-opened

regions.

A number of electric utility companies (both from the

United Kingdom as well as from the United States) have

also set up subsidiaries in the newly-deregulated regions.

(As noted earlier, some electricity companies have also

moved into telecommunications and water distribution.)
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 29

Table 9. Major UK Regional Natural Gas Pipeline Privatizations

Recent Natural Gas

Distribution Licence Applicants Owner/Nationality

Secured Licenses

Amerada Hess Ltd. Amerada Hess (U.S.)

Beacon Fuels Gas Ltd. SEEBOARD (UK)

British Fuels Gas Former subsidiary of British Coal (UK)

Sterling Gas East Midlands Electricity (UK)

Manweb Gas Scottish Power (UK)

Northern Electric plc Northern Electric (UK)

Midlands Gas Ltd. Midlands Electricity (UK)

Eastern Natural Gas Ltd. Eastern Group (Hanson) (UK)

British Gas Trading Ltd. British Gas (UK)

London Total Energy Company London Electricity/Total Petroleum (UK/France)

NORWEB Gas Ltd NORWEB (UK)

Southern and Phillips Gas Ltd. Southern Electric/Phillips Petroleum (UK/U.S.)

Calortex Calor/Texaco (UK/U.S.)

SWALEC Gas SWALEC (UK)

SWEB Gas South Western Electricity/Utilicorp (UK/US)

Conditional Licenses

Alliance Gas British Petroleum/Statoil & Norsk Hydro (UK/Norway)

Kinetica PowerGen/Conoco(UK/U.S.)

Southern Gas Amoco/SEEBOARD (U.S./U.S. & UK)

 Notes: Calor is a major marketer of liquefied petroleum gases in the United Kingdom.

These developments may eventuate in the creation of a Prior to the privatization of electricity, the cost of domestic

residential energy service industry in the UK with a coal to electric utilities far exceeded the cost of coal traded

variety of single service (e.g., natural gas only or in international markets. For a variety of political and

electricity only) and mixed service (e.g., electricity and economic reasons coal has assumed a special place in the

natural gas) companies. Such a residential energy service UK’s economy and polity ever since the UK entered the

industry would be markedly different from the past Industrial Revolution. Between 1984 and 1985, the UK

structure of Britain’s electric power and natural gas experienced a year-long coal mining strike—an event

distribution structures, when two single companies (the which would subsequently significantly reduce the politiCEGB and British Gas) were the sole, but separate, cal influence of the UK coal miners’ union and the longproviders of these services. term viability of the industry. At the time, Margaret

The Demise of the UK Coal Industry

and the Dash to Gas strike additionally served to alienate much of the nation

Privatization of electricity in the United Kingdom had an

important impact upon fuel use in electricity generation.

Coal had long been the predominant fuel in electricity

generation and the electricity industry had long been the

primary purchaser of British coal. However, between 54

the 1980's and the mid 1990's, developments in the electricity, coal, and natural gas industries, along with

changes in the political environment, created an environment that favored the use of natural gas (rather than coal)

to become the preferred fuel of choice in UK electricity

generation.

Thatcher was the prime minister, and conservative

governments in the UK had long had a confrontational relationship with the coal miners’ union. However, the

from the coal miners’ union.

Electricity privatization also reduced the power of the UK

coal mining industry itself. The replacement of the more

publicly- accountable Central Electricity Generation Board

(CEGB) as the primary purchaser of UK coal with the

newly-privatized generation companies, National Power

and PowerGen, weakened the bargaining power of

British Coal, the national coal company. The former relationship, whereby the CEGB largely subsidized the UK

coal industry through purchasing domestic coal at above

world market rates and then passing through those costs

to consumers, would eventually end.
30 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

In 1990 (during the creation of National Power and Much of the reduction in coal consumption has been made

PowerGen), the UK government renegotiated its contract up for by a greater dependence on natural gas. The dewith British Coal so that both the volume of purchases and mise of the British coal industry is closely interlinked with

the price declined over 3 years. During the first three both the privatization of electricity and the developments

years after privatization, generators were required to in the UK’s natural gas industry. Prior to the privatization

purchase a set quantity of British coal at set prices; of natural gas, natural gas use in electricity generation

however, both prices and quantities of coal were to be was discouraged. Furthermore, after British Gas (the

substantially reduced over the contracted period. In turn, former state-owned natural gas monopoly) was privathe generators could still pass on these higher prices, but tized, the UK natural gas market grew more competitive,

only to the regional electricity companies’ franchised leading to ample supplies and reduced prices. The natural

market. Expectations at the time saw coal imports taking gas share of utility fuels rose from 1 percent in 1988 to 17

up the slack. percent in 1995. By 2010, natural gas is expected to

By the fall of 1992, British coal had reached a crisis stage.

Several factors led to this, including growing competition

from increasingly available natural gas: the imminent

removal of the regional electricity companies’ captive

franchise supply market; a more assertive National Power

and PowerGen; newly-enacted pollution abatement goals;

and ample coal stocks at electric utilities. As the deadline

for the first three-year contract approached, the government initially recommended even greater reductions in

electricity industry coal purchases from British Coal than

those negotiated for in the first three-year contract. Large

reductions in prices were also expected. The new contract

called for annual coal supply to be reduced to 30 million

metric tons by the 1994/1995 fiscal year time period, or to

less than half the 81-million ton level in the 1989/1990

fiscal year time period. 55

When it became clear that these proposals would result in

massive coal employment losses in coal production, a

Parliamentary crisis ensued. By March of 1993, however,

the crisis had largely dissipated and the British government was able to push through most of its earlier proposals, with only a few meaningful alterations. The 56

resulting coal contracts required National Power and

PowerGen to purchase 40 million tons of coal in the first

year of the contract and only 30 million tons in each of the

four years that followed. Furthermore, when British Coal 57

was privatized in 1994, it was done so with government

expectations that it would eventually operate as a competitive company and not be dependent upon government

subsidy.

Coal production at British mines fell from 84 million tons

in 1988 to 35 million tons in 1995. In 1988, coal (on a 58

crude oil equivalent basis) accounted for 66 percent of fuel

use at UK electric utilities (Figure 6). By 1995, this share

had fallen to 48 percent. By 2010, coal’s share of electricity

production is expected to fall to 31 percent. Coal 59

industry employment has clearly reflected the decline in

energy consumption. In the 1981/1982 fiscal year time

period, 184,400 workers were employed by the coal

industry. This number had fallen to 11,000 by 1995.60

61

account for 46 percent of fuel use at electric power

plants.62

Allowing the regional electricity distribution companies

to enter into the power business encouraged them to find

quick power generation alternatives to the electricity pool.

Combined cycle natural gas turbines provided the

quickest means of entry into the generation market due to

their low construction costs and short lead times. Due to

efficiency improvements and the startup of a new reactor,

nuclear power has also partly displaced coal. Between

1988 and 1995, nuclear’s share of generation rose from 22

percent to 28 percent. 

Environmental considerations also worked against UK

coal in recent years. In 1988, the United Kingdom ratified

a European Community directive requiring a 60-percent

reduction in total sulfur dioxide emissions by 2003,

compared to 1980 emissions levels. 63

Independent Power Producers in 

the United Kingdom

In recent years, independent power producers (IPPs) have

played an increasingly important role in electricity

generation in the United Kingdom (Table 2). Companies

from the United States have also been major investors in

independent power projects in the United Kingdom. The

independent power production industry owes its

existence to passage of the Electricity Act of 1983, which

provided new electricity producers with access to the

national grid, and to passage of the 1989 Electricity Act

which made that access non-discriminatory. All of the

RECs have formed independent production subsidiaries,

as have National Power, PowerGen, Scottish Power, and

Hydro Electric. The RECs’ IPPs account for roughly half

of the recent additions to generation capacity in England

and Wales. Several foreign (and mainly U.S.-based 64

companies) have also been very active in the UK’s IPP

industry (Table 10). A favored form of generation for

independent power-producing companies has been the

combined cycle natural gas turbine electric facility. This

is in part due to the improved economics of natural gas as
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 31

Table 10. Major Foreign Equity Investments in UK Independent Power Projects

Project Site Megawatts Equity Sharea Company/Companies Involved

Teesside ................ 1,875 50 Enron (U.S.)

Medway . . . . . . . . . . . . . . . . . 660 38 SEEBOARD

38 AES (U.S.)

Brigg South Humberside . . . . 240 25 IVO (Finland)

Dinorwig ................. 1,728 100 Mission Energy (U.S.)

Derwent . . . . . . . . . . . . . . . . . 214 33 Mission Energy (U.S.)

Ffestiniog . . . . . . . . . . . . . . . . 360 Mission Energy (U.S.)

Humber Power . . . . . . . . . . . . 750 30 IVO (Finland)

30 Tomen (Japan)

20 ABB (Swedish/Swiss)

Aylesford . . . . . . . . . . . . . . . . 58 ABB (Swedish/Swiss)

Meekatharra (Australia)

Barry . . . . . . . . . . . . . . . . . . . . 250 AES (U.S.)

Brigg . . . . . . . . . . . . . . . . . . . . 240 25 IVO (Finland)

Indian Queens . . . . . . . . . . . . 140 Destec (U.S.)

Isle of Grain . . . . . . . . . . . . . . 675 25 AES (U.S.)

South Humber Bank ....... 1,320 30 IVO (Finland)

25 Tomen (Japan)

20 ABB (Swedish/Swiss)

Spondon . . . . . . . . . . . . . . . . 33 Mission (U.S.)

Sutton Bridge . . . . . . . . . . . . . 700 Enron (U.S.)

Wallend . . . . . . . . . . . . . . . . . 750 100 Enron (U.S.)

 Note: Equity shares do not always total to 100 percent due to the unreporting of some ownership shares. a

 Source: UK Electricity Association, Generation Projects since Privatization, http://www.electricity.org.uk/inds_fr.html, 1997.

an electric fuel. The improved efficiency of natural gas

turbines and the short lead time needed to construct a

combined cycle gas turbine facility have also encouraged

the IPP move into natural gas. Since Vesting Day, combined cycle gas turbines have provided 12,978 of the In the seven years since privatization began, the UK

14,738 megawatts of new generation capacity scheduled electricity industry has clearly become more efficient. In

to be completed by the end of 1996 in England and 1995, the United Kingdom produced 8 percent more elecWales. For the RECs, the combined cycle natural gas tricity than in 1988. Between the 1989/1990 and 65

turbine provided the quickest means of entry into the 1995/1996 fiscal year timeframes, employment in the UK

power generation business. electricity industry was reduced by roughly fifty percent

Natural gas and IPPs have grown hand in hand in pro- cally scheduled regulatory reviews clearly had an impact

viding future growth in the UK’s electric generation on later price reductions to electricity consumers.

capacity. In the 1990/1991 fiscal year time period, the Although consumers have generally experienced lower

IPPs accounted for roughly 1 percent of the UK’s elec- inflation-adjusted electricity prices since privatization,

tricity generation capacity. By the 1995/1996 fiscal year Figure 7 indicates that gains to larger consumers have

time period, the IPPs increased their share of total UK generally exceeded those to households. 

generation capacity to 15 percent and are expected to

account for 21 percent of this UK capacity by the However, other factors have also played a role in retail

2000/2001 fiscal year time period (Table 2). electricity price reductions. Prior to Vesting Day, UK

Privatized Electricity: 

A Performance Appraisal

66

(Table 11). Reductions in prices as a result of the periodi-
1988 1989 1990 1991 1992 1993 1994 1995 1995

0.6

0.8

1

1.2

1.4

1.6

Coal

Fuel Oil

Retail Prices

Natural Gas

1988 1989 1990 1991 1992 1993 1994 1995

1

1.1

1.2

1.3

1.4

1.5

1.6

Retail Price Index

Residential 

Industrial

Commercial

32 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Table 11. Employment in the UK Electricity Industry, Selected Years

Segment 1989/1990 1994/1995 1995/1996

National Power & PowerGen ............... 82,478 62,948 54,469 

National Grid ............................ 26,407 9,618 8,996

Regional Electricity Companies ............. 14,415 9,426 4,907

 Total .................................. 123,300 81,992 68,372 

 Note: The National Electricity Code. <http://acc.gov.au/sched/httoc.htm7>.

 Source: Electricity Association, Electricity Industry Review (January 1997), p. 54. 

Figure 8. Fuel Price Index for UK Electric Utilities,

1988-1995

Figure 7. Index of UK Electricity Prices, 1988-1995

 Note: 1988 = 1.00. Values listed are in current monetary

units.

 Source: Department of Trade and Industry, Digest of the

United Kingdom Energy Statistics, 1993-1996..

 Note: 1988 = 1.00. Values listed are in current monetary units.

 Source: Department of Trade and Industry, Digest of United

Kingdom Energy Statistics, 1993-1996.

regulators allowed for significant electricity price

increases (which made later price reductions by the

industry easier to achieve), in part to increase the

attractiveness of the soon-to-be privatized electricity

industry. Fuel costs have also decreased since privatization. The price of the most heavily used fuel in electricity generation—coal—has fallen even in nominal terms

(Figure 8). Natural gas prices in the United Kingdom

have also trailed the overall rate of price inflation.

Deregulation in the United Kingdom was driven by the

belief that electricity prices were held artificially high due

to the inefficient operation of government-owned electric

utilities. The government could have attempted to close

this price gap via stricter regulation, but instead chose

competition and price caps as a means of reducing

electricity prices. In part, this decision stemmed from the

belief that the regulated utilities were better equipped

than the regulator to know what kind of efficiency

improvement measures could be undertaken once they

had an incentive to make them. 

The other factor is political. Much improvement in the

efficiency gains in UK electricity were achieved through

massive workforce reductions. Under the old style of regulation, it is highly unlikely that the regulator could have

dictated such workforce reductions to the utilities, given

that the then regulator (a public official) would have been

held publicly accountable for the rising unemployment.67

A Light-Handed Approach to

Electricity Regulation? 

The Electricity Act of 1989 created an Office of Electricity

Regulation (OFFER), which has primary responsibility for

electricity regulation. The 1989 act also created the position of Director General of Electricity Supply, providing

a single individual with responsibility for electricity regulatory activity. The initial (and current) director is 68

Stephen Littlechild, a former professor of commerce. The

Director’s term of office was set at five years. Littlechild

was appointed to his first term of office in 1989 and

reappointed in 1994. Littlechild has long been associated

with incentive regulation, and has been a strong proponent of replacing rate-of-return regulation with price

cap (or RPI-X) regulation. This regulatory approach has 69

frequently been characterized as being “light-handed.”

The OFFER’s missions are to assure that an adequate level

of electricity supply be available; that the industry remain

competitive; and that organizations licensed (by the

OFFER) to engage in electricity operations be capable of

financing those operations. The OFFER has similarly
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 33

structured regulatory watchdog counterparts in the has substantial political influence. The Office of Fair

recently-privatized UK natural gas industry (OFGAS), the Trade, whose purpose is to promote and safeguard

recently-privatized UK telecommunications industry economic interests of consumers, also has a say in elec-

(OFTEL), and the recently-privatized UK water industry tricity industry matters. Further, the Department of Trade

(OFWAT). and Industry has some influence over electricity regulaThe UK approach of having a single official responsible

for regulation differs considerably from the regulatory

approach most commonly practiced in the United States,

where various regulatory commissions (with several

commissioners) have oversight authority. At the national

level in the United States, the Federal Energy Regulatory

Commission (FERC), an independent agency within the

U.S. Department of Energy, has jurisdiction over interstate

electricity sales and wholesale electric rates. The FERC’s

policy-setting arm consists of one chairperson and four

commissioners. Primary responsibility for electricity

regulation in the United States resides with individual

state public utility regulatory commissions.

Although the Director General of OFFER is clearly more

independent and has more discretion over policy making

than his U.S. counterpart, the UK’s system of single

person authority has been criticized for lacking debate. 

Access for UK electric utility producers and consumers to

petition OFFER is also less than in the United States,

making the UK electricity policy decision-making process

perhaps less accountable than that which exists in the

United States. The single-person regulatory approach has

also tended to personalize both the OFFER and the

decision-making process, possibly causing the UK regulatory regime somewhat of a credibility problem.70

Another difference between the UK and U.S. models

concerns the prominent role that local governments (or

states) play in regulating electricity. At the state level,

elected officials usually appoint public utility commissions (PUCs) to exercise regulatory oversight. There is no 71

equivalent counterpart to these commissions in the United

Kingdom where regulatory matters are handled exclusively at the national level. In comparison to the

situation in the United States, the UK Director General has

a relatively lean staffing level—a purposeful advantage of

the UK model. The task of regulating the entire UK

electricity industry falls on OFFER’s staff of slightly more

than two hundred employees. In contrast, the California

public utility commission (PUC) alone has employment of

roughly 900, although the California PUC also regulates

water and telecommunications.72

The OFFER is not the only government agency having

oversight authority over the UK electricity industry. Two

other agencies also engage in some supervisory role. The

Monopoly and Mergers Commission (MMC), through its

authority to conduct and rule on antitrust investigations,

tory matters since its most senior official (the Secretary of

State) is responsible for appointing the Director General of

the OFFER.73

The OFFER is responsible for determining the appropriate

price caps and their durations for the regulated portion of

the UK electricity industry. Although generation is nominally unregulated, OFFER can (and has) exerted influence

over the electricity generation sector. An option available

to OFFER is the right to propose an MMC investigation

into any portion of the industry OFFER deems not

competitive. The OFFER used its authority to intervene in

setting pool prices in 1994 when it implemented a price

cap. The OFFER also required that National Power and

PowerGen sell off 6,000 megawatts of electricity generation capacity when concerns over market dominance in

electricity supply were raised.

The OFFER has been a target of criticism by both UK

consumers of electricity and the electricity industry itself.

Consumers have voiced complaints that OFFER’s choices

of productivity (X) factors have been too favorable to the

industry and have led to excessively high profits. In

contrast, electricity producers have criticized the OFFER

for increasing electricity regulation through its unscheduled reviews of price rate structures.

Industry’s criticism of the OFFER has to do with the

agency’s lack of commitment to its previous regulatory

decisions. In March of 1995, OFFER reopened its price

review on the distribution companies after putting forth

an initial August 1994 proposal regarding one-time rate

reductions and “X” factors. Precipitating OFFER’s unscheduled price review was a takeover attempt of

Northern Electric (a REC) by Trafalgar, coming shortly

after the initial OFFER price cap proposals for the second

review period had been released. Northern’s resistance to

the takeover attempt included a stock buyback, a move

which suggested to the financial community that

Northern’s financial position was much better than

indicated by previous assessments. The reassessment of

Northern’s value instigated a reassessment of the entire

value of all of the UK regional electricity distribution

companies. In a decision which appeared to be a reaction

to these reassessments, the OFFER later tightened its

previously-proposed rate caps and one-time revenue

reductions for the 1995 to 2000 review period, an action

which at the time was seen by the industry as evidence of

a lack of commitment by the OFFER.
34 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Performance-Based Utility Regulation

Issues of fairness and equity have dogged performancebased ( RPI-X ) price-cap regulation since its inception in

the United Kingdom (for a detailed discussion on RPI-X

regulation, see the section entitled: “RPI-X: Price Caps

Versus Rate of Return Regulation”). In privatizing and

reforming their electricity industry, the UK government

undertook an experiment. Initially, neither the government (nor perhaps the industry) expected cost reductions

of the magnitude that were eventually achieved. 

The major regulatory problem in implementing RPI-X has

been determining (or discovering) what the appropriate

level of initial prices and the appropriate “X” factors

should be. OFFER’s decisions regarding appropriate

starting rates and “X” factors during the industries’ periodic reviews indicates a strong asymmetry of knowledge of

the industry between regulator and regulated. In retrospect, it is clear that the regulator had a propensity to

underestimate the industries’ potential for achieving cost

reductions.

However, at the same time, it is reasonable to assume that

this same propensity to underestimate would have

occurred had the regulator operated under traditional

rate-of-return regulation, making it even more doubtful

that the efficiency gains actually realized would have

been achieved had the industry not been given a strong

financial incentive to cut costs. (It should be noted though

that the generation companies also realized large efficiency gains following privatization, although these

companies were essentially unregulated.) Clearly, RPI-X

has produced very large efficiency gains in UK electricity

distribution and transmission. In a sense, RPI-X’s usefulness as an efficiency improvement tool was undone by its

own success.

The UK’s experience with RPI-X has clearly influenced

regulatory reform in Argentina and Australia (See

Chapters 3 and 4). It may have also influenced recent regulatory reform in the United States. In recent years,

several public utility commissions in the United States

have adopted a hybrid form of both price cap regulation

and rate-of-return regulation, with the difference between

price cap regulation and rate-of-return regulation becoming a matter of emphasis. Several variations of the 74

hybrid exist. However, regardless of the variation, in

essence the hybrid method allows utilities to keep only a

share of the gain realized from cost cutting, the remainder

being turned over to the rate payers more immediately.

Advocates of a “sliding scale” method of regulation feel it

to be a more fair system because it immediately shares a

portion of the gain with consumers. Critics feel it reduces

potential efficiency gains because it presents companies

with less incentives to cut costs and in the end simply

provides consumers with just a larger slice of a smaller

cake.

The California Public Utilities Commission recently employed a form of “sliding scale” regulation which allocates efficiency gains between electricity companies and

consumers. Within a bandwidth of 50 to 300 basis points

of the benchmark, consumers would accrue up to 25

percent of the gains. Stockholder’s gains would vary from

25 percent to 100 percent of the gain beyond the 300

points. 75

Early efforts at cost cutting did enable the National Grid

Company and the regional electricity distribution companies to greatly improve their financial performances,

which, in turn, raised public concerns over the fairness of

the new system. Net income for the National Grid

Company and the twelve regional distribution companies

increased by more than 50 percent between the fiscal year

1985/1986 and the 1992/1993 fiscal year time periods

(Table 12). However, during the first three years of 76

implementation (1990 to 1993), promised benefits to

residential users appeared elusive. Household electricity

prices rose slightly more than overall retail price inflation

during this period despite a decline in steam coal prices

for electricity generation (Figures 7 and 8). The fact that

shareholders reaped large dividends during the utilities’

initial public offerings also gave rise to questions of

fairness. Large increases in executive compensation in the

face of wide-scale labor force reductions compounded the

matter further.

A large part of the problem stemmed from the UK

government’s initial choice of X—which, depending on

the REC, ranged from zero to a negative 2.5 percent (Table

13). At the time it was felt that the industry needed to

make extensive capital investments over the coming years

and thus needed a secure cash flow. As stated earlier, a

generous X also made companies more attractive to

shareholders, thereby increasing their auction value. In

any event, the industry’s high level of profitability during

the first period resulted in OFFER proposing more severe

price caps for the second regulatory cycle. OFFER called

for a one-time reduction in REC prices of between 11 and

17 percent and an X of a positive 2 percent.77

In March 1995, the OFFER announced a more stringent

price reduction and X factors. This action gave rise to

concerns that the new regulatory regime lacked a sense of

commitment. Whereas the distribution of economic rents

realized during the first regulatory cycle tended to reduce

consumer confidence in the new arrangement, OFFER’s

eversal on earlier price benchmark and X factor proposals

was a source of concern for industry. Whereas the former

event illustrates the difficulties that may be encountered

if the initial price caps are inadequate, the latter event 
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 35

Table 12. Net Income for UK Electricity Generation Companies, Selected Years

(Million Dollars)

Company 85/86 88/89 89/90 92/93 94/95

CEGB ................................ 1,229 -4,751

National Power . . . . . . . . . . . . . . . . . . . . . . . . 279 911 1,107 

PowerGen . . . . . . . . . . . . . . . . . . . . . . . . . . . . 367 667 856

Nuclear Electricity ...................... -1,457 171 1,677 

National Grid .......................... 674 837 959

REC’s Distribution ...................... 914 1,501 1,753 

REC’s Marketing ....................... 157 273 377

 Total ................................ 1,229 -4,751 -137 2,586 4,599 

 Source: Michael Brower, Stephen Thomas, and Catherine Mitchell, “Lessons from the British Restructuring Experience, The

Electricity Journal (April 1997), Gordon Mackerron and Jim Watson, “The Winners and Losers So Far,” The British Electricity

Privatization Experiment, Privatization: The Record, the Issues, the Lessons, ed. John Surrey (London, England: Earthscan

Publications Limited, 1996), p. 199.

Table 13. The Initial Regulation of Electricity

Distribution

Regional

Electricity Company X Factor

London .............. 0.00

Manweb ............. -2.50

NORWEB ............ -1.40

Southern ............ -0.65

SWEB ............... -2.25

East Midlands Electricity -1.25

Eastern Group ........ -0.25

Midlands Electricity .... -1.15

SEEBOARD ......... -0.75

SWALEC ............ -2.50

Yorkshire Electricity .... -1.30

Northern Electric ...... -1.55

 Source: Thomas Weyman-Jones, “Problems of Yardstick

Regulation in Electricity Distribution,” The Regulatory Challenge,

eds. Matthew Bishop, John Kay, Colin Mayer (Oxford University

Press: London, 1995), p. 429.

highlights the commitment problem in policy making—or

the efficacy of any particular policy when it fails to endure

political opposition. Investment decisions can be jeopardized by the uncertainty created when the commitment of

the regulator is called into question. This could create an

unacceptably uncertain investment environment. Fur- 78

ther, when public concerns over industry profitability

induces unscheduled industry reviews, RPI-X may in

reality approximate rate-of-return regulation—just by

another name.

Was RPI-X the Right Choice?

Politically, it is not clear whether RPI-X regulation will

survive the recent change in the UK government. Tony

Blair, the Labor Party leader and new prime minister, had

in May of 1995 called for a replacement of RPI-X by a

regulatory formula that “shares excess profits between

utilities and customers.” Since assuming office, the new 79

prime minister has proposed a windfall profits tax on

recently privatized public utilities. The fact that the new 80

form of regulation became so politically untenable with a

change in government questions its efficacy as a means of

public policy.

Despite the perceived problem with “fairness” which has

dogged RPI-X regulation, it is doubtful that the efficiency

gains realized through its implementation could have

been achieved via the more traditional rate-of-return type

of regulation. The major problem in implementing RPI-X

has related to the regulator’s determination of the appropriate level of initial prices and what the appropriate

X factors should be. If, for instance, the regulator had

greatly underestimated both, would using a rate-of-return

style of regulation have added in any material way to the

regulator’s ability to predict future potential cost reductions? This question deserves consideration, especially

given that a rate-of-return style of regulation would have

offered few incentives for the utilities to maximize those

cost reductions.
36 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Paul Cook, The British Council, Governance and Law, The Evolution and Performance of UK Privatization, INTERNET address: 1

http://www.britcoun.org/governance/briefing/iss2int.htm.

“Sale of the Century,” The Wall Street Journal (October 2, 1995), p. R17. 2

Often times the marketing function of the electricity industry is subsumed in the distribution segment. However, certain services normally provided by 3

distribution companies can be separated out. These services include such items as brokering, billing, and metering. As stated earlier, the marketing segment

of the electricity industry along with generation was considered to be potentially competitive and deregulated gradually. It should be noted that in the United

Kingdom, the conventional term for the provision of these services is “supply” rather than “marketing”. 

A single-firm “natural monopoly” industry is warranted when the operating costs of an industry are lower with a single supplier. See: Alfred E. Kahn, 4

“The Economics of Regulation”, (The MIT Press, Cambridge Massachusetts: 1988), p. 11/1.

“Time’s Up for Greedy Bosses,” The Daily Mail, March 1, p. 1. 5

John Chesshire, “UK Electricity Supply Under Public Ownership, ” The British Electricity Privatization Experiment, Privatization: The Record, the 6

Issues, the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 15

For background information on the history of the British Electricity industry see, Regulating Utilities: A Time for Change?, ed Colin Robinson (London, 7

England: Institute of Economic Affairs, 1996), pp. 109-144 or The British Electricity Privatization Experiment, Privatization: The Record, the Issues,

the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996). 

According to Robinson, the industry had become both “an instrument of government policy and government industrial policy.” Regulating Utilities: A 8

Time for Change?, ed Colin Robinson (London, England: Institute of Economic Affairs, 1996), p. 111.

John Chesshire, “UK Electricity Supply Under Public ownership, The British Electricity Privatization Experiment, Privatization: The Record, the Issues, 9

the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 19.

John Chesshire, “UK Electricity Supply Under Public ownership, “The British Electricity Privatization Experiment, Privatization: The Record, the 10

Issues, the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 19.

The semi-autonomous relationship of the former regional distribution boards to the rest of the industry was one reason why vertical deintegration was 11

more easily achieved in the United Kingdom than in other countries. In additions to the recently privatized elements of the electricity industries in the UK, other participants in UK electricity include independent power 12

producers and Electricity de France. In 1995, the UK imported roughly 2 percent of its electricity from France via its 2000 megawatt link to France. Source:

Department of Trade and Industry, Digest of the United Kingdom Energy Statistics, 1996, p. 99. In the United Kingdom, costs associated with the privatized, deregulated electricity industry are often expressed in budgetary time periods (i.e., April 1 13

to April 1 fiscal years) and not calender year time periods. Thus, for the purposes of this report, 19xx/19yy will refer to particular fiscal years and 19xx –19yy

will refer to particular calender years. Nuclear Electric, which was to remain under public ownership, accounted for 17 percent of generation capacity. During the initial debate over 14

privatization, the viability of the nuclear power industry as a private entity came into question. As in the United States, the issue of stranded cost liabilities

was an important issue in the debate on industry restructuring in the United Kingdom. The initial plan called for the coupling of thermal and nuclear assets

as a means of encouraging investor acceptance. National Power was to be given all of the UK’s nuclear power plants along with roughly half of the country’s

non-nuclear capacity. This plan, however, was latter dropped when it became apparent that the financial liabilities of nuclear power made early privatization

unfeasible. Nuclear power was to remain under public ownership, but under a new company name, Nuclear Energy. Plans to privatize nuclear power were

postponed although a portion of the industry was eventually privatized in 1996 as the company British Energy (for a discussion on the issue of stranded costs

and nuclear power in the United Kingdom, see box entitled: “Nuclear Power and the Issue of Stranded Costs”). 

Green, R.J. and Newberry, D.M. “Competition in the Electricity Spot Market,” Journal of Political Economy, vol. 100, no. 5, October, pp. 929-953. 15

“The Busiest Merger Lab: The UK Electricity Sector,” Electrical World, Vol. 210, No 7 (New York, New York, July 1996), p. 29. 16

“The Busiest Merger Lab: The UK Electricity Sector,” Electrical World, Vol. 210, No 7 (New York, New York, July 1996), p. 29. 17

“The Busiest Merger Lab: The UK Electricity Sector,” Electrical World, Vol. 210, No 7 (New York, New York, July 1996), p. 29. 18

In February of 1997, the conglomerated Hanson split up its various businesses and consolidated its energy holdings in the newly created company the 19

Energy Group. The Energy Group is the largest private producer of coal in the world and owner of Peabody Holding Co, the largest U.S. coal company.

In June 1997, PacifiCorp, of the United states, purchased the Energy Group. The REC’s franchised operations consisted of the below 1 megawatt users of electricity in each of the geographical territories assigned to the former Area 20

Boards. 

The initial non-franchised marketing market applied to the > megawatt consumer of electricity. 21

Customers whose electricity demand ranged from < 1 megawatt and > 1 kilowatt. 22

Customers whose electricity demand < 1 kilowatt. 23

Petroleum Times, July 1, 1991, p. 4. 24

Internal document, Smith New Court United Kingdom. 25

26

Nuclear Electric participates in the pool but as a passive price taker. 27

Alex Henney, Electricity Journal, January/February 1997. 28

CFDs are similar in many ways to forward contracts in that they are generally bilateral contracts and often non-standardized. They are also similar to 29

futures contracts in that they are purely financial instruments (i.e., no delivery of electricity takes place) and they are hedges against future price changes.

See: Alex Henney, The Privatization of the Electricity Supply Industry in England & Wales (London, England: EEE Limited, 1994), p. 350-351. 

Steve Thomas, “The development of Competition, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, the Lessons, 30

ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 82.

Colin Robinson, “Profit, Discovery, Entry:The Case for Electricity,” Regulating Utilities: A Time for Change?, ed. M. E. Beesley (Wiltshire, England: 31

Redwood Press, 1996), pp. 128-129. A natural monopoly is defined as a situation where “a single firm can serve the market at lower unit costs than two or more firms.” F.M. Scherer, 32

Industrial Market Structure and Economic Performance, Second Edition (Chicago, Illinois: Rand McNally College Publishing Company, 1980), p. 482.

There is also the issue of regulatory lag. Regulatory lag refers to the period between a rate-case review (after the regulator has agreed upon a base-case) 33

and the next review, when utilities have an incentive to operate more efficiently than what was assumed during the base-case. Through efficiency gains,

utilities can realize greater rates of return than those anticipated during the initial rate review. However, although frequent rate reviews can reduce regulatory

lag, such reviews might also make long-run investment planning more difficult. In the extreme, regulatory lag could transform rate-of-return regulation into

a form of rate-cap regulation.

Endnotes
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 37

In the case of expected future productivity declines, the formula in essence would become RPI+X. 34

Ray Rees and John Vickers, “RPI-X Price-cap Regulation,” The Regulatory Challenge, ed. Matthew Bishop, John Kay, and Colin Mayer (Oxford 35

University Press, London, 1995), p. 376.

It should be noted that in rate-of-return regulation, during the interim period between regulatory reviews, utilities have an incentive to cut costs and 36

thereby boost profits. The more infrequent the regulatory review, the stronger this incentive becomes.

In RPI-X, regulation incentives exist for the industry to encourage a passive form of regulation and favorable X factors. Although the initial X factors 37

imposed on the industry have generally been favorable to the industry, that the regulator, OFFER, has engaged in several unscheduled interventions suggests

that regulatory capture has not occurred. See: Ray Rees and John Vickers, “RPI-X Price-Cap Regulation,” The Regulatory Challenge, ed. Matthew Bishop,

John Kay, and Colin Mayer (Oxford University Press, London, 1995), p. 382. There are several means of reducing public ownership and control and increasing private ownership and control. One option is to have a public auction 38

with no limitations placed on participants. Another option is to conduct the auction but to limit participation, for instance, to citizens. A company may be

sold off partly or fully. A company may be sold off to another company or there maybe restrictions placed on the share of any individual purchase. A

company may be privatized simply by issuing ownership shares (vouchers) to all citizens or to selected groups of citizens (e.g., employees). Other more

passive forms of reducing government control (but not ownership) include deregulation, the removal of subsidies, and the lifting of restrictions on competitions

(e.g., from foreign companies). For more detail on the various privatization methods recently employed around the world, see: Energy Information

Administration, Privatization and the Globalization of Energy Markets (DOE/EIA-0609) (Washington, DC, October 1996). 

Catherine Price, “Gas Regulation and Competition: Substitutes or Complements?” Privatization and Economic Performance, ed. Matthew Bishop, John 39

Kay and Colin Mayer (Oxford, England, Oxford University Press, 1994), p. 137 and Tim Jenkinson and Colin Mayer, “Privatization in the UK and France,”

Privatization and Economic Performance, ed. Matthew Bishop, John Kay and Colin Mayer (Oxford, England, Oxford University Press, 1994), p. 293.

Alex Henney, “The Restructuring and Privatization of the Electricity Supply Industry,” The Privatization of Public Utilities, ed Leonard S. Hyman (Public 40

Utilities Reports, Vienna, Virginia), p. 253.

”Sale of National Power, PowerGen Shares Seen as ‘Wildly Successful,’ ” Independent Power Report (March 29, 1991), p. 10. 41

John Surrey, “Unresolved Issues of Economic Regulation, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, 42

the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 235. Mission Energy is a subsidiary of Edison International, the parent of Southern California Edison, the second largest electric utility in the United States. 43

“DTI to Keep Share in Electricity, ” Times Newspaper (May 3, 1996), p. 19. 44

Electricity Association, Electric Industry Review (January 1997), p. 6. 45

“Global Independents Power Capacity Hits 113,447 megawatts; Asian Players Gain,” Electric Utility Week (July 29, 1996), p. 13. The ranking is 46

measured by net project ownership but not company portfolios with a preponderance of in-house generation, state-funding or vintage capacity.

Privatization International (September 1, 1996), p.1. 47

PowerGen, 1996 Annual Report, p. 12. 48

National Power, 1996 Annual Report, p. 3. 49

PowerGen, 1996 Annual Report, p. 14. 50

National Grid Home Page, http://www.hgc.co.uk. 51

The Energy Group is the parent of the Eastern Group REC. The Eastern Group is also the world’s largest private coal producer and owner of Peabody, 52

the largest producer of coal in the United States. Source: PR Newswire (May 20, 1997). A therm is equivalent to one hundred thousand Btu. 53

In 1995, the electricity industry purchased over three quarters of all UK coal production. Source: Department of Trade and Industry, Digest of United 54

Kingdom Energy Statistics 1996, p. 36.

Mike Parker, “Effects on Demand for Fossil Fuels, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, the Lessons, 55

ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 120.

Mike Parker, “Effects on the Demand of Fossil Fuels, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, the 56

Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), pp. 129-130.

Colin Robinson, “Profit, Discovery, Entry: The Case of Electricity,” Regulating Utilities: A Time for Change? ed. Colin Robinson (London, England: 57

Institute of Economic Affairs, 1996), p. 116.

Department of Trade and Industry, Digest of the United Kingdom Energy Statistics 1996, p. 156 58

Organization of Economic Cooperation and Development (OECD), Country Annexes, p. 297. 59

United Kingdom, Department of Trade and Industry. 60

Colin Robinson, “Profit, Discovery, Entry: The Case of Electricity,” Regulating Utilities: A Time for Change? ed. Colin Robinson (London, England: 61

Institute of Economic Affairs, 1996), p. 115.

Organization of Economic Cooperation and Development, Country Annexes, p. 297. 62

Mike Parker, “ Effects on Demands for Fossil Fuels, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, the 63

Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 123.

Electricity Association, Electricity Industry Review, 1996, p. 27. 64

Electricity Association, Electricity Industry Review, 1996, p. 27. 65

Department of Trade and Industry, Digest of United Kingdom Energy Statistics, 1993 and 1995 editions. 66

Matthew W. White, Paul J. Joskow, and Jerry Hausman, “Power Struggles: Explaining Deregulatory Reforms in Electricity Markets,” Brookings Papers 67

on Economic Activity, Washington DC, 1996.

Gordon MacKerron and Isabel-Segarra, “Regulation, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, the 68

Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 97.

See the 1983 article by Stephen Littlechild and Michael Beesley in “Principles, Problems, and Priorities,” Privatization & Economic Performance, ed. 69

Matthew Bishop, John Kay, and Collin Mayer (New York, Oxford University Press, 1994), pp. 15-31. 

Irwin M Stelzer, “Lessons for UK Regulation from Recent U.S. Experience,” Regulating Utilities: A Time for Change?, ed. Michael Beesley (London, 70

England: The Institute of Economic Affairs, 1996), p. 196. In some states, PUC commissioners are selected directly by the electorate. 71

“UK Electricity Privatization: The Regulator Rides Forth,” The Financial Times, September 27, 1990. 72

John Surrey, “Unresolved Issues of Economic Regulation, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, 73

the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 235.

“Labor Threatens REC Incentives, ”Public Utilities Forthrightly, June 15, 1995, p. 37. 74

“Calif. Oks Price Cap Plan for T&D,” Public Utilities Forthrightly, January, 1997, p. 48. 75
38 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

George MacKerron and Jim Watson, “The Winners and Losers So Far, ” The British Electricity Privatization Experiment, Privatization: The Record, 76

the Issues, the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 199.

Gordon MacKerron and Isabel Boira-Segarra, “Regulation, ” The British Electricity Privatization Experiment, Privatization: The Record, the Issues, 77

the Lessons, ed. John Surrey (London, England: Earthscan Publications Limited, 1996), p. 104. According to Rees and Vickers, this presents the following situation: “Where it is irrational for one party to make investments ex ante without some 78

guarantee that the other part will not opportunistically exploit the situation ex post.” Ray Rees and John Vickers,.“RPI-X Price-cap Regulation,” The

Regulatory Challenge, ed. Matthew Bishop, John Kay, and Colin Mayer (Oxford University Press, London, 1995), p. 365.

“Labor Threatens REC Incentives, “ Public Utilities Forthrightly, June 15, 1995, p. 37. 79

“Blair, Keeping Up Pace, Pledges Package of Reforms,” New York Times, May 15, 1998, p. 3A. 80
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 41

Table 14. Australian Electricity Profile: Consumption By Class of Customer and Population in 1995

Residential

(Billion kWh)

Commercial

(Billion kWh)

Industrial

(Billion kWh)

Population 

(Thousands)

Australian Capital

Territory . . . . . . . . . . . . . . . . 1.0 1.2 --- 305 

New South Wales ........ 16.1 8.2 23.8 6,152

Northern Territory . . . . . . . . .3 .9 -- 177

Queensland . . . . . . . . . . . . . 7.7 6.4 11.6 3,316 

South Australia . . . . . . . . . . .4 2.2 3.6 1,476

Tasmania ............... 1.8 .7 5.6 473 

Victoria ................. 15.6 7.8 15.6 4,521

Western Australia . . . . . . . . 2.9 7.8 -- 1,746

 Sources: Australian Electricity Supply Industry, Electricity Supply Association of Australia Limited, http://www.ozemail.

com.au/`esaamelb/page 2.htm; and Australian Bureau of Statistics, Australia Demographic Statistics, September Quarter 1996

(Canberra, Australia, March 1997), Table 3.

 Notes: kWh (kilowatt-hour) = one watt x one hour x 10 . The sum of the three consumption sectors will not equal total consumption 3

because other sectors (such as public lighting, traction, and not classified) are not included in this table. For total consumption for each

state and territory, see Table 3.

3. Electricity Reform and

Privatization in Australia

Prior to the reforms of recent years, the supply of elec- of Argentina and nearly thirty times the size of the United

tricity in Australia was provided by vertically-integrated, Kingdom. However, the majority of the population is

publicly-owned state utilities meeting the needs of concentrated in three states (New South Wales, Victoria,

individual states and territories. The electricity industry and Queensland) located in the eastern portion of the 1

had never operated on a national basis. Interstate grid country (Table 14). Consequently, these three states

connections were weak and electricity trade had been account for most of Australia’s electricity industry.

limited between the interconnected states. The state 2

governments were responsible for operational and Per capita electricity consumption in Australia is roughly

planning activities, and tariff structures. The National ten times that of Argentina and more than twice that of

Commonwealth government’s only involvement in the the United Kingdom. In 1995, Australia’s electricity

industry was through its principle shareholder status in generation was 160 million kilowatts per hour (Table 15).

the Snowy Mountains Hydro-electric Scheme in which the Australia’s two most populous states—New South Wales

two states of Victoria and New South Wales also hold and Victoria accounted for 35 percent and 23 percent,

shares. Some regulatory controls by the Commonwealth respectively, of total domestic electricity consumption

were exercised, however—mainly through control over (Tables 14 and 15). Electricity generation was provided

state borrowing limits, taxation, foreign ownership, and primarily through coal-fired power stations, which

environmental regulations. represented about 80 percent of the total fuel usage. The 3

In 1995, Australia’s population of 18 million was roughly through a combination of natural gas and hydroelectricity.

one third that of the United Kingdom and half of Nuclear power plants have never been used for electricity

Argentina’s population. Australia’s landmass totals generation.

almost three million square miles, almost double the size

4

remaining 20 percent of electricity generation is fueled

5
42 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Table 15. Australian Electricity Consumption, Generation, Imports, and Capacity by State and Territory,

1995

Consumption

(Thousand kWh)

Generation

(Thousand kWh)

Net Imports

(Thousand kWh)

Principal Power 

Stations Capacity

(MW)

Australian Capital

Territory .............. 2,272 -- 2,272 --

New South Wales ...... 49,648 54,339 4,478 12,150

Northern Territory ...... 1,203 1,317 -- 350

Queensland ........... 26,497 31,670 -285 6,617

South Australia ........ 9,257 8,157 2,420 2,407

Tasmania ............. 8,044 8,698 -- 2,434 

Victoria ............... 32,843 38,174 -1,151 7,805

Western Australia ...... 10,772 12,177 -- 2,638

Snowy Mountains . . . . . . -- 5,600 -- 3,804

 Hydroelectric Scheme

 Total ................ 140,536 160,132 8,019 38,235

 Note: kWh (kilowatt hour) = one watt x one hour x 10 , and MW (megawatt of electricity ) = one watt x 10 . Consumption does not 3 6

always equal generation plus net imports due to transmission losses.

 Sources: Australian Electricity Supply Industry, Electricity Supply Association of Australia Limited. <http://www.ozemail.com.

au/~esaamelb/page2.htm>.

Unlike the situation in the United Kingdom (UK), elec- new national regulatory regime is to be “light handed”

tricity reform and privatization in Australia have occurred and a form of price regulation (intended to promote

at both the state and national levels. Although the efficiency) will be applied to the regulated sectors.

Australian and U.S. electricity industries are in many

ways very different, Australia’s dual path to electricity The privatization of energy is a recent, but internationally

reform bears some similarities to current developments widespread, trend which has placed greater reliance on

in U.S. electricity markets. One result of Australia’s dual market forces and less dependence on government in the

state/national approach to electricity reform is that each allocation of resources. Australia’s electricity industry is

state has pursued different reforms with reform efforts at part of this trend as state government involvement in and

the national level providing more guidance than direction. ownership of this industry has moved toward corReform at the state level differs from UK reform, which poratization and privatization since 1995. The “overwas entirely a central government effort. These distinc- capitalized investments” made by the state governments

tions are noted below. Victoria has pursued the most in the electricity sector (generation capacity, transmission

aggressive electricity reform measures in Australia and systems, and distribution) had resulted in “high levels of

has most closely followed the UK model, while other reserve plant margins combined with high debt levels

states have pursued various degrees of more limited with minimum returns.” Monetary restraints and debt

reform. placed pressures on the federal and state governments to

At the national level, Australia’s electricity reform also providing service for the public.

differs significantly from the UK model in the operation of

the national electricity pool, in the authority of the The objective of reform in Australia was to “deliver more

national electricity regulator, and the level of regional efficient and sustainable use of capital infrastructure and

control. In other ways, national reforms have been quite energy resources and to improve Australia’s domestic and

similar to those of the United Kingdom. Australian gov- international economic performance.” To achieve these

ernments have generally split up their electrical industries objectives, the government considered competition the

along functional lines, with the state of Victoria adopting most effective tool. In addition, the state governments

the UK model’s separation of electricity into four seg- estimated that electricity reform would add an estimated

ments. A national grid and national pool are currently $5.0 billion annually to the Australian Gross Domestic

operating and are expected to be further developed. The Product.

6

7

reduce expenditures and increase efficiency while still 8

9

10

11
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 43

The Australian political institutions and practices are based on the Western liberal democratic tradition, reflecting institutions in

Canada, the United Kingdom and the United States. Although Australia is an independent nation, like Canada, it retains close a

constitutional links with Britain and gives allegiance to Queen Elizabeth II of Great Britain and Northern Ireland, who is also formally

Queen of Australia. The Queen is represented in Australia by a Governor-General and six state Governors. Under the Federal

Constitution, the Governor-General's responsibilities include summoning and terminating Parliament, concurring on Bills, appointing

Prime Ministers and judges, setting up Departments of State, and commanding the armed forces. 

The Executive (the Cabinet) is the major policy-making agency of the Federal Government and is presided over by the Prime Minister.

The Federal Constitution of Australia describes the powers of the Federal parliament (government). (The division of powers between

the Federal and State Parliaments follows the American model of federation.) The Federal government has two chambers: the House

of Representatives and the Senate. The House of Representatives membership is almost twice that of the Senate. The House has

148 member representing states and territories. State parliaments (governments) are subject to the provisions of the constitution at

the Federal level as well as their own state Constitutions. All state parliaments (governments) except Queensland, which abolished

its Senate in 1922, have two chambers. State Governments are responsible for the remaining powers not administered by the Federal

Government. The powers of the local government vary from state to state and are derived from legislation enacted by the state

government.

 

The Australian federation has a three-tier system of government and is characterized by the separation of powers to provide checks

and balances: 

• at the national level (under the provisions of the Constitution) there are three bodies which are responsible for the national

interest of the country: the Legislature (the House of Representatives and the Senate), the Executive Government, and the

Judiciary; 

• at the State and Territory level (under the relevant statutes) a Legislature, Executive Government and Judiciary; all are

responsible for matters specifically relevant to the States and Territories; 

• there are approximately 900 local government bodies at the city, town, municipal, and shire level. 

 

 Fact Sheet January 1995-0011:”Australia’s System of Government”, <http/www/dfat.gov.au/ipb/pubcn/fact_sheets_96/011sysgv.html. a

The Australian Governmental System

The electricity reform effort has been underway since introducing competition into the generation sector;

1991, when the various state and territorial governments combining the state-owned transmission units into a

agreed to work cooperatively to introduce a competitive single national grid; and restricting transmission and

electricity market in the southern and eastern regions of distribution businesses to the transport of electricity. In

Australia. (For a general description of the structure of addition, the Industry Commission recommended that

the Australian government, see the box entitled “The after privatization, tariffs should be reflective of actual

Australian Governmental System.”) costs, and cross-subsidies (from urban to rural consumers)

At a special conference in November of 1990, the Industry wealth, state and territorial heads of government estabCommission (a federal statutory body whose main lished the National Grid Management Council as an

objective was to improve the efficiency of the Australian intergovernmental advisory body to develop the National

economy) was appointed by the Commonwealth to Electricity Code in consultation with industry, stakereview the electricity industry and discuss the feasibility holders, and the public.

of a national electricity grid. The Industry Commission

recommended reforms that would eventually lead to the In October 1994, the National Grid Management Council

privatization of the electricity market. These reforms prepared the first draft of the national electricity market

included: unbundling the electricity industry into report entitled “Restructuring of the Electricity Supply

separate generation, transmission, distribution sectors; Industry in Australia.” This report addressed the broad

privatizing and corporatizing the separate (but still state- objectives for the proposed national electricity market, as

owned) electricity transmission and distribution sectors; well as the different types of trading arrangements to be

should be eliminated. Six months later, the Common- 12

13
44 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

provided, how it would operate, and how its security generation in the pool--the lowest bid price will be

would be maintained. The report’s recommendations dispatched first to supply demand):

were endorsed by each of the state governments and the

Australian Capital Territory. In September 1995, the

National Grid Management Council prepared a second

report that outlined the market functions of the proposed

national electricity market. The National Electricity Code

(the Code) establishes the rules and procedures for

operating in the competitive national electricity market.

The Code was completed in September 1996 and was sent

to the Australian Competition and Consumer Commission

for approval in November 1996.14

A further impetus to reform was the release of the 1993

National Competition Policy Review, known as the

Hilmer Commission Report. The report identified industries where reform could yield substantial benefits to

Australia’s economy. Electricity was one of these industries. In April 1995, the Council of Australian Governments agreed to a national competition policy reform, the

National Competition Reform Act of 1995, which provides

for uniform protection of consumer and business rights

and increased competition in all jurisdictions. This policy

would also enhance the national economic interest by

improving Australia’s international competitiveness, as

well as encourage competition in the trading activities of

government-owned enterprises. 

As part of the reform package, the Commonwealth agreed

to provide financial assistance payments to the states and

territories totaling $4.2 billion Australian dollars in 15

return for the states meeting their agreed obligations,

including the reform of their electricity, gas, water, and

road transport industries.16

Creation of the National

Electricity Market

As specified, the objectives of the competitive national

electricity market are:

• unbundling (the separation of transmission, generation, distribution, and marketing activities);

• ensuring non-discriminatory access to the national

transmission and distribution system;

• ensuring that customers (including generators,

marketers, and traders) have a choice of supplier;

• establishing transmission prices that are reflective

of actual costs;

• utilizing a merit order dispatch system (i.e., the South Australia, and the Australian Capital Territory

order in which generators will dispatch their (ACT) are connected to form a grid network. However,

• providing for interstate trading of generation;

• ensuring non-discriminatory access for new industry participants in generation and marketing; and

• establishing uniform regulation based on an

industry code of conduct.17

The Australian national electricity market (NEM) is to

develop in stages until a fully competitive market for

electrical generation and retail supply is achieved by 2001.

Although it is referred to as a national market, NEM will

initially include the states of Victoria, New South Wales,

South Australia, Queensland, and the Australian Capital

Territory, with the possibility of an expansion into

Tasmania following its grid interconnection. Western

Australia and the Northern Territory will not participate

in the market due to geographical and cost factors.

Victoria, New South Wales, and the Australian Capital

Territory are currently operating in a transitional phase of

the national electricity market (NEM1). South Australia

will enter the market in 1998 and Queensland is

scheduled to connect to the national grid by 2001. (See the

box entitled “The National Electricity Market (NEM) Time

Table.”)

The first phase of the NEM was scheduled for 1995

(covering New South Wales, Victoria, and the Australian

Capital Territory), but the actual startup of phase 1 began

on May 5, 1997. A national electricity generation pool was

introduced when Victoria and New South Wales began an

interstate wholesale electricity trading market, with the

Australian Capital Territory participating in the linked

market through New South Wales. In this market, the

states still operate under a separate wholesale power pool

but generators compete directly with each other (see the

section entitled “National Australian Power Pool” for a

discussion on the operation and structure of the new

national power pool). When less expensive electricity is

available in one state (e.g., Victoria), the pool allows

another state (e.g., New South Wales) to import this

cheaper electricity. The new power pool is intended to

create a national electricity market in Australia. 

Transitional Phase: Interstate Connections

Before the national electricity market can become fully

operational in the southern and eastern regions of Australia, three main transmission links need to be built to

interconnect these regions to form a national electricity

grid. Currently, the states of New South Wales, Victoria, 18
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 45

The different phases of the national electricity market provide a timeframe for the evolution of state and territory electricity markets

into the full national electricity market. There are three phases: NEM1 (two stages) , NEM2, and NEM3. a b

NEM1 stage 1: On May 5, 1997, the interstate wholesale electricity trading market began between New South Wales, Victoria, and

the Australian Capital Territory (Australian Capital Territory is participating in the market via New South Wales. The interstate

market operates under each state’s existing state code arrangements. In this phase, interstate trading among the states exist but

the security of the power system is still the responsibility of the individual states. There are limitations on the amount of power that

can be traded between state markets; however, this will be gradually removed.

The NEM1 stage 2 phase will began in October 1997. In this stage, all the regulations of the Code will be enforced (except for

market rules and system security, which will continue to be the responsibility of the states until the national electricity market

becomes operational).

(The original program for the phased introduction of the NEM included three phases: NEM1, NEM2, and NEM3. However, due

to the rapid implementation and development of the national electricity market in the NEM1 phase, it was recognized that NEM2

was no longer necessary.)

NEM3 pilot: Beginning in October 1997, Queensland will participate in the national electricity market. Although Queensland is not

connected to the national grid (and does not participate in interstate electricity trade), it will operate its own electricity system based

on arrangements specified in the Code. Since the state does not have an existing wholesale power market, it chose to follow the

Code’s arrangements instead of developing temporal arrangements. (The states’ trading arrangements would be nullified once

it was interconnected to the national grid).

NEM3: By mid 1998, the national electricity market will be operational and the market arrangements specified by the Code will be

applied. South Australian generators will enter the market as full participants.

In the future, NEM may expand to incorporate Tasmania, following grid interconnection.

 

Transgrid, NEM1: Gateway to the National Electricity Market (Implementation Edition, May 1997), http://www.tg.nsw.gov.au/sem/doc/reports/nem1- a

gateway/(May, 1997).

John Landels, “National Electricity Market Developments in Australia,” National Grid Management Council (Australia, June 1997). b

The National Electricity Market (NEM) Time Table

each government grid is not directly connected to the In 1993, a feasibility study to evaluate the economic and

other state grids; instead, they are all linked together via environmental implications of the Victoria to Tasmania

Victoria. The grids of Victoria and New South Wales are sub-sea link was both initiated and completed. In 1996,

linked with a maximum transfer capability of 1,100 similar feasibility studies were initiated for the other two

megawatts (with the largest capacity transmission net- necessary grid links. In 1997, New South Wales and

work running through the Snowy Mountains Hydro- Queensland announced their intentions to build the actual

electric Scheme). Victoria and South Australia are linked link interconnecting their two states by 2001. As of early

with a total transfer capability of 500 megawatts. The 1997, the remaining feasibility study was still in 19

ACT does not generate electricity; it imports its electricity progress.

from New South Wales. In 1995, interstate flows of

electricity represented on average less than 2 percent of The introduction of a national electricity market will

total electricity consumed within the states mentioned change the structure, operation, and regulations of the

above (excluding ACT). traditional Australian electricity industry. The expected

The three main links that must be built to interconnect the

southern and eastern regions of Australia to form a • separation of the vertically-integrated, state-owned

national grid are (1) New South Wales and South electricity monopolies into four activities—

Australia, (2) New South Wales and Queensland, and (3) generation, transmission, distribution, and mara sub-sea link between Victoria and Tasmania with a 300- keting—with competition being allowed for genmegawatt interconnection after the year 2000. eration and marketing activities.

20

21

changes include:
46 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

• regulation of the wholesale power generation participants (contestable customers, generators, marketers,

market; transmission networks will be transferred and brokers). Initially, only contestable customers—a

from the states to the national government. Since consumer with an annual electricity consumption of at 22

the transmission sector will retain monopoly chara- least 10 megawatts— will be eligible to participate in the

teristics, the prices charged to customers for the market. However, as the market matures, all customers

connection and use of the system will be listed will eventually have the option to participate because

separately. In addition, network prices will be cost- eligibility requirements will be reduced. All generators

reflective, and non-discriminatory to new entrants with a net export in excess of 30 megawatts are required

entering the market. to participate in the wholesale power generation market.

• introduction of competition into the individual

state electricity distribution systems (the existing

distribution companies will now have a marketing

function).

Implementation-The National

Electricity Code

The National Electricity Code (“the Code”) establishes the

regulatory and operational framework of the new

Australian national electricity market and binds all

participants in the wholesale power generation market to

the specified rules.23

The Code addresses the following: market rules; grid connection and access; metering; network pricing (transmission and distribution); and system security and

procedures for Code administration. The Code also contains a chapter on transitional matters which specifies

permissible short-term deviations from the Code and the

transitional paths that will be adopted by the participating

state jurisdictions to reach conformity by the end of the

transition phase. The Code is not legislation enacted by

the Australian national government. However, it is

binding on all market participants. In addition, the Code

also outlines the objectives, roles, and functions of two

new national regulatory bodies, the National Electricity

Market Management Company (NEMMCO) and the

National Electricity Code Administrator Limited. (See the

box entitled “The Regulators.”) These bodies were established by the participants of the national electricity market

(state and territory governments). The Code must be

submitted to the Australian Competition and Consumer

Commission (ACCC) for approval before it can be

implemented. In addition, changes in the Code can be

made only with the approval of the ACCC. In November

1996, the Code was submitted to the ACCC, with approval

expected in late 1997. 24

There are four groups who will participate in the wholesale power generation market. These groups are required

to become participant members of the National Electricity

Code Administrator Limited and are subject to all the

Code rules. The first group is comprised of market

25

Smaller generators can also participate on a voluntary

basis. The other three groups are NEMMCO, network

service providers (transmission and distribution), and

regional system operators (Figure 9). 

Buying Electricity in

 the National Market 

The national electricity market will offer a range of

options to suit the specific needs of electricity buyers and

sellers. Contestable customers have two options: (1) participate in the wholesale market, or (2) participate in the

retail market. If the contestable customer decides to participate in the retail market, all of their electricity will be

supplied through a marketer and they can not participate

in the wholesale market. On the other hand, if the contestable customer chooses to trade in the wholesale market

they must register as a participant with the NEMMCO.

Wholesale Trading Market. In the wholesale trading

market there will be three levels of trading: via a longterm bilateral contract; via a short-term forward market;

and via a spot trading market. (For further explanation of

the trading market, see the box entitled “Trading Arrangements.”) Participants in the wholesale market can operate

in any combination of these markets. All wholesale electricity trading will be accounted for through the pool. For

example, electricity provided to the network from wholesale suppliers (generators) and electricity taken from the

network by contestable customers and marketers will be

recorded. Marketers will participate in the wholesale

market on behalf of those contestable customers who have

made a decision not to participate in the wholesale market

or who have not met the megawatt eligibility requirements to participate in the wholesale market. In the

wholesale environment, electricity buyers could be both

end-use customers as well as marketers. Sellers of

electricity could be generators as well as marketers. 

Although each form of trading operates independently,

the operations and results in each trading market affect

the others. For example, when a contestable customer has

a long-term contract with a generator, it can operate its

business in a secure environment knowing that their costs
National Electricity Market

Generators

Pool

Distribution Network 

and Marketing

Noncontestable Consumers

Contestable 

Consumers

(Wholesale Market)

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 47

The National Electricity Code Administrator Limited

As the administrator of the Code, the National Electricity Code Administrator Limited (NECA) will monitor and report on compliance

with the Code; enforce the Code; resolve disputes through the Code; and manage changes to the Code. 

National Electricity Market Management Company

The National Electricity Market Management Company (NEMMCO) will be responsible for the management and administration of

the national electricity market across participating jurisdictions. It is also responsible for national merit order, and spot and forward

trading markets. In addition, the NEMMCO will be responsible for the operational integrity of the power pool in terms of achieving

an equilibrium between supply and demand.

Australian Competition and Consumer Commission (ACCC)

The ACCC is a Commonwealth agency responsible for applying and administering Australia’s national competition law (the national

anti-trust laws). The Code must be approved by the ACCC before it can be implemented. Before the ACCC approves the Code

it must be satisfied that the Code’s rules will result in a net benefit to the public and are not anti-competitive. The ACCC will have

a continuous oversight role in ensuring that the Code promotes competition and delivers public benefit.

The Regulators

Figure 9. Australian National Electricity Market

 Source: International Energy Agency, Energy Politics of IEA Countries, 1997.
48 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Trading Arrangements

Long Term Trading

• A long-term bilateral contract market - is a market where contestable customers, marketers, and generators have the choice

of entering into contractual arrangements. These contracts typically cover long-term commitments between buyers and

sellers of electricity and have a fixed volume of electricity over a specified time period. Contractual agreements are purely

financial trading instruments and will not have an impact on pool trading. The bulk of electricity generated in Australia may

be covered by this type of contract, particularly for those contestable customers who do wish to operate in the pool--a highrisk environment.

Short Term Forward Trading

• A short-term forward trading market - is a secondary market where participants (both generators and contestable customers)

can trade contracts, one to two days ahead of actual dispatch, thus allowing the contestable customer to adjust his

generation demand on the basis of short-term planning commitments in his business. It also allows the contestable

customer to better manage risk by not participating in the spot market. In addition, this type of trading allows generators

to better manage risks associated with earlier generation commitment decisions.

Spot Trading

• A spot trading market - is a market where the supply and demand of electricity is balanced at any point in time--at half hour

intervals. (Because electricity cannot be stored, equilibrium in this market must be achieved.) In general, at this half-hour

interval, the spot price is created, reflecting the actual market conditions that exist at that particular time. More specifically,

the spot price is based on a merit order dispatch system where the spot price is calculated after the last selected generator

in that half- hour interval has dispatched his last unit of power generation. This type of market can be beneficial to the

contestable customers because it allows them to trade on the basis of their actual generation or demand needs. This type

of trading is likely to be marginal in Australia because of the high risks associated with this trading market. When the

national electricity market has fully evolved (expected in mid 1998), the Australian National Electricity Market Management

Company (NEMMCO) will operate the spot trading market (often referred to as “the pool”).

are fixed for electricity generation. In addition, long-term and network charges and, in turn, would charge the

contracting provides the foundation for contestable cus- customer for these services. Prices for network service

tomers to make long-term plans. On the other hand, payments and energy payments would be unbundled in

short-term forward trading allows the contestable the bill. These charges would look similar to traditional

customer to make changes to its contract coverage one or tariff arrangements; however, the payment under the

two days before actual trading begins, in turn, giving the retail contract would reflect competitively-determined

customer the flexibility of purchasing more electricity at prices.

less expensive prices. Spot trading is a vehicle that is used

to balance supply and demand in half-hour increments (in

Australia) and establish the price of electricity at that

specific time.26

Retail Trading–Opting Out Of The Pool. In addition to Since low-cost coal is relatively abundant, total generating

the wholesale trading arrangements described above, capacity in the Australian electricity industry is domicontestable customers have the choice to purchase nated by large coal-fired power stations. Even though

electricity under a retail contract and thereby forfeit the fuel usage varies from state to state (depending on the

opportunity to participate in the pool (perhaps due to availability of natural energy resources), coal is the domrisk). Under retail trading, the buyer and seller can enter inant fuel source, accounting for 80 percent of primary

into any type of contractual arrangement and are not energy consumption (Table 16). The state of Tasmania is

bound to restrictions like those of the wholesale trading the exception, where electricity generation is mostly

market. Customers have the opportunity to negotiate fueled through hydroelectric power.

competitive contracts with the marketer of their choice,

thereby adding competitive pressure on suppliers for In the past, electricity generation in Australia was devebetter service and lower prices. In a typical contract, the loped independently by the individual states on a need

marketer would pay for the customer’s electricity usage basis (the Australian Capital Territory, however, does not

27

Electricity Reform at the State

and Territory Levels
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 49

Table 16. Australian Electricity Generation Fuel Usage in 1994

State or 

 Territory 

Coal

 Percentage

Gas 

Percentage

Hydroelectric

Percentage

Queensland ............. 86.0 13.4 0.6

New South Wales ........ 94.6 2.9 2.5

Victoria ................. 86.0 7.0 7.0

Western Australia ........ 71.6 20.9 -- 

Northern Territory ........ 98.0 2.0 -- 

Tasmania . . . . . . . . . . . . . . . 9.8 89.9

South Australia .......... 86.0 13.4 -- 

 Source: “State Poll May Delay Power Industry Reform,” The Australian (February 9, 1995) p. 4. Australian Electricity Supply

Industry, Electricity Supply Association of Australia Limited. < http://www.ozemail.com.au/~esaamelb/page2.htm>.

generate its own electricity). Total generation capacity companies were restructured into 5 companies. The

varies among individual states and territories. For transmission sector was divided into two components:

example, the states of Victoria, New South Wales, and PowerNet Victoria owns the high voltage transmission

Queensland account for a substantial majority of grid network and was made responsible for its mainAustralia’s total electricity consumption. However, in the tenance; and the Victorian Power Exchange was made

national electricity market, states will no longer supply responsible for pool operations and system dispatch. In

electricity to customers directly in their respective states, addition, the Office of the Regulator General was created

but will participate in the national power pool. (See the to promote competition in the generation and marketing

section entitled “Creation of the National Electricity sectors; to maintain an efficient and economic system; and

Market.”) to protect the rights of customers. 

The Australian electricity industry has implemented

significant reforms in preparation for their eventual entry

into the national electricity market. Although some states

will not participate in the market, they have implemented

reforms where possible to gain efficiencies to supply

customers and generators. Each state government has

made different arrangements (and adopted different time

schedules) for separating the segments of their electricity

industries for entrance into the national competitive

market. The state of Victoria is the first and most

advanced in its reform in the electricity sector compared

to reform in the other states and the single territory (the

Australian Capital Territory) that are participating in the

national electricity market.

Victoria

In October 1993, the state of Victoria began its reform with

the separation of the electricity system. The State Electricity Commission of Victoria was vertically separated

into three segments: generation, distribution, and transmission. In 1994, only a year later, Victoria restructured its

state-owned electricity industry further with the intention

of privatizing it (Figure 10). The generation sector was

divided into 5 companies, and the Victorian Power

Exchange was established to operate the wholesale power

generation market. The former 29 electricity distribution

28

29

Victoria permitted each of the five distribution companies

to retain monopoly rights to supply power to customers in

their respective geographic regions. However, in 1996 (in

an attempt to introduce competition into what was still a

state-owned system), large users (the contestable customers) were free to purchase electricity from any of the

five distribution companies. The current monopolies that

the five distribution companies have to supply electricity

to noncontestable customers will be phased out by

December 2000. In December 2000, all customers in

Victoria will be contestable. 30

In 1995, Victoria began the privatization of its electricity

assets (Table 17). Since launching its privatization program, the state has generated almost $16 billion in revenue, an amount which is mostly being used to repay state

government debt.

Through the auction process, Victoria sold off all of its five

electric power distribution companies (United Energy,

Solaris Power, Eastern Energy, Powercor, and Citipower)

in 1995 (Table 17). Companies from the United States,

and their consortia, led the way in purchasing these

plants.

Victoria pursued a markedly different approach to

privatizing its electricity industry than that undertaken in
Generation

Yallourn 

Energy

Hazelwood 

Power

Loy 

Yang A

Southern

Hydro

Ecogen 

Power

Loy 

Yang B

Snowy 

Mountain 

Hydroelectric 

Scheme

Victorian Power 

Exchange

(Wholesale Power)

Victoria Power Net

(Transmission Grid)

Distribution and Marketing

Electricity Generation and Transmission

50 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Figure 10. Victoria’s Wholesale Electricity Market

Table 17. Australian Electric Utility Privatization-Related Mergers and Acquisitions

(U.S. Dollars)

Australian Electricity Assets

Acquirer/Merger Partner

(Nationality) Value

Regional Generation Companies

Yallourn Energy , Victoria ......................... a PowerGen (UK) $1.8 billion

Loy Yang B, Victoria ............................ b Edison International (U.S.) $2.4 billion

Hazelwood, Victoria .............................. National Power (UK)) $1.9 billion

Loy Yang A, Victoria ............................. CMS Energy (U.S.) $3.7 billion

Queensland Power (Gladstone), Queensland ......... Northern States Power (U.S.) $1.7 billion

Regional Distribution Companies

United Energy,Victoria ........................... Utilicorp United (U.S.)c $1.2 billion

Solaris Power, Victoria ........................... Energy Initiatives (GPU/U.S)d $823 million

Eastern Energy, Victoria .......................... Texas Utilities (U.S.) $2.1 billion

PowerCor, Victoria ............................... PacifiCorp (U.S.) $1.6 billion

CitiPower, Victoria ............................... Entergy (U.S.) $1.2 billion

Transmission Companies

Queensland Pipelines ............................ PG&E (U.S.) $128 million

Moomba Sydney Pipeline ......................... Nova Corp (Canada) Petronas $262 million

(Malaysia)

 PowerGen took a 49.9-percent stake. PowerGen’s partners include the Australian Mutual Provident a

Society (26 percent), the New South Wales State SuperCorp. (8 percent), Hastings Funds Management 

(5.7 percent), and Itochu, a Japanese trading house (10.4 percent). 

 In 1992 Victoria sold a 51-percent interest in the power plant for $2.4 billion and later sold the remainder of the plant in 1997 for b

$66 million.

 Utilicorp holds a 49.9-percent ownership interest. Other investors were Australian companies, AMP Investments (40 percent), c

and State Superannuation Investment and Management Corporation (9.23 percent). Utilicorp’s direct investment was $258 million.

 Energy Initiatives is a subsidiary of General Public Utilities. Energy Initiatives’ partner is the Australian Gas Light Company. d

 Source: Power Asia, various issues, 1996-1997.

 Source: ABARE Economics, Commonwealth of Australia, Australian Commodities, Forecasts, and Issues, September Quarter 1995.
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 51

the United Kingdom. In contrast to the United Kingdom Victoria began its private sector involvement in the gen-

(where electricity assets were sold at prices set by the eration sector with the 51-percent sale of its Loy Yang B

national government), Victoria conducted a series of power station to the U.S.-based Edison International’s

staggered auctions of its five electricity distribution Mission Energy Company for $2.4 billion, with the agreecompanies and its four generation companies being ment that the government would purchase the station’s

privatized. Furthermore, all of the distribution and electricity over the life of the plant. Almost five years

generation companies were sold intact, and to other later, in May of 1997, Edison Mission Energy purchased

companies or consortia of companies. No restrictions the remaining stake in the Loy Yang B power station for

were placed on foreign investors. $66 million—thus terminating Victoria’s take-or-pay conIn the end, all of the newly-privatized Victorian electricity has enabled Victoria to further reduce its future state

companies were, at least in part, purchased by U.S. and debt.

UK utilities. As a consequence, corporate control over

these companies was concentrated in no more than a

handful of companies, unlike in the United Kingdom

where, at least initially, the new shareholders were

exclusively portfolio investors. In all cases a premium

was paid for shares in the newly-privatized Victorian

electric companies. The Victorian treasury benefited fully

from these premiums. 

Interestingly, the pattern of the disposal of Victoria’s

electricity assets bears some resemblance to current

electric utility restructurings in the United States. A case

in point is the recently announced intention of New

England Power (a wholly-owned subsidiary of New

England Electric) to sell its electricity generation units

intact to Pacific Gas and Electric. Apparently, maximum

value was achieved via a transfer of corporate control to

Pacific Gas and Electric. The divestiture could have been

undertaken via a leveraged buyout, or via the creation of

a new generation company and a distribution of shares in

this company to New England Electric shareholders.

The first distribution company to be sold (United Energy)

was purchased by UtiliCorp United (a U.S. company), and

its Australian partners for $1.2 billion. Initial bidders 31 32

on the plant were Pacific Gas and Electric, (a U.S. utility),

the French government-owned Electricite de France, and

Scottish Power (a United Kingdom company). However,

the latter two withdrew from the bidding process. The 33

second distribution company, Solaris Power, was sold to

Energy Initiatives (a subsidiary of General Public Utilities,

a U.S. company) and the Australian Gas Light Company

for $713 million plus an additional $110 million in fran- 34

chise fees. Texas Utilities (a U.S. company) purchased 35

Eastern Energy for $1.6 billion in November 1995. Two

other groups (Pacific Gas and Electric and PacifiCorp,

both U.S. companies), as well an Australian consortium

bid on the plant. In November 1995, PacifiCorp won the

bid for Powercor for $1.6 billion. The fifth distribution 36

company, Citipower, was sold in January 1996 to Entergy

(a U.S. company) for $1.2 billion. 37

Between late 1992 and 1997, Victoria sold its four electric

power generating plants (Table 17). In December 1992,

tract with the company. The termination of this contract

38

A second generation company, Yallourn-W, was sold in

March 1996 to PowerGen PLC (of the United Kingdom)

for $1.8 billion. PowerGen PLC outbid several U.S. 39

companies. In August 1996, the Victorian government 40

sold the Hazelwood coal-fired plant and coal mine for

$1.9 billion to a group led by National Power PLC of the

United Kingdom. National Power PLC purchased a 51.9-

percent interest. Others in the consortium included U.S.-

based PacifiCorp (a 19.9-percent interest), U.S.-based

Destec (a 20-percent interest), and the Commonwealth

Bank Group of Australia (an 8.2-percent interest). 41

In May 1997, Victoria sold another power plant (the Loy

Yang A coal-fired power station) and a coal mine. This

was the largest energy asset privatization in Australian

history. The Loy Yang A has the largest coal mine in

Australia and is the lowest-cost electricity generator in

Victoria, comprising 35 percent of the state’s electric

supply. A group led by the U.S. company CMS Energy 42

(50-percent interest) won the bid in May 1997 for $3.7

billion. Other partners in the consortium were NRG

Energy (a subsidiary of Northern States Power of the

United States) and Horizon Energy Australia, which each

purchased a 25-percent interest. Other assets in Victoria 43

scheduled for privatization include the Newport and

Jeeralang gas-fired power plants, and Victoria’s 29-

percent interest in the Snowy Mountains Hydro-electric

Scheme. PowerNet Victoria Transmission, the owner of 44

the state’s high-voltage electricity transmission grid, is

expected to be sold in late 1997. 45

Victoria also announced that it will privatize its stateowned gas utility. The utility will be separated into two

or three distribution businesses and its retail sector will be

divided into two or five businesses. The state’s gas

pipelines, Gas Transmission Company, will be sold as a

single company.

New South Wales

In contrast to Victoria, New South Wales (the most populous of the Australian states (Table 14)) has not privatized

its electricity industry. Instead, it unbundled the industry
Generation First State 

Power

Macquaria

Generation

Pacific 

Power

Snowy 

Mountains 

Hydroelectric

Transgrid

Distribution and 

Marketing

(Transmission and 

Wholesale Market)

52 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Figure 11. New South Wales’ Wholesale Electricity Market

 Source: ABARE Economics, Commonwealth of Australia, Australian Commodities, Forecasts, and Issues, September Quarter 1995.

into corporatized state-owned entities. Reforms in New Regulatory Tribunal, and Transgrid operates the state’s

South Wales have focused on the separation of the power pool. In July 1997, customers with energy conElectricity Commission of New South Wales’ generation sumption of 750 megawatts per year became eligible to

and transmission corporations. In August 1991, the Elec- choose their electricity marketer. This eligibility requiretricity Commission of New South Wales was renamed ment brings the state in line with Victoria’s eligibility

Pacific Power and was restructured internally into six requirements, which have existed since 1996.

smaller business units. Pacific Power's total generating

capacity is 11,512 megawatts, excluding the Snowy The state government initially declared it would not

Mountains Hydro-electric Scheme’s generation, and con- privatize its electricity assets to compete in the national

tributes 32 percent to Australia’s generation capacity. In market but would continue to maintain ownership of

1994, Pacific Power’s electricity transmission network electricity assets. However, in May 1997, the New South

business unit was established as a separate legal entity. Wales treasurer, Michael Egan, recanted this decision and

The Electricity Transmission Authority was separated announced his intentions to privatize all of the state’s

from Pacific Power in February 1995 and was formed as electricity assets. This new decision is expected to face

a separate state-owned corporation now called Trans Grid opposition within the state’s ruling Labor Party as well as

(Figure 11). The management, operation, and mainte- in the labor unions.

nance of the state’s high voltage transmission grid is the

responsibility of TransGrid. In October 1995, the The proposed privatization would generate an estimated 46

previous 25 distribution boards were aggregated into six $22 billion dollars in revenue, which would be used to

businesses and were later corporatized in March 1996 retire government debt. All of the assets would be auc-

(Table 18). tioned off without restrictions—excluding Pacific Power,

The New South Wales interim wholesale market began in ownership interest. So far, only three privately-owned

March 1996 and became fully operational in May 1996. projects have been initiated. In December 1995, Sithe

The market is regulated by the Independent Pricing and Energies (a U.S.-based independent power producer

47

48

49

which would be sold with a retained Australian majority 50
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 53

Table 18. The Australian Electricity Supply Industry Infrastructure Operators 

State/Territory Generation Companies Transmission Companies Distribution Companies

Victoria Yallourn Energy* PowerNet Victoria Eastern Energy*

Hazelwood Power Corp.* Solaris Power*Loy Yang Power A* United Energy*Southern Hydro Powercorp*Ecogen Power CitiPower*Loy Yang B*

New South Wales First State Power TransGrid Energy Australia

Macquarie Generation Integral EnergyPacific Power North Power Energy

Advance EnergyEnergy SouthFar West Energy

Queensland AUSTA Electric Queensland Transmission and Supply Queensland Transmission and

Supply Corporation Gladstone* Powerlink QueenslandCapricornia ElectricityFar North Queensland ElectricityMackay ElectricityNorth Queensland ElectricitySouth East QueenslandSouth West QueenslandWide Bay-Burnett Electricity

South Australia ETSA Corporation ETSA Corporation ETSA CorporationTasmania Hydro-electric Commission Hydro-electric Commission Hydro-electric CommissionWestern Australia Western Power Corporation Western Power Corporation Western Power CorporationAustralian Capital Territory --- -- ACTEW CorporationNorthern Territory Power and Water Authority Power and Water Authority Power and Water AuthoritySnowy Mountains HydroElectric Scheme Owned by New South Wales, Victoria, and the Commonwealth Government -- --

 *Denotes assets are privately owned. The states of Victoria and New South Wales are the only two that have privatizated some of their electricity assets. Source: Robin D6avey, APEC Electricity Regulator’s Form, Summary Submission (Australia, July 1996), pp. 14-19.
54 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

which is 29-percent owned by the Japanese company been split into three generating companies that will

Marubeni) and Broken Hill Proprietary (Australian- compete amongst themselves to supply the seven existing

owned) began the construction of a 175-megawatt cogen- government electricity distributors. In addition, three new

eration plant at Smithfield (near Sydney, Australia), with electricity marketing corporations will be created with 51

commercial operations to begin in 1997. Energy operations to begin in July 1997. Currently, there is no 52

Developments Limited is involved in a small-scale (4- physical electricity grid link between Queensland and the

megawatt) gas-fired power generation plant, and a pro- southern states; however, Queensland and New South

posed 90-megawatt coal steam methane power plant. Wales have announced that they will proceed with an 53

A consortium consisting of Air Liquide Australia Ltd,

Itochu Corporation (a Japanese company), and Energy

Australia (New South Wales’ electricity distributor) was

formed in 1995 to develop a 350-megawatt cogeneration

plant in Sydney. However, Energy Australia announced

in 1997 that it would sell its interest in the project, citing

that the company’s long-term strategic objectives have

changed due to its experience with the first stages of deregulation in the national electricity market. The company’s

20-percent interest in the project will be sold to Itochu

Corporation.54

Australian Capital Territory

The Australian Capital Territory (ACT) consists of Canberra and a number of surrounding areas. The ACT

corporatized its combined electricity and water utility 55

company in July 1995 (Table 18). This process included

separating electricity regulation from the water regulatory

function. The ACT does not generate its own electricity

and must rely on imports from New South Wales and the

Snowy Mountains Hydro-electric Scheme. In March 1996,

the ACT began to participate in New South Wales’ electricity market. In May 1997, the ACT began to operate in the

national electricity market in conjunction with New South

Wales and Victoria and will begin competition in electricity marketing in late 1997.56

Queensland

In January 1995, the Queensland Electricity Commission

was restructured and corporatized to form two new

government corporations—AUSTA Electric and the

Queensland Transmission and Supply Corporation

(QTSC). AUSTA Electric is responsible for electricity generation and QTSC is responsible for retail supply, distribution, and transmission. The QTSC has eight

subsidiaries: the transmission section of the former

Queensland Electricity Commission (Powerlink) and seven regional corporations in charge of distribution and

marketing (Table 18). 57

To further its commitment to the competitive national

electricity market, the Queensland government plans to

transform its monopolistic electricity industry into a competitive market by the end of 1997. AUSTA Electric has

interconnection between the two states by 2001.58

Queensland began the privatization of its generation

sector with the 37-percent equity sale of its Gladstone power station to a consortium led by Comalco (an Australian

company) and Northern States Power (a U.S. company).

Although there are no further plans to privatize electricity

assets, the government will no longer control either electricity prices or AUSTA Electric’s investments. The 59

Broken Hill Proprietary Company (an Australian company) began construction of a 105-megawatt gas-fired power station in 1994. By 1997, 30 percent of Queensland’s 60

generating capacity was owned by the private sector; that

proportion is expected to increase as new power stations

are constructed to meet expected electricity demand from

1998 through 2006. Energy Equity (an Australian com- 61

pany) has announced plans to build a gas- fired facility at

Barcaldine. Australia Shell has started a feasibility study

for the construction of a power station in Callide,

Queensland. Also in 1996, Pacific Gas & Electric (a U.S. 62

company) purchased Queensland’s natural gas pipeline.

AUSTA Electric is also considering additional supply

options for new generating capacity. Proposals for the

1998-to-1999 time period include the recommissioning of

the Collinsville and Callide-A plants; grid interconnection

with the New South Wales transmission link; and

construction of a 440-megawatt plant between the years

2000 to 2002. In the years 2003 to 2006, the state plans to

build a power plant with generating capacity between

600 and 1,400 megawatts.63

South Australia

South Australia accounts for 5.1 percent of Australia's

total generating capacity (Table 15). In 1995, the

vertically-integrated state-owned utility, Electricity Trust

of South Australia, was restructured and corporatized as

ETSA Corporation (Table 18). The corporation has four

subsidiaries: ETSA Generation, responsible for generation;

ETSA Transmission, responsible for transmission, system

control, and system planning; ETSA Power, in charge of

distribution and marketing; and ETSA Energy, responsible for gas trading. In January 1997, ETSA Generation 64

was separated from its parent company and became an

independent government business (ETSA Generation was

formerly a subsidiary of ETSA Corporation). South 65

Australia is scheduled to participate in the national

electricity market in 1998.66
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 55

Western Australia

Western Australia accounts for 7.6 percent of Australia's

generating capacity (Table 15). In January 1995, the

vertically-integrated state-owned utility, State Electricity

Commission of Western Australia, was divided into two

independent electricity and gas corporations, trading as

Western Power and Alinta Gas, respectively (Table 18).

Both corporations are currently state-owned. However,

the Western Australia government has now decided to

permit foreign investment in independent electricity

generation, separate and apart from the Western Power

and Alinta Gas operations. In 1995, Edison International

(a U.S. company), through its subsidiary Mission Energy,

began a project to build a $111-million power plant.67

Like Queensland, Western Australia is also privatizing

other energy assets. Western Australia has announced its

intention to privatize its gas pipelines. The CMS Gas

Transmission Storage Company (gas pipeline), a subsidiary of CMS Energy (a U.S. company), will purchase a

100-percent interest in the West Australia Natural Gas

(WANG) Pipeline near Perth, Australia. In addition, the

company will purchase the Western Australia petroleum

assets operated by Chevron, Texaco, Mobil and Shell. 68

Tasmania

The Hydro-electric Commission of Tasmania (HEC)

passed legislation in June 1995 to allow the entry of new

participants and extend customer choice in the industry

(Table 18). The HEC remains a vertically-integrated,

state-owned electricity business with separately organized

generation, transmission and distribution. A 1993 feasibility study concluded that while it was technically possible

to construct a subsea-link between the states, the project

would not be economically viable until the year 2000. In 69

April 1997, the government announced intentions to

introduce retail competition in its electricity industry and

to sell some of its equity interest.70

Snowy Mountains Hydro-electric Scheme

The Snowy Mountains Hydro-electric Scheme is a cooperative venture between the Australian Commonwealth

government, New South Wales, and Victoria. It represents a vital part of both Victoria’s and New South Wales'

electricity supply arrangements. The Scheme sells power

to the central government of Australia and to the electric

distributors in the states of New South Wales and Victoria.

It has a generating capacity of 3,740 megawatts, representing over 10 percent of Australia's capacity.

Under the national electricity market reforms, the Scheme

will not compete with New South Wales and Victoria in

generation. However, prior to the completion of the national electricity market, the Scheme will be corporatized.

It will then be expected to sell electricity on the national

grid in competition with other state and interstate generators.

Reforms in Price Regulation

The current Australian national electricity reform aims to

create a fully competitive national market in the generation and marketing sectors and to provide the incentives

for efficient outcomes at the state level in the transmission

and distribution sectors. The price for electricity genera- 71

tion will be determined by the spot price or the pool price.

As in the United Kingdom, Australia has instituted a form

of price and revenue cap regulation that has been applied

to the transmission and distribution sectors (because these

segments are still deemed natural monopolies). 

Currently, only the states of New South Wales and

Victoria have a wholesale power generation market and

have instituted reforms in price regulation (the Australian

Capital Territory is participating in the national electricity

market via the New South Wales electricity system). The

other states that will participate in the national electricity

market do not have a state-level wholesale power generation market. Since the first phase of the national electricity

market (NEM1) is already underway, Queensland will not

develop its own price arrangements prior to participating

in the national electricity market but will operate its electricity system on the basis of rules specified in the Code.

The National Australian Power Pool

The planned national electricity market is designed

around a power generation pool (or spot market). The

pool ensures that the demand and supply of electricity are

balanced at all times—every day is divided into half hour

segments. Prices are effective for these half-hour periods

and this price is paid to any generator supplying electricity during that period and is the same price charged to

any customer who consumes it during that period. All

generators with a generating capacity of greater than 30

megawatts are required to participate in the national

market. Customers with an annual usage of at least 10

megawatts will be eligible to participant in the market,

along with retail electricity suppliers. Generators and customers must submit their bids 24 hours in advance to

specify the amount of power and the price they will supply and purchase generation, respectively. 

Currently, the national electricity market’s power pool is

operating in a transitional phase, NEM1. In NEM1, the

goal is to integrate the wholesale power markets of New
56 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

South Wales and Victoria into one market in order to ease needs of their individual states (Figure 10 and Figure 11).

the eventual full transition to the national electricity The wholesale power market in New South Wales began

market. in 1996. Victoria’s wholesale power market began in 1994.

In the operation of NEM1, there is a central entity (called will supply electricity to an integrated wholesale power

the “interconnection scheduling module”) where both pool, and (through that pool) they will compete with each

states’ transmission operators, the TransGrid (New South other to supply the combined energy needs of the two

Wales) and the Victorian Power Exchange (Victoria), states and the Australian Capital Territory.

submit the generation bids and the estimated electricity

demand of their individual states. In turn, the demand for

generation is forecast, and the amount of interstate power

trading between the states is determined. A dispatch order

is established and is sent back to each state market

operator (TransGrid and the Victorian Power Exchange),

who dispatches generation. The price of the highestpriced generator dispatched in a given period (the

“marginal” generator) sets the pool price for that period.

This price is received by all generators who dispatch

electricity in that period and is paid by customers who

take electricity. 

After the National Electricity Code is approved and the

full national electricity market is implemented, the

National Electricity Market Management Company

(NEMMCO) will assume the functions of the interconnection scheduling module. 

The Code realized that in order to give the correct market

signals in the spot market, it is important for the spot price

to be allowed to approach realistically high values. The

Code also recognizes that in an immature market, such as

Australia, allowing the spot price to operate at a level

where supply and demand are balanced may result in a

very high price which would expose inexperienced participants to unnecessarily high financial risks. Therefore,

the Code makes provisions for a temporary Value of Lost

Load (VoLL) price cap. The price cap is set (in Australian

dollars) at $5 per kilowatt hour. The Code set the value 72

of the price cap at this level in order to strike a balance

between the highest price that purchasers of power might

consider acceptable and a price high enough to ensure

that generators would not be discouraged from investing

in plants with high operating costs.

In the implementation of the full national market, the

National Electricity Market Management Company

(NEMMCO) will be responsible for the operation of the

power pool and the short-term forward trading market.

At the state level, the wholesale power generation market

operates almost like the operations contemplated for the

national electricity market (the fully transitional national

market will begin in the first half of 1998). The state

(Victoria and New South Wales) operates its own pool, Currently, the regulations for both transmission and

and generators compete in the pool to supply the energy distribution are established by state regulators. The

In NEM1, generators in Victoria and New South Wales

Price and Revenue Cap Regulation

Pricing in the transmission and distribution sectors of the

Australian electricity industry are set by a cap, above

which prices or revenues are not permitted to rise.

Victoria’s tariff regulation is mainly a price cap. A price 73

cap consists of a ceiling where a company has complete

price flexibility as long as its price stays below that level;

that is, prices can move up and down but they must stay

under (or at) the ceiling. The price cap can serve to keep

prices (both unit electricity costs and distribution network

costs) from rising too high, and it can protect electricity

customers from large and/or frequent price fluctuations.

It can also provide an incentive for productivity improvement and cost efficiency. In other words, operators have

incentives to cut costs and increase efficiencies.74

However, it can also result in unusually high levels of

profitability, which can raise public concern.

The price cap is commonly referred to as “CPI (Consumer

Price Index) minus X.” As in the United States, the “CPI”

is a measure of inflation. The “X” is a productivity factor.

The theory behind the use of the “CPI-X” price ceiling is

that a regulated company must be allowed to recover

inflationary increases in its input costs, but should not

receive additional benefit from productivity improvements that result in lower operating costs which also offset

inflationary increases in input costs. The Australian CPI-X

formula is similar to the RPI-X form of regulation adopted

in the United Kingdom. (See the section in Chapter 2

entitled “RPI-X: Rate Caps versus Rate-of-Return Regulation” for further details on UK price-cap regulation.)

In New South Wales, a revenue cap is applied in the

transmission and distribution sector. Revenue cap regu- 75

lation works much the same way as price-cap regulation.

However, instead of indirectly limiting a company’s

revenues by controlling its prices (the price-cap approach), under a revenue cap the CPI-X formula directly

limits the total amount of revenue a company can receive.

Future Regulation of Transmission

and Distribution Sectors
1980

1985

1990

1994

1995

0

20

40

60

80

100

120

1985

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 57

Figure 12. Total Direct Investment in Australia,

Selected Years

 Source: United Nations Conference on Trade and Development,

World Investment Report 1996, Investment, Trade and

International Policy Arrangements, (New York, New York: United

Nations, 1996).

regulator in New South Wales is the Independent Pricing fair and open competitive markets are leading to opporand Regulatory Tribunal, and the regulator in Victoria is tunities for private investment in the electric industry. In

the Office of the Regulator General. (As previously stated, 1995, the direct investment position in Australia in the

Victoria’s electricity tariff regulation is mainly a price cap, category “other industries” (of which electricity is the

whereas in New South Wales a revenue cap is mainly major part) almost tripled from the prior year’s level

applied.) Regulatory arrangements in transmission partly due to the acquisition of Australian electricity

pricing under state jurisdiction will end in June 1999 in assets. (According to the U.S. Department of Commerce,

New South Wales, and in December 2000 in Victoria.76 direct investment involves the establishment of a new

Thereafter, the Australian Competition and Consumer firm, the expansion of an existing firm, or the acquisition

Commission (ACCC) will become responsible for trans- of a business enterprise or real property in which a foreign

mission regulation. The ACCC has not made a final person or company obtains direct or indirect ownership of

decision on the regulatory guidelines and rules to be used at least ten percent of controlling equity). The 1995 total

in determining transmission pricing except that the direct investment position in Australia (by the United

guidelines will be cost-reflective and will utilize revenue States and other countries) was $104.2 billion, a $13.1-

or price capping or a combination of both. After this deci- billion increase from investment during the prior year

sion has been made, transmission network service pro- (Figure 12). Of this increase ($13.1 billion), the United

viders must develop their own pricing structures and States accounted for almost $5 billion and total direct

tariffs and submit them to the ACCC for approval. investment has increased every year since 1988 (Figure

Additionally, the ACCC will produce a “Statement of 13). 

Regulatory Intent,” which will establish guidelines as to

how it will exercise its power in this regulatory area.77

In the area of distribution, the Code provides national

objectives and economic principles that each state should

follow; however, the states retain jurisdiction over distribution pricing. The Code recognizes that it may be

inappropriate to apply national guidelines to state jurisdictions because of existing distribution service pricing

regimes. Nonetheless, the Code has made provisions

which allow the states to develop a set of national guidelines for distribution service pricing. However, any such

proposed distribution pricing guidelines must be unanimously approved by all of the states and must not conflict

with or override any pre-existing distribution regulations

in any of the individual states.78

The ACCC will be responsible for three missions. First, it

will ensure that economic efficiency gains are realized by

customers (in terms of price, level of service, and quality

of service) and by generators (in terms of optimizing their

generating plants and lowering operating costs). Second,

its role is to ensure that generators do not raise prices to

reap excessive profits. Third, it will ensure that anti-competitive pressure is not exerted by generators to exclude

potential competitors from entering the market.79

Privatization and Reform Outcomes

Investment in Australia

The level of foreign investment in the Australian electricity industry has increased and is expected to continue to

expand as reforms and privatization in the electricity

industries continue. The reforms aimed at developing 80

81

82

83

American companies’ attraction to foreign investment in

Australia can in part be traced to the passage of the 1992

Energy Policy Act in the United States, which, for the first

time, permitted U.S. utilities to own an equity interest in

foreign utilities.

The introduction of electricity reform in Australia has

given U.S. companies (as well as companies from other

countries) the opportunity to invest in an electricity system which has the potential for improved efficiency. In

fact, some U.S. companies have stated that investments in

Australia’s electricity market would give them expertise

in operating in a deregulated electricity market and

therefore would give them an added advantage when

deregulation begins in the United States. Slow economic 84
Generation Yallourn 

Energy

Hazelwood 

Power

Loy 

Yang A Southern

Hydro

Ecogen 

Power

Loy 

Yang B

Snowy 

Mountain 

Hydroelectric 

Scheme

Victorian Power 

Exchange

(Wholesale Power)

Victoria Power Net

(Transmission Grid)

Distribution and Marketing

Electricity Generation and Transmission

58 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Figure 13. U.S. Direct Investment Position in

Australia, 1988-1995

 Note: The other industries category of foreign direct investment

includes electric utilities, natural gas and sewage. The data for

other industries between the years of 1988 and 1990 are close to

zero.

 Source: United States Department of Commerce, Bureau of

Economic Analysis, Survey of Current Business, various issues.

growth in the United States, Australia’s low political risk, customers to compete for power within the individual

and their new regulatory climate for electricity are power pools of their own states (first in Victoria in 1994,

additional factors. Efficiency gains are already evident and then in New South Wales in 1996). 85

in New South Wales and Victoria, the two states with the

greatest degree of reform and privatization. If the results of the ACM survey of this type of customer

Prices, Labor Productivity 

and Customer Service 

In February 1997, the New South Wales Independent

Pricing and Regulatory Tribunal reported that wholesale

electricity prices in Australia have steadily decreased

since 1993, representing a 32-percent drop in real terms

over a four-year period.86

Victoria has also realized a decline in electricity prices of

6 percent as well as improvements in service quality. Due

to continued improvements in labor productivity between

the years of 1991 and 1995, returns on assets have also

increased. The labor productivity increases have, in

particular, been attributed to Victoria’s reform and

privatization efforts.87

An Australian Chamber of Manufacturers’ (ACM) survey will compete in the power pool as they acquire the

of its contestable customers (large end users) in Victoria necessary skills to do so. As the national electricity market

reported that approximately 2,500 Victorian companies in Australia matures, the nature of the relationship

were eligible to enter the wholesale power market in 1996. between “middleman” distributors/marketers and large

The survey was developed to examine prices, customer end users requiring power from the national pool may

satisfaction with service, and supply conditions in the become more apparent.

market. Of the 800 contestable customers who were given

the survey, the ACM had 312 respondents. Of the 312

respondents, about 78 percent of the respondents believed

their negotiated electricity prices were cheaper compared

to rates prior to the 1994 beginning of the Victorian

wholesale power market. Only 10 percent believed they

were worse off under the new arrangements. The average

price reduction response per respondent was about 10

percent, with savings varying between 1 percent and 39

percent. While price was the major consideration for most

customers when choosing a supplier, almost 33 percent of

the contestable customers reported an improvement in

service, while almost 64 percent reported no change. As

for supply conditions, of the 312 respondents, 93 percent

had negotiated a new contract subsequent to the 1994

reform. Thirty-five percent of the respondents who had

negotiated a new distribution contract had also changed

their electricity supplier.88

In constructing its national electricity market reform,

Australia plans to expand upon the UK model by large

end users (contestable customers) to directly compete for

generated power in the national electricity pool. This

concept was tested (on a smaller scale) by allowing these

(large end users) are considered to be representative of all

of the large end users in Australia, several questions

might arise. Why are the majority of these customers

choosing to use the marketing services of a distributor to

compete in the power pool on their behalf, instead of

cutting out this “middleman” and directly competing for

their own power needs themselves, as the electricity

reform allows? The answer to this question is not entirely

clear. It may be that the large end users need time to

acquire the skills and gain the experience necessary to

effectively operate in the competitive power pool process.

It may also be that purchasing these services through

contractual arrangements from a distributor experienced

in the power pool bidding process lowers the risk of pool

competition for a relatively small charge. Perhaps purchasing these services is simply more convenient. Or, it is

possible that this trend (of large end users retaining

distributors to compete for power on their behalf) is

transitory, and that more and more of these customers
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 59

Australia has six states—Victoria, New South Wales, Queensland, South Australia, Western Australia, Tasmania—and two mainland 1

territories—Australian Capital Territory and Northern Territory. Victoria, New South Wales and the Australian Capital Territory are the only states and territory that are currently interconnected to form a grid. 2

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996), p. 1. 3

Electricity generation is fueled mainly by coal in all the states of Australia except in Tasmania. Electricity generation in Northern Territory is also fueled 4

mainly by coal. Ninety percent of Tasmania’s electricity generation is supplied by hydropower. South Australia rely heavily on gas turbine combustion.

 The Snowy Mountains Hydro-electric Scheme contributes 11 percent of the total electricity generation in Australia. 

Australian Bureau of Statistics, Year Book Australia 1997 (Canberra, New South Wales, 1997), p. 445; International Energy Agency, Energy Policies 5

of IEA Countries: 1996 Review (Paris, France: Organization for Economic Cooperation and Development, 1996) p. 108; and Australian Electricity Task

Force, Summary of Electricity Market Reforms in Australia (May 1997), p. 1.

 N. Cain, “Australia-Power Generation Profile,” 1995 Trade Data Bank: Market Reports (December 14, 1995), p. 2. 6

 N. Cain, “Australia-Power Generation Profile,” 1995 Trade Data Bank: Market Reports (December 14, 1995), p. 2. 7

 N. Cain, “Australia-Power Generation Profile,” 1995 Trade Data Bank: Market Reports (December 14, 1995), p. 2. 8

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996), p. 1. 9

 In this paper it is assumed that the exchange rate is US $0.74 equal A $ 1.00 currency. 10

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996), p. 1. 11

Organization for Economic Cooperation and Development, “Electricity Supply Industry: Structure, Ownership and Regulation in OECD Countries, Part 12

3 Country Annexes” (1994), pp. 162 and 163.

Empowering the Market: National Electricity Reform For Australia, (Melbourne, Victoria:National Grid Management Council, 1995), p. 2 and 3. 13

The National Electricity Code. <http://acc.gov.au/shed/httoc.htm7> 14

International Energy Agency, Energy Policies of IEA Countries: Australia (Paris, France: Organization for Summary of Market Reforms in Australia, 15

March 1997) Chapter 8.

Organization for Economic Cooperation and Development Economic Surveys: Australia 1996 - 1997 (December 1996), pp. 123 and 191; and Council 16

of Australian Governments, “Communique,” Canberra, New South Wales (April 11, 1995).

International Energy Agency, Energy Policies of IEA Countries: Australia (Paris, France: Organization for Summary of Market Reforms in Australia, 17

March 1997) Chapter 8.

The national electricity grid is the combination of all the electricity poles, wires and cables within the southern and eastern states of Australia-- New South 18

Wales, Victoria, South Australia, Queensland, Tasmania, in addition to the Australian Capital Territory. Western Australia and the Northern Territory are

not involved in the national electricity market due to distance and cost factors.

Organization for Economic Cooperation and Development Country Analysis: Australia (March 1997), p. 93. 19

 “Australian States Agree on Route for Electricity Grid Link,” Dow Jones Newswire (June 6, 1997), p.1. 20

Organization for Economic Cooperation and Development Country Analysis: Australia (March 1997), p. 93. 21

The first phase of the national electricity market was expected to begin in 1995 and was later rescheduled to 1996. VPX: Market Update, March 1997 22

vol 3 Issue 2; < http://electricity.net.au/update>

Empowering the Market: National Electricity Reform For Australia, (Melbourne, Victoria: National Grid Management Council, 1995), p. 7. 23

Electricity Legislation And Codes - Australia, <http/www/ccw.com.au/ccwpub/22fa.htm> 24

Some of the generation power plants are publicly owned, such as Electricity Trust of South Australia and some are privately operated, such as Mission 25

Energy’s Loy Yang B plant. 

Market Trading Working Group, Restructuring of the Electricity Supply Industry in Australia, (National Grid Management Council, September 1995), 26

<http/www/energyonline.com/Restructuring/models/2austtoc.html> Ibid. 27

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996). 28

Choice of Electricity Retailer: For Customers with Consumption Greater than 750 MWh per year (Victoria: Office of the Regulator-General, Victoria, 29

February 1996).

Choice of Electricity Retailer: For Customers with Consumption Greater than 750 MWh per year (Victoria: Office of the Regulator-General, Victoria, 30

February 1996). UtiliCorp United will manage the utility operations and hold a 49.9 percent ownership interest and the remainder of the ownership will be owned by AMP 31

Investments with almost 41 percent and State Superannuation Investment and Management Corporation with 9 percent.

“UtiliCorp Says Earnings of Australian Electric Operations Exceed Expectations,” Business Wire (May 15, 1996); and “UtiliCorp Expand Again, Wins 32

Australian Utility Bid,” The Energy Daily (August 8, 1995). 

“UtiliCorp United Plans to Bid on More Projects in Australia,” Kansas City Business Journal (August 18, 1995), Section 1, p. 4. 33

“GPU Subsidiary Energy Initiatives to Acquire Half Ownership of Solaria Power Ltd., an Electricity Distribution Business in Australia,” Business Wire 34

(October 30, 1995), p. 1.

“T. U. Beats Out PG&E and PacifiCorp for Eastern Energy of Australia,” Electric Utility Week (November 20, 1995), p. 15. 35

“PacifiCorp Hikes Australian Presence by Acquiring Share of 1,600-MW Plant,” Electric Utility Week (August 12, 1996), p. 15. 36

“1995: The Year In Review,” The Energy Daily ( January 2, 1996); “Entergy Opens Sydney, Australia Office,” PR Newswire ( September 19, 1996); 37

and “Global Expansion,” Electric Light & Power ( January 1996).

 “Australia: Loy Yang B Sale Slashes Victoria’s Risk Exposure,” Dow Jones Newswire (May 5, 1997), p. 1. 38

“PacifiCorp Hikes Australian Presence by Acquiring Share of 1,600-MW Plant”, Electric Utility Week (August 12, 1996), p. 15. 39

Northern States Power, Central and South West, Consumers Power affiliate CMS Generation, American Electric Power, Public Service Electric and Gas 40

affiliate Community Energy Alternatives, and Duke Power. “U.S. Utilities Dominate Shortlist for 1,450-MW Plant in Australia”, Electric Utility Week

(December 18, 1995).

“PacifiCorp Hikes Australian Presence by Acquiring Share of 1,600-MW Plant”, Electric Utility Week (August 12, 1996), p. 15. 41

“CMS, NRG Energy and Horizon Energy Australia Investments Close on Acquisition of Australia’s Loy Yang A Plant and Coal Mine”, PR Newswire 42

(May 12, 1997). Other bidders were Transpower, a subsidiary of U.S.-based AES Corporation, in a consortium with Singapore Power Ltd. and U.S.-based

American Electric Power and China Light Power. 

Endnotes
60 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

 “CMS-Led Group in Australian Power Plant Deal,” New York Times (April 23, 1997), p. 43

“Mission to Buy Rest of Lo-Yang B,” Power In Asia (April 7 1997), p. 25; and (January 13, 1997), p. 29. 44

“Victoria $10bn Power Sale,” Power In Asia (January 13, 1997), p. 29; and “Victoria to Sell,” Power In Asia (May 5, 1997), p. 26. 45

“Electricity Generation, Structural and Regulatory Reform in Australia,”Australian Commodities, Vol 2, No. 3(September 1995), pp. 358-373. 46

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 1996). IEA Countries: Australia, p. 91. 47

Australia’s NSW Welcomes Foreign Buyers In Electricity Sale,” Dow Jones Newswire (May 27, 1997), p. 1. 48

“Australia: NSW Electricity Sale Faces Opposition-Amplifier,” Dow Jones Newswire (May 27, 1997), p. 1. 49

“Australia’s NSW Welcomes Foreign Buyers In Electricity Sale,” Dow Jones Newswire (May 27, 1997), p. 1. 50

“Deals of the Year: The Annual Financing Review - Project Finance,” Asia Money (February 1996 ), pp. 37-46. The Smithfield plant is the largest 51

co-generating plant in Australia.

Sithe Energies, Inc., Securities and Exchange Commission Form 10-K, 1995, p. 3. Cogeneration is the simultaneous production of two or more useful 52

forms of energy, such as electricity and steam, from a single primary fuel source. 

“Transfield Set for 160 MW Congen Unit for NSW,” Power In Asia (April 28, 1995), p. 25. 53

“Energy Australia Sells Out of $215 mln Botany Project,” Asia Pulse (March 20, 1997); and “Air Liquide to Build Australia’s Biggest Combined Heat 54

and Power Plant,” European Report (May 29, 1996).

Corporatized - the entity will remain in the public sector with a board nominated by the states but their functioning and legal obligations are identical 55

to those in the private sector.

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996); and “Introducing Competition in A.C.T. Electricity 56

Retailing,” A.C.T. Government, Department of Urban Services (December 1996).

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 19. 1996), p. 24. 57

 “Australian States Agree on Route for Electricity Grid Link,” Dow Jones Newswire (June 6, 1997), p.1. 58

“Queensland Energy Minister Decides Not to Sell 5,316-MW Austa Electric,” Independent Power Report ( December 27, 1996). 59

“BHP Unit Cleared by W.A.,” Power In Asia (May 15, 1995), p. 24. 60

“Australia: Queensland Electricity Mkt On Track - Minister,” AP-Dow Jones News Service (April 23, 1997). 61

“Shell Makes Move to Sell Power,” Power In Asia (April 7 1997), p. 25. 62

“Progressive Change,” Independent Energy (July/August 1996), pp. 27-31. 63

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 19. 1996), p. 24. 64

John Landels AC, “National Electricity Market Developments in Australia” (National Grid Management Council, Australia: June 1997). Paper presented 65

at the Edison Electric Institute. 

Transgrid, NEM1: Gateway to the National Electricity Market (Implementation Edition, May 1997), http://www.tg.nsw.gov.au/sem/doc/reports/nem1- 66

gateway/(May, 1997).

The San Diego Union-Tribune (February 25, 1997), p. C1. 67

“CMS Energy’s International Gas Pipeline Unit Acquires Western Australia Natural Gas Pipeline Serving Perth,” PRNewswire (May 9,1997). 68

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996), p. 24. 69

John Landels AC, “National Electricity Market Developments in Australia” (National Grid Management Council, Australia: June 1997). Paper presented 70

at the Edison Electric Institute. 

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996), pp. 6-11. 71

National Electricity Code, Chapter 3.9. <http://electricity.net.au/code_r.htm> 72

Organization for Economic Cooperation and Development, Country Analysis: Australia (March 1997), p. 96. 73

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia,” (July 9, 1996), p. 96. 74

Organization for Economic Cooperation and Development, Country Analysis: Australia (March 1997), p. 96. 75

State regulator control in Queensland and Australia Capital Territory will both end in June 1999; and South Australia in December 2000. Source: National 76

Electricity Code, Chapter 6.2, <http//www.electricity.net.au/code_r.htm>. National Electricity Code, Chapter 6.10. <http://electricity.net.au/code_r.htm> 77

National Electricity Code, Chapter 6.10. <http://electricity.net.au/code_r.htm> 78

Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia,” Regulator General Victoria, Australia (July 9, 1996). 79

Australia is also currently undertaking efforts to deregulate its natural gas industry. Natural gas is expected to increase its share of the electric utility 80

industry’s fuel market.

United States Department of Commerce, Bureau of Economic Analysis, Survey of Current Business, various issues. 81

H. A. Poniachek, Direct Foreign Investment in the United States, (Lexington, Massachusetts:Lexington Books), p. xi. 82

United Nations Conference on Trade and Development, World Investment Report 1996, Investment, Trade and International Policy Arrangements, (New 83

York, New York: United Nations, 1996). 

“PacifiCorp Hikes Australian Presence by Acquiring Share of 1,600-MW Plant,” Electricity Utility Week, (August 12, 1996), p. 15. 84

“International Investing by U.S. Utilities”, Institutional Investor, Inc.(October 1996), p. 3. 85

 “NSW Takes the Low Road,” Power In Asia (February 10, 1997), p. 26. 86

 Robin Davey, APEC Electricity Regulators’ Forum, Summary Submission: Australia (July 9, 1996). 87

“Customer Feedback on Victoria’s Competitive Electricity Market: A Report on the ACM Survey of Contestable Electricity Customers,” Australian 88

Chamber of Manufactures, (November 1996).
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 63

4. The Transformation of Argentina’s

Electricity Industry

Argentina’s economy of the 1980's was engulfed in late 1950's and early 1960's, Argentina privatized some

numerous problems, some of which could be traced to nationalized industries. Again, during the 1970's, another

developments in the 1940's. Economic problems of hyper- wave of privatization was undertaken, resulting in the

inflation, low economic growth, and rising national debt sale of 120 companies. Attempts to increase the efficiency

were worsened by a deteriorating infrastructure, of remaining public companies during the late 1970's and

including the electricity infrastructure. Hyperinflation 1980's were largely unsuccessful. For example, the 13 1

was dramatically reduced following passage of the largest public companies in Argentina (exclusive of deConvertibility Law of 1991, which formally initiated then- fense) had an operating deficit of $3.8 billion on revenue

Economy Minister Cavallo’s plan to align Argentina’s of $8.7 billion during 1989. During the first half of 1990,

peso to the U.S. dollar. Additionally, the law required the operating deficit grew another 35 percent. 

100-percent backing of the nation’s currency by foreign

reserves. The decision to link the Argentine peso to the The country’s inability to resolve these problems led to the 2

U.S. dollar limited Argentina’s available solutions to other 1992 privatization program. By this time, Argentina’s

problems (for example, low economic growth) by severely electricity industry “...had deteriorated badly and was

limiting discretionary changes in the nation’s money characterized by severe operational and financial

supply. Thus, privatization was not only an action that difficulties... .” The industry was constantly threatened

could solve many of Argentina’s remaining problems (i.e., with the possibility of blackouts, a threat which worsened

rising debt and deteriorating infrastructure) but also an during periods of relatively little rainfall (such as the

action that was permissible under the new economic plan. summer) because of Argentina’s reliance on hydroelectric

Privatization directly addressed the problem of rising debt sive and often stolen by consumers either through illegal

by divesting inefficiently-operated assets and companies. hook-ups or by failure to pay bills. (Argentina’s probIn addition, it was expected that the new owners of lems were similar to those of other Latin American

privatized assets would improve the assets, thereby countries. For a brief review, see the text box entitled,

upgrading Argentina’s infrastructure. Further, privatiza- “Historical Overview of Latin American Electricity.”)

tion indirectly addressed the country’s economic problems Despite these problems, the industry achieved a positive

by providing Argentina’s treasury with a financial growth rate. For example, between 1985 and 1991, net

cushion while the fiscal reforms worked through the production of electricity increased 19 percent, averaging 3

economy. Privatizations also were a solution for a slightly more than 3 percent annually. However, since 4

number of other problems (such as the absence of com- privatization began in 1992, the growth rate of electricity

petition to spur the reduction of production costs) that production has doubled. Between 1992 and 1995, net

tend to drain the national treasury, and that often are production of electricity in Argentina has increased 22

attributed to publicly-operated companies as opposed to percent, averaging slightly less than 7 percent annually.

similar privately-operated companies. Finally, as in the Argentina’s electric industry problems included recurring 5

Australian state of Victoria and the United Kingdom (UK), power outages, substantial and regular unavailability of

a surge in foreign investment accompanied electricity power generators, and rampant theft of electricity. Given

privatization in Argentina. these problems and Argentina’s economy-wide problems,

A Historical Perspective for 

Argentine Privatization Efforts

The Argentine privatization that began in 1992 was the by Chile. Argentina began privatization of its electricity

most recent of a series of privatizations. As early as the industry more than ten years after Chile privatized its

6

7

power generation (Table 19). Electricity was also expen8

the dramatic increase in electricity production that has

accompanied privatization demonstrates the extent of its

effectiveness.

Argentina’s privatization was modeled after Chile’s with

modifications introduced to correct problems encountered
64 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Table 19. Net Production of Argentine Electricity by Independent and Public Producers, 1985-1995

(Million Kilowatt Hours)

Year Thermal Generation Hydro Generation Nuclear Generation Total Generation

1985 . . . . . . . . . . . . . . 17,719 20,434 5,434 43,587

1986 . . . . . . . . . . . . . . 20,922 20,796 5,383 47,101

1987 . . . . . . . . . . . . . . 22,364 21,810 6,141 50,315

1988 . . . . . . . . . . . . . . 29,585 15,633 4,845 50,063

1989 . . . . . . . . . . . . . . 30,522 13,195 4,787 48,504

1990 . . . . . . . . . . . . . . 23,963 17,952 7,030 48,945

1991 . . . . . . . . . . . . . . 28,055 16,267 7,695 52,017

1992 . . . . . . . . . . . . . . 27,844 19,375 6,745 53,964

1993 . . . . . . . . . . . . . . 28,794 23,907 7,315 60,016

1994 . . . . . . . . . . . . . . 28,685 27,116 7,823 63,624

1995 . . . . . . . . . . . . . . 28,650 30,000 7,070 65,720

 Sources: 1990-1995: World Energy Database, http://www.eia.doe.gov/emeu/world/ contents.html; 1985-1989: International

Energy Database, International Statistics Branch, Energy Markets and Contingency Information Division, Office of Energy Markets

and End Use, Energy Information Administration, May 1997.

Historical Overview of Latin American Electricity

Until the post-World War II period, most electricity in the Latin American countries was provided by private firms. This also was the

case in Argentina. However, due to widespread confiscatory government policies, Latin American capital markets of the post-War

period remained undeveloped. 

In the 1950's and 1960’s, in an attempt to better provide capital, most Latin American countries began to nationalize their key

industries. The Argentine electricity industry was one of the industries nationalized. As the nationalism movement swept Latin

America, foreign ownership and participation in energy industries became politically difficult. a

Nonetheless, the investment necessary for power generation in Latin America was substantial. The region experienced

considerable economic growth in the 1960's and the 1970's. For example gross domestic product, adjusted for inflation, expanded

at a 6-percent annual rate over the period (per capita growth was 4 percent). Concurrently, total electricity consumption grew about

20 percent during the 1970's (per capita electricity consumption grew more than 7 percent).b

Latin American electrification was fueled by this growth. At the outset of the 1950's, approximately 30 percent of Latin America had

access to electricity. By the end of the 1970's 70 percent of the region had access to electricity. The general opinion of the time

was that “only the state had both the resources and borrowing power to finance the public utilities industry.”c

However, by the 1980's, Latin America faced a major debt crisis. Substantially reduced economic growth caused by falling oil prices

and reduced government spending contributed to the crisis. In addition, the Latin American electricity infrastructure had become

antiquated. A general record of poor maintenance and operational inefficiencies complicated the problem. 

As in the 1950's and 1960’s, Latin American governments once again sought ways to improve their access to capital. For many

countries, especially Argentina, this desire became one of the driving forces in the resulting industry privatizations of the 1990's.

As a result, the Latin American electricity industry now has become a prime target of privatization and reform efforts.

______________________

 Although five private electricity companies survived the period of nationalization that swept Latin America, none of these a

companies were in Argentina, whose electricity industry became publicly-owned. The companies were in Venezuela (owned by

Venezuelan investors), Bolivia (owned by Canadian investors), Ecuador (owned by one U.S. investor), Barbados (owned by

investors of Barbados, Canada and the United States), and El Salvador (owned by U.S. investors).

 Everett J. Santos, “The Push to Privatize: Developing Essential Infrastructure in Latin America,” Latin Finance, Number 44 b

(January 1993), p. PR4.

 Santos, p. PR4. c
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 65

industry. The features of Chile’s privatized electricity companies, including the Buenos Aires electricity comindustry that Argentina adopted included open access to pany. Although parliamentary approval of privatization

the wholesale electricity market guaranteed by law sales to domestic companies and/or foreign companies

despite widely dispersed generation plants, and dispatch was assured by the Reform Law, further laws to govern

of electricity based on the production costs of the available the restructuring and privatization of Argentina’s difgenerators, with the lowest-cost generation dispatched ferent industries were necessary.

first. However, Argentina, unlike Chile, required complete separation of transmission from generation and Although the 1989 laws allowed foreign companies to

distribution. Other willful differences in the privatizated invest in Argentina’s privatizing industries, U.S. comindustries of the two countries include Argentina’s panies were given a further incentive to invest by a 1992

restriction that no single generator provide more than ten trade treaty. The 1992 Bilateral Investment Treaty accorpercent of national generation capacity. ded U.S. companies the privilege of investing in 9

In 1991, just prior to the beginning of privatization, those accorded domestic investors. 

Argentina’s electricity industry included four federal

utilities, one Argentina-Paraguay agency (controlling a Also during 1992, an electricity privatization law was 10

large hydroelectric plant owned jointly by the two passed. Public Law 24,065 (Electric Law), enacted in

countries), one Argentina-Uruguay agency (also control- January 1992, established a legal structure for restructurling a large hydroelectric plant owned jointly by the two ing and privatizing the electricity industry. The federal

countries), 19 provincial utilities, and several electricity government intended for the Electric Law to reduce

cooperatives. One of the four federal utilities generated electricity rates and improve service. The restructuring

and distributed electricity to the greater Buenos Aires and that preceded privatization was designed to lead to

La Plata area, one served the balance of the country’s competition between the soon-to-be-privatized electricity

needs for power generation and transmission, one companies and was modeled after earlier restructuring 11

oversaw the hydroelectric power generators of southern by Chile and the price-cap regulation of the United

Argentina, and one oversaw nuclear power generation Kingdom. 12

plants. At the time of privatization, the non-nuclear 13

utilities accounted for about 80 percent of the approxi- Two further legal changes occurred during 1993. A 1993

mately 15,000-megawatt generation capacity of the amendment to the Foreign Investment Law more

system. Since 1992, at least some part of each of the first explicitly addressed the question of foreign investment.

three former federally-owned utilities (the power genera- This amendment removed restrictions that applied only to

tion branch of the national atomic energy agency is the foreign investors, freeing them of the need to receive prior

lone exception) has been privatized. approval for most investment. Later in 1993, the measures 14

Changes in Legislation and

 International Agreements

Several legal changes preceded the most recent round of and to freely repatriate the profits and capital to their

privatization, which began with the passage of two 1989 home country. The passage of these laws, amendments,

laws. The first, the Economic Emergency Law, prohibited and treaties restructured Argentina’s legal system to

the Argentine central bank from financing government facilitate the sale of government-owned companies and

deficits and suspended all state subsidies and many assets, including those comprising the electricity industry.

incentive programs to mining and manufacturing

companies.15

The second 1989 law was the Administrative Reform Law

(Reform Law). The Reform Law, enacted in September 16

1989, defined the ground rules for investment in formerly

federally-owned companies. The ground rules implicitly The most recent round of privatizations by Argentina was

allowed foreign investment by not expressly prohibiting conducted with guidance from the World Bank.

it. Additionally, the Reform Law gave the Argentina Although the World Bank was not directly involved in 17

federal government authority to privatize federal each individual privatization, Argentina largely adopted

18

19

Argentina’s private sector at terms at least as favorable as 20

21

22

23

of the 1989 Economic Emergency Law, the 1989 Reform

Law, and the 1993 amendment to the Foreign Investment

Law were combined in an act called Decree 1853, which

removed most of the remaining restrictions on foreign

investment. Decree 1853, with few exceptions, allows

foreigners to own 100 percent of Argentine companies,

24

The Industry Restructuring and 

Privatization Plan

25
66 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

the Bank’s recommendations in restructuring and priva- retaining no ownership and only 2 percent retained for

tizing its industries. the generator’s employees. 26

Prior to the Initial Sale

After the passage of industry-specific privatization laws,

the companies to be privatized were restructured so that

a competitive industry with multiple companies could be

created. Regulatory bodies for the newly-privatized

industries also were established. Technical specialists

defined and structured the assets into viable, independent

business units. Legal advisors created charters for new

corporations spun off from the privatized entity and prepared bidding documents, contract terms, and conditions

consistent with sale objectives and with the govern- 27

ment’s intent regarding privatization of the sector.28

Financial advisors determined necessary investment and

price levels for the viability of the privatized entities.

Advisors were paid expenses, an agreed-upon fee, and a

bonus linked to the price the government received for the

privatization(s) on which they worked.29

The Initial Sale

Privatized companies were sold through auction. The auction method used is known as the “two-envelope”

process. Firms and consortia were prequalified for an 30

intentionally short list of bidders. Those selected as

bidders submitted a two-part bid. The first part of the bid

was the technical offer, which had to conform with the

requirements established by the bidding documents.

Firms not meeting the technical requirements were eliminated. The second part of the remaining companies’

bids, which contained the financial offers for the assets,

were then examined. Winners either offered the highest

price for the concession offered or agreed to provide the

minimum level of service at the lowest price.

After the Initial Sale

The initial auction usually resulted in privatization of at

least a bare majority (51 percent) of the company. During

early privatizations of federal electricity assets, the

Argentine government retained no more than 39 percent

and set aside at least 10 percent for company employees.

However, as much as 90 percent of formerly governmentowned companies was sold, with the employees receiving

10 percent of the company and the federal government

retaining no ownership. At least one 1995 sale resulted 31

in the privatization of 98 percent of a relatively small (448

megawatts) hydroelectric company to an Argentine

aluminum manufacturer, with the federal government

32

The shares retained by the Argentine government during

the initial sale/privatization could be sold later. Depending on how successfully winners of the initial sale

operate the privatized company, the value of the government shares may change. However, sometimes the

average price hardly changed. For example, in the case of

the privatization of the southern distribution company of

greater Buenos Aires, $511 million was paid for a

51-percent share in 1992 by a consortium. The federal 33

government’s 39-percent share retained after the initial

sale was sold in December 1995 for $390 million, essen- 34

tially the same per-share price as in the 1992 sale.

The Creation of a

Competitive Industry

Privatized Federal Enterprises

Argentina first restructured the federal electricity companies, and the electricity industry in general, and then

privatized them. The restructuring began in 1992 with the

creation of a national regulatory body, Enre, for the 35

soon-to-be privatized Argentine electricity industry. Also

during 1992 a national electricity wholesale market was 36

organized and the privatization of companies began,

within the new rules established by the various treaties

and privatization laws discussed earlier. The first three of

the federally-owned electricity companies that were

privatized produced a total of about 80 percent of the

nation’s supply of electricity. The companies were 37

Segba, Ayee, and Hidronor.

Segba. The first of the federal companies privatized was

Segba, which served the greater Buenos Aires area,

including the city of La Plata. (Buenos Aires accounts for 38

one-third of Argentina’s total population.) Before Segba

was privatized it was restructured by separating it vertically, and, to a lesser extent, horizontally. First, power

generation was separated from transmission and distribution. Then, the constituent power generation facilities

were separated from one another resulting in six separate

companies (Figure 14).

Power transmission and distribution also were separated.

The transmission assets were combined with those of

Ayee and Hidronor to create a single high-voltage transmission company and six regional transmission

companies (Figure 15). The distribution assets of Segba

were separated into three companies, one each serving

northern Buenos Aires, southern Buenos Aires, and La

Plata (Figure 16).
Segba

Servicios Electricos

del Gran Buenos Aires

Ayee Hidronor

Agua y Energia Electrica Hidroelectrica 

Norpatagonica, S.A.

6 Thermal Power 

Generation Enterprises

(Aqua del Cajon; Central 

Costanera; Central Dock Sud; 

Central Pedro de Mendoza; 

Central Puerto S.A.; and 

Central Termoelectrica Buenos Aires)

22 Thermal Power 

Generation Enterprises

5 Hydroelectric 

Generation Enterprises

(Agua del Toro; Cabra Corral; 

Central Alto Valle; Central Guemes; 

Central Sorrento; Central San 

Nicolas; Centrales Termicas del 

Noreste Argentino; Central Termicas 

Patagonicas, S.A; el Cadillal; el 

Tigre; Escaba, Fataluefu; Florentino 

Ameghino; Los Reyunos Pueblo 

Viejo; Rio Grande; Rio Reyes; 

Sociedad del Estado; Ullum.)

(Hidroelectrica Alicura, S.A.; 

Hidroelectrica Cerros 

Colorados, S.A.; Hidroelectrica 

el Chocon; Hidroelectrica 

Piedra del Aquila; and Pichi 

Picun Leufu.)

4 Hydroelectric Generation 

Enterprises

(Hidroelectrica Ameghino; 

Hidroelectrica Arroyito; 

Hidroelectrica Diamante; and 

Hidroelectrica Los Nihuiles.)

Before Restructuring After Restructuring

Segba

Servicios Electricos

del Gran Buenos Aires

Ayee Hidronor

Agua y Energia 

Electrica

Hidroelectrica 

Norpatagonica, S.A.

Before Restructuring After Restructuring

1 High-voltage Transmission Company

Transener (Compania de Transporte de Energia en Alta Tension Red)

6 Regional Lower-voltage Transmission Companies

Distro Cuyo

Transnoa (Empressa de Transporte de Energia Electrica por Distribucion Troncal 

 del Noroeste Argentino, S.A.)

Transpa (Transportadora Patagonica)

Transnea (Empressa de Transporte de Energia Electrica por Distribucion Troncal 

 del Noroeste Argentino, S.A.)

Transener (Compania de Transporte de Energia en Alta Tension Red)

Transcomahue (Transportadora Comahue)

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 67

Figure 14. Argentine Federal Electricity Restructuring of Conventional Power Generation

Figure 15. Argentine Federal Electricity Restructuring of Power Transmission
Segba

Servicios Electricos

del Gran Buenos Aires

Before Restructuring After Restructuring

3 Distribution 

Companies

[Buenos Aires: Edenor 

(Empresa Distribudora 

Electrica Norte) and Edesure 

(Empresa Distribudora 

Electrica Sur); La Plata: 

Edelap (distribudora 

electrica de la Plata)

68 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Figure 16. Argentine Electricity Restructuring of

Power Distribution

Privatization of Segba’s components began during 1992.

The first sales were Segba’s power generators. Of these,

the first sold was Central Puerto in April 1992. Central

Costanera and Central Alto Valle were next, in May and

August 1992, respectively. Next to be sold were the

distribution companies formed from Segba. The two

distribution companies serving northern and southern

greater Buenos Aires were sold in September 1992.39

Subsequently, the remaining three power generation companies, the remaining distribution company, and the

high-voltage transmission company, Transener, were

privatized.

One interesting aside concerning the privatization of

Transener, the high-voltage transmission company, is that

National Grid Group, PLC was one of the members of a

consortium that purchased a 95-year concession for 65

percent of Transener. National Grid Group, PLC 40

operates the transmission grid in the United Kingdom.

Ayee. The second of the federal electricity companies

privatized had generation and transmission assets nationwide (i.e., everywhere but the Buenos Aires/La Plata

metropolitan area). Because of the large area for which 41

Ayee was responsible, its restructuring resulted in many

more individual companies than the restructuring of

Segba, but affected substantially fewer electricity

customers in total.

The restructuring of Ayee also separated the stages of

power generation and transmission, and divided the

generation facilities from one another. A total of 12

generation companies were created from the former federal utility (Figure 14). As previously mentioned, the

transmission assets of Ayee were combined with those of

Segba and Hidronor, creating a total of six transmission

companies (Figure 15).42

As with Segba, the first assets of Ayee privatized were

power generators. The first privatized was the thermal

generator Central Termica Guemes in September 1992.43

Subsequently, nine additional thermal generators and two

hydroelectric generators were privatized.

Hidronor. The final privatization of the federal electricity

companies involved Hidronor, which oversaw several

hydroelectric power generation in southern Argentina.44

Hidronor’s primary assets were its four hydroelectric

power facilities, each of which was restructured into a

separate company and then privatized (Figure 14). Again,

the transmission assets of Hidronor were combined with

those of Segba and Ayee (Figure 15).

The first privatized was Central Hidroelectrica Alicura,

S.A. in August 1993. Also privatized in August 1993 were

Cerros Colorados and Chocon. By December 1993, the

fourth and final generation company, del Aguila, was

privatized.

Nuclear, Binational, and Provincial

Enterprises

Although still not privatized, nuclear electricity assets

were restructured in July 1994. The federal government

separated the functions of the original nuclear agency into

three distinct entities (Figure 17). The first is a company

that the Argentine government wishes to privatize. It includes two operational nuclear generation plants, along

with one plant still under construction. The second is the

nuclear regulatory agency, which will continue to be

government-owned and will regulate the individual

nuclear powerplants after the plants are privatized. The

third is the Argentine federal nuclear research organization, which retained the name of the original nuclear

agency and will remain government-owned.

Also still unprivatized are Argentina’s two binational

hydroelectric generation facilities. One is jointly owned

with Uruguay (Salto Grande), and the other is jointly

owned with Paraguay and is still under construction

(Yacyreta).

Following the onset of privatization of federally-owned

electricity companies, restructuring of the provincial

electricity companies began. Nearly all distribution assets

outside Segba’s service area (Buenos Aires and La Plata)

belong to these companies. However as of early 1997,
Before Restructuring After Restructuring

(Comision Nacional 

de Energia Atomica)

Conea

1 Nuclear Research 

Enterprize: Conea

1 Nuclear Regulatory 

Body: Enrn

1 Nuclear Power Generation 

Enterprise: Nucleoelectrico 

Argentina, S.A.

(Comision Nacional de 

Energia Atomica)

Nacional Nuclear Regulatory 

Authority

 Atucha I and Atucha II, and 

Embalse

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 69

Figure 17. Argentine Electricity Restructuring of the Federal Nuclear Agency

relatively few of the 19 provincial companies have been sortium of AES Corp and Community Energy Alternatives

privatized. The most prominent of the exceptions is (both U.S. companies) won the concessions for the

Eseba, the electricity company of the Buenos Aires northern and southern areas of the province, paying $565

province, which has been partially privatized. million. Apparently, there was little concern with pos- 45

As with the federal electric companies, Eseba was separated both vertically and horizontally, and two generation

companies, one regional transmission company, and three

distribution companies were created. However, unlike

the federal privatizations, the first provincial companies

privatized were distribution companies, not power generators. In April 1997, 95-year concessions for 90 percent

of the ownership of each of the three distribution companies were awarded. Since then, privatization tem- 46 47

porarily ceased; bids for the two generation companies

were unexpectedly low and the governor of Buenos Aires

province was advised to delay privatization. At the

writing of this report (during the summer of 1997), it is

unclear as to whether the privatization of the transmission

company, planned for the summer of 1997, will proceed 48

as scheduled.

One apparently unprecedented event occurred during the

privatization of Eseba. Among the companies unsuccessfully attempting to buy the distribution companies of

Eseba were both of the privatized former-federal distribution companies of Buenos Aires (Edesur and Edenor) and

one of the privatized former-federal power generators,

Central Costanera. The Atlantic region concession was 49

awarded for $404 million to a consortium of United

Utilities International (a UK company, which is the parent

of the regional electric company Norweb), Camuzzi (an

Italian natural gas company), and Loma Negra

(Argentina’s largest cement manufacturer). A con- 50

51

sible problems arising from increasing the concentration

of Argentine power distribution, should Edesur or Edenor

have won any of the three provincial distribution concessions.

The Structure and Regulation of Industry

Segments

As implied by the foregoing discussion of the restructuring and privatization of Argentina’s electricity industry,

much has changed in the past five years. Therefore, it is

useful to provide an overview the current state of the

different sectors of Argentina’s electricity industry, beginning with a brief discussion of the federal regulatory

body, Enre.52

The regulatory structure of Argentina’s electricity industry was guided by earlier efforts by Chile and the United

Kingdom. The federal regulator of Argentine electricity

is Enre, which regulates all stages of the electricity

industry, but most extensively transmission and distribution. Enre mediates disputes between electricity companies and enforces federal laws, regulations, and terms

of concessions. Enre also establishes service standards 53

that distribution companies must meet and sets the

maximum price that transmission and distribution companies may charge for their services. (This type of

regulation is known as “price-cap regulation.” See the

section entitled “RPI-X: Price Caps Versus Rate of Return

Regulation” in Chapter 2). Enre oversees the operator of
70 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

the wholesale electricity market, Cammesa, and the gener- problematic. (See the boxes entitled “Privatization of

ation companies. However, the generation companies are Argentine Nuclear Generation: The Long Good- bye” and

not subjected to price-cap regulation. “Privatization of Binational Generation: Twice the Usual

The post-privatization Argentine electricity industry consists of conventional power generation, transmission, Even though still state-owned, the companies yet to be

distribution, and large users. Each of these is discussed in privatized effectively act as independent power produthe following sections. cers, selling the power they generate through the wholePower Generation. Conventional electricity (thermal and

hydroelectric) facilities were sold separately, essentially

making each privatized generation facility an independent power producer. The thermal generation facilities

were sold outright, while concessions (averaging 30 years)

were awarded for the hydroelectric plants. The majority 54

of Argentina’s privatized generation capacity was purchased by foreign companies. Because foreign companies

generally showed little interest in small capacity generation facilities, these privatized facilities tended to be

exclusively owned by domestic companies. Also, these

domestic companies tended not to purchase generation

facilities in order to sell electricity in the national

wholesale market. Rather, the generation facilities were

intended to be captive facilities, purchased to provide for

the companies’ own electricity needs. For example, two

Argentine companies, a paper manufacturer and a steel

producer, bought a 20-megawatt oil and gas-fired generating plant for $8.5 million.55

The post-privatization Argentine power generation indus- Wholesale Electricity Market. The wholesale electricity

try (including both conventional and non- conventional market (also known as a power pool) has both a supply

power facilities) is composed of independent, largely side and a demand side. The supply side of the wholesale

unregulated power generation companies. The com- electricity market is composed of independent power

panies are essentially unregulated because electric power producers, privatized generators, generators still owned

generation is considered a competitive market. The nearly by the federal government (including the two nuclear

40 generating companies operating in Argentina (Figure power plants), the two binational hydroelectric power

14) are assured by the national electricity regulatory body plants (also still not privatized), and foreign producers

(Enre) of having open and equal access to the national selling imported electricity. The demand side of the

grid and receive unregulated prices (Argentine elec- wholesale market is composed of distribution companies, 56

tricity prices are discussed below). Nonetheless, some large users, and foreign consumers purchasing exported

restrictions have been placed on power generators. In electricity. 

order to avoid market concentration difficulties, generation companies are legally restricted to a market share of The interaction of the supply and demand sides of the

10 percent or less of the national electricity sales volume. wholesale market largely determines wholesale prices for 57

They also are prohibited from owning majority shares in electricity. Additionally, a fixed charge is added to all of

electricity transmission facilities. the market-determined prices to cover payments made by 58

About ten power generators (including both conventional to the electricity grid. Three kinds of wholesale electricity

and non-conventional) are still owned by the federal or prices exist in the Argentine electricity industry:

provincial governments (in addition to those under con- contractual prices, seasonal prices, and spot prices. Of

struction or in the planning stage), either because efforts these, seasonal and spot prices are determined directly in

to privatize have not begun or because efforts are still the wholesale market, while contractual prices are

unsuccessful. Nuclear power plants and the binational affected indirectly by the wholesale market. (Prices are

hydroelectric power generation facilities have been more discussed in a separate section below.)

Number of Headaches” for discussions of each.)

sale electricity market. (Any power they generate is

always dispatched.) Additional power demand is met by

dispatching power from thermal power generators and

cogenerators, in reverse order of their marginal cost of

generation.

Generation companies receive income from providing

actual electricity and reserve capacity to the transmission

network. All generators whose power is dispatched by

Cammesa receive a price equal to the marginal cost of the

last generator whose power is dispatched. Generators

whose production costs are too high to be dispatched by

Cammesa receive a payment for providing the system

with reserve power. The payment is based on the power

they agree to provide, effectively creating a price floor for

generators. However, the reserve payment is sufficiently

low that generators have a dual incentive to reduce their

costs —foremost, to have their electricity dispatched and,

second, to increase the difference between electricity

production costs and revenues from sales. 

Cammesa to power generators providing reserve capacity
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 71

Privatization of Argentine Nuclear Power Generation: The Long Good Bye

Argentine Executive Order 1540/94 combined the two operating nuclear facilities (Atucha I and Embalse de rio Tercero) and the

under-construction (Atucha II) plant into a newly-created state-owned nuclear power company for the purpose of subsequently

privatizing all three plants. According to a former president of the nuclear agency, the basic reason that Argentina intends to a

privatize its nuclear generators is, “to finish Atucha II.”b

The major attraction of the Argentine nuclear plants is Embalse (648-megawatts capacity), which is in the province of Cordoba.

 Embalse was put into service 10 years later and produces electricity more efficiently than Atucha I. 

Privatizing the Argentine nuclear plants together instead of separately presents two major sets of problems from the standpoint

of potential buyers: the amount of new investment spending required of the winner of the concession and the amount of risk the

winner of the concession must undertake.

Most new investment spending will be for Atucha I and II. Atucha II (750 megawatt capacity), which began in 1981, is 88-percent

complete after $2 billion of spending. Completion and activation is expected to require an additional $700 million. d

The extensive repairs and upgrades to Atucha I (335 megawatt capacity) are another requirement for new investment spending.

Atucha I was put into service in 1974 and around $140 million is needed to make the necessary upgrade and repairs. Complicating

this situation is the unusual design of the plant. Atucha I was designed by Siemens of Germany to meet Argentina’s requirements

for a heavy-water plant fueled by natural uranium, instead of the more commonly used enriched uranium fuel. The natural uranium

technology is little known outside Argentina.e

Allocating the risks associated with the operation and decommissioning of the nuclear plants may present a greater problem for

potential bidders than the required investment spending. Potential bidders for the plants are unwilling to accept open-ended risk.

However, it will be politically difficult for the Argentine government to provide substantial risk guarantees.e

The currently proposed legislation to privatize Argentina’s nuclear electricity requires the private operator to purchase sufficient

insurance to pay up to $80 million for nuclear accidents, with Argentina paying all additional costs. The operator would make

payments to a fund to cover anticipated future decommissioning costs. Additional decommissioning costs from technological or

legislative changes would be paid by the state.f

Little movement toward privatization has occurred since June 1996, when agreement was reached with regional representatives

concerning nuclear waste disposal. The government also agreed to retain at least one share in excess of 20-percent ownership

of the plants.g

 

“Nuclear Privatization Progresses in Argentina,” Nuclear News (July 1996), p. 38. a

David Pilling, “The Americas: Argentina Plans Nuclear Industry Sell-off,” Financial Times (July 5, 1996), p. 5. b

“World Bank issues a warning; It May Not Be a Good Idea to Sell off Customs Service,” Latin America Regional Reports: c

Southern Cone (April 15, 1997), p. 6.

Atucha I was built to Argentina’s specification because of international concerns regarding the expansion of nuclear d

technology, because of weapons implications, and because using natural uranium saved Argentina the costs of enriching their

uranium. See David Pilling, “The Americas: Argentina Plans Nuclear Industry Sell-off,” Financial Times (July 5, 1996), p. 5. 

“Argentina Privatization Legislation Being Prepared,” Latin American Law and Business Report, Volume 3, Number 10 e

(October 31, 1995).

Mark Hibbs, “Siemens Restructures Nuclear Side Following Market Price Cuts,” Nucleonics Week, Volume 38, Number 3 f

(January 16, 1997), p. 1.

“Argentina Investment: Power Privatisations Run Into Opposition,” EIU ViewsWire (September 6, 1996). g

Use of the wholesale electricity market has increased the same period, particularly by large users, as total

substantially since its creation in 1992. For example, the participants increased from about 50 (between February

number of exchanges taking place in the market has and April 1994) to more than 500 (between November

increased from approximately 20 (between February and 1995 and January 1996).

April 1994) to around 450 (between November 1995 and

January 1996). The number of participants in the The wholesale market is administered by Cammesa, a 59

wholesale market has demonstrated similar growth over nonprofit, independent operating agency jointly owned

60
72 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Privatization of Binational Generation: Twice the Usual Number of Headaches

Although Argentina still intends to privatize its nuclear power generation assets, it appears that, at least temporarily, the federal

government has abandoned its attempts to privatize its share of each of two huge binational hydroelectric facilities. The two

facilities are Salto Grande and Yacyreta. The former is a joint venture between Argentina and Uruguay, while the latter is a joint

venture between Argentina and Paraguay.

Salto Grande is the older plant, having become fully operational in 1979, with a capacity of about 1,800 megawatts. The facility

is situated on the Uruguay River, which separates northeastern Argentina from Uruguay. Almost 40 years after Uruguay and

Argentina agreed in principle to build the plant, it finally became fully operational. Thus, given the beginnings of Salto Grande, it

is not surprising that the two countries are experiencing difficulties in reaching an agreement concerning the privatization of the

facility.

Yacyreta is substantially newer than Salto Grande. Construction on the Yacyreta facility began 20 years before the first of its 20 a

turbines was brought on-line in September 1994. Less than a year later an additional four turbines were operational. b

Despite the differences in the two facilities, many of the same problems must be overcome in order to privatize either. For example,

before either facility can be privatized, the Argentine Congress must approve the privatization of Argentina’s share of the joint

venture. Additionally, the approval of the congress of the venture partner must be received before the entire facility can be

privatized. Argentine Congressional approval of the sale of the binational plants has been withheld at least partially because the c

proposed 30-year contracts appear too long and allow the concessionaire too much freedom to export the power generated.

Potential bidders for the concession for Salto Grande or Yacyreta (if the process proceeds) may have second thoughts about

dealing with two sets of governments. d

Despite the problems, foreign investment in the binational hydroelectric projects eventually may occur. As recently as January

1996, Ontario Hydro International (a Canadian company) and AES Energy (a U.S. company) met with Argentine government

officials about Yacyreta. Argentine officials also met with other private developers around the same time. However, although e

foreign interest in the binational projects appears to exist, occasional disparaging public comments (such as Argentina’s President

Menem characterizing Yacyreta as “a monument to corruption,” ) do not make the outlook bright. f

 

“Argentine Government Reveals Large Hydro Plant Plan by U.S. Consortium,” Independent Power Report (April 19, 1996), a

p. 12.

Uriel Federico O'Farrell, “Energy Sector Legal Update,” Latin American Law and Business Report, Volume 3; Number 9 b

(September 30, 1995).

Salto Grande has an additional complication in this regard. Because the facility provides much electricity to the nearby c

Argentine province of Salto Grande, the approval of the province appears necessary to the successful privatization of Argentina’s

of the facility. See“Argentina Investment: Power, Energy Companies Readied For Sale,” EIU ViewsWire (April 9, 1996).

“Argentine Government Reveals Large Hydro Plant Plan by U.S. Consortium,” Independent Power Report (April 19, 1996), d

p. 12.

“AES, Ontario Hydro Unit in Talks to Buy 2,700-megawatt Argentine Plant,” Independent Power Report (January 12, 1996), e

p. 13.

The president’s comments appear warranted, given the 20 years and $8 billion expended during construction, with an f

estimated $4 billion to complete the plant. See “Argentine Government Reveals Large Hydro Plant Plan by U.S. Consortium,”

Independent Power Report (April 19, 1996), p. 12.

wholesale by the government and the power generation charges and other fixed fees added to spot, seasonal, and

companies. Cammesa is directed by a board composed of contractual prices to cover the full costs of transmission;

two representatives from each of the following: Argen- and ensuring that the power system maintains adequate

tina’s federal government, power generators, transmission reserve capacity.

companies, distribution companies, and large users. The

board of directors makes decisions based on simple Power is dispatched to the national electricity grid by

majority rule. (However, the president of the board of Cammesa. Cammesa determines the cost of generation

directors is the Secretary of Energy, who has veto power for each producer and then dispatches electricity to the

over board decisions and apparently can be overridden transmission grid (discussed in the following section),

only by the President of Argentina.) Cammesa has three sending the cheapest power first until current demand has

primary tasks: dispatching power; determining the fixed been satisfied. The price that is paid to each generator 61
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 73

is determined largely by the highest cost producer whose struct, operate, and maintain transmission lines and transpower is dispatched . (This arrangement is similar to the former stations associated with the binational Yacyreta 62

marginal cost pricing systems employed in the United hydroelectric plant. Construction of two additional

Kingdom and Australia, discussed in Chapters 2 and 3 of transmission lines is under consideration and bids have

this report.) Revenues to fund Cammesa’s operations may been solicited. One will connect Salto to the Chilean

be no more than 3.5 percent of the gross revenues border and the other will add a fourth transmission line

generated by the wholesale electricity market. from Patagonia to Buenos Aires.

Power Transmission. Although the wholesale market Power Distribution. The final stage through which elecallows buyers and sellers of electricity to interact and tricity passes between creation and use is the distribution

determine prices, it is the transmission network of stage. In Argentina electricity distribution is defined as a

Argentina that physically links the buyers and sellers of natural monopoly within the geographic area for which a

electricity to one another, delivering power to distribution concession is awarded. Firms may enter distribution only

companies and to large industrial users. The transmission after successfully bidding for a concession. Distribution

network has two parts, one high-voltage (500 kilovolts) concessions are 95 years in length. As with transmission

transmission system, and six lower-voltage (220 kilovolts) companies, distribution companies have regulated maxiregional transmission systems. mum rates that they may charge for their services and

As in the United Kingdom and Australia, electricity third parties. 

transmission has been defined by Enre (the national

electricity regulator) as a natural monopoly and is closely Distribution companies provide power to their end users

regulated. Firms may enter the industry only after at rates that are capped by regulators (similar to prosuccessfully bidding for a fixed-duration concession for a visions in the United Kingdom and Australia, discussed in

particular area and may charge no more than regulated the section entitled “RPI-X: Price Caps Versus Rate-ofprices for their services. Concessionaires are required to Return Regulation” in Chapter 2). Incentives to reduce

allow open access to their transmission network to third operating costs are provided by price-cap regulation, and

parties. the benefits of cost reductions are received by the regTransmission companies are not allowed to buy or sell eventually save from lower operating costs because the

electricity. Instead, their revenues come exclusively from cap is reset every five to eight years.

the regulated prices they receive. The price is based on

the availability (providing a fixed source of income) and Distribution assets formerly owned by federal electric

the use (providing a variable source of income) of their utility companies generally were privatized or transferred

network assets. The rate at which they are paid is to the provinces, which have begun to privatize the 63

capped by the federal electricity regulatory body, pro- distribution operations. Several distribution companies

viding an incentive for Argentine transmission companies were created by the restructuring. The two largest, which

to reduce their costs. (Price-cap regulation also is serve greater Buenos Aires, were the first privatized. 64

employed in the United Kingdom and Australia.)

The lower-voltage, regional transmission systems transmit

power to and from the high-voltage transmission system.

Transener owns and operates the high-voltage segment 65

of the Argentine transmission network (in addition to one

of the lower-voltage, regional systems). Transener serves

a total 14 of Argentina’s 24 provinces, possibly carrying 90

percent of Argentina’s transmitted power. Thus, 66

Transener is considered the primary electricity transmission company in Argentina. 

Among the six transmission companies, more than half

have been at least partially privatized. The privatized

companies are Distro Cuyo, Transnea, Transener, and

Transpa. The creation of a seventh private regional com- 67

pany was approved by the Argentine national electricity

regulatory body during 1996. The company will con68

69

70

71

must allow open access to their distribution network to 72

ulated company and its stockholders. Customers, too,

73

74

Large Users. Large users (who consume at least 2

megawatt hours of electricity annually) may choose to be

supplied by the distribution company serving their area

or purchase electricity directly from a generation company. Large users are in one of two categories: major,

which consume at least 4,380 megawatt hours of electricity annually, and minor, which consume less than

4,380 megawatt hours annually.

Large users choosing to be supplied directly by a generation company pay a contracted price determined

through bilateral negotiation with a generation company.

Large users who instead choose to be supplied by a distribution company pay the same rate charged any other

customer of the distribution company. Large users additionally are permitted to buy power directly from the

wholesale electricity market, paying the spot price. The 75
74 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

number of large users active in the wholesale electricity

market has increased from about 5 in 1993 (none during

1992) to more than 200 in early 1996.76

Electricity Prices 

Contractual Prices. Contractual prices are negotiated

between generation companies and distribution companies, or between generation companies and large users.

The length of the contracts is typically one year. These

prices are largely unregulated. Hydroelectric generators

may contract only up to 70 percent of their anticipated

monthly production. (Note that weather conditions and

other factors may dramatically affect water levels and,

therefore, the generation capacity of hydroelectric generators.) Similarly, thermal generators may not contract

for more delivered electricity than their net generation

capacity (some electricity use occurs at the generation

facility).77

Seasonal Prices. Seasonal prices are determined by

Cammesa in the seasonal component of the wholesale

electricity market and officially maintained for 6-month

periods, beginning May 1 and November 1 of each year.

The seasons are based on water level and generally 78

correspond to winter/spring and summer/fall, respectively. Every 3 months Cammesa receives updates to the

information it uses to determine seasonal prices and may

then revise the current seasonal price. Thus, seasonal 79

prices are effectively 3-month prices.

Cammesa sets seasonal prices by using information

provided by distribution, transmission, and generation

companies. The information includes demand forecasts

for typical days, unavailable reactive power, and weekly

load curves from distribution companies; availability,

restrictions, reactive power equipment unavailable, and

net equipment information from transmission companies;

capacity, efficiency, planned maintenance, internal

electricity consumption, and availability from all generation companies; fuel use and prices from thermal

generation companies; and historical and predicted water

flows and other characteristics of the reservoirs from

hydroelectric generation companies. 80

The seasonal price is paid by distribution companies

purchasing power in excess of the amount they had

contracted to purchase from power generators. Seasonal

prices during the winter/spring presume that hydroelectric generators are the primary source of power and

have lower seasonal prices than the summer/fall period.

Alternatively, seasonal prices during the summer/fall

presume that thermal generators are the largest source of

power and have relatively higher prices.81

Spot Prices. Spot prices are determined by the interaction of buyers and sellers in the spot component of the

wholesale electricity market. Spot prices vary hourly.82

The buyers who pay the spot price include generators and

large users. Generators buy electricity they contractually

agreed to provide in excess of actual generation. Additionally, large users who contracted for too little power to

cover their current need may purchase additional electricity in the wholesale market, paying the spot price. 

Sellers receive the spot price and may include distribution

companies, generators, and large users. Distribution companies contracting for more electricity than actually

purchased by their customers may sell their excess electricity in the spot market. Similarly, generators may sell

electricity produced beyond their contractual obligations

(to either distribution companies or large users) in the spot

market. Large users, too, may sell any electricity they

have contracted to buy that exceeds their current use,

receiving the spot price. 

Spot prices received are adjusted through application of

fixed charges. These charges are assessed by Cammesa

and are to cover the costs of ensuring some minimum

level of reserve capacity and coverage of transmission and

other losses. 

Reserve capacity provided by thermal generators is based

on the level of undispatched, but available, capacity they

provide. Hydroelectric generators are paid on the basis of

the amount of power generated. Reserve capacity is

assigned on the basis of least-cost generation.

Transmission loss charges are based on the physical

distance of the electricity seller from Buenos Aires. The

greater the distance, the more the price received is discounted to cover transmission losses.83

As of May 1996, the base price paid for electricity dispatched by Cammesa was $5 per megawatt hour and the

fee paid for reserve capacity also was $5 per megawatt

hour, summing to $10 per megawatt hour.84

Electricity Sector Effects

Argentina created a wholesale market for bulk electricity

sales in which prices are based largely on the interaction

of the two sides of the market, sellers and buyers. The

wholesale market is overseen by Cammesa, while Enre,

the federal electricity regulatory agency, oversees the

electricity industry as a whole. Enre established regulations mandating services that distribution companies

must provide to end users and instituted price-cap

regulation of transmission and distribution. Price-cap

regulation is not applied to generation. The Argentine
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 75

federal government continues to engage in power plan- Buenos Aires, typically was available before privatization.

ning, granting concessions, and setting overall electricity By 1994, availability was increased to 75 percent.

policies. Since privatization, many noticeable changes Similarly, the electric distribution company serving the

have marked the Argentine electricity industry. The city of La Plata increased its customer base from 228,000

changes include lower prices, increased reliability, lower to 270,000 customers between 1992 and 1995, even while

employment, higher productivity, and increased foreign company employment fell.

investment.

Lower Prices and Increased Reliability. Following

privatization, Argentine wholesale electricity prices fell

about 60 percent from the pre-privatization level of $60

per megawatt hour in August 1992. As of 1997, 85

Argentina’s wholesale power rates stabilized at about 40

percent below the pre-privatization level. However, this

occurred only after a period of adjustment, during which

wholesale rates fell almost to zero. 86

Increased reliability of electricity service has been substantial in some cases. For example, the northern Buenos

Aires distribution company reduced outages from 22

hours per year in 1992 to 6 hours per year in 1995.

Meanwhile, the southern Buenos Aires distribution company cut outages from 39 hours per year to 6 hours per

year over the same period.87

Reliability also has been increased through the introduction of improved technology. For example, following

privatization, incumbent generating plants were retrofitted with power system stabilizers. Once the stabilizers

were in place, a system to automatically disconnect generating capacity could be designed. Transmission faults

were then less likely to cause widespread outages because

the automatic system disconnects as little generating

capacity as possible, given the particular transmission

fault.88

Increased Productivity, Efficiency, and Investment.

Increased productivity did not occur overnight in

Argentina. Many newly-privatized companies struggled

to institute changes and make improvements. For example, the southern distribution company of greater Buenos

Aires, one of the first distribution companies privatized,

lost $150 million in the first 16 months after privatization.

A concerted effort to discover and eliminate illegal connections, through which much electricity was stolen from

the company, was eventually successful and the amount

of Argentine electricity stolen through illegal connections

was substantially reduced. This reduction at least partially accounts for an approximate profit of $60 million

during 1995. 89

As productivity at the generation stage was increased,

overall efficiency eventually was increased. For example,

30 percent of the capacity of Costanera, a generator near

90

Electricity service to Buenos Aires will be increased with

the construction of a new $250 million transmission line

from Patagonia to Buenos Aires. The transmission line

will be commissioned by a consortium of eight pri- 91

vatized electricity generation companies. The companies

are legally prohibited from holding a majority share in the

planned transmission line, but will fund the construction

and award the concession. The consortium also plans a

$25-million capacitor project, which is expected to substantially increase the electricity supply to the greater

Buenos Aires area from 2,700 megawatts to 4,600 over a

three-year period. The consortium members currently

produce 31 percent of Argentina's total electricity supply.92

With increased productivity, unemployment has become

a problem as individual electricity companies in Argentina (and Chile) have reduced their total employment by

as much as 40 percent since privatization. Further, rising 93

economy-wide unemployment prompted the 1994 signing

of an agreement between the Argentine federal

government, business organizations, and labor unions to

restrain unemployment. This agreement includes the

creation of training programs for displaced workers.94

Increasing foreign investment was one of the primary

reasons the Argentine government undertook the 1992

round of general privatization. The government has

indicated satisfaction with the level of foreign investment

since privatization began (Figure 18). For example, the

private owners of the northern distribution company of

greater Buenos Aires made capital investments of about

$380 million between September 1992 and 1995. Between

1995 and 2000 an additional total investment of $500 million is planned for northern Buenos Aires. Anticipated 95

economy-wide electricity investment between 1996 and

2001 is $7 billion, most of which is attributed to private

investors. The primary purpose of at least some of the 96

anticipated investment is to improve customer service.

Economy-wide Effects

Debt Reduction. Privatization has reduced Argentina’s

federal government debt in two ways. First, federal assets

were sold and the proceeds were used to retire debt.

Privatization resulted in payments to the Argentine

federal government of $10 billion. Second, the losses 97
1980 1985 1990 1994 1995

0

5

10

15

20

25

30

Billion Dollars

76 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Figure 18. Total U.S. Direct Foreign Investment in

Argentina, Selected Years

 Source: U.S. Department of Commerce, Survey of Current

Business, Various issues.

generated by many federal companies were eliminated by

selling the companies, thus ending the drain on the federal treasury as additional savings from reduced government subsidies to public companies were anticipated.98

There was a concern that some Argentine federal electricity companies might have drawn unacceptably low

bids. As a result, in order to ensure their sale, the

Argentine federal government agreed to retain some of

these companies’ liabilities and debt. (This type of partial

assumption of the debt of federal companies in order to

ensure their sale was applied to federal assets of many

Argentine industries, not just the electricity industry.) The

assumption of these debts (essentially, privatizationrelated expenses) necessarily contributed to Argentina’s

increase in publicly-guaranteed foreign debt (from $47.6

billion in 1991 to an estimated $62.2 billion in 1995 ) and 99

could lead to the conclusion that privatization worsened

Argentina’s external debt. However, in reality, Argentina’s external debt may have increased substantially

more in the absence of their assumption of this debt, due

to the anticipated continued losses and debts of the federal companies.

The anticipated long-term effect of privatizing former

federal companies in Argentina is reduced federal debt.

Between 1990 and 1994, Argentine government foreign

debt was reduced by $15 billion as a result of proceeds

from direct sale of federal assets. An additional $2.7 100

billion of debt was transferred (via privatization) by the

federal government to the new private owners of the

former-federal companies. Further, the ratio of debt 101

interest payments to exports has fallen from nearly 35

percent in 1991 to an estimate of slightly less than 17

percent in 1995.102

Privatization proceeds have been considerable. As a

result, the Argentine federal government has been able to

substantially reduce domestic borrowing. Other privatization funds are earmarked for the repurchase of government bonds, which also will reduce federal debt. 

Employment Reduction. Federal employment in Argentine industries selected for privatization was anticipated,

by the completion of privatization, to fall from a

pre-1990-level of 222,000 employees to less than 42,000

employees. About 66,000 of those losing their public jobs

were expected to be hired by the new private firms and

another 19,000 of these employees were expected to

retire. At the same time, slowed economic growth and 103

restructuring of the economy contributed to a soaring

Argentine unemployment rate. The unemployment rate

increased from 6.8 percent in 1991 to about 13.5 percent in

1995 and, through May 1997, was about 17 percent. 104 105, 106

However, as of 1993, opposition by organized labor to

such traumatic change was limited and was more than

offset by public approval and by increased opportunity in

the private sector.107

Few data are available concerning actual employment

changes in privatized companies resulting from Argentina’s massive privatization program. It is unclear how

closely actual employment changes in the electricity

industry have reflected anticipated reductions.

Improved Economic Environment. By almost every

measure, Argentina’s economy has improved since the

1992 privatization efforts began. One of the first signs of

the country’s improvement occurred in December 1992,

when it was allowed to enter into a credit-enhancing international debt agreement with the United States (generally

known as “Brady debt”). Inflation (measured by the 108

wholesale price index) fell from an annual rate of 1,607

percent in 1990 to 5.9 percent in 1994. Real investment 109

grew at an annual rate of approximately 20 percent

between 1991 and 1994. Economic growth (measured 110

by the change in real Gross Domestic Product) varied

between 5.8 and 8.7 percent between 1991 and 1994, fell 111

to about 1 percent during 1995, but rebounded (by May 112

1997) to reach a 1997 annualized rate of about 8 percent.113

The interaction of supply and demand for electricity will

determine the price in the newly-privatized environment.

Increased efficiency is expected to reduce costs and put

downward pressure on prices. However, real prices after

privatization may increase as elimination of the use of

government subsidies and ceilings that historically kept

prices low may raise some prices. Further, elimination of

previously existing cross-subsidies in which rural and

large industrial customers subsidized urban residential

customers may also lead to increases in some prices paid 114

for electricity.
Generation Facilities Transmission Facilities Distribution Facilities

Private

Provincial

Federal

Federal

Private Private

Federal

Provincial

Binational

Cumulative Percentage 100

80

60

40

20

0

Generation Transmission Distribution

Private Provincial Federal Binational

53

12

17

18

17

83

47

50

Cumulative Percentage

100

80

60

40

20

0

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 77

Figure 19. Ownership of Argentine Electricity

Assets, 1995

 Source: World Power Service, Latin American Report

(Eddystone, Pennsylvania: WEFA Group, November 1996)

Figure 20. Argentine Electricity Sales Volume

Market Shares, 1995

 Source: World Power Service, Latin American Report

(Eddystone, Pennsylvania: WEFA Group, November 1996).

Foreign investment in all Argentine industry has

increased, providing capital needed for the introduction 115

and application of new technologies. According to the

Inter-American Development Bank, net capital inflows to

Argentina increased each year between 1991 and 1994,

reaching almost $11 billion in 1994 (with the private sector

receiving almost $9 billion).116

Resulting Foreign Investment

According to recent information, the largest concentration

of private firms in Argentine electricity is in the area of

power generation, the first segment of Argentina’s electricity industry privatized (Figure 19). However, despite the

substantially larger number of privatizations in power

generation, electricity distribution based on sales is almost

as heavily controlled by private firms (Figure 20).

Nearly all the companies that are investing in Argentina’s

electricity industry are from the United States or Chile. 

The reduced risk associated with the political climate of

Argentina, the apparent dedication of the current government to its program of macroeconomic stability, and the

large growth rates forecast for Latin America (and for

Argentina, in particular) have attracted many companies

to participate in the privatization of Argentina’s electricity

industry. For example, when 90 percent of the Buenos

Aires provincial electricity company was privatized

during 1996, sixteen consortia made offers. (A listing of 117

foreign companies with current investments in Argentine

electricity is provided in Table 20. See Appendix Table C1

for more information.)

Private companies have invested in the privatization of

Argentina’s electricity industry for several reasons. First,

there are growth opportunities (the U.S. electricity

industry is forecast to grow two percent between 1994 and

2000, while Argentina’s electricity industry has been

forecast to expand at an average annual rate of 8 percent

for the same period). Second, U.S. companies may see 118

Argentina as a laboratory for learning how to operate in

a deregulated market and hope to transfer the knowledge

gained to the soon-to-be deregulated U.S. electricity

industry. Third, companies have invested in Argen- 119

tina’s privatized electricity industry in order to be

positioned to subsequently expand into investments in the

privatized electricity industries of other Latin American

countries. Fourth, some companies have developed 120

specialities in electricity operations (e.g., power generation) and see opportunities to apply those specialities in

Argentina. 121

However, some companies investing in Argentine

electricity have made mistakes. Companies have made

investments in properties that later were sold. There also

have been cases where, by substantially outbidding other

companies, buyers have in fact overpaid for properties.122

Some companies have reacted to mistakes by others by

exercising caution. Others have decided to refocus their 123

investments to a more narrow range of activities.

Many of the companies investing in Argentina’s privatized electricity industry are active in power generation

in their own country. For example, privatization in 124

Argentina has enabled several of Chile's electricity firms

to enter power generation in Argentina. 
78 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Table 20. Argentine Electricity Privatization-Related Acquisitions

Argentine Electricity Assets Acquiring Company (Nationality) Value

Power generation, and power distribution .............. AES Corporation (U.S.) $771.5 million*

Power generation ................................. Amoco Co. (U.S.) N. A.

Power generation, and power distribution .............. Camuzzi Gazometri (Italy) $8.6 million*

Power generation, and power distribution .............. Chilectra/Enersis (Chile) $119.6 million

Power generation ................................. Chilgener (Chile) $162.7 million

Power generation ................................. Chilquinta (Chile) $45.4 million

Power generation, and power distribution .............. Cinergy (U.S.) N. A.

Power distribution ................................. Citicorp Capital Investors (U.S.) $139 million**

Power generation ................................. CMS Energy (U.S.) $124.5 million*

Power distribution ................................. Community Energy Alternatives/Public $188 million

Service Enterprise Group

Power generation ................................. Consumers Energy Co. (U.S.) N. A.

Power generation ................................. Dominion Resources, Inc., (U.S.) $152.7 million

Power generation, and power transmission ............. Duke Power (U.S.) $147.1 million

Power generation, power transmission, ................ Electricite de France (France) $110.3 million

and power distribution El Paso Electric (U.S.) $157 million

Power generation, and power distribution .............. Endesa (Chile) $446.1 million*

Power transmission, and power distribution ............ Endesa (Spain) $42.8 million*

Power generation, and power distribution .............. Enersis (Chile) $703.5 million

Power generation, power transmission, ................

and power distribution

Entergy (U.S.) $85.1 million*

Power generation, power transmission, ................ Houston Industries (U.S.) $68.2 million

and power distribution

Power distribution ................................. Hydroelectrica, de Ribagorzana, S.A.

(Spain)

$85.6 million

Power generation ................................. Iberdrola (Spain) $17.3 million

Power generation ................................. Kansas City Power and Light/Western $23.4 million

Resources (U.S.)

Power generation ................................. LG&E Energy, Corp. (U.S.) $31.3 million

Power generation ................................. Louis Dreyfus Argener, S.A. (U.S.) $13.8 million

Power generation ................................. Merrill International, Ltd. (U.S.) $100 million**

Power generation ................................. National Electricity Co. of Chile (Chile) $600 million*

Power transmission ................................ National Grid, PLC (U.K.)

Power generation ................................. New World Power (U.S.) N.A.

Power generation ................................. Northeast Utilities (U.S.) $18 million*

Power generation, and power distribution .............. PSI Energy (U.S.) $131 million

Power generation ................................. Repsol (Spain) N.A.

Power distribution ................................. Sociedad Austral de Electricidad (Chile) $97.8 million**

Power distribution ................................. Societe D’Amenagment Urbain et Rural ) $42.8 million

(France)

Power generation ................................. Southern Co. (U.S.) $107.8 million

Power generation ................................. TransAlta Energy (Canada) $90.4 million

 Note: * indicates that the value is a lower boundary on the amount of total investment because the company’s contribution was

not disclosed for at least one consortium (of which it is a member) that invested in Argentine electricity. ** indicates that the value

is a lower boundary on the amount of total investment because the value of one (or more) of its investments was not disclosed.

 Sources: Annual reports to shareholders and various public news sources. 
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 79

A network of Latin American transcontinental gas pipe- Argentina’s electricity privatization has further spurred

lines (permitting the conversion of coal-fired to natural speculation that the natural gas network under construcgas-fired electricity plants) is well under way. Some of tion will be formally extended, creating a regional electrithe firms active in the expansion of the natural gas pipe- city/natural gas network. In fact, the chairman of one of

line network also are electricity companies. Examples these Chilean electricity firms, Chilgener, has publicly

include Chilgener and CMS Energy (a U.S. company). 125 126

(See the box entitled “Latin America's New Natural Gas

Pipeline Network” for a discussion of the relationship

between natural gas pipeline investment and electricity

investment in Latin America.)

The success of the network of gas pipelines may enhance

the probability of a Latin American electricity grid.

speculated that within ten years an interconnected grid

for the seven Southern Cone countries (Argentina, Bolivia,

Brazil, Chile, Paraguay, Peru, and Uruguay)—with a

single multinational regulator ensuring efficient use of

capacity—will exist. Such an extraordinary innovation

would substantially advance Latin America’s standing in

world markets.
80 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Latin America's New Natural Gas Pipeline Network

Many Latin American countries currently are developing an infrastructure that will facilitate inter-country trade in natural gas, which

is expected to fuel future electricity generation investment. One of the problems facing Argentina and other Latin American

countries is the antiquated state of existing natural gas transportation assets. This problem may grow more acute, because Latin

American natural gas consumption has been predicted to grow as much as four to five percent annually through 2005, a

substantially higher growth rate than the two percent forecast for worldwide gas consumption. (Two primary destinations for a,b

proposed and under-construction natural gas pipelines are Brazil and Chile, both of which have substantial air pollution problems,

implying that environmental considerations may be involved in the development of the pipeline.)

Nearly $7 billion and 6,000 miles of new natural gas pipelines are either under construction or under active consideration. The

pipelines will connect natural gas-producing areas in Argentina, Bolivia, Colombia, and Peru with consumers in Brazil and Chile;

with electric powerplants in Chile, Peru, and Brazil; and with seaports for export markets. Other projects under consideration will c

connect Argentina with Paraguay and Uruguay. These projects offer substantial opportunities for U.S. companies. d

Enron, El Paso Energy, and CMS Energy (all U.S. companies) are among international companies involved in Latin American

natural gas pipeline projects. Plans for a $1.8-billion, 1,800-mile Bolivia/Brazil pipeline are proceeding despite domestic protests e f

concerning the transport of natural gas from Bolivia to Brazil. Construction will begin with the approval of the financing of the g

project, both financial approval and construction are expected during the summer of 1997. Enron has a 34-percent share in the h

Bolivian segment of the pipeline and an 8-percent share in the Brazilian segment. El Paso Energy holds a 10-percent share in i

the Brazilian segment of the same project. j

CMS Energy is the primary member of a consortium building a $700 million, 160-mile pipeline connecting Argentina and northern

Chile. CMS also owns the largest private share of Argentina’s privatized 2,600-mile transportation gas pipeline. k l

 

“Latin American Gas Industry Poised for Enormous Growth, Industry Overview,” Gas World International (August, 1994). a

Energy Information Administration, International Energy Outlook 1997, DOE/EIA-0484(95) (Washington, DC, April 1997), pp. b

48 and 54.

Warren True, “World Pipeline Construction Looks to Remain Robust to Century’s Turn,” Oil and Gas Journal (February 10, c

1997), p. 34; David Abramson, “El Paso Energy Pushes Into Latin America in Search of Good Investment Opportunities,” The Oil

Daily, Volume 47, Number 72 (April 16, 1997), p. 3; and Michael Davis, “Enron Wins Bid for Brazilian Project,” The Houston

Chronicle (June 17, 1997), p. 1.

The numerous regional trade accords probably contributed much to the legal and commercial foundations underlying the d

inter-country natural gas transportation projects. The trade agreements include: the Andes Group, the Southern Cone Common

Market (Mercosur), and the Group of Three Amigos. The Andes Group includes Bolivia, Colombia, Ecuador, Peru, and Venezuela;

Mercosur includes Argentina, Brazil, Paraguay, and Uruguay; and the Three Amigos includes Colombia, Mexico, and Venezuela.

See “Focus on the Grupo Andino,” Latin America Regional Reports (April 20, 1995), p. 4.

Michael Davis, “Enron Wins Bid for Brazilian Project,” The Houston Chronicle (June 17, 1997), p. 1. e

Frank Gray, “Latin America: Regional Dash for Gas,” Financial Times (June 19, 1997), p. 4. f

Micael Kepp, “Critics’ Voices Begin to be Heard on Brazil-Bolivia Gas Line,” Platt’s Oilgram News (February 21, 1996), p. 8. g

“Brazil-Bolivia Pipeline,” Privatisation International, Number 102 (March 1, 1997). h

Enron Corp, 1994 Annual Report to Shareholders and Customers, p. 26. i

David Abramson, “El Paso Energy Pushes Into Latin America in Search of Good Investment Opportunities,” The Oil Daily, j

Volume 47, Number 72 (April 16, 1997), p. 3. The 750-mile, $700 million Chilean-Argentinean pipeline that was to have been

constructed by a consortium led by Tenneco Energy was canceled during the summer of 1996, before El Paso Energy acquired

Tenneco Energy. See John Javetski and Jeffrey Ryser, “New Gas Finds, Pipelines Shaping Latin American IPP Environment,”

Electrical World, Volume 210, Number 9 (September 1996), p. 28.

“CMS Energy Tries U.S.-style Industrial Incentives to Boost Demand in Argentina,” Industrial Energy Bulletin (February 7, k

1997), p. 12; and “Chile to Build Gas Pipeline,” The Oil Daily, Volume 47, Number 114 (June 16, 1997), p. 6.

“CMS Energy Introduces Argentina’s First Utility-Sponsored Business Expansion Program,” PR Newswire (December 11, l

1996).
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 81

“Getting the government books in order,” The Economist (October 12, 1996), U.S. Edition, p. S15. 1

Unfortunately, Mexico’s currency devaluation of December 1991 had negative ramifications for all of Latin America, including Argentina, an effect termed 2

the “tequila effect.” The “tequila effect” caused to a substantial reduction in the level of Argentina’s foreign reserve beginning in 1992, severely constricting

the country’s money supply and was followed by a recession. By 1996, however, the Argentina’s economy began to expand (“Getting the government books

in order,” The Economist (October 12, 1996), U.S. Edition, p. S15.). Argentina’s fiscal reforms included balancing the state public accounts, balancing the budget of the federal government, increasing the revenues collected 3

by the federal government, and reducing some import and export tariffs (Latin American Report, (Baldwyn, Pennsylvania: WEFA Energy World Bank,

1996), p. 2.1.).

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), pp. 3-4.). 4

These costs are referred to as “X-inefficiency” and were identified by Harvey Leibenstein in “Allocative Efficiency vs. X-efficiency,” American Economic 5

Review, Volume 56 (1966), pp. 392-415. Argentina’s electricity industry may have substantial X-inefficiency as it produced losses of almost $1 billion each

of the two years before privatization (Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), pp.

3-4.).

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), pp. 3-4. 6

Peter R. Lalor and Hernan Garcia, “Reshaping Power Markets: Lessons from South America,” Electricity Journal, Volume 9, Number 2 (March 1996), 7

pp. 63-71.

Jonathan Friedland and Benjamin A. Holden, “Utility Deregulation in Argentina Presages Possible U.S. Upheaval,” The Wall Street Journal (June 19, 8

1996), p. A1. R. Peter Lalor and Hernan Garcia, “Reshaping Power Markets: Lessons from South America,” Electricity Journal, Volume 9, Number 2 (March 1996), 9

pp. 63-71. Respectively, these companies were: the aforementioned Segba, Compania de Agua y Energia Electrica (Ayee), Hidroelectrica Norpatagonica S.A. 10

(Hidronor), and the power generation capacity of Commission Nacional de Energia Atomica (Cnea). Ayee also oversaw Argentina’s interests in its joint-venture with Paraguay in the huge Yacyreta hydroelectric plant. 11

Hidronor also was responsible for development of hydroelectric generation, most of which was in southern Argentina. 12

Commission Nacional de Energia Atomica (Cnea) was created by Executive Decree Number 1540/94 (Bernardo E. Duggan And Victoria Zoldi, “A Guide 13

to Energy, Natural Resources and Utilities Law: Argentina,” International Financial Law Review (April 1996), Supplement pp. 3-7.). 

Peter R. Lalor and Hernan Garcia, “Reshaping Power Markets: Lessons from South America,” Electricity Journal, Volume 9, Number 2 (March 1996), 14

pp. 63-71.

Jorge Cubas, Sabastiao Mattos, Miguel Moyola, Paul Slocomb, and Tom Studwell, “Latin America,” The International Lawyer (Spring 1990). 15

Public Law 23,696. 16

Bernardo E. Duggan and Victoria Zoldi, “A Guide to Energy, Natural Resources and Utilities Law: Argentina,” International Financial Law Review (April 17

1996), supplement pp. 3-7.

The electricity company was Servicios Eléctricos del Gran Buenos Aires (Segba), Argentina’s Privatization Program: Experience, Issues, and Lessons 18

(Washington, DC,: The World Bank, 1993), pp. 2-3. The names of the privatized companies and their acronyms will generally be relegated to

footnotes/endnotes. In so far as possible descriptive terms will be used in this report to reduce the possibility of the reader’s becoming lost in the maze created

by the large number of similarly-named companies and numerous acronyms. Among energy industries separate laws were passed for electric power, oil, natural gas, and mining. Bernardo E. Duggan and Victoria Zoldi, “A Guide 19

to Energy, Natural Resources and Utilities Law: Argentina,” International Financial Law Review (April 1996), Supplement pp. 3-7. ”Foreign Investment,” http://www.invertir.com/05forei.html (May 15, 1997). Similar agreements are in force with the countries of Austria, 20

Belgium-Luxembourg, Canada, Egypt, France, Germany, Hungary, Italy, Poland, Spain, Sweden, Switzerland, and the United Kingdom. Interestingly, of

the countries with investment in Argentina’s privatized electricity industry, only Chile, which is a fellow member of Mercosur with Argentina, and Finland

don’t have a current bilateral trade agreement with Argentina.

Duggan, Bernardo E. and Victoria Zoldi, “A Guide to Energy, Natural Resources and Utilities Law: Argentina,” International Financial Law Review 21

(April 1996), supplement pp. 3-7. The importance of pre-privatization restructuring is discussed by Spiller and Martorell. See Pablo T. Spiller and Luis Viana

Martorell, “How Should It be Done? Electricity Regulation in Argentina, Brazil, Uruguay, and Chile,” International Comparisons of Electricity, Gilbert,

Richard J. Gilbert and Edward P. Kahn, eds., (New York: Cambridge University Press, 1996), p. 83. According to Argentina’s then Energy Secretary Bastos, “In reforming [the electricity] sector, we wanted to use the best electricity model worldwide, so 22

we borrowed aspects of the Chilean and British systems ... .” See “Argentina: Ongoing Infrastructure Improvement,” Infrastructure Finance (December

1995/January 1996), p. 2. Public Law 21,382. 23

“Foreign Investment,” http://www.invertir.com/05forei.html (May 15, 1997). 24

The World Bank is an international organization that is headquartered in Washington, D.C. of the United States. However, the United States, at least 25

formally, exercises no more control over the World Bank than any other supporting country. 

In the World Banks’ own words, it is, “[t]he International Bank for Reconstruction and Development, frequently called the "World Bank" [and] was

established in July 1944 at the United Nations Monetary and Financial Conference in Bretton Woods, New Hampshire, USA. The World Bank opened for

business on June 25, 1946. The World Bank’s goal is to reduce poverty and improve living standards by promoting sustainable growth and investments in

people. The Bank provides loans, technical assistance and policy guidance to help its developing-country members achieve this objective. The World Bank

group of institutions includes: the International Bank for Reconstruction and Development (IBRD), the International Development Association (IDA), the

International Finance Corporation (IFC), the Multilateral Investment Guarantee Agency (MIGA), and the International Centre for the Settlement of Investment

Disputes (ICSID). See The World Bank, http://www.worldbank.org/html/extdr/faq/97111.htm#E19E1 (July 18, 1997). It may be instructive to briefly review the World Bank’s general steps of privatization. These are: 26

parliamentary approval; establishment of a privatization commission; preparation and approval of regulatory legislation or decrees; contracting technical,

legal, and financial consultants; definition of separate business units; labor-restructuring and voluntary retirement schemes; organization of regulatory

structure; preparation of bidding documents and transfer contracts; prequalification of potential bidders; issuance of calls to tender; evaluation of bids;

preliminary and final awards; company and asset transfer; disposal of minority share holdings; and organization of employee stock ownership programs.

See Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), pp. 2-3.

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 5. 27

Endnotes
82 Energy Information Administration/Electricity Reform Abroad and U.S. Investment

Several conditions are important for the creation of competitive and efficient energy markets. Lalor and Garcia enumerate those conditions for electricity 28

markets. The conditions include: a) mandatory separation of regulated functions and clear delineation of the limits of involvement by regulated entities in

competitive markets; b) unbundling of transmission charges and provision of “comparable” fair transmission access; c) clearly defined, published nodal or

zonal transmission prices reflecting incremental operating and upgrade costs; d) establishment of a centrally-dispatched commodity market, spot markets

for both capacity and energy priced at system marginal costs, and a parallel bilateral market based on long-term contracts; and e) access by generators and

marketers to at least a part of the retail market. See Peter R. Lalor and Hernan Garcia, “Reshaping Power Markets: Lessons from South America,” Electricity

Journal, Volume 9, Number 2 (March 1996), pp. 63-71.

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 6. 29

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 6. 30

Argentina Ministry of Economy and Public Works and Services, http://www.mecon.ar/invest/english/parti2htm (July 1, 1997). 31

Argentina Ministry of Economy and Public Works and Services, http://www.mecon.ar/invest/english/patri2h.htm (July 1, 1997). 32

The consortium is called Distrilec Inversora and includes Perez Companc of Argentina (32.5%), Chilectra of Chile (20%), Endesa of Chile (10%), Entergy 33

of the U.S. (10%), and PSI Energy of the U.S. (8%). See David Pilling, “Argentina Comes Alive,” Privatisation International, Number 88 (January 1, 1996).

David Pilling, “Argentina Comes Alive,” Privatisation International, Number 88 (January 1, 1996). 34

The regulatory body is known as the National Entity of Electricity Regulation and often is referred to by its acronym, Enre. However, regular use of such 35

acronyms may prove distracting to the reader and will be relegated to footnotes as often as practical. The market’s Spanish name is El Mercado Electrico Mayorista (Mem). 36

Peter R. Lalor and Hernan Garcia, “Reshaping power markets: Lessons from South America,” Electricity Journal, Volume 9, Number 2 (March 1996), 37

pp 63-71. The federal utility serving Buenos Aires was Servicios Electricos del Gran Buenos Aires (Segba). Segba was restructured into 6 power generation 38

companies and 3 distribution companies in order to privatize it. Segba’s transportation capabilities were transferred to create an electric transportation

company during the restructuring. The distribution company serving northern Buenos Aires is Empresa Distribudora Electrica Norte (Edenor). Meanwhile, Empresa Distribudora Electrica 39

Sur (Edesur) is the distribution company serving southern Buenos Aires.

“Duke, Entergy in Winning Group Paying $234 Million for Grid in Argentina,” Electric Utility Week (July 5, 1993), p. 1. 40

The company was known as Compania de Agua y Energia Electrica (Ayee). 41

The transmission company is Compañía de Transporte de Energía en Alta Tensión Red (Transener). 42

“Powerco Assumes Ownership of Guemes Power Station,” PR Newswire (September 30, 1992). 43

The company was known as Hidroelectrica Norpatagonica S.A.( Hidronor). 44

The company was known as Empresa Social Electrica de Buenos Aires (Eseba) and was separated into 2 generation, 1 transmission company, and 3 45

distribution companies. See “Argentina Investment: Power Privatisations Run Into Opposition ,” EIU ViewsWire (September 6, 1996).

“CEA and AES Win Bids on Two Electric Distribution Systems in Argentina,” PR Newswire (April 22, 1997). 46

See “AES, Partner to Buy Argentine Power Firms,” Reuters Financial Service (April 22, 1997) and “United Utilities Unit Consortium Wins 95-year 47

Argentina Electricity Concession,” AFX News (April 22, 1997).

“Buenos Aires Kicks off Tender for Privatization of Eseba,” Latin American Power Watch, Volume 3, Number 1 (February 1, 1997). 48

“ Argentina: Privatization of Eseba,” International Market Insight Reports (April 1, 1997). 49

“United Utilities Unit Consortium Wins 95-year Argentina Electricity Concession,” AFX News (April 22, 1997). 50

“CEA and AES Win Bids on Two Electric Distribution Systems in Argentina,” PR Newswire (April 22, 1997). 51

Enre is formally known as Ente Nacional Regulador de la Electricidad. See Mariano F.Grondona, “Birth of a New Market,” Infrastructure Finance 52

(June/July 1994), p. 59.

Claudio A. Onetto, “Competitive Restructuring,” Independent Energy, Volume 26, Number 3 (April 1996), pp. 30-35. 53

Peter R. Lallor and Hernan Garcia, “Reshaping Power Markets: Lessons from South America,” Electricity Journal, Volume 9, Number 2 (March 1996), 54

pp. 63-71.

“Houston Industries Group Buys Small Argentine Utilit,; Triples Rival Bids,” Electric Utility Week (December 7, 1992), p. 1. 55

Charles R. Moyer, “The Future of Electricity: Energy in the Twenty-First Century,” Business Economics, Volume 31, Number 4 (October 1996), p. 13. 56

“Staff Investigation on the Restructuring of the Electric Industry,” Virginia State Corporation Commission, http://www.state.va.us/scc/restrct3.htm (May 57

12, 1997).

Market concentration may be a problem in Chile and the United Kingdom. For example, in Chile the electricity industry essentially is dominated by one

company, Endesa (see Peter R. Lalor and Hernan Garcia, “Reshaping power markets: Lessons from South America,” Electricity Journal, Vol. 9, No. 2

(March 1996), pp. 63-71.). It may be that Argentina is adopting a model designed to improve upon the Chilean and UK experiences.

Guillermo Hiskel, “Interview: Argentine Utilities Form Strategic Group,” Reuters Financial Service (August 1, 1996). 58

Cammesa, http://www.cammesa.com.ar/6de1.htm (June 3, 1997). 59

Cammesa, http://www.cammesa.com.ar/3de2.htm (June 3, 1997). 60

"Advanced Technology for Argentina,” European Power News (February 1997); and Jonathan Friedland and Benjamin A. Holden, “Utility Deregulation 61

in Argentina Presages Possible U.S. Upheaval,” The Wall Street Journal (June 19, 1996), p. A1. Other factors also enter into the determination of the price paid generators. These factors are discussed in the section below on electricity prices. 62

Cammesa, http://www.cammesa.com.ar/8de2.html (June 11, 1997). 63

Peter R. Lallor and Hernan Garcia, “Reshaping Power Markets: Lessons from South America,” Electricity Journal, Volume 9, Number 2 (March 1996), 64

pp. 63-71. Transener is formally known as Compañía de Transporte de Energía en Alta Tensión Red. 65

Personal conversation with Emilio Sawada of the Private Sector Department of the Inter-American Development Bank (Washington, DC, June 1997). 66

“Argentina to Accelerate Sale of Remaining Power Assets,” Latin American Power Watch, Volume 2, Number 6 (July 1, 1996); and Ministry of Economy 67

and Public Works and Services, http://www.mecon.ar/invest/english/parti2h.htm (July 1, 1997).

Bernardo E. Duggan and Victoria Zoldi, “A Guide to Energy, Natural Resources and Utilities Law: Argentina,” International Financial Law Review (April 68

1996), Supplement pp. 3-7.

“Chilgener Opens Bidding for Power Lines,” Reuters Financial Service (January 16, 1997). 69

“Argentina Industry: Power Inflows To Spark Efficiency, Expansion,” EIU ViewsWire (October 1, 1996). 70

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 10. 71

Facsimile provided by the Argentine embassy in Washington, DC (February 12, 1997), p. 2. 72

Jonathan Friedland and Benjamin A. Holden, “Utility Deregulation in Argentina Presages Possible U.S. Upheaval,” The Wall Street Journal (June 19, 73

1996), p. A1.

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 10. 74

Charles R. Moyeer, “The Future of Electricity: Energy in the Twenty-First Century,” Business Economics, Volume 31, Number 4 (October 1996), p. 13. 75
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 83

Cammesa, http://www.cammesa.com.ar/3de2.htm (June 3, 1997). 76

Argentina Ministry of Economy and Public Works and Services, http://www.mecon.ar/invest/english/ (June 3, 1997). 77

”Energy. Argentina: the Silver Giant,” Latin Finance, Number 75 (March 1996), p. 60A. 78

“Prices Have Plummeted in Argentine Spot Market, Where Ownership of Gas is Key,” Power Markets Week (March 24, 1997), p. 12. 79

Cammesa, http://www.cammesa.com.ar/sea.htm (June 11, 1997). 80

Claudio A. Onetto, “Competitive Restructuring,” Independent Energy, Volume 26, Number 3 (April 1996), pp. 30-35. 81

”Energy. Argentina: The Silver Giant,” Latin Finance, Number 75 (March 1996), p. 60A. 82

”Prices Have Plummeted in Argentine Spot Market, Where Ownership of Gas is Key,” Power Markets Week (March 24, 1997), p. 12. 83

Argentina Ministry of Economy and Public Works and Services, http://www.mecon.ar/invest/english/parti2h.htm (July 1, 1997). 84

“Argentina; Ongoing Infrastructure Improvement,” Infrastructure Finance (December, 1995/January, 1996), p. 2. 85

Charles R. Moyer, “The Future of Electricity: Energy in the Twenty-First Century,” Business Economics, Volume 31, Number 4 (October 1996), p. 13. 86

“Energy. Argentina: The Silver Giant,” Latin Finance, Number 75 (March, 1996), p. 60A. 87

"Advanced Technology for Argentina,” European Power News (February 1997). 88

David Pilling, “Argentina Comes Alive,” Privatisation International, Number 88 (January 1, 1996). 89

“Argentina Industry: Power Inflows To Spark Efficiency, Expansion,” EIU ViewsWire (October 1, 1996). 90

Companies having ownership in one or more of the companies comprising this consortium of electricity generators include: the U.S. companies CMS 91

Energy Corp., Dominion Resources, Duke Power Co., and Southern Electric Co.; the Chilean companies Chilgener, Chilquinta SA, and Endesa; the Argentine

companies Capsa and Cooperativa Provincial de Servicios Publicos y Comunitaries de Neuquen Limitada (electric cooperative); the Canadian company

TransAlta Corp.; and the Japanese company OMRON Corp. See Guillermo Hiskel, “Interview: Argentine Utilities Form Strategic Group,” Reuters Financial

Service (August 1, 1996); and “Houston Industries Group Buys Small Argentine Utility, Triples Rival Bids,” Electric Utility Week (December 7, 1992), p.

1.

Guillermo Hiskel, “Interview: Argentine Utilities Form Strategic Group,” Reuters Financial Service (August 1, 1996). 92

Leonard S. Hyman, The Privatization of Public Utilities (Vienna, Virginia: Public Utilities Reports, 1995), p. 71. 93

Inter-American Development Bank, http://www.iadb.org/~http/argentina/argqfact.html (June 3, 1997). 94

“Energy. Argentina: The Silver Giant,” Latin Finance, Number 75 (March, 1996), p. 60A. 95

“Argentina: Ongoing Infrastructure Improvement,” Infrastructure Finance (December 1995/January 1996), p. 2. 96

“Argentina: Ongoing Infrastructure Improvement,” Infrastructure Finance (December 1996/January 1997), p. 2. 97

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), pp. 13-14. 98

Inter-America Development Bank, http://iadb6000.iadb.org/~http/argentina/arbsed.html (June 3, 1997). 99

Two types of debt are discussed in this study. External debt is composed of Argentine private and public securities that are held by foreigners. 100

Government debt is composed of future obligations owed by the federal government.

“Argentina: Ongoing Infrastructure Improvement,” Infrastructure Finance (December 1996/January 1997), p. 2. 101

Stat-USA, http://www.stat-usa.gov/bems/bemsarg/argfact.html (May 20, 1997). 102

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), pp. 14-15. 103

Stat-USA, http://www.stat-usa/bems//bemsarg/argfact.html (May 20, 1997). 104

Michelle Wallin, “Argentina Politics Tense But Economy Remains Unfazed,” The Wall Street Journal Interactive Edition, 105

https://interactive.wsj.com/archive/retrieve@cgi (July 1, 1997). However, according to Argentina’s statistics bureau (Indec), the increase in the unemployment rate from 17.1 percent in May 1996 to 16.3 percent in 106

October 1996 was due to an increase in the labor force of 202,000, much of which was offset by a concurrent increase in jobs of 200,000. See Economic

News Newsletter (Washington, DC: Argentine Embassy, January/February 1997), http://athea.ar/cwash/homepage/news197.htm (July1, 1997).

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 14. 107

The Brady Plan, so named for former U.S. Treasury Secretary Brady, was approved in 1989 and created a class of bonds called Brady bonds, or, more 108

simply, Bradys. Commercial bank debt of a developing country is converted at a discount into Brady bonds. Brady bonds typically have a life of at least

10 years in length, and more than half those outstanding mature in 20 years or more after issuance. See Carol Palombo, “Brady Bonds: Past, Present and

Future,” Latin Finance, Number 79 (July 1996), p. 46. The plan allows countries to restore their credit status in the international community, giving them

access to international capital markets. One of the preconditions of issuing Brady bonds is that the country implement strict fiscal monetary policies

established by the International Monetary Fund that are expected to create both economic stability and sustainable growth.

DRI/McGraw-Hill World Energy Service, Latin American Outlook, 1996 (1997), p. 25. 109

DRI/McGraw-Hill World Energy Service, Latin American Outlook, 1996 (1997), p. 25. 110

DRI/McGraw-Hill World Energy Service, Latin American Outlook, 1996 (1997), p. 25. 111

Big Emerging Markets, U.S. International Trade Administration, U.S. Department of Commerce, http://www.stat-usa.gov/bem/bemsarg/argqfact.html 112

(May 1997).

Michelle Wallin, “Argentina Politics Tense But Economy Remains Unfazed,” The Wall Street Journal Interactive Edition 113

https://interactive.wsj.com/archive/retrieve@cgi (July 1, 1997).

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 15. 114

Argentina’s Privatization Program: Experience, Issues, and Lessons (Washington, DC: The World Bank, 1993), p. 14. 115

Inter-American Development Bank, http://iadb6000.iadb.org/~http/argentina/arbsed.html (May 22, 1997). 116

The Buenos Aires provincial electricity company billed $850 million of electricity annually to 750,000 direct and 600,000 indirect clients (directly serviced 117

by cooperatives purchasing power from Eseba) before its restructuring. The company was restructured into three distribution companies, two generation

companies, and one transmission company. See "Argentina Investment: Power Privatisations Run Into Opposition,” EIU ViewsWire (September 6, 1997).

Energy Information Administration, AEO97 National Energy Modeling system, run AEO97B.D1002961C; and Latin America Report (Baldwyn, 118

Pennsylvania: WEFA Energy, 1996), p. 2.15.

Deepak Gopinath, “Power to the Customer,” Infrastructure Finance (April 1997), p. 45. 119

For example, acquiring distribution companies may ensure outlets for the generation that the companies are bringing on line in the same market. 120

Distribution revenues also may balance cash flows from generation. Finally, distribution may pay a return on the investment more quickly than generation

investment. See DeepakGopinath, “Power to the Customer,” Infrastructure Finance (April 1997), p. 45.

Leonard S. Hyman, The Privatization of Public Utilities (Vienna, Virginia: Public Utilities Reports, 1995), p. 63. 121

“HL&P Parent in Group Vastly Outbidding Rivals for Small Utility in Argentina,” Independent Power Report (December 4, 1992), p. 1. 122

Duke Power, http://www.dukepower.com/duke/faq.htm (June 10, 1997). 123

Appendix C, Table C1 contains a listing of the companies with Argentine electricity investments, their primary line of business, their home country, and 124

types of Argentine electricity investment.

"The Race to Bridge Borders,” The Economist (October 12, 1996), U.S. Edition, p. S18. 125

“Transition Complete In Argentina's Entre Rios, CMS At Helm,” The Energy Daily (May 21, 1996). 126
Appendix A

U.S. Electricity Utility Companies

Not Investing in Argentina,

Australia, and the United Kingdom
2 Energy Information Administration/Electricity Reform Abroad and U.S. Investment 

Table A1. U.S. Electric Utility Companies Not Investing in Argentina, Australia, and the United Kingdom

Allegheny Power System Florida Public Utilities Peco Energy Co.

Atlantic Energy Inc. FPL Group Inc. Pinnacle West Capital

Baltimore Gas & Electric Green Mountain Power Corp. Portland General Corp.

Bangor Hydro Electric Hawaiian Electric Inds. Potomac Electric Power

Black Hills Corp. Idaho Power Co. PP&L Resources Inc.

Boston Edison IES Industries Inc. Public Service of New Mexico

Carolina Power & Light Illinova Corp. Public Service Enterprises

Centerior Energy Interstate Power Co. Puget Sound Energy Inc.

Central Hudson Gas & Elec. IPALCO Enterprise Inc. Rochester Gas & Electric

Central Louisiana Electric Kansas City Power & Light Scana Corp.

Central Maine Power KU Energy Corp. Sierra Pacific Resources

Central Vermont Pub Serv. LG&E Energy Corp. Sigcorp Inc.

Cilcorp Inc. Long Island Lighting St Joseph Light & Power

Cipsco Inc. Madison Gas & Electric Co. Teco Energy Inc.

Commonwealth Edison Co. Main Public Services TNP Enterprises Inc.

Commonwealth Energy System MDU Resources Group Inc. Tucson Electric Power Co.

Consolidated Edison of New York Midamerica Energy Hldg. UGI Corp.

Dayton Power & Light Inc. Montana Power Co. Unicom Corp.

Delmarva Power & Light Nevada Power Co. Union Electric Co.

DPL Inc. New England Electric System United Illuminating Co.

DQE Inc. New York State Elec & Gas Unitil Corp.

DTE Energy Co. Niagara Mohawk Power Upper Peninsula Energy Corp.

Eastern Utilities Assoc. Nipsco Industries Inc. Washington Water Power

El Paso Electric Co. Northwestern Public Serv Co. Western Resources

Empire District Electric Co. NRG Generating U.S. Inc. Wisconsin Energy Corp.

Enova Corp. OGE Energy Corp. WPL Holdings Inc.

Environmental Power Corp Ohio Edison Co. WPS Resources Corp.

Eselco Inc. Orange & Rockland Utilities York Research Corp.

Florida Progress Corp Otter Tail Power Co

 Source: Standard and Poors Compustat, July 1997.
Appendix B

Electricity Reform Milestones 

in Argentina, Australia,

and the United Kingdom
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 91

Appendix B

Electricity Reform Milestones in 

Argentina, Australia, and the United Kingdom

Explanatory Notes

This appendix is designed to aid the reader in following discussed more fully (and in context) in Chapters 2, 3, and

important electricity developments through time as they 4. Table B1 provides milestones for the United Kingdom.

have occurred in Argentina, Australia, and the United Tables B2 and B3 provide milestones for Australia and

Kingdom over the last century. These developments are Argentina, respectively. 
92 Energy Information Administration/Electricity Reform Abroad and U.S. Investment 

Table B1. Electricity Reform Milestones in Argentina

Date Event

1947 . . . . . . . . . . . . . . . First 100-percent federally-owned electric utility, Agua y Energia Electrica, Sociedad del Estado

(Ayee), was created.

1950 ............... Argentina begins its nuclear research and development program, creating Comision Nacional de

Energia Atomica (Conea).

1957 . . . . . . . . . . . . . . . Second 100-percent federally-owned electric utility, Servicos Electricos del Gran Buenos Aires

(Segba), was created to serve the Buenos Aires metropolitan area.

1977, March ......... The Foreign Investment Law is passed, allowing foreign investors for the first time to remit all their

profits from Argentine investments to their home country.

1982 . . . . . . . . . . . . . . . Nationalization of electricity ends with the acquisition of the remaining investor-owned utility-Compania

Industrial de Argentina Electrica (Ciae).

1989 . . . . . . . . . . . . . . . The Economic Emergency Law passed, suspending all state subsidies and creating incentive

programs for mining and manufacturing companies.

1989, September . . . . . The Administrative Reform Law passed, defining the ground rules for investment in formerly

federally-owned companies.

1992, January ....... The Electric Law passed, establishing a legal structure for the restructuring and privatization of the

electricity industry.

1992 . . . . . . . . . . . . . . . The Bilateral Investment Treaty is signed, giving U.S. companies the right to invest in Argentina under

terms at least as favorable as those accorded Argentine firms.

1992, April . . . . . . . . . . 60 percent of the thermal generator Central Puerto (formerly part of the federal electricity company

Segba) is sold to three Chilean electricity companies, marking the initial privatization of Argentina’s

electricity industry.

1992, May . . . . . . . . . . 60 percent of the thermal generator Central Costanera (formerly part of the federal electricity company

Segba) is sold to foreign companies, including the U.S. company Entergy. This was the first purchase

of an Argentine electricity company by a U.S. company.

1993 . . . . . . . . . . . . . . . The Amendment to the Foreign Investment Law is passed, removing foreign investors’ burdensome

requirement of receiving prior federal approval for all investment (a few investments still require the

prior approval step).

1993 . . . . . . . . . . . . . . . The Decree 1853 is passed removing most remaining restrictions on foreign investment. The Decree

allows 100-percent foreign ownership of Argentine firms and full repatriation of profits and capital to

the home country of foreign investors.
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 93

Table B2. Electricity Reform Milestones in Australia

Date Event

1990, November . . . . . . . . . . The Industry Commission recommended reforms that included the privatization and/or commercialization of all state-owned electricity industries.

1991, May ............... The Commonwealth, state and territorial heads of government established the National Grid

Management Council, an intergovernmental advisory body, to develop the National Electricity

Code.

1993 . . . . . . . . . . . . . . . . . . . . The National Competition Policy Review, known as the Hilmer Commission Report, identified

industries (such as electric, gas, water, and road transport) where reform could yield substantial

benefits to Australia’s economy.

1994, October . . . . . . . . . . . . The National Grid Management Council developed interim market arrangements and broad

objectives for the national electricity market, released in a report entitled “Restructuring of the

Electricity Supply Industry in Australia.”

1995, April . . . . . . . . . . . . . . . The Council of Australian Governments agreed to a national competition policy reform, the National

Competition Reform Act 1995, which provided, in part, for uniform protection of consumer and

business rights and increased competition in all jurisdictions. 

1995, April - July .......... The first draft of the National Electricity Code was issued to the public for comment.

1995, September . . . . . . . . . . The National Grid Management Council prepared a second report detailing the market functions

proposed for the National Electricity Code.

1996, September .......... The National Electricity Code was finalized.

1996, November . . . . . . . . . . The National Electricity Code was submitted to the Australian Competition and Consumer

Commission, with approval expected in late 1997.

1997, May . . . . . . . . . . . . . . . The first phase of the national electricity market began in New South Wales, Victoria, and the

Australian Capital Territory.

1997, October . . . . . . . . . . . . All the regulations of the National Electricity Code are to be imposed, except those for market rules

and system security, which will be governed by State Codes until the national market systems are

operational.

1997, October ............ Queensland is to participate in the national electricity market system.

1998 . . . . . . . . . . . . . . . . . . . . The national market systems are to be in operation and full implementation of market arrangements

will be applied according to the National Electricity Code. 

1998 .................... South Australian generators will enter the market as full participants.

Date Electricity Reform Milestones in the Australian States

Victoria

1993, October . . . . . . . . . . . . Victoria’s monopolistic electricity industry, the State Electricity Commission of Victoria, was

vertically separated into three segments: generation, distribution, and transmission.

1994 . . . . . . . . . . . . . . . . . . . . The government created state-owned entities. The generation sector was divided into 5

competitive and independent companies. The former 29 electricity distribution companies were

merged into 5 companies and a transmission company, PowerNet Victoria, was created.

1994 .................... The state’s wholesale market became operational.

1992, December .......... Generation

In December 1992, Victoria began the privatization of its generation sector with the 51-percent sale

of its Loy Yang B power station to the U.S.-based Edison International’s Mission Energy Company.

In May of 1997, Edison International purchased the remaining stake in the Loy Yang B power

station.
Table B2. Electricity Reform Milestones in Australia (continued)

Date Event

94 Energy Information Administration/Electricity Reform Abroad and U.S. Investment 

1996, March .............. The generation plant, Yallourn-W, was sold to PowerGen PLC of the United Kingdom.

1996, August . . . . . . . . . . . . . The Hazelwood coal-fired plant and a coal mine were sold to a group led by National Power PLC

of the United Kingdom. 

1997, May . . . . . . . . . . . . . . . The Loy Yang A coal-fired power station and a coal mine were sold to a consortium group led by

the U.S. company CMS Energy. This was the largest energy asset privatization in Australian

history.

1996 . . . . . . . . . . . . . . . . . . . . Customers with energy consumption of 750 megawatts per year became eligible to choose their

electricity marketer.

1995 .................... Distribution

The state began the privatization of its electricity assets through the auction of all of its 5 electric

power distribution companies (United Energy, Solaris Power, Eastern Energy, Powercor, and

Citipower).

1997 .................... Transmission

PowerNet Victoria Transmission, the state-owned agency operating Victoria’s high-voltage

electricity transmission grid, is expected to be privatized.

New South Wales

1991, August . . . . . . . . . . . . . The states’ monopolistic electricity industry, Electricity Commission of New South Wales, was

renamed Pacific Power and was restructured internally into six smaller business units. 

1994 . . . . . . . . . . . . . . . . . . . . Pacific Power’s electricity transmission network business unit was established as a separate legal

entity, the Electricity Transmission Authority, and was later separated from Pacific Power in

February 1995 to form a state-owned corporation (now called TransGrid).

1995, October . . . . . . . . . . . . The state’s previous 25 distribution boards were aggregated into six businesses and were later

corporatized in March 1996. 1

1996, May ............... The wholesale market became fully operational.

1997, July . . . . . . . . . . . . . . . Customers with energy consumption of 750 megawatts per year became eligible to choose their

electricity marketer. 

1997, May . . . . . . . . . . . . . . . The New South Wales’ treasurer, Michael Egan, announced his intentions to privatize all of the

state’s electricity assets. 

1995 .................... Generation

A consortium consisting of Air Liquide Australia Ltd, Itochu Corporation (a Japanese company),

and Energy Australia (New South Wales’ electricity distributor) was formed to develop a 350-

megawatt cogeneration plant in Sydney. 

1995, December . . . . . . . . . . Energy Developments Limited (an Australian company) became involved in a 4-megawatt gas-fired

power plant, and a proposed 90-megawatt coal steam methane power plant.

1995, December . . . . . . . . . . Sithe Energies (a U.S.-based independent power producer) and Broken Hill Proprietary (Australianowned) began the construction of a 175-megawatt cogeneration plant at Smithfield (near Sydney,

Australia), with commercial operations to begin in 1997.

1997 .................... Energy Australia withdrew from the cogeneration project in Sydney.

The Australian Capital Territory (ACT) 

1995, July ............... The ACT’s monopolistic electricity industry was corporatized.

1996, March .............. The ACT began to participate in the New South Wales electricity market.
Table B2. Electricity Reform Milestones in Australia (continued)

Date Event

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 95

1997, May . . . . . . . . . . . . . . . The ACT began to operate in the national electricity market in conjunction with New South Wales

and Victoria.

1997 .................... The ACT is to begin retail competition.

Queensland

1995, January . . . . . . . . . . . . The state’s monopolistic electricity company, the Queensland Electricity Commission, was

restructured and corporatized to form two new government corporations-- AUSTA Electric and the

Queensland Transmission and Supply Corporation (QTSC).

Late 1997 ................ AUSTA Electric is to be split into three generating companies that will compete amongst

themselves to supply the seven existing government electricity distributors.

Late 1997 ................ Three new electricity marketing corporations are to be created.

1994, March .............. Generation

The Queensland Electricity Commission sold the 1,650 megawatt coal base-load power station,

Gladstone, to Comalco (an Australian company) and Northern States Power (a U.S. company).

1994 . . . . . . . . . . . . . . . . . . . . The Broken Hill Proprietary Company (an Australian company) began construction of a 105-

megawatt gas-fired power station.

1996, August ............. AUSTA Electric issued proposals to recommission generation plants (Collinsville and Callide-A)

and to have an interconnection transmission link with the state of New South Wales. Both projects

will be completed between 1998 to 1999.

1997, April . . . . . . . . . . . . . . . Australia Shell began a feasibility study for the construction of a power station in Callide,

Queensland. 

2002 .................... The state plans to construct a 440-megawatt plant.

2003 to 2006 ............. The state plans to build a power plant with generating capacity between 600 and 1,400

megawatts.

1997, June ............... Transmission

Queensland and New South Wales announced their intentions to built an interconnection grid link

between the two states, with operations to begin by 2001.

South Australia

1995 . . . . . . . . . . . . . . . . . . . . The vertically-integrated state-owned utility, the Electricity Trust of South Australia, was

restructured and corporatized as ETSA Corporation. 

1997, January . . . . . . . . . . . . ETSA Generation was separated from its parent company and became an independent

government business (ETSA Generation was formerly a subsidiary of ETSA Corporation). 

1998 .................... The state is scheduled to participate in the national electricity market.

Date Western Australia

1995, January . . . . . . . . . . . . The vertically integrated state-owned utility, the State Electricity Commission of Western Australia,

was divided into two independent electricity and gas corporations, trading as Western Power and

Alinta Gas.
Table B2. Electricity Reform Milestones in Australia (continued)

Date Event

96 Energy Information Administration/Electricity Reform Abroad and U.S. Investment 

1995 . . . . . . . . . . . . . . . . . . . . Edison International (a U.S. company), through its subsidiary Mission Energy, began a project to

build an $111-million electric power plant.

Tasmania

1995, June ............... The Hydro-electric Commission of Tasmania (HEC) passed legislation to allow the entry of new

participants and extended customer choice in the industry. (The HEC remains a verticallyintegrated, state-owned electricity business with separately organized generation, transmission,

and distribution segments.) 

1996 . . . . . . . . . . . . . . . . . . . . A feasibility study that began in 1993 concluded that while it was technically possible to construct

a subsea-link between Tasmania and Victoria, the subsea-link would not be economic until the

year 2000.

1997, April . . . . . . . . . . . . . . . The state government announced intentions to introduce retail competition in its electricity industry

and to sell some of its equity interest in the electricity industry.

The Snowy Mountains Hydro-electric Scheme

. . . . . . . . . . . . . . . . . . . . . . . . . The Scheme will be corporatized under the national electricity market reforms and will sell

electricity on the national grid in competition with other states.

 In Australia, in general a corporatized entity remains owned by the public sector, with a board nominated by the states. However, 1

the company’s operation and legal obligations are identical to those in the private sector.
Energy Information Administration/Electricity Reform Abroad and U.S. Investment 97

Table B3. Electricity Reform Milestones in the United Kingdom

 Date Event

1926 . . . . . . . . . . . . The UK government passes Act establishing the central government’s authority in electricity matters

through the Central Electricity Board.

1935 ............ The UK’s central electricity grid goes into operation.

1947 ............ The electricity industries in England, Wales, and Southern Scotland are nationalized.

1947 ............ The British Electricity Authority assumes responsibility for generation and transmission.

1957 ............ The Central Electricity Generating Board (CEGB) is created.

1965 ............ Natural gas is discovered in the North Sea, which (nearly 2 decades later) provides electric utilities with

an important alternative fuel.

1973-1974 . . . . . . . First oil price shock occurs: the UK moves towards greater reliance on nuclear power and domestic coal.

1978-1979 ....... Second oil price shock occurs further encouraging the UK toward greater reliance on domestic fuels.

1979 . . . . . . . . . . . . The Conservative Party assumes national power under the leadership of Margaret Thatcher resulting in

the implementation of radical economic reforms.

1983 ............ Energy Act of 1983 is passed, opening the central electricity grid up to independent power producers.

1984-1985 . . . . . . . Year-long miners strike ensues, calling into question reliance on domestic coal as the predominant

electricity fuel.

1986 ............ The Gas Act of 1986 is passed, deregulating the natural gas market and privatizing British Gas.

1988 . . . . . . . . . . . . A Fossil Fuel Levy is introduced in order to subsidize nuclear power and nonrenewable fuel industries.

1989, July ....... The Electricity Act of 1989 is passed, inaugurating a sweeping deregulation and privatization of UK

electricity.

1989 ............ The UK government postpones nuclear power’s privatization indefinitely due to concerns over potential

auction problems stemming from upward estimations of the financial costs associated with spent fuel

disposal and decommissioning. 

1990, April ....... Vesting Day inaugurates the initial implementation of the Electricity Act of 1989.

1990, April ....... The Office of Energy Regulation (OFFER) assumes the responsibility of industry regulator.

1990, April ....... The > 1 megawatt electricity marketing market is deregulated, allowing large industrial consumers to

purchase electricity directly and at unregulated prices.

1990, April ....... New coal contracts take effect (with an expiration date of March 1993).

1990, April . . . . . . . OFFER employs price caps to regulate distribution, transmission, and the still-regulated (tariff) marketing

services. 

1990, April . . . . . . . A new electricity industry comes into being. The new industry includes two thermal power producers

(National Power and PowerGen), a nation-wide transmission company (the National Grid Company), and

twelve regional electricity distribution companies (RECs).

1990, December . . The RECs are auctioned off.

1991, March ...... Sixty percent of the shares in the two newly-created power generation companies are auctioned off.

1991, July ....... OFFER introduces service standards for tariff customers.

1991, December . . OFFER releases pool price inquiry report.

1992, October .... Crisis ensues over coal contract negotiations.

1993, October .... OFFER raises electricity service standards to tariff customers for the second time.

1993, March ...... 3-year coal contracts officially expire.

1993, March . . . . . . The UK government releases white paper presenting official government proposal on future 3-year coal

contract.

1993, April ....... OFFER places new price caps on National Grid Company.
Table B3. Electricity Reform Milestones in the United Kingdom (continued)

 Date Event

98 Energy Information Administration/Electricity Reform Abroad and U.S. Investment 

1993, July ....... OFFER releases report criticizing pool competitiveness.

1993, November . . Coal contract agreement reached (for the April 1994 through April 1998 period).

1993, December . . OFFER reaches agreement with National Power and PowerGen to sell off a total of 6000 megawatts of

capacity in order to create more competition in electricity generation.

1994, February . . . OFFER establishes electricity pool price ceiling because of concerns that electricity suppliers were

exercising undue market control.

1994, April ....... The > 100 megawatt electricity marketing market is deregulated.

1994, August ..... OFFER proposes new price caps on RECs.

1994, December . . Trafalgar attempts to purchase the REC, Northern Electric, resulting in a general reappraisal of REC asset

values and, in turn, an unscheduled regulatory review by the OFFER.

1995 ............ British Coal is privatized.

1995, March ...... OFFER announces a reexamination of REC prices.

1995, March . . . . . . The UK government’s “golden share” in the RECs expires. This “golden share” had previously limited

individual ownership to no more than fifteen percent of any particular REC.

1995, March . . . . . . The UK government’s remaining shares in National Power and PowerGen are auctioned off, although the

government retained its “golden share” in the two generation companies.

1995, April ....... OFFER raises electricity service standards for tariff customers for the third time.

1995, July ....... Scottish Power places bid for the REC, Manweb (which would eventually become successful).

1995, July . . . . . . . U.S.-based Southern Company bids for the REC, South Western Electricity (which would eventually

become successful).

1995, July ....... North West Water places a bid for the REC, NORWEB (which would eventually become successful).

1995, August ..... Trafalgar withdraws bid for Northern Electric.

1995, September . . Hanson bids for the REC, the Eastern Group (which would eventually become successful).

1995, September . . PowerGen bids for the REC, Midlands Electricity (which eventually is rejected by the UK government).

1995, October . . . . National Power bids for the REC, Southern Electric (which eventually is rejected by the UK government).

1995, October . . . . U.S.-based Central and South West Corp bids for the REC, SEEBOARD (which would eventually become

successful).

1995, Autumn . . . . PowerGen sells 2000 megawatts of generation capacity to Hanson in compliance with the December 1993

agreement with the OFFER.

1995, December . . Welsh Water bids for the REC, SWALEC (which would eventually become successful).

1995, December . . REC sell shares in the National Grid Company (NGC) and NGC’s shares trade on London Stock

Exchange.

1995, December . . The UK government consolidates eight of the countries’ advanced nuclear plants to form the company

British Energy.

1996, January .... NGC sells pumped storage units to Mission Energy of the United States.

1996, April ....... National Power sells 4000 megawatts of generation capacity to Hanson in compliance with the OFFER

proposal.
Table B3. Electricity Reform Milestones in the United Kingdom (continued)

 Date Event

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 99

1996, April ....... U.S.-based Southern Company makes a bid for National Power (which is eventually rejected by the UK

government).

1996, April ....... The UK Trade and Industry Secretary thwarts REC takeover attempts by National Power, PowerGen,

and the Southern Company.

1996 April ........ The UK creates the government-owned entity, British Electric, retaining public ownership of the nation’s

older style nuclear reactors.

1996, May ....... U.S.-based General Public Utilities and Cinergy bid for Midlands Electricity (which would eventually

become successful). 

1996, July ....... British Energy (which assumed ownership of the country’s advanced nuclear reactors) is privatized.

1996, October .... U.S.-based CalEnergy bids for the REC, Northern Electric (which would eventually become

successful).

1996, November . . U.S.-based Dominion Resources bids for the REC, London Electricity (which would eventually become

successful).

1997, February . . . U.S.-Based American Electric Power and Public Service of Colorado bid for the REC, Yorkshire

Electricity (which would eventually become successful).

1997, May ....... Energy Group purchases the U.S. electric power marketing company, Citizens Power.

1997, June ....... U.S.-based Pacificorp places a bid for the REC, Energy Group (the success of which had not been

determined by publication date of this report).

1998, March ...... Expiration date for the March 1994-March 1988 coal contract.

1998, April ....... All of the electricity marketing segment is deregulated, implementing the final stage in the deregulation

of the UK electric marketing segment.

1998 ............ The nuclear levy is scheduled to be completely phased out.
Appendix C

Review of Argentine

Electricity

Privatization

Investment
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 103

Appendix C

Review of Argentine Electricity

Privatization Investment

Explanatory Notes

This appendix indicates the various companies that were referrs to the post-restructuring company. Table C4

created during Argentina’s restructuring of its federal and resents Argentine power generators built since restrucprovincial electricity companies. Table C1 contains invest- turing began in 1991.

ments made by foreign companies in Argentina’s

privatized electricity industry and is a more detailed Similar reviews for the United Kingdom and Australia are

version of Table 21 in the text. C2 provides details contained within the text of the Chapters 2 and 3,

concerning the restructuring of federal electricity com- respectively. An appendix was used to present the

panies and Table C3 provides similar details for the Argentine review because of the many companies into

rovincial electricity companies. The 1991 column refers to which the federal and provincial electricity companies of

the pre-restructuring company and the 1997 column Argentina were divided during the restructuring.
104 Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Table C1. Foreign Companies’ Investments in Argentina’s Electricity Industry, as of 1997

Company Headquarters Investment (million)

Country of Amount of

Incorporation/ Investment

AES Corporation ...... United States Central San Nicolas (coal- and gas-fired $8.1 (plus $45.4 debt)

generation) 71% a

Eden (distribution) 60% $377 (for both Eden &

Edes (distribution) 60% Edes)

Rio Juramento (hydroelectric generation) 98%

Cobra Corral (hydroelectric generation) $41

____ (hydroelectric generation)

Parana (combined-cycle generation) N.A.

N.A.

$300 million (under

construction)

Amoco Co. ........... United States Comodoro Rivadavia (gas-fired generation) N.A.

<50%

British Gas ........... United Kingdom Central Dock Sud (oil- and gas-fired generation) $24.5 

45%c

Camuzzi Gazometri .... Italy Comodoro Rivadavia (gas-fired generation) N.A.

>50%

Hidroelectrica Ameghina, S.A. (hydroelectric $1 (plus $7.6 debt)

generation) 35%

Transpa (distribution) 50%

N.A.

Chilectra ............. Chile Central Costanera (oil- and gas-fired generation) $4.5 

3%

Central Puerto (gas-fired generation) 9.8% $15.1

Edesur (distribution company) 10%

$100 

Cinergy .............. United States Edesur (distribution company) 8% stake in N.A.

Distrilec Invesora

SA, 

Citicorp Capital Investors United States Edelap (distribution) part of consortia holding $139 (total for Edelap)

51%

CMS Energy ......... United States Hidroelectrica Arroyito (hydroelectric generation) N.A.

Central Termicas Mendoza (gas-fired

generation) 41% $1.6 (plus $6.5 debt)

Central Termica de San Nicolas (coal- and

gas-fired generation) 0% $66 (total for San b

Central Hidroelectrica El Chocon, S.A., Nicolas)

(hydroelectric generation) 18%

Edeersa (generation & distribution) 36% $0.3 (plus $41.1 debt)

La Plata (gas-fired generation under

construction) 100% N.A.

$75 

Community Energy United States Eden (distribution) 30% $188 (for both Eden &

Alternatives .......... Edes (distribution) 30% Edes)

Compania Chilena de Chile Central Puerto (gas-fired generation) 20.2% $31.0 (later increased

Distribucion Electrica V (later increased to 29.3%) to $45.4)

Region (Chilquinta

International Inc)., .....
Table C1. Foreign Companies’ Investments in Argentina’s Electricity Industry, as of 1997 (continued)

Company Headquarters Investment (million)

Country of Amount of

Incorporation/ Investment

Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 105

Compania Chilena de Chile Central Puerto (gas-fired generation) 30.7% $47.6 

Generacion Electrica Edessa (distribution company) 34%

(Chilgener) ........... Piedra del Aguila (hydroelectric generation) $26.1 

15.8% $89 

Consumer’s Energy Co. United States Central Termica de San Nicolas (coal- and N.A.

gas-fired generation)

Dominion Resources, United States Central Alto Valle (gas-fired generation) 60% $13.3

Inc., ................. Central Cerros Colorados (gas-fired generation)

50.2% $23 (plus $116.4 debt) 

Duke Power .......... United States Central Guemes (gas-fired generation) 15% $2.5 (plus $19.1 debt)

Hidroelectrica Piedra del Aguila, S.A.

(hydroelectric generation) 19.7% $33 (plus $57.4 debt)

Transener (transmission) 9.8%

$4.5 (plus $30.6 debt)

Electricite de France . . . France Distro Cuyo, S.A., (transmission) 21% $8.3

Edenor, S.A. (distribution) $6 (plus $79.6 debt)

Hidroelectrica Diamante, S.A. (hydroelectric $2 (plus $14.4 debt)

generation) 29.5%

El Paso Energy ....... United States Agua del Cajon (gas-fired generation) 16% $157 

Endesa de Chile ...... Chile Buenos Aires S.A.(gas-fired generation) N.A.

Central Termoelectrica (__-fired generation)

Central Costanera (oil- and gas-fired generation) N.A.

30%

Central Dock Sud (oil- and gas-fired generation) $45

90%

Edesur (distribution) 5% $350, including

planned expansion

through year 2000

$3 (plus $48.1 debt) 

Endesa de España .... Spain Edenor, S.A. (distribution) 5.1% $3 (plus $39.8 debt)

Yacylec (transmission) 22.2% N.A.

Enersis S.A. .......... Chile Central Costanera (oil- and gas-fired generation) $13.5

30%

Edesur (distribution) 10% $100 

Edesur (distribution) 64% (directly and through $390 

Chilectra)

Edenor, S.A. (distribution) $200 (including new

distribution lines)

Entergy Corp., ........ United States Central Costanera (oil- and gas-fired generation) $11.3 (by entire

part of consortium holding 7.5% consortium)

Transener (transmission) 9.8%

Edesur (distribution) 5%

$4.5 (plus $30.6 debt)

$50 

Houston Industries .... United States Edelap (distribution) 25% $2.5 (plus $65.7 debt)

Hydroelectrica de Spain Edenor, S.A., (distribution) 10.2% $6 (plus $79.6 of debt)

Ribagorzana, S.A.

Iberdrola ............. Spain Central Guemes (gas-fired generation) $2 (plus $15.3 debt)
Table C1. Foreign Companies’ Investments in Argentina’s Electricity Industry, as of 1997 (continued)

Company Headquarters Investment (million)

Country of Amount of

Incorporation/ Investment

106 Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Kansas City Power and United States Central Costanera (oil- and gas-fired generation) $23.4

Light . . . . . . . . . . . . . . . . 6%

LG and E Energy Corp., United States San Miguel (gas-fired generation) $18 

Tucuman (gas-fired generation) $13.3 

Louis Dreyfus Argener, United States Hidroelectrica Cerros Colorados (hydroelectric $4 (plus $9.8 debt)

S.A. generation) 9%

Merrill International .... United States Ave Fenex, S.A. (gas-fired generation) $100 (total for Ave

Fenex)

National Electricity Co. of Chile Central Costanera (oil- and gas-fired generation) $600 ($120 for the

Chile . . . . . . . . . . . . . . . . 24% plant and $480 for an

El Chocon (hydroelectric generation) 43% expansion of capacity)

N.A.

New World Power ..... United States Rio Negro (wind and diesel-fired generation) 15-year contract

signed to finance,

build, and own plants

Northeast Utilities ..... United States Ave Fenex, S.A. (gas-fired generation) $100 (total for Ave

San Miguel (gas-fired generation) Fenex)

$18 

PSI Energy ........... United States Central Costanera (oil- and gas-fired generation) $ 91 

part of a consortium holding 60%

Edesur (distribution) 4%

$40 

Repsol Spain Central Dock Sud (oil- and gas-fired generation) N.A.

3.7%

Sociedad Austral de Chile Energia de Rio Negro (distribution) part of $97.8 (total)

Electricidad consortium holding 90%

Societe D’Amenagment France Edenor, S.A., (distribution) 5.1% $3 (plus $39.8 debt)

Urbain et Rural

Southern Company .... United States Central Hidroeléctrica Alicurá S.A. (hydroelectric $3.8 (plus $104 debt)

generation) 47%

d

Transalta Energy ...... Canada Central Hidroelectrica Piedra del Aguila, S.A. $33 (plus $57.4 debt)

(hydroelectric generation) 19.7%

e

Western Resources United States Central Costanera (oil- and gas-fired generation) $23.4

6%

 AES converted San Nicolas to a gas-fired generator. See Friedland, Jonathan and Benjamin Holden, “Utility Deregulation in a

Argentina Presages Possible U.S. Upheaval,” The Wall Street Journal Interactive Edition (June 19, 1996).

 CMS sold its share of San Nicolas to its partner AES. See Friedland, Jonathan and Benjamin Holden, “Utility Deregulation in b

Argentina Presages Possible U.S. Upheaval,” The Wall Street Journal Interactive Edition (June 19, 1996).

 British Gas and its partners sold Central Dock Sud for a total of $1.3 million less than 4 years after purchasing it. See c

Friedland, Jonathan and Benjamin Holden, “Utility Deregulation in Argentina Presages Possible U.S. Upheaval,” The Wall

Street Journal Interactive Edition (June 19, 1996).

 Southern has committed to spend $301.7 over the initial 9 years of its 30-year concession for Central Hidroelectrica Alicura. d

 Transalta currently values its investment in Hidroelectrica Piedra del Aguila at $36.5 million, which was written down at year e

end 1996 from $39.4 million.

 Sources: Annual reports to shareholders and various public news sources
Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 107

Table C2. Organization of Argentina’s Federal Electricity Industry, 1991 and 1997

1991 1997

Enterprise Description Enterprise Description

Servicios Electricos del Gran generation and distribution Agua del Cajon 382 megawatt gas-fired power

Buenos Aires company serving the Buenos generation facility near

(Segba) ................ Aires/La Plata area, which Neuquen

includes more than one-third

of the country’s population. Central Costanera 1,260 megawatt oil-and

gas-fired power generation

facility

Central Dock Sud 211 megawatt oil and

gas-fired power generation

facility

Central Pedro de Mendoza 58 megawatt oil- and gas-fired

power generation facility

Central Puerto S.A. 1,009 megawatt gas-fired

power generation facility

Central Termoelectrica 220 megawatt gas-fired power

Buenos Aires S.A. generation facility

Compañía de Transporte de created by combining the

Energía en Alta Tensión Red transmission assets of Segba,

(Transenor) Ayee, and Hidronor; owns and

operates the high voltage (500

kilovolts) segment of the

transmission system serving

14 (of 24) Argentine

provinces; and owns and

operates a regional 220 kilovolt trunk transmission system

Segba . . . . . . . . . . . . . . . . . . Empresa Distribudora distribution company serving

Electrica Norte (Edenor) northern Buenos Aires

Empresa Distribudora distribution company serving

Electrica Sur (Edesur) southern Buenos Aires

Empresa Distribudora distribution company serving

Electrica de la Plata (Edelap) la Plata

Compania de Agua y non-Buenos Aires/La Plata Agua del Toro 150 megawatt thermal

Energia Electrica (Ayee) . . . generation and national generator

transmission company, also

oversaw Argentina’s interests

in the Yacyreta hydroelectric

plant joint-venture with

Paraguay

Cabra Corral 102 megawatt hydroelectric

generator

Central Alto Valle 165 megawatt gas-fired

generator in the province of

Neuguen (700 miles

southwest of Buenos Aires)

Central Guemes 245 megawatt gas-fired

generator located in the Salta

Province (northwest

Argentina)

Central Sorrento 226 megawatt thermal

generator (specific fuel not

known)
Table C2. Organization of Argentina’s Federal Electricity Industry, 1991 and 1997 (continued)

1991 1997

Enterprise Description Enterprise Description

108 Energy Information Administration/ Electricity Reform Abroad and U.S. Investment

Central San Nicolas 650 megawatt coal-fired

generator (since converted to

gas-fired)

Ayee ................... Centrales Termicas del Litoral, 94 megawatt thermal

S.A. generator (specific fuel not

known)

Centrales Termicas Mendoza 135 megawatt gas-fired

generator (expansion to 406

megawatt underway)

Centrales Termicas del 241 megawatt thermal

Noreste Argentino generator (specific fuel not

known)

Centrales Termicas del 214 megawatt thermal

Noroeste Argentino, S.A. generator (specific fuel not

known)

Centrales Termicas 254 megawatt thermal

Patagonicas, S.A. generator (specific fuel not

known)

el Cadillal 13 megawatt thermal

generator

el Tigre 14 megawatt hydroelectric

generator

Escaba 52 megawatt hydroelectric

generator

Fataluefu 448 megawatt hydroelectric

generator

Ayee ................... Hidroelectrica Ameghino 54 megawatt hydroelectric

generator

Hidroelectrica Arroyito 120 megawatt hydroelectric

generator

Hidroelectrica Diamante 388 megawatt hydroelectric

generator

Hidroelectrica Los Nihuiles 260 megawatt hydroelectric

generator

Los Reyunos 236 megawatt hydroelectric

generator

Pueblo Viejo 15 megawatt hydroelectric

generator

Rio Grande 750 megawatt thermal

generator

Rio Reyes 7 megawatt thermal generator

Sociedad Del Estado 145 megawatt gas-fired

generator
Table C2. Organization of Argentina’s Federal Electricity Industry, 1991 and 1997 (continued)

1991 1997

Enterprise Description Enterprise Description

Energy Information Administration/ Electricity Reform Abroad and U.S. Investment 109

Ullum 45 megawatt hydroelectric

generator

Yacyreta partially completed 3,200

megawatt hydroelectric

power generator joint venture

by Argentina and Paraguay

Transener transmission company

serving the country with the

transmission assets formerly

of Segba, Ayee, and

Hidronor

Hidroelectrica Norpatagonica hydroelectric generation Central Hidroelectrica Alicura, 1,000 megawatt hydroelectric

S.A. (Hidronor) ........... company operating in S.A. generator

southern Argentina

Central Hidroelectrica Cerros 450 megawatt hydroelectric

Colorados, S.A. generator

Central Hidroelectrica El 1,320-megawatt hydroelectric

Chocon generator

Hidroelectrica Piedra del 1,440 megawatt hydroelectric

Aguila, S.A. generator

Pichi Picun Leufu 252 megawatt hydroelectric

generator

Transener transmission company serving

the country with the

transmission assets formerly

of Hidronor, Segba, and Ayee

Comision Nacional de national nuclear energy Conea conducts nuclear research 

Energia Atomica (Conea) . . agency, created in 1950 to

conduct nuclear research,

oversees the operation of

nuclear power generation

units and regulates the

domestic nuclear industry

Nucleoelectrico Argentina S.A. oversees and operates

Argentina’s 2 completed

(Atucha I and Embalse) and 1

under-construction (Atucha II)

nuclear plants

Nacional Nuclear Regulatory domestic nuclear regulatory

Authority (Enrn) agency. Will continue its role

after privatization of the

nuclear generation facilities

Comision Tecnica Mixta de Binational commission Salto Grande 1,800 megawatt hydroelectric

Salto Grande (Ctmsg) . . . . . overseeing the Salto Grande power generator joint venture

hydroelectric plant by Argentina and Uruguay

joint-venture with Uruguay

Sources: WEFA; Argentine Ministry of the Economy, http://www.mecon.ar/invest/energy/prim.htm (July 1, 1997); Electric Utility

Week (various issues); Privatization (various issues); and Latin American Power Watch (various issues)
110 Energy Information Administration/Electricity Reform Abroad and U.S. Investment 

Table C3. Organization of Argentina’s Provincial Electricity Industry, 1991 and 1997

1991 1997

Enterprise Description Enterprise Description

Empresa Social Electrica de vertically-integrated electric Piedrabuena thermal generator, near Bahia

Buenos Aires (Eseba) ..... utility serving the province of Blanca (specific fuel not

Buenos Aires known)

thermal generator, near Mar

del Plata and Necochea

(specific fuel not known)

Empresa Distribuidora de distribution company serving

Energia Norte S.A. (Eden) the northern part of the

province of Buenos Aires;

based in San Nicolas

Empresa Distribuidora de distribution company serving

Energia Sur S.A. (Edes) the southern part of the

province of Buenos Aires;

based in Bahia Blanca

Empresa distribution company serving

Distribuidora de Energia the Atlantic part of the

Atlantica province of Buenos Aires;

based in Mar del Plata

Servicios Energetics del electric utility serving the Servicios Energetics del distribution company serving

Chaco .................. province of Chaco Chaco the province of Chaco

Empresa Provincial de electric utility serving the Epec distribution company serving

Energia de Cordoba (Epec) province of Cordoba the province of Cordoba

Empresa Social Electrica de electric utility serving the Empresa Distribuidora de distribution company serving

Entre Rios (Eseer) ........ province of Entre Rios Entre Rios, SA (Edersa) the province of Entre Rios

Energia de Mendoza, S.A. vertically-integrated electric Distro Cuyo transmission company for the

(Emse) ................. utility serving the province of western Andes provinces of

Mendoza Mendoza and San Juan

Emse distribution company serving

the province of Mendoza

Patagonia .............. vertically-integrated electric Transportadora Argentine transmission company for

utility serving the province of Northwest Company mainline distribution for

Patagonia (Transnoa) Patagonia, the provinces of La

Pampa, Neuquen, and Rio

Negro

Transportadora Patagonia transmission company serving

(Transpa) the province of Patagonia

Empresa de Energia Rio electric utility serving the Empresa de Energia Rio distribution company serving

Negro .................. province of Rio Negro Negro the province of Rio Negro

San Juan ............... electric utility serving the Distro Cuyo transmission company for the

province of San Juan western Andes provinces of

Mendoza and San Juan
Table C3. Organization of Argentina’s Provincial Electricity Industry, 1991 and 1997 (continued)

1991 1997

Enterprise Description Enterprise Description

Energy Information Administration/Electricity Reform Abroad and U.S. Investment 111

Empresa Distribuidora de distribution company serving

Electricidad Sanjuanina S.A. the province of San Juan

(Edessa)

Empresa Provincial de electric utility serving the Empresa Provincial de distribution company serving

Servicos Publicos de Santa province of Santa Cruz Servicos Publicos de Santa the province of Santa Cruz

Cruz ................... Cruz

Empresa Provincial de electric utility serving the Epe distribution company serving

Energia de Santa Fe (Epe) . province of Santa Fe the province of Santa Fe

Dirección Provincial de Tierra electric utility serving the Dirección Provincial de Tierra distribution company serving

del Fuego ............... province of Tierra del Fuego del Fuego the province of Tierra del

Fuego

Hidroelectrica Tucuman . . . Vertically-integrated electric El Cadill 13 megawatt hydroelectric

utility serving the province of generator

Tucuman

Escaba 24 megawatt hydroelectric

generator

Pueblo Viejo 15 megawatt hydroelectric

generator

Distribudora Electrica de la Distribution company serving

Tucuman (Edet) the province of Tucuman

Sources: WEFA; Argentine Ministry of the Economy, http://www.mecon.ar/invest/energy/prim.htm (July 1, 1997); Electric Utility

Week (various issues); Privatization (various issues); and Latin American Power Watch (various issues).

Table C4. Argentine Power Generators Built Since 1991

Are Fenex, S.A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168 megawatt gas-fired power generator near the city of

Tucuman

Comodoro Rivadavia ................................ Gas-fired power generator in the area of Patagonia

La Plata . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120 megawatt gas-fired power generator in the province of

Buenos Aires

San Miguel ........................................ 114 megawatt gas-fired power generator in San Miguel (north

central Argentina)

Sources: WEFA; Argentine Ministry of the Economy, http://www.mecon.ar/invest/energy/prim.htm (July 1, 1997); Electric Utility

Week (various issues); Privatization (various issues); and Latin American Power Watch (various issues)