Energy Information Administration
Introduction
The
Structure of UK Electricity Prior to Privatization
The
England and Wales Power Pool
RPI-X:
Price Caps Versus Rate of Return Regulation
The
Sale of UK Electricity
Electricity
Investment Activity
Electricity's
Relationship to UK Natural Gas Privatization
Privatized
Electricity: A Performance Appraisal
The United Kingdom (UK) offers an interesting case study into the process of electricity industry restructuring, privatization, and regulatory reform. The United Kingdom was one of the first nations to embark upon widespread privatization of its electric utilities. Although a growing number of nations have privatized their electricity industries since (or are currently undertaking such efforts), the UK's electricity privatization reform efforts have been among the world's most ambitious and path breaking. Several other nations have subsequently followed their example, using the UK experience as a policy guide in their own electricity restructuring, privatization, and regulatory reform efforts. In particular, Argentina and Australia have adopted variations of the UK model (as will be discussed in Chapters 3 and 4 ).
Electricity privatization in the United Kingdom has occurred in the larger context of the privatization of much of the formerly state-owned UK industries and the diminution of the central government's role in the national economy. The overall privatization of industry was initiated shortly after a conservative government came to power in the United Kingdom in 1979 under the leadership of Margaret Thatcher. A primary aim of the new administration was to reduce government's role in the economy. This goal has clearly been achieved. The share of employment accounted for by state-owned industries fell from 7 percent of total UK employment prior to privatization to less than 2 percent currently. 1
Partly due to the fact that the electricity industry strongly reflects the features of a natural monopoly, electricity was among the last and more controversial privatizations. British Aerospace was the first large industry to be auctioned off in 1981, followed by Cables and Wireless (1981), and by British Telecommunications (1984). Soon afterwards, British Gas (1986), British Airways (1987), British Steel (1988), and British water utilities (1989) were privatized. More recently, British Coal was privatized in 1995, and British Rail in 1996. As of 1995, the United Kingdom has raised over $95 billion through privatization. 2
Electricity privatization and reform got off to a relatively late start in the United Kingdom, having its origins in the passage of the UK's Electricity Act of 1989. The industry was initially restructured by the government along functional lines. Guiding the government's restructuring was the idea that electricity generation and marketing 3 could be made competitive industries, while transmission and distribution needed to be treated as natural monopolies for the indefinite future. 4 Regulation would therefore gradually be withdrawn for the former segments but remain for the latter. For the still regulated segments, a new form of regulation (based on a price cap) was introduced--along with a new regulatory authority, the Office of Energy Regulation (OFFER). On Vesting Day (April 1, 1990) a newly-created electricity industry emerged.
The creation of a national wholesale electricity pool was another important area where the United Kingdom charted new ground in electricity reform. As in the United States, a major complication surrounding electricity reform in the United Kingdom was how to allocate the financial burdens associated with stranded costs. Stranded costs in the United Kingdom resulted largely from earlier investments in nuclear power and an overhang of high-priced coal contracts.
Although UK electricity reforms are not yet a decade old, some general assessments can be made regarding their performance. In terms of efficiency, the reform of the electric industry in the United Kingdom is generally viewed as a success. By any measure, the current industry is markedly more efficient than it was prior to privatization. However, where issues of fairness and equity are concerned, the industry reforms have been controversial. The new system has been criticized for unfairly and disproportionately benefiting industry shareholders and corporate executives over taxpayers, rate payers, and electricity industry employees. The auction of electricity assets to the general public was criticized for failing to obtain the full value of the assets offered for the treasury. Further, a large share of the industrys' efficiency gains was realized through massive workforce reductions. The fact that the heads of the newly-privatized companies were awarded substantial pay raises in the midst of these workforce reductions added to the controversy. 5 Although electricity prices have generally trailed inflation in the intervening years since electricity reforms were implemented in 1990, electricity consumers have often felt less well treated than industry shareholders, who have realized profits well beyond those reported for UK industry in general over the same period of time.
Privatization of electricity in the United Kingdom did not occur all at once. It evolved. The following sections describe important developments and trends in the UK electricity industry--from its fruition in the last century, through the period of nationalization, and up to the current period of industry restructuring, regulatory reform, and privatization. The problems encountered during the period of nationalization are discussed first, followed by a discussion of what has transpired since recent reforms were undertaken.
The central government's role in electricity has grown gradually since the industry's beginning in the latter part of the nineteenth century. The Electricity Lighting Act (1882) allowed the central government to break up streets for laying of electrical cable. The national government established an Electricity Generation Board in 1926 whose mission was to construct a national transmission grid, to coordinate the transmission of electricity across the country, and to establish a set of common technological standards. 6
In 1947, the electricity industry--long with several other "key" industries--as nationalized by the UK's post-war labor government. All segments of the industry became government owned and operated. So the newly-nationalized electricity company comprised most of the country's generation capacity, the national grid, as well as the 12 semi-autonomous regional distribution boards in England and Wales, two vertically-integrated companies in Scotland, and one vertically-integrated company in Northern Ireland.
The role of central government in electricity was extended further with the Electricity Act of 1957. This act established a Central Electricity Generating Board (CEGB) whose responsibilities included control over the operation of electricity generation and transmission facilities and all related investment decisions. The twelve regional electricity boards remained semi-autonomous. An Electricity Council acted as a form of regulator. The council consisted of three representatives of the CEGB, the twelve regional Area Board Chairmen, and six independent members, appointed by the presiding governing Minister. 7 The regulatory method used employed an inexact and controversial measure of long-run marginal cost in order to construct a bulk supply tariff, the price charged to the distribution companies by the CEGB.
Between 1947 and 1990--the period of nationalization--the two major competing national ruling political parties pursued various and often conflicting energy policies. Often electricity policy directives were guided by some overriding macroeconomic objective. 8 For example, during the 1970's, the ruling labor party put pressure on the electricity industry to restrain prices in order to reduce general inflation. During the 1980's, after the conservative party took power, the industry was urged to increase prices in order to reduce public borrowings. Several currency crises and two oil price shocks encouraged the 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 industry--which by the early 1990's had grown vastly inefficient by world standards. Beginning in 1957, in an attempt to support the coal industry, utilities were continually pressured to purchase set quantities of British coal. Eventually, a more formalized arrangement emerged whereby utilities were required to purchase set amounts from the nationalized coal industry at predetermined prices. Since electric utilities were required to pay above world prices for British-produced coal, electricity prices became excessively high, and the British coal industry in essence became dependent on the electricity industry for its survival.
Another major policy goal of the UK government since the 1950's was the promotion of nuclear power as a secure and economical source of electricity. Nuclear power has also generally been a target of large government-imposed subsidies, again underwritten by the electric utility industry. As elsewhere in the world, when the United Kingdom embarked upon its nuclear power program, nuclear power was perceived as an economically viable form of energy and as a means of achieving energy security. In reality, nuclear power's full costs have far exceeded the costs of non-nuclear forms of electricity generation.
In the 1960's and 1970's, several attempts by the government at reforming the electricity industry were made. However, due to both a lack of commitment and to political turnover, these efforts largely proved unsuccessful. By the 1970's, the United Kingdom experienced several economic setbacks, many of which were attributed to an excessive state role in the economy. A growing disappointment with the general quality of services provided by nationalized companies, along with the nationalized companies' growing financial difficulties, greatly diminished UK public perception of the viability of several state-run industries. At the time, many state-owned companies approached financial insolvency involving several costly government bailouts.
The election of the Thatcher government in 1979 marked a major watershed in British politics and economic policy. Privatization became an important element in the Thatcher government's overall economic program. Privatization of nationalized industries was intended to achieve several goals. Foremost among them were to reduce the central government's role in economic decision making; to force privatized companies to become more accountable to owners; to increase net state revenue through asset sales and divestiture of fiscally draining state enterprises; and to encourage the creation of a shareholder society through widespread stock ownership.
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 independent power sector did not occur until several years later. Initially, the low rates of return that the CEGB allowed incumbent power producers discouraged entry of new producers. 9 Further, the 1983 Electricity Act did not entirely remove the unfair access to the grid that incumbent power producers had over new entrants. 10 The evolution of a UK independent power production industry--along with the complete transformation of the UK electricity industry as a whole--would await passage of an omnibus piece of electricity legislation which followed six years later.
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 was the larger of the two generation companies and accounted for 46 percent of electricity supplied in England and Wales in the 1990/1991 fiscal year time period ( Table 2 ). 13 At the time, PowerGen accounted for 28 percent of generation output. 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 to be a separation between the wires (distribution) side of the RECs' business (which was to be continually regulated) and the marketing function of the RECs (which was to be gradually deregulated). The RECs were also the first segment auctioned off to the public by the UK government. 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.
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.") No specific price regulation was initially intended for generation, as the pool was intended to produce market-based pricing. However, although OFFER's mandate was not to set pool prices, it had considerable influence over National Power and PowerGen through its authority to refer cases involving monopolistic behavior to the Monopoly and Mergers Commission (MMC). Concerns over whether the generation business was sufficiently competitive and was behaving as a duopoly caused OFFER to intervene several times after privatization. 15
In December 1993, a sharp increase in electricity pool prices prompted OFFER to reduce market concentration in electricity supply by negotiating an agreement with National Power and PowerGen whereby the two companies would use their best efforts to sell off 6000 megawatts of generating capacity--roughly 15 percent of the companies' combined capacity and 9 percent of total UK electricity generation capacity. This objective was met by both companies during the following year. Further, in February of 1994, OFFER proposed a cap on pool prices 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." 16 At the 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." 18 The 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 Manweb. Apparently, due to Scottish Power's geographical location, its acquisition of Manweb posed less of a threat to competition than the takeover attempts occurring in England proper. The other acquisition involved Hanson's purchase of generation assets from National Power and PowerGen, shortly following Hanson's purchase of another REC, the Eastern Group. 19
An important means of leverage the government retained over the electricity industry after privatization was exercised through its "golden share" in the two power generation companies and the twelve RECs. Since Vesting Day (April 1, 1990), the government had restricted any single private entity's ownership in the two generation companies and the twelve RECs to a maximum stake of 15 percent. For the RECs, the government's "golden share" expired in March of 1995. The government's "golden share" in the generation companies was extended in March of 1991, and in May of 1996 the government indicated that it would retain its "golden share" in the two power generation companies indefinitely.
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).
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 the NGC in December of 1995, thus making the NGC a separate company under the new name, National Energy Group PLC.
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 regulated through an RPI-X form of price regulation. The franchised 20 marketing portions of the RECs' business segments were to be regulated in a similar fashion, albeit with a different productivity factor ("X") and a different regulatory time frame. On Vesting Day, the government provided the RECs with price caps ranging from a high of zero to a negative "X" of 2.5 percent. Negative "X" (that is, an apparent allowance for annual rates of productivity decreases of X percent) factors were chosen in order to provide the industry with sufficient future cash flow in part to meet projected future investment needs and also to increase the attractiveness of the companies to the investment community during their upcoming public auction. The initial regulatory timeframe was set at the fiscal year 1990/1995 time period.
Since privatization, the distribution companies have been allowed to acquire generation assets with the restriction that no REC generation facilities account for more than 15 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 newly-created 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 ). 21 The RECs were allowed 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) 23 in April of 1998.
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 company unaffiliated with their local REC. As of 1996, 39 second-tier suppliers have entered the market. These second-tier suppliers include several RECs operating outside of their franchised distribution territories, as well as the newly-created electricity marketing units of the two privatized generation companies, National Power and PowerGen. Due to concerns relating to maintaining competition, however, the generators (as well as the RECs) were required to establish separate marketing units.
It appears that deregulation has given rise to greater competition in the marketing end of the electricity market. In the aftermath of the opening up of the industrial market to competition, the newly-formed second tier suppliers have made substantial inroads into what had been a captive market for the RECs. Since Vesting, the second-tier companies have seen their share of the large industrial market climb from 43 percent in the 1990/1991 period to 69 percent in the 1995/1996 period ( Table 5 ). This occurred despite the fact that marketing costs for the large industrial customers are very small relative to the costs of generation ( Table 6 ) Newly-formed marketing companies have also made substantial gains in the 100 kilowatts to 1 megawatt market. In the mid-range commercial and small industrial company market, the second- tier companies' share has risen from 30 percent in the 1994/1995 fiscal year time period to 43 percent in the 1995/1996 fiscal year time period.
Another area of continued regulation of the retail electricity business in the United Kingdom concerned services standards. Although services provided by the electric industry in the United Kingdom were generally considered reliable even prior to reform, higher quality of service standards were placed on the industry by OFFER during the initial privatization phase. These standards were later tightened in 1993 and 1994. RECs are required to offer various special services to the elderly and disabled. Service standards also were directed to bill payment, meter reading, and speedy responses to complaints.
It is not clear whether the second-tier marketing companies will be as successful at encroaching on the RECs' share of the residential market as they were in the large-to-mid-level user market. Even though marketing costs to residential users (unlike industrial and commercial users) account for a relatively large portion of their overall electricity bill, the residential market is expected to be a more difficult market to break into. This is largely due to the high estimated costs (such as in advertising) which would need to be incurred to encourage small consumers to switch suppliers. With unbundled electricity rates, different classes of consumers face different price schedules. For instance, industrial users have a tendency to face a cost structure where the share of generation costs relative to total costs far exceed that of smaller users. In contrast, residential and mid-level users face disproportionately higher distribution and marketing costs. The transmission cost portion of final electricity bills tend to be uniform across all classes of consumers.
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 attempts to measure the "extent to which generators are prepared to invest in additional capacity in excess of the actual maximum on the system." 25 The LOLP simply measures the probability that supply will be insufficient to meet demand at a particular point in time.
The LOLP changes over the course of the year and the course of the day. The closer demand is to scheduled supply, the higher the LOLP and therefore the higher the 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. 27 , 28 According to these allegations, 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 electricity purchaser reimburses the generator for the difference. In reality the CfD market uses a variety of different hedging contracts. Contracts for differences are purely financial contracts; however, in terms of hedging pool prices, they cover more than 90 percent of the electricity traded in the pool 30 . Nonetheless, pool prices have still continued to be a source of controversy.
In February of 1994, in response to a sharp run up in pool prices in April of 1993, OFFER issued its first report on pool pricing activity. The report called for a two-year price cap and required National Power and PowerGen to sell off 6000 megawatts of generation capacity. Since February of 1994, OFFER has issued five reports on pool pricing . 31
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 monopolies 32 to restrain output, raise prices, and realize supra normal profits. In theory, the way the two regulatory methods accomplishes these goals differs considerably. In practice, however, the methods have tended to converge.
Rate-of-return regulation is also called cost-of-service regulation in that it essentially allows companies to pass through those costs which are deemed necessary by the supervising regulatory body to ensure that an adequate level of service is provided to end users. During periodic regulatory reviews, expenditures that are deemed appropriate by the regulatory body are added to the rate base. In order that appropriate levels of capital investment are undertaken, supervising regulatory bodies (in the United States, these are generally State public utility commissions) estimate appropriate rates of return for the regulated utility, based in part on the cost of capital to the utility.
Rate-of-return regulation has both its virtues and its weaknesses. Rate-of-return regulation allows representation of the public in matters regarding utility price setting, rates of return, and investment so that utilities cannot restrain supply and realize monopoly profits. However, rate-of-return regulation offers utilities few financial incentives to aggressively restrain or reduce operating costs. 33
Price-cap regulation has been the common means of regulation for the recently privatized industries in the United Kingdom. For several reasons, rate-of-return regulation was rejected in the United Kingdom. For one, obtaining detailed industry data was deemed an excessively expensive effort that would require a large bureaucratic structure. Further, it was felt that regulators would always suffer from a disadvantage, given that any information the regulator obtained from the regulated industry was always incomplete relative to the information possessed by the industry, leaving the regulator in an inferior negotiating position relative to that of the industry. Moreover, as stated earlier, rate-of-return regulation offered insufficient incentives for the utilities themselves to reduce costs aggressively.
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.
In essence, RPI-X employs price caps which allow individual utilities (or companies) discretion over all investment and operating decisions. In contrast to rate-of-return regulation, utilities in the United Kingdom realize all gains from efficiencies achieved beyond the established benchmark up until the next regulatory review. RPI-X regulation has not only been employed in the electricity sector but also has been applied to the recently privatized telecommunications, natural gas, and water industries. For expository purposes, a generalized form of RPI-X price- cap regulation works the following way:
Let us suppose t is our base year and pt are electricity prices in the base year. The RPI in RPI-X regulation represents the change in the retail price index in the United Kingdom and is a measurement similar to the Consumer Price Index (CPI) in the United States. X is generally considered to be a productivity factor, which could be positive if the industry is expected to operate more efficiently in the future, or negative if efficiency declines are expected. 34 The productivity factor, X, is based upon past performance and projected analysis of future productivity gains. 35 A third variable (let's call it K) could be added to the equation to account for all costs over which a regulated company had no control (exogenous costs), allowing, for instance, an electricity company to directly pass through all costs related to changes in energy prices (making our new equation, assuming efficiency gains, RPI-X+K). Thus, maximum prices one year hence (Pt+1 ) should equal: pt+1 = pt + RPI-X+K. RPI-X regulation employs a multi-year review cycle. In the United Kingdom, depending on the industry being regulated, the review cycle has typically been from 3 to 5 years. This allows companies to realize the benefits of their cost reduction efforts over a set period of time, or until the next review cycle comes due. Upon completion 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 non-franchised marketing are in general freely determined in the marketplace.
The chosen base price in the United Kingdom was directly related to the asset value at the beginning of the initial regulatory period. The selected productivity factors tended to vary across segments of the industry, with the transmission companies assigned an initial X of zero. For the twelve distribution companies, various X's were applied, varying from zero to a positive top rate of plus 2.5. The franchised supply companies were assigned an initial X of zero. The regulatory cycles for the three regulated industries have varied from 3 to 5 years.
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 36 . The other 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). 37 The visibility of a single national 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 government was also attempting to maximize the value of these companies for a successful initial public offering. Lower future electricity prices would have meant lower immediate gains to the treasury during the public auction of electricity industry assets.
A second problem involves estimating future productivity gains. In practice, this has proven to be a rather problematic process in the United Kingdom. In order to achieve the desired allocation of the future benefits achieved through realizing greater industry efficiency gains, the regulator would still need detailed knowledge of the industry and future market developments in order to come up with a suitable initial price and projected future productivity gains. In addition, X would represent not expected future productivity gains, but rather some theoretical cutoff rate for electric utilities to have an incentive to surpass in order to retain all of the cost reductions benefits that accrue beyond X.
Thus far, in terms of economic efficiency, RPI-X has been a clear success. In the United Kingdom, the RPI-X regulatory approach has induced cost reductions well beyond expectations. Electricity companies have been able to greatly reduce operating costs in large part through substantial work force reductions. As intended, the electricity industry has benefited financially because these cost reductions have made substantial contributions to the bottom line results. However, substantial controversy has surrounded the new form of electricity regulation. In particular, some dissatisfaction has arisen over whether the efficiency gains (the economic rents) have been equitably distributed between the industry's stakeholders, i.e., investors, labor, and consumers. As a result of this controversy, several of the basic tenets of RPI-X pricing have become suspect.
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. 38 In the United Kingdom, public flotations 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.
However, in the United Kingdom, the flotation was also conducted to further yet another goal--shareholder democracy. Certain shares were reserved for small UK shareholders in order to induce more widespread ownership of industry among social classes. Restrictions on ownership (especially during the early stages of privatization) were also employed to allow the national government to retain some influence over future corporate governance.
Another government goal during the flotation was to achieve a timely sale since privatization lacked a clear national consensus and a change in government might lead to its reversal. The conservative government was determined to complete the privatization process as soon as possible in order to discourage any future successor labor government from slowing down or reversing the process. The performance of earlier sales of major UK industries also influenced the method of electricity industry sell off. Some earlier company sales, notably British Gas and British Petroleum, had been viewed as less than a success. 39
An overriding issue in the privatization of electric utilities in the UK concerns the tradeoff between equity and efficiency. Whereas economic efficiency in electric power generation is relatively easy to define in theory, achieving social equity through privatization becomes a somewhat subjective, but clearly not trivial matter, in privatization's perceived success and public support. In the United Kingdom, much political controversy surrounded the initial public auction of the electric distribution companies. Again, this related to whether the treasury obtained fair value for the companies sold.
Privatization got underway in late 1990. The RECs were the first segment of the industry to be sold in December of 1990 with their shares being sold for $11.6 billion. 40 Fifty-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 8.4-percent dividend yield. On Vesting Day shares of the RECs soon began trading on the London stock exchange and the values of these shares rose sharply. Although it is common in initial public offerings of privately-owned 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. 41 The proportion of 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 sales stood at 49 percent, and foreign investors' shares at 23 percent (10 percent of the foreign share went to investors from continental Europe, 6 percent to Japan, 5 percent to the U.S., and 2 percent to Canada).
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. 42 The generation 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. 43 None of the five newly-created generation subsidiaries of the regional distribution companies were allowed to have more than a 1-percent stake in the newly-privatized NGC.
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 Industry announced in May of 1996 that it would retain its share in National Power and PowerGen indefinitely. 44
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 recently-privatized distribution companies. There was also wide-scale 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.
Since the expiration of the government's "golden share," all of the twelve UK distribution companies and one power company have been takeover targets ( Table 8 ). 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. 45 Both NORWEB and 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.
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. 47 Similarly, a consortium led by PowerGen purchased 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 coal-fired 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. 51 Several RECs have also invested abroad. The Energy Group purchased Citizens Power, of Boston, Massachusetts, for $120 million. 52 Midlands Electricity, another REC, is investing 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.
Natural gas has played an important and growing role in UK electricity {Figure 6}. Between 1989 and 1995, coal production in the United Kingdom fell by half, while natural gas production increased 74 percent. Britain's move away from coal-fired electric power towards natural gas power is the result of rapidly changing prospects for both of these UK industries. The closure of uneconomic coal mines in the United Kingdom coincides with increasingly available natural gas supplies that have come onstream in the North Sea. Improvements in the efficiencies of combined cycle natural gas turbines used in electricity generation provided added demand. Environmental concerns and pollution abatement laws have also promoted the switch to gas because coal burning has long been a major contributor to air pollution in the United Kingdom.
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 53 a year) to seek alternative sources of marketing. The initial group consisted largely of Britain's industrial users of natural gas. In August 1992, users of natural gas in excess of 2,500 terms (primarily commercial demand) were allowed to bypass British Gas in favor of other suppliers. Both actions greatly diminished British Gas' share in the market for industrial and commercial uses. The final stage of privatization, which began in 1995 with the enactment of the Gas Act of 1995, is currently being implemented.
The Gas Act of 1995 set out the framework for competition in the residential gas market. Following passage of the Act, the UK initiated a free market experiment in natural gas distribution by allowing a half-million residential and small business consumers in three southwestern counties to choose their natural gas suppliers. Previously, the sole supplier of natural gas to these markets had been British Gas. This pilot program is intended to provide a testing 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 newly-opened 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.) These developments may eventuate in the creation of a residential energy service industry in the UK with a variety of single service (e.g., natural gas only or electricity only) and mixed service (e.g., electricity and natural gas) companies. Such a residential energy service industry would be markedly different from the past structure of Britain's electric power and natural gas distribution structures, when two single companies (the CEGB and British Gas) were the sole, but separate, providers of these services.
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. 54 However, between 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.
Prior to the privatization of electricity, the cost of domestic coal to electric utilities far exceeded the cost of coal traded in international markets. For a variety of political and economic reasons coal has assumed a special place in the UK's economy and polity ever since the UK entered the Industrial Revolution. Between 1984 and 1985, the UK experienced a year-long coal mining strike--an event which would subsequently significantly reduce the political influence of the UK coal miners' union and the long-term viability of the industry. At the time, Margaret Thatcher was the prime minister, and conservative governments in the UK had long had a confrontational relationship with the coal miners' union. However, the strike additionally served to alienate much of the nation 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.
In 1990 (during the creation of National Power and PowerGen), the UK government renegotiated its contract with British Coal so that both the volume of purchases and the price declined over 3 years. During the first three years after privatization, generators were required to purchase a set quantity of British coal at set prices; however, both prices and quantities of coal were to be substantially reduced over the contracted period. In turn, the generators could still pass on these higher prices, but only to the regional electricity companies' franchised market. Expectations at the time saw coal imports taking up the slack.
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 alterations56 . The 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. 57 Furthermore, when British Coal 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. 58 In 1988, coal (on a 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. 59 Coal 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
Much of the reduction in coal consumption has been made up for by a greater dependence on natural gas. The demise of the British coal industry is closely interlinked with both the privatization of electricity and the developments in the UK's natural gas industry. Prior to the privatization of natural gas, natural gas use in electricity generation was discouraged. 61 Furthermore, after British Gas (the former state-owned natural gas monopoly) was privatized, the UK natural gas market grew more competitive, leading to ample supplies and reduced prices. The natural gas share of utility fuels rose from 1 percent in 1988 to 17 percent in 1995. By 2010, natural gas is expected to 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
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. 64 Several foreign (and mainly U.S.-based 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 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 14,738 megawatts of new generation capacity scheduled to be completed by the end of 1996 in England and Wales. 65 For the RECs, the combined cycle natural gas turbine provided the quickest means of entry into the power generation business.
Natural gas and IPPs have grown hand in hand in providing future growth in the UK's electric generation capacity. In the 1990/1991 fiscal year time period, the IPPs accounted for roughly 1 percent of the UK's electricity generation capacity. By the 1995/1996 fiscal year time period, the IPPs increased their share of total UK generation capacity to 15 percent and are expected to account for 21 percent of this UK capacity by the 2000/2001 fiscal year time period ( Table 2 ).
In the seven years since privatization began, the UK electricity industry has clearly become more efficient. In 1995, the United Kingdom produced 8 percent more electricity than in 1988. 66 Between the 1989/1990 and 1995/1996 fiscal year timeframes, employment in the UK electricity industry was reduced by roughly fifty percent ( Table 11 ). Reductions in prices as a result of the periodically scheduled regulatory reviews clearly had an impact on later price reductions to electricity consumers. Although consumers have generally experienced lower inflation-adjusted electricity prices since privatization, ( Figure 7 ) indicates that gains to larger consumers have generally exceeded those to households.
However, other factors have also played a role in retail electricity price reductions. Prior to Vesting Day, UK 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
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. 68 The initial (and current) director is 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. 69 This regulatory approach has 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 structured regulatory watchdog counterparts in the recently-privatized UK natural gas industry (OFGAS), the recently-privatized UK telecommunications industry (OFTEL), and the recently-privatized UK water industry (OFWAT).
The 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. 71 There is no 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, has substantial political influence. The Office of Fair Trade, whose purpose is to promote and safeguard economic interests of consumers, also has a say in electricity industry matters. Further, the Department of Trade and Industry has some influence over electricity regulatory 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.
Issues of fairness and equity have dogged performance-based ( 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. 74 Several variations of the 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 ). 76 However, during the first three years of 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 (Figure 7 and Figure 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 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. 78 Further, when public concerns over industry profitability induces unscheduled industry reviews, RPI-X may in reality approximate rate-of-return regulation--just by another name.
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." 79 Since assuming office, the new prime minister has proposed a windfall profits tax on recently privatized public utilities. 80 The fact that the new 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.
