Silviase/jgov_v1.4_full_ann huggingface dataset:
requires an initial definition and allocation of capacity rights. Where transmission owners have private information about the network and this forms the basis of market power, it is doubtful whether a truly unbiased capacity definition and allocation process would or could occur. It is difficult enough without private information to define capacity in a electricity transmission network. Where private information is ubiquitous, the prospects are dim. For reasons such as this, as well as concerns over the efficiency of dispatch, Hogan has recently argued for a broader pooling structure in wholesale markets to implement node pricing (Garber, Hogan and Ruff, 1994).

### D. Evaluation

The three generic approaches to transmission pricing outlined above can be expected to have different implications for industry performance. In this section we evaluate these approaches by four criteria to assess their relative merits.

#### D.1. Efficient Dispatch

The existing institutions in the U.S. provide for reasonable efficiency in the utilization of generating resources. This is accomplished in the “business as usual” scenario by central dispatching of units within a utility’s control area. Regional transmission groups could preserve centralized dispatching, as demonstrated by the operations of existing power pools. Node pricing implicitly assumes centralized dispatching. Without efficient dispatch, node prices are unreliable indicators of transmission costs.

Clumsy regulatory intervention may have more potential to cause harm than improvement in the utilization of existing assets. The mandated access policy carries the greatest risk in this regard. If mandated access results in a pattern of generation that displaces efficient production with inefficient production, then it is not clear whether the net effect is positive.

#### D.2. Reliability

The existing bulk power system was built with reliability objectives in mind. As wholesale trade has increased, there is a perception among power engineers that the safety margin has declined. To a large degree, reliability in the bulk power system is a coordination problem. The interconnectedness of the network means that many real time actions are required to control or contain disturbances that may originate locally, but propagate throughout the system. While new technology is increasingly available to improve response time and automate coordinated response, this is offset by increasing the number of entities involved in managing or using the network.

The transmission policies are differentiated along this dimension in much the same way as they are with regard to efficient dispatch. Regional transmission groups are capable of maintaining a high level of reliability. Mandated access could cause some stresses by overloading particular links, or failing to require sufficient emergency co-ordination obligations. Node pricing
#### D.5. Summary

We summarize this discussion in Table 10 where we rate the policy alternative by high performance (H), medium (M) or low (L).

Table 10. Rating Transmission Pricing Approach on Key Criteria

Criteria
Efficient Dispatch	Reliability	Choice of Service Quality	Efficient Investment
Regional Transmission Groups	H	H	H	M-H
Centrally-Mandated Prices	M	M	L	L
Node Pricing $ ^{*} $	H	H	L	L

* Assumes central dispatching

### I II. Retail Competition

The Energy Policy Act explicitly excludes transmission access for retail customers. It delegates to the states authority over the decision to allow such access. In April, 1994 the California Public Utilities Commission (CPUC) put forward a proposal to allow for competition of this kind (CPUC, 1994). Since that time a number of other states have initiated similar activities, although as of the time of this writing none of these has reached any conclusions.

The principal motive for retail competition is high electricity prices. This is cited prominently in the CPUC order, and in the literature of advocates for retail competition. For industrial customers paying $ 7\phi9B/kWh $ or more, there are many attractive opportunities at prices ranging from $ 3-5\phi9B/kWh $ . The short-term avoided cost in Southern California is currently about $ 3\phi9B/kWh $ (SCE, 1994). The long term prices in Table 8 are below $ 5\phi9B/kWh $ in the best cases; even less attractive projects would be priced at that level in the near term. Industrial electricity prices in the U.S. vary substantially by region. The states with rates at $ 7\phi9B/kWh $ or higher in 1992 include California, New York, Massachusetts, Arizona, Northern Ohio, and Northern Illinois. In most states, industrial prices are lower than $ 5\phi9B/kWh $ (see Table 4). In these areas retail competition has minimal potential.

If customers are allowed direct access to low cost electricity providers, there could be serious financial consequences for investor-owned utilities, and perhaps as well for customers remaining on their systems. The difference between the market price of electricity and utility rates makes a number of the utility's assets uneconomic. The magnitude of the stranded asset problem, and the policies concerning its disposition are the major questions facing retail competition proposals.
### A. Stranded Assets

The motivation for customers to seek alternative electricity suppliers is greatest where utility rates exceed opportunity costs by the largest margin. Most of the difference between rates and opportunity costs represents fixed obligations that cannot be easily reduced in the face of reduced utility demand. It is difficult to quantify the magnitude of this problem due to various uncertainties. Table 11 shows the estimates made by the Pacific Gas and Electric Company (PG&E, 1994) in response to the CPUC investigation.

Table 11. PG&E Estimates of Stranded Costs

($ Billions 1996 Present Value)

Competitive Price (1994 $)
3.2¢/kWh	4.0¢/kWh	4.8¢/kWh
PG&E Generation	12.4	5.1	0.6
QF Contracts	4.0	2.9	2.0
Regulatory Assets	1.2	1.2	1.2
Total	17.6	9.2	3.8
PG&E Generation: Proposed Settlement	6.3	1.0	0.0
Revised Total	11.4	5.1	3.2

This table shows the substantial sensitivity of stranded costs to the estimated competitive market price. In all these calculations, that price is assumed to increase at an average rate of about 5% annually over a twenty year period. Additionally, the table reflects a proposed settlement that PG&E has made to reduce the cost of its most expensive asset, the Diablo Canyon nuclear plant. This proposed settlement amounts to reducing shareholder returns, thereby reducing the amount of stranded costs that customers would have to bear. The magnitude of rate impacts associated with stranded cost recovery depends upon the time period over which these costs are spread. PG&E estimates that the maximum rate impact could be as much as 23% in the case where the competitive price were the lowest of those shown in Table 11 and the recovery period were 6 years. Extending the recovery period to 12 years under the same assumptions reduces the rate impact to about 7%.

Further reductions in retail prices would need to come from price concessions by private power producers. Their prices are protected by contracts rather than the kind of regulatory bargain existing between utilities and state authorities. Therefore, these prices are likely to be less responsive.

The regulatory assets category includes a wide range of items, mostly involving costs incurred by utilities whose recovery has been delayed by agreement with state regulators. In some
jurisdictions these include recovery of nuclear investment. There is considerable variation in the incidence of these costs (Fitch Investors Service, 1993). One significant deferred cost in this category is deferred federal taxes associated with large investment programs from the past. Federal tax policy has allowed utilities to take certain benefits during the construction and early operating phases of these projects. These benefits are due for recapture, unless they could be offset further by additional investment activities. In the current slow growth environment, where investment is substantially below historic levels (see Table 6), further deferral of these obligations is unlikely.

### B. Employment Impacts

To reduce costs in the face of retail competition, utilities have relatively few short term options. One which is likely to be exercised is reduced employment. U.S. utilities have been reducing their workforce in the past few years in anticipation of competitive pressures. These efforts are likely to increase substantially in the future. Data from the recent past is presented in Table 12 for major investor owned electric utilities and Table 13 for the ten largest companies (EIA, 1990;1995).

Table 12 shows that employment for the major U.S. investor-owned electric utilities represented in Table 12 was 12.7% higher in 1986 than in 1993. This sample accounts for about 99% of sales from the privately owned segment. The data show some effort to adjust labor requirements through the use of part-time employees, by the end of this period, adjustments in full-time employment have become dominant.

Table 12. Employment in Investor Owned Electric Utilities 1984-1993

Year	Number of Full Time Employees	Number of Part Time Employees	Total Employees	Total Employment Annual Change (%)
1984	484,088	20,867	504,955
1985	492,098	23,138	515,236	2.04
1986	493,129	23,151	516,280	0.20%
1987	478,977	29,391	508,368	-1.53%
1988	474,054	32,722	506,776	-0.31%
1989	475,066	19,837	494,903	-2.34%
1990	484,651	16,758	501,409	1.31%
1991	482,127	15,003	497,130	-0.85%
1992	466,253	14,752	481,005	-3.24%
1993	446,901	11,172	458,073	-4.77%
Looking at the ten largest U.S. investor-owned electric utilities, Table 13 shows a similar pattern on average, but with significant variation in individual cases. The very large employment reduction for Texas Utilities represents the end of a major construction program. This effect is absent in the other cases.

It is unclear how much further the employment reductions will go as a result of increased productivity. Compared to changes in employment levels in the UK, these are relatively modest, but the initial levels of labor productivity were much lower in the UK compared to the US (Yarrow, 1995).

Table 13. Employment in the Ten Largest Investor Owned Electric Utilities: 1988 and 1993

Utility	Total Employment 1993	Total Employment 1998	Percent Change 1988-1993
Pacific Gas and Electric	17,309	19,687	-13.74%
Southern California Edison	18,207	17,531	2.75%
Commonwealth Edison	18,757	17,716	5.55%
Florida Power and Light	13,058	15,018	-15.01%
Texas Utilities	7,560	12,486	-63.22%
Consolidated Edison	14,901	16,555	-11.10%
Houston Lighting and Power	9,581	10,949	-14.28%
Georgia Power	12,528	15,394	-22.88%
Virginia Electric and Power	11,971	13,585	-13.48%
Duke Power	17,677	19,429	-9.91%

### C. Other Effects

Retail competition will have other effects as well. If it results in lower electricity prices, which is generally believed to be the case, then the macroeconomic impact should be positive. Within the electricity sector, there are likely to be shifts of activity. Research and development spending will probably decline as utilities attempt to reduce all costs which are not fixed. Utility programs directed at demand-side management, which had been significant in some regions, are also likely to decline, for very much the same reason. The burden of stranded asset costs may well be disproportionately borne by small customers.

None of these potential effects within the sector are certain to occur, all raise
controversial issues, and are significant topics for political discussion. There is widespread interest in negotiating a compromise among the various interests, but no clear lines along which such compromises may be drawn.

### I V. Conclusions

Deregulation of the U.S. electricity sector is proceeding steadily, but unevenly. Competition at the wholesale level is increasing. Both the short term transactions market and the long term market for new capacity show vigorous new forms of entry and substantial downward pressure on prices. The central question of pricing transmission access remains unresolved.

Competition at the retail level is more controversial. Pressures for such competition are greatest where utility rates are high. The resulting stranded assets may be written down in the case of utility ownership. Where these assets are private power contracts, it is more difficult to anticipate whether and how the pressures may be resolved.

It is almost certain that competition at both the wholesale and retail levels will result in structural changes. The large number of investor-owned utilities is likely to decline further through consolidation. The viability of vertical integration is more uncertain. Given the predominance of private ownership, restructuring assets is costly and time consuming, because of the number of private and public claims that need to be satisfied.
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2. United Kingdom

# ELECTRICITY PRIVATIZATION IN THE UNITED KINGDOM AND ITS RESULTS

Colin ROBINSON

University of Surrey

and

Institute of Economic Affairs
### 1. A brief history

### 1.1 The nationalised period

The electricity supply industry in Britain was nationalised by the Electricity Act of 1947, as part of the sweeping programme of nationalising the ‘commanding heights’ of the economy carried out by the 1945-51 Labour Government under Prime Minister Clement Attlee.

Prior to nationalisation the industry had been regulated by the state almost from its beginnings in the late nineteenth century and the degree of regulation had grown in the interwar period. $ ^{1} $ In 1919, Electricity Commissioners, responsible to the Minister of Transport, were appointed and in 1926 a Central Electricity Board was established to construct and own an electricity grid; the Board could give directions to power station owners and the Commissioners could determine the price of electricity from power stations if the Board and the owners could not agree.

Nationalisation was seen at the time as the logical next step in this trend towards greater state involvement in the industry. The initial structure of the industry under nationalisation was a development of earlier regulatory schemes, designed to cope with what was perceived to be a rather complex industry. Most nationalised industries were run by a single corporation with Board members appointed by the responsible Minister. In electricity, however, there were a number of corporations.

Under the 1947 Act, a British Electricity Authority was created which took over generation and transmission and was the dominant force in the industry. It was responsible for raising finance after scrutinising the expenditure plans of the industry as a whole. Distribution was in the hands of twelve Electricity Boards in England and Wales and two in the south of Scotland. The vertically integrated Hydro Electric Board, established in 1943, continued to cater for the north of Scotland. The industry was given a monopoly of the public supply of electricity.

Electricity supply was reorganised several times in its nationalised period in the search for an effective structure. In 1955 the two Boards in the south of Scotland were amalgamated. But the most important reorganisation came in 1957 when the Electricity Act of that year established a structure for England and Wales which persisted until the industry was privatised in 1990. The 1957 Act created the Central Electricity Generating Board (CEGB), responsible for both generation and bulk transmission in England and Wales: the CEGB controlled the bulk of the industry's investment and was de facto its most powerful organisation. Twelve Area Boards took electricity from the CEGB's bulk supply points, then distributed and supplied it within their designated areas. An Electricity Council had somewhat vague policy-making and co-ordinating functions: it contained three representatives of the CEGB, the twelve Area Board Chairmen and six independent members.