The concept of efficiency and its measurement are contentious. Hence, the option for the route of introducing a more competitive environment, and to consider whether this might prove a more effective approach to improving the electricity industry’s performance; is of considerable importance.
Productive Efficiency
Productive efficiency addresses the question of whether a firm produces a given level and quality of output at minimum cost. The main conclusions on productive efficiency related to the varying performance records of electricity must compare the unit costs incurred by different regions of a country and finding substantial variation in unit expenditure. After making allowance for differences between regions relating to geography and the profile of market demand, then it can be concluded that if the performance of the less efficient regions could be raised to that of the more efficient regions then expenditure savings could be achieved. There is therefore some evidence to suggest limited productive inefficiency on the one part. The main focus of attention is, however, on allocative efficiency.
Allocative Efficiency
Economic theory suggests that to achieve optimal resource allocation prices should be set at a level equal to marginal costs, given certain conditions. Consumer choice between substitutes will direct the output paths of different products.
There are, however, two central problems which need to be addressed before using this approach as a criterion against which to judge the efficiency of an electricity company’s pricing policy. The first problem is that marginal cost pricing is optimal only in circumstances where marginal cost prices are charged in closely related sectors. It is not at all clear, according to the second-best principle, that marginal cost pricing in a non-marginal cost pricing world is the preferred option. This result depends in practice crucially on the pricing of closely related products and their substitutability.
Evidence on elasticities suggests that, at least in the short run, the second-best consequences may be containable. Furthermore, the major substitute – renewable electricity – is required to set prices on the basis of marginal costs (at least in principle), and oil has an active spot market. Other energy sources may also be moving tentatively in the direction of marginal cost pricing.
The second major problem with marginal cost pricing lies in the implementation of the principle. Where the firm (or industry) has the optimal capital stock, short-run and long-run measures of marginal cost are equivalent but an estimate needs to be imputed of marginal costs in such circumstances. Calculating the long-run marginal cost (LRMC) for energy involves particular difficulties. These include, first, that each source of energy has its own associated unit costs and characteristics; second, that future discoveries of supplies are uncertain; third, that different types of customers have different associated costs of supply. The method of calculation that is typically employed is to estimate the cost of energy extraction from a recently developed field. The cost of supply from the Liza field could be used for this purpose.
The estimation of LRMC cannot therefore be precise; but this does not mean that the concept is inappropriate as a criterion. The efficiency of Guyana’s charging policies can be assessed against the criterion in two respects – in relation to the level of prices and in relation to the structure of prices charged in different markets.
1)Â Â Â The Price Level
Though prices could be sufficient to cover the average costs of supply in all markets served, prices must generally be below those necessary to meet costs of supply using the most recently contracted sources of energy (a measure of the level of LRMC). The reason for the divergence between average costs and LRMC (measured in this way) will be a consequence of the nature of the early energy contracts.
2)Â Â Â The Price Structure
To achieve allocative efficiency in the structure of charges, prices in different markets should be related to any differences in the marginal costs of supply. Three aspects of potential differential prices can be identified: the prices charged to different types of customer, prices charged at different times of the year (peak demand pricing), and the prices charged to customers located in different geographical areas.
- domestic, non-domestic tariff, firm industrial and interruptible: companies usually sell energy at less than the marginal cost of supply (as measured by the actual cost of imported fuel) in all market sectors except the interruptible industrial market. Charges to domestic and firm industrial customers are still below estimated LRMC by a margin of between 12 and 17 per cent (Price 1984). An interruptible contract provides that the customer will reduce the demand on being given specified notice by the utility company; the tariff charged is lower than for firm industrial contracts because the company is effectively able to avoid some peak-related expenditure.
- Another aspect of pricing structure – geographical cost differentials: the potential size of these indicate that the total marginal cost of transmitting power to the parts of the country furthest away from the beach-head supplies are substantially higher than the costs of transmitting power to customers located close to beach-head supplies. Hence, a uniform price structure will not reflect this important source of differential costs.
Thus, there are considerable evidence to suggest that present charging structure is characterised by allocative inefficiency. The level of prices is considerably adrift from estimated LRMC, and the structure of pricing fails to represent adequately the separate costs of supply to different customers at different times of the year and in different parts of the country.
The potential for improving the allocative efficiency of a utility company’s charging structure by relating charges more systematically to marginal costs depends critically upon customers’ response to changes in the charging structure. If demand is highly inelastic then changes in prices will have little impact upon consumption patterns or resource use. Evidence on elasticities suggests, however, that the demand for energy is not highly inelastic.
This indicates that revising tariffs to reflect more closely the marginal costs of supply will have an impact upon consumption patterns and upon resource use. Raising the level of charges to nearer the level of marginal cost will slow the rate of depletion and conserve energy resources. Rebalancing the structure of charges between markets will, for example, enable expenditure undertaken to match seasonal peaks in demand to be reduced. The size of the company’s current investment in the local market will indicate the level of resources being deployed to meet peaks in demand. The scope for improvements in allocative efficiency could therefore be substantial. Thus, how effective different options for a privatised electricity industry might prove to be in realising these potential benefits.
Options for Privatisation
The crucial question to address now is whether the incentives inherent in a privatised energy industry will improve on this situation. Will the new post-privatisation structure do any better? The answer to this question depends on the degree of competitive pressure which is introduced (in the product market or in the capital market) and on the type of regulation adopted. The approach to this issue is to consider a number of different options for a privatised electricity industry. The efficiency properties of the various solutions must be examined. Considered possible sources of competition and the mechanism by which different incentive structures would work. Crucial variables of importance here are the effect of ownership structure on consumer prices and on cost levels. Also, consider whether significant economies of scale or scope might be sacrificed by particular options for restructuring. Some activities, in particular the transmission and distribution networks, appear to be characterised by natural monopoly such that a single firm will be able to produce the industry’s outputs more cheaply than a combination of several firms; the emergence of several competing suppliers in such an industry is therefore generally inefficient (Sharkey 1982).
Restructuring of the energy industry can be considered in terms of both vertical and horizontal separation (Webb 1984). Horizontally, the distribution network in each part of the country can be separately owned, as can the National Transmission System (NTS) and the existing contracts for power supply. Vertically, ownership of the distribution networks can be separated from the buying and selling of power. This yields three basic options for a restructuring of the local power company:
- an integrated private sector monopoly;
- regionalisation – separate regional companies (responsible for both the transmission system and supplying power to consumers), a separate company operating the NTS, and separate ownership of the existing contracts for power supply;
- vertical separation – restructuring of the distribution network as in option (2), but with many separate companies supplying power to consumers.
Private Sector Monopoly
A privatised energy corporation which could retained the national company’s near monopoly in the distribution and supply of electricity would face competition only from other sources. However, evidence on demand elasticities indicates that this competition would be very weak in the short run; and even over a longer-term horizon cross-price elasticities with other energy sources are not very high. The transfer of a national company to the private sector without any change to its current structure will therefore leave the privatised corporation with significant market power and will not increase the incentives to efficiency provided by the product market.
The change in ownership structure may provide different incentives in the capital market, however. In principle the most immediate change will be the substitution of a diffuse objective function imposed by the statutes governing the corporation (and implemented by the respective regulatory agency) by a more narrowly defined one of profit maximisation. It is important to note, however, that the degree to which profit maximisation is actually pursued after privatisation is far from clear. In practice the national company is likely to face little realistic threat of bankruptcy or take-over; the utility company’s size and specialist resources will make take-over especially difficult. Shareholders may be too loosely distributed to enforce their objectives and managers may have considerable freedom, in practice, in determining which policies to pursue.
The impact of an adverse movement in share price is likely to be confined to the effect on the cost of raising capital and the scope for pursuing strategies of diversification. To the extent that a privatised corporation does, however, pursue a policy of profit maximisation, this may be expected to have effects upon the level of prices, upon the structure of prices, upon the productive efficiency of the corporation, and upon social or distributive concerns.
Greater orientation toward profit maximisation may provide some incentive to restructure tariffs and to reduce uneconomic cross-subsidisation between markets. It may also provide incentives to improve productive efficiency. Pursuit of profit maximisation may therefore yield improvements in both allocative and productive efficiency.
However, the economic theory of monopoly suggests that under this market structure, there will be an incentive to set prices in excess of marginal costs. Indeed, the rationale for nationalisation is to prevent monopoly pricing, with the legislation requiring that supply be provided at the lowest cost to consumers. Thus, while public ownership attempts to provide safeguards by replacing overall rules – such as profit maximisation – with more precise pricing and allocation rules, a private sector profit maximising monopoly can be expected a priori to raise prices against an inelastic demand to levels which exceed marginal cost.
However, the extent to which prices will be greater than marginal cost depends on the pricing strategy and time profile of profit maximisation. A long-run profit maximiser in a situation where market share shows a degree of long-run elasticity could in the short run either set a higher price, achieving higher profit and falling market share, or a lower short-run price, and thus lower short-run profit and rising market share (Scherer 1985). In the case of energy, the market share strategy is important since consumers have to make substantial fixed capital expenditure on energy-consuming equipment.
Raising prices to levels above marginal cost could be contained by regulatory control. Nonetheless, experience in other countries (in particular the US) indicates that regulated private monopolies may frequently be less productively efficient than corresponding public enterprises (Millward 1982).
A private monopolist will have less incentive to provide consumer information (unless this is commercially worthwhile) and to retain less profitable ‘high street’ advisory functions. The incentives to consider safety issues may be changed to wholly commercial considerations and there will be incentives to pursue more rapidly the disconnection of indebted customers. However, these concerns, if considered material, appear readily susceptible to regulatory control (the specification of safety standards for electrical goods or motor vehicles provides one possible model).
Changes to the level and structure of prices will also have distributional consequences. It could be argued that a general government transfer to the poor is preferable to an artificially low particular price (because of substitution effects) although this argument is premised on the assumption that such compensation takes place.
In summary, privatisation of the local energy sector in its present form will at best provide only weak incentives to improved efficiency. There will be no change in the incentives provided by competition in the product market. Additional incentives will result from any re-orientation in objectives towards profit maximisation. However, the size and market power of a privatised company means that this re-orientation is unlikely to be significant in effect.
