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Electricity and the primary fuels: technology, market structure and prices.

only short periods. The RECs have therefore understandably been eager to balance their risks by concluding long-term purchase contracts (15 years) from the IPPs, whose market power to squeeze the RECs is negated by the fact that most IPPs are partially owned by their REC customers. The attractiveness of these contracts has been even greater because the primary fuel input and the technology involved are new--CCGTs; and because all the relevant peer group--all 12 RECs--are doing the same thing. If the decision turns out to be wise, bravo. If it turns out to be mistaken, 'well we all made the same mistake'. The Regulator has the role of helping to ensure that the ultimate consumer does not pay for any mistaken investment, but in the A sharp change of pace in energy policy

The last twelve months have seen much disputatious change in investment for electricity supply, in likely developments in the supply and distribution of natural gas, and above all in the coal industry. The Government's announced Review of policy for nuclear energy will soon begin. The outlook for policy on the North Sea oil and gas business, despite the 1993 Budget changes for profits taxation on oil exploration and extraction, is by contrast relatively calm--the disputes of the 1970s and 1980s on the use of North Sea benefits for the fiscal balance and the balance of payments has subsided, lost in larger macroeconomic problems.

This article concentrates on the changes in the ownership, methods of control, and technological developments in electricity supply; the economic and financial decisions that these changes have caused; and their effect on the coal industry.

The change of ownership and control of the electricity supply industry, although very new (beginning only in 1990), has been startlingly abrupt in form; and, as the last twelve months have shown, also in content. The revolution (it is not too strong a word) is not just for electricity--because the mix of primary fuels into electricity generation is now the crucible in which the relative shares of coal, nuclear energy, and gas will be determined. The change in the ownership, control and motivation of the electricity enterprises has coincided with other events to push the UK into the world lead in utilising a brand new gas-based technology for electricity generation, to surround nuclear development with a strongly negative aura, and to topple the UK deep mined coal industry over the final small cliff on its long decline towards a small subsidiary part in the fuel sector.

If these decisions on resource allocation are largely correct, the speed and vigour of their appearance is a triumph for the privatisation process. If they are largely wrong, or wrongly timed, they are of sufficient importance, and sufficiently 'basic' to the British economy, to constitute a grave error. The result is that energy policy, for the first time for fifteen years, is once again of some general economic importance: and the rules of operation of the electricity supply industry are at centre stage in the energy policy drama.

Table 1a and 1b and their accompanying charts give a quick snapshot of the energy sector in 1992. It measures fuels in tons of 'coal equivalent'--converted by standardised rules of thumb from their own original units of measurement, the test being the amount of crude heat that can be supplied. This is a poorly specified form of equivalence--nobody uses coal to run motor vehicles, and electricity (although it can produce heat for cooking or space heating) is mainly prized for its power to produce light or rotational force. Nevertheless, in electricity generation all primary fuels do compete, and their thermal equivalence is a key factor (although not the only one). A measure of equivalence of more immediate attraction to economists is money (prices or costs). Table 1a shows that although electricity provides only 17 per cent of total fuel sales in coal equivalent terms, it TABULAR DATA OMITTED TABULAR DATA OMITTED constitutes 51 per cent of money expenditure on fuel; per unit of thermal output, electricity is very expensive, but customers are happy to pay that high price to power their machinery, to light their offices, or even to boil a kettle.

The sector of the economy on which this article concentrates is the production, distribution and supply of 'energy'; for the most part, this term is defined so as to exclude petrol and so on for transport--it concentrates on the fuels measured in row 3 of Table 1b, and in Chart A. But if our focus were petroleum, or the North Sea, Chart A would be an inappropriate way to depict the main flows.

Row 4 of Table 1b shows the input of primary fuels to electricity generation. An important point to bear in mind that much (most) of the primary fuel is 'wasted'--it is dissipated or lost in the conversion process. The thermodynamic efficiency of conversion is closely related to the temperature differential between the operating temperature of the turbine and that of the 'heat sink' (the river or ocean) into which the waste heat is discharged--the larger is this differential, the greater is the efficiency of conversion. Hence the large gap reported in the table between the fuel input into electricity generation (131 mtce) and the output of electricity (42 mtce); 89 mtce is however somewhat of an overestimate of the heat losses in the UK--for instance, we import 'electricity' from France, not a slice of a French power station.

Ownership, technical change, performance

The search for a general policy framework for the fuel industries, considered as one interrelated group, became fashionable in the 1960s and 1970s (in the 1960s, 'Fuel Policy' was the usual term, reflecting a general innocence of and lack of concern with those global issues which are evoked by the 1970s title 'Energy Policy'); but the 1950s had already seen a number of large changes in the management structure, technological basis, and market shares of the individual fuel industries. The approach of the 1960s and 1970s (for Fuel as for Transport) was to analyse the sector as a whole. The 1990s have witnessed a certain reversion to the approach of the 1950s, in which the different component enterprises are treated separately, against a general market background. These shifts of approach in part follow British ideological fashion; but they have also been driven by developments in technology, by events in the world outside the UK, and by changes in the attitude of the public to particular industrial technologies and to rapid transformation of industrial structures in general.

Coal (whether used directly or as converted into electricity or gas) was almost as dominant in 1950 as a century before; but during the 1950s, without a great deal of fuss, coal began to lose much of its market to the actual enemy--oil, and to the potential enemy--nuclear energy. By the late-1960s, the main issue of fuel policy was clearly the extent, speed, and the management of, the decline of coal. A level of UK deep mined production as low as 40 or 50 million tons by the mid-1990s did not seem a bad guess for those who analysed the issue 25 years ago. Then, as now, the main question was the choice of fuel for electricity generation. In the mid-1960s, it seemed that UK coal could be driven out by coal imports, by liquid hydrocarbons (oil) and by nuclear power; in the 1990s it is coal imports and gaseous hydrocarbons that threaten further inroads on the share of coal, while (in the UK at any rate) nuclear power rests like a beached whale as the tide of belief in the early exhaustion of reserves of oil and gas ebbs away.

The productivity of coal getting in the UK has improved far faster than was expected 30 years ago, and appears likely to continue a fast rate of improvement; this process has of course been helped by the very rapid closure of geologically difficult collieries, but is high even after excluding that effect (H of C, para 19, reports an increase in output per man shift between 1987 and 1992 of 61 per cent, of which nearly half is attributed to improvements at existing mines). But competing technological developments, in coal extraction industries abroad, and in the design and operation of gas turbines, have denied British deep mined coal the benefits which its engineers and work force understandably believe themselves to deserve; this common result of freer trade and unfettered engineering ingenuity is familiar in manufacturing industry, but bewildering to those accustomed to long-term linear developments in technology.

The nuclear enemy is, by contrast, apparently now held at bay (except in the form of some electricity purchases across the Channel from French sources). Gas is far more plentiful, and far more efficient in electricity generation, than had been imagined. And the energy ratio, relating total fuel consumption (including petrol for transport) to changes in the GDP, has fallen much faster and further than had been expected; it was near unity in the early-1950s, and less than 0.6 today. At the time of the 1967 White Paper, there were plausible grounds for believing that the ratio might stay around 0.8 or 0.9. One reason for this downward trend is no doubt the persistence of relative prices for most fuels, to industry as well as households, which are 10 or 20 per cent above the levels of the 1960s, although far from the peaks of the early-1980s. But other forces are also at work, not directly connected with prices. The planners of the 1960s were correct in their general pessimism about coal, although sharply wrong in their detailed reasons.

But big shifts away from coal, and other important changes in resource allocation, occurred under the TABULAR DATA OMITTED structure of ownership and control developed during the 1950s. Some components of this story are, admittedly, to the discredit of the system of public ownership. We summarise in the next Section some of the extraordinary series of false starts with the second generation of nuclear power station, which were born of a triangular relationship between the state electricity monopoly (CEGB), the state nuclear energy lobby (AEA), and a shifting cartel of private industry. Perhaps we have now emerged successfully from 30 years of struggle and abortive expenditure: perhaps not.

Other important developments which matured in, or were born of, the publicly-owned industries of the 1950s were accomodated at least adequately, and sometimes rather well. The first revolution in the gas industry (the switch from coal to petroleum products as the feed stock for making town gas), and the foundations of the second (the conversion to natural gas, and the early exploitation of the North Sea) happened speedily and with complete technical success. The changes were facilitated by the cautious but adequate strengthening of the central body of the nationalised industry (Gas Council) at the expense of the Area Boards, as a result of timely government legislation. These were not trivial successes, either from an engineering or from an organisational standpoint; they required a measure of centralisation. They exploited proved technology in an effective way.

Similarly, in electricity generation, the huge 'cathedrals' of coal based plant, and some based on oil, were technically advanced and, from an engineering standpoint, kept close to the moving frontier of thermodynamically imposed limits on the efficiency of energy conversion. The integration of all available plant through the transmission grid, and the 'despatching system' for minimising system running costs, worked smoothly and satisfied many criteria familiar to economists. But even at the time, and more so with the benefit of hindsight, repeated construction and commissioning delays suggest strongly that the market structure that then existed inhibited the successful design, supply, and costing of new plant. The cathedrals were fine monuments, and had (so to speak) splendid acoustics, but were excessively expensive to construct. Such elements of failure may have stemmed from the system of ownership and control in place during the 1950s and 1960s, or they may be a feature of any complex task of civil engineering--for instance, the Channel Tunnel. Popular attributions of the blame for these faults, offered at the time, were the divorce of responsibility for design specification (in the hands of the CEGB as customer) from those responsible for construction, the system of 'Buggins turn' by which construction contracts were awarded to supposedly competing consortia, and a strong pattern of stop-go in the CEGB's ordering programme.

Oil supplies before 1973 were on several occasions disrupted by crises of supply associated with political events in the Middle East, with some consequences for costs. Despite these disruptions, Britain's policy of reliance on the world oil companies, although criticised from time to time, has never been shown to be at fault. The French and Italians would argue that this policy was substantially buttressed by the large British stake in BP and Shell, and (in the early part of the period) by a military presence in the oil producing countries; but it is hard to find real evidence for this. Certainly CEGB's budding taste for oil fired generation in the 1960s was reinforced by its conviction that it was buying in a market with a high degree of competition amongst sellers. It did not see itself as rushing from extreme dependence on the National Coal Board to dependence on a tight oil cartel.

The sudden rises in the price of traded oil in the 1970s seemed at the time to call into question most of the trends in government policy, and most of the investments that had been made by corporate and household users of oil products. The subsequent long decline in the real price of oil has not however restored petroleum to the position of residual supplier of fuel for steam raising that it seemed to be gaining in the 1960s. If we put aside the huge market for petrol spirit and Derv--that is, petroleum for transport uses--oil products will be no more important in the UK's energy usage in the last years of the century than will UK deep-mined coal. One reason for this change is that petroleum--particularly crude oil--is still significantly more expensive, relative to prices generally and also to other fuels, than it was in the 1960s Another reason is the perceived ready availability of low cost coal as a world traded commodity, which makes coal a more serious competitor for oil in the UK market. But perhaps the most important cause is the diversion of a larger proportion of the refined barrel of crude oil towards the far more profitable transport markets for gasolines, Derv, and the lighter distillates generally, and away from the heavy fractions suitable for burning under boilers. Important technological changes in the refining process, driven by the urgent hunt for profits in a vigorously competitive world market, have enabled a 'whitening of the barrel' which has sharply diminished the interest of the oil companies in the production of fuel oil for electricity generation.

The continuing fall in coal sales within the UK, and the somewhat faster contraction of the NCB's deep mined business, despite the painful and unpleasant strike of 1984, has been a rather well managed affair--well managed for the economy as a whole, and the coal mining communities. Use of coal for electricity generation actually increased by about 50 per cent between 1960 and 1986; what was lost was the general industrial and household market. Lord Robens, the coal baron of the 1960s (ex Labour Minister, ex trade union boss--a powerful and charismatic leader) was once described as 'a general who faced the enemy at the front of his army, cried 'forward', and walked steadily backwards'. In leading the retreat in this way he served his country and the mining labour force well. Several mineworkers' leaders, during the same period, deserve similar praise. Until 1972 this process was conducted without a major labour dispute, and in an important sense the 1974 strike was about macroeconomic policy, not about coal. The process of decline has been long and continuous, although during the period of very high oil prices it did slow down. Table 4 shows that, in the 15 years to 1975, output declined by 3 per cent per year, and during the subsequent 12 years the rate of decline accelerated only slightly. The contraction of the labour force was always faster than the decline in output, and it accelerated more sharply in the 1980s. The 1967 White Paper, a sign-post along this path to oblivion, was criticised at the time, with some percipience, not for ordering the decline, but for announcing it too explicitly. It has been, with the exception of the 1984 strike and the closing episode that started in summer 1992, a very British story, in a good sense of the term.

True, the central economic services of the NCB (led by Fritz Schumacher, later to excel as the high priest of low technology growth for poor countries) complicated the analysis by arguing, counter-intuitively that the geological development of any mine was an unpredictable random walk, and hence that we could never select the right mines to close (this argument is admitedly lent some implicit support by the very elastic 'supply curves' printed in the H of C Report,para.23, and by the Caminus study, page 43). But many closures did happen, and were rendered more acceptable by being attributed to the blind malevolence of natural forces. As to the effect of union power--productivity could perhaps have moved ahead, at key moments, more sharply, if management had been permitted a freer hand. And the relative wages of underground miners have, over a 40 year period moved ahead relative to the traditional peer groups, although during the most recent 20 years, for which the relevant statistics are available from the New Earnings Survey, there is little evidence of any further relative improvement of the position already reached in the early-1970s. But despite the evident signs of strong union power in the collieries, it would be hard to make the case that, in coal mining, the gap between actual and potential costs per tonne is much wider than comparable gaps in other parts of the British economy.

The new privatised structure for gas is now sufficiently well established (Sid bought his first shares in 1986) for research to be possible on the basis of published statistics, although none has been attempted for this paper. For the moment, until the Monopolies and Mergers Commission report during this summer on a reference made to them TABULAR DATA OMITTED by the industry's Regulator, British Gas is recognisably the same entity as it was a decade ago, despite the fact that the 'common carrier' obligation, now forced on the old British Gas main transmission line, has allowed some of the largest and juiciest customers to be tempted away from this well established, and toughly commercial, hydrocarbon trader. Prices to the domestic customer have, for a number of years, been held down by the regulatory formula 'RPI minus x'. This expression, invented for the control of the still publicly- owned post office in the 1970s, is designed to force real price reductions at a rate of x per cent per year, where x is a regulator's judgement of the potential rate of relative cost reduction offered by capital investment and technical change. Whether privatised status has allowed the regulator at OFGAS to be more severe than an old fashioned Minister of Power, or National Board for Prices and Incomes, is hard to judge.

Anecdotal evidence does suggest a sharp improvement in the performance of the service offered to domestic TABULAR DATA OMITTED TABULAR DATA OMITTED customers for gas. Costs of transmission and distribution during the last decade seem to have fallen more swiftly than in the past. In the gas industry, and more recently in electricity, sharp falls in employment suggest that a previously feather-bedded work force is now facing private sector practices. Regulation, if not competition, forces cost cutting. Some of this apparent increase in productivity is doubtless illusory, as work is contracted out (often on a labour-only subcontracting basis); but much must be real. Green and Newbery argue in a recent paper that, in reconstructing the regulatory regime for Gas, we have lessons to learn from Electricity, where vertical disintegration has been the rule. Perhaps we may even see a return to the old structure of the industry, with regionally based retail distribution networks; trunk transmission could be managed like the electricity grid; the corporate headquarters might virtually disappear. Certainly the oil and gas operators in the North Sea would be glad to get rid of their old adversary. And possibly the ordinary customer, who has benefitted from a firm centralised control in the two large technological changes in gas during the post-war years, might nevertheless find such a reversion attractive: we do not pursue this question here.

From the point of view of the domestic customer for gas, our 30 years experience of North Sea supplies have been pleasant. Much of the profit from the discovery and successful exploitation of the generosity of nature has been passed through to the final customer in the form of lower prices both by the original publicly owned industry, and also under privatisation. Changes in the regime of ownership have not changed that feature, although under public ownership some of the benefit also came to the general taxpayer, through the 'negative borrowing requirement' imposed on British Gas before privatisation, and from taxes on the North Sea suppliers. The taxpayer, as a result of the sale of British Gas in the 1980s, capitalised most of his potential stream of revenue from this source, perhaps at an excessively high rate of discount; but the consumer continues to benefit. A more corporatist regime, over the last 20 years as a whole, would have taken more of the benefit directly to the Treasury.

Environmental issues and nuclear energy(2)

The oil price increases of the 1970s gave rise to a widespread assumption that, at the turn of the century, the world would be faced by possible exhaustion of the cheaper forms of liquid hydrocarbon resources. Most people now regard this threat as postponed, by perhaps half a century at least; and even if gasoline for vehicles will cost far more in 2050 than it does now, the theory of natural resource depletion recommends strongly that mankind should take the cheapest sources first, and leave its grandchildren to pay a bit more in the future.

Moreover, the political threat posed by Middle East dominance of the market for world traded oil, although not abolished, is certainly in abeyance, the importance of oil in non-transport energy in the UK is now much lower than we expected 30 years ago, and traded natural gas is not dominantly an OPEC or Middle East commodity. Generally, the problem of 'shortages' is less urgent than it seemed 20 years ago.

Nevertheless, it perhaps makes sense that the OECD as a whole should continue to be cautious about energy use, and to encourage energy conservation, seeking non-fossil possibilities where they can be found.

Such caution is now reinforced by worries about the emission of greenhouse gases, and the consequential risk of global warming. Remembering how 'Club of Rome' fears about shortages were overplayed in the 1970s, most economists and many natural scientists are rightly sceptical of today's environmental concerns. Those observers (including the present author) who press for action now on greenhouse gases must acknowledge that we are singing the same conservationist tunes today in response to global warming risks as we sung 20 years ago in response to fears of shortages of cheap fuels. To some extent conservationists 'believe' in conservation, and merely select whatever rationale for that belief is currently popular. We must acknowledge that many of the relevant parameters in the global warming story (the role of the Antartic ice sheet, the role of ocean plankton as a CO2 sink, and so on) are not known or understood, and cannot be estimated from simple theory. They have to be carefully researched. Even if warming is to occur, we are not sure how large it will be relative to the normal fluxes. Palaeoclimatological research, based largely on ice core analysis, is already indicating very substantial fluctuations in average temperatures since the last ice-age, and the living

world has survived that experience (so far).

Nevertheless, CO2 emission is a source of concern, and coal/fuel oil combustion is the biggest CO2 emitter.The well balanced economist should be prepared to take global warming fears fairly seriously, and be prepared to recommend quite strong policies (mainly policies to maintain high prices in the final market) for the encouragement of 'energy conservation', particularly in space heating and motor vehicle design and operation. A general expectation that fuel costs, and gasolene prices, are trended upwards can give a continued push to actions by car manufacturers and households which probably are cost effective even at today's prices, but are unfamiliar and neglected by many economic agents with other more urgent concerns. And this reliance on the price mechanism can appropriately be reinforced by continued efforts to explain that, as Government campaigns in the 1980s put it, 'energy saving makes sense'--for instance, help could be given to the elderly to escape some of the pain caused by VAT on heating costs by reducing the escape of heat from roofs and walls.

Economists should also favour the spending of significant sums now as insurance policies against a future need to limit greenhouse gases sharply. The optimum 'insurance' package to purchase today is continuing research into those energy technologies which do not cause large greenhouse emissions, and continued investment to keep various forms of nuclear energy on the shelf as realistic options at short notice in the future. There is no way to achieve completely what has been called a 'no regrets policy' for green house gases--the insurance premium would be very high--but we can move reasonably in that direction.

This approach would be good for gas, which has more hydrogen and less carbon than other fossil fuels; and good for nuclear energy; but bad for coal.

Old fashioned pollution, by SOx, NOx, and so on, is not to be neglected. The traditional British refusal to give a damn about noxious emissions from large conventional power stations is now totally unacceptable. 'Clean Coal technology', to which the Flowers Commission on Energy and the Environment gave so much attention 15 years ago, could probably have been developed so that a new wave of coal fired generating stations could pass the environmental tests. But now no one intends to build such stations; and retrofitting such devices as flu gas desulphurisation is very expensive. This is a serious threat not just to British coal, but to coal imports as well.

Fells and Lucas provide, in three succinct pages, an excellent summary of events in UK nuclear investment over the last 30 years. They write from a slightly 'pronuclear' bias, but are frank about the remarkable series of reestimates of the true costs, and then the true true costs, and then the real true cost of generating nuclear electricity. The H of C Report, paras 107 to 131, provides a clear and painstaking unravelling of the recent numbers, and reveal many of the causes of misunderstanding, although there are still questions to explore: see bibliography. The Government is to undertake a Review of Nuclear Generation which will start, some months earlier than originally intended, later in 1993.

It would be best if those appointed as Reviewers were all very young. Anyone who has been even sporadically active in the field of energy engineering or energy economics since the 1950s will find, if he or she examines their own files, that they have been implicated in one or other of the cost reassessments that have so frequently been made. I have to admit that I have endorsed more varieties of nuclear plant than can be counted on one hand, and it is now apparent that all those endorsements were mistaken.

The full story is long and complex; the two summaries to which I refer above, and the book by Williams cited in the bibliography provide and excellent introduction. Here we need to explore a few key points, in the context of the central arguments of this paper.

Many (not all) scientists and engineers came, in the 1960s, to believe in nuclear power in the same sense as economists believed in growth or the market. It is not quite perpetual motion, but it certainly economises fuel inputs, and uses a readily available raw material. Apart from little local problems with radiation, it is free of all pollutants, and does not add greenhouse gases. Nuclear fusion (although not the currently available fission) would allow mankind to behave like the sun--what could be more natural? Some (but by no means all) of those scientists who have now lost their belief in fission, because of safety problems, and of the difficulties in handling the waste products from nuclear reactors, have come to believe instead in fusion (for our grand children). The recent successful fusion experiment with the Joint European Torus (JET) near Oxford did succeed in generating a wee drop of electricity; but it was a pilot experiment only, using far more energy than it generated--a huge coal-fired power station had to work quite hard to generate the input necessary to make the experimental fusion machine produce enough output to boil a domestic kettle. Some respected technologists believe that the fast breeder--a way of using for further generation of power the waste products from ordinary reactors--would be a better bet than fusion.

It is wrong for economists to laugh at the faith of some physicists and engineers in this high technology. We too live in glass houses. For what it is worth, I would certainly support continued substantial research expenditure in nuclear fusion. But the study of the history of nuclear electricity in the UK is likely to induce worries in the minds of economists who have not been involved in past errors, if only because most of the mess of the past has been about cost overruns, apparent industrial inefficiencies, and over confident economic assessments: if economists did not make the original mistakes, they lent their professional cachet to the various reports and assessments.

The whole process was driven by the hunch of the nuclear engineers and executed with excruciating delays by private and public construction teams. Technological options of a 'purely British' type were backed with large investments, and abandoned either too late (after much money had been wasted) or too soon (before they had time to succeed). Specifications, and indeed fundamental design features, were changed so often that economies from replication, or learning by doing, were never achieved. Above all, costs, and in particular costs of construction, proving, and safety, were badly underestimated. Table 2 shows, for instance, that we have never achieved the output from nuclear plant that the planners of 1967 believed would be delivered by 1975. The costs of actually producing nuclear electricity (in contrast to widespread, and widely believed, earlier estimates) have been revealed as relatively high, especially when future decommissioning costs which are brought into the calculation.

Economists should separate sharply three distinct questions for present decision:

1. Does it make economic sense to go on running the UK's existing stock of nuclear power units, instead of scrapping them and using coal or gas instead?

2. Does it make sense, say for the OECD world as a whole, to invest in more nuclear power, now?

3. Does it make sense for the UK to follow the average OECD pattern?

The answers we offer to those questions are Yes; probably Yes, on a modest scale; and possibly No.

1. Yes we should go on producing from the first generation Magnox and the second generation AGRs and possibly from the Sizewell PWR (which has not yet started to dispatch), because their avoidable costs are below those of alternatives. The H of C Committee are a little dubious about this, partly on grounds of fact, partly on grounds of analysis. The main point of contention concerns the contracts between the nuclear station operators and the eventual reprocessors of waste products--have these contracts transformed costs which are technologically avoidable into costs which are legally fixed or sunk? I believe there is a robust case for continuing, because the avoidable costs of using the existing plant are very probably lower than that of alternatives.

2. Yes, probably OECD as a whole should keep the technology going, with at least a continuing thin stream of investment: as an insurance, as a signal to oil exporters, as a risk diversifier. Nuclear technology cannot be pursued as if it were a military staff college 'Tactical Exercise without Troops'. The engineers have to cut metal, build plants, operate them, learn from the problems they encounter.

3. But perhaps the UK should not follow this general pattern, instead leaving it to the Japanese, the Koreans and the French to make the running: we have a sizeable tranche already, let us wait and see Sizewell running, and consider starting again early next century. It is true that we would risk losing thereby the skills and ability to play this game, but why should we not buy these skills from others, together with the many other advanced technologies that we treat in this way. To maintain our current membership of the club of those who continue serious investment in nuclear energy require a very high subscription, and the cost all falls on public expenditure! (Wise supporters of a continuing nuclear expansion are searching for some option that would attract private venture capital.)

The answers to questions 1 and 3 are further explored in Box B below on Nuclear Energy.

How does all this effect the market for coal? Table 5 suggests the answer: if today's nuclear output were cut, coal (not necessarily British Coal) would be the gainer. If everything asserted in this Section is correct, coal should not be helped in this way. But, if any of the key facts as stated here is wrong, if nuclear's marginal avoidable costs are higher than the H of C suggests, then there would be a clear case for trimming present nuclear output.

The primary fuel mix for electricity generation

A main characteristic of electricity generation is that capacity must be installed to meet system maximum demand--the half hour in mid-winter when demand is at its peak. Over a normal run of years, total annual sales are likely to increase in tune with increases in the system peak--that is, the load factor may remain fairly constant. The structure of retail prices can induce increases in the load factor. But, in any year, there will be a stock of generating plant much of which will not be utilised full time. The plant load factor, defined as the average hourly quantity of electricity supplied as a percentage of average plant capacity, was 47 per cent in 1991. A supply system needs to hold enough installed capacity to meet the estimated absolute peak, a margin for plant outage, and some additional margin for contingencies, usually expressed in some probabilistic terms. The system needs to solve:-

a) A short-term problem, of how to use the existing stock of equipment in an optimal way;

and

b) A long-term problem about the rate, and type of, investment in new plant.

Box A on electricity displays the new 'system' for solving these problems, and contrasts it with its predecessor, pre-privatisation. The new system is in fact very new, and much of what is said below contains predictions of how it will behave in the future, rather than a spot snapshot of 'today'. It is a system in the process of creation, and the Regulator, Professor Littlechild, is actively concerned in developing his arrangements, not just in managing the system as it now exists.

As regards the short-term problem, in the past it was the CEGB's task to use its capacity to meet demand in a way which minimised its costs. Today, all those who operate generating sets offer, for the year ahead, prices at which they are willing to sell in 'each half hour'. The Grid operators each day call successively each plant into operation when they need it to meet demand (no doubt, as in the past, they always keep a 'spinning reserve' ready for instantaneous use). Then the Pool price for electricity in each half hour is based on the system marginal price--the price originally quoted by the most expensive plant called onto stream in that half hour.
Table 5. Primary fuels for electricity generation, UK, MTCE(a)

 1960 1975 '1975'(b) 1986 1992

Coal 53 75 65 83 79
 (83) (67) (54) (70) (61)
Oil 8 22 20 10 11
 (13) (19) (16) (8) (8)
Natural gas - 3 - - 3
 (3) (2)

Nuclear/Hydro 3 13 37 24 31
 (4) (11) (30) (20) (24)

Imports from France - - - 2 7
 (2) (5)
Total 64 113 122 119 131
 (100) (100) (100) (100) (100)

TPEG 1975 = 100 57 100 |108~ 105 116

Note:

(a) Figures in parentheses are percentage terms.

(b) Projections of 1967.
Table 6. Net exports (+ve) of fuels: MTCE

 1960 1975 '1975'(a) 1986 1992

Coal +6 -3 +4 -8 -19
Petroleum -85 -151 -146 +84 +23
Natural gas Nil +1 Nil -18 -8
'French' electricity Nil Nil Nil -2 -7

Note:

In this table, petroleum trade includes all oil products,
including those associated with transport and petrochemicals.

(a) Projections of 1967.


For the future, the Regional Electricity Companies(RECs) are arranging to buy as much as a quarter of their needs on long-term contracts from new Independent Power Producers, and to meet only their residual demand by purchases from the big generating companies and Nuclear Electric, who together are the descendents of the old CEGB; many of these spot purchases are also transformed, through a process analogous to stock market deals in 'derivatives', into medium-term contracts between the big generators and the RECs. In 1993 almost all REC purchases still come from the big producers, but a big burst of investment, started about 18 months ago, will have changed the system markedly by 1996. The Grid company, owned by the RECs jointly, manage (in an engineering sense) the transmission of almost all electricity, including that which will in future come from the Independents. It also manages, by a system akin to the old CEGB despatching programme, the selection of plants (owned by the big generators) from which to purchase electricity in any given half hour. As we have noted above, the Grid is bound to take stipulated quantities of electricity from nuclear plants, and it is also committed to contractual use of French electricity; these commitments effectively override the general Grid practice of 'buying from the source which quotes the lowest price'.

The path of capacity creation for the future--part of the solution to problem b)--is now the result of a number of individual profit seeking decisions. The newly formed Independents, who encounter in this aspect of their work little interference from the Regulator, can invest in new plant, whether or not they have already secured long-term contracts for their product. The big generators can behave similarly, but it has also been assumed that their decisions will in part respond to the capacity reminueration payments paid mandatorily by their customers on a scale decided by the Regulator. It is the Regulator today who pays attention to the trade-off question--'how much is it worth to keep spare capacity available to meet the risk of unexpectedly high demand?' which in the past was a matter for CEGB and Minister, and sets the capacity payments accordingly.

It appears that the Regulator has not radically departed either from the analytical method or from the implicit evaluation of the losses from potential disconnection that moved his predecessors. But there does seem some considerable doubt as to whether the device which he uses to convey his views to the market--the capacity remuneration credits--can perform the desired function of stimulating an appropriate stream of investments. In the past, the Minister (having taken advice)issued orders. The aim now should be to 'post prices', so that individual profit seeking enterprises can react in the way they judge to be best for their own particular circumstances. For this purpose what are surely required are 'prices posted in the futures market'--that is, a promise about the capacity remuneration credits which would be paid in the future. From that point of view, today's system, which relies only on today's prices, seems very weak.

An alternative criticism is that the capacity remuneration is a redundant device--a fifth wheel to the coach. If there is likely to be a shortage of capacity in 1998, and that likelihood is perceived by individual generating companies (advised by the Grid's periodic forward look), then many of them they will invest because they anticipate high Pool prices at that time. Alternatively, such expectations of very high prices for peak half hours may attract generators who own old, nearly obsolete sets to keep them maintained and available for a few more years so as to take advantage of those high prices when they come.

These points are well explored in the House of Commons Energy Committee Report, 1992. My own conclusion is that, as soon as capacity problems begin to loom for the future, either as perceived in the Grid company's periodic reports or by outside observers, the Regulator's present armoury will need to be strengthened. To bring new large power plants on stream requires a long lead time (in the bad old days, as much as 10 years; today, perhaps 4 or 5 years). They tend to come in rather large 'lumps', although the new technology has diminished that tendency. For these two reasons, the Regulator may well need to influence the outcome more directly than he does at the moment.

But we have so far analysed only one aspect of capacity growth--its quantum, measured by its capacity to generate power. Another aspect of is the choice of technique which is embodied in the new equipment.

Today's rules force attention to the same criteria for choice of the optimum mix of generating plant as followed by CEGB in the past. Privatisation has changed the agency which is responsible for this decision, but has not itself changed the essence of the problem or the broad shape of the optimal solution. It is because of changes in technology that the outcome of the choice has dramatically changed; the effect of the change in ownership and control has, however, in my view sharply increased the speed and the extent of the response to the change in market signals.

In the early-1970s, there were two 'conventional' technologies--oil fired or coal fired (only in a few cases could one and the same plant switch from oil to coal at short notice, although this versatility was unexpectedly expanded during the 1984 coal strike). The choice between them was determined chiefly by the cost (price) of the alternative primary fuels. The difference in capital cost of these two types of plant was small. But there were, so it was believed, two other extreme choices:

* 'peak-lopping' plant, with high running cost (because the primary fuel had a high price, or because its efficiency of conversion was low), but very low capital cost per MW of installed capacity. A highly desirable feature of this equipment was its ability to be 'turned on' at very short and inexpensive notice--unlike a possible alternative, which was merely to keep alive for long periods very old conventional coal or oil burning plant. Old fashioned Gas Turbines were the standard case of such equipment.

* 'base-load' plant, with high capital cost but low running cost. In the past, most of the energy establishment believed that one version or another of nuclear plant met this specification.

The essence of the calculation then used to be, in the 'plans' of the past, to fill up the base load with nuclear plant, until the point at which the saving on running cost ceased to be large enough, because of the limited duration of the load, to outweigh the high capital cost per GW of capacity. The peak would be met by specially built gas turbines, or by pump-storage plant or by old conventional plant, near final retirement, called in to run for only a few hours per year. And all the rest of the load would be the battle ground between oil and coal or between imported and home produced coal.

Today, according to the reports in front of us, a new technology is available, which eventually may sweep the board completely. It has lower capital cost and lower running cost than all or most of its competitors; and its margin of advantage is so great that it can force the premature retirement of existing plant, and therefore the abrupt extinction of demand for the primary fuel input appropriate to that plant. This new technology,the Combined Cycle Gas Turbine (CCGT), is claimed to be the exemplar of that classic case from the economic text books--a new plant whose total cost of operation is below the marginal cost of at least some of the existing plants. A less dramatic but more fully true statement is that the new plant is sufficiently attractive to encourage the accelerated scrapping of old plant.

A plain-man interpretation of the new engineering possibilities of the CCGT is that new materials have enabled the first stage in the cycle to operate at higher temperatures than in older designs, which improves the efficiency of energy conversion; and, in addition, the 'waste heat', instead of being consigned to a heat sink, can be used to spin a conventional steam turbine. As a result, the total fuel efficiency of the two turbines together can match that of the best existing conventional plant, at a capital cost of installation per GW very much lower than for existing plant. Moreover, economies of very large scale are not necessary for the success of this technology (and perhaps not available), so that plants can be rapidly and flexibly contructed, in customer-friendly and environment-friendly sizes. The thermal efficiency of a modern oil/coal fired station can attain perhaps 34 per cent (all the waste heat goes up the chimney or into the cooling waters of the river or sea). A CCGT can attain 53 per cent efficiency. For a comparable output of power, an oil/coal fired station might need to employ 1000 men, a CCGT only 50 men.

And, on top of that, it is claimed (although somewhat contentiously) that, at the prices at which gas is sold in the new contracts to the Independent Power Producers (IPPs), the cost per joule (useful unit of energy) to the new plant is lower than the actual cost of coal to the big generators, and lower than all but the most optimistic scenarios for coal (home produced or imported) in the future. The purchase contracts, concluded by the IPPs with the ultimate suppliers of natural gas, are no doubt complex and full of special features. But they are, it seems, of the form familiar in the world oil and gas industry, particularly in the United States, for the last 30 years or more. They are 'take or pay' contracts, committing the customer to a firm series of cash payments into the far future, and therefore allowing the ultimate sellers of gas to provide bankable balance sheet assets to offset the capital liabilities originally incurred for exploration and plant installation. How the managers of British Coal would love to acquire such assets!

There are price variation clauses, providing some linkage between selling prices in 'this' contract, and spot selling prices for a range of fuels in the future. The pass through of such price variations to the ultimate customers of the IPPs and RECs, if they are ever triggered, may provide the Regulator with headaches, because he has (in February 1993) come to the decision that the contracts are in accordance with his Regulation which require the RECs to purchase at the 'best effective price': electricity customers in some hypothetical future year when gas prices rise sharply may have to learn that byegones are byegones. But, on the face of it, these are contracts which would seem attractive today to most final customers for electricity, if they were allowed to see them and could be bothered to read them.

The managers of the RECs have responded to these opportunities by doing their best to help create new IPPs who would construct new-style plant. In the old days, the Area Boards might have licked their lips at the possibilities, but they would have been able only to murmur their wishes at the quarterly meetings of the Electricity Council--it would have been for the CEGB, and the Minister, to make the decisions. It seems likely that if the new technology had appeared five years earlier, before privatisation, the Minister would have been inclined to temper the wind of competition to the nakedness of the shorn lambs in the mining industry, and to permit a rate of investment in the new technology which limited the rate of decline in the mining labour force to, say, around 10 per cent per year--double the steepness of the previous three decades but less than the 18 per cent per year now expected.

Can coal compete with the new technology?

A key question about the relative attractiveness of coal-fired and gas turbine generation concerns the prices charged by British Coal. One way to approach this issue is to introduce another element of choice --between British and imported coal. The House of Commons Committee is clear that, if we were constructing a new power station now, the CCGT has a strong cost advantage over a long-term contract for imported coal from the cheapest source--an advantage which may be more than 20 per cent if we take into consideration the cost of cleaning the exhaust gases from a coal fired station, but is unlikely to be less than 10 per cent even if we ignore that extra cost for coal. However, an existing coal fired station using the cheapest imported coal, and aiming to cover only its avoidable costs, can generate electricity more cheaply than a new CCGT which needs to cover its total costs. Cannot some UK coal be produced at or below the cost of imported coal? How much coal could be produced at that cost? If enough UK coal could be produced at internationally competitive costs, the pace of decline of British Coal would be reduced. Is the commercial policy at present being conducted by British Coal the policy best suited to the maximisation of its sales?

We may explore these questions by contrasting the outcome under present practices with those which would rule in other market formats. Under simple text book conditions, with a multiplicity of individual buyers, all of whom enjoy equal access to finance from well informed long-term investors, a publicly owned monopoly which aims to maximise its sales, subject to the constraint of covering the costs of its continuing operation, would sell the same quantity of coal at the same uniform price as would be achieved by a highly competitive fragmented coal industry, each component of which was attempting to maximise profits. Transport costs, and the geographical location of collieries and power stations, would complicate the analysis, but the essence would be unchanged.

The record of the last 18 months seems to suggest that the path of bargaining is following neither the competitive nor the monopolistic model; the unfortunate management of British Coal is very short of finance, it cannot bank on the future (and certainly cannot persuade anyone else to bank on its future), and it is faced with a duopsonistic pair of buyers (the two big generators) who are determined to diversify their sources of supply--they want more imported coal, and more gas, and their own customers, the RECs, have similar aims.

The Caminus(3) study shows a supply curve for deep-mined coal which is very elastic along its central segment in 1993/4--costs per tonne rise by less than 10 per cent when output increases from 20mt per year to 60mt per year. But the analysis used for this study seems to me to suggest that the steepness (inelasticity) of that curve will increase as further improvements in equipment and managerial effectiveness are concentrated on the best geological prospects.

How could the resulting prospects for the future be indicated to potential buyers?

a) A free trading solution would be for British Coal to be forced to sell at the price set by long-term contracts for internationally traded coal--no tonne of British coal would be sold if its expected (marginal) cost of production were above that level, but there would be a target to aim at and the comfort of a long-term contract (perhaps a 5 year rolling contract?) to fall back on.

b) If any temporary element of protection, say for a three year period, were to be given to British coal, then this could be expressed by a selling price, which would, for a finite period, be held above world prices, to allow time for more British collieries to force their costs below world levels.

c) A third possibility would be to allow some freedom for price differentiation. A set of independent privatised collieries would each attempt to secure a long-term market for its coal in the same way as individual North Sea gas producers have been actively selling long-term packages of gas to the IPPs for CCGT plant. The outcome of such a system would be hard to predict, but it would have an element of symmetry with the generators' purchase of gas, and play on any wish of the big generators and their REC customers to attain an element of certainty in their medium-term fuel costs.

The tactic used by British Coal constitutes an attempt at solution c). The big generators are doing their best to force tactic a), without a long-term contract. The H of C Report favours tactic b). The outcome seems likely to be a higher price and a lower output than would be chosen by an all powerful Minister.

The calculations in the H of C Report, suggest that the costs of the marginal (most expensive) tonne of British deep mined coal,which at present sells at |pounds~1.50 per gigajoule, would have to be kept down to about |pounds~1.25 per gigajoule if it is to sell competitively with imported coal on long-term contracts. Perhaps British collieries with a total output of 40 mt could meet this target within three years; perhaps only a smaller number could succeed.

But why should the generators be interested in long-term contracts, and, in particular, in paying an extra premium price for the first three years to give their suppliers time to force down costs? There are large and efficient coal based generating plants in existence. Transport facilities for imported coal exist, or could rapidly be adapted. If coal becomes very expensive to buy, further CCGTs can be constructed at relatively short notice. If coal becomes more expensive to use (because of tighter environmental standards), the shorter the contract, the better. A smart generator, with a world market market to cull, may be happier to keep his coal contracts short. If the effect is that some potential suppliers of coal within the UK are faced with a degree of uncertainty about the future which makes it unattractive for them (and their bankers) to invest new managerial effort or long-term capital in British collieries--too bad, Australian, South African or American coal is still traded in large quantities. Perhaps when the time comes for the generators to wish to replace some of their best existing coal fired plant--in the last two or three years of the century--they will wish for long-term contracts to secure supplies of the primary fuel inputs. But the future can look after itself, world trade will still flourish, and, in extremis, new British collieries could be sunk.

The approach of the 1960s was to tie up the bulk of UK fuel needs (save for gasolene) with long-term contracts, comfortable for both suppliers and users of primary fuel. The ultimate customer for fuel, industrial or household, paid the price of this comfort, but also enjoyed some of the benefit of assured prices. This seemed very attractive until world oil prices began their long decline a decade ago. The engineers and work force in the electricity generating and distribution system, and in the coal mines, enjoyed some of the benefits. The marginal or flexible supplier, relegated to short-term contracts, was found in the market for internationally traded fuels. The long-term decline of the UK coal industry has so far mainly occurred not in its protected market--electricity generation--but in the residual UK markets for coal. In the absence of electricity privatisation, and of the CCGT revolution, that decline was expected to continue during the 1990s at a pace determined by world oil prices, and by the slow replacement of conventional generating plant by the nuclear alternative, with the spur of some greater import of coal if the other two pressures seemed insufficient to maintain a reasonable rate of closure of British collieries.

British coal now faces the reversal of these conditions. It is the alternative fuels (particularly the gas fired alternatives) which enjoy long-term certainties; while deep mined coal is condemned to play the spot market. Since the technical constraints of coal mining (geological, engineering, managerial) really take several years and much investment to circumvent or change, it is no surprise that the still publicly owned British Coal is inclined to abandon hope for nearly half its existing business. In the old days, it might have hoped for continued and increased subsidies, but those days have passed.

We would observe, in the same spirit as seems to have inspired the Parliamentary Committee in their consideration of the matter, that it is unfortunate for British Coal to be faced with the CCGT revolution simultaneously with the freeing of the market for electricity generation and supply, and before the coal industry itself has been freed to play the market more adventurously, colliery by colliery. The 'sequencing of events' (to use the language of economic reform in east Europe) has been bad luck for British coal, and very bad news indeed for 20,000 miners, their families, and the districts in which they have been working. No doubt, by contrast, this has been good luck for some new mining ventures in the Americas or Australia, using new technologies, new sites, mobile labour forces.

The longer-term prospects for British Coal cannot be very good, even if the precipitous decline that we are now experiencing could be moderated. Technical change cannot be resisted for ever, and it is technical change which is the real driving force for present events.

Prices and costs

When all the fuel industries, other than oil, were under public ownership, much attention and ingenuity were expended by economists and others in prescribing the correct way to set selling prices. Purchasers were assumed to react rationally to price signals, which should therefore be so set as to guide users to least cost solutions, to encourage greater use of cheaper products, and so on. Both for electricity, and subsequently for gas, the subtle and intricate discussion of long-term marginal cost pricing was pursued in a succession of official and Parliamentary enquiries, and applied with modest diligence in practice, at least from the early-1960s onwards: the 1961 (Conservative) White Paper (Cmnd 1337) on Nationalised Industries was broadly endorsed by its 1967 (Labour) successor (Cmnd 3437).

One key notion was the close relation between relative costs and relative prices. The slogan of 'cost integrity' in pricing policy was popular. Another important concept was the differentiation of prices according to the time/load curve, so that customers who used units produced at peak times would be charged more than those who bought off-peak supplies. The discount offered to gas customers who would allow their supplies to be 'interrupted' was one application of this doctrine.

It is now therefore somewhat surprising to find in reports from the electricity regulator, and in a more qualified form in the Report of the H of C Committee (H of C,para 96, quoted approvingly by OFFER, Further Statement) that the main emphasis is laid on the comparison of prices of alternative primary inputs into electricity generation, with lesser attention to underlying facts about costs. Equally strange is the importance placed on judgements about whether the decision makers (for instance, managers of RECs deciding on long-term contracts with generators) have interpreted in good faith the very limited information made available to them by those who have tried to sell them contracts for the future supply of electricity, rather than on whether those contract prices accurately embody resource costs.

Reflection on current economic doctrine allows understanding of the elementary logic of this new approach. In highly competitive conditions, with widespread shared knowledge and common assumptions about facts, with reasonable flexibility of resources and reversibility of decisions, and so on, the set of contracts agreed in the market place may approximate well to a moving optimum of resource allocation. There is, according to this approach, no need for market agents to go 'behind the scenes' to the study of costs. Nevertheless, the informed public, Ministers, and the Parliamentary Committee and its advisers and even the Regulator himself, have all been worrying rather hard, over the last six months, about the cost/price relationship.

They are right to do so! The RECs enjoy a substantial monopoly today, but face increasing competition in their final markets in a few years time. They have in the last few years been buying almost all their supplies in the spot market from the two big generating companies, who in turn have been engaged in a largely political tussle with the still nationalised coal industry, striving to obtain British coal at much lower prices or to exercise their rights to buy coal imports. The RECs' spot purchases of electricity from the coal-dominated Pool can be (and usually are) hedged, in a novel futures market; but over
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Title Annotation:includes related articles
Author:Posner, M.V.
Publication:National Institute Economic Review
Date:Aug 1, 1993
Words:10395
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