The UK natural-gas industry

Applied Energy 31 (1988) 263-303

The UK Natural-Gas Industry

P. Russell* & S. D. P r o b e r t School of Mechanical Engineering, Cranfield Institute of Technology, Bedford MK43 0AL, UK

ABSTRACT The recent history of the British gas industry has been reviewed. The powerful, and sometimes ill-conceived, influences of the UK Treasury on the Government's energy policy do not always appear to be in the long-term energy interests of the UK. Present trends and implications for the future are outlined.

GLOSSARY Gas

Long term Medium term Monopsony

Pipeline gas

Unless otherwise stated, wherever the term 'gas' is referred to in the present text, it implies natural gas, whose main constituent is methane Beyond 20 years hence From 5 to 20 years hence A situation where only one buyer exists for the product of several sellers, or where one of several buyers is large enough to exert an undue influence over the price of a product, which in the present context is gas Has a calorific value sufficiently high to permit the gas to be conveyed commercially over long distances

* Present address: McKinnon & Clarke Ltd, Lyndean House, Albion Place, Maidstone, Kent MEI4 5DZ, UK. 263

Applied Energy 0306-2619/88/$03.50 ~ 1988 Elsevier Science Publishers Ltd, England. Printed in Great Britain

264

P. Russell, S. D. Probert

Possible reserves

Those which, at present, are estimated to possess a significant, but less than 50%, probability of being produced commercially Those which are estimated to have a better than 50% chance of being produced commercially Those which, on available evidence, are virtually certain to be able to be extracted in a commercially-viable manner During the next 5 years That produced from coal, oil or plants

Probable reserves

Proven reserves

Short term Synthetic (or substitute) natural gas

ABBREVIATIONS BC bcm BG BGC BP CNS CHP DEn ESI FLAGS GUC LNG LRMC MMC Mtce Mtoe n/a NEDC NGL Nosheb Of gas

R&D

British Coal One billion (=109 ) cubic metres of natural gas at one atmosphere absolute pressure British Gas plc British Gas Corporation (known as British Gas since its privatisation occurred in December 1986) British Petroleum plc Central North Sea Combined heat and power UK Department of Energy Electricity-supply industry For liquids and gas system Gas Users' Council Liquefied natural gas Long-run marginal cost Monopolies and Mergers Commission Million tonnes of coal equivalent Million tonnes of oil equivalent No available data National Economic Development Office 'Natural-gas' liquid North of Scotland Hydro-electric Board Office of Gas Supply, 105, Victoria Street, London SW 1E 6QT; the regulatory body set up to monitor the behaviour of British Gas plc Research and development

The UK natural-gas industry

RPI SNG UKCS

265

Retail price index Synthetic (or substitute) natural gas (derived from coal or oil feed-stocks) United Kingdom's Continental Shelf

AN OVERVIEW The British gas industry supplies an explosive product by pipeline to the majority of buildings in the U K with surprisingly little regulation. If the industry was starting now, it is unlikely that this would be allowed to happen. In the early 1950s, the gas industry (i.e. the town-gas industry, as it then was) in the UK was in a state of stagnation, and rapidly becoming uncompetitive with the oil, coal and electricity industries. Then new technologies (e.g. involving high-pressure national transmission pipelines-see Fig. 1; utilization improvements, such as new radiant gas-fires; and imported L N G from Arzew in Algeria) were adopted. Simultaneously more and more cities and towns introduced 'smokeless" zones, which benefitted the gas industry. In 1965 the first natural-gas field in U K waters was discovered at West Sole, in the Southern Basin of the North Sea. Two years later it was in production, and the first town in the U K was 'converted' to the use of NorthSea gas that year. It took approximately 10 years, from mid-1967, to convert Britain from the use of town gas to natural gas (which is more difficult to ignite, more air being needed in the mixture; and it burns with a lower flame speed): this relatively clean, benign, piped fuel, requires almost no storage at the point-of-use. Approximately 35 × 10 6 appliances (of --~8000 different designs) and in total about 200 million burners were modified to take natural gas. Only relatively small amounts of NOx and negligible percentage SO2 emissions occur as a result of natural-gas combustion, and so these pollutants lead to only a small contribution to the greenhouse heating of the Earth. Natural gas is convenient to use and is easily stored: it is a fuel which produces no ash, dust or smoke; the HES removal usually being accomplished before the entry of the natural gas into the distribution pipelines. The high capital investment in harnessing North-Sea gas necessitated the rapid growth in the number of domestic customers for the gas, and this was achieved by a vigorous marketing policy and relatively low unit prices. The BGC m o n o p s o n y ensured that the beach-head cost of natural gas was

266

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1. A simplified representation of the natural-gas transmission-pipeline network and main off-shore gas fields supplying the UK. This natural gas arrives in Britain at places which tend to be remote from areas of dense population. Thus a network of 17 000 km of highpressure mains pipeline had to be constructed: this was achieved with little permanent disruption to the countryside. In the Norwegian sector of the N o r t h Sea, a sub-sea pipeline crosses over a 300 m deep trough.

competitive with imported crude-oil prices at that time. This resulted in low unit gas prices being passed on to consumers, and so to an increasing share (relative to coal and electricity) of the domestic heating market being captured for gas. So natural gas made a rapid penetration of the market, the demand rising from 26-0 Mtoe in 1973 to 44"0 Mtoe in 1983. By 1986/87,

The UK natural-gas industry

267

British Gas had captured 16%, 29% and 55% by volume of the commercial, industrial and domestic U K markets respectively: over half this gas is used for space heating, so resulting in high seasonal and diurnal load swings. In 1987, the use of natural gas amounted to 25% of the total inland U K primary-fuel consumption, and this is likely to increase. Consider, for example, that traditional cast-iron mains are being replaced by buried polyethylene pipelines, which can be jointed thermally in situ: they do not corrode and can accommodate to significant ground movements. Distribution costs are consequently being reduced, and hence even isolated villages are now being connected to gas supplies. Approximately three-quarters of the natural gas consumed in this country comes from U K 'waters'. Other potential sources are Norway, particularly the Troll field, the USSR and Iran via the Trans-Siberian pipeline, and Algeria through L N G facilities at Zeebrugge. Substitute Natural Gas can be manufactured from coal: both BG and British Coal have pertinent research programmes underway. British Gas, the largest gas undertaking in the world, provides fuel for about 40% of the heating in the UK's commercial, industrial and domestic sectors. Most of this gas is derived from fields operated by other companies. Cleeton and Ravenspurn South, two of the newest fields, are operated by BP and will start supplying gas late in 1988. The Morecambe off-shore gas field, which is owned by British Gas, will, when at full rate of production within the next 2 years, be satisfying approximately 10% of the UK's total peakdemand for gas. Because developments in the northern North Sea have reached a growth plateau, and production from the gas fields in the southern sector of the North Sea has passed its peak, attention has been switched to the CNS (see Fig. 2). BP's Miller field will probably be the first of the CNS fields to yield marketable quantities of oil and gas. Marathon's Brae, Mobil's Beryl, Amoco's Everest and Texas Eastern's L o m o n d fields are soon likely to follow in producing gas. These fields have large amounts of gas and liquid condensate, and so, before they can sell their product to chemical companies and BG, they will have to use processing facilities. The gas from BP's Miller field is sour--it contains hydrogen sulphide, which would probably have to be removed prior to the sale of the gas to BG. But Nosheb will purchase the untreated gas, thereby avoiding BP having to undertake the cleaning. The next generation of gas/oil fields developed will be at a cost per therm of several times those for the shallower waters of the southern sector. Nevertheless a vast a m o u n t of flaring of gas associated with oil production still occurs. Since 1977, an average of 12 x 1 0 6 m 3 per day of natural gas at atmospheric pressure has been burnt and so wasted in this way in the UK sector of the North Sea alone.

268

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M a i n factors that influence the supply o f natural gas • • • •

LOMOND

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Its unit price in the l o n g and s h o r t term. R a t e o f d e p l e t i o n o f reserves. Level o f imports. C o s t s o f d e v e l o p i n g n e w resources.

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The UK natural-gas industry

• • •

269

Government policy. International events. Technology.

Factors influencing the demand for natural gas • • • • • • • • • • •

Unit price--on an absolute basis and relative to those for other fuels. Security of supply, in the short and long term. Government policy. Ease of its substitution for other fuels. Environmental considerations and legislation. Size and type of markets. Efficiency of use. International events (e.g., the occurrence of a Middle-East war). Technology. State of the economy. Environmental temperature required, and hence space-heating loads incurred.

The future behaviour of many of these factors is uncertain and cannot be assessed easily, so predictions of the demands for natural gas are somewhat unreliable.

THE POLITICS OF THE EARLY YEARS OF H A R N E S S I N G U K N A T U R A L GAS The five major natural-gas accumulations (namely West Sole, Viking, Leman Bank, Indefatigable and Hewett--see Fig. 1), which had all been discovered by October 1966, account for approximately half of the current estimate of initially recoverable, proven and probable dry gas reserves on the UKCS. The mass of gas in these Southern-Basin fields was large in relation to the UK's expected annual demand throughout the 1970s, yet simultaneously the expectations of finding further major accumulations under this part of the North Sea were low. In 1972, the BGC, shortly after its creation, contracted to purchase the entire output from the Frigg field. This reservoir straddled the median line, with approximately 60% of the reserves (originally estimated to be 230 bcm) being deemed to be in the Norwegian sector. It was envisaged that the supply of natural gas from this source would contribute substantially to the UK's requirements from the late 1970s and throughout the 1980s--see Figs 3 and 4. By the end of 1986, this Southern Basin gas, now in decline with respect to annual supply, provided

P. Russell, S. D. Probert

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Fig. 3. Indigenous and imported combustible-gas supplies (in therms) sent out to customers via the national gas-supply pipeline network.1 The amounts of gas put into and taken out of the network differ slightly because of stock changes and the generation of SNG and town gas. Producers also use some gas for their own purposes as well as lose some. From 1984 onwards, the town-gas figures were relatively so small, that they were not accounted for separately, and hence the overlap of the curves.

approximately half o f the total supplies, Frigg one-third, and the natural gas from the central North-Sea region and the associated supplies from the northern North Sea the remaining one-sixth. As the large oil-field discoveries began to be developed during the latter half o f the 1970s, it became clear that substantial additional quantities o f natural gas were likely to become available from several diverse sources, mainly as supplies associated with oil extractions. A study, completed in 1978, by private and public sector operators, o f the prospects for constructing a gas-gathering system concluded that insufficient natural gas was likely to come ashore from the new U K C S fields to justify introducing any further trunk lines to shore. Instead it recommended that BGC and/or

The UK natural-gas industry

271

GAS USED IN THE U.K IRON ANO STEEL INDUSTRY 19 GAS USED FOR PUBLIC ADMINISTRATION,COMMERCE AND AGRICULTURE

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Shell/Esso should be invited to construct a gas-gathering system in the region of the Brent field, and that, in the central North Sea, a further pipeline network might be installed to service the Tartan, Piper and Beryl fields. These recommendations were aimed at maximising the use of the existing Brent and Frigg pipelines. The report also recognised that the situation could change if either additional sources of natural gas were discovered or Norwegian supplies were made available. The situation had indeed changed by the end of 1979 as a result of the unit oil price increases. This made commercially viable the development of some marginal fields, which had been discounted by earlier studies. Moreover, the then prevalent perception of an imminent 'fuel shortage' served to emphasise the desirability of harnessing the natural gas which would otherwise have been flared. In consequence the BGC, in collaboration with Mobil and later BP, proposed the construction of an extensive gas-gathering facility in order to

272

P. Russell, S. D. Probert

increase the use of this associated gas. The capacity of the collection system was estimated to be between 9-5 and 14.5 bcm per annum. 2 These figures presumed that solely UKCS supplies would be collected. However in conjunction with the investigation, the Corporation also entered into negotiations with the Norwegian Government to purchase natural gas from the Stratl]ord field, for which it made a firm offer late in 1979. But a longterm contract to import Norwegian gas would have (i) had an enormous effect on Britain's annual trading balance-of-payments and (ii) led to the UK Exchequer foregoing immediately revenue derived from taxing the outputs from U K gas fields. Although the BGC clearly regarded the gas-gathering project as being economic, the then (1979) newly-elected Conservative Government had made it clear that it wished the scheme to be financed privately. The Norwegian decision (which was not announced until early in 1981), to supply the Stratfjord gas to a consortium of other European utilities, was a major setback for the gathering scheme because the operating companies did not regard the speed with which UK supplies alone were likely to be built up to be fast enough to make the project commercially attractive. Even leaving aside the loss of the Statfjord-field gas, a circular argument had been created whereby the financial institutions would not lend money (the estimated cost of the project being £2.7 billion) without a guarantee of repayment from the oil companies. In turn, the companies wanted a commitment on price from the BGC: this the Corporation was unwilling to give without quantity and delivery-time profile guarantees. Such problems proved to be intractable and in September 1981, after almost 18 months of negotiations, the Government vetoed the proposal that the Corporation would itself guarantee the necessary finance for the gas-gathering scheme.

T H E OIL A N D GAS (ENTERPRISE) ACT 1982 F r o m the outset of the development of the UKCS natural-gas reserves, the producers were required under the terms of the production licences to land in the UK all the natural gas extracted from the UK sector of the North Sea (see Appendix 1, Note A). This requirement effectively excludes the option that the producing companies might have of exporting any gas they discover, because the transportation costs of landing the gas in the U K and then, for instance, conveying it back to Continental Europe would be prohibitively expensive. Similarly, under the terms of Section 9 of the Continental Shelf Act (1964), the producers had to offer all supplies (other than those for use as chemical feedstocks) to the BGC and, in turn, the Corporation was obliged to make an offer for any natural-gas supply the

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producer proposed. In the event that no contract could be agreed, the producer had the right of appeal to the Department of Energy. The appointment of Nigel Lawson as Secretary of State for Energy in September 1981 presaged the first attempt to bring about a greater degree of competition in the gas market. The passage of the Oil and Gas (Enterprise) Act (1982) changed the legal position and enabled producers to offer supplies directly to consumers if one, of three, conditions is satisfied, namely: (i)

after notification of the proposal to the Secretary of State, if the supply was to be in excess of two million therms per annum; or (ii) after the Secretary of State's approval had been given, if the annual supply was to be between 2.5 × 10 4 and 2"0 × 10 6 therms; or (iii) if the BGC had not objected and the Secretary of State's approval had been received, and if the supply was less than 2.5 x 104 therms per annum, with the premise to be supplied being within 25 yards of a distribution main. Viewed from a naive theoretical perspective, the Act appeared to introduce a degree of competition into the down-stream gas market. However, as with the case of exports, the practicalities were somewhat different. First, the BGC's access to cheaper supplies from its earlier longterm contracts allows it to undercut any potential competitors with newlydeveloped fields. Secondly, the Act effectively restricted such competition to the industrial and commercial sectors, where the profit margins are lower than in the domestic sector. Thirdly, the BGC could offer a greater security of supply than any other producer taking gas from a single field: the 1982 Act did not provide any statutory obligation on the BGC to provide back-up supplies. Fourthly, the question of how the charges for using the BGC's transmission network were to be arrived at, was not defined specifically. If the charge was to be based on average costs, rather than marginal costs, this could again have given the BGC an effective cost advantage. Whilst the Act may not have brought about direct competition in the supply of gas, it did alter the bargaining positions of the producers (vis-fi-vis the BGC) both by removing the former's obligation to offer new supplies to the Corporation and by releasing the latter from having to make an offer for such supplies. The producers' statutory right of appeal to the Department of Energy was also repealed. In turn, the gas Act (1986) made it easier for other companies besides BG to supply gas directly to final consumers. Nevertheless there still appears to be considerable scope for British Gas to engage in predatory pricing to keep out new entrants. 3 However one responsibility which persisted upon the BGC was the statutory requirement to meet 'all reasonable demands'. In a situation where the large Southern-Basin gas-fields were starting their decline phases (the

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imports from the Frigg field were also considered likely to follow suit in the early 1990s) and with the loss of the gas-gathering system, the removal of the necessity to offer new supplies to the Corporation strengthened the negotiating positions of the oil companies. Against this background, the BGC's interest in negotiating an import contract for the 1990s was understandable.

T H E S L E I P N E R P R O P O S A L A N D ITS ASSOCIATED F O R E C A S T S Having tried, and failed, to secure additional natural-gas imports from the Statfjord field, in mid-1982, the BGC turned its attention back to Norway and this time to the Sleipner field. In parallel with the negotiations for this new supply, it was announced that a significant number of blocks in the 'good prospects for gas' Southern Basin would be offered as part of the eighth licensing round. In the same year, supplies of associated gas from Brent and other oil-producing fields began to come ashore through the F L A G S pipeline. The negotiations over the Sleipner field were conducted against a background of renewed drilling activities, both in the Southern Basin and the UKCS as a whole (see Table 1). In February 1984, the BGC and Statoil agreed on the terms of the contract, £17.9 x 109 for importing gas from Norway's Sleipner field. Although the Department of Energy had originally encouraged the BGC to bid for imports, an immediate decision on the merits of the proposed contract proved to be unforthcoming. At the end of June 1984, the Department informed British Gas that modifications and additions to the agreement would be required before a contract could be signed. The points at issue were: (i) a reduction in the plateau level of off-take to a maximum of 11.7 bcm per annum from the agreed range of 11.7 ~ 15.3 bcm per annum; (ii) the destination of the NGLs from the Sleipner field; (iii) the level of participation from British contractors; and (iv) juridical matters, concerning the treaty between the UK and Norwegian Governments. Only the first of these matters could be directly affected by the BGC; by the end of August 1984, the new plateau level had been agreed without any alteration to the price terms. Direct negotiations between the U K and Norwegian Governments took place on the other issues. Whilst these were not unimportant, had there been a real commitment to the contract, it is doubtful whether such details would have posed serious problems in reaching a settlement: in practice their consideration simply provided more

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time to re-examine the question of imports. During the period which elapsed between the agreement of the draft contract and February 1985, when the U K Government's decision not to sanction it was announced, 4 several projections were made purporting to support or oppose the contract. The following text outlines the issues which were usually, though not always, implicit in such exercises.

THE SLEIPNER C A N C E L L A T I O N The justification to the public for the decision to veto the proposed Sleipner contract centred on the addition of 176 bcm to the proven and probable reserves, which were alleged to have been 'discovered' during 1984. However it also became clear that the Treasury had, from the outset, opposed the idea that the U K should enter into a long-term import commitment just at the time when oil exports were likely to be declining, favouring instead to delay imports until they had been proved to be absolutely necessary. In evidence to the House of Commons Energy Committee, the Department of Energy stated that it reviewed the level of the UKCS oil and gas reserves at the turn of each year in the light of the results of the previous year's drilling programmes. Whilst it was aware that 1984 had been a successful year for exploration, it was not until the results had been finally consolidated in the review that the degree to which the reserves had been augmented was fully apparent. In turn, this augmentation was regarded as having clear implications for the scale of gas imports which would be required during the remainder of the twentieth century. On this basis, the justification for the veto of the proposed contract, occurring approximately 18 months after negotiations started, was based almost entirely on a reassessment (of the supply-and-demand position) which could have been little more than 5 weeks old. In due course, the Committee reported it was most disturbed by the fact that: 'the Department of Energy should wish to emphasise a five-week old reassessment of reserves as almost the only justification for the Sleipner veto, even if their decision to do so was motivated by a wish to conceal the powerful influence of the Treasury on energy policy'. 5 A more detailed analysis of the reserve figures shows the Committee's scepticism was well founded. Table 2 shows that a more precise pronouncement would have been that an increase of 13 bcm in proven reserves and 163 bcm in probable reserves had occurred. This distinction, made by the Department's statisticians, belied the Government's optimism. The two main constituents of this increase in the probable category were the

2

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1230(+52)

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Total initial reserves in present discoveries

40 ( + 1) - - (--) 40 ( )

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600(+163)

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210 (+92) 272 (+89)

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156 (+28) 1057 (+51)

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Initially-recoverable reserves

TABLE

UKCS Natural-Gas Reserves (in bcm) in 1985 Q(Ref. 6)

1 325 (+ 176)

1829(+215)

102 ( + 6) 45 (--6) 147 (0) 31 (-- 3) 178 (--3)

48 ( + 1) 275 (+77) 323 (+78)

365 (+ 119) - - (--) 365 (+ 119) 1 328 (+ 139)

739 (+23) 224 ( - 3 ) 963 (+20)

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643(+103)

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176 (+48) 42 (0) 218 (+48) 269 (+60)

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P. Russell, S. D. Probert

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increments of 92 bcm of dry gas in the Southern Basin and 77 bcm in the condensate fields. Furthermore, both of these increases were in fields not, as then, fully appraised.

UKCS GAS RESERVES As the negotiations were proceeding, exploration and appraisal drilling on the UKCS reached a record level in 1984, with 43 wells being sunk in the Southern Basin and 182 in the whole of the UK sector of the North Sea. As a result of this activity, the assessment of the remaining proven and probable natural gas reserves underwent substantial revision. The figure published in 1985 was 1325bcm: allowing for gas produced in 1983 and 1984, this compared with 1110 bcm a year earlier and 870 bcm in 1982, i.e. an increase of 53% in 2 years. Although the figures, which were published the year after the decision to veto the proposed Sleipner contract, showed a slightly downward revision as a result of the reassessment of several geologicallycomplicated low-permeability gas regions in the Southern Basin, the 1987 estimates give the volume of the remaining proven and probable reserves as 1325 bcm (see Table 3). A similar analysis to that in Table 2 shows that the increase in the probable category effectively compensated for the volumes of gas used in 1985 and 1986. The stated ranges for undiscovered gas reserves had also been contracting previously, but the 1987 estimate shows the largest spread since the figures were first published. The doubling of the upper range of the estimate of undiscovered reserves is accounted for by the belief that there could be significant amounts of gas at much deeper levels than had hitherto been drilled in the Southern Basin. However, when placed in the TABLE 3 Estimates o f the Remaining Recoverable G a s Reserves in the U K C S (in bcm} 7 Year a

Proven

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Proven plus probable

Possible

Undiscovered

Total

1980 1981 1982 1983 1984 1985 1986

739 664 633 712 725 648 634

362 343 308 437 600 594 691

1101 1 007 941 1149 1 325 1242 1325

458 398 526 540 643 773 691

0-575 65-660 65-635 185-570 150-475 220-835 175 820

739-2134 7 2 9 - 2 065 698-2102 897-2259 875-2443 868-2850 809 2836

a Estimates relate to 31st D e c e m b e r o f the stated year.

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279

context of the UK's production rate of approximately 42 bcm per annum, or even the UK consumption of 52bcm per annum, the absolute level of reserves is of secondary concern. If the UK's requirements are to be met solely from UKCS reserves, then what is of primary importance is the rate at which they are likely to be developed and the consequent relationship between the future rate of production and the country's gas demand.

ESTIMATES OF UK N A T U R A L - G A S D E M A N D The projections which were made of the likely trends in UK gas demand (see Table 4) show a general agreement that it will increase from 52 bcm per annum in 1986 and continue to do so up to the turn of the century. Whilst the different assumptions made about economic growth rates, price elasticities, substitution rates for other fuels, as well as the effects of increased efficiencies of appliances and other implemented energy-thrift measures will all lead to disparities between the various predictions, it should be noted that the estimates of the final demand for gas are quoted in isolation. Consequently the extent to which the projections vary could also reflect different views concerning the total energy demand and/or the share of gas in this market. British Gas plc envisages the number of natural-gas consumers in the domestic sector continuing to increase (in connection with the continued expansion of the central-heating market) up to the end of the decade, though the rate of growth will decline as the ownership of such systems reaches saturation level. With respect to the 'commercial' sector (which, for accounting convenience, includes public administration and agriculture), in 1986 natural gas satisfied approximately 37% of the total final energy demand. The assumption, on which the projected increase in volume is based, is that the price relativities between natural gas and heating oil will remain sufficiently large so as to induce commercial premises, currently heated by burning oil, to convert to the combustion of natural gas. However, the relative fall in oil-product unit prices which occurred world-wide after the projections were made may well ameliorate the rate of increase in demand previously envisaged. The share of natural gas for space heating in the commercial market is relatively low in the Government and health-service sectors, where oil-fired systems are still currently dominant. Hence future consumption patterns will also be influenced by public-sector purchasing policies. Whilst there is general agreement between the various predictions as to the likelihood of increased sales in both the domestic and commercial sectors, it is in the industrial sector that differences of view are most marked, and indeed have undergone most revision.

7"8-8'3

30.3-34"7 6.9-8"0 45-0-51"0 1-4

46"4-52"4 3"9 -4"2 50-3-56.6

5"8-7-8

23.9-30"0 5"8 6"9 35-5-44"7 1.4

36"9-46"1 3'3-3"9 40"2-50.0

50-0-61"1 n/a n/a

30-0 8"9 n/a See* above

18"0

BGC

58"9 2'2 61.1

31"1 8"6 n/a See * above

19-2

29-4 8-9 n/a See * above 56.3 n/a n/a

18"0

BGC

29"2 7"8 n/a See * above 55"0 2'2 57-2

18-0

ESSO

29-4 8-3 n/a See * above 53"8 n/a n/a

16'1

58"6 6' 1 64.7

32"2 8"9 n/a See * above

17"5

BP lower price

49"4 3.6 53'0

25"8 7"8 n/a See * above

15'8

BP higher price

51"9 4.7 56.6

27"5 9'1 n/a See * above

15"3

Shell high growth

25-3 7"2 n/a See * above 48.3 n/a n/a

15"8

46'3 4'7 51-0

24-7 6'6 n/a See * above

15-0

Shell low growth

25-8 8"0 n/a See * above 50.5 4.7 55.2

16-7 25"5 7-5 n/a See * above 49.1 4-7 53"8

16-1

44-1-64-9 n/a n/a

28'9-32'5 6.1-9"4 n/a See * above

9"1-23-0

ES I

31-4 7-2 n/a See * above 53.3 n/a n/a

14-7

BP BP Shell Shell ESI lower price higher price high growth low growth scenario C

(b) Estimates for the year 2000

49.4-54.1 3"9-4.2 53"3-58-3

27"8-30"8 6-4 7"5 45"0-49"7 4.4

10"8-11"4

DEn low price

E S SO

47.2 5 2 . 4 3"9 4'2 51.t-56"6

46.9 50 51.9

Total final demand BGC: Own use and losses Total UK gas demand

DEn low price

26-9-30.0 6"7-7.5 42.8 48'0 4.4

24'7 6"4 41"9 5.0

Domestic Other Total energy use Non-energy use

DEn high price

9"2-10-5

DEn high price

10"8

1983 actual

Industry

Sector

TABLE 4 Prediction of the Natural-Gas Demands (measured in bcm) in the U K for the Years 1990 and 2000 s (a) Estimates for the year 1990

~"

.~

.~

oo

The UK natural-gas industry

281

GAS SALES BY THE BGC TO THE I N D U S T R I A L SECTOR IN THE UK Early in 1982, the BGC was of the opinion that such sales would decline steadily throughout the 1990s as it withdrew from the bulk-heat market. The reason for this withdrawal was based on the assumption that, by the late 1980s, the development of storage facilities, such as the Rough field and the South Morecambe field, to provide for peak supplies, would be a more economic means of matching the load factor than the use of interruptible contracts. By contrast, the BGC's 1984 estimate was based on the assumption that its firm contract sales in the industrial sector would show some increase as a result of both economic growth and substitution for fuel oil, and that interruptible gas sales would continue to be competitive in the bulk-heat market. Some idea as to the scale of this reassessment can be gauged by comparison with the electricity supply industry's estimates. The Scenario 'C' projections (regarded as the 'central estimates' at the Sizewell Inquiry) were based on the BGC's earlier sales policy. The difference between these two projections is around 22% or just over 3 bcm. There was a similar difference between the Department of Energy's figures and those of the BGC (and, as with the ESI's predictions, those of the Department were also prepared for the Sizewell Inquiry). However, in response to the BGC's new optimism, the Department also re-examined its own assumptions. The result was that in March 1985, i.e. after its decision to cancel the Sleipner contract, it concluded that there could be scope for industrial gas sales to continue at levels of some 2.8 bcm in 1990 (and 2.8-6.9 bcm in the year 2000), above those shown in Table 4. 9 Taking account of the non-fuel use of natural gas (i.e. mainly as a chemical feedstock), the revised estimates now appear to lie in the range of 16.4-18.6 bcm for 1990 and 10-0-16.6 bcm at the turn of the century. The BGC's central estimate by comparison was 18 bcm for both years. The majority of the BGC's contracts with the gas producers are on a takeor-pay basis. Thus BGC's expectation of increased sales for satisfying spaceheating requirements reinforces the possibility of increasing the interruptible supplies as their sales provide added scope for load management. However one countervailing factor, in relation to interruptible supplies, is that new developments in the industrial use of natural gas are tending to replace centralised bulk-steam raising by point-of-use applications within premises. This increases efficiency, but requires a firm gas supply as opposed to an interruptible one. The BGC's prediction for industrial gas consumption also includes an allowance for non-fuel use, which is essentially the synthesis gas market

282

P. Russell, S. D. Probert

(from which the principal products are ammonia and methanol): at present, the latter is produced by reforming natural gas. In 1982, British Coal regarded this activity as a potential growth market and there was a widelyheld view that the U K petrochemicals industry would switch progressively to coal from natural gas during the 1990s. Indeed, the prospect of this switch was reflected in the Department of Energy's original projections for non-fuel gas use (see Table 4). BC estimated that this market could provide an outlet for some 8 million tonnes per annum of coal by the year 2000 (i.e. equivalent to about 2 bcm per annum of natural gas, assuming that the synthesis gas has a calorific value of one-third that of natural gas). By contrast to BC's earlier optimism (and, at least implicitly, that of the Department of Energy), the current view is that this low calorific-value gas could not be produced and transported at present more cheaply than British Gas could make available supplies of natural gas to bulk-heat consumers. F U T U R E GAS SUPPLIES F R O M T H E UKCS The vast majority of available reserves, already being used or under contract, is from dry-gas fields, whereas a high proportion of the uncontracted reserves is associated with oil or condensate fields. Another difference between the gas reserves which currently supply the UK, and those which have yet to be developed is their size. With respect to existing non-associated sources, the position at the end of 1986 was as follows: (a)

Sixty-two dry-gas discoveries had been reported, with initially recoverable proven and probable reserves estimated to be 1418 bcm. (b) The 24 discoveries, either in production or under development, accounted in total for 1135 bcm and were of 47 bcm average size. (c) The remaining 38 discoveries accounted for the balance, i.e. 283 bcm: 28 of these are in the Southern Basin and have an average size of 9 bcm, whereas the other 10 discoveries in the central and northern North Sea regions were of 2"6 bcm average size. (d) In addition to the dry-gas discoveries, the initially-recoverable (proven and probable) reserves to be derived from condensate fields, together with those from associated gas sources, were estimated to be 485 bcm. In turn, 187 bcm of this was accounted for by the 41 oil-andcondensate fields in production or under development, with another 137 discoveries accounting for the balance of 298 bcm.

During 1986, slightly over 75% of the UK's natural-gas requirements was supplied from five large fields in the Southern Basin and from the Frigg field (including imports). By the mid-1990s, these fields will be approaching exhaustion.

The UK natural-gas industry

283

D E P A R T M E N T OF E N E R G Y ' S REVISED P R O J E C T I O N S OF F U T U R E P R O D U C T I O N P R O F I L E S F O R N A T U R A L GAS F R O M T H E UKCS These profiles, which the Department produced after the decision to veto the Sleipner contract, were much more optimistic than previous estimates (see Table 5). Given that the Department had revised upwards its gas-demand estimates, the need for such optimism was understandable. The later projections suggest that the UKCS rate of gas production could increase from 40 bcm in 1985 to 45 bcm in 1990 and 58 bcm at the turn of the century: this would a m o u n t to a 45% increase over the 15-year period. In relation to the possible production levels in the year 2000, the latest 'central' estimate is above the 'high' estimate made previously. Recent 'central' projections also assume that imports from the Frigg-field satellites (East and South-East) and the Odin field would be increased by about 22-5 bcm in total and will provide around 12-5 bcm towards the UK's gas requirements in 1990. These supplies are then assumed to fall away to zero by 1995, leaving the UK self-sufficient in gas for only the next decade. At the turn of the century, 86% of the projected production is expected to come from existing discoveries and the remainder from new ones (see Table 6). Two points should be borne in mind about this projection. First, it was made prior to the unit oil price fall and secondly before the reserves in the Frigg field had been subjected to an independent reassessment. Whilst the former could well lead to some delays and reductions in the production of associated gas and supplies from gas-condensate fields, the latter has led to the estimate of the volume of originally-recoverable reserves being reduced by 16% to 191 bcm. The observation well, drilled in the UK sector of the Frigg field, was reported to have confirmed that the output, which was originally envisaged as falling offrapidly in 1991/92, is instead likely to do so TABLE 5 The Department of Energy's Estimates of UKCS Rates of Gas Production for the Period 1990-2000 (bcm/year) 1° Estimate and date o f estimate High (Oct. '84) Central (Oct. '84) Low (Oct. '84) Central (March '85) Low (March '85)

1990

1995

2000

51 48 40 45 49

61 47 38 57 56

55 38 27 58 52

P. Russell, S. D. Probert

284

TABLE 6 D e p a r t m e n t o f Energy's Assessments of the Sources of the U K ' s F u t u r e G a s Supplies (in bcm)' 1 Year

Source I II III IV

1995

1990

2000

Central

Low

Central

Low

Central

Low

Contracted UKCS C o n t r a c t e d imports Existing discoveries F u t u r e discoveries

36-8 12.8 8.2

38-8 8-8 10.2 --

24-0 0"3 31.7 1.4

25.0 -30.3 1.4

12.2 -37-6 8'0

I 1.2 -34'8 6.2

Total supplies

57.8

57.8

57-4

56.7

57.8

52.2

in 1988 'give-or-take a year'. 12 Comments on this from either Total (the field operators), Elf, who have a 66% interest in the field, or British Gas were noticeable by their absence. In the light of these events, the scenario encompassed by the Department of Energy's 'low' case begins to look more realistic. The principal risks allowed for in this case are that the Frigg supplies will decline in 1988, with gas availability being reduced by l l'5bcm, and that gas from existing condensate fields will be both delayed and smaller. Also the contribution from future discoveries will similarly be later and smaller. In this case, the early decline in Frigg supplies will be compensated for by increased annual rake-offs from other contracted sources in the early 1990s (the majority of contracts allowing for a degree of flexibility, which would enable this to happen). As a result, less UKCS gas would be available from these sources in later years and the effect on the overall load factor of gas supplies of this measure could also be retrogressive: again the precise effect is dependent on what is allowable under the terms of the previously-negotiated contracts. In the 'low' case, UKCS gas production is predicted to increase to 49 bcm in 1990, 56 bcm in 1995 and thereafter to decline to 52 bcm at the turn of the century. On this basis, imports would be required (at least to satisfy the British Gas 'central' demand estimates) throughout the 1990s, though the level of such imports would appear to be approximately half of the finallyagreed plateau rate for the Sleipner contract. A further implication of the rapid decline in the Frigg field is that many UKCS fields will be required to start production in the early 1990s. The Department of Energy's revised assessment of gas supplies suggests that some 550 bcm of UKCS reserves will be produced between 1985 and 1995: on this basis, the remaining proven reserves would be virtually exhausted and the country would be heavily dependent on those reserves currently categorised as 'probable' and

The UK natural-gas industrv

285

'possible'. If the UK continues to be self-sufficient after 1995, then it will become increasingly dependent on the rate of gas production from condensate fields.

PIPELINE A N D T R A N S P O R T A T I O N ISSUES Estimating the scale and timing of production from condensate fields is fraught with difficulty because of the uncertainties concerning the options for transporting the liquids as well as the method of development. There are two common approaches that can be taken to produce hydrocarbons from a condensate field. The first is the normal 'depletion' method, which allows the reservoir pressure to decline from the start of production. The second is to maintain the reservoir pressure by injecting another fluid for a period of time and then to adopt the 'depletion' method. In the former case, the heavier hydrocarbons will begin to condense out as a liquid when the reservoir condition falls below the dew-point. This, in turn, reduces the gas flow and also leads to a low recovery factor for the NGLs. In the latter case, the most likely source of the fluid to be injected is obtained from recycling the gas from the well stream. This process would usually be continued until the majority of the NGLs have been recovered: after this, the reservoir can be considered as a dry-gas field. Again generalisations are difficult to make because when the liquids are removed and the gas is reinjected into the reservoir, it is an insufficient replacement and so the pressure continues to decline. If the reservoir and dew-point pressures are similar, then the pressure drop could be sufficient to result in condensation problems in the early stages of the recycling period. In order to overcome this, gas 'imports' from neighbouring fields would be required. Consequently some condensate fields may require an existing pipeline infrastructure as a prerequisite for this type of development. In relation to the availability of gas supplies from condensates in cases where the reservoir is pressure-depleted from the start, the gas would be available for collection from the onset of production. If the gas is recycled, then availability would be delayed, depending on the size of the accumulation, for somewhere up to 10 years. When a field is large, say, above 30 bcm, and the liquid content is high (--~0.5 million tonnes per bcm), revenue from the condensate alone could be sufficient to justify the development. However if the per unit purchase price for the gas were high enough, then development by depletion might be financially more attractive (the corollary being the permanent loss of some condensate). The issue of timing, as to when future supplies of associated gas and those from gas-condensate structures will become available, is inextricably linked to the transport options available to the producers. As none of the future

286

P. Russell, S. D. Probert

developments is expected to be large enough to support a new pipeline to shore in its own right, then the capacity of the FLAGS line could be a constraint on the development of the northern North-Sea fields not yet in production. In the central North Sea, the Frigg lines are covered by a Treaty (signed by the Governments of the U K and Norway) which gives priority to Norwegian supplies. Whilst the decision to contract a further 22.5 bcm of imports does not compensate fully for the reported reduction of 36 bcm in the Frigg reserves, what is important, with respect to the pipeline issue, is the rearranged profile of these supplies and the consequent effect on the degree of spare capacity in the line, especially in the early 1990s, when, on the basis of the predictions, a large number of the UKCS fields will be required to supply their gas ashore. In turn, the prospects for such a development will be enhanced if BP's proposal for a gas-gathering system in the central North Sea (see Fig. 2) comes to fruition. The current timetable calls for a final decision on the project to be made early in 1988. (Four other gas-gathering schemes are also currently under consideration.) It is these types of issues, which were implicit in the projections for futureproduction profiles, which must be resolved satisfactorily if the UK is to meet the envisaged demands entirely from indigenous reserves. Given the uncertainties in such projections, it is not surprising that British Gas plc has once again been discussing the possibility of importing supplies from Norway, this time from the Troll field. THE UNIT GAS PRICE ISSUE Despite the multiplicity of assumptions and judgements that have to be made in arriving at supply and demand projections for the future, one point is evident: neither supply, demand nor (effectively) the reserve levels exist in isolation. They are linked by the unit price. The first point to note, with respect to beach-head prices, is that there is no 'market' as such. The contracts for the bulk supply of gas are negotiated on a field-by-field basis between BG and the producers. Due to this long-term nature of the gas supplies, mechanisms for escalating the base price over time or allowing for a re-negotiation after a set period are usually incorporated into the contracts. The final unit price paid is also dependent on such things as the agreed production profile, the ratio of peak supply to average supply (i.e. the load factor) and the gas quality. Because of these factors, it should be borne in mind that the 'price', when quoted in isolation, is rather meaningless. From 1980, the unit gas prices (imposed by the Government) paid at the beach-head were influenced by the perceived need to support the UK electricity-supply industry by not allowing gas and electricity prices to get too far out of line with one another.13

The UK natural-gas industry

287

One point on which all the producers are agreed is that future gas contracts should be related to 'international prices'. By comparison with the BGC's average gas costs in 1983/84 of 13.08p/therm (or 16-13p/therm including the gas levy, see Appendix 1, Note B), in 1984 BP stated that new contracts for UKCS supplies had been struck in the range of 23-24p/therm, TM though no details were given of what the contracts consisted, when the starting date of this (presumably) base price was, or what type of escalation clauses were to be used. Purchases made by other EEC utilities at this time were also reported as being in excess of 28 p/therm. 15 With respect to the proposed Sleipner contract, the (again presumably base) price was reported as being 27-29 p/therm, though these supplies are not due to start flowing until 1990 at the very earliest. Furthermore, the contract incorporated the costs of providing an oversize pipeline to shore in order to facilitate the landing of supplies from smaller UKCS fields in its vicinity. Taken at face value (and the previous comments on price should be borne in mind), the prices negotiated and paid by BG for 'new' UKCS supplies have been approximately 10-20% below the 'international' price. On this basis, it is not difficult to see why the producers have consistently lobbied for the removal of the landing requirement. Viewed from the producers' perspective, it is the margin that is important as opposed to the absolute price. The extent to which the ability to export the gas would offer the producers a better rate of return is essentially dependent on perceptions as to the supply and demand outlook for Western Europe as a whole. However, it should also be noted that the greater the distance over which the majority of UKCS gas supplies would have to be transported would necessitate a higher 'landed' price being achieved in Europe in order to provide the same rate of return. These arguments over the rate of return have recurred throughout the history of the development of the UKCS. In 1983, the producers argued that the concessions granted for developments in other parts of the North Sea by the Finance Act (1983) and the Petroleum Royalties (Relief) Act (1983) should be extended to the Southern Basin. The Government rejected these arguments and took the view that there was sufficient prospective profitability for new developments within this area without altering the fiscal regime. The high level of drilling activity which has taken place in the Southern Basin since then tends to support this contention. In an international context, the reserves in the Troll field, the largest offshore reservoir so far discovered, in addition to the Sleipner field means that Norway is well placed to continue as a major supplier of natural gas to Western Europe. Similarly, the Netherlands has also upwardly revised its estimate of the remaining reserves in the giant Gr6ningen on-shore field, in consequence of which existing export contracts have been extended and the

288

P. Russell, S. D. Probert

country is also seeking to negotiate for new markets. The USSR, despite much argument in the early 1980s amongst both the non-communist European countries and the USA, is currently supplying large volumes of natural gas to Western Europe. Furthermore, reserves of Soviet gas are extremely large and there can be little doubt that, if they chose to, they could make large additional quantities of natural gas available for decades into the future. There is also a pipeline connection between north Africa and western Europe, which conveys Algerian gas to Italy. In Nigeria and the Middle East, there are enormous gas reserves, though the cost of supplying this gas to the European market, in the form of LNG, would be prohibitively expensive at present. In the early 1980s, as a result of a perceived supply shortage, the producing companies were seeking to achieve gas prices which were near parity with crude-oil prices on a heat-equivalent basis. This aim was effectively quashed by the introduction of Soviet gas into Europe and that country's willingness to use alternative escalation indices in its contracts. In marked contrast to this era, the underlying principle which has been applied in recent years to the beach-head pricing of natural gas in western Europe, is that supplies should be competitive with the non-gas fuels available to the final consumers. This much improved supply outlook could, in the short-tomedium term, lead to competition even between the gas suppliers themselves. This, in turn, makes the method of price escalation incorporated into the supply contracts extremely important if the purchasers are not to find themselves in the position of having to take what could become expensive supplies. An example of the transition to a buyer's market was the ability of British Gas to renegotiate a reduced plateau off-take for the Sleipner contract, without any alteration to the pricing regime. The irony of the UK's position is that the arguments over international price comparisons have at least the potential for coming full circle. Imports from the Frigg field had, by the early 1980s, become increasingly expensive when compared with the then existing UKCS contracts. Looking to the 1990s, the improved supply outlook for western Europe as a whole and the potential weakening of the unit price could provide a situation in which, just at the time when the UK is intent on becoming entirely self-sufficient, it could find itself paying higher unit prices for gas from many small accumulations than it would otherwise have done for imports. T H E P R I V A T I S A T I O N OF T H E BRITISH GAS C O R P O R A T I O N In general, lower costs ensue in private firms than in public organisations: 16"1v this presumably was a major stimulus for privatisation.

The UK natural-gas industry

289

Shortly after vetoing the Sleipner contract, the Government announced its intention to transfer ownership of the BGC to the private sector and that the Corporation would be offered for sale as a fully-integrated company. The subsequent legislation (the Gas Act (1986)) was essentially an enabling measure and the regulations which govern the actions of British Gas plc are stipulated in the Authorisation granted to the company by the Secretary of State for Energy.18 The Act was intended to create an environment within which competition can develop amongst large suppliers of natural gas. Unfortunately this has, as yet, not happened, and so the monopsony position of British Gas persists. Thus the sale by the State of almost a monopoly, rather than just its assets, to the commercial sector has led to criticism. The privatisation of British Gas, which occurred in August 1986, was the largest transfer of ownership from the public to the private sector in the U K to that date. The price-control formula and the common-carriage provisions are the two items which have the most potential to exert influence on the energy market, and are discussed below. THE SELLING PRICE (SEE FIG. 5) A N D THE F O R M U L A BY WHICH IT IS D E D U C E D 'FOR DOMESTIC' CUSTOMERS Following privatisation under the terms of the Authorisation, the unit price of gas to those consumers who take less than 25 000 therms per annum (i.e. domestic and small commercial premises) is regulated by means of a formula (see Appendix 2). The contract customers who negotiate charges individually with British Gas are assumed to be protected from any potential abuse of monopoly power by virtue of the competitive pressures operating in the industrial and commercial sectors of the energy market. This may be true for those companies which have the ability to change fuels rapidly, e.g. those on interruptible contracts who (at least at present) could change to the use of oil by the turn of a switch. It may also apply to those where energy costs represent a high proportion of total costs and a rapid change makes economic sense, for example, in the cement industry where a significant degree of conversion to coal-fired sources for bulk-heat has taken place. Between these two extremes, some fuel switching will doubtless occur in response to price signals, but will do so at a much slower rate, governed predominantly by the speed of replacement of fuel-using equipment (which is especially low in the domestic sector). Moreover, unit price per se is not the only factor which affects decisions to convert from one fuel to another: fuel storage, maintenance charges, environmental-control costs, as well as convenience, are also important.

P. Russell, S. D. Probert

290

50

1,0

/ J'° x ,*/'i/2

7260

f/ /" ,,ml o .p ,,,, ,/ ,~,.o r/ ,," /___ 23o

30

I

8~ m 20

y

/ Y

i

Z

-1~1° t ~°° x

r~

4 190

4 180 (3_ 170 160

t 150

10

"t 1~,0 -~130 120

~

/ ,,(/,

J11o ,

,

~

,

L

~

J

J

,

,

100

1975 1976 1977 1978 19791980 1981 1982 1983 19841985 1986 1967

Fig. 5. Average unit gas sales prices charged to domestic, commercial and industrial customers in the UK relative to the Retail Price Index. 1 Under the terms of the authorisation for privatisation in 1986, British Gas can increase its profit margin--the difference between the unit cost o f supplies and the unit price it charges to c u s t o m e r s - - b y 2% less than the rate of inflation. The pricing formula (see Appendix 2) contains two variables, X representing the efficiency factor, which has been set at 2% and is supposed to remain at this level for 5 years, and Yt representing the average increase in the cost of gas purchased from the North Sea during the relevant year. The X a n d Yt parameters, which together with the Retail Price Index change over the year, are combined according to the formula to give the m a x i m u m average price which the company may charge. As both the percentage change in the RPI and the allowable gas cost

The UK natural-gas industry

291

have to be forecast, a correction factor, K t, will operate from 1988 onwards. Additionally there are penalty clauses which provide that, where forecasting errors result in the average revenue per therm being 4% or more higher than they should have been in any one year, or by an average of 5% or more in any 2 years, then British Gas may be instructed not to make any price increases in the subsequent year. Although the formula sets a limit on the m a x i m u m which the c o m p a n y can charge, it may choose to set a lower price. If however the average revenue per therm is less than 90% of the m a x i m u m for two consecutive years, then again the c o m p a n y may be instructed not to recover all the difference in the following year. The intention of such a provision is to provide some degree of protection against any predatory underpricing. The allowable gas cost (Yt) is to be passed straight on in the tariff to the consumers. The gas-supply contracts themselves are escalated to take account of such parameters as the RPI, crude oil and gas oil unit prices, U K electricity unit prices and for imported supplies, the $US to Sterling exchange rate which is a major determinant of cost. Without knowing the precise formula for such indexation, it is impossible to say how rapidly the average beach-head price of gas delivered to the c o m p a n y can change and how problematic such changes would be in forecasting the Yt factor (see Appendix 1, Note C). Where British Gas produces supplies from its own fields, something which is likely to increase in future, the effect on the allowable gas cost is to be determined by reference to the market price established for the purposes of taxation. Hence any temptation British Gas might have to inflate the imputed costs from such sources will be curbed by the counting for tax of the cost of gas which it declares for regulatory purposes. The allowable gas cost is also based on the total volume of gas purchased, whereas the average price per therm is based on the tariff quantity sold. This is a practical measure designed to make the formula workable. Attempting to ascribe particular tranches of gas to particular markets would be both arbitrary and make the formula much more complex. However, this does provide a potential loop-hole whereby the sales to the industrial and commercial sectors could be cross-subsidised from the profits made in the regulated tariff sector.

P R I C I N G OF GAS F O R T H E I N D U S T R I A L S E C T O R There is a growing controversy concerning the pricing of gas, particularly for the large users in the industrial sector. This has resulted in BG being

292

P. Russell, S. D. Probert

referred to the Monopolies and Mergers Commission in November 1987. In the wake of the 60% collapse in price per barrel of crude oil, which occurred during 1985 and 1986, many countries cut dramatically their average unit gas charges to their industries (see Fig. 6). However such freemarket forces were inhibited by political interference in the UK. So it is not surprising that British industry (e.g. Sheffield Forgemasters) regards the unit prices it pays for natural gas as excessive compared with those paid by its commercial rivals in other countries (e.g. West Germany and the USA). Most adversely affected in the UK are those captive industrial users on fixed contracts, who cannot employ interruptible supplies to take advantage of alternative cheaper fuels. The pricing policy for sales of natural gas to industry by British Gas should be less 'cloaked in secrecy', i.e. greater transparency in cost-allocation methods is required. An advantage of adhering to a well-publicised fuelpricing formula, applying to all industrial customers over, say, at least 5 years,

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-19°,o FRANCE

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-33 6% o~

-263 %

t,q

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-83% /.77%

52% -58%

w

~c/ ANADA.'////, / / / //.,./ / / /~ /.,/.... . / /,/ /.."./// / - ' ."" -/ / / , / /4 // ' ,//./ / /,/ / /,190.I

V/////:.'//,

,,/,

,., / / , . ,

V, / / //////./,/,',',',

///J

"/.,//'//," 4

12 % I / A U S T R A L I A / / / / . ' / / / ".." "//~.//~1834 [////////,./,." /" /..", ,/, "/A

AVERAGENATURAL- GAS UNIT PRICES ( plfherm) DURING1986/7 FINANCIALYEAR

Fig. 6. Comparative data ['or natural-gas average unit prices which are charged to industrial customers in different countries. Decreases are indicated by the presence of minus signs. From this and Fig. 5, the policy of the U K is apparent, i.e. of trying to keep up the unit prices of fossil fuels, especially to domestic customers, despite having more than sufficient indigenous supplies for present purposes. Nevertheless in the UK, natural gas is not subject to V A T (which is contrary to what happens in Europe).

The UK natural-gas industry

293

is that industry would find it easier, because of the then reduced uncertainties, to adjust to market conditions. If it is assumed that supplies are secure and the capital market is perfect, then the costs and prices o f natural gas will determine the optimal depletionrate profile. This cannot be known in advance. Hence the importance of forecasting to optimise depletion policy. Such forecasting should affect the tax regime that dictates the division of economic rent between the government as taxes and the oil companies as profits, which they can then use to develop new sources.

THE COMMON CARRIAGE PROVISION As mentioned previously, the Oil and Gas (Enterprise) Act (1982) introduced a degree of competition into the gas market, albeit theoretically. The provisions in Clause 19 of the Gas Act (1986) and Condition 9 of the Authorisation are aimed at enhancing such competition. The Authorisation requires that British Gas publishes examples of the prices that it would expect to be paid under stipulated circumstances for allowing third parties to use its national gas transmission-and-distribution pipeline systems as the c o m m o n carrier directly to the customers of the third party, together with the principles on which such charges are calculated. Similarly the Act stipulated that the c o m p a n y must use its 'best endeavours' to provide backup supplies for other parties and that it must offer terms for the residual gas in any field being used to supply gas to a final consumer. Taken at face value, these provisions would appear to offer a greater possibility of competition between British Gas and other producers, but in practice it would still take a remarkable set of circumstances for such competition to occur. As Britoil's Chief Executive asserted, it would require that 'a customer, or number of customers, would want gas at the exact phasing of our development of a gas field; that they would be willing to pay the price we asked and that they would be subject to interruptibility, which will occur anyway with a one-field development'.19 In practice the most likely situation in which such criteria could be met is if the natural gas is to be used for the C H P generation of electricity. The terms under which British Gas is required to provide back-up supplies state that such arrangements must not prejudice their statutory or contractual obligations. In practice the ability to implement such legislation is dependent on the degree of spare capacity in the transmission and distribution system at any given time. Due to the predominant use of gas for space-heating purposes, demand is subject to major seasonal variations. The peak winter load can be up to six times the minimum summer requirement.

294

P. Russell, S. D. Probert

Whilst existing gas-supply contracts with the North-Sea producers enable greater volumes of gas to be landed during the heating season, several other mechanisms have evolved in order to deal with this problem. Underground storage in former salt-mines (within ~ 1 0 0 m wide cavities at a depth ,-~2000 m) at Hornsea, North Humberside have been developed, and together with the ability to vary the pressure in the transmission system, such measures are being used to aid load management on a daily basis. In order to accommodate seasonal variations in demand, the Morecambe Bay field, which is wholly owned by British Gas, has been developed specifically for winter production and the partially-depleted Rough field has been adapted for use as a gas-storage reservoir, the gas being pumped in during each summer. The first contract for supplies from an off-shore structure to be supplied on a purely seasonal basis, from the North and South Sean fields, was signed in November 1984 and the gas first came ashore during the winter of 1986/87. The production of SNG from either liquefied petroleum gas or naphtha can also be used to meet peak-load requirements. The use of L N G provides a compact, but relatively expensive, means of satisfying 'peak-shaving' demands during winter. L N G (at approximately - 1 6 0 ° C ) is stored in above-ground double-skin, well thermally-insulated, steel tanks: unit mass of L N G occupies about one sixth-hundredth of its volume as a gas at NTP. (The frozen-ground storage of L N G at Canvey Island, Thames Estuary, in the 1960s was discontinued during the 1970s due to frost heave, the continuing spread of the ice wall and the consequent energy dissipation.) The practical difficulties in assessing precisely when British Gas can provide back-up supplies without prejudicing its own obligations, and then deciding what a fair price should be, are immense. Even though the Government has aimed at alleviating these problems slightly, by arguing that back-up supplies to other parties should take preference over British Gas's own interruptible contracts, it is difficult to conclude anything other than that the idea of genuine competition in the gas market remains a chimera for the immediate future.

POLICY T R E N D S The policy of extending existing import contracts into the 1990s and thereafter requiring British Gas to look, in the first instance, solely to UKCS supplies has undoubted potential benefits in terms of the prospects for the balance of payments, the employment opportunities in the off-shore industry and the greater (though deferred) Exchequer revenues, which

The UK natural-gas industry

295

would be forthcoming. However, the ability to reap such benefits remains in doubt at the present time. If the estimates of reserve levels, or far more importantly, production profiles prove to be seriously adrift either because of the slower pace of development as a result of lower unit oil-prices than anticipated or because of the logistical problems surrounding the development of numerous associated gas and gas-condensate fields, then the U K has two basic options. The first is to enter into negotiations for short lead-time imports (assuming that the volume and time-span of such supplies--which would be regarded as commercially viable by both the exporter and British G a s - would be low enough to ensure that all the objections of the oil companies and Treasury, which were levelled at the Sleipner proposal, were not simply repeated). However, if such imports were to be agreed, they would also need to be sanctioned by the British Government. The longer such a decision is delayed, the greater is the probability that this option will be lost by default. However, a possible variation on this theme would be for British Gas to use the South Morecambe field as a base-load supply to make up any potential shortfall in supplies in the early 1990s, and use the intervening time to agree financially-advantageous contracts for imports to come ashore in the second half of the next decade. The alternative to this supply-side option is to restrain demand and here the marketing strategy of British Gas is vitally important. The company could choose to pursue a policy of profit maximisation as opposed to one of market maximisation, and concentrate on the higher-price tariff market at the expense of the lower value industrial sales. If such a policy were to be pursued, the role of British Gas's storage facilities would be central to its implementation. Firm industrial sales could be cut back, and the supplies to the interruptible market retained in order to aid overcoming the seasonal load-management problem. Similarly, in future years, it could have an incentive to negotiate for a greater proportion of peak-load supplies from future fields as, although they would be more expensive, such costs could be passed straight on to the final consumer, whereas the cost of building more storage capacity will be included in that parameter which the company is required to reduce. If, however, sufficient storage capacity already exists, then it would be more profitable to abandon the lower-price interruptible market. Both of these options have implications for the consumption patterns of other fuels. In the first case, the likely beneficiaries would be gas oil and/or fuel oil. In the second case, it would most likely be coal, at least in the long run.

Growth in the domestic market could also be restricted without contravening the Authorisation. Unit prices could be raised in absolute terms or relative to those for electricity. The tariff structure could also be

296

P. Russell, S. D. Probert

modified in order to reflect the differential transmission costs, which in turn would almost certainly stop any further expansion of the system. Another possibility would be for British Gas to pursue more vigorously its policy of promoting the rational use of energy amongst its consumers. The conclusion to be drawn from the Sleipner issue is that the idea of any, at least preconceived, depletion policy is an anathema to the present G o v e r n m e n t and instead the intention is that the U K C S gas reserves should be produced as rapidly as is commercially feasible. The corollary of such a policy is that it is much more likely that the U K will become significantly more dependent on imported supplies in the first decade of the next century.

O T H E R T R E N D S , C O N T E N T I O U S ISSUES A N D F U T U R E POSSIBILITIES The adoption of natural gas as an energy source by a customer can often represent the least-cost solution if good energy-efficient design is adopted. Thus the British gas industry has a vitally important future as an energy supplier. Its aim should be to bring cheaper, and even less polluting gas to its customers. To achieve this will require the employment in the industry of more, appropriately-trained engineers and so its R & D programme will then probably be enhanced even though the British Gas Corporation is now privatised. In the immediate future, British Gas plc is likely to attempt to: (i) purchase various foreign fuel-firms (e.g. in Canada and New Zealand); (ii) sell more vigorously its exploration, production and consultancy services world-wide; and (iii) maintain, at about 90% of its total activity, the provision of gas for British customers. At present, supply capability exceeds demand for almost every energy form, e.g. coal, oil, natural gas and electricity. Thus the increased inter-fuel competition has led to uncertainties for the gas industry. Also local, large, medium and small scale C H P systems are being introduced, m a n y of the smaller ones being gas fired: these will affect dramatically the traditionally separate, competing fuel industries of coal, oil, gas and electricity. It is possible that Regional Resource Boards, responsible for C H P plants, gas supplies, water power, refuse handling, etc., will be established. If their performances (e.g. with respect to profit, reliability or safety) are regularly not as good as those of neighbouring Boards, then questions would be raised and remedial actions required.

The UK natural-gas industry

297

British Gas's state-guaranteed near monopoly-monopsony position as a private-enterprise supplier of natural gas is stronger now than when it was nationalised, because of the sale of participation in the benefits to millions of individuals and institutional shareholders. Thus the present structure provides even fewer commercial constraints on a management accustomed to State-backed sovereignty over consumers and competitors. 2° As a private organisation, there is the temptation that BG would use its surpluses to strengthen its already dominant position in the market place, i.e. a strategic entry-deterrent policy concerning competitors would be implemented. For instance, British Gas has the incentive, in the short term, to follow a strategy of increasing its share of the fuel market by setting selling prices lower than they need be. Then, in the longer term, when consumers are locked in to the use of gas because of the high switching-costs involved in purchasing other fuel-burning equipment, these customers will remain with gas. The application of marginal-cost pricing would result in the unit price of gas being deduced from the full cost of meeting the additional demand, accounting for short and long term market factors. The long-run marginal cost (LRMC) unit price so deduced should then indicate to consumers a good approximation to the truth of the costs of resource usage. LRMC pricing should ensure that gas reserves will be depleted in a near optimal manner. The importance of LRMC pricing was emphasised in the 1979 Price Commission Report on Gas Changes--the price of gas for domestic consumers then being 6-7p/therm below the LRMC. 21 Unfortunately LRMC pricing is not generally pursued. 22 For 1982/3, unit gas prices for domestic consumers were between 1.8% and 4.8% below LRMC according to whether or not an allowance was made for a 5% return on capital. 2a Gas charges remain significantly below the LRMC. 24'25 However if the LRMC is substantially higher than the current average cost, as is the case with natural gas in the UK, LRMC pricing will inevitably lead to the production of large financial surpluses. These could be politically embarrassing, and hence would have to be regulated. At present, the incentives for gas producers to resist selling the gas to BG, and so supply customers on their own account, are severely blunted. By permitting the privatised British Gas to retain its role as a producer of natural gas as well as remaining a quasi-monopsonistic purchaser of natural gas from other off-shore producers, there is a high probability that competing producers will be manipulated. British Gas's access to privileged information (e.g. concerning the geological explorations of the North Sea by other companies) appears to give them an unfair advantage in this respect. The privatised gas industry needs more effective competition. So the restrictions on anti-competitive practices within the gas industry are likely to

298

P. Russell, S. D. Probert

become more rigorous, and the regulatory pricing formulae adopted to prevent excessive profits persisting will probably be strengthened. The clause in the Enterprise Act, which restricts the purchase of natural gas from companies other than BG to a minimum of 25 × 103 therms per annum, is likely to be removed. Natural gas is at present satisfying an increasing share of the U K primeenergy market. The production ratio, i.e. the proven and probable reserves of natural gas divided by its rate of consumption (presently 32 bcm per annum) equals, in 1988, approximately 40 years, though estimates of up to 70 years have been made because indigenous recoverable resources are still being discovered regularly. However, the future demand rate is uncertain, partly because it will be influenced by the tax regime imposed. Other factors which will influence the pattern of energy usage are: (i) Increasing demands for the desulphurisation of fuels. (ii) Inhibition of the formation of nitrogen oxides resulting from fuel combustion. (iii) Growing concern for environmental protection, so that natural gas will be used increasingly for applications where a clean fuel is essential. (iv) More rigorous application of safety requirements, which will curb the rate of nuclear-power production increase. 26 (v) Transport will become progressively more dependent upon derived fuels. (vi) Methods are being developed to capture commercially-viable amounts of natural gas from fields which had previously been abandoned as uneconomic. Also, in the past, too high a proportion of the combustible condensates from the oil and gas fields were not recovered. Thus Government inducements (e.g. tax breaks) are likely to be introduced which will encourage the greater exploitation of even large fields of high-concentration condensates. (vii) Further exploration of the UKCS and on-shore for oil and natural gas is being encouraged. For domestic heating, transport and certain industrial processes, synthetic liquid and gaseous fuels (e.g. methanol) will replace petroleum derivatives and natural gas. Technology is already well developed for the conversion of raw, dry coal into naphtha and thence into SNG, but this is at present more expensive per MJ for the derived fuels than natural gas. It is unlikely that SNG will be commercially available in the U K before A.D. 2020. 27 In the longer term (i.e. > 30 years hence), the world unit price of L N G is expected to rise to such an extent that coal-derived SNG could well replace natural supplies almost completely. However with the existing

The UK natural-gas industry

299

elaborate gas-distribution system, as the natural-gas resource runs out, it is likely that a steady transition will occur so that the system is supplied by large coal-gasification plants and/or coal-plexes. Convenience (of the use of a fuel) is now rated more highly than 30 years ago, and so it is likely that, 50 years hence, S N G will occupy a significant sector in the space-and-water heating markets. The rising unit costs of fossil fuels and fossil-derived fuels will encourage the increased use of ambient energy (e.g. via better building design, so that more solar energy is harnessed passively) and renewable energy sources (e.g. sewage, hydro-power, timber, and tidal-energy recovery via the proposed Severn and Mersey barrages). In the longer term, electricity, the ubiquitously convenient fuel, will probably occupy an increasing percentage of the total at point-of-use fuel employed, especially as Britain becomes an energy-thriftier, higher technology society. Breaking BG's effective m o n o p o l y over North-Sea gas could possibly make cheaper supplies of gas available for generating

electricity! ACKNOWLEDGEMENTS The authors are very grateful to Ted Rowlands, M P for guidance and help in obtaining information for this project. However, the opinions expressed and conclusions drawn are not necessarily his. REFERENCES 1. Energy Trends Bulletins, HMSO, London, 1975-1988. 2. Department of Energy, A North-Sea Gas-Gathering System, Energy Paper No. 44, p. 19, HMSO, 1980. 3. M. Wright, Government divestments and the regulation of natural monopolies in the UK, Energy Policy, 15 (June 1987) pp. 193-216. 4. House of Commons, Official Report, Col. 23, HMSO, llth February 1985. 5. Energy Committee, The Development and Depletion of the UK's Gas Resources, HC 76-1 Session 84/85, Para. 117, HMSO, 1985. 6. J. Stern, After Sleipner: A policy for UK gas supplies, Energy Policy, 14(1) (1986) pp. 9-14. 7. Department of Energy, Development of the Oil and Gas Resources of the UK, HMSO, 1982, 1983, 1984, 1985, 1986 and 1987. 8. op. cit. Ref. 5, HC 76-I. p. xxi. 9. ibid. HC 76-II, p. 158. 10. ibid. HC 76-II, p. 156. 11. ibid., HC-76-II, p. 298. 12. House of Commons, Official Report, Standing Committee F, Gas Bill, Eighth Sitting, 23 January 1986, Col. 240, HMSO, 1986.

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13. Select Committee on Energy, Electricity and Gas Prices, Session 1983/84, HC276, HMSO, London, 1984. 14. Energy Committee, The BGC's Proposed Purchase of Gas from the Sleipner Field, HC 438 Session 83/84, HMSO, 1984. 15. R. Johns and D. Lawson, Probe into Sleipner Gas Deal Considered, Financial Times (15 March 1984) p. 8. 16. R. Millward, The Comparative Performance of Public and Private Enterprise, in The Mixed Economy (Ed. Lord Roll), Macmillan, London, 1980. 17. B. Frey, Democratic Economic Policy, Martin Robertson, Oxford, 1983. 18. Department of Energy, Authorisation Granted and Directions Given by the Secretary of State for Energy to the British Gas Corporation under the Gas Act 1986, HMSO, 1986. 19. Energy Committee, Regulations of the Gas Industry, HC 15 Session 85/86, Q.115, HMSO, 1986, p. 22. 20. R. Atkinson, The Energy Polk 3, Mess, Bow Group Publications Ltd, London, October 1985. 21. Price Commission, British Gas Corporation--Gas Prices and Allied Charges, HMSO, London, 1979. 22. NEDC, A Stud), of UK Nationalised Industries, HMSO, London, 1976. 23. Deloitte, Haskins and Sells, British Gas E~'ciency Stud)', BGC and the Department of Energy, London, 1983. 24. C. M. Price, Distribution Costs in the UK Gas Industry, University of Leicester, Department of Economics, Discussion Paper 31, 1984. 25. C. M. Price, Competition in UK Gas Distribution: The Effect of Recent Leglislation, Energy Policy 13(1) (February 1985) pp. 37-50. 26. R. G. Temple, Energy Perspectives after Oil and Natural Gas, Gas Engineering and Management (February 1980) pp. 55-76. 27. I. Fells, P. Warner and A. Williams, Energy for the Future, Institute of Energy, London, 1986. 28. The Petroleum Production (Continental Shelf and Territorial Sea) Regulations, Statutory Instrument No. 1964/708, HMSO, 1964. 29. House of Commons, Energy Committee, Regulation of the Gas Industry, HC 15, Q15. HMSO, London 1985/86, p. 37. 30. House of Commons, Official Report, Standing Committee F, Tuesday 4 February, 14th Sitting (Part III), Col. 579, HMSO, London, 1986. 31. Department of Energy, Authorisation and Directions Given by the Secretary of State for Energy to the British Gas Corporation under the Gas Act (1986), HMSO, London, 1986, pp. 8-9. A P P E N D I X 1: N O T E S (A) The precise wording, as incorporated in the model clauses of the petroleum production licences, states 'the licensee shall ensure that all petroleum won and saved from the licensed area, other than petroleum used therein for the purposes of carrying on drilling and production operations or pumping to field storage and refineries,

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(B)

(c)

301

shall be delivered on-shore in the United Kingdom unless the Minister gives notice of his consent in writing to delivery elsewhere, and in such cases the licensee shall ensure compliance with any conditions subject to which that consent is given. '28 The Gas Levy Act (1980) introduced a tax of 5 p/therm from supply contracts which had been entered into before the effects of the Oil Taxation Act (1975) came into force. The levy was subsequently reduced to 4 p/therm, with effect from April 1982, and has been fixed at this level in subsequent years. On this issue, the Chairman of British Gas, Sir Denis Rooke, in evidence to the Energy Committee stated that 'prices may vary very swiftly' as a result of escalation clauses--see Ref. 29. By contrast, the then Minister of State at the Department of Energy, Alick BuchananSmith, informed the Standing Committee considering the Gas Bill that 'I understand from British Gas that only about 50 per cent of gas costs are linked to oil prices'. Whether this applies to crude or product prices (or both) and what percentage of its supply this represents are not clear. However he went on 'at the same time, such provisions can lead to a time lag of up to a year before the changes in oil prices feed through into gas costs'--see Ref. 30. One possible explanation for such an apparent contradiction is that Sir Denis Rooke was thinking mainly about the import contract for the Frigg field, whilst the Minister was thinking about the early contracts for UKCS supplies. If this is so, then presumably the effect of the escalation clauses on later contracts falls between these two extremes.

A P P E N D I X 2: RESTRICTION OF GAS PRICES TO T A R I F F CUSTOMERS 31 In setting the unit prices, which are charged to tariff(i.e, primarily domestic) customers, with effect on or after 1st April 1987, the supplier shall take all reasonable steps (having regard to the interests of those customers) to secure that, in each year, its average price per therm shall not exceed the maximum average price per therm calculated in accordance with Mr=

[ 1+(

100

jj

p,_,+Y,--K,

where Mr, M t_ 1= Maximum average prices per therm in the relevant years t and ( t - 1) respectively.

P. Russell, S. D. Probert

302

= The percentage change (whether of a positive or negative value) in the Retail Price Index between that published or determined with respect to October in the relevant year t and that published or determined with respect to the immediately-preceding October, i.e. in year ( t - 1). X = A parameter related to changes in British Gas's nongas costs. The rationale behind incorporating the parameter X in the above pricing formula is to encourage British Gas to achieve productivity improvements. The Secretary of State for Energy, in June 1986, set X t o be 2. This was based on an analysis by Touche Ross, which concluded that the scope for future efficiency improvements lay within the range 1-75-2% per year. The unit price of gas used for domestic purposes in the Pt-1 previous year less the gas element of costs; RPI t

In relation to the first relevant year, P t - ~ shall have a value equal to the average price per therm in the financial year commencing on the 1st April 1986 less the allowable gas cost per therm in that year. II, = Allowable gas cost rise per therm in the relevant year t; when calculating the value of Y, BG takes the weighted average cost of gas from all suppliers. = The correction per therm (whether a positive or negative value) to be made in the relevant year t (other than the first relevant year);

{

T,-1 - ( O t - i M t - O =-

Qt

[ "It 1+

T66

in which: Tariff revenue from tariff quantity in the relevant year T t 1 ~( t - 1). Qt, Q t - 1 = Tariff quantities in the relevant years t and ( t - 1 ) respectively. The percentage interest rate in the relevant year t which 6= is equal to, where K~ (taking no account of/~ for this purpose) has a positive value, the average specified rate plus three or, where K~ (taking no account of/~ for this purpose) has a negative value, the average specified rate.

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303

The value of K, takes retrospective account of the deviations of actual average price per therm from the m a x i m u m price allowed. The value includes an interest charge penalty if BG over-estimates its cost increases. 3 There are regional differences in the cost of supply of natural gas (e.g. due to less pumping expense). This should be reflected in the pricing formula. Thereby those consumers living in areas with low supply costs will avoid subsidising those in high supply-cost regions. At present, such unit-cost differentials between areas are not contained in the pricing formula, and neither are the differences between peak and off-peak costs of supply. The Office of Gas Supply (Ofgas) possesses regulatory powers to protect the interests of domestic users of gas. The unit prices of gas charged to British Gas customers or (via resale) to their customers (e.g. tenants) are controlled via the pricing formula. However the abilities of Ofgas, the Gas Users' Council (GUC) and the Monopolies and Mergers Commission (MMC) to monitor BG's behaviour effectively are impaired because much of the information they require is provided by BG's internal system. 3 0 f g a s needs to insist that the rationale used by BG in arriving at unit price levels should be more transparent to its customers.

APPENDIX 3

( i ) Approximate Conversion Factors

~,,, To

From ~

Mtce Mtoe Million therms TWh (electricity)

Mtce

Mtoe

Million therms

1 0"60 250 7-35

1"7 1 425 12.5

0'004 0"002 35 1 0.029 5

Amount of fuel (average grade) equivalent to a TWh of energy. 1 Mtoe ~ 1.111 Gm 3 of natural gas ~ 12"5TWh 425 M therms.

( ii ) Prefixes k M G T

103 106 109 1012

TWh (elec.) 0' 135~ 0-080 0 ~ 34"0 1