House of Commons - Trade and Industry

Select Committee on Trade and Industry Twelfth Report

4 Competition in the wholesale gas market

37. It is generally acknowledged that, while the UKCS declines and demand continues to grow, the excess of gas supply over gas demand has narrowed as, to date, neither import nor gas storage capacity has been expanded to offset the decline in the UKCS.[96]However, taking into account all sources of supply—the UKCS, imports via the Bacton to Zeebrugge Interconnector, and gas in storage—we were told that total supply capacity still exceeds demand. Centrica said that existing capacity could meet demand of up to 475-480 million cubic metres of gas a day, and in 2004 there had been a demand of only about 430 million cubic metres even on the coldest day.[97] At the end of January 2005, NGT told us that they had experienced no difficulty in balancing supply and demand in the National Transmission System over the previous 18 months.[98] This did not mean that there was complacency, though: NGT underlined the fact that the next few winters, and the winter of 2004-05 in particular, could become difficult for them if there was a prolonged period of bad weather.[99]

Decline of the UKCS

38. Production of oil from the UKCS peaked in 1999, production of gas in 2000. The industry has already produced about 34 billion barrels of oil and gas from the North Sea, and the model used by the industry and DTI predicts that possibly another 28 billion barrels of oil equivalent remain to be exploited. To make comparisons with demand easier, UKOOA expressed this as remaining gas reserves (including proven and probable reserves and exploration potential) of over 1250 billion cubic metres of gas, which is the equivalent of 12 years' production at current rates. However, exploration is becoming more difficult.[100] The remaining fields are smaller,[101] generally deeper and technically more difficult to exploit;[102] the majority of new discoveries are of joint gas and oil fields rather than 'dry' gas;[103] the infrastructure is ageing (much is about 25 years old) and requires more maintenance; and unit costs of production are increasing in what is already—because of the difficulties of producing offshore in often adverse weather conditions—one of the most expensive oil and gas provinces in the world.[104] Production from existing gas and oil fields is declining at the rate of about 15 percent per annum, though UKOOA suggested this was at the lower end of the range and could increase to 20 percent. However, significant investment by oil companies in new fields is reducing this decline to about seven percent a year.[105]With such investment, UKOOA believed that the UKCS would still be able to supply about 60 percent of the UK's requirement for gas in 2010 and a significant proportion beyond that.[106] NGT was slightly more pessimistic: it expected 46 percent of UK gas to be imported by 2010, and about two-thirds by 2013.[107]

39. Shortly before we took oral evidence in relation to this inquiry, several newspapers published reports that the decline in UKCS production was occurring faster than had previously been predicted.[108] NGT acknowledged to us that supply from the UKCS was decreasing more rapidly than it had anticipated. About two years ago, NGT had estimated total UKCS capacity for the short-term as about 400 million cubic metres of gas a day, but actual supply had fallen short of that, and NGT was not sure why that was so. It had therefore revised its estimate down to a capacity of 377 million cubic metres of gas a day, but it had now had to reduce this again to about 364 million at the peak. This was expected to decline further, to about 350 million cubic metres in the winter of 2005-06. In practice, NGT did not expect 100 percent of such capacity to be used: for planning purposes it always applied a factor of 95 percent to theoretical total capacity, to allow for unexpected losses of supply.[109]

40. It was these downward revisions that had provoked concern about the apparent unpredictability of the rate of decline in the UKCS. We asked the gas producers why production had decreased (had there, for example, been an overestimate of reserves, or an underestimate of technical difficulties in extracting the gas?), and whether we could expect such discontinuity in future, or whether the steady but slow decline would resume. None of them felt able to answer these questions. UKOOA cited its latest Activity Survey, which showed that, because of the significant new investment in exploration and production wells, UKCS production of oil and gas was expected to decrease at a slower rate than previously anticipated.[110] Ofgem's response was more enlightening. It explained that the problem was not an over-estimate of remaining reserves: "There is still the same amount of gas in the ground that we always thought, it is the rate at which it can be produced on a cold winter day that has gone down." This, the regulator said, was because as gas fields start to age a variety of technical problems affect reservoir pressure and therefore gas flow. Although the problems were understood, it was difficult to predict which would strike and when. One technical solution, already adopted by Centrica in relation to its Morecambe Bay field, was to invest in additional compression plant in the fields.[111]

41. In the context of the price spike early last autumn, it is interesting to note that production of gas from the UKCS was unusually low in October 2004, at 90,806 GWh, as compared with over 100,000 GWh for each of the months in the fourth quarter of 2003, 97,985 GWh in November 2004 and 104,856 GWh in December 2004 ( a decrease of 7.7 percent in the fourth quarter of 2004 compared with a year earlier). Production in the third quarter of 2004 also represented a significant decrease on production in the same quarter of 2003 (225,103 GWh as compared with 244,158 GWh, a decline of 7.8 percent year on year).[112] Official figures do not make it clear why the October 2004 drop occurred, but we note Ofgem's comment that some of the big offshore fields were closed for maintenance in October in an attempt to avoid the problem of the summer peak for maintenance.[113]

42. Because of the difficulties in extracting the—substantial—remaining reserves of gas from the UKCS, it is not at all clear that the decrease in production will take place in a managed and predictable way. This simply highlights two points which we address later in this Report: the need urgently to put in place infrastructure to ensure that adequate supplies can be imported into and stored in the UK to meet any shortfalls from the UKCS; and the need for sufficient information to be supplied to the market about why production rates are lower than expected, in order that the market players can then take a more rational view of pricing.[114]

Legacy contracts

43. In its report, Ofgem expressed concerns about the operation of certain older, long-term contracts[115] which may have had the effect of withholding supplies from the market even when prices were high.[116] It later emerged that these contracts related to the Sean field and affected four production companies. Ofgem announced in its report that it was launching an inquiry into the contracts. We asked the gas producers about this issue. UKOOA said that it would be wrong to suggest that gas had been 'withheld' as this implied it was at the behest of the producer: the contracts in question put the onus on the purchaser to 'nominate' the amount of gas required. UKOOA also cast doubts on Ofgem's assessment of the amount of gas covered by these contracts, noting that in its report Ofgem mentioned six percent of current (that is, October 2004) supplies while a elsewhere in its report it referred to one percent.[117] Ofgem was unable to inform us of its findings as the inquiry was still in progress. However, it praised the willingness of the four production companies to provide the necessary information about these contracts. Ofgem told us that the inquiry would take another three to six months to complete (as of 2 February 2005).[118]

Interconnector

44. The Bacton-Zeebrugge Interconnector is one of only two means of importing gas into the UK at present.[119] In the summer, the UKCS has tended to produce more gas than needed by the UK, so gas prices have fallen in the UK to below the level experienced in Continental Europe. Therefore in summer the excess gas has been exported to mainland Europe via the Interconnector, and this has continued until the price in the UK has reached the level of Continental prices. Continental prices therefore tend to set a floor for UK prices in summer. In winter, however, UK prices have tended to be higher than Continental ones as the UKCS is unable to satisfy peak winter demand, with the result that shippers use the Interconnector to import Continental gas into the UK. This should reduce UK prices to the Continental level, until the Interconnector is importing at full capacity, when any extra constraint on supply or excess of demand will lead Continental and UK prices to de-couple, and the UK price will continue to rise. During the winter of 2003-04, for the first time the Interconnector was importing gas at maximum capacity for several weeks. UKOOA suggested that the market was expecting this situation to be repeated during at least the next two winters (2004-05 and 2005-06).[120]

45. We were given evidence that some of those affected by the price spikes had wished to buy cheaper gas on the Continent, but they were unable to transport it to the UK. Centrica said that, during the price spikes in 2004, while there had been a large quantity of gas available at the Zeebrugge hub at a price substantially cheaper than in the UK, the company could not bring it into the UK as it did not have the 'back haul' capacity.[121] Ineos Chlor implied that it was unable to import gas because of constraints on the Interconnector, but its main difficulty appears to have been obtaining access to the gas transmission networks at a reasonable price.[122]

46. One of Ofgem's findings was that in the autumn of 2003, even though wholesale gas prices in the UK were higher than they were in Continental Europe, gas was still being exported from the UK through the Interconnector. Ofgem was unable to explain this, other than attributing it to the fact that, because of the absence of a true gas market on the Continent where suppliers would naturally sell their gas where it would obtain the highest price, Continental suppliers were instead refilling their gas storage capacity ready for the winter. An added incentive to do so was the fact that that October 2003 was especially cold on the Continent.[123] Centrica agreed with Ofgem that it was impossible to obtain firm information on why gas exports had continued, but it noted that there was a recognised problem with what it referred to as the "shoulder months"—the spring and autumn periods when the Interconnector made the transition from summer/export to winter/import mode—when the direction of gas flow depended on the storage levels in Continental Europe.[124] At the time of writing, it is impossible to confirm this, but it has been suggested that a similar situation occurred in late February-early March 2005, when a sudden 'cold snap' affected both the UK and Continental Europe. We have been informed that while the Interconnector was importing at maximum capacity into the UK at the start of the cold period, the flow slowed after a week or so, and by early March little gas was being imported in this way, despite high wholesale prices in the UK (around 70 pence a therm). Again, the reason for the reduction in flow appears to have been that Continental gas suppliers were buying up stocks, perhaps to replenish their storage capacity in order to prepare for a prolonged spell of cold weather.[125]

Gas storage

47. At peak periods, when no more gas can be pumped from the UKCS and the Interconnector is importing as much gas from the Continent as is available, then suppliers turn to gas that has been stored.[126] Apart from the depleted Rough field owned by Centrica, which is now used for gas storage, there is little storage capacity in the UK. The UK has traditionally depended on being able simply to pump extra gas from the UKCS when demand seemed likely to outstrip supply, and, since such gas could be accessed fairly quickly (within a day or so), the lack of storage facilities has presented no real problems until recently.[127] The result is that while the UK has storage for about four percent of its supply requirements, most Continental European countries have storage capacity for over 20 percent of their requirements.

48. As we discuss below, there are currently plans to build significant storage capacity in the UK. However, this does not help with the immediate problem of a tight supply over the next year to 18 months. Both Ofgem and the DTI suggested that the price spikes had provided strong market signals that extra storage capacity was necessary. So they have, but even before the price spikes it was absolutely certain that storage would be needed as the UKCS declined: we pointed out the consensus on this issue in our January 2002 Report into the Security of Energy Supply.[128] More recently, the European Union Committee of the House of Lords published a major report on this very subject.[129] We are therefore disappointed by the lack of progress in the last three years. We recognise that this is not entirely due to lack of foresight: because of difficulties in obtaining planning permission, construction has begun only recently of the storage facility in Cheshire which we were told in the winter of 2001-02 would shortly be built. As one of the witnesses from Ofgem indicated, the tight supply situation this winter would have been significantly eased if even one of the proposed facilities had already been built,[130] and both domestic and I&C consumers might have been spared a proportion of the recent price increases. Planning guidelines should be reviewed to ensure that the strategic importance of gas storage and other infrastructure projects is fully recognised.

Overall supply situation

49. Over this and perhaps the next two winters, the UK will be in the uncomfortable position of having a relatively small surplus of gas over normal winter demand. As National Grid Transco has indicated,[131] because supply cannot be increased measures may have to be taken to decrease demand—which means that customers with interruptible supply contracts may find their gas supply temporarily suspended. Although the existence of the price spikes seen over the last six months is explicable by the actual state of supply in relation to demand, it seems to us that the degree of volatility is not fully explained by this. Ofgem attributed this 'extra' volatility to market sentiment; as we have already noted, others believe that properly functioning markets are not as swayed by speculative fever as Ofgem implies. In this context, we are concerned that Ofgem was unable to give a more detailed explanation than 'market sentiment' for up to 51 percent of the price increase in the autumn of 2004 for forward prices in winter 2004-05. We have therefore focussed on whether the current structure of wholesale gas trading actually supports the regulator's and the Government's contention that it is a fully functioning market.

How gas is traded

50. We have already described the different roles played in the gas market by producers, shippers and retailers, and we have touched upon the different types of price-setting within the market: spot prices (for same day delivery); day forward prices (for delivery on the following day); and agreements of varying periods for delivery in the future, typically a month, a quarter or in multiples of a quarter (for example, six months or a year). However, there are further complications. Perhaps the most significant one from the point of view of our inquiry is that most of the gas brought into the UK is not initially traded in the wholesale market, but is sold under contract to shippers. UKOOA estimated that 75 percent of gas produced from the UKCS was sold to shippers at the beach-head terminals under long-term contracts.[132] Shell explained that the reason for this reliance on long-term contracts was that, when the oil producers were making the substantial investments needed to extract oil and gas from the UKCS, they wanted to ensure that they could sell enough of the product to repay their investment.[133] The contracts between producers and shippers typically set out maximum and minimum quantities of gas that the shipper can 'nominate' to receive on a daily basis, with nominations made in advance and confirmed on the day before delivery. Because of the difficulty in predicting both supply and demand on any particular day, some adjustments to nominations are allowed during the day.[134] It is the shippers, not the production companies, that have to ensure that they balance supply on a daily basis—in other words, that on a daily basis they have acquired enough gas to meet the demand of their customers. (The overall responsibility of ensuring that demand and supply balance in the system, while maintaining the necessary gas pressures in the pipelines and ensuring safety, lies with Transco.) Shippers meet any shortfalls left by their long-term contracts from gas which they hold in storage or which they buy in the wholesale market, and much of the liquidity of the wholesale market depends upon the degree to which at least some shippers are willing to run the risk of contracting to supply gas that they have not already bought ('selling short').

51. UKOOA portrayed the gas producers as rather passive participants in this supply process: "Offshore production is in response to shippers' nominations which are driven by market requirements to meet demand."[135] However, a number of the production companies also hold shippers' licences, so the distinction between the two is blurred. Although we are not suggesting that the shipper subsidiaries of production companies are able to buy gas at a lower cost than external competitors can—we accept that the transfer price of gas sold to the shipper arm by the production company is scrutinised closely by the tax authorities[136]—such vertical integration may give shippers better access to pertinent information than other market participants.

52. Although the short-term spot and day ahead wholesale gas markets have been volatile, this is in the nature of such short-term trading, and most of our witnesses thought that there were few problems with the liquidity of these markets.[137] E.ON pointed out that the volume of gas traded in the short-term markets had increased about sevenfold between the late 1990s and 2003.[138] Such liquidity did not prevent some price spikes in the autumn of 2004. (And in fact the recent spell of cold weather, in late February to early March 2005, has led to heightened concern about gas supply, resulting in spot market peaks of, on 3 March, about £1.10 a therm.)[139] Some witnesses argued that in a market where there was relatively little excess of supply over demand, the loss of even small amounts of supply (caused by unplanned production shut-downs or an inability to transport gas because of previous contractual commitments) would have a disproportionate effect as shippers hastily purchased gas to ensure that they could balance the supply, and as a result prices increased more rapidly than justified by the physical availability of gas.[140]

Forward market

53. Most of our witnesses agreed that the real problem in liquidity lay not with the spot markets but with the forward market, in which electricity generators and I&C consumers alike were attempting to buy gas for delivery over the next few months or year. At its peak last autumn, the forward gas price for delivery during 2005 was nearly 140 percent higher than the price of gas delivered in 2003, but by late November 2004 this had reduced to a level about 65 percent higher than the 2003 price.[141] The forward price for gas rose to levels of more than 50 pence a therm for 50 days and more than 70 pence a therm for six days in the autumn of 2004, when—we were told—about 40 pence a therm would have better reflected the reality of the supply-demand balance.[142]Prices then dropped back to roughly the 40 pence level. In market terms, we were told, this sudden increase in prices followed by a decrease is called a 'price excursion', and: "A price excursion that you can explain is an efficient market. A price excursion you cannot explain is market failure."[143] Our witness concluded that, without doubt, the price excursion in the autumn of 2004 represented market failure. Although no one had experienced a shortage of gas in practice, many gas buyers reported a dearth of shippers who were willing to sell forward in the autumn of 2004.[144] The Chemical Industries Association carried out a survey of its members, a number of whom reported that during the last contract renewal period (in the autumn of 2004) they had received very few quotations, and these tended to be available for only short periods of time—from one week down to a few hours—making real choice impossible.[145] Moreover, there was very little variation in the prices being offered: all sellers seemed to be assuming that the very cold winter predicted by some in the media would actually take place.[146] The CIA conceded that, in general, only two or three shippers in the market were able to supply large energy-intensive producers, and only four or five to supply smaller users. However, the Association felt that being made only one offer at a time was not normal for a market: it was not a situation with which chemical companies were familiar in relation to other raw materials which they bought in large quantities.[147] Again, there was general agreement that the unwillingness to sell forward was based not on a belief that there would actually be a shortage of supply in 2005, but on fears that, if something happened to disrupt either predicted supply or predicted demand, then the shippers would have to buy gas at much higher prices in order to achieve balance.[148] BP expressed the problem as follows: that shippers who still had gas available for sale were waiting until they knew more certainly whether this was sufficient to meet their commitments. The representative of BP's shipper division said that even he did not know whether he would have enough gas from the production arm to supply all the buyers with whom he had made agreements.[149] Shell agreed with other witnesses that if, in October 2004, there had been a big shipper willing to sell 'short' on the forward market (that is, without actually having bought all the gas necessary to cover its position), then this would probably have had a moderating effect on the forward price rise, "but there do not seem to be any players of that kind." Shell added: "It certainly is not part of our business strategy to go into open positions of that kind."[150]

Competition in production

54. We tried to discover which aspects of the market were not functioning as well as might be desirable. Given that the UKCS still largely determines the state of supply—and therefore the price—of gas in the UK we looked first at the question of the competitiveness of the production industry. The oil and gas companies and the DTI assured us that the industry was very competitive. They pointed out, for example, that no single company contributed more than 14 percent to total UKCS supply, and argued that there was a number of significant players in the North Sea and new players were able to enter the marketand, indeed, were being actively encouraged to do so under the arrangements for transferring under-exploited fields to new operators.[151] Others argued that, following the wave of company mergers over the last 15 years, the UKCS was dominated by a small number of multinational oil companies: the five companies with the biggest share together represented about 58 percent of total UKCS production.[152] A different source suggested a higher degree of concentration: published data by WoodMackenzie showed six major oil companies as responsible for 71 percent of UKCS gas production in 2004.[153] All six companies also hold shippers' licences.

55. Moreover, the majority of gas fields and production facilities in the UKCS, and the pipelines connecting the fields with each other and with the beach-head terminals, are jointly owned by several oil companies; and, even where ownership is not shared, for safety and basic operational reasons a lot of information is shared. For example, if a major pipeline needs repair or maintenance, all those using the pipeline have to be informed of this, so all will realise that a certain proportion of supply from the UKCS will be disrupted.[154] This is a market where different companies have more information than the norm on what their competitors are doing.

56. A further difficulty arises in relation to maintenance of offshore facilities. Because of adverse weather conditions for a considerable portion of the year, maintenance of production facilities has normally taken place during the summer months. Owing to the seasonal nature of gas demand, the resulting interruptions to supply have less effect on gas prices than they would do in winter. In its October report, Ofgem suggested that it had detected a higher than normal level of maintenance during the summer of 2003 which, the regulator believed, had contributed to the price spike that year. The CIA suggested that there should be an inquiry into whether the closures for maintenance that year were justified and carried out in a timely manner.[155] The oil producers argued in effect that Ofgem was wrong: there had not been significantly more maintenance in the summer of 2003 than normal; there were practical reasons why different companies working in adjacent or linked fields might undertake maintenance at the same time (because maintenance on a trunk pipeline would prevent them from transporting their gas anyway, or because they could improve efficiency by timetabling maintenance so as to make best use of scarce pieces of maintenance equipment); and they suggested that increasing numbers of unplanned outages—breakdowns—were to be expected given the age of infrastructure in the UKCS and the incentives to produce as high a volume of gas as possible.[156] We asked Ofgem whether it still believed that maintenance levels had been unusually high in 2003, and Ofgem replied that it stood by its earlier assessment.[157]

57. Whether all closures of offshore production for maintenance in the summer of 2003 were justified is an argument that is unlikely to be resolved. As Ofgem pointed out, the main problem is that there is little or no information about levels of maintenance in previous years[158]—though this difficulty will be dealt with over time under the new agreement under which producers will notify National Grid Transco (NGT) and the market of maintenance plans.

58. We received no evidence that producers have withheld supply from the market to drive prices up. None of our witnesses has suggested collusion or any other illegal behaviour in the offshore production market; nor do we consider that the sharing of information between companies owning or making use of the same facilities is improper or unnecessary. However, the structure of the UKCS production market does mean that participants in it have access to significantly more knowledge than those to whom they are selling their gas. We note also that there have been allegations in the past that the oil majors have shown a disinclination to share infrastructure with newer market entrants—a situation that, the industry hopes, it has addressed by a new Code of Practice "to ensure equitable and timely access to infrastructure", which was launched in September 2004.[159] These factors, together with the fact that the big gas production companies also act as shippers, result in a market where actual competition appears less than might be expected from the number of players and market share. This leads to a further question, which is whether the market therefore needs to be regulated or made subject to closer monitoring. We discuss this later in this Report.[160]

Shippers

59. We were concerned about the lack of shippers active in the forward gas wholesale market in the autumn of 2004, as reported to us by would-be purchasers. Ofgem provided a list of 164 companies to which it had issued shippers licences. On closer analysis, a number of these were either subsidiaries of other companies or in administration, leaving around 100. However, according to Ofgem's published information, only 27 of these companies were active suppliers of gas, 25 to smaller I&C customers (buying 50,000 therms or less) in July 2003, and 20 supplied the largest customers (buying over 50,000 therms).[161] One of these companies, BP Gas, which supplied both small and large customers, has since exited the market. Centrica thought that a dozen or so shippers did the bulk of the trading in the wholesale gas market.[162] Ofgem said that 14 shippers accounted for 90 percent of trade on the wholesale market.[163] This accords with Ofgem's broad indication of market share, where 21 of the 25 listed shippers supplying smaller customers, and 13 of the 20 shippers supplying larger customers, had a market share of less than five percent. Ofgem further said that those who were both producers and shippers probably accounted for between 70 and 80 percent of the trade in the wholesale market for I&C customers and owners of power stations.[164]

60. We wished to pursue this analysis further by, for example, finding out how actively each of these 20 or so companies engaged in trading, and how many of them competed for different types of business. However, Ofgem told us that it was constrained from releasing any more detailed data by its statutory duty to maintain commercial confidentiality of certain types of information, under section 105 of the Utilities Act 2000.

61. This is a pity, as the extra data would have enabled us to place in context the anecdotal evidence about a severe shortage of sellers in the forward market in September to October 2004. However, Ofgem, which does have this data, told us that six or seven shippers were active in the forward market. Both Centrica and Ofgem referred to the effect on the wholesale market of the exit—by one means or another—of the American traders which had been market makers: Enron, Dynergy, TXU, Reliant, El Paso, and so on. These companies had been willing to work on a speculative basis—in other words, to sell short.[165] The disappearance of such traders had had the effect not only of reducing the number of companies trading in the market (Centrica estimated that the amount of liquidity in the futures market had decreased by 40 percent between 2002 and 2004[166]), but also of limiting other companies' ability to trade. As Mr Steve Smith[167] explained: "Following the demise of Enron, the capital markets are looking much more closely at companies which trade electricity and gas and putting much more pressure on them to look carefully at how much risk there is in the business and place limits on their ability to trade." The credit limit placed on trading companies was, we were told, typically about 40-45 pence a therm. Mr Smith added, "Clearly, liquidity has fallen" and "I think it is a fair issue … whether above a certain level of price the market becomes thin."[168] In other words, the banks financing shippers have prevented them from buying gas when the price rises above a certain level, in order to reduce the risk to the lending institutions; but this has the effect of limiting trading with the result that prices rise even higher. Ofgem was of the view that this lack of liquidity over a certain price was a common feature of traded markets.[169]

62. For the future, Centrica thought that the example of the profits that could have been made in the autumn of 2004 would tempt more players into the wholesale gas market.[170] Ofgem reported that one or two new companies had recently entered the market as shippers, and there were rumours of interest among some of the hedge funds and other large financial institutions.[171] Both thought that greater transparency in the market was vital to enable buyers to take informed decisions on risks; but the real need was for more supply and a greater diversity in the sources of supply.[172]

63. A gas shipper also explained why—as reported by I&C customers—the few quotes that they did receive varied so little. The basis on which suppliers quoted prices to a large I&C customer was the forward market price plus a small margin, so quotes tended to be very similar. Centrica said that as a shipper it found it "very difficult to compete in that market."[173]

64. Ofgem asked the Financial Services Authority ('FSA') to investigate certain aspects of market behaviour during the price spikes in 2003 and 2004. On 4 October 2004, the FSA issued a press release saying that it had found no evidence of conduct that warranted further action on its part. A number of our witnesses were surprised at this outcome. We therefore wrote to the FSA asking for further information about their investigation. The FSA explained that it had received specific complaints about the actions of two named companies in 2003, and described the scope of its investigation into these. It had found that the conduct which had caused the complaint "fell outside the scope of our market abuse regime" and had decided not to pursue any charge of market manipulation[174] because this, being a criminal charge, involved a high burden of proof. As for the concerns about the autumn 2004 price rises—which were much higher and were the proximate cause of our inquiry—the FSA reported that there had been no specific allegations, so it had simply asked questions of a range of market participants to gain a better understanding of prevailing conditions. The consensus of those questioned was that "the market was driven by fundamentals and not by any inappropriate behaviour in the traded market", so the FSA decided not to pursue the matter any further. However, the FSA was careful to point out that its remit is limited in respect of the physical market for gas: its primary concern is contracts traded in exchanges.[175]

65. There is a serious shortage of companies willing to sell gas in the wholesale market when prices are high. Unfortunately, because of the tight supply situation, prices are likely to remain high over the next two years. This does not bode well for I&C customers. We hope that Ofgem's prediction about the imminent arrival of more active traders proves correct. Perhaps—if they are financial institutions themselves—they will not be subjected to as tight a credit straitjacket as current market traders, and greater liquidity will return. However, we can only conclude that at present the market is not functioning efficiently. Price spikes are more and more frequent, and they seem to be higher each time. Much of the volatility can be attributed to real difficulties in balancing supply and demand, but the scale of the peaks will remain high until more traders are encouraged to sell short.

Lack of information about the market

66. A recurring theme in the evidence we received was the limitation on competition imposed by the paucity of timely and accurate information in the wholesale gas market. The main problem was the lack of information about gas flows from the UKCS. Until recently, even NGT was experiencing difficulties in obtaining enough information to enable it easily to plan the balancing of the system. As a result, over a period of several years,[176] the DTI persuaded the production industry of the need to release more information and negotiated with the industry a voluntary agreement on the types of information to be supplied and the form in which some of the information was to be released.[177]

67. The process has been a gradual one. In November 2003 the production companies agreed to standardise the information about available gas supplies and planned and unplanned maintenance shutdowns provided to NGT via the operators of the beach-head terminals. In March 2004 they agreed to provide, on a confidential basis, further operational and planning information to help NGT's ten year planning process. More pertinently for our inquiry, they also conceded that NGT should provide certain information to the market in an aggregated form. This information falls into four categories:

— Category 1: physical flows of gas, close to real time

— Category 2: forecast flows, ahead of the day and hourly throughout the day

— Category 3: deliverability of gas (reflecting planned maintenance)

— Category 4: sub-terminal 'after-the-day' flows.

Information under Categories 3 and 4 is already available on NGT's website; Category 2 is expected to become available on 15 March 2005; and Category 1 is expected to be available during the third quarter of the year.[178] NGT told us that the reason for the delay in publishing Category 1 and 2 information was the difficulty in devising the processes and establishing IT systems robust enough to enable a large quantity of data to be accessible in a comprehensible form.[179] UKOOA and BP felt that, taken as a whole, the information to be released "will address the market issues."[180]

68. Although all our witnesses welcomed the provision of the extra information by the production companies, some argued for further disclosure. energywatch advocated the model applied to the electricity industry, under which anyone could obtain from websites real time information on the amount of power being produced by each generating station and the bids being made in the markets for the power available. It wanted Transco to publish real time information about sub-terminal gas pressure and planned maintenance, and it warned that further measures might be necessary. energywatch also disliked the voluntary nature of the current disclosure by gas producers: it suggested that the licences for the offshore industry should be revised to ensure the disclosure of information to all market participants.[181] energywatch's proposals were supported by the CIA, E.ON and Scottish and Southern Energy (SSE).[182] SSE argued that only if there was as much transparency in the gas as in the electricity market would buyers of gas accept that the prices they were being offered were fair.[183] An alternative model, suggested by the CIA, was that provided by the US Energy Information Administration.[184]

69. Centrica said that, as a producer, it was willing to provide further information—after all, within two years its ability to supply 25 percent of its own needs from its production facilities would have fallen to 20 percent, so it had an interest as a purchaser of gas. It suggested that the type of extra information likely to be most useful related to maintenance: it argued for a fairly tight time period for reporting unplanned outages and for a requirement to give some indication of how long they would last, and was generally concerned that, under the recently agreed arrangements, there was no requirement on producers to explain why gas was not flowing.[185] However, Centrica understood why other producers might be reluctant to provide further information: if a company faced production problems which made it difficult to honour contracts for the supply of gas, it would want to be able to buy the replacement gas before the market became aware of its difficulty and the price rose accordingly. Centrica suggested that the key to providing extra information was aggregation: if aggregation was feasible, then enough information could be provided for market participants to be able to make rational buying decisions, but without causing disadvantages to any specific player.[186]

70. NGT said that there were practical difficulties in supplying further information[187] and it gave us a comprehensive explanation of why this was so. The background was that in many cases NGT did not itself own the flow meters at the beach-head terminals, and therefore did not own the data provided by these meters. In essence, there were two issues. The first was a statutory limitation on its right to disclose information relating to individual companies that it had obtained in the course of its activities as the operator of the transmission system (section 105 of the Utilities Act 2000, again). The second was the fact that the flow meters at the various sub-terminals did not provide strictly comparable or easily interpreted information, so release of such data in real time—and therefore in raw form—would at best be costly for market participants to analyse individually and at worst, if not properly interpreted, could mislead the market. NGT's solution had been to aggregate the data and provide it an hour in arrears, rather than in real time.[188]

71. We asked why it had taken so long for the industry to agree to supply the basic information now being made available; and why there had been such a difference in transparency between the gas and the electricity markets. UKOOA argued that the gas wholesale market was still a young and developing market, whose needs were gradually becoming apparent.[189] Although the wholesale gas market is fairly young, it is a fundamental principle of all markets that they cannot function properly without all parties having roughly equal access to basic information. More plausibly, NGT cited the genesis of the electricity wholesale market from a nationalised industry, with the associated regulatory regime when it was privatised; whereas the 'North Sea' was seen as a functioning, competitive market from the start. While the electricity industry is used to, and accepts, the need to provide ample information to the regulator, systems operator and market participants, this is a novel situation for the major oil companies.[190]

72. We understand and accept NGT's explanation of why it is currently impossible to provide real time information on gas flows. This may not be very significant: information delayed by an hour represents a huge increase in the transparency of this market, and is, we believe, quite sufficient for the needs of customers. However, we suspect that to restore market confidence there may be a need for still more information about production outages, not least because of the mistrust that has arisen over maintenance patterns in 2003. It is too soon to make a firm judgement on this, but we recommend that the DTI and Ofgem keep a watch on this area to see whether further information is needed.

73. We note that the Norwegian gas production companies have agreed to participate in the arrangements for providing voluntary information.[191] We welcome this. We consider that the advantages of receiving information from all major parties, albeit on a voluntary basis, outweigh any benefit from imposing any element of compulsion which might lead the Norwegian companies to withdraw from the scheme altogether.

96 See, for example, App 14 (E.ON), paras 12-15 Back

97 Q 374 Back

98 Q 351 Back

99 Q 352 Back

100 Only a quarter of exploration wells are successful. Back

101 We were told that the average discovery size is half what it was a decade ago, being typically 25-30 million barrels in size: Q 108 (UKOOA) and App 29, para 38 Back

102 For example, BP explained that about a third of its remaining reserves of about 4.5 billion barrels presented considerable technological difficulties to extract: Q 111 Back

103 Qq 115-116 (UKOOA) and App 30 Back

104 For a succinct description, see App 29, paras 24 and 36-38 For confirmation of the degree of maturity of the UKCS as a province, see Q 225 (Shell) See also Q 111 (UKOOA and BP) Back

105 App 29 (UKOOA) para 42 and Q 108 Ofgem said that at present 'new independent players' account for about 30 percent of UKCS gas production: Q 454 Back

106 Q 109 Back

107 Q 367 Back