Select Committee on Trade and Industry Second Report


Gas network

25. The UK gas transmission system is a network extending from Aberdeenshire to the South West of England. The network is fed through seven beach terminals at which gas from more than 100 gas fields on the UK Continental Shelf is landed. The main terminals, in terms of throughput, are sited at St Fergus, in the North East of Scotland, and Bacton, Norfolk. Smaller terminals are sited at Theddlethorp, Lincolnshire; Easington, East Yorkshire; Barrow, Cumbria; Burton Point, North Wales; and Teesside.

26. In addition, gas could be supplied to the UK through an interconnector to the European gas networks. At present, the Bacton-Zeebrugge Interconnector is capable of transporting 20 billion cubic metres (bcm) per year from the UK to Europe, or 8.5 bcm in the other direction (although this capacity is planned to increase to 20 bcm in the near future.[21]) The technical feasibility of a second interconnector between the Netherlands and the UK is under consideration by a number of potential investors and if developed would provide a valuable alternative route. The UK is currently a net exporter of gas but, in the course of 2000, imported about 2% of its gas demand of about 97 bcm per year. Some predictions indicate that by 2006 this may rise to 15%.[22] An Irish Interconnector running from Moffat in South West Scotland to Loughshinney near Dublin delivers about 4.7 bcm gas to the Republic of Ireland to meet 50% of Irish needs.

27. The physical infrastructure has been identified by several witnesses as the most serious security-of-supply issue to be addressed in the gas sector.[23] At present, gas throughput is concentrated at St Fergus and Bacton and the capacity there might not be adequate to meet demand and guarantee security and reliability of supply.[24] It also leaves the system open to the risk of major disruption in the event of serious accident (such as the explosion at the Esso Longford gas plant in 1998 in Victoria, Australia, which disrupted supplies across the State for nearly two weeks), or terrorist attack.[25]

28. Concerns over bottlenecks in the gas transmission system seem to us to be well-founded. The Government should keep under the review the need for more gas landfall facilities and the advisability of greater diversity in the siting of such facilities. It should consider whether the market alone will provide the necessary incentives for this investment, given the lead-times needed for such construction projects.

29. Several witnesses emphasised the need to ensure higher investment in the distribution infrastructure itself. As the Regulator, Ofgem has the responsibility for ensuring that the correct signals for investment are given to the market via the gas trading arrangements. Its effectiveness in this role is discussed later in this Report.[26]

30. The gas grid is a high-pressure (up to 75 bar) transmission system which moves gas at 25 kph through the network, progressively reducing the gas pressure according to the needs of the end consumer, to the point where domestic appliances receive gas at about 25 millibar. The network is not comprehensive. Homes in large tracts of Great Britain are without a domestic gas supply, on the grounds that it would not be commercially viable for gas suppliers to provide the infrastructure necessary to extend the domestic distribution system.[27] This is a particular problem for householders in Scotland, Wales and rural England and presents an obstacle to the development of Combined Heat and Power (CHP)[28] and micro-CHP facilities in those regions where natural gas is not available. While we recognise that there are practical and economic factors which hinder the further extension of the natural gas distribution network, it remains a matter of concern to a large number of potential consumers, who consider themselves to be disadvantaged by the restriction on their freedom of choice. The Government should consider whether further encouragement could be given to Transco and the supply companies to address this anomaly.

Gas storage

31. In the UK, BG Storage provides gas storage services to a wide range of customers operating in a competitive market. The company utilises man-made salt cavities at Hornsea, Yorkshire, to store gas 1800 metres below ground. The Rough field is a partially depleted gas field in the southern North Sea which has been developed to store natural gas 3,000 metres underground. More limited storage facilities for LNG are situated at locations close to Bristol, Strathclyde, Rochester, Manchester and in Mid Glamorgan. In addition, Transco owns more than 450 overground gas holders, with a total storage capacity of 24 million cubic metres of gas at low pressure for delivery to domestic and industrial consumers. These are scheduled to be phased out over the next ten years or so. In practice, the North Sea gas fields have themselves been regarded as reserves in the past, in that they could be tapped to a greater or lesser extent, within transmission and compression limits, depending on demand.[29] Compared to countries elsewhere in Europe, the UK has very limited purpose-built storage facilities, providing for less than 4% of annual consumption. In comparison, France, Germany and Italy each have storage capacity in excess of 20% of annual consumption.[30]

32. There is currently no statutory requirement for the provision of strategic gas reserves, unlike in the coal and oil sectors. While, in general, the UK Offshore Operators Association (UKOOA) and the gas supply companies did not feel that this should pose a particular problem, given secure access to the offshore gas fields and the gas interconnectors, UKOOA advised us that operators would be prepared to invest in extra storage capacity once market conditions made it economic to do so.[31] The DTI reported that storage capacity had actually increased by 10% since deregulation of the gas sector. We accept that in the past ready accessibility to UK gas reserves may have justified the relatively low priority which has been attached to the development of strategic gas storage in the UK and we recognise the cost implications of such a development. However, it is widely anticipated that the UK is to become a major net gas importer, which would put it in the same situation as other EU member states which are dependent on external sources for supply of natural gas. To guard against the unforeseen disruption of external supplies, it would be prudent for the Government, together with the industry, to give serious consideration to the development of strategic storage capability.[32]

The Electricity Transmission Grid and Distribution Systems

33. Historically, the electricity transmission network has been developed around large scale fossil fuel-fired or nuclear generating stations, usually of more than 1000MW generating capacity. These power stations were sited either close to fuel sources, for example on coal fields, or with deep-water access to allow fuel delivery by sea. Additionally, coastal siting gave easy access to adequate cooling water for all types for power station, notably nuclear facilities.

34. The national electricity grid system is designed to accommodate large injections of electrical energy from these power stations and is operated at very high transmission voltages (275kV and 400kV) for reasons of efficiency. Large amounts of electricity are moved around the country using the transmission system for delivery to 'bulk supply points'. Here, electricity is transformed down in voltage for onward movement via distribution networks to commercial, industrial and domestic customers, each category operating at lower voltages.

35. The operation and control of the grid is the responsibility of a grid operator (the National Grid Company (NGC) in England and Wales, for example). The operator ensures that generating companies have access to the transmission network and that the level of supply balances the level of demand on an instant-to-instant basis. Stations are 'despatched', that is they are instructed to produce electricity in order to help the operator maintain the demand/supply balance. With conventional power stations, despatch is reasonably straightforward since they hold stocks of fuel and can generate at will, but small-scale generation (for example, from renewable sources such as wind power) is often available only on an intermittent basis and consequently is not deemed despatchable. Instead, a scaled value of the rating of the plant is taken to be equivalent to despatchable plant, so-called declared net capacity (DNC). For example, for wind energy, DNC is around 35%, so, basically, a 100MW wind farm is regarded by a network operator in the same light as a 35MW conventional station. However, some renewable sources are more predictable than others and some can be despatched. With the current low level of penetration of renewable energy into the network, the operators can cope with the intermittence of generation. Some commentators believe that if renewable energy developed to the point where it was supplying 20% or so to the grid, system operation might become a matter of concern. Others believe that new methods of system operation will be developed and that effective operation will be possible.[33]

36. The distribution network was not designed in the same rigorous way as the transmission network. Rather it grew as demand presented itself. For example, a small industrial estate might be built outside a town and would have to be supplied with electricity, so the distribution network would be extended to accommodate the new demand. It is at this level in the electricity network that small-scale generators are connected since connection at transmission level cannot usually be justified either economically or technically. Connections made at distribution voltage are known as 'embedded generation'.[34]

37. While small-scale generators are not usually connected directly to the transmission network, they may use that network to move power around. For this, they incur 'use-of-system' charges which are based on the degree to which they place a burden on the network.

38. The current design of the electricity grid presents several challenges to the renewable energy and combined heat and power industries.[35] The existing networks were designed for tapered voltages, reducing from the very high voltage of the transmission network through the distribution system down to the domestic consumer's voltage. Voltage levels depend partly on the settings of equipment on the network and partly on the direction of the flow of current in the network. If current flows are reversed, which happens when power flows are reversed, voltage tapering will be reversed. This can have a significant and detrimental effect on the protection systems of the network and on the continued stable operation of the network. Embedded generators provide electricity into the system at distribution level, where it was not originally expected. Protection systems on the distribution network have to be reassessed and, in most cases, redesigned. This problem is most difficult with intermittent energy sources, such as wind energy: when no power is generated during flat calm the direction of power flow will be the 'conventional' direction; when the wind blows, it can be opposite to that.

39. There are statutory limits for voltage, frequency and availability for the network. The system operator maintains these by despatching plant and by controlling power flow. When a perturbation occurs to the network there will be a momentary mismatch between supply and demand. If this mismatch continues the resultant network frequency change will be detected by automatic protection devices. Such devices will disconnect sections of demand until a balance has been achieved. In the most extreme case where no balance could be achieved, the fault would cascade through the entire network causing it to shut down. In the present UK network, this is extremely unlikely.

40. The first responsibility of the network operator is to protect the network. Any installation connected to the network must not jeopardise its operation. The 'fault level' at a particular point is the maximum power flow in the network as a consequence of a failure in the equipment at that point. In many cases, the fault level at an embedded generation site is well above the power generation capability of the embedded station. To protect the existing grid, equipment at the embedded power station must be installed by the network operator to meet this more onerous (and more expensive) rating. The owner of the embedded station will normally be asked to bear the cost of upgrading immediately, rather than being allowed to spread the cost over the lifetime of the plant. The cost of both connecting the generating plant and dealing with any consequent changes to the distribution network, we were told, "can stop [renewables] projects in their tracks".[36] The Renewable Power Association explained that the charges could reach anything up to £1 million per megawatt, which was often more than the value of the renewable development itself.[37] We took evidence on the problems caused for renewable power by the present arrangements for connecting to the distribution network. The Association of Electricity Producers said that the real problem was the fact that producers had to pay these 'deep connection' charges immediately. An alternative would be to change to a system of 'shallower connection', where the producer would pay a smaller charge immediately, and the costs of the consequential changes to the network would be recovered from the producer over a longer period by means of charges for using the system.[38] Ofgem is at present undertaking a consultation on the whole issue of connection charges.[39] A number of witnesses thought the timing of this very useful because it would enable decisions to be taken well ahead of the next price review for the distribution companies, which would be held in 2005.[40] Connection charges represents a serious obstacle for small scale generators which can affect the viability of developments which may otherwise be financially sound.

41. The present network was designed to include points where the network could accept and distribute large quantities of electricity. With embedded generation, such points do not usually exist and the construction of a new embedded generator will necessitate a local upgrade of the distribution network. While this process is not difficult technically, involving the 'restringing' or 'reconductoring' of wooden poles or the introduction of new distribution lines, it does incur significant cost. Since many new generators are in remote areas, the cost of providing the necessary connection and distribution infrastructure can be such that the expense will preclude the building of one, or several, power stations.

42. The present transmission network and distribution networks are, understandably, strong near the main centres of population. While embedded generation, such as CHP schemes, can often (but not always) be installed at suitable places in the existing electricity network, the probable location of a significant proportion of the UK renewable energy generation capacity is not convenient. Renewable resources, predominantly in the North and West of Great Britain, are far from the major electricity markets of the Midlands and the South East of England and the transfer of large quantities of energy presents a challenge to their exploitation. The use of conventional overhead transmission (pylons) is the cheapest and most technically-attractive solution, but major environmental hurdles would have to be overcome to drive transmission lines through areas like the Western Highlands, for example.[41] An existing transmission bottleneck in Yorkshire already makes it difficult to export power from Scotland to England. Land cabling over such distances would be extremely expensive (up to twenty times the cost of overhead) and technically demanding, as well as controversial environmentally. The Minister conceded that one of the difficulties in the way of exploiting wind and wave power fully was the immense — and perhaps insuperable — objections to strengthening the transmission network on land to the extent required.[42] Furthermore, proposals to make charges for the use of the transmission network more cost-reflective (by, for example, increasing them for electricity lost in transmission, which would penalise the more distant electricity producers) would have a significant effect on many existing and proposed renewable energy developments.[43]

43. We have highlighted a number of areas where the systems in place for electricity transmission and distribution present technical and economic barriers to the future development of renewable energy and embedded generation. It could be argued that such obstacles will be overcome once the electricity market conditions make it economically viable, but this would ignore the rate at which such capacity must be developed if the Government's targets of reduced reliance on carbon-based energy sources are to be achieved in practice. The Government needs to take a strategic view of what is required and to have a clear idea of what mechanisms it could use to steer the market to provide the necessary infrastructure.

Future investment in transmission infrastructure

44. The DTI recently announced a feasibility study of proposals to run a submarine cable from North West Scotland down the West coast of Great Britain to provide a transmission system for offshore and other renewable energy generation. This would appear to have great potential to alleviate the problems caused by the North-South transmission bottleneck and would provide a significant boost to the development of renewables such as offshore wind and wavepower. It seems to us that the installation of hundreds of kilometres of cable in areas of some of the most hostile seabed and surface conditions around the UK would be a severe engineering test and could prove to be very cost-intensive. The identification of a suitable bulk injection point(s) to connect to the existing network would be an important consideration. In this regard, we were surprised to hear from NGC that the company had not been involved in preliminary discussions during the development of the project proposals.[44] Given the misgivings that have been expressed we welcome the feasibility study commissioned by the Government.

45. The costs of such a cable would be very high. Greenpeace expressed the view that the cable should be paid for by the Government, on the grounds that existing, land-based power generating companies had benefited from the earlier creation of the transmission/ distribution networks using public money, and that providing offshore renewable power generators with a similar infrastructure was only fair.[45]

46. In general, the Government relies on the regulatory regime to produce the right market signals to secure investment to maintain and develop the distribution systems in both the gas and electricity sectors, although different regulatory devices are used in each case. For the electricity industry, planning standards are used to maintain supply security. The NGC is required to report on the state of the transmission network and to provide forecasts of power flows and loading on all parts of its system, by means of the Seven Year Statement that it produces as a condition of its licence to operate. Distribution companies must meet minimum supply security standards and publish five-year outlooks for investment in their part of the infrastructure. Ofgem intends to introduce new transmission access and pricing arrangements to ensure that the true value of transmission access can be identified. This could place a further hurdle in the way of the creation of a network suitable for renewable energy generation.

47. For the gas sector, Ofgem has developed proposals for long-term signals and incentives to investment by Transco. Ofgem will provide for longer-term auctions of rights of entry to the transmission system.[46] It is intended that these auctions, together with data on the secondary trading of transmission capacity, will provide Transco with signals about the need for new capacity and additional investment, and that the new price proposals agreed with Transco will give the company the financial capability to make such an investment.

48. Much of the concern about whether there will be sufficient investment in future infrastructure needs focuses on the operation of the "RPI - x" formula (Retail Price Index minus a stated percentage) for energy pricing. The Regulator has used this formula since privatisation to provide downward pressure on prices for consumers, and it has clearly been very effective; but it has been vigorously criticised both by energy companies and by some other commentators on the grounds that it encourages the 'squeezing' of existing assets without encouraging companies to make necessary investment: in effect, companies are using the over-capacity built into the system in the days of nationalisation to meet demand without making provision for future needs.[47] Some critics even suggested that the formula, by encouraging short-term exploitation of assets, not merely failed to encourage long-term investment but actually discouraged it.[48] Mr Callum McCarthy, the Chief Executive of Ofgem, admitted to us that RPI - x was "essentially a revenue cap and did not do enough to define outputs" in terms of service standards; but he said that Ofgem did not accept that the formula needed to be scrapped: it would be adjusted, not thrown out of the window.[49]

49. We are pleased that Ofgem is reviewing the operation of RPI - x and is aware of the need to devise a formula that will give clearer signals to the market about long-term investment. We also note that, by the time we took oral evidence from them, both NGC and Transco expressed themselves satisfied that their concerns about investment needs would be taken into account.[50] However, even the most enthusiastic advocates of market forces admitted that liberalised competitive markets did not necessarily provide investment in areas like infrastructure,[51] and that state intervention might be necessary. We concur in this view, and therefore urge the Department and Ofgem to make it a priority to ensure that companies are given sufficient leeway to invest in maintaining and developing a robust energy infrastructure, and to continue to keep under review all the mechanisms available to ensure that there are no regulatory/fiscal disincentives to such investment.

21   A new compressor has to be installed at Zeebrugge before the gas flow to the UK can be increased. The upgrading should be completed in 2005-6: Q 668 (Lattice/Transco). Back

22   Transco noted that whereas "last winter" (ie 2000-01) there were gas imports on peak days, by 2005 the UK was likely to have to import in average winter conditions (Q 659). Centrica estimates imports will run at about 20% in 2010, notwithstanding further development of the UKCS (Appendix 27). Back

23   See, for example, Qq 90-2 (Gas Forum), 376 and 377 (Chemical Industries Association), 461-3 (Electricity Association) and 667 (Lattice/Transco); Appendices 14 (Memorandum from Jonathan Stern) and 30 (Memorandum from Total Fina Elf Holdings UK Ltd). Back

24   See the concerns expressed, for example, by the Gas Forum (Qq 92, 111, 120 and 137); UK Offshore Operators' Association (Qq 206 and 233); Chemical Industries Association (Q 377); Lattice/Transco (Qq 667 and 668); Centrica (Appendix 27, paragraphs 23-24); and Total Fina Elf (Appendix 30). Back

25   Appendix 14 (Jonathan Stern). Back

26   Paragraphs 48 and 49 below.  Back

27   Q 642 (Energywatch). Back

28   For a description of CHP, see the annex to this Report, p.77. Back

29   Qq 121 and 128-131 (Gas Forum), 218 and 222 (UK Offshore Operators' Association), 663 (Lattice/Transco). Back

30   Q 123 (Gas Forum). Back

31   Qq 122 and 128-31 (Gas Forum), 218-221 and 226 (UKOOA), 674-7 (Lattice/Transco). Back

32   Standards may have to be set at a European level: see Qq 663-4 (Lattice/Transco) and also the interesting options put forward by Lattice in Appendix 25. Back

33   As might be expected, the British Wind Energy Associations believes any problems can be overcome (Appendix 11). The potential problems caused by intermittency are discussed further in paragraphs 38-40 below. Back

34   Larger renewable energy generators, such as some offshore wind farms, might, however, be connected directly to the transmission system: Qq 710 and 711 (NGC). Back

35   See the comments of Northern Electric (Appendix 10) and British Wind Energy Association (Appendix 11). Back

36   Q 349 (AEP). Back

37   Q 358. Back

38   Q 349. The National Grid Company told us that its approach for renewables projects large enough to connect directly to the transmission network, was to charge on a 'shallow' basis, recovering the other costs by means of a location-based tariff which imposed higher costs the further the generators were from their customers (in order to reflect transmission losses): Qq 710 and 711. Back

39   Ofgem recognises the great importance of this work to the development of renewable energy in the UK: Qq 527 and 528. Back

40   Qq 349 (AEP) and 602 (Energy Saving Trust). Ofgem's consulation document on this subject is entitled Embedded generation: price controls, incentives and connection charging (September 2001) and is available at The deadline for responses was 16 November 2001. Back

41   The National Grid Company told us that, because of cost and planning difficulties, "We try to avoid building any new [transmission lines] at all costs." (Q 688) Back

42   Q 299. Back

43   Appendix 38 (Ofgem's Supplementary Memorandum). See the views of the Electricity Association, Qq 466 and 467, 469 and 470. For a description of the problem of transmission losses, see Qq 707-9 (NGC). Back

44   Qq 712 and 713. Back

45   Q 542. Back

46   See paragraphs 71 to 73 below on gas auctions. Back

47   Qq 139 and 140 (Gas Forum), 461-3 (Electricity Association), 705 and 706 (NGC). Lattice/Transco and UKOOA argued that even the service requirements (for example, to meet a peak demand for a 1 in 20 winter) did not give sufficient flexibility, and Ofgem should recognise the need of the transmission companies to invest in extra capacity: Qq 233 and 679. Ofgem suggested that there were differences between the gas and electricity networks: although little extra infrastructure might have been provided for the electricity network, the gas network had expanded significantly since privatisation: Qq 529 and 30. Back

48   See, for example, the comments made by the Electricity Association (Q 461), pointing out that with a price review period of five years, it is very difficult for Ofgem to take into account the sort of long-term investments needed to be made now in order to ensure security in 15 or 20 years' time. Lattice (Q 679 and 683) complained that, in fixing transmission companies' prices and terms, Ofgem disallowed investment in necessary extra infrastructure capacity on the grounds that it was too expensive to the consumer. See also Appendix 10 (Northern Electric). Back

49   Qq 497 and 498. Back

50   Although some reservations were expressed by Transco: see, especially, , Qq 683 and 684. For NGC see Qq 705 and 706. Back

51   Appendix 16 (John Mitchell, paragraph 7). See also Q 669, where Lattice/Transco describes how upgrading the Zeebrugge compressor would significantly increase security of gas supplies for UK consumers but, because it would be used only a few days per year, might not be worth the extra investment to the owners of the compressor. Back

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