Select Committee on Business and Enterprise Eleventh Report

3  The wholesale electricity market

43. As Good Energy said, the wholesale and retail markets "are closely interlinked and it is the problems with the wholesale market structure that are restricting competition in the retail market".[76] The wholesale electricity market is shared between the 'Big 6' vertically integrated firms, which also operate in the retail/supply sector, and a number of independent generators, the largest of which are British Energy, Drax Power, and International Power. Figure 5 below shows the breakdown of market shares between the companies. In this Chapter we look at the influences on wholesale prices, and the current structure and operation of the market.

Figure 5: General output shares, 2007

Source: National Grid

Rising input prices

44. As noted in Chapter 1, wholesale electricity prices have been increasing since spring 2007, and are currently higher than those for many of the UK's main competitors, including France and Germany. There are several factors behind the increase in prices, but the most important is the higher cost of gas and coal, which provide respectively 37% and 38% of GB power generation. Figure 6 below shows the recent trend in coal, gas and oil prices in relation to electricity. Those for gas and electricity have mirrored one another consistently, reflecting the role of gas as the marginal source of generation. Whereas during winter 2005/06 the price of coal remained stable, since 2007 its price has roughly doubled, following the same trend as for oil and gas. The recent concurrent increases in the price of coal and gas means most power producers have faced the same rising input costs, regardless of their generating portfolio. We accept that this may go some way to explain the apparent synchronisation of electricity suppliers' prices increases in early 2008.

Figure 6: UK Energy Prices May 2005 - Mar 2008 (30 day moving average)

Source: Bloomberg

Rising environmental costs

45. Since the establishment of the European Union Emissions Trading Scheme (EU ETS) in 2005, the cost of carbon has been factored into the wholesale price of electricity by generators. Phase 2 of the Scheme, which began in January 2008, has created a carbon dioxide price of around €20-30 per tonne.[77] Under Phase 2, electricity generators receive a large proportion of their carbon permits at no cost. However, Ofgem and the European Commission told us because permits have a market value generators have benefited from windfall profits by increasing their wholesale prices to reflect the opportunity cost of using their permits.[78] This is because power companies could choose not to generate electricity and, instead, sell their free permits on the open market. They need wholesale prices to rise by at least the value of their permits in order for them to have an incentive to generate.

46. Ofgem believes the EU ETS adds around £9 per megawatt hour (MWh) to the wholesale price of electricity, which translates into a £9 billion windfall to the UK electricity generating sector over the lifetime of Phase 2, from 2008 to 2012.[79] Similar outcomes can be expected throughout the European Union, so this factor plays no part in the differential in prices between the UK and the Continent. For Phase 3 of the EU ETS all carbon permits will be auctioned, so the windfall will not arise. It therefore represents a one-off gain for the generators. Several of the 'Big 6' firms accepted that they had, to varying degrees, benefited from the free allocation of allowances, but told us the money was either helping to shield their customers from higher costs, or to fund investment in new plant, and plant that would otherwise have closed.[80] Scottish Power questioned too, whether Ofgem's estimate of £9 billion was accurate, given it is based on a simple multiplication of the value of permits by the number of free permits given to companies.[81] As well as the 'Big 6', the independent generators will also have benefited under Phase 2 of the EU ETS. For example, Drax Power reported in July 2008 that it was sitting on a £100 million cash surplus, which it planned to return to shareholders as a special dividend.[82] The Government will also gain financially from the auctioning of 7% of the permits under Phase 2. The CBI has estimated the value to the Treasury of these at £1.6 billion.[83]

47. It is clear that the 'Big 6' firms and the independent generators have, to varying degrees, benefited financially from the free allocation of permits in Phase 2 of the EU Emissions Trading Scheme. However, the magnitude of this windfall is not clear. Furthermore, at least some of the value may be passed on to consumers through lower prices, via cross-subsidy from their generating arms, while some may support much needed investment in new capacity. We are disappointed by the superficiality of Ofgem's current analysis. We recommend that the Government now conducts and publishes a rigorous analysis, estimating the value of any windfall profits which companies have gained, and the use to which they have been put, or are planned to be put. It is only on this basis that the Government can then decide if there is a case for reallocating some of this windfall—an issue we return to in Chapter 5.

Market concentration

48. Based on output, the wholesale electricity market has a Herfindahl-Hirschman Index (HHI) of 986, which suggests relatively low concentration of market power.[84] Ofgem told us proposed new capacity would, if anything, reduce the market's HHI in the future.[85] That said, although the 'Big 6' accounted for 55% of output in 2007, Drax Power told us that through controlling interests, part ownership, and contractual arrangements the vertically integrated firms actually control just under three-quarters of price-setting plant (that which uses oil, gas or coal).[86] Moreover, there has been much speculation recently over the possibility of consolidation in the market, including a takeover of British Energy by one of the 'Big 6', and an acquisition of Scottish Power's parent company, Iberdrola, by EDF—thus resulting in an even 'bigger 5'. International Power, Drax Power and Energywatch expressed concern over the implications of such consolidation for the competitiveness of the generation market.[87] Although British Energy's nuclear power stations are not a price-setting power source in the wholesale market, Ofgem noted that a takeover of the firm, particularly by one of the European multinationals, could significantly reduce the amount of information on its generation and trading activities that it currently provides to the market.[88]

49. At present, Britain has a diverse electricity generation portfolio, owned by a number of different companies. However, we are concerned that this may be undermined by market consolidation, such as a takeover of British Energy or Scottish Power. Ofgem and the Competition Commission should ensure that, were this to happen, measures are put in place to protect current information flows to the market, and to ensure no single generator has excessive market power. We acknowledge the urgent need to secure investment in new generating capacity, but that investment must not come at the price of a less competitive or transparent market in the long term.

New capacity

50. In the coming years many coal-fired and nuclear power stations are due to close. Significant new investment in generating capacity is needed to replace them. Around 12 gigawatts (GW) of coal and oil-fired generation will be decommissioned by 2015 as a result of the EU's Large Combustion Plant Directive (LCPD), and 7.4 GW of nuclear power plant will have closed by 2020 as stations come to the end of their operating lives.[89] At present, BERR is aware of around 18 GW of potential new conventional generating capacity that is at various stages of development, over 90% of which will be gas-fired.[90] In addition, National Grid estimates up to 6.2 GW of onshore wind power and 2.5 GW of offshore wind power could come on-stream between now and 2014/15.[91] However, whether or not the required increase in capacity will be delivered within this timeframe depends on a number of factors, including the planning regime, the availability of transmission grid capacity to connect new generation, and the skills capacity of the construction industry.[92] The most important factor for private sector companies, though, is the likely return on investment. The long lead times for new plant, combined with even longer payback periods, means that companies need a degree of market certainty in order to have the confidence to invest.[93]

51. A properly functioning wholesale market provides sufficient price signals for firms to invest in new generating capacity.[94] We received conflicting evidence on this issue. Drax Power told us large conventional new capacity is mostly being built by the vertically integrated companies, whereas 'incentivised generation capacity', such as renewable energy projects, which are subsidised through the Renewables Obligation, were being delivered by a mixture of the 'Big 6' and smaller independent companies.[95] However, Ofgem highlighted, among other examples, the fact that Welsh Power—a small independent—is currently constructing an 800 MW gas-fired power station in South Wales. Elsewhere, Barking Power has recently secured planning permission for a 450 MW extension of its existing power station in east London. This suggests there are signs of new entry from firms outside the 'Big 6'. Nonetheless, independent generators clearly face greater challenges in seeking to enter the wholesale market. For example, the 'Big 6' companies are able to fund large-scale projects from their balance sheets.[96] They also do not face the same credit requirements for buying and selling electricity that independent generators do.[97] The wholesale market is also not sufficiently liquid for independent generators to be able to hedge their positions—an issue we consider in the next section.[98] In evidence, the Minister for Energy noted his concern that there was not greater new entry into the wholesale electricity market.[99]

52. The need for investment in new generating capacity—and associated transmission infrastructure—in the coming years is huge. This investment will only be delivered by profitable companies which see a commercial opportunity, whether they are existing players or new entrants. While the market seems to be providing price signals for the vertically integrated firms to invest in new large-scale conventional capacity, there is a question mark over whether new companies face disproportionate barriers to entry.

Vertical integration

53. Ofgem estimates that the 'Big 6' vertically integrated companies hold sufficient generating capacity of their own to cover their respective commitments to supply households and SMEs.[100] This business model has some advantages for consumers. By contracting internally, the 'Big 6' are able to reduce their transaction costs and protect domestic consumers from price volatility by cross-subsidising their supply operations.[101] The Chief Executive of Scottish and Southern Energy (SSE) told us: "At present […] supply is loss-making. If it was not for the fact that all of the six are vertically integrated, prices to customers would already be higher than they are now".[102] Scottish Power confirmed this, while Centrica told us its margin on the supply side of its business had averaged only 3.6% in the last four years.[103]

54. However, witnesses raised a number of questions about the vertical integration model. First, in order to cross-subsidise their supply businesses, the 'Big 6' firms must be making a reasonable level of profit in their wholesale businesses. The National Right to Fuel Campaign (NRFC) and the Government's Fuel Poverty Advisory Group (FPAG) both cited a paper by Cornwall Energy Associates that attempts to separate out the energy companies' input costs from their profits.[104] It estimates that while fuel costs doubled between 2003 and 2006 to almost £9 billion, profits rose almost five-fold, from £557 million to £2,635 million, most of which were attributable to profits in electricity generation. The FPAG noted that in 2003 profit levels were unsustainably low, given the level of investment required in the sector. However, its Chairman also acknowledged the difficulty in defining what a normal level of profit might be, stating that: "Clearly the pendulum has gone the other way for various reasons and they [the 'Big 6'] are now making very significant profits".[105] It notes too that while the EU ETS windfall will have accounted for some this recent increase in profits, it only explains 15% of it.[106]

55. Drax Power argued that vertical integration could lead to inefficiencies in plant operation, where firms use more costly power sources to provide baseload generation, while more efficient stations are used only to meet peak demand.[107] Another concern was the extent to which the vertically integrated firms made information available to the market. Four of the 'Big 6' are part of larger European multinational firms. They therefore do not report detailed separate financial accounts for their UK operations. SSE also told us it did not break down its accounts between its wholesale and retail businesses.[108] Centrica is the only 'Big 6' company that does report separate accounts for its wholesale and retail businesses.[109] This kind of information is important for potential new entrants, both to the wholesale and retail markets, as it provides transparency about where profit-making opportunities lie.

56. While the 'Big 6' claim to be losing money in domestic supply, there is evidence that they are earning increased profits from their wholesale operations. We acknowledge that some of these profits may be earmarked for investment in new capacity rather than for distribution to shareholders, but we recommend that Ofgem conducts further work to understand where profits are being made within the energy supply chain. As part of this, we also recommend that Ofgem investigates whether it can require more detailed financial disclosure from the vertically integrated companies on the performance of their wholesale and retail operations, where they do not already provide this. Such information should not deter new investment, but would inform potential new entrants to the sector—both generators and suppliers.


57. The biggest concern raised over vertical integration was about the lack of liquidity in the wholesale electricity market. Ofgem, Energywatch, the European Commission, the independent generators, the large-scale consumers and the small suppliers all highlighted this issue.[110] Because the 'Big 6' are able to supply most of their domestic and SME customer base from their own generating capacity, there is much less need for them to trade in the open market. They need only do so to balance or hedge their positions.[111] As a result, the wholesale market has increasingly provided only a balancing function for participants, focused primarily on short-term trading. Total traded electricity is currently equivalent to 2-3 times physical delivery. Ofgem notes that this is low compared to other commodities, for example gas trades at around 11 times physical delivery.[112] It is also in stark contrast to German and Dutch electricity markets, where liquidity in recent years has been increasing.[113] There have been recent signs of greater liquidity, with screen-based traded volumes up 30% in 2007/08 to £41 billion.[114] Nevertheless, Ofgem's Chief Executive went so far as to say that: "The electricity market remains profoundly illiquid".[115]

58. The lack of liquidity in the wholesale market has various implications. Small electricity suppliers find it difficult to get forward contracts that provide the volume and shape to meet their customers' needs.[116] Welsh Power told us: "Quite simply we cannot buy what we need to buy to deliver the power for our customers when we need to".[117] BizzEnergy told us the 'Big 6' firms had proven very reluctant to provide suitable offers for selling their generation, the implicit rationale being: "We do not want to deal with you because all you are going to do is compete against our supply business".[118] Independent generators are also reluctant to sell their electricity in the smaller amounts required by the smaller suppliers. We heard evidence that the credit worthiness of those smaller suppliers was another obstacle for the generators, but we find this surprising given the very small sums currently involved, with all the independent suppliers put together accounting for only 1% of the market. Suppliers are also less able to hedge out any risks in the wholesale market.[119] Furthermore, for both independent generators and suppliers, the lack of liquidity creates greater volatility in the wholesale price. With limited trading, there is very little price transparency. This further discourages market participants, while those that do trade are less able to determine whether the price they are paying or receiving reflects the true market value. This risks dulling price signals to any potential new entrants both in generation and supply.[120]

59. The 'Big 6' companies did not agree that they were responsible for the lack of liquidity in the wholesale market.[121] Rather they pointed to the demise of Enron and TXU, and the restructuring of British Energy several years ago, as key factors in the decline in the number of market participants.[122] There was disagreement over the possible solutions to the issue. Both BizzEnergy and Welsh Power called for Ofgem to require the 'Big 6' generators to trade all their generation openly in the forward market.[123] The large industrial energy consumers said they would welcome some fixed proportion of the generators' output being forced into the open market.[124] However, British Energy noted that any such requirement on the independent generators would increase the collateral they would have to put up to trade in the market, and that this could act as a barrier to new entrants in generation.[125]

60. When we suggested to the 'Big 6' the proposal of selling a proportion of their electricity in the open market, they told us they already did this.[126] However, the fact that they trade and hedge an equivalent or greater amount of electricity than they actually produce is different to saying that their generating capacity is available to other parties in the forward market. It is worth noting that EDF Energy subsequently retracted its oral evidence that the company traded all its electricity through the wholesale market, stating instead that it traded "the equivalent of all [the] electricity we generate" for balancing and hedging purposes.[127] We note Centrica argued that the vertically integrated firms would still need to buy back most of their power from the market. The additional transaction costs of this would inevitably be passed back to the consumer.[128]

61. E.ON UK did acknowledge that "the trading market structure can be improved".[129] To this end, the "Market Design Project" was initiated in 2006 by a number of industry players to help stimulate greater forward market liquidity. However, it has made limited progress to date, and is not expected to make significant advances until at least 2009. Although this project, aimed at "capturing all, or a significant majority of trades" is welcome, Cornwall Energy Associates recently stated that "the bottom line is that an important industry project kicked off three years ago has stalled".[130]

62. We also discussed the impact that trading rules can have on the market, particularly in relation to the so-called "cash out" arrangements intended to keep the supply and demand of electricity to the market in balance at the time of delivery. We are inclined to agree that these well-intentioned rules could deter entry by smaller generators and suppliers as they currently work. Ofgem is at present examining this issue separately. Given its highly technical nature we make no recommendation on it in this Report, but we look forward to Ofgem's conclusions on this important issue.

63. The wholesale electricity market suffers from a severe lack of liquidity, which contributes to price volatility and poor price transparency. This, in turn, dulls market signals for potential investors in new capacity, outside of the 'Big 6'. It also reduces the ability of new energy retailers to compete in the market. As Ofgem has already identified the issue as a serious problem, and in the absence of tangible progress on the Market Design Project, its market probe should propose a solution. As a starting point, and in addition to any increase in transparency that can be achieved as a result of our earlier recommendation, the regulator should conduct a detailed analysis of the risks and benefits of requiring the 'Big 6' firms to trade a proportion of their electricity openly in the forward market. We acknowledge that the regulator must take account of the need to balance the effects that greater regulatory risk might have on the investment decisions of incumbent companies. In principle, however, creating a better functioning wholesale market should facilitate new entry both in supply and generation.

76   Ev 391, para 16 (Good Energy) Back

77 Back

78   Ev 445, para 39 (Ofgem) and Q 909 (European Commission)  Back

79   Ev 445, para 39 (Ofgem) Back

80   Qq 790 (Scottish Power) and 792 (Scottish and Southern Energy); Ev 213 (EDF Energy) Back

81   Q 795 (Scottish Power) Back

82   The Times, Difficulties elsewhere in power industry boost Drax's image, 1 July 2008 Back

83   Ev 195 (Centrica) Back

84   Ev 449, para 54 (Ofgem); See paragraph 20 for an explanation of the HHI Back

85   Ev 449, para 55 (Ofgem) Back

86   Ev 205, para 7 (Drax Power) Back

87   Qq 191 (Energywatch) and 401 (International Power); Ev 208, para 12 (Drax Power)  Back

88   Q 568 (Ofgem) Back

89   Ev 584 (Ofgem) Back

90   BERR, Table of potential new conventional electricity generating plants in Great Britain, November 2007 Back

91   National Grid, GB Seven Year Statement, May 2008 Back

92   Ev 584 (Ofgem) Back

93   Ev 453, para 71 (Ofgem) Back

94   Ev 453, para 69 (Ofgem) and Ev 186, para 2.15 (Centrica) Back

95   Ev 205, para 12 (Drax Power) Back

96   Q 393 (International Power); Ev 213 (EDF Energy) Back

97   Q 361 (British Energy); Ev 553 (Welsh Power) Back

98   Q 424 (Drax Power) Back

99   Q 61 (Minister for Energy) Back

100   Ev 450, para 57 (Ofgem) Back

101   Ev 450, para 56 (Ofgem), Ev 186, para 2.13 (Centrica), Ev 213 (EDF Energy) and Ev 562 (Wright and Rutledge)  Back

102   Q 785 (Scottish and Southern Energy) Back

103   Q 750 (Centrica); Ev 496, para 2 (Scottish Power) Back

104   Ev 426 (National Right to Fuel Campaign) and Ev 378 (Fuel Poverty Advisory Group) Back

105   Q 518 (Fuel Poverty Advisory Group) Back

106   Ev 380, para 11 (Fuel Poverty Advisory Group) Back

107   Q 385 (Drax Power) Back

108   Q 783 (Scottish and Southern Energy) Back

109   Ev 189, para 6.4 (Centrica) Back

110   Qq 329 (Major Energy Users' Council) and 907 (European Commission); Ev 274, para 36 (Energywatch), Ev 159, para 19 (BizzEnergy), Ev 452, para 67 (Ofgem), Ev 205, para 9 (Drax Power), Ev 243 (Energy Information Centre), Ev 234 (Electricity4Business), Ev 553 (Welsh Power), Ev 172 (British Energy) and Ev 248 (Energy Intensive Users' Group) Back

111   For example, EDF Energy told us: "We trade to source electricity for our larger industrial and commercial customers, to hedge our generating position, balance and 'shape' the mismatch between the electricity we generate and our customer demand, and to adjust for volume changes arising from events such as abnormal weather". Ev 233 (EDF Energy) Back

112   Ev 467, para 16 (Ofgem) Back

113   Ev 313, para 3.3.1 (Energywatch) and Ev 553 (Welsh Power) Back

114   Ev 373, para 2 (E.ON UK) Back

115   Q 549 (Ofgem); Ev 537 (University of Greenwich) Back

116   Ev 274, para 37 (Energywatch) and Ev 537 (University of Greenwich) Back

117   Q 703 (Welsh Power) Back

118   Q 713 (BizzEnergy) Back

119   Ev 159, para 20 (BizzEnergy) Back

120   Q 568 (Ofgem); Ev 510 (University of East Anglia) Back

121   Qq 779 (Scottish and Southern Energy and Centrica) and 833 (EDF Energy) Back

122   Q 845 (Npower); Ev 213 (EDF Energy) Back

123   Ev 160, para 35 (BizzEnergy) and Ev 553 (Welsh Power) Back

124   Qq 328 (Energy Intensive Users' Group), 329 (Major Energy Users' Council) and 333 (Chemical Industries Association/INEOS ChlorVinyls) Back

125   Q 362 (British Energy) Back

126   Qq 788 (Scottish and Southern Energy and Scottish Power), 844 (EDF Energy), 845 (Npower) and 852 (E.ON UK) Back

127   Ev 233 (EDF Energy) Back

128   Q 779 (Centrica) Back

129   Ev 374, para 6 (E.ON UK) Back

130   Ev 373 (E.ON UK) Back

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