Select Committee on Environmental Audit Minutes of Evidence

Memorandum submitted by Climate Change Capital

INTRODUCTION

  1.  Climate Change Capital (CCC) is a specialist merchant bank focused on energy and environmental markets driven or impacted by government policy. CCC has expertise in finance, climate policy, power pricing, renewables and emissions trading markets.

  2.  We are aware that the Committee will be receiving many submissions concerning the costs of the different electricity generating technologies. We will therefore confine our contribution to section 3 of the Committee's invitation.

The barriers to new investment

  3.  Financial institutions will always be willing to invest in projects where the returns appear to be commensurate with the risks. The problem facing new nuclear build in the United Kingdom is that the risks appear to be higher than elsewhere. Some of these risks are nuclear in nature, such as:

i.  the large up-front costs required to secure the appropriate authorisations;

ii.  the uncertainties associated with decommissioning and the treatment of spent fuel;

  whilst others are associated with any large project:

iii.  will the station be built to time and to cost; and

iv.  can the project generate sufficient revenues to provide adequate returns to capital?

  4.  The first two barriers will, in CCC's view, require direct intervention by Government. The costs of obtaining the necessary approvals could be many tens of millions of pounds and would be forfeited if the authorisations were not forthcoming. It is doubtful that investors would be willing to accept such a risk. Secondly, the uncertainties associated with the back-end costs could be so large that investors would not be able to secure protection from the capital markets. As a consequence, it would be necessary for the Government to underwrite these costs, as in other countries.

  5.  No doubt the Committee will be receiving copious amounts of evidence about the cost of building and operating a nuclear power station in the UK. However, we question whether, even if we were confident that a nuclear station could be built to time and cost, anyone would want to finance one in the UK? This is the question we would like to address.

Financing New Generating Capacity

  6.  Until 1990, all electric utility companies served monopolistic markets. Under these circumstances, utilities could always be confident of enjoying a return on their investment, since their tariffs were usually set so as to allow them to enjoy a reasonable return on capital. Of course, sometimes the return was influenced by political or industrial issues, but, in the main, utilities could always be confident that their customers could not seek alternative means of electricity supply.

  7.  The choice of generating technology was relatively straightforward; the utility's planning department would consider the operating (fuel) and capital cost of the different options and would choose that with the lowest cost; as depicted in Figure 1 below. Of course, utilities can, and often did, make mistakes by incorrectly forecasting demand, the various fuel prices, and the cost of building and operating the various types of plant. However, in a regulated monopoly, it is customers, in the main, who bear the cost of such mistakes, in the form of higher tariffs than necessary or, it must be remembered, lower tariffs if the utility chooses well. Moreover, in setting the tariffs, the utility can assume that the plant can operate over its "engineering" life, and so amortise the capital cost over an extended period.

Figure 1

PLANT CHOICE IN MONOPOLY CONDITIONS

  8.  Under these circumstances, it is relatively straightforward to determine the generating costs of each technology, for a given suite of assumptions concerning relative costs. Table 1 below sets out a typical assessment of the different average generating costs of various technologies, where capital costs have been amortised over the physical life of the stations. It was carried out by for the Royal Academy of Engineering in 2004, when gas prices were far lower. The table suggests that, with current fuel prices, nuclear could be the low cost option, were the power market monopolistic.

AVERAGE GENERATING COSTS

	Average lifetime cost (p/kWh)
Gas-fired CCGT	2.2
Nuclear fission	2.3
Coal-fired pulverised fuel	2.5
Coal-fired IGCC	3.2
Source: Royal Academy of Engineering

COMPETITIVE MARKETS

  9.  In competitive markets, capital investment decisions are far more complicated. In such markets, there are no "tariffs" as such. The revenues any particular generating plant receives will be determined by the market price and this, in turn, will be influenced by the balance of demand and capacity, marginal generating costs and the degree of competition in the market. Such factors are impossible to forecast precisely. Therefore, in making investment decisions, power station developers will consider the capital and operating costs of different generation technologies and explore the returns they each may deliver under a number of different assumptions concerning fuel prices, demand patterns and capital costs. Only after carrying out an exhaustive exploration of the different net present values that a project could deliver under a myriad of different assumptions should a developer decide whether or not to build a generating station of a particular technology.

Figure 2

PLANT CHOICE IN COMPETITIVE MARKETS

  10.  In simple terms, this means that the owners of a power station must be sure that the revenues they receive from selling their power, will be able to cover all their fuel costs, the fixed costs (salaries, other bought in costs, rent and rates), interest charges on any debt they may have raised to build the power station and then provide a return to shareholders. At the very least, owners must be confident that, after the fuel and fixed costs, they will meet their interest charges. If they fail, on account of power prices being far lower than anticipated, the power station will become bankrupt. Thus, discussions about "average" prices are not really of much help to investors. Investors must be sure that the company will always be profitable, not that just that it will be profitable "on average".

  11. The analysis of future revenues is currently particularly difficult in the UK, owing to the market's current structure. The wholesale power market in England & Wales underwent a radical restructuring in 1990, creating the opportunity for generating companies to compete with each other in the provision of electricity. For almost the first decade, the structure of the industry caused the degree of competition to be muted. Initially two power companies, owning coal and oil generating assets, dominated the market and, as a result, were able to set prices where they wished. Generation gross margins, as measured by the difference between power prices and fuel costs, were wide, as shown in Figure 3. As a consequence, there were two developments:

—  The regulator forced the two companies to sell 10GW of their generating capacity; and

—  A flood of gas fired generating capacity was built by new entrants, encouraged by the high power prices and the low price of gas.

Figure 3

BRITISH WHOLESALE POWER PRICES AND FUEL COSTS

  12.  Initially, the incumbent fossil generators, joined by TXU and Mission energy, American utilities that bought the 10 GW, were able to maintain high prices by yielding market share. They continued to maintain high margins even after a further 6GW was sold in 2000. However, by 2000, the market had fragmented to such an extent that margins collapsed, and have remained low ever since[24] (see Figure 3).

  13.  There is some evidence that this collapse was also prompted or exacerbated by the change in the trading rules of the British market under NETA (April, 2001). This precise cause is, however, irrelevant. The fact is that the price behaviour exhibited in Figure 3 is just that anticipated of a highly competitive commodity market, which is hardly surprising, given that power is the most extreme commodity in that it cannot be differentiated by source.

  14.  It is therefore reasonable to assume that prices will remain close to marginal cost until the demand for power approaches the available generating capacity, at which time prices will soar. Such price behaviour is depicted in Figure 4. The time before the first spike, T1, will be determined by the rate of demand growth and the balance of supply and demand, and that between spikes T2, by the rate of demand growth and the unit size of new generation. The duration of each spike, T3, will be influenced by the construction time for new capacity and the height, h, of each spike by, well—it is difficult to judge—given that there has been no experience of a complete capital cycle in the liberalised power sector in Europe. The chart also indicates the level of marginal costs—and that of a "new entrant", which assumes that the capital cost and returns are amortised over a number of cycles.

Figure 4

PRICE BEHAVIOUR IN HIGHLY COMPETITIVE MARKETS

  15.  According to economic theory, such high peak prices should encourage developers to build new stations, or customers to reduce their load. However, there are good reasons to believe that such a mechanism may not operate smoothly:

—  Developers will recognise that, in such a visible market, they will only be able to enjoy returns during these "spikes. Thus the timing of the commissioning of a new station will have a large impact on the financial performance of a new station. Given such uncertainties, investors will require large discount rates, effectively driving prices higher.

—  The timing of such a peak in the UK would not, necessarily, coincide with any on the continent. Therefore, it may become difficult for the Government to tolerate large rises in the price of power when they are not mirrored by similar increases in those of British industry's continental competitors. This might cause the Government to intervene, such as by applying a price cap. Even if the Government did not take such action, potential developers would believe it would represent a risk, thereby increasing the price they would require to see before they committed to construction.

  16.  Economists would also argue that a market in long term contracts will develop, effectively smoothing the price peaks, making them more acceptable. However, such a market has not developed, despite liberalised markets having operated since 1990 and NETA having operated for three years, so it is not just a question of maturity. The reason why a liquid market in long contracts at prices that would encourage new entry has not emerged is that no-one would want to commit to buy power for extended periods at prices far higher than their competitors, even though, over the longer term, it may prove cheaper. There is an analogy with the oil market. This market is hardly immature, but no such long term market has developed. This is a consequence of the final market for petroleum products being so highly competitive. The same is true for the market for industrial power in the UK, though to a lesser extent for supplies to the domestic sector. Therefore, suppliers of energy in the UK are sensibly not signing such long term contracts. Indeed, such contracts were the reason for the demise of TXU Europe.

  17.  Of course, over time, suppliers' reluctance to sign longer term, fully priced, contracts may weaken, especially in the face of increasing demand and as they gain confidence that various segments of their customer base are not price sensitive. However, at present, it is highly unlikely that suppliers will be willing to commit to purchase power for long periods at prices that reflect new entry costs. Thus a developer building a station in a highly competitive market will need to be confident that the station will commission just before a "peak", if any returns to capital are to be made. Developers naturally choose to build plant with short construction periods—and so favour gas plant over clean coal and nuclear. However, we are seeing that, in this market, even gas could be problematic since power station developers cannot be sure that they will be able to enjoy returns to capital.

  18.  The obstacles to the construction of new capacity could be removed were the suppliers willing to enter into longer term contracts, but such willingness is only likely to emerge if the markets are less competitive. The alternative, is to place additional obligations on suppliers to purchase capacity.

CONCLUSION

  19.  It therefore appears that some changes may be required to the wholesale power market in Britain before developers commit to the construction of any new capacity; be it nuclear, clean coal and perhaps even gas. Of course, the construction of renewable forms of generation is likely to proceed, on account of the support provided by the Renewables Obligation, but that will not satisfy the anticipated need for base-load generation.

29 September 2005

---

---

24   The recent rise since January 05 is due to the European Emissions Trading scheme, whereby the cost of greenhouse gas emission allowances should be added to the fuel costs. The gross margins net of these carbon costs are still under £5/MWhe. Back

---

Prepared 16 April 2006