3.3 Fuel Diversity
MODEL RESULTS
This model uses the fuel and carbon prices discussed above. It also assumes that, with the exception of the price of carbon dioxide, past price behaviour over the 35 years 1968 to 2003 is a good guide to future price volatility. In Figure 3.2, the x-axis represents the standard deviation, which can be thought of as a measurement of risk. The larger is the standard deviation, the bigger is the risk. The y-axis denotes the time-weighted average (TWA) of the long-run marginal costs of generation by the various technologies (€ a MWh).35 Each line symbolises a different estimated price for carbon
permits and measures the level of risk for a given TWA price. Figure 3.2: Price Risk Trade Off for Different Portfolios and Costs of Carbon
25 30 35 40 45 50 55 60 65 70 75 1 3 5 7 9 Standard Deviation
Time Weighted Average Price
40 Carbon 30 Carbon 20 Carbon 10 Carbon No Carbon
It can be seen from the diagram that the decision becomes a matter of a trade-off between risk and price. A low risk of a price shock would require a high average cost, due to insufficient fuel diversity, with concentration on technologies which are very capital intensive (relative to input costs), e.g. wind. A low cost for generation means that the risk of price shocks occurring increases. Also, it is important to note that as the price of carbon increases, the slope of the trade-off line decreases. This is because carbon at €40 adds more stability to the price of each fuel than carbon at €10. If the model allowed for the uncertainty regarding the price of carbon, this issue would not arise.
35 The Time-weighted average (TWA) is the marginal cost of production averaged
over every hour in the year. The system marginal cost varies significantly over the course of the day, as well as on a seasonal basis.
Table 3.3: Portfolio Weights for Minimum Risk (€68 a MWh) Carbon price €0 €10 €20 €30 €40 Coal 0.0032 0.0085 0.0137 0.0126 0 Oil 0.0145 0.0104 0.0051 0 0 Gas–CCGT 0.0066 0.0164 0.0318 0.0488 0.0723 Gas–OCGT 0 0 0 0 0 Peat 0.0148 0.0131 0.0047 0 0 Wind +Back-up 0.9609 0.9517 0.9447 0.9386 0.9277
The graph indicates that the lowest level of risk is attached to an average price of €68 a MWh in all cases. Table 3.3 shows the unconstrained optimum weights for each of the technologies for the point where the associated level of risk is at its lowest. In each case wind would have a very high weight because most of the cost is capital. This cost is known at the time of installation so that there is little uncertainty about the future cost of electricity from a wind generator once it is installed. Obviously, such high penetrations would not be feasible in reality but it does show how a desire to reduce risk will involve greater use of wind power than would be the case if cost-minimisation were the only consideration.
As shown in Figure 3.2, low risk translates into a very high price, €68 a MWh. This is arrived at by including an extremely high percentage of wind in the mix of technologies used for electricity generation. This is unrealistic but it demonstrates the attractiveness of fixed cost technologies in the discussion of security of supply. The output table also highlights the problem of assuming a fixed price for carbon. As the price of carbon goes up, so does the advantage of gas-fired CCGTs. This arises because gas and oil are correlated but, since oil is a more carbon intensive fuel, the price of oil-fired generation increases more rapidly than that of gas. Therefore the pull towards gas-fired CCGTs intensifies.
Table 3.4: Cost, Risk and Weights
Carbon P. €0 €10 €20 €30 €40 Min. Cost €37 €43 €49 €55 €60 Std. Dev 8.7731 9.2904 9.3808 8.9069 7.7328 Coal 0.4606 0.5189 0.4971 0.3252 0.011 Oil 0 0 0 0 0 Gas-CCGT 0.106 0.224 0.3672 0.4892 0.5934 Gas-OCGT 0 0 0 0 0 Peat 0.3091 0.1634 0 0 0 Wind + Back-up 0.1243 0.0937 0.1357 0.1856 0.3956
If the lowest possible cost in each case were taken, then the corresponding risk would be at its highest and the unconstrained weights would appear as shown in Table 3.4. These results indicate that if the risk and the price of carbon were not a concern coal and peat would have a high weighting in an optimal portfolio of electricity generation. However, peat becomes uncompetitive as the price of carbon dioxide goes above €10 a tonne. Coal begins to become uncompetitive over €30 a tonne of carbon dioxide. It is only
at €40 a tonne that a large share of wind would begin to become attractive.36
The results from this model suggest that even if coal were not the lowest price fuel, which occurs when the price of carbon goes above €20 per tonne, the inclusion of coal in the generation mix would reduce price uncertainty at a relatively small cost up to a carbon cost of €30. The inclusion of both wind and peat also would reduce uncertainty but the cost would be high for wind below a carbon price of €40 and high for peat at a carbon cost of €10 per tonne. However, there is considerable uncertainty about what will be the future price of carbon dioxide emissions over the likely lifetime of new electricity generating plant. This uncertainty would argue for keeping coal-fired generation at its current level and also including some peat and wind generation in the mix of technologies. Such a portfolio would not represent a minimum cost choice of plant, but it would reduce the risks to consumers from fuel price shocks at a relatively limited cost.
Market forces could theoretically continue to deliver a diversified portfolio of electricity generation plant in the future, as they have done in the past. However, given the drive to reduce greenhouse gas emissions it seems probable that market forces, left to their own, would result in a very big increase in the dependence on gas for electricity generation. A second instrument to counter this dependence and the attendant risk of price shocks could be needed by the regulatory authorities. Such an instrument should aim to provide market incentives to encourage a more diversified portfolio.
While such mechanisms may be needed in the future to ensure a sufficiently diversified portfolio of fuels used in electricity generation, the analysis in this paper suggests that it should not be necessary in the immediate future. It seems likely that the announced investment in Moneypoint needed to keep it open will be recovered over the remaining life time of the plant up to a carbon dioxide price of at least €20 a tonne, a level at which Moneypoint would still provide base-load. Even at a price of €30 a tonne it would probably still run as mid-load plant and make a sufficient margin over its costs to justify the investment. It is only at a cost of carbon dioxide of €40 a tonne that it would no longer be economic. As a result, such a large coal-burning station plays an important role as a hedge against price shocks, while simultaneously providing additional insulation against a quantity shock (physical interruption).
While it is for policymakers to use this model to choose the portfolio of generating technologies having the desired mix of price and risk these results would suggest that a diverse portfolio would be better than one which concentrated on a single technology, such as gas. Coal (Moneypoint) is likely to have a value for another decade through reducing risk, even as its price rises through higher costs of
36 The costing of wind assumes a constant cost over all levels of wind penetration.
In practise for low penetration of wind where backup supply is not required the costs would be much lower. At exceptionally high levels of penetration the costs would also be likely to be much higher.
carbon dioxide. The optimal deployment of wind will be somewhat greater than would be suggested by its headline cost; more wind on the system reduces risk at a limited cost. Oil based technologies look to have limited prospects. Finally, peat plant should either be closed or, as suggested elsewhere in this report, gradually converted to burn biomass.
I
f the market price for gas and electricity fully reflected the risks involved in economy-wide dependence there would be no need for the regulatory authorities (The Commission on Energy Regulation (CER), The Department of Communications, Marine and Natural Resources and Eirgrid) to take specific policy measures to deal with the issue of security of supply. However, it is clear that market prices do not fully reflect the risks from extreme dependence on gas and that, left to itself, the market could deliver an unsatisfactory result from the point of view of national welfare.3.5
Policy
Instruments and
Options for Fuel
Diversity
Fuel diversity, and the supply security enhancement which it is supposed to bring, confers benefit to which consumers would attach value if the market mechanisms existed to allow them to make such a choice. However, diversity may come at some additional cost. The task of an economically efficient policy is to deliver security up to the point where end-users with full information, are willing to cover the costs, and not beyond.
An unregulated energy market,37 left to its own devices, could be
expected to only partly respond to the public’s demand for supply security. It may not be able to respond adequately for a range of reasons and the public’s actual demand (willingness to pay) for supply security may not be efficiently revealed in a real-world market structure due to the public good quality of security of supply. It is important to realise that markets have partially responded to real demands for ‘qualitative’ features such as supply security or fuel diversity in the past e.g. companies buy standby generators and hedge fuel price risk. The issue is whether the ‘socially optimal’ amount of supply security as well as the optimal private level of fuel diversity will emerge without explicit intervention in this regard. Further, electricity markets are typically subject to market-dominant players and (hence) intrusive regulation associated with that, as well as structural features that inhibit efficient pricing.
There is undoubtedly a security of supply case for intervention into the capacity planning side of the energy market to correct an obvious market failure. This issue is dealt with in Chapter 5. The uncertainty about future market prices and the future price of emissions will militate against new investment, especially investment aimed at replacing inefficient plant. It could be some considerable time before new plant would come on-stream to replace existing plant. With an uncertain market, failure to invest in time would see the consumer rather than the producer carrying the cost of the
inefficient production. Business and household (private) sectors will respond to the price signals in the marketplace. In a less than perfect market, their responses may not be socially optimal, and the responses of supply-side players may be constrained. However, state action to provide supply security over and above market provision needs to be justified in terms of cost; the oil crises of the 1970s resulted in expensive policy actions in many countries, including Ireland, aimed at reducing exposure to oil price shocks and supply disruptions, which in the event, did not materialise.
In the longer run, as the electricity market faces greater liberalisation, it is likely that some incentives will be needed to ensure that there is sufficient diversity in fuel (including renewables) used in electricity generation. If such incentives were felt to be necessary these could take the form of a special levy on gas used in electricity generation (or any other fuel that would be over represented) with the resulting revenue being used to provide a subsidy per MWh for all electricity consumers. If the levy were set at an appropriate level this would incentivise new investors to use the next cheapest technology to gas for the next generation of electricity generation. This would leave it to the market to choose the most efficient means of finding a diversified portfolio of generation.
The alternative of using regulation to impose a solution could give rise to substantial windfall gains for existing players, at the cost of a higher overall price of electricity for consumers. For example, if the regulator were to require that the next electricity generator to be built should use oil (which is more expensive than gas), then the price of electricity (the system marginal cost) would rise to allow that generator to recoup all its costs. The result of such a rise would be that all existing generators that were allowed to use lower cost gas would make bigger profits.
In the case of the levy, if chosen at an appropriate rate, the profits of the gas and oil generators would be similar and the revenue from the levy could be used to ensure that the rise in the consumer price of electricity was held to a minimum. However, in the example chosen, no mechanism could avoid the additional costs for consumers arising from the use of oil rather than gas in the new generating station, but at least the additional cost would be confined to the electricity generated in that station.
PHYSICAL SECURITY