THE FUTURE OF ELECTRIC COMPETITION
An analysis of competitive power markets finds that oligopolies are the end game for liberalized power markets.
The British wholesale power market is about to enter a new phase. Having enjoyed a long period of surplus capacity, the combination of the forced retirement of some nuclear plant and continued demand growth is likely to lead to a capacity shortage within the next three to four years, and it is by no means clear whether the market, as it currently operates, will be able to maintain secure supplies.
There is evidence, in other markets, that such disruptions can be avoided. However, the power industry is not famous for looking outside its immediate vicinity to provide guidance. In the late 1990s, the German industry ignored the "British experiment" when preparing for liberalization. As a consequence, the collapse in prices took that industry completely by surprise. Similarly, the British and U.S. industries, and their financiers, were surprised when power prices fell to marginal cost at the turn of the century, despite the German experience.
Looking to other commodity markets can help us predict the future behavior of competitive power markets. Where commodity markets are highly competitive, markets have been likely to give rise to volatile price cycles, with prices driven by marginal costs for long periods, punctuated by short periods of extreme prices. Observation of commodities also suggests that a market in long-term contracts is unlikely to develop in many competitive energy markets. As a consequence, domestic customers will be exposed to extreme price volatility, which is unlikely to be politically sustainable.
Is an oligopoly structure the appropriate end game for liberalized power markets?
The British Experience
The behavior of spot prices in the England and Wales wholesale power market is shown in Figure 1 (). The red line shows the spot power price; the green follows the marginal cost of generating power in a combined-cycle gas turbine (CCGT) based on spot gas purchases, and the black line shows the same for coal. The difference between the red and green lines is often referred to as the "spark spread." Similarly, that between the red and black lines is the "dark spread." The chart clearly demonstrates that the gross margin for generation effectively vanished between December 1999 and June 2000.
It is not necessary, for the purposes of this paper, to determine the cause of the collapse precisely. Certainly, the introduction of NETA in April 2001 increased the downward pressure on prices by bringing the demand response explicitly into the price-setting mechanism, a feature missing from the superseded "Pool" system. In addition, the control of generation was becoming increasingly dispersed. The cause of this fragmentation, and the effective demise of the generating sector, is shown in Figure 1. The chart shows two different periods of price behavior. When the industry was first liberalized, the fossil generating capacity was controlled by just two players, which were joined by a third in 1997. These generators set prices well in excess of that required to build and operate a new gas station. As a consequence, many new entrants did exactly that (, they built new gas capacity). Initially, the incumbent generators were willing to yield market share to maintain prices. However, this process went on so long that the incumbents realized they would no longer be able to control prices, and in 2000 they decided to increase their own output. Prices collapsed as a consequence.
The crucial point to observe is that wholesale power prices now appear to be set at a small premium, £5/MWhe, above the higher of the coal or gas marginal costs. This is exactly the behavior to be expected of a highly competitive commodity market. However, the problem facing the authorities, given these prices, is whether there is sufficient incentive for the private sector to maintain sufficient generating capacity. Or, more importantly, whether there is sufficient incentive for new entrants to build new capacity. Although this has been a rather "academic" question over the past decade, the surplus capacity is likely to run out in the next two to three years. Figure 2 shows the demand and plant forecast by the National Grid for 2004, including one demand forecast and three generation capacity forecasts, together with estimates of the associated "plant margin." The first capacity forecast (SYS) shows the forecast based on existing plant and all projects with "connection agreements" with National Grid; the second (consented) shows operational plant and projects that hold all the necessary permits; the last shows just plant in operation and projects under construction.
Given the current depressed generation margin, it is unlikely that developers will be keen to commit to construction in the absence of a rally in potential profitability. Thus the "under construction" curve gives the best estimate of the balance of supply and demand and suggests that, by 2007-2008, the plant margin will have fallen to less than 15 percent. It is not yet clear whether such a narrow margin will give rise to a substantial increase in prices. Such a situation has not previously been experienced in England and Wales, and it is not certain whether a price rise will give sufficient warning for developers to invest in new capacity.
Indeed, consideration of competitive power markets suggests that the price behavior could be expected to follow one of the two forms shown in Figure 3.
The green line shows the full cost of a "new entrant." An oligopoly would be expected to set prices at or just below this level. This would enable them to maintain profitability and market share because their cost of construction, and probably capital, would be lower than that of an independent new entrant.
The blue line shows the behaviour of a fragmented market, where prices stay just above marginal cost when there is surplus capacity but rise dramatically when demand exceeds supply. The factors determining the price in fragmented markets are:
The time between peaks (T2); probably related to the unit of new capacity and inversely related to the rate of demand growth; The magnitude of the peak (h); and The peak's duration (T3) related to the construction time of new plant.
For a new developer, a critical factor will be the time to the first peak occurring post commissioning. A study by Smith Barney (2002) investigated these factors for a new CCGT (costing £400/kW). The results, shown in Figure 4, suggest that the most crucial factor concerning a developer is that of commissioning (T1). If a station commissions just after a peak (such as happened to International Power's stations in Texas), the consequences for cash flow and the net present value (NPV) of the project are disastrous. The NPV of the cashflow is lower than the investment and value is destroyed, because in this idealized model, returns to capital can only be enjoyed when there is a shortage.
Given this outlook, it would take a very courageous developer to proceed with a new plant in England and Wales, were it to rely on revenues from the spot market. Avoidance of a shortage of capacity therefore may have to rely on a demand response to price, rather than capacity.
Other Commodity Markets
Other commodity markets that respond to price signals appear capable of bringing forward capacity in time to meet demand, so perhaps there is something the power sector can learn before it is overwhelmed. The key to the avoidance of shortage may be seen in Figure 5. This chart shows the returns on capital enjoyed by the commodity sector over a 10-year period to 2002, with the market share of the four largest companies in each market.
The chart demonstrates how the average returns enjoyed by companies in these markets are extremely sensitive to the market shares enjoyed by the leading players. The annual returns may well deviate from the averages shown above. Indeed, when there is a shortage of steel capacity, returns will rise dramatically. But they will fall as soon as additional capacity comes on line. Companies with a significant position in iron ore, on the other hand, are able to enjoy prices that allow a handsome return on capacity-even when there is surplus supply-because they can control it.
Indeed, Figure 6 shows the spot prices of the various commodities shown in Figure 5. The volatility of the iron ore prices is an order of magnitude lower than the others. This suggests that a high degree of control offers stable prices and attractive returns on investment.
A crucial issue is how much market share will provide "control." This is a difficult question and is likely to be very market specific. On the one hand, Figure 5 suggests there may be a smooth relationship between market share and return. Whether this is the same as "control" is an entirely different matter. For power markets, it is doubtful that a simple market share measure would work, such as the four forms' ratio, or a Herfendahl index. For the power sector, it is likely that control over the marginal plant will be a highly important factor-but this is a possible area for further research. Indeed, the remarkably fast transition from oligopoly to competitive market shown in Figure 1 suggests that, perhaps, electricity is, after all, rather special. It suggests a power market can exist in only one of two states; oligopolistic or fragmented.
The above analysis suggests that in a highly competitive fragmented power market, a developer would wait until spot prices are extremely high before committing investment in new generation capacity. Put simply, the risks of "missing the peak" are too great if the station relied on spot prices for revenues. But what about the possibility of obtaining a guaranteed price for power at a level that would cover both variable and fixed costs, including a return on capital? A forward market in electricity contracts of many years' duration has yet to emerge in England and Wales and is unlikely to do so, especially if there is competition at the domestic level. Put simply, a supplier would be foolhardy to enter into long-term contracts for power at prices in excess of marginal cost, since it would be undercut by competitors who continue to purchase on short-term contracts. Indeed, this is one of the reasons for TXU Europe's demise. While such forward markets develop for some other commodities, such as aluminum and steel, the products made from these minerals are sold on the basis of brand and intellectual property. The commodity cost is only a small fraction of the final product price. Purchasers of the commodity may feel more confident about buying for the long term.
The wholesale electricity price, on the other hand, represents around 40 percent of the final price to domestic customers. A better analogy is the oil sector, as the market for the final product is competitive and the product is a large proportion of the final price. Despite the maturity of the oil market, there is little liquidity in forward contracts of more than 6 months' duration. Thus it would be unwise to depend on the emergence of a medium- to long-term forward market in power contracts to protect customers from spikes in the wholesale power price.
On the other hand, if the domestic supply market were not competitive, suppliers may be sufficiently confident of their ability to pass on costs to customers that they might offer long-term contracts to generators at prices well in excess of marginal cost. This would allow generators to recover capital charges over many years, and not force them to recoup these costs over the one- or two-year period available to them in the fragmented market as prices spike. However, there then might be a requirement to ensure that these vertically integrated monopolies did not exploit their position by enjoying excessive margins in the supply business.
Alternatively, if there were fewer generators, they could hold prices above marginal cost and so enable them to carry surplus capacity to meet demand growth and amortize their investments over a longer period. Of course, under the circumstances of such "managed competition," it would be essential to ensure that access to the networks is open to all. This would ensure that the incumbent generators respond to reductions in new entry costs caused by movements in fuel prices and advances in technology. If the incumbent generators fail to respond in this way, it will suffer a loss of market share and run the risk of a return to a fragmented market with the associated marginal cost pricing. Thus, the threat of competition would protect customers under this "managed competition."
The conclusion of this analysis is that unless there is some oligopoly control, either in the supply to final customers or in generation, prices in a fragmented generation market are likely to be driven to extremely high levels, as demand starts to exceed supply. Although this might be acceptable from an economic point of view, as it would encourage a demand response, it is unlikely to be politically acceptable, let alone sustainable. Unless the supply businesses have sufficient confidence in their supply base, such that they would be willing to sign long-term contacts, or an oligopoly exists in generation, it is difficult to believe that politicians will not intervene when prices rise dramatically. This uncertainty would serve to increase the cost of capital in generation.
Consolidation and control in generation may be preferable to a high degree of competition because it would remove the risk of price excursions and the threat of intervention by government. It would lead to a market where prices move in line with the long-run costs of new entrant production, and where incumbents would be confident to invest in new capacity. In this way, "managed competition" would help develop a sustainable electricity industry.
[Editor's Note: This paper is based on a speech made at the 2004 International Society for New Institutional Economics (ISNIE) Conference in Tucson, Ariz.]
- Although NETA started after the collapse, the regulator and British government claimed that the market anticipated the effect of the introduction of the new rules.
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