Om-PART MARKETS FOR ELECTRIC POWER: ENSURING THE BENEFITS

OF COMPETITION

Frank C. Graves, E. Grant Read, Philip Q Hanser, and Robert L. Earle1

In order to ensure adequacy of generation supply, the utility industry has traditionally been required to carry two to three years of planning reserves, e.g., 20 percent over projected peak demand. Closely related, they have often used twepart (capacitylenergy) pricing to buy and sell generation (real power) output. This paper argues that continued use of this approach, especially continuing to require planning reserves under power pool or NERC or other mandate, wit1 undermhe the benefits of power industry restructuring. In contrast, a market with no administered capacity requirement, but a one-part commodity price reflecting both marginal operating costs and capaaiy scarcrty, will have many benefits. In particular, it will induce efficient capacity planning-which has been the real problem in the past (not inefficient dispatch) and which is where the real opportunities for future efficiency gains lie. It will also encourage demand-side participation in peaking "reserves", and forward contracting for risk protection and expansion financing, both of which atso reduce generation market power. Independent system operator (ISO) planners and regulatory agencies should concentrate more attention on encouraging demand-side participation and forward contracting, and less on the sufficiency of

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physical reserves or on customer protection against possible high market prices.

Introduction.

Traditionally, the utility industry has administered the capacity market by requiring utilities to carry 2-3 years of planning reserves, e.g., 20 percent over projected peak demand, as a condition of participation in power pools or regional reliability coordination councils. Closely related, hey have often used two-part (capacitylenergy) pricing to buy and sell generation (real power) output.

This paper argues that continued use of this approach, especially continuing to require planning reserves under power pool, North American Electric Reliability Council (NERC). or other mandate, will undermine the benefits of power industry restructuring. In cantrast, a market with no administered capacity requirement but a one-part commodity price refledng both marginal operating costs and capacity scarcity will have many benefits. In particular, it will induce efficient capacity planninewhich has been the real problem in the past (not inefficient dispatch) and is where the real opportunities for future efficiency gains lie. It will also encourage demand-side partidpation in peaking 'reserves", and fonrrard contracting for risk protection and expansion financing, both of which also reduce generation market power.

This conclusion Funs counter to much past utility economics literature that advocated two-part pricing, and to well-intentioned concerns about preserving generation reliability. but the assumptions of that literature and of the coordinated generation planning tradition are no longer appropriate to the future power markets (at least in the United States).

Notwithstanding its advantages, a commodity power market with one-part pricing has its own difficult implementation issues, including externality concerns and antitrust questions of how to tell when prices reflect more than just capacity scarcity and have become monopolistic rents. The latter determination will be especially difficult if, as many industry analysts expect, unregulated power markets become quite

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volatile and peak-intensive, recovering capacity costs in a few percent of hours per year at prices 5-50 times as large as typical variable costs. Concerns about exposf anticompetitive behavior in such periods may be alleviated if ex ante there are active, competitive forward markets that customers can access to insure themselves against price spikes. Hence, a key question is under what circumstances such forward markets will evolve. It is not clear that effective forward markets mn exist i f there is slgniflcant market power in the spotlphysical market. Evidence from other commodity markets on this question is mixed, but it is dear that high levels of forward contracting reduce incumbents' incentives to force spof prices up. Game-theoretical modeling also suggests that forward markets can create a prisoners dilemma situation that drives oligopolistic producers towards efficient competition.

Besides diluting anticompetitive behavior, forward contracting is essential as a means for investors to wpe with the risks of building and maintaining new peaking capaaty that may have only rare, but significantly profitable use. Another aid for inadequate spat market competition and the risks of oblainlng peak reserves is demand-side participation in pools. This could help cure the problem associated with must-run generation inside of many urban load pockets, allowing cornpetifion where bid-price restrictions would otherwise be required. Demand-side participation is more likely to be induced with one-part

than two-part pricing, and no planning reserves obligation. One thing which will certainly destroy the forward conkact market

is the expectation that regulators may force generators to supply consumers at "reasonable prikes," even if they are not contracted. In that case, why should customers contract? If owning a backup plant means that a generator is forced to sell at the regulator's price, helshe will only build what the regulator requires.. .hence undermining the market. 'Standard offer" service obligations, designed to protect customers from the risk that market prices will rise after stranded cost allowances have been set, are an example of such a policy that may interfere with competition.

There is good news for twepart pricing, despite the above argument that organizing the industry in traditional, two-part markets with administered capacity is fast becoming undesirable. Once efficient one-part spot markets have evolved, any buyers or sellers preferring the certainty of pricing they enjoyed under the two-part regulatory

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tradition can recreate it with call options written against the spot market. These are superior to administered capacity provisions for which quantity and cost recovery are determined by regulatory fiat, because each customer can design them to suit his or her risk preferences, e.g., by buying options that are more or less out of the money to cover part or all of expected requirements.

This chapter first examines the economics literature on twepart pricing and argues that, at [east in the United States, because of structural changes, much of it no longer applies to generation. Second, the undesirable consequences of capacity market management are examined and contrasted to the likely outcome from one-part pricing. Both empirical analysis and theory indicate that the benefits of restructuring are likely to come not from more efficient dispatch (allocational efficiency), but better deployment of capital and innovations in demand management (dynamic efficiency). Third, the volatility of prices that may result from ompart pricing is discussed. There, it is suggested that the high spikes of these prices provide the signals and incentives for the construction of new capacity or adjustment on the demand side, although forward markets should ameliorate price volatility's impacts. Fourth, some lessons are drawn from results in New Zealand. There, despite some initial problems, one- part pricing has not resulted in the disasters predicted for it beforehand. Fifth, it is briefly described how options can replicate the effects of a capacity purchase wlthout necessarily distorting the energy market. Finally, the chapter concludes with some policy recommendations for power pool planners and regulatory agencies.

Economic Heritage of Two-part Market and Pricing.

Some economic literature has shown that, under certain areurnstances, two-part pricing of electric power can be the second-best ideal (typified by Boiteux2). In brief, these analyses typically conclude that energy should be priced at short-run marginal cost, while capacrty-related fixed costs should be recovered through a demand charge that achieves full recovery of the remaining costs (revenue requirement).

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Today, however, those ciumstances favoring two-part pricing are not likely to apply to some, perhaps most, prospective deregulated power markets. For instanm, this literature tends to assume that there are significant economies of scale in generation, so that incremental oonsumption should not be discouraged by one-part prices. But generation technology has now evolved to where there are far fewer consequential economies of scale; 400 MW gas combined cycle gas turbines (CCs) are now cheaper to build (per kW) than traditionat baseload technologies like coal and nuclear generation. This literature is also strongly tied to the revenue requirementlregulated monopolist tradition, seeking to prevent monopolistic prices while achieving cost-of- service average prices that minimally distort power use. But of course we are hoping to deregulate generation and let the market determine prices.

There may also be implicit assumptions that are equally important and increasingly inappropriate for a competitive generation market. Even when these are not present in economic derivations, they are common in engineering studies designed to formulate the industry's capacity management policies. For instance, they generally assume:

Knownlfixed capacity requirements, determined by loss of load probability or reserve margin targets--but empirical estimates of the marginal value of lost load (VOLL) designed to equate the social value of avoidable curtailments to the marginal cost of additional generation capacity are extremely imprecise, and dearly indicate that these values are highly situation-specific (e-g., depending on lead time for notification, length of outage, efc.). Such uncertainty and diversity makes this an ideal problem for markets, rather than regu tators, to solve. Static demand curves, sometimes with zero elastictty-yet real-time pricing (RTP) experiments in New York, Georgia, and elsewhere show strong price responses. Moreover, few customers have ever been given a strong price signal to which they could respond; competitive generation creates the opportunity to tap previously unexplored price elasticity, via spot prices that are likely to be volatile and peak-intensive. Uniform annual reliabilityfexpected availability of existing generation-unlikely to apply to generators facing a volatile spot market. Traditional modeling of availability (e-g., in LOLP studies)

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treats outage as a Poisson process, randomly occurring throughout the year. Similarly, optimal pricing models often treat the supply curve as fixed with respect to outages, regardless of price. To the contrary, in a competitive generation market with onepart commodity prices, generators' incentives to be online during peak hours should be much higher, even if average availability does not improve.

Thus administering twepart markets requires a degree of confidence in our information about supply and demand curves that we probably should not have.

Another concern about continued reliance on administered capacity markets is that they may become unworkable and even have anti- mmpetitive impacts. Unworkability arises because in the past, planning reserve obligations have been imposed on utilities with long-lived obligations to serve and protected franchise monopolies. In this context, it was meaningful to speak of a long-term requirement, as well as reasonable and feasible to achieve cost recwery of the carrying costs of those planning reserves with average cost demand charges. This approach could be sustained under whojesale access if the reserve obligation were made a contractual obligation of the distcws. But it is untenable under retail access. Retail customers will want the opportunity to be served with self-selected reliability, not with paol- specified reliability. Of course, it is true that we cannot (easily) direct power towards certain customers and away from others. In this regard, power flawing in accordance with Kirchoffs Laws displays externalities that could result in free-ridership. But future smart appliances and meters that can be curtailed in response to price thresholds may eliminate much of this pr~blern.~ Moreover, this problem is not nearly as unique to electricity capacity as those concerned about externalities have suggested. For instance, any time someone builds a house it slightly improves (reduces) the price of housing for all other buyers, yet this is not deemed to discourage home building.

Similar issues arise because suppliers will want the opportunity to rely on spot power procurement alone to cover some of their customers' needs. That is, they will want the right to offer service without holding physical capacity, provided they are willing to financially indemnify their customers for nondelivery. (As explained further below, this becomes

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the only workable definition of reliability in a deregulated power market.) This is the way all other commdity markets enforce perfomance, e.g., in their futures markets. Or, suppliers (e.g., cogenerators) may only want to offer serilce in off-peak periods when the need for planning reserves is effectively zero. In principle, this could be accommodated: the planning reserve obligation an load-serving entities (LSEs) could be converted to a very complicated function. conditional on the precise time, location, and duration of service. In practice, this unbundling would itself become a source of controversy and litigation.

The antitrust implications of enforced capacity obligations arise if pools oblige LSEs to cany planning reserves as a condition of entry, and as a result fewer suppliers are able or willing to do so. This will reduce competition. Insistence by pool governing bodies on planning reserves could be challenged as a conspiracy in restraint of trade. if h e incumbents are perceived as having mated entry baniers that only they can readily surmount with their existing generation capacity reserves.

Finaljy, the concept of 'capacity" itself is not clearly defined, with the imprecisionlgaps becoming increasingly important in the restructured power markets. In the traditional pricing models (and even some pool reserve requirements), all MWs are treated as equivalent. In fact, features that can vary enormously across same-sized units include:

Minimum run constraints, Black start capability, Ramping speed and range, Availability(forcedoutage), and Emergency capability

Thus it is not just the number of MWs but performance capabilities that determine value. In principle, we could imagine performing an analysis of the marginal contribution to pool reliability of each LSE's reserves, but devehpment of art effective ancillary services market is a beffer way to solve this problem, with only financial indemnifimtion for non- delivery of real power being the relevant measure of "reliability" in the one-part commodity market4 This, of course, will not guarantee that power is always delivered; occasionally, indemnifimtion for nondelivery will occur. However, the required amount of compensation will be marketdriven, hence efficient, and thus will send the right sized signal for avoiding the problem in the future.

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Undesirable C~nsequences of Capacity Market Management.

The danger in sticking with the conventional capacityienergy distinction is that it may encourage preservation of two markets that are not necessarily in equilibrium with each other, or that are in equilibrium but at undesirable levels. Pool rules that require traditional loss of load probability (L0LP)lreserve margin planning reserves for would-be marketers or LSEs will lead to:

Administrative, not economic capacity targets. Artificial size of the supply pool with resulting distorted (too low) energy prices. Continued (over) reliance on supply-side approaches to balancing the market, rather than letting demand vary in response to a one- part commodity price that reflects marginal operating costs and capacity scarcity. A bias against adoption of supply-side technologies which do not provide the *normalw mix of generation and reserve mpacity. Figures 1 and 2 illustrate the difficulty. In Figure I, the equilibrium

prices and quantities in a on-prim market are depicted. In Figure 2, the equilibrium conditions in the Weprice market are shown.5 If adequacy targets are administratively set, say by the state, then there may be a chance it will be set too high with the result that the single price energy market will need to be split into an administratively set price for capacity and an energy only market. In Figure I , the increase in the price of electricity above GEN 6's short-run marginal cost cleared the market. In the two-price market. the additional capacity required by setting a reserve margin is labeled as GEN 7 in Figure 2. Note that GEN 7 never is inframarginal as a unit, thus never earns a margin to cover its fixed cost. As a result, GEN 7 will not remain in the market unless it receives a separate payment to cover its fixed costs--a capacity payment. Note also that all other generators' margins have been lowered by virtue of adding GEN 7. However, since they do have positive margins, they mutd potentially bid into the mpacrty market at a price lower than that for GEN 7. Because the reserve requirement mandates the existence of GEN 7, the resolution is to administratively set a capacity payment based on what GEN 7 requires in order to be

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financially viable and which al\ generators then receive. af course, GEN 7 increases reliability but, if it was required in order to satisfy p\anning reserve standads, then it has not had to pass an economic test. This in turn will necessitate an administered cost recovery payment which will be inefficient, and ultimately more expensive.

If the quantity of MWs in the market continue to be administered, e.g., by mandating traditional planning reserves, the role of economic forces in shaping the capacdy decisions in the market will be severely reduced. All that may be achieved by restructuring is (slightly) improved dispatch from creating large regional pools. The U.S. already has fairly efficient dispatch, simply from pool prad~ces and existing wholesale trading between utilities. The reason that restructuring and generation deregulation is an issue at all is bemuse the regulatory process has not resulted in good capacrty planning or more exactly, dernandfsupply balance. (Observe the share of non-util'i generator (NUG) contracts and nuclear units responsible for the stranded costs of the industry!) Thus, it is essential that the focus be more on achieving competitive capacity planning, and demandisupply interactions, rather than competitive dispatch.

Recent analytic; studies confirm the suspicion that existing dispatch is fairly efficient. Simulations of a few very large regions of the ooun try (each well over 100,000 MWs, e-g., the entire Western Systems Coordinating Qunal (WSCC)) show that only a few percent reduction in dispatch costs would ensue from region-wide dispatch as a single control area, even assuming transmission capacdy were costless and infinite. Figure 3 summarizes tfie range of dispatch improvements in 1 994, 1997, and 2000, for three regions of the country: While this is a valuable savings, it is not anywhere near as large as the 10-15 percent savings that have sometimes been promised as the immediate payoff of restru~turing.~ These results strongly suggest that policymakers should not be Imking to restructuring to provide an immediate "competitive dividend.' The true benefits of restructuring will come in 5 to 10 years, as the fixed costs and capacity requirements of the industry and the character of the demand curves change in response to price signals and risk that have never been felt before by suppliers or customers under regulations. That is, the benefits will be both in dynamic efficiency and aIlocational efficiency.

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Likely Characterirtics of One-Part Electric Prices.

How might one-part prices for wholesale generation behave? As suggested above, it is quite likely that they will be very volatile, for several reasons: the capital intensity of the industry, volatility of the upstream fuel costs (especially natural gas in the U.S.) or availability (especially in hydro systems), high customer VOLL, and scarcity conditions that are random, often sudden, and nomlinear, Evidence for what this might look like can be found in the U.K. power pool. Figure 4 shows the weekly average of half-hour spot prices paid to producers (the Producer Purchase Price) since vesting. This price includes the marginal bid price plus a capacity scarcity term administered by the Pool based on a VOLL of roughly WlkWh times the prevailing LOW. We see that since privatization, the average price of power has not risen significantly but the volatility (as measured by standard deviation of half-hourly prices within each week) has risen dramatically. Moreover, the price has become very peak-intensive; Figure 5 shows that a combustion turbine (CT) could be paid for in 2-5 percent of hourslyear, with prices in top half percent of hours averaging 257 UMWh in 1996. Such volatile, peak-intensive prices are perfectly consistent with other capital-intensive commodity businesses (gas, metals, etc.) and with prevailing U.S. industry beliefs about VOLL. (Even though the U.S. pools may not follow the practice of adding a capacity term based on VOLL ' LOLP, reserve targets are based on similar estimates. If we have been justified in requiring roughly 20 percent planning reserves, then we should expect demand-side bidders to set the market clearing price occasionally at such very high numbers as observed in the U.K. Wholesale power markets in the U.S. are already moving strongly in this direction. Day-ahead prices in July 1997 briefly exceeded $340/MWh in the East Central Area Reliabilrty (ECAR) region. While, at first blush, these erratic, and occasionally very high, spot prices might appear undesirable, the opposite is actually the case:

Figure 3: Cost Savings from Dispatch under Restructuring Not Likely to Be High

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I cn 8 8 d L

8 2 UI m r .- $ CD f "

s

0

- 3.8 Base case is trade with existing

I I transmission constraints and fees.

Range shown is for three regions (WSCC, -- NE, SE) dispatched for 1994, 1997, and 2000.

TX Only = No fees, but existing ** Transmission constraints.

Fees Only = No Transmission constraints,

1 .o but Transmission fees (handoff charges).

0.5 Free Trade = No fees, No Transmission n n Constraints.

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TX Only Fees Only Free Trade

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UK Pool Purchase Prlce by Component 1996 Price Duration Curve

Avanp. Pflce Capmclty

durlng 'K of Year ConMbutlmnm K Of Y..t

0.5% 10

assumlng f201MWh varlable cost 100

50

n

UK price paid to producers ( S M P + LOLP x (VOLL - SMP)) is very concentrated on peak. A CT can be paid for in a few percent of hours of a year-

The highest half-hourly price to date was El, 1081M Wh, recorded at 5:OOpm on December 7,1995 (roughly $1.7OlkWh).

Fnctlon of Yaar

Note: SMP = System Marginal Prlce = highest accepted energy bid price, wlthout transmission wntraints LOLP = Loss of Load Probability

Figure 5: Power Price Peak Intensiveness: U.K. Experience

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Acute price swings would motivate and reward timeof-use demand flexibility, though the focus would now be on peak demand reductions rather than reductions in the average use of energy that has been the focus of most administered demand-side management under regulation. A key driver in achieving this flexibility will be rapid penetration of real-time metering and behind- the-meter innovations in smart appliances and commercial equipment. This will result in flatter load shapes that reduce or defer the need for new =pacity additions. Peak-intensive commodity prices also reward only those generators fhat are actually online in the few hours when prices spike. Under such a stimulus, forced outage rates around peak hours should drop radicajly, again delaying our need for generation capacity expansion. With locational spot prices that reflect capacity scarcity as well as energy variable costs, the transmission congestion rents (basis differentials) across bottlenecks will be much larger--large enough to elicit transmission expansion ifhhere that is the preferred solution instead of new generation. Transmission and generation should substitute for each other in this fashion, whenever expansion is an issue. Sharp peaks will elicit firm curtailable demand, prioritized by price levels, that effectively bring the entire curve of marginal willingness to be curtailed (i.e., the entire VOLL curve) into competition with supply. This increases cumpetition' and eliminates the need to estimate what the marginal VOLL is for generation LOLP planning.' The voIatili of spot prices may be unappealing to many customers, who will enter into long term fonnrard contracts that inoculate them from the extremes. These contracts provide financial stability for the seller as well as the buyer, enabling the seller to finance and operate new mpacity profitably. Absent such forward contracts, a new entrant hoping to capture a piece of the spot market profitability faces very substantial risk, particularly at the hig h-price, low-volume peaking end of the market and, if making a significant capacity addition, may also drive the price of power down and fail to capture

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the desired profits. As explained below, this will help lirnft market power, if any, in the physical generation (spot) market.

Implementation Issues-Adequate Competition.

When prices are allowed to signal the need for capacity and the market allowed to fill that need, it is likely that spot prices occasionally will have some very high spikes. Contrary to the conventional wisdom, these spikes can be acceptable and desirable. Even if they are the result of the abuse of market power, there are a muple of principle ways of dealing with them. First, forward markets both hedge the risk of spiky markets and also lessen the incentive of the seller to manipulate prices. Second, the high prices serve both to communicate the need and provide the incentive for new capacity.

Spiky Prices Can be Accephzble.

Partly because extreme spot prices are so unfamiliar under our current system of administered, average cost prices, it is possible that they will occasionaUy have the appearance of being anticompetitive. Recall that they could be much higher than traditional electric prices; the British record to date is fl,l801MWh for a few half hours in December, 1995, or roughly $1 .TO/kWh! Even higher prices have recently been &sewed in M e highly mrnpetitive Australian market, where recent spot prices have averaged little more than 1 $kwh (U.S. dollar) but VOLL is currently set to around USS3.30lkWh and likely to be raised to US$16.50. In part, the appropriate publlc pollcy reaction to these situations should be a function of the market conditions under which they occur. If there is little a pnbri reason to suspect market power, antitrust agencies should be more tolerant than if there is a structural reason for suspicion. This requires making a distinction between ex ante vs, ex post market power.

Scarcity premiums implicit in the spot price, i.e., margins in excess of the variable operating cost of the marginal unit in the bid dispatch ladder, should not be deemed monopolistic unless I) they are consistently above replacement cost, for assets likely to recover their total costs over a small, and highly uncertain, number of hours of use,

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and 2) there are no ex anfe barriers to customers insuring themselves against ex post price spikes via forward contracts, e.g., futures or options.

An example from anofher context may be helpful. If local prims of water spike after a hurricane, most economists would aver that we should be appreciative rather than resentful, even if the temporary premiums are very high. After all, there is a capital cost associated with holding water in inventory for this rare purpose, or a risk associated with foregoing some of your own water consumption in the interest of a fast profit. The high prices will encourage more people to sew-insure (by storing water) or even to go into the emergency water business to drive down the price. There are no ex ante barriers to being insured against this, so ex post we should not object. Likewise for electric power contingencies.

Unfortunately, this replacement cost pricing test is very difficult to apply, because of the great uncertainty associated with how long or how often the opportunity to recover more than variable costs will prevail for the marginal generating units. For the majority of units, it will be profit maximizing to bid something very close to short run variable costs, assuming that the pool or power exchange (PX) clears all bids at the price of the last dispatched unit in each period. Units that are expected to dispatch for only a few hours may need to make a tough decision as to whether or not to embed startup costs in their bid, but any units very likely to be inframarginal for long periods gain little or nothing by bidding more than their variable costs. To do so risks impairing their position in the dispatch curve, hence reducing their hours of operation and profitability, since they are not setting the clearing price anyway. Even if a plant is marginal in one hour, it is likely to be inframarginal in the next iflwhen load is increasing. Thus only units at or near the very top of the ladder may be able to bid more than their variable cost; indeed they may have to do so to make up for the lack of inframarginal operating profits that would otherwise help cover fixed COS~S. '~

For instance, a new CT costs around $350ikW to build and perhaps $8-7OfkW-year to aperate (ignoring fuel costs), entailing an annual carrying charge of $50-6OlkW-year to cover fixed costs. If these amounts were to be recovered over only the few hours of the year in

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which the last percent of reserves were expected to be used, a bid of several dollars per kwh could be required. An owner might go a few years without experiencing the demand and system conditions in which such a bid would be taken, so bids in those years (or the number of hours in which the plant operates at those prices) might have to be well in exess of steady annual payment rates at cost-of-sewice levels for new capacity." Identifying abusive versus reasonable pricing in this kind of environment will be very tough. Accordingly, it may be more useful to turn to the second test, of whether or not there are adequate forwatd markets toinsure against ex post price premiums. If so, then spot price premiums should be tolerated.

Forward Markeh.

The obvious distinction between electricity and water is that electricity is effectively not storable in bulk. However, power can be stored "synthetically" through forward contracts, e.g., buying power in October and selling the same quantfty in November is financially equivalent to storing and reselling. This suggests that forward markets might provide some of the same kind of ex ante protections as we find for other. storable commodities. So where might spot price abuses occur, and will fotward markets be likely to emerge for those locations?

Bottlenecks behind contingent transmission constraints may create the opportunities for ex post price spikes we would like to insure against, and there are likely to be many such locations throughout the country that have occasional bottlenecks. Indeed, it would be a bad sign if here were very few such locations, as it would indicate that the grid was over-built; it is efficient that there be lots of locatlons where out-of-merit, multi-lambda dispatch occurs some of the time but not often enough to yet justify expansion. Many cities in the U.S. have this feature. For instance, San Francisco was recently identified as a "load pocket" in the California IS0 planning studies. The San Francisco Bay Area has a peak load of between 5000 and 7400 MW and an import capability of roughly 4500 to 5300 MW. Generation within the San Francisco Bay Area must be used to serve the last 500 to 2100 MW of peak,'' and ownership of that generation has been and will necessarily remain highly concentrated. (All were owned by Pacific Gas & Electric until its recent divestiture; now two of the plants are owned by Duke:

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Moss Landing (1474MW) in Monterey, and Oakland (165MW) in Alameda. Both are currently designated must-run by the ISO.)

The concern must be that horizontal concentmiion of generation in such load pockets could discourage third parties from writing forward contracts. Potential contract writers may fear that the local (nodal) spot market is not a "fair game." Specifically, the incumbent (or affiliate thereof) may be perceived as being able to write fo~lard contracts that are relatively assured of ending up in the money, hence the incumbent can take less of a bid-ask spread on his transactions.

Evidence on the influence of horizontal market power in other commodities is mixed. Several markets with active financials have fairly concentrated supply markets, e.g., coffee, and some metals, yet their futures contracts have escaped cornering. (Newbery reported that for eight traded commodities, producers from a single country, often coordinated internally, controiled over 50 percent of the available supplies, yet the corresponding futures contracts trade fluidly.13) Of course, these markets are not necessarily analogous to electric power, as m e r i n g of commodities almost always involves inventory accumulations that are not feasible for electricity. There may also be a selection bias, whereby markets with successful futures contracts are precisely those that have not experienced pervasive spot price manipulations, notwithstanding high concentration of production ownership. Some futures markets have failed to take root because of market power in supply, e.g., tini4, and it has been speculated that Britain has not developed active power futures trading because of the horizontal market power problems in generation that have been documented there."

The problem in a nutshell is that the futures price for a non-storable commodity should reflect the expected spot scarcity premiums. For a highly storable commodity, one can always buy the product when its spot prices are low (unmanipulated) and hold it or sell it fonvard. This cannot be done for power, so the f m a r d price is a pure derivative of the spot market. This means that ex ante futures prices will be much lower per kwh than ex post spot prices in periods of spikes, but the futures prices will be paid on many kwh for which the spot price premium does not occur. If this is all that can be accomplished, theri

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the forward markets do not reduce spot market power, they simply disperse the exposure across all other periods.

In fact, forward contracting creates more competitive protections than this. First, any forward contracting that the dominant players undertake reduces their incentives to manipulate spot prices at the expirafion (delivery dates) of those contracts. It is only the net position, e.g., spot sales in excess of forward sales, that can profit from price spikes. Moreover, the net position of a big supplier may occasionally be short (more presold than producible by that party), making spot price decreases preferred by that seller. Relatedly, forward sales reduce the amount of uncommitted capaaty that the seller can manipulate, effectively reducing his w her market share in the price-setting generation. Concentration is down; competition is up. Moreover, there are game theoretic arguments for expecting that in a market with two or more dominant players, forward contracting will become a mode of competition between the oligopolists, driving them towards eplicient spot pricing at delivery because of the very limited net positions they are likely to hold at the time. AIlaz and Vila show that the situation becomes akin to a "prisoners' dilemma" for which the equilibrium, repeated game (Cournot) strategy is to not cooperate.16

Thus forward markets for power may play a key role in alleviating generation market concentration concerns, and those fotward markets are more likely to develop the more the spot price of power reflects the full value of the service. That is, a one-part commodity market, with its attendant volatility and occasional substantial premiums, provides a more fertile ground for the emergence of forward markets than a two- part market in which the mpacity component is regulated or obligatory under non-market standards. Of course, there remains a chiken-or- egg issue of whether enough market power will prevail to stifle participation in forward markets. The above results of Allaz and Vila suggest that this is likely to be a pmblem only where there is a near monopoly on local production, which can be alleviated by strict divestiture policies requiring a few new owners.

The importance of Price Sign&.

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It is also likely that one-part spot prices exhibiting any kind of market power will quickly sow the seeds of thdr own destruction, if they are given the chance to da so: High spot prices in load packet regions will encourage curtailable demand bidding into the pool. Indeed, such participation may be the best or even only comprehensive solution for inducing significantly more wmpetition in these places, as generation expansion in urban areas is likely to be limited by environmental restrictions and the lack (or high cost) of good sites. Conversely, if bidding restrictions and cost recovery assurances (from the ISO) are imposed on "must-run" units behind transmission limits, then the price signal to induce demand-side participation, or to build generation, or to expand transmission across the bottleneck will be very weak. As a result, the dispatch will contain (many) out-of-merit plants not facing wmpetition, and this inefficiency wYl be perpetuated indefinitely.

Note that transmission expansion is also impaired by such a policy. Transmission can be a substitute for generation capacity, once expansion is needed, if there is slack generation available elsewhere. The lack of a capacity scarcity premium in generation spot prices behind a transmission constraint will mean that there is no meaningful signal in congestion rents for solving his problem with new wires. The only congestion rents will be almost trivial, e.g., for marginal losses and for occasional grid contingencies that are not systematic enough to have any associated expansion implications.17

This issue has arisen in California, where a recent study for the IS0 concluded that under at least one of six possible operating conditions, more than 14%0 MW of the fossil generation in the state (nearly a third of the state's generating capacity) should be deemed 'must run for reliability purposesn-and this analysis did not even take into account the units that are occasionally needed for stability and security purposes.'Vartly as a result, the vast majority of gas generating stations in California may be operated under a contract with the IS0 that prohibits them from bidding above their variable costs during 'constrained on" periods designated by the ISO, and which requires them to rebate 90 percent of their bid profits in other periods in exchange for operating under a contract that covers all of their fixed

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costs. Many of these units are gas-fired s t e m generators that are not particularly efficient and might even be unemnomic against new technology, absent their particular locational roles. Another undesirable consequence of this is that since under California's restructuring law power generated by nuclear plants, qualrfying facilities, and spilled hydro must be accepted first in the PX, the remaining amount of generation open to competitive bidding is fairiy limited.

Imposing price restrictions of this kind is of course a very sensible policy to pursue if one has no recourse but to rely on unconcentmted ownership and oontrul of margin-setting physical supply before deregulating generation. But there are clear costs to this approach, despite the protections it offers--most notably the risks of extending the economic lives of units that might not necessarily be viable otherwise, and discouraging Innovations and expansions that would otherwise ameliorate this problem. If, as in California, a very large numberof "must-run" units are designated, then many of the potential fruits of restructuring may be suppressed.

Empirical Evidence for Onepart Power Markets-the New Zealand Experience.

In the U.S., we can only assess these restructuring policy issues by analogy to other commodity markets. In a few other countries, there has been deregulated production and trading of power for some time under one-part pricing, notwithstanding some oonerns about potential market power. New Zealand provides one of the most interesting case studies. A similar regime is operating successfutIy in the Australian market.

The New Zealand system consists of two alternating current (AC) sub-systems, for the North and South Islands, connected by a 1200 MW submarine high voltage direct current (HVDC) link. The South Island system which is entirely hydro, with moderately sized reservoirs allowing storage of SpringlSummer flows to meet winter peaks, but relatively small inter-annual carry-over, typically meets South Island requirements and allows export to the North, where there is a mixed hydralthemal system. On average, 75 percent of national

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requirements are met from hydro, 7 percent from geothermal, and the remainder from a variety of thermal plant, mainly burning gas.

Reservoir capacity is also relatively small, making the country quite vulnerable to shortages in a dry year, when inflows may be 20 percent less than normal. The transmission network is relatively sparse, covering an area the size of the U.K., but serving only 3.5 million people, with an annual load of around 3000GWh. As a result, transmission accounts for a relatively large proportion of the cost of delivered energy, especially because the major hydro resources are in the south of the South Island, while the population is concentrated in the north of the North Island. In such a small system, spinning reserve is a significant issue, particularly bemuse it is necessary to guard against the failure of the HVDC link. In fact, there have been occasions on which more generation capacity has been devoted to spinning reserve than to energy production in the receiving islandz0

Prior to 1987, the energy sector was totally dominated by the Government, and reform has proceeded in three broad stages. First, the Government's generationltransmission assets were corporatized as the Electriciv Corporation of New Zealand (ECNZ), which operates under normal commercjal law, and is expected to operate as a profitable commercial enterprise. Second, ECNZ's transmission assets were formed into a separate company, Trans Power, while the local distributorlretailers, which had formerly been under local government ownership, were corporatized and in many cases privatized. Finally, ECNZ's generation assets have been formed into two competing firms, both still in public ownership, with fringe assets being sold off. There is no explicit regulation of the sector. Apart from some surveillance by the Ministry of Commerce, the parties have been left to form and maintain satisfactory institutional and commercial arrangements, with all parties being free to appeal to the Courts andlor the Commerce Commission. There are no legal barriers to entry in generation and retailing, or in transmission/ distribution, although dw latter sector is not expected to be particularly competitive.

Market arrangements have also evolved over the last demde. Prim to the reforms, ECNZ sold power to a large number of generally small, local distribution companies under a two-part tariff, 50 percent of which was accounted for by the capacity charge reflecting, in part, the

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traditional importance of transmission capacity constraints. After corporatization, transmission and energy pricing were separated. For energy pricing, ECNZ introduced a pseudo-spot market.?' Under these arrangements, half-hourly short-run marginal cost (SRMC) based "spar prices were determined a week in advance, using ECNZ's production costing Annual 'energy" contracts were then written in the form of "two-way" financial contracts, under which the parties each agreed to compensate each other on the agreed quantity, should the "spof' price turn out to be higher, or lower, than the agreed strike price. These contracts were negotiated with each party, and sculpted to meet their requirements, although ECNZ insisted on its customers mnfracting for between 90-1 10 percent of forecast demand. The goal of this market was twofold. First, it was designed to improve efficiency by ensuring that, even though the average price of power was largely determined a year in advance by the contract price, the rnarket participants always faced an efficient price signal reflecting the SRMC of meeting their actual requirements. Second, it was designed to introduce power companies to what was then a radically new way of organizing the electricity market, as a preliminary to the development of a truly competitive spot market in which all parties would be free to enter into their own spot and contract arrangements, and take commercial responsibility for the consequences as advocated, for example, by Ruff .23

An important feature of those interim market arrangements was the imposition of a cap on spot prices, set to the SRMC of the most expensive thermal generator, which was around three times the average spot price. Conceptualfy, it was recognized that the spot market should really be uncapped, and that capping the market was equivalent to issuing all parties with "one-way" cab options, or 'capacity tickets," with a strike price set at the market price cap. In principle. it was argued that the price of such option contracts would set the "capacity charge," and that, in the long run, this should equal the cost of building and operating peaking plant, in this case open cycle distillate-fired turbines, able to generate at an SRMC equal to the price cap. Thus, under this interim "capped market" regime, contracts included an additional component, sometimes described as an "insurance premium" to cover this cost, with a similar 'upliff" component being added on to pool prices. These arrangements were not ideal, but

26 Tiff e

they did operate for several years, with apparent success in terms of facilitating retail competitiona and inducing more flexible demand response, as evidenced by a flattening of the daily load curve. This is reflected at the retail level, where domestic customers may have a variety of tariff options, involving dierent daylnight rates and/or interruptibility provision^.^^ Larger users, such as universities or factories, can opt to face spot market prices directly and may install sophistimted signaling and control systems to reduce usage at times of peak prices.

These market arrangements passed their severest test in 1992 when hydro inflows reached record low levels. Peaking plant which had seen little or no service in its twenty year life was called on to operate extensively, and spot prices were maintained at the market mp level continuously for several weeks. This induced national load reductions of the order of 15 percent, with most local power companies making significant profits under their contracts. effectively 'selling back' power which ECNZ had contracted to deliver. Far from 'profiteering' in this shortage situation, ECNZ paid out nearly as much to buy back that power as it did for extra fuel, and had very strong incentives to keep output up and prices d m . (This experience may be mmpared with that in a similar crisis twenty years earlier when, in the absence of a spot market, regulation induced load reductions of only 7 percent.) It is now expected that there will be a much stronger demand response in any future crisis, b w u s e power companies and ultimate consumers have put systems and procedures in place to react more quickly and effectively. This suggests that the spot market can provide very effective signals for demand-side response in extreme circumstances. The implications for reserve margins are obvious.

These interim market arrangements remained in place for rather longer than had been pbnned, but a competitive spot market was introduced in 1996, following the breakup of ECNZ. The spotldispatch market is now operated by the Electricity Market Company (EMCO). Generator offers, and load bids, are used to perform a day-ahead (indicative) market clearing to prduce a pre-schedule and forecast prices. The market clearingldispatch model represents all nodes in the national network, and determines nodal prices reflecting inter-regional dispatch and congestion for some 120 n d e s where active trading

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occurs. Offers and bids may be freely changed up to four hours before real time, though, and the market is re-cleared to provide new dispatch and pricing foremsts on a regular basis. Real time dispatch must meet actual loads, but is detemrined, as far as possible, by re-solution of the market clearing model using the latest generator offers. The former price cap has been removed, and final prices are determined, ex posf, by re-solution of the market clearing model to meet the actual metered load using the generator offers, and grid state, which pertained for that half-hourly trading periodba Spot prices have been fairly stable at levels similar to those prevailing prior to the establishment of the market. There is little daylnight variation, as is expected given the abilrty of the two hydro reservoirs to absorb short-term demandlsupply fluctuations.

The principal concern here is with the role of oontracting in such a market, and particularly with its role as a substitute for regulatory intervention, and in fostering appropriate provision of various forms of reserve. During the reform process, there were real concerns about the economic wisdom, or political viability, of breaking up the relatively small ECNZ system, and fear that the resultant firms would be unwilling, or unable, to manage their reservoirs appropriately in the event of another hydro crisis. There was also considerable fear that an uncontrolled transition to market sttuctures could result in significant short term damage to pubiic welfare, and to an unfortunate regulatov backlash. Thus it was accepted that, even given a goal of totally free markets, transitional guarantees of some fom were required. In fact the Wholesale Electildty Market Studyz7 conduded that, without a reasonably high degree of bng term conlracting, the market would be subject to gaming by oligopolistic generators in the small New Zealand system, even if breakup were pursued to the level of individual hydro systems and major thermal plant. Conversely, it was shown that, by reducing market power, financial contracts would provide strong incentives to maintain adequate storage, and assist in providing reservoir coordination similar to that obtainable in an integrated system.= Such contracts were also seen as key to ensuring a smooth transition to a more competitive structure by providing consumers with protection against the risk of exploitation, while protecting the value of public assets. Thus it was proposed that agreement should be reached on a set of vesting contracts, withering over the initial years of the market, before any asset breakup or divestiture occurred.

It may be argued that this approach is 'artificial," but it should be understood that, whatever approach would have been taken, the situation existing immediately after such a sectoral rearganization will necessarily be artificial, with market institutions, firms, supplyldernand balance, plant mix, and contracting relationships all creations of the re- organization process, or of the prior regulatory regime, rather than of the market. In particular, it would have been equally artificial to create a market In which the incumbent suppliers inherit sunk cost plant, but no long term contracts. Thus it was proposed to establish the market with contracts in place, perhaps approximating the portfolio which might have arisen from a competitive market history. The aim was to leave the market free to determine signals for operation, consumption and investment, via spot p r i ~ s , while determining an allocation of the value of the existing system between the stakeholders. The key principle was that any transitional guarantees should be implemented via contracts of the form that might have been expected to evolve naturally in a mature market, and that could evolve into appropriate market instruments. It was feared that once any form of regulation was established it would tend to perpetuate itself and expand, rather than allow the market to mature to h e point where such intervention &came unnecessary. Thus, rather than impose price controls on a 'httlenedf generator, for example, a policy was considered which would allow local prices to be uncapped. but require a negotiated option contract that negated local market power. This philosophy continued that of the interim market arrangements, which established a market apparatus which auld be "freed up" later, rather than choosing a form which might have been mathematically equivalent. but would have tended to develop toward a regulated, rather than a market regime.

Even this degree of intervention proved una-table, and a compromise was reached whereby ECNZ was only partially broken up, but the market power of the larger firm resulting from that split was limited by a requirement to o&r, annually, a substantial proportion of its capacity in the form of mid-term (one- to five-year) contracts at prices close to those prevailing prior to breakup. To date. the market has shown a reasonable, but by no means ovewhelming, appetite for such contracts, with ECNZ selling perhaps 70 percent of its potential generation capacity in this way. This relativeb low participation may be

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taken as evidence that the market does not really believe that ECNZ is in a position to sustain spot prices above current levels, because of an impled threat of regulatory intervention andor anticompetitive pressure. The threat of intervention cannot be denied, but the requirement to offer contracts effectively disciplines spot prices. while competitive pressures are actually quite strong in the critical investment market. Although some critics maintained that independent investors would be reluctant to enter so long as the market is dominated by an incumbent such as ECNZ, it can be argued that, provided access to transmission and ancillary services was available to all on a neutral basis, the presence of a dominant incumbent is more likely to muse excessive entrypa This results from investors expecting the incumbent to accommodate entry by sacrificing vofume to maintain prices and because consumers will be strongly motivated to foster diversity of supply by offering contracts to new entrants. These predictions now appear to have been correct, with significant entry occurring beyond, and putting much more downward pressure on prices than previous analyses might have suggested. Similar effects would seem to be evident in the U.K.

It should be understood that most contracting in the New Zealand market is still in the farm of Weway options, as in the previous regime. This is probably not surprising, given the immaturity of the market, but may also reflect the fact that most parties are not attempting to match their load profile at all exactly, instead only conhcting a year ahead for perhaps 75-80 percent of their expected load, a level which they are almost certain to consume at any price. Generators, purchasers and traders operating in the market are free to form a wide variety of financial contracts between themselves, lhough, according to their own circumstances. Dairy factories, for example, have highly seasonal loads but can only predict the onset of the peak season within a few weeks; they can purchase an option covering that window of uncertainty. Smaller purchasers who simply want to buy on a traditional 'tariff basis can do so from traders who c;an diversify some volume risk. 'Call options" (i.e., price caps) have been offered for those who may only want to protect part of their load against very high price spikes, while "capped options" suit those who wish to simply reduce load at such prices. Such contracts are not likely to be actively traded, though, and WEMS laid great stress on ensuring that standard tradable contracts were available, in the form of a hedge against prices at each

Title

island's reference node, so as to ensure sufficient liquidity in the contract rnarkeLm

Still, there has only been limited trading in the first year of market operation. Initially, EMGO introduced a day-ahead contract market, but this soon collapsed due to lack of interest. This should not be surprising in a market where the major uncertainties relate to hydro inflow variations in the monthly to annual time horizon. A d hoc trading occurs between participants when, for example, a trader on-sells "re- packaged" contracts to clients and although EMCO's plans to facilitate trading of standard ECNZ hedges have yet to mateilalze, monthly contracts are belng traded on the futures exchange. Trading activity is sporadic, occurring mainly when there is a significant change in long term weather predictions, but active trading should not be expected in a sector where contracts are mainly bought by participants to cover expected rebil sales, and retail market shares change relatively slawly. It is more significant that each of the two major firms involved have reasonably balanced plant portfolios. However, there is little of the speculative activity which creates much of the liquidity in other markets. This is partly attributable to unfamiliarity with a new market in a technically specialized sector, but it is probably unre~onable to expect independent speculators to get involved with a sector dominated by only two firms, each with significant stockpiles. The malt New Zealand market clearly does not provide an ideal environment for the development of active trading in electricity contracts. Indeed further reform of both the generation and retail sectors is now under very active consideration to create a more dynamic competitive and contracting environment. Thus, the New Zea\and experience suggests some caution with regard to predictions of very active electricity futures markets, although experience may be very different in larger, more competitive, thermal dominated markets, where the pattern of price volatility will be quite different. Nonetheless, these deficiencies should not distract from the very real achievements of the market in bringing forward new investment to discipline prices and providing opportunities for all parties to enter into contracts that match their particular requirements with regard to price and volume risk.

Finally, it is useful to consider the impact of these market arrangements on reserve provision of various kinds. Read ef a1 [1997j3'

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explain how the provision of "contingency reserve" is actually incorporated into the spot market itself, with joint energylreserve offers being used to form a joint energylresetve schedule in a single market- clearing optimization, which also produces prices for energy at every node, and for two classes of reserve in each island. In principle, it has been suggested that contingency events should b e handled by allowing "instantaneous' spot prices to reach very high levels during the event, and relying on market participants to hold reserve in order to capitalize on such occurrences. In practice, this ideal has been deemed unworkable, and the New Zealand spot market uses half-hourly pricing periods. But generators, and other reserve providers who are paid to be "on reserve duty," are effectively offering half hourly 'hedging" contracts against a notional instantaneous spot price, to deliver the agreed increment of power at the half-hourly energy price, rather than to exploit the market power which they would otherwise have, for a brief period, to drive prices to extremely high level. The resultant reserve prices can be significant in New Zealand, averaging around 5-10 percent of the energy price, hence their inclusion in the spot market. Inclusion of reserve In the market seems to be having the desired effect in terns of innovatiin and refinement of resenre management mechanisms. In particular, prices are trending down as more interruptible load enters the resenre market. Legitimate concerns have been raised with regard to the market power which particular participants may possess in the reserve market, particularly in situations where inter-island transfer rates are limited by reserve requirements. In reaIity, by offering intemrptibility at competitive prices, consumers are opting to handle the prospect of inter-island link failure themselves, rather than accept generator offers of secure transfer, backed by traditional spinning reserve. Thus this market is actually much more competitive than the underlying energy market.

Of more concern, in the long run, may be the pmvision of dry year backup of the type which might only be required once in twenty years. Critics of the market reforms advomted a U.S. style regulatory regime, whereby generators would be required to carry some kind of wpacity margin. It was difficult to see how that could be achieved in a market context Apart from the overheads of trying to administer such a regime, it seemed likely to militate against the very kind of innovation in unconventional technologies and demand side response which the

32 Title

market was designed to foster. It was recognized, though, that independent investors would have insufficient incentives to invest in plant which was so rarely called upon, particularly if there was any prospect of government intervention to limit 'price gouging" in any future crisis. The appropriate form of contract to underpin such investment was seen to be a "capacity ticket,' in the form of a call option with a strike price of. say, three times the average energy price. It was also suggested that retailers who have no local franchise and. unlike "distributors," few assets could be tempted to take their chances on the spot market rather than carry what amounts to fairfy expensive insurance cover for quite rare events. Thus a transitional measure was proposed whereby retailers should be required to cover a specified proportion of their load with such capacrty tickets, or equivalent financial guarantees, or at least to make some public declaration of their cover.= Ultimately, this approach was rejected in favor of simply leaving the spot market price uncapped so that those who do not contract for dry year capacity will be fully exposed to the wsts of non-supply in such circumstances. It remains to be seen how much dry yeartpeak support plant will be built under the new regime, but that may be a moot point so long as entry continues at the current rate. In fact, the current level of energy contracting, which includes wver of extreme price peaks, is probably not too far below the bad leveb which might occur in response to extreme prices, and there is certainly sufficient physical capacity now in the system to cope with any likely event. Thus there is no evidence, as yet, that any kind of intervention is required to ensure adequate provvision of backup capacity.

A Restructured Role for Two-part Pricing.

The New Zealand experience is quite encouraging in that it appears to demonstrate that competition a n flourish despite apparently worrisome initial concentration in generation ownership. Further, it provides support that forward contracting and demand-side bidding can jointly alleviate market power abuse that might otherwise occur. Substantial entry has occurred, despite a lack of traditional engineering 'need" for new capacity. The New Zealand experience also reveals that the form

Tile 33

of fonvard contracting can be quite various, spanning many durations and degrees of risk protection. This diverse appetite is by itself an important insight and a good reason for pursuing one-part pricing, since regulated capacity markets under two-part pricing typically offer only one "flavor" of service.

One of the most prevalent new forms of fonvard contracting in the past few years in the U.S. has been option purchase agreements (DPAs), which provide the opportunity but not the oblgation to buy and sell firm energy in the future at pre-specified "exercise" or 'strike" prices.

OPA contracts are obviously much more valuable if written for peaking periods than for off-peak periods, at a given exercise price Thearealsomorevaluableinagivenperiodthelowertheexercise price

Thus the value in OPA contracts is contingent on the precise terms and conditions of delivery, even if the same number of MWs are involved. Such contracts can be valued formally as call options against the projected spot marketWM Figure 6 illustrates this idea.

Since OPAs are for future delivery, it is almost impossible to appraise the reliability characteristics (especially, the forced outage rate or LOLP) of the machine or system that might eventually supply the power, as those machines or capabilities may not even be known at present, and they may vary enormously in mmplex ways acrass offers for the same number of MWs, rendering them noncomparable. Those who have been involved in OPA analyses usually conclude that the term "capacity' is not well defined and that the mast useful, s tandardizable alternative is financially indemnified, firm energy (perhaps with a penalty above replacement cost for nondelivery). With that standard in place, one can put OPA offers (or any other kind of forward contracts) on a common foundation and evaluate their insurance value against price spikes from future mpacity shortages.

While there are many intriguing features of OPA contracts, their relevance for the present discussion is that power options written against a one-part commodity market recreate Wepart pricing, but in a customized fashion:

> 0 5 10 16 20 15 30 35 n

Price of Underlying Asset (S) =spot prlce of power SlkW

Figure 6: Capacity as a Call Option

Call option on power is exercised iflwhen the underlying spot value exceeds the strike price.

Uncertainty over that future value gives options a greater present value as insurance against high prices.

Generating capacity is equivalent to holding a porifolio of call options (as Illustrated above) on energy, with serial expiration dates, with the exercise price equal to the dispatch cost.

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Each buyer (or seller) can move as much or as Iiffle mst per MW into the fixed, demand charge (option acquisition premium) or the energy charge (exercise price per MWh) by simply altering the terms of the option (e.g., a higher exercise price implies a lower premium and a higher energy a t ) . Each buyer or seller can insure as little or much of hislher demandlload obligation as desired, with no need to put all pool-area customers on the same footing, by buying (or selling) options to cap their individual exposure to only a self-selected portion of total requirements. Such options could (in principle) be traded in a secondary market, especially if they were written against a public exchange. Financial indemnification as the standard for delivery firmness allows this, while tying pefiormance to specific physical units makes #is practically impossible.

Thus, two-part pricing can be recreated in a much more custorner- sensitive manner when it arises as derivative contracts written against a one-part commodity market.

Conclusions.

There are a few clear public policy implications of the above. In several venues around the country, ranging from NERC to power pool ISOs, to Congress and state regulatory commissions, policy makers concerned about supply reliabiiity under restructuring are contemplating imposing legal obligations on suppliers to cany planning reserves. This should be discouraged. Instead, the strategy should be to; 1. Encourage one-part pricing and avoid the temptation to regutate

capacity planning reserves or to guarantee 'reasonable" prices under supplier-of-last-resort regulation. There is no good model for poticy among the U.S. retail restructuring experiments to date: California is not requiring planning reserves, but it may place so many units under must-run cost-based contracts that competition is felt only in &peak periods, when no signal for capacity expansion or conservation will be felt. Conversely, the eastern tight power pools do not (yet) have must-run, cost-based protocols in

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mind for their load-pocket capacity, but they seem intent on administering a planning reserve obligation on LSEsaM

2. Encourage demand-side participation as a precondition to opening up power markets that might otherwise require must-run, cost- based contracts for plants behind transmission bottlenecks. Such contracts prevent abuse but discourage entry and would inoculate those (often inefficient) plants from competition,

3. Encourage forward markets with as simple protocols as possible and rapid resolution of regulatory policy uncertainty. Try to create at \east duopolies in the ownership of bottlenecked capacity, using divestiture, and then observe whether the producers contract themselves forward and largely out of their incentives to manipulate spot prices.

4. Tolerate ex post spot price premiums unless there are strong, ex ante concerns about sustainable market power. Many such price shocks will be transients, others will be reasonable by replacement cost standards, and the few others will rapidly sow the seeds of their own destruction.

5. Above all, do not try to create a regime that mixes competition and regulation in generation. This auld easily pruve less efficient than a more enlightened form of conventional regulation, e.g., comprehensive real-time pricing, which would at least send market- like commodity prices to all customers in all locations. A hybrid system is more likely to bring the worst of both worlds rather than the best.

1. Frank Graves is a prhcipal with The Brame Group, Cambridge, Massachusetts; Grant Read is wiih Canterbury University, Christcburch. New Zealand; and Phil Hanser a senior consultant with The Bratfls Group, Cambridge, Massachusetts; and Robert Earle is an associate with The Bratlle Group, Washington, Disttict of Columbia.

2. See Jacques H. Dreze [I 9841, 'Some Postwar Contributions of French Economists to Theory and Public Policy P 54 Amerimn Economic Review (June): 1-64, for a good summary in English of Boiteux's work.

3. It is conwhable that certain customers may lack the means to purchase devices that would insulate them from expensive on-peak consumption of commodity power. Their needs for reIiabilkly could be covered with special subsidies that do not alter the mode of reslructuring recommended herein.

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4. At the time of this writing yet another article (Robert J. Michaels [199T], 'MW Gamble: The Missing Market for Capacity," The EIectricity Journal (Deoamber): 56-64) has appeared espousing the 'uniqueness" of electrlei and the risks of inadequate future capacity under a deregulated market. We feel that It is ironic that Michaels claims that the old, regulated system generated an 'efficient mix of energy and capacity, regulated to be peed as if it were in a competitive environment." To the contrary, regulators are pursuing restructuring precisely because past capacity decisions based on unRm reliabildy aiteria have not produced an economical supply mix. The financial indemnification approach to motivating reliability is exactly alien to the rules and incentives used by commodity Mures markets to assure Liquidi and compensation for contract default.

5. The curves labeled demand in the figures should he interpreted as consisting of demand plus losses and operating revenues.

6. Simulations were performed with the IREMM model of productjon costing and trading. It uses derated capacity and monthly load duration curves, with local areas dispatched first to seme their o w loads and trading occurring with marginal resources amss all interconnected regions. Interconndions are based on NERC summer total transfer capability ratings. and wheeling charges are based on FERC filings or equivalent cost-based rates derived from FERC Foml t transmission data. This work is discussed in detail in U W c Wility Restructuring lmpacfs on Fuels-AnalMng Off- Peak Condifions (Palo Alto, CA: Electric Power Research Institute, I gQ8).

7. To the extent that the 10-1 5 percent savings oceur. it will be because d stranded cost disallowances, which of oourse are not eficienq gains, just zemsum wealth transfers.

8. See Steven R. Backman, Steven J. Rassenti, and Vemon L. Smith [1997],'€fficiency and Income Shares in High Demand Energy Networks: Who Receives the Congestion Rents When a Line is Conslrained?," Economic Science Labmatory (January 21 ), The University of Arizana, Tucson; and Steven R, Backemran, Michael J. Denton, Steven J. Rassenti, and Vernon L. Smith [1997j, 'Market Power in a Deregufated Electrical Industry: An Experimental Study* (February), The University of Arizona, Tucson; and Jijgen Weiss [1997], 'Market Power Issues in ihe Restructuring of the Eleckicity Indusby: An Experimental Investigation," Harvard Business Schml.

9. Forthe integration of demand bidding with supply dispatch sse Fred C. Schweppe, Michael C. Caramanis, Richard D. Tabors, and Rwer E. Bohn [1988], Spot Pricing of Electricity (Boston: Kluwer Academic Publishers). For diswssbn of curtailable demand priorikaticn see Hung-pa Chao and Stephen Peck [I 9971, "An Institutional Design for an Electricity Contract Markot with Central Dispatch: Energy Journal 18(1): 851 10.

10. As a bidding strategy, it would be feasible and profit-increasing to bid the variable mst of the unit most likely to be just above you in the dispatch ladder. For most hours in most market areas in the US., this next unit is likety to be very close in price, as the supply wrve is almost continuous. As peak conditions are appruached, the steepness of the curve and the sparsity of mmpetitors may make this a more meaningful proit-

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seeking strategy of the competing parlies.

f I. This range assumes 33-50 percent debt financing and 20 year capital recovery, the cost of equity at 14-15 percent. The '7 day in 10 years" LOLP standard that

many pods have applied for planning reserves is often associatd (depending on load shapes and other factors) with 4-20 hours per year of expect4 utlserved toad. It is over this many hours that the fixed costs of the marginal peaker would have to be recovered if it were to romain viable. Of course, a new peaker is very likely to have an efficiency much greater than the older units in a market area (i.e., much better heat rate), so it is unlikely that the full costs of a CT will set the marginal value of capacity in a region. That Is, any aew CT will o f k t some of its fixed costs with irrfrarnarginal profits. Nonetheless, the truly marginal unit will have to recover some of its fixed costs in its per kwh bid, and the premium over variable costs muid be quite large.

Z2. Steven Schleirner [i99T], 'Market Power Analysis In Support of PG8E's Application for Market-Based Rates Before the FERC," presentation to the Energy Modeling Forum, Stanford University, January 23.

13. 0. New* [ I 9841, 'Manipulation of futures markets by a dominant producer: in The industrial Organization of Futures Markets, R. Anderson, ed. (Lexington, MA: Lexington Books).

14. Hendrik Houthakker, private communication; Stephen C. Pimng [1995], The Eficient a p e of Private Transactions-Cost-Reducing Instikrtions: The Successes and Failures of Commodity Exdlanges," 24 Journal of Legal Studies (January): 229-255; Stephen C. Pimng [1993], 'Manipulation of the Commodity Futures Market Delivery Process," 66 Jwrnal of Business (No. 3): 335-369.

15. Hendrik Houthakker. private communication.

16. Blaise Allaz and Jean4.C. Vila [f 9931, 'Coumat Competition, Forward Markets and Efficiency," 59 Journal of E m f c Theory: 1-16. See also Richard Green (is961 The Electricity Contract Market" Cambridge University, U.K., preprint May, 1996. It should be stressed that the above authors are addressing oligopoly situations; their results would not apply in a market with a single dominant player.

17. The above discussion of one-part pricing applies to generation because scale economies are not a major problem. This is not the case for transmission, h i c h means that you may still need h v o ~ a r t pricing with a large part of the transmission infrastructure mst baing recovered via some form of 'fixed charge' (possibly a lang run takear-pay TCC ). At the retail. or even wholesale, level these charges may weU be converted in$ a peak cansumption charge, though. and this can cause unfortunate distortions. A pure one-part tariff system is not ne-arily ideal at all levels in the system. See E.G. Read [I 998b1, "Transmission Pricing in New Zealand," forthcoming in Wlities Policy, for a detailed discussion of this issue.

18. R R . Austria, T.1. W n , W.R Puntel, and J.R. Willi [199a, 'Final Report Phase I: Operating Reliability Requirements Study (July 181, PTI Report No. R5W7 (Schenectady: NY: Power Technologies, Inc.).

1 9. The nature and history ol the New Zealand elecbicity system is discussed by J. G. Cub, E.G. Read and 8. Wright [1996], 'Structure and Regulation of the New Zealand Electricity Sector," in R. Gilbert and E. Kahn (eds.), International Comparison of Elecfn'city Regulation (Cambridge University Press), p 3 12-365, while current arrangements and recent experience are covered by E.G. Read [1998a], 'Electricity Sector Reform in New Zealand: Lessons from the last Decade," forhoming Pacilic Asia Journal of Energy, from which lhls summary is derivad. E.G. Read [3998b], Transmission Pricing in New Zealand: forthcoming in Utililies Wicy. E.G. Read and D.P.M. Sell [I 9871, A Framework for Electricity Pricing, Arthur Young report released by the Eledricity &rporation of New Zealand, Wellington.

20. See Note 18 above.

21. Read [1998b] argues that capacity elements are still important in the transmission pricing emngements, reflecting the prevalence 01 scale economies in that sector, although those capacity elements should properly be expressed in ths form of long term transmission congestion contracts.

22. In fact the market shcture adopted here was a natural extensbn to the way in which ECNZ's costing model had been constructed. Since hydro was typically -on the margin: the SRMC prices were themselves determined by a reservoir management model, which effectively calculated the 'option value' of a unh of water as the expected voluo of that water, if stored to avold the cost of thermal fuel, or shortage, at some future date.

23. See L.E. Ruff 119921, 'Competitive E l d c i t y Markets: Economic Logic and Practiwl Implcmentaiion" In Copirtg wift~ the Enetgy Future: Markets and Regulations. Prowedings of the International Amciation of Energy Economists, Tom. France, for a description of tfie kind of market sbucture that New Zealand may pursue eventually.

24. See M.E. Bergera and P.T. Spiller 1199T], The introduction af Direct Access in New Zealand's Electricity Markets" in A Lapointe, P.-0 Pineau and G. Zaccour (eds.), Proceedings of ihe lntemafional Workshop on Deregulation of Electric WIifies, Montreal, pp. 253-274.

25. Most domestic water heating systems are electric, with a substantial storage tank and remote control systems allowing the local power company to determine when heating will omur. Wight storage" heating is also common, and can be corrtrolled in a similar fashion.

26. This supplyldemand asymmetry in dispatch and final pricing is less lhan ideal, and seems likely b prove inadequate, should there be a repeat of the 1992 crisis. Normally bough, this B a reasonable approximation, given hat demand can only react to ex ante price projections, and 4his reaction is reflected in the loads to be met by real time

40 Title

dispatch.

27. WEMS [1992], Towards a Competitive Wholesale EIedtfcW Mafiet: Conclusions and Recommended Approach, Who\esale Electriuty Market Study (WEMS), Final Report, Wellington, New Zealand.

28. See T.J. Scott and E.G. Read [1996], 'Modeling Hydro Reservoir Operation in a Deregulated EleMcity Sector." Infemahnal Tmnsactions in Opemtions Research, 3(3-4): 209,22 1.

29. See WEMS [I 9921.

30. Hedging between those reference nodes and local nodes may be bbtained from Trans Power, but this is not compulsory, artd many participants, who are only exposed to relatively minor pice d'irentials due to losses, may operate withut any su& m r .

31, E.G. Read, G.R. Drayton-Blight and B.J. Ring [1994, 'An Integrated EnergylReserve Market for New Zealand" in A. Lapointe, P.-0 Pineau and G. Zaccour [eds.), Prcrceedings of the International Workshop on Deregulation of Electric Utilities, Montreal, pp. 275-291.

32. The grounds k t purchasers in the wholesale market may not realty represent the interests of small cansumers who have Insufficient choice, or information, to judge the creditworthiness of competing suppliers in the event of a crisis. Such arrangements ware seen to be equivalent to the prudential requirements placed on financial institutions involved in what are essentially similar types of transaction.

33. Frank C. Graves and James A. Read, Jr, ff 99Tj, 'Capacity Rices in a Competitive Environment," Chapter 7 in The Virfual UUIh'y, Shlmon Awerbuch and Alistair Preston (eds.) (Bosfon: Kluwer Academic Publishers): 1751 92. Frank C. Graves [I WT], "Capacity Prices in a Competitive Power Market,' presentation, IEEE PES Summer Meeting (July). Bemn, Germany.

34. Reliabilify Assmnce Agreement a m g Load Serving Entities in the PJM Control Area, June 2,1997. William W. Hogan [I 99a, Report on the Propmd fo Resfnrctrrre the New York Electric@ Market (January 31 ).