Imagine if the airlines had followed a utility model when they deregulated back in 1978.You and five other planeloads show up at the airport to catch a flight to Chicago. Every few hours the airport operator holds an auction for the next hour's Chicago flights. Delta offers two new 767's at $200 per ticket. U.S. Air bids one 737 at $300. American has six
DC-9's and bids each one at $1,000 per head. When the auction ends, Delta and U.S. Air fill their planes. American fills two of its six flights. But despite the broad range of bids, you and everyone else pays $1,000 per ticket.
Welcome to electric utility "deregulation," as some envision it. It is known as "PoolCo."
PoolCo has already been adopted in the United Kingdom. It was recently endorsed by a majority decision of the California Public Utility Commission (CPUC), though Commissioner Jessie Knight recommended an alternative direct-access plan in his dissenting opinion.1 If PoolCo is adopted for the electric utility industry, consumers will not enjoy the benefits achieved through deregulation in the airline, telephone, and natural gas industries, because the power supply remains in the monopolists' hands. Ratepayers still purchase from a single monopolist distributor. PoolCo may mean deregulation, but not true competition.
Under PoolCo, utilities ignore traditional service areas and bid resources hourly to supply all the needs of the region or state. The same utilities then purchase power at the highest accepted bid price and distribute it to consumers. In PoolCo theory, the winning bid marks the marginal cost (essentially fuel cost only) of the least efficient resource needed at the time to meet demand.
Recent reports indicate that a compromise solution may emerge in California that contains elements of both the direct access and PoolCo concepts.2 But whatever model emerges, the debate will include PoolCo. In the United Kingdom, two major power producers found they could bid up prices because of limited competition. Some say "it can't happen here." We strongly disagree.
A New York PoolCo?
Let's consider how a California-style PoolCo might operate in New York State.
The hypothetical New York PoolCo would encompass a huge power market with a peak demand of roughly 27 million kilowatts and a supply of nearly 36 million kilowatts (see Figure 1). Under the California model, nonutility generators (NUGs) would be directly assigned to utilities and would not participate in PoolCo, limiting competition. In a New York PoolCo, Consolidated Edison Co. of New York (Con Edison) would be the dominant supplier, with more than 10 million kilowatts, or 30 percent of total pool generation. Two other high-cost suppliers, Long Island Lighting Company (LILCO) and Niagara Mohawk (NiMo), would own another 29 percent of total supply. Four other investor-owned utilities would come in as lower-cost producers, but by themselves could not supply enough power to meet requirements, even during lowest demand periods. NUGs would command a 15-percent share of all supply, which would not participate in the bidding process.
Taking into account that the outage rate of power plants is approximately 20 percent (more than 30 percent for nuclear plants), Con Edison's status as the dominant supplier becomes clear. Even if all other utilities in the pool ran all units full out, the pool could not meet peak demands for hundreds or even thousands of the hours during the year without relying on Con Edison. During such periods, Con Edison could charge virtually any price, and the hypothetical PoolCo would have to accept its bid. The other major suppliers, recognizing this situation, likewise would see no real need to compete on price much of the time. The U.K. situation would arise again, despite the apparent presence of eight major suppliers and numerous NUGs in the New York market. Without robust competition, monopolistic prices and profits would emerge, constrained only by the elasticity of demand.
Moreover, utilities would stand in an excellent position to legally manipulate bids to maximize profits due to their intimate knowledge of competitors' costs. In years past, electric utilities have shared information and computer databases to facilitate joint planning. Interestingly enough, for 1995 Con Edison and two other utilities filed their Form 1 data with the Federal Energy Regulatory Commission (FERC) under a seal of confidentiality, allegedly to protect their competitive positions.
Manipulating Prices
We performed a computer simulation of a hypothetical New York PoolCo (see sidebar on page 28). Our results demonstrate that Con Edison and LILCO would both exert sufficient market dominance to bid generation at prices well in excess of incremental production cost, and in fact could substantially increase their profit margins by doing so. The model predicted that none of the other utilities in the state would command sufficient market power to profit from such pricing tactics; instead, they would lose profits by increasing bid prices. But they would not need to. They would enjoy a free ride and reap windfall profits stemming from the monopolistic pricing practices of the dominant suppliers.
Con Edison's pricing strategy would essentially dictate the market price for power in the New York PoolCo. For example, if Con Edison bid at only its incremental production cost, the market would price power at approximately $29 per megawatt-hour (Mwh). Assuming Con Edison bid at two times its incremental production cost, a market price of $40/Mwh would prevail. This result is important, for it is unlikely that new generation could be installed (at least in New York) at these price levels. Assuming that both Con Edison and LILCO adopted a pricing rule equal to two times incremental cost, a market price of $49/Mwh would result. We believe this is probably close to the levelized cost of new gas-fired generation in New York.3
Would investors invest in new gas-fired capacity in such an arrangement, with volatile fuel prices and two dominant suppliers able to manipulate prices? It is quite possible that coal-fired capacity would offer the cheapest realistic source of alternative generation, at a cost of approximately $60/Mwh. Con Edison could price at more than three times incremental cost before the average market price exceeds this level. Profits for Con Edison and all utilities in the pool would rise substantially in this scenario.
Stranded Cost Implications
PoolCo's determination of market prices will affect determinations of stranded cost, since estimation of stranded cost is ultimately an exercise in estimation of market prices. If the actual market prices that develop reflect limited competition, they may differ substantially from those that were expected when the compensation for stranded cost was originally set. Either ratepayers or shareholders could stand to lose enormous sums of money.
Figure 2 shows estimates of the cumulative stranded costs for each New York utility, given four different predictions of market prices under PoolCo.
With the price at $29/Mwh, potential stranded cost for the New York PoolCo could be as much as $25 billion.4 But if Con Edison would bid generation at two times incremental cost, the figure would fall substantially, to (a still enormous) $15 billion. In this case, the market price would rise to $40/Mwh, probably less than the cost of new capacity. With a somewhat more aggressive pricing strategy and a market price of $49/Mwh (probably less than the long-run cost of new gas capacity), stranded cost is reduced to "only" $7.6 billion.
Assuming Con Edison adopts an even more aggressive pricing strategy, our modeling indicates that prices can be maintained at $58/Mwh, which is probably less than the cost of new coal-fired generation. In this case, the stranded cost for the New York PoolCo as a whole goes negative. However, Con Edison would remain the one utility in the state that would still experience a positive stranded cost. Con Edison's stranded cost would fall from nearly $9 billion to "only" about $3 billion. Our results indicate clearly that Con Edison could set the pool price for power, and then mitigate its stranded cost by
bidding supply at far above its marginal production cost.
Mergers (em
From Bad to Worse
Now imagine how the New York PoolCo would work if Con Edison merged with one of the other major suppliers in New York, creating an even greater concentration of market power.
Such concerns emerged in the California proceedings, but PoolCo proponents argued that if all 60 utilities in the western U.S. grid participated, it would be
impossible for any one to dominate the market. However, this view assumes that regulators in other states will want to participate in this experiment and free their low-cost utilities from the existing customer base. Furthermore, like New York, most states and regions have (or soon may have) a few dominant suppliers and transmission constraints that would serve to limit the ability of a PoolCo to function competitively on a regional scale.
If mergers occur on a wide scale, and PoolCo is the primary restructuring model, the consumer benefits of competition may disappear even before industrywide restructuring ever takes place. Mergers may serve to allow some utility cost-cutting, but more significantly, may permit anticompetitive behavior that will be apparent only after the industry is deregulated.
While PoolCo is being proposed as a means to deregulate the utility industry, one should never forget that deregulation without true competition may be far worse than the current system of monopoly regulation. Utility mergers could increase the market dominance of the remaining players and lead to windfall profits under a PoolCo arrangement. t
Randall Falkenberg, vice president of J. Kennedy and Associates, Inc., has a BS and an MS in physics and 17 years' experience in the utility industry. He has appeared as an expert witness in more than 70 utility industry hearings, and written numerous studies examining the economics of power generation and cogeneration projects on behalf of regulators, financial institutions, and industrial power and steam consumers.A Computer SimulationTo simulate a hypothetical New York PoolCo, we examined data from each IOU in the state: load and capacity, plant capacities, capital costs, fuel and O&M expenses, and estimates of outage rates. We also collected comparable information for NUGs and offsystem purchases. As in the California PoolCo model, we assumed that NUG generation was directly assigned. We based all data on 1993 values, as reported in each company's FERC Form 1 filing. Given the limited level of detail, we offer our results primarily for qualitative comparison and for drawing inferences.
Our model reflected conventional production cost simulation. Dispatch of power resources was done on a poolwide basis, and the dispatch priorities were based on bid prices rather than incremental cost. Generation is allocated to power plants based on economic dispatch, probabilistic treatment of full and partial forced outages, maintainance requirements, and any applicable must-run constraints.
Once the dispatch sequence is determined, the overall system pricing is determined. For submarginal (i.e., baseload) units, the average "award price" is simply the probability weighted average (PWA) system incremental bid price of the "marginal" (or cycling) units across all hours in the time period modeled. (This period may be as short as one hour or as long as one year.) For units at the margin, the award price is the PWA of the unit's own bid price for hours when it is the "swing unit," and the PWA of the higher-bid-price units dispatched after it is fully loaded.
For example, if Unit A is the most expensive (highest bid price) unit on the system, its award price, AP(A) is equal to its bid price P(A). This bid price is in effect during the hours of the period when Unit A is dispatched, H(A). If Unit B is the second highest bid price unit, with price P(B), and operated for H(B) hours, then for Unit B the award price is set by Equation 1:Equation No. 1
Award Price for Unit B =
AP(B) = [(H(A) x P(A) + (H(B) - H(A) x P(B)] / H(B)A similar equation is applied for each of the marginal or swing units on the system. Revenues derived from each unit represent simply the product of the award price, AP, and the unit generation, as determined by the production-cost dispatch model.
The model also estimates the stranded cost (SC) for each unit as the difference between the revenues produced by the unit and its conventional revenue requirement, RR, as allowed under current regulatory practices. Typically this result would include fuel, variable and fixed (O&M), taxes, return on investment, depreciation, and decommissioning expenses, if any.
In our model, we assumed that each utility would pursue a pricing strategy to maximize profit margins, and that the initial starting point would price at the incremental production cost (fuel plus variable O&M) for each plant. The modeling allows for pricing strategies set to any multiple of incremental production cost, and could easily be expanded to include reasonable alternative strategies.
1 Re Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation, Decision 95-05-045, R.94-04-032, I.94-04-032, May 24, 1995, 161 PUR4th 217.
2 See, A. Henney, "Electric Restructuring and the California 'MOU', Public Utilities Fortnightly, Oct. 15, 1995, p. 44.
3 It is frequently suggested that gas generation would cost approximately $40/Mwh. However, this figure reflects low gas prices and the ability of qualifying facilities to obtain long-term power contracts. Without low gas prices and such contracts, gas-fired generation would probably cost more, particularly in a high-cost state such as New York.
4 These results are premised upon extrapolation at constant 1993 price and cost levels. In addition, the figures quoted refer to only operational units. Canceled plants or retired units were not included in the analysis, NUG contracts were also excluded because they were directly assigned.
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