Fortnightly
Some Thoughts About Load Pockets
Thinking locally, acting hopefully.
March 01, 1998
By Michael Schmidt
THE PEOPLE HAVE spoken. They want choice in power supply in California and in other states. But people are also "load," at least in utility parlance. And some load in some areas can prove awfully difficult to serve. They're called "load pockets."
The Challenge
A load pocket is formed when a deficiency in transmission capacity to a market area cannot be priced away sufficiently to clear the market during peak-load periods. Consequently, the market area must rely on "must-run," local generation units during part of or all of the year. These must run plants will exert market power, regardless of whether they operate under a poolco model (suppliers bid into and customers purchase from a central pool) or a bilateral contracts model (customers and suppliers deal directly with each other).
Examples of significant load pockets include San Diego and Redding, Calif., Consolidated Edison's service area in New York, and Las Vegas (and probably several other places around the country). No matter who owns the plants, either individually or collectively, all or a portion of the load pocket plants must run during the peak-load periods. Whoever owns the plants will have market power.
This market power stems from a choice available to local (load-pocket) generators. They may choose to sell in either of two ways: (1) into a regional spot market, or power pool, or (2) locally, where competition is limited.
Under the California model, the pool price would become the minimum for a load pocket contained within the pool. However, the local generator could extract higher prices by selling its output within the load pocket, since all the needs of the load pocket cannot be served from the pool because of the transmission constraints.
Similarly, if the load pocket were located in a state where bilateral contracts were the rule, the parties to the bilateral contract would be forced to deal with one or more of the area generators to have sufficient capacity to meet load. Local area generators could hold out for the highest bidder. The issue could be even more complicated if customers used up the available transmission on a first-come, first-serve basis. Customers signing up for power after available transmission is taken would be forced to buy all their power from the local generators at market power prices set during load-pocket conditions.
Depending on the severity of the problem, it may prove difficult to predict when load-pocket conditions will occur. Identification may come concurrently, after the fact, or unexpectedly, such as during a forced outage on a transmission line.
The question is, how can consumers who are constrained within the load pocket receive the benefits of competition in spite of this market failure?
A Look at Options
One obvious solution, but not necessarily the cheapest, would have utilities building more transmission. This answer might work for stagnant growth areas or for areas with relatively short periods of constrained conditions. For other areas, however, this option would be prohibitively expensive and inefficient, compared to building more local area generation. The cost of new transmission could wipe out any potential savings from lower power prices.
What about having the local company sell its generation to multiple independent power producers? Theoretically, the IPPs would compete with each other. However, each IPP would soon realize that it could hold out for higher prices. One can always add more IPPs, but the best one could expect to achieve under this scenario is a price equal to the cost of new capacity. That's not all bad, but local problems with siting, air quality and water rights may limit or bar new construction. IPPs may prefer to build in other locations until those markets become saturated.
Here's another idea: Set the price for local generation equal to the pool price (where applicable) plus transmission delivery charges. Some other posted price could also work, such as the California Oregon Border (COB) market price. However, such prices may not cover the costs of the local generation. Also, any linking of the local price to some market index would call for regulatory action, either state, federal or both. And since COB and other market prices could change hourly, this solution would involve ongoing oversight inconsistent with competition.
All of this leaves society still regulating the generators within load pockets. That doesn't look particularly appetizing, keeping in mind that regulation is like salt and pepper \(em a seasoning, not a full meal.
More Regulation?
If we must regulate must-run plants, it may prove more expedient to leave the generation in utility hands. At least the utility is accustomed to it. Investors know what to expect. An IPP might find life more exciting (and profitable) on the outside.
Under regulation, all customers within the load pocket would share the cost of must-run plants during load-pocket conditions. No one customer or group could tie up transmission capacity. But one might expect some political pressure to allocate transmission to the residential class. In fact, there is some precedent for this situation. The Tennessee Valley Authority allocates all of its relatively low-cost hydro to the residential class. Perhaps, in a similar vein, the necessary portion of the transmission system that serves the load pocket could be allocated to the residential class. This solution may offer a greater chance for the residential class to benefit from competition.
The form of the regulated price could be "performance based" or tied to the traditional rate-of-return model, though neither seems destined to withstand the test of time. In this case, let's assume the traditional model wins out.
Recovering the operating costs is easy. Such costs (fuel, primarily) would be recovered dollar for dollar through a fuel adjustment clause, as they are likely to change continually with ups and downs in fuel prices. Adjustments would occur monthly, perhaps with an annual true-up.
Capital and other costs present more of a challenge. In certain conditions, the market-linked generators may be able to recover a portion or all of their capital-related costs, depending on pool or market prices. If the load-pocket generator is reasonably assured of full capital cost recovery through the regulatory process, the consumer may be no better off than under the status quo. That is unacceptable.
What is needed is a process to simulate how the load pocket generators would price their product under competitive conditions. Tying the price to a pool price or a market index could serve as a "floor," but that doesn't guarantee that load-pocket generators recover all costs. If the load-pocket generator cannot recover costs, the plant may close down altogether. In theory at least, outside the load pocket in the open market other plants would take up the slack if one competitor fails. That may not occur in the load pocket, or at least not quickly enough to meet reliability requirements.
A reasonable compromise would simulate what a new cost-effective generating facility would cost \(em both capital and operating. That would likely require a mix of plants. Such a simulation would cover long-run marginal cost, since even in the open market (pool or bilateral) as new capacity is brought on-line market prices likely will follow.
In this way, existing load pocket generating capacity would be reconfigured to simulate the latest generating technology. The capital price associated with such technology would be adjusted annually, continually simulating the long-run marginal costs of providing capacity and energy. Under the plan, regulators must be prepared to allow existing plants to earn market earnings or above if their plants are more efficient or less costly (i.e., depreciated below reproduction cost). Also, under the plan, utilities must be prepared to write-off generation assets that are not market competitive and, depending on regulatory approval, recover such stranded costs through appropriate transition charges.
As with current regulation, this plan is not without risk for load-pocket generators. For one thing, the load pocket might simply go away, leaving the local generator to the whims of the market with capital costs still unrecovered.
Also, regulators might set the allowed rate of return too low for load pocket plants under a "competitive simulation" model.
A Less Complicated (but not simple) Proposal
This problem need not be so serious. From a physical standpoint, as long as the load-pocket plant is running, the load-pocket problem is mitigated. A load-pocket plant need not sell power only to customers within the load pocket. Local generators can sign contracts to sell to customers outside the pocket. Since electrons follow Kirchoff's law, the actual electron flow could diverge completely from the contract path.
Therefore, a utility could spin off or sell its load-pocket generation to IPPs, a separate corporation or a separate subsidiary of the local utility. What is done with the load-pocket generation from an organization or ownership structure is immaterial, because the local generation is not physically required to sell to any customers within the load pocket. Contracts (approved by the regulatory agency) must be in place that require the load-pocket generators to run during periods when the load pocket is short of generating capacity. This operating mode is sometimes referred to as counter-scheduling.
This model would require limited regulation; oversight extends only to the contract prices charged by the local generators to be available to run during periods when the load pocket is transmission constrained. Such contract prices would likely be reasonable, since the load-pocket generators would have the freedom to be out earning their revenue in the open market, just like every other supplier. This arrangement would leave the customer no worse off than buying from the open market and paying wheeling charges to get the power to the point of consumption. In addition, load-pocket generation could be allowed to sell to marketers or aggregators within the load pocket during periods of system emergencies (i.e., during transmission line forced outages). The price for such emergency service also would fall under FERC regulation.
Critics may cite reliability issues inherent in counter-scheduling. At this point, I can only agree with them. But naysayers have always expressed such concerns in telephone, gas and early attempts at electric deregulation. Perhaps any reliability concerns can go by the wayside as did early concerns over "loop flow." One can only hope.
Free of the load pocket constraint, consumers would gain access to the competitive power markets. Free of regulation, load pocket generators would learn to enjoy the discipline of the market. The load pocket problem would be solved.
Michael Schmidt is interim director of pricing and economic analysis at Nevada Power Co. and adjunct professor at the University of Phoenix.
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