J. Kevin Fitzsimons for The New York TimesA.E.P. has indicated that it will shut down generators at the Philip Sporn power plant near New Haven, W.Va. But some companies are waiting to see what their competitors will do.

In an article in Friday’s paper, I described how some companies that operate dirty coal-fired power plants are playing chicken as they face a decision on whether to retire them or install expensive scrubbers and filters. They are waiting to see what their neighbors will do as new environmental rules take effect: as with two restaurants in a town that can support only one, if your neighbor goes out of business, more business comes to you, and prices may well rise.

In fact, in the largest grid jurisdiction in North America, the one operated by PJM Interconnection, money comes to plant owners in several different ways. The biggest is selling energy, or kilowatt-hours, and that price varies by time of day. Plants in areas where there is a lot of congestion on the grid and new supplies cannot easily be shipped in will enjoy something close to a monopoly and take in very high revenues on peak summer days.

American Electric Power, a multistate utility based in Columbus, Ohio, has been arguing that if it and its competitors close some big low-cost plants, customers will face abrupt rate increases of 10 to 35 percent. The nature of the PJM market magnifies the importance of losing a cheap generator; all producers get the same payment, equal to the highest-cost generation running, and if a low-cost generator is retired, then the most expensive generator needed to replace it will set a higher price for everyone.

But the consulting firm Bloomberg New Energy Finance identifies a second mechanism by which prices will increase. In PJM and in parallel organizations covering New York, New England, the upper Midwest and California, electric generating stations are selling several services at once, each with its own price.

The simpler thing they sell is electricity, which is priced in units of megawatt-hours. A megawatt-hour, or 1,000 kilowatt-hours, is the amount of energy that a suburban house uses in a month or so. But they also sell capacity: each utility that serves customers has to go into the wholesale market and buy not only energy but the actual availability of generation.

There are few parallels outside the electricity world; it is as if a restaurant charged upfront for a reservation for a table, independent of the price of the food. The way the electric system works, the equivalent in a restaurant would mean paying for a table of adequate size, whether or not everybody showed up.

The capacity market is not only a way to compensate generators; it can also be used to set a value on the services of “demand response” companies. Those are companies that line up electricity customers who agree, in exchange for a payment, to turn off their equipment on peak days.

Companies that serve retail electricity customers must buy as much capacity as the retail customers used in their last peak load day, plus a margin. And this summer, many of the companies had new peak loads.

Eventually electricity customers pay for both the energy and the capacity. The mechanism is intended to compensate generators that sit idle much of the year but are really important on hot days. The price also serves as a signal to companies thinking about building new plants; if it rises high enough, they know it is time to build.

Capacity payments have mostly been low in the last few years because the recession has cut demand for electricity and supply has been high relative to demand in the auctions or individual deals between utilities that serve customers and companies that own generation.

In a research note released late Friday, Bloomberg New Energy Finance said that capacity payments in 2014 and 2015 would reach a level equal to $7 per megawatt-hour of electricity sold — in other words, about $7 on the monthly bill of that suburban house, or seven-tenths of a cent per kilowatt-hour. The national average retail price of a kilowatt-hour is about 10 cents, although in some parts of the Northeast it can be triple that amount.

Higher capacity payments are one of the mechanisms through which surviving electric plants will get the revenue needed for add-on antipollution devices.

Charles Blanchard, an analyst at Bloomberg New Energy Finance and author of the research note, said in an e-mail that capacity payments may reach 25 percent of total revenues as supply is reduced.

For the Independent System Operators, or I.S.O.’s, like PJM, the capacity problem will become more important as fewer generators are coal- or gas-fired power plants, which can be switched on at will to meet peak load, and more are wind or solar, which must be compensated for times it is not sunny or windy.

“This trend is going to continue, as intermittent resources like wind and solar force I.S.O.’s to pay to keep gas-peaking plants online even though they’re not used enough to be profitable based on electricity sales,’’ Mr. Blanchard said in an e-mail.

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