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PJM's New Game

If transmission can substitute for gen-plant capacity, why not clear both products in the same auction?

Fortnightly Magazine - December 2005
  • right, able to compete against power-plant capacity.

Now consider what these differences could mean in practice.

Under traditional ICAP and LICAP constructs, suppliers don’t submit actual bids. The “price,” as it were, is a benchmark, not an equilibrium point between willing buyers and sellers. It denotes a deficiency charge that LSEs must pay to the ISO (for reallocation to suppliers) if they fall short of the capacity reserve mandated by passive reliability standards, or by planning mandates imposed by state regulators.

In practice, the benchmark creates a default price floor for bilateral capacity trading, which goes on daily, weekly, and monthly, since capacity-short LSEs presumably would be willing always to buy capacity privately at the benchmark level or higher, at least to avoid assessment of the deficiency charge.

By contrast, under PJM’s proposed RPM plan, the RTO can force LSEs to buy more capacity than would be warranted by the nominal reliability standard. That occurs because the RPM plan sets the reserve requirement by inviting suppliers and LSEs to bid, and then committing them to the price and quantity that clears the auction. In short, it is bidding behavior—not a passive set of reliability standards—that dictates the required amount of installed reserve margin.

In a position paper submitted in PJM stakeholder discussions back in February, AEP said PJM’s RPM model would penalize vertically integrated utilities that own generation and provide their own supplies and reserves. According to AEP, LSEs might have to purchase a different mix of capacity in the auction process than has been approved by state regulators in the state’s process for integrated resource planning:

“If the supply curve from the auction intersects the demand curve at 20 percent, then the LSE will be required to purchase enough capacity to meet a 20 percent reserve margin, even though the IRM could be set at 15 percent.

“If AEP, through the IRP process, has long-term capacity acquisition plans designed to meet 13 percent, or even 16 percent … it must purchase at least 4 percent more capacity (if the auction clears at 20 percent) than has been found to be reasonable in ECAR.

“For a vertically integrated, self-supplying utility such as AEP, which has constructed its own generation to meet IRP plans, it means that the company must actually pay out additional funds to meet the PJM auction.”

(Of course, as a supplier bidding into the RPM capacity market, AEP eventually would be entitled to an allocation of revenues covering those same capacity costs, by the time of the delivery year at the end of the four-year resource commitment period. But revenues might not quite cover costs, depending on results in intervening auctions during the four years.)

Recurring Issues

Consider this small sample of some of the most difficult issues posed by PJM’s RPM construct.

• Too Few Zones. PJM’s phase-in plan calls for two large LDAs during the first year (6/1/06 to 5/31/07), then four LDAs in year two. Critics say that will socialize costs by allocating “locational price adders” (LPAs—the constraint premium) over too broad an area in early