The Nuclear Regulatory Commission has issued a final policy statement on its intended approach to nuclear plant licensees as the electric industry moves toward greater competition.
later. 3 Numerous parties testified about market power, but none independently suggested that MMIs be formed. Apparently few found it strange that regulators would rely on a watchdog institution proposed by the utilities whose market power was at issue.
The MMIs acquired structures and rules during the lengthy process that fleshed out the PX and ISO. Meetings were open to all, but only the three large utilities could vote on most matters. 4
California got not one but four MMIs-internal and external units at the PX and the ISO. Market power concerns had separated the two institutions, but there was no obvious reason for separating and multiplying their monitors. In particular, it would be harder to detect and evaluate market power that exploited interactions between the PX and ISO. California required that its utilities obtain all of their power through the PX and ISO. 5
In all RTOs except Texas, a day-ahead market (DAM) takes bids and determines hourly PX prices. 6 The RTO then checks security and schedules power from the DAM and bilateral contracts. A real-time market (RTM) prices the differences between planned and actual quantities. California required that those submitting day-ahead schedules commit resources equal to expected demand, fearing that over-reliance on the RTM would bring operating and pricing problems.
There were, however, reasons for buyers to behave otherwise. The supply curve slopes gently upward over normal loads but becomes steep between 35,000 and 40,000 megawatts (MW), where costly peaking capacity must operate. On a certain day, 40,000 MW would normally clear the DAM at $75 per megawatt-hour (MWh), which must be paid to all suppliers. Now assume a large buyer understates its day-ahead demand (underschedules load) by 5,000 MW, intending to make up the shortfall in the RTM. This action cuts the DAM volume to a level of 35,000 MW, where peakers are not necessary, and now it clears at $45. The remaining 5,000 MW are generated by peakers in the RTM, which clears at $75. Instead of paying $3.375 million in the hour, (45,000 X $75), buyers get the same quantity for $1.8 million (DAM) plus $0.375 million (RTM), saving $1.2 million.
Absent the buyer's action arbitrage would roughly equalize the DAM and RTM prices. Buyers that shift load can deny generators the revenue they would have earned in a competitive market. To succeed, however, they must be large enough to affect price, i.e. they must have market power. Buyers' gains could further increase if, as in California, the RTM had a lower price cap than the DAM. FERC's recent Western Market Report described one utility's actions:
PG&E's strategy involved a deliberate attempt to push the Cal PX price below the capped price in the [RTM]. ... [Utilities'] underscheduling violated the California restructuring plan and the anti-gaming provisions of the Cal ISO and Cal PX tariffs. Both of these conclusions are true irrespective of the fact that the California public utilities viewed this practice as a cost minimization strategy. 7
California's monitors understood the operational and price effects of load shifts. 8 Initially they claimed that generators