(March 2007) Constellation Energy named Kevin W. Hadlock vice president, investor relations, and Robert L. Gould vice president, corporate communications. Subsidiary...
Transmission Tariffs: Still Pro Forma? Locational Pricing and the Federal Power Act
of power at the two locations will be the same; the transaction will impose no economic cost on the system. If the system is constrained, however, the ISO may be forced to dispatch a higher-cost generator in the consumer's locale to accommodate deliveries under the contract, causing a locational pricing disparity. The difference in price at the two locales (em the higher-cost generator and consumer (em would constitute the transmission cost created by the bilateral contract, requiring compensation.
So long as the parties realize their interest under the bilateral contract and a settlement reimburses the ISO for any costs other than those associated with generation, the CPUC sees no need for the regulator "to take a proactive role in defining these settlement arrangements."4 Nevertheless, the CPUC acknowledges that many market participants will need some degree of certainty about future transmission costs to arrange long-term power transactions. Thus, the commission decrees that the ISO will administer a system of TCCs. The essential features of TCCs are not detailed; the CPUC simply directs the participating utilities to present the FERC with a detailed proposal that adheres to the minimum requirements specified in the Final Policy Decision.
Mechanically, coordination between the ISO, the Power Exchange, and bilateral contracts will work as follows. The Power Exchange will match generation and load bids for the next day, and submit a tentative dispatch schedule to the ISO. Parties to bilateral contracts will also submit their transactions to the ISO, with bids for increments and decrements of nominated inputs or outputs that would be available, if needed, to redispatch the system.
The ISO will determine locational marginal costs, incorporating the cost of generation, losses, and congestion. These locational costs in turn will define the market-clearing prices for the Power Exchange and the price of transmission used for bilateral transactions. The marginal cost of redispatch to provide an incremental load at each location will define the purchase and sales prices through the Power Exchange. The differences in the locational marginal costs between source and destination will define the price of transmission applied to a bilateral transaction.
Every winning generation bidder will receive the market-clearing price at its location. But customers will see only one clearing price, regardless of locale, because the Power Exchange will average the locational clearing prices for customers. Hence, the Power Exchange will collect more from customers (who pay an average price) than it will pay out to generators in the aggregate, based on specific locational prices. The net difference, plus transmission congestion costs paid in by bilateral traders, will be disbursed through the ISO to pay for transmission losses or as congestion payments under TCCs.
If the devil lies in the details, then the CPUC's discussion of transmission pricing and
allocation is a saintly piece of work. However, in supplemental comments5 filed in the FERC's Notice of Proposed Rulemaking (NOPR) on open-access transmission, the PJM companies provide a somewhat clearer view of the details of a pool operation based on transmission congestion contracts.
A Weighted-Average Surrogate
Currently, the PJM companies participate in a power pool