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Transmission Tariffs: Still Pro Forma? Locational Pricing and the Federal Power Act

Fortnightly Magazine - May 1 1996

Two power pools (em one existing, the other inchoate (em have announced that they will file tariffs to price electric transmission as the difference in spot prices in the generation and consuming markets. Revenues in excess of embedded costs would be distributed to the holders of firm transmission rights through "transmission congestion contracts" (TCCs).

"Locational pricing" and TCCs may achieve pristine economic efficiency in the generation and delivery of power. However, these concepts lie outside of "cost basis" in the traditional sense; they imply the virtual deregulation of transmission pricing.

While the Federal Energy Regulatory Commission (FERC) has encouraged "innovative"

transmission pricing proposals,1 particularly from pools, it nevertheless clings to the anchor of cost-based rates as historically adopted under the aegis of the Federal Power Act (FPA). In the past, when economic efficiency and the "just and reasonable" standard met, economic efficiency was generally lost. Will the FERC's recent embrace of competitive principles win the new day?

Locational pricing and TCCs lie central to the plans of new competitive power pools proposed by the California Public Utilities Commission (CPUC) and the Pennsylvania-New Jersey-Maryland Interconnection (PJM). These ideas will pose a challenge to the traditional utility ratemaking principles employed by the FERC under the "just and reasonable" standard of the FPA.

California: Comparing Prices

at Source and Load

The California commission did not address the allocation or pricing of transmission capacity in its May 1995 proposed decision2 on electric restructuring, because all electric generation and transmission assets would have been placed under the control of an independent system operator (ISO). Under that scenario, participants would purchase electricity only from a power pool; the price of power would reflect the bundled cost of generation and transmission.

But in its latest order, the Final Policy Decision3, the CPUC accepted a hybrid structure. Utilities will sell into and purchase from the Pool, but bilateral transactions will also be accommodated. The change is significant: the CPUC must now integrate power deliveries under the Pool and bilateral contracts; it also must allocate and price transmission services.

To accommodate this hybrid structure embracing a spot market for energy and direct bilateral sales contracts, the CPUC divided the formerly monolithic structure of the ISO into two distinct entities: The ISO and the Power Exchange. The ISO retains responsibility for grid operation and economic dispatch of generation resources. The Power Exchange will supervise the matching of power supply and demand bids. As the CPUC notes, bilateral contracts do not control the actual physics of the generation, transmission, and distribution that deliver the product the buyer consumes. Yet a dispatch nomination originating from a bilateral

contract places a burden upon the transmission grid, creating a liability for the cost incurred.

These costs, however, will not simply reflect the aggregate embedded cost of each transmission segment lying between the generator and a consumer. Instead, the ISO, in effect, will sell the generator's power to a different load located nearby, and instead serve the consumer with a purchase from a generator located nearer the consumer. In the absence of transmission constraints, the marginal cost

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