On May 31, 1995, the Federal Energy Regulatory Commission (FERC) issued its Statement of Policy in Docket No. PL94-4-000, Pricing Policy for New and Existing Facilities Constructed by Interstate...
A West Coast View: The Case for Flow-Based Access Fees
Divide the grid by usage (em local vs. regional. Apportion costs accordingly, to energy customers by fixed charge, and power producers by flow and distance.
Traditionally, utilities have received transmission costs through an average, rolled-in access fee, or postage-stamp approach. In a deregulated environment, that approach will lead to distorted pricing.
And not just because of transmission-line congestion.
Much of the current debate over electric transmission pricing has centered on the various competing methods of congestion pricing, such as zonal vs. nodal pricing, or financial vs. physical rights. Meanwhile, a related problem receives scant attention. Simply put, congestion pricing will not collect enough revenues to fully recover the revenue requirement associated with transmission-line assets.
To recover the full revenue requirement of a transmission plant, any congestion-pricing regime should include two separate access charges. Retail consumers would pay the first charge, a flat, postage-stamp fee to recover local transmission system costs. The second charge, a regional access fee reflecting transmission usage based on flow and distance, would be assessed to all power producers that use the grid. In effect, this two-part fee divides the transmission grid into two segments: 1) Low-voltage lines that serve a local function, and 2) High-voltage lines that serve regional needs.
The logic behind this proposal rests on both engineering and economic rationales. By assigning separate, mutually exclusive access fees to end users and power suppliers, the grid will send correct, long-run pricing signals for siting generation. In this way, the electric transmission price will really consist of a combination of three competing pricing methods: 1) short-term congestion pricing, 2) long-term, postage-stamp pricing for local service, and 3) long-term flow- and distance-based pricing for regional use.
Generation vs. Load: The Myth of Common Costs
Many proposed methods of pricing electric transmission concentrate on optimizing use of the existing system and providing incentives to build new transmission facilities. These methods, however, rely on the principle of setting price equal to short-run marginal cost. %n1%n In fact, the marginal cost of transmission operation is usually zero or close to zero. %n2%n Thus, marginal-cost pricing will not lead to the full recovery of initial investments in transmission. Many authors note this fact, recommending an additional fixed charge to correct this revenue deficiency. %n3%n
How should this fixed charge be designed?
First of all, the fixed-charge component, the access fee, should be large enough to recover embedded costs of transmission, but not so large as to discourage access to end users or generators. Clearly, the collection of sunk costs should not distort operational decisions. However, this idea should not warrant abdication of the principle of cost responsibility according to cost causation. %n4%n Each set of customers should face the full cost of supplying its product.
In the past, under vertical integration, the utility planner had access to costs for both transmission and generation. To meet expected load growth, electric system planners would weigh the benefits and costs of additional resources in generation versus transmission. New plant construction could offset transmission upgrades, and vice versa. Rolled-in, bundled rates were assessed to all customers to