[BETA] Fortnightly

 

Why power plants should pay for grid upgrades.

Do we make all generators equal- using affirmative action to give rights to merchants that are "comparable" to utility-owned plants?

Or, do we let the locational price signals shine through-trusting all plant developers, whether regulated or not, to act in self-interest?

These questions capture the choice now pending before the Federal Energy Regulatory Commission (FERC) in its rulemaking case on generation interconnection, ¹ as FERC ponders who should pay for expanding the transmission grid to accommodate new power plant projects.

The Problem

Let's look at a simple example that compares variable operating costs between two power plants located in different states.

One developer builds a gas-fired, combined-cycle power plant in Southern California. A second developer builds a plant in Arizona. In operational terms, the two plants are similar. Both projects have similar characteristics: minimum up/down time, forced outage rates, maintenance rate, capacity, and heat rate. They both have identical fuel prices, as they are both tied to the same gas transmission pipeline.

Nevertheless, the two plants differ significantly in actual performance, if we compare the two on the basis of unit dispatch and variable costs (ignore capital cost recovery and emission constraints). ²

Consider capacity factor-the degree to which each plant is used. In our example, for 2003, the Southern California project will show a capacity factor of 80 percent, while the Arizona project comes in lower at 42 percent. ³ For 2004, the two projects post capacity factors of 78.4 percent and 40.6 percent, respectively. By contrast, a re-power project located in the Los Angeles basin, which pays an additional intrastate gas transportation fee of about four mils per kWh ($4 per MWh), but has lower capital costs, will post a capacity factor of 63.3 percent. Why the difference in utilization?

The reasons for the difference in capacity factors between the Arizona and the California projects stem from transmission constraints into Southern California and the additional transmission losses (three to six percent, on average) associated with wheeling energy from Arizona to California. Bottom line: The Arizona unit is not making its expected rate of return.

Viewed another way, this example shows that congestion costs and losses provide short-run locational signals that new generation should locate in California. Yet that is not the case.

Despite this obvious price signal, more new generators are expected to continue to come online in the Arizona region, increasing congestion. At the same time, the gap in capacity factors between these locations is expected to widen.

Why would generators continue to build in a constrained area that is relatively far from the load, and when the plant loses money?

In our case, the answer must lie not with variable costs, but with fixed costs. From the perspective of the power plant developers, the fixed costs (land, environmental mitigation, permitting) must be lower in Arizona. But this focus is too narrow. It ignores another important locational factor-namely, the long-run marginal costs. By siting their plants in Arizona, far from load, the developers ignore the long-run costs of transmission network