|Title||Market Structure and the Predictability of Electricity System Line Flows: An Experimental Analysis|
|Year of Publication||2005|
|Authors||Adilov, Nodir, Thomas Light, Richard Schuler, William Schulze, David Toomey, and Ray Zimmerman|
|Keywords||consortium for electric reliability technology solutions (certs), energy analysis and environmental impacts department|
Robert Thomas has shown, using simulations of experimental results, that the power flow on any line in an electric network is linearly proportional to the total system load when that system is optimally dispatched using accurate generator cost data. By comparison, when offers from generators obtained in a wholesale market that is not perfectly competitive are used to dispatch the system, that relationship between line flow and system load becomes nearly random. These simulations were conducted in a single-sided market environment, however, that is typical of most wholesale market regimes around the world. Here the central dispatcher (ISO, RTO, etc.) accumulates the demand from various buyers and satisfies that load with a least-cost purchase schedule, regardless of price, subject to all of the physical and reliability constraints imposed on the system. If buyers were also able to submit a schedule of bids that are related to price, does the same random relationship between line-flows and system load prevail?
This experimental analysis demonstrates that letting the customers participate fully in the market reestablishes the predictability of line flows as a function of system load. In all of these experiments there are no restrictions on permissible offering behavior by suppliers (e.g. no price caps, prohibitions on withholding capacity or automated mitigation procedures). Two alternative forms of demand side participation are considered: 1) a demand response program (DRP) where customers are alerted to high prices in the subsequent period and are paid a pre-specified amount for each kWh less than their benchmark level of usage for that period, and 2) a real time pricing program (RTP) where customers are given forecasts of prices for each period over the subsequent day and they then pay the actual period-by-period market clearing price. As a benchmark, these experiments with six suppliers and seventeen buyers are also repeated where customers pay an average constant price in all periods (FP); although in all cases sellers receive the market-clearing price in each period. R-squares were greater, variances were smaller and the t-tests on regression coefficients were stronger on the relationship between line-flow and system load for RTP, as compared to the FP system that is commonly used in most electricity markets. DRP was usually somewhere in between. Not only does inducing active customer participation in the market through RTP lead to better system predictability, it also reduces price spikes and leads to greater overall economic efficiency in these markets. It is a winner on both economic and operational grounds.