The electric utility industry as it has operated over the past 70 years is changing. Historically, most of the industry has been vertically integrated, meaning that one company provided electric services from generation to transmission to distribution to customer service. It has been widely argued that the generation portion is not a natural monopoly and should be separated from the other functions of electric service. Generation would then become a competitive market from which distribution companies, or even retail customers, would purchase their requirements. Transmission would be controlled by a separately-regulated Independent System Operator (ISO). This would help to maintain reliability of the system and avoid the problems of market power in which a company could use its transmission lines to limit competition for generation and increase its prices. The purpose of this paper is to examine the calculations used to evaluate transformer costs and how they may be affected by the restructuring of the industry.
RESTRUCTURING—THE MARKET AS A WHOLE
Although generation will become deregulated, distribution of electricity will continue to be a regulated business. It is a natural monopoly in that it is most cost-effective to have a single set of distribution lines for a given region, rather than multiple companies each having electric wires to ultimate consumers. Because of the deintegration of the industry, the distribution business will look more like current distribution-only utilities. Currently, roughly 14% of the country is served by distribution utilities that have no generation of their own4. These companies sign long-term supply contracts with either nearby investor-owned generating utilities or public power suppliers such as TVA. Their costs are based on the terms of these contracts rather than the cost of specific generating plants. Most of these distribution companies are either publicly owned cooperatives or municipal utilities.
In the future, retail customers may have contracts with different generation providers at different prices. Distribution companies will bill consumers for the use of their wires; these bills will include the costs of losses. Customers could pay for the losses by either having their generation supplier provide extra power, or simply pay the distribution company to procure the power.
In this environment, utilities will continue to need to purchase transformers. The purpose of this paper is to examine the calculations used to evaluate transformer costs and how they may be affected by the restructuring of the industry. Section 2 describes what the transformer costs are, section 3 describes the equation used for comparing the total operating costs (TOC) of different transformers with an emphasis on those parameters most likely to change by restructuring, section 4 discusses the incentives for companies to purchase efficient transformers, and section 5 is a summary.
Distribution Transformer Losses
Measurement of Losses
There are two types of losses associated with transformers: core losses (also called no-load losses) and load losses. Core losses occur at a constant value all the time that the transformer is energized. They are due to the resistance of Load losses resistance which vary as a square of the energy flow across the transformer. Consequently, they will be much higher proportionately during peak loads than during off-peak times.3,5,7
A distribution utility does not specifically measure its transformer losses. Instead, it meters how much electricity enters and exits its system. The difference in the amount measured is due to a combination of line losses, transformer losses, internal use by the utility, and unmetered theft. Some large transformers may have measurements taken around them that allow the losses to be calculated, but for the most part, utilities rely on the manufacturers’ specifications to determine transformer losses. Unless the power flow through the transformer as a function of time is measured, the actual losses can only be estimated.