Author: Frank Swigonski, Director, Market Design

In the mid-nineties, FERC issued a landmark order, Order No. 888, that directed public utilities to remove impediments that blocked independent power producers from accessing utility-owned transmission facilities. In Order No. 888, FERC directed transmission-owning utilities to “unbundle” their wholesale rates and establish separate rates for the supply of energy and transmission service. In addition, FERC recognized that the transmission system needed certain additional services, called ancillary services that support the quality of the power flowing on the grid and are necessary for the grid to function properly. Among these ancillary services, FERC included reactive power. FERC left it up to each utility to decide whether it wanted to establish a separate rate for reactive power.

One of the first to propose such a rate, American Electric Power Service Corporation (AEP), devised a methodology to estimate the cost of providing reactive power and establish a cost-of-service rate for reactive power service. The AEP methodology, as it became known, catalogues each component of a generator and isolates the portion of those components that plays a role in providing reactive power. This allows the AEP methodology to estimate how much of a generator’s overall costs are attributable to reactive power as opposed to real power.

It is important to note that not all utilities provide cost-based compensation for reactive power in their service territory. Some utilities opted to provide no compensation for the service (e.g., California Independent System Operator, Inc.) while others opted for a flat rate (e.g., New York Independent System Operator, Inc.). FERC has permitted this disparate treatment so long as it meets what has come to be known as FERC’s “comparability policy,” which states that utilities must treat their own affiliated generators in the same way as non-affiliated, independent generators.  Thus, if a utility compensates its own generation fleet for reactive power, then it must also compensate independent generators for the service. In areas where the utility provides cost-based compensation, each individual generator makes a filing at FERC proposing an annual revenue requirement for its generator based on its reactive costs as determined AEP plus an allowable return. Once an annual revenue requirement is determined, the utility will collect a charge from its transmission customers and pay the generator. The utility will then pay the generator a monthly fixed payment for the entire life of the asset.