Proposals for flow-based electricity markets are based on the assumption that there are only a few commercially significant flowgates (CSFs) with fixed capacities and fixed power distribution factors (PDFs) that describe how power flows over individual elements of the system. These assumptions are highly suspect for many reasons, including non-flow (e.g., voltage) constraints that can be more constraining than flow limits, non-linear physical relationships that cause PDFs to change with operating conditions, and the widespread use of equipment (e.g., phase-shifters) specifically designed to change PDFs. But one reason to doubt the basic assumptions of a flow-based market is particularly noteworthy, if only because it is so consistently misunderstood and under-appreciated: the actual operations of an electricity system are constrained, not only by the actual flows on individual network elements, but also by the flows (and voltages, etc.) that would appear under any of many contingencies such as sudden loss of a network element or a critical generating unit.
This note uses a simple example to illustrate the process of contingency-constrained dispatch (CCD), 1 discusses some of the implications for a flowgate/FGR market, and explains why these same problems do not arise in a market based on locational marginal pricing (LMP) and point-to-point financial (or firm) transmission rights (FTRs). It is shown that a flowgate/FGR market on any complex system must have either very many (hundreds of?) abstract, contingent CSFs or only many (scores of?) physical CSFs but each with many (scores of?) contingent capacities and PDFs. The only way to make FGR trading easy and liquid in such a situation is for the RTO to define for trading purposes an artificially simplified and restricted set of CSFs with fixed capacities and PDFs.