output to franchised utilities. In some states, the terms of purchase were so attractive that development of QF capacity overwhelmed expectations. In response, utilities and regulators sought mechanisms to ration the supply efficiently. The result was a competitive bidding process for long term power sales contracts. This mechanism has proved to be sufficiently flexible and attractive to both buyers and sellers, that it has been broadened to include a new classes of suppliers; first, Independent Power Producers (IPPs), more recently Exempt Wholesale Generators (EWGs). Together these new entrants are expected to sustain a significant share of the market for new generating capacity. In this part we describe the background and development of the private power industry and characterize its current state.

### I I. The Public Utilities Regulatory Policies Act of 1978

PURPA opened the door to competitively supplied power in the U.S., but with considerable restrictions. Under PURPA, a Qualifying Facility could have production capacity of no more than 50 Megawatts, unless it used either renewable fuels or cogeneration, the combined production of useful heat and power in a single process. Although PURPA legislation set a general framework for QF development, implementation was delegated to state regulatory commissions. FERC was mandated to write rules that state commissions had to follow in their deliberations. The two irreducible requirements of the legislation and FERC rules were the obligation placed upon utilities to purchase QF output, and the avoided cost concept as the guide to determining the purchase price. In this section we review these issues.

The primary obligation PURPA placed on utilities was the requirement to purchase QF output. Absent such an obligation, private suppliers had little or no bargaining power with the utility. Prior to PURPA, some utilities did purchase a minor amount of private power, principally from industrial self-generators selling excess production. PURPA required that all utilities create a tariff under which they would purchase from QFs (tariffs were also required for back-up and related services from the utility). The FERC rules also allowed for long term purchase contracts between utilities and QFs, but did not require these.

In practice, the difference between tariff and contract turned out to be decisive. Private investors were reluctant to support projects whose revenue was based on revisable tariffs. Because many projects were financed on a “stand-alone” basis, long term pricing certainty was necessary to support the project’s credit (Kahn, Ch.6, 1988). In states where regulators were sympathetic to QF development, utilities were encouraged or required to make available long term contracts. These contracts typically had standard language which defined mutual relationships explicitly, or at least substantially narrowed the room for negotiation. The availability of standard contracts frequently made all the difference with regard to development. For example, the staff of the New Jersey Board of Public Utilities found that when tariffs only were offered, the response was minimal. When long term contracts were offered, the response was substantial (NJBPU, 1986).

The need for long term contracts to stimulate investment in private power is probably due in part to the immobility of generating assets. The obligation to purchase is limited to the utility