Above: Hinkley Point C is one of the new reactor projects underway backed by long-term power purchase agreements


by providing open access to electric transmission lines and establishing the independent system operators (ISO), thus creating an ‘arms-length’ separation between the operation of the transmission grid and its owners. Arising from this string of legal and regulatory changes


was a restructured electricity market serving approximately two-thirds of the US market. Here, electric utilities were required to divest their regulated electric generating assets, and electric plants are now developed, owned, and operated by non-utility independent power producers (IPPs). No longer are there regulated monopolies for the generation of electricity. There are competitive wholesale and retail electricity markets, and retail customers are free to choose their electric suppliers the same as they choose cell-phone carriers. These IPPs sell their electricity into the wholesale electric grid as a commodity using prices provided by each IPP to the ISO on a daily basis. Cost-of-service regulations are not available to these IPPs. They survive, or not, on their ability to make a return on investment in a competitive market – the same as other competitive businesses such as automotive manufacturing, oil and gas, pharmaceuticals, and food products. The goal of engineering economists several decades


ago to deregulate and restructure the electricity generation market, and bring economic efficiencies through competition, has largely succeeded. Numerous studies have shown that deregulation led to increases in operating performance and plant efficiency, as well as lower electricity prices for customers. However, deregulation also shifted some risks away from electric ratepayers and toward power plant investors. There are multiple types of risk which affect the construction and operation of a power plant, and it is the shifting of revenue risk and how this risk affects different types of power plants differently that is a key to private sector investment in power generation.


Changes in dispatch risk It is well established that the economics of a high fixed cost/low variable cost technology such as nuclear power improve at higher capacity factors, typically represented as the baseload segment of the market. Capacity factors of 90%+ are considered the critical range of operation if nuclear power is to be cost-competitive vis-à-vis competing technologies, and this characteristic has important financing implications. In other words, it is important to maintain a high output quantity (Q) to keep average fixed costs (AFC) down because nuclear plant fixed costs are high relative to its variable costs. Thus, by operating as a baseload unit, the high fixed costs of a nuclear plant can be


allocated over a greater quantity of kWh to minimise AFC, which in turn, minimises the plant’s average total electric costs.


Thus, it is economics, not physics, that restricts nuclear


plants from being dispatchable (changing Q during the course of a day to meet changes in electric demand) as this would lower Q and, in turn, increase AFC. The nuclear plant would have insufficient cash flow to meet its debt and equity obligations. This economic principle that nuclear plants should not be dispatchable also applies to any of the proposed advanced nuclear plant designs. These new designs do not alter the high fixed cost/low variable cost relationship that is inherent to nuclear power, and it is this relationship that dictates whether a power plant economically operates as a baseload, intermediate, or peaking unit. The new designs do not alter the economic issue at the center of our analysis with its important financing implication that nuclear plants require baseload operation. The conundrum, whether analysing existing nuclear plant


technology or a proposed advanced modular design, is that the daily quoted price (P) of the electricity supplied by the owner of the plant to the ISO must remain low enough to ensure that the plant will be dispatched by the ISO in order to sell a high quantity (Q) of the plant’s output, and thus be a baseload unit, yet the total revenue (TR = P x Q) must be large enough to cover all costs, including the plant’s high capital costs. This is a tight operating window, and the nuclear plant must be able to satisfy this constraint over the plant’s life, despite changes in competing technologies, regulations, and customer demand in order to attract financing. The debt and equity financiers of the nuclear plant seek to have this operating risk minimised because the tight operating window leaves little cushion to absorb the effects of other long-term revenue risks. Prior to deregulation, nuclear plant owners were able


to eliminate this dispatch risk by designating each nuclear plant as “must run”. Today, under deregulation, this ability no longer exists because the dispatch sequence is determined by the ISO and not by the owner of the power plant.


Changes in price and output quantity risks Lenders and equity investors have concerns about long- term price certainty for all types of power plants, not just nuclear. The concern is that the power plant will remain capable over the long term of selling its output at a price that is high enough to cover its costs. Adding to this concern is the possible emergence of any new, competing


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