Current Status of Electric Industry Regulation

While the competitive bidding process promoted competition for generation markets, it was still subject to the judgment of electric utilities as to how to evaluate the cost impact of purchased power versus utility-owned generation capacity. While subject to regulatory scrutiny, the evaluation process was still somewhat subjective, given all of the nuances associated with the evaluation process.

In many cases, there is still some disagreement about the degree to which capacity value should be included in avoided cost determination. Some utilities reason that so long as they do not need power in the present, the only value of purchased power in the short term is its commodity value. Others reason that NUG capacity is not dependable enough. Non-firm purchases are thus seen as having no capacity value, because the utility must still maintain its own capacity to ensure delivery of power to consumers.

Reliability remains a critical concern. In some cases, contracts are structured with performance incentives, penalties, or takeover provisions to promote delivery performance. While not always the case, capacity value should be treated equally for NUG purchases and DSM programs. Moreover, current data indicates that new NUG cogeneration and combined-cycle plants are every bit as reliable, if not more so, than electric utility-owned plants.

Since most of the newer contracts require NUG plants to be on-line to receive payment, utility rate payers often have better protection than they would with utility-owned plants. NUG plants must be reliable to ensure their own profitability. Also, because most NUG plants are far smaller than most utility-owned plants, overall system reliability is higher because of the diversity of multiple modular plants. Fixed price contracts also protect customers from construction cost overruns and the impact of fuel price escalation.

While today, utilities can determine the long- and short-term value of supply with greater accuracy than in the past, limitations, uncertainties, and controversies remain over factors such as future fuel costs, appropriate values for discount rates, and environmental compliance impacts. For example, when the utility purchases power, the power comes to the utility free of emissions, because the owner of the source is responsible for environmental compliance. However, emissions at the utility's marginal plant are being displaced. This may produce some savings in Clean Air Act Amendment (CAAA) compliance cost or create marketable emissions offset credits. The purchasing utility can sell these credits in the allowance or other emissions trading markets, or use them as internal offsets toward the construction of a future utility-owned plant. While this economic value should be considered in the avoided cost, the utility would have to take some type of emissions restriction on its own generation system. Avoided cost determinations for issues such as these will continue to be controversial. However, growing market competition should diminish such controversies.

Increasing access to transmission services for wheeling purposes means that the local utility is no longer the only real buyer. If another utility has higher avoided costs (in actuality or as a result of different avoided cost calculation techniques), it can compete with the local utility for the power. The local utility still retains an advantage over outside utilities, however, because of the transmission charges necessary for wheeling and, in many cases, the utility's ability to recover costs for its own stranded investment.

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