As the debate over restructuring the U.S. electricity industry moves forward, there comes a host of new theoretical models. Two proposals in particular serve well to frame the debate.
The Utah Test
Defining a test period to overcome controversies and inaccuracies.
developed. The process of developing forecast standards likely will continue over several rate-case cycles covering several years before many of these issues become settled.
Accountability relates to what happens if the forecast in the previous rate case is materially different from what actually occurred. For example, suppose a regulated company predicted that it would have $100 million in capital expenditures, and this amount was placed into rate base in the forecast test year. What if it turned out that capital expenditures were only $80 million, but a year later the utility files a new rate case forecasting that it will need $150 million in capital expenditure recovery? Does the PSC discount the new request by 20 percent? What if the utility had forecast that in a given year it was going to issue $100 million in debt at 7-percent interest, but instead issues $50 million at 6-percent interest? In these two scenarios, should the utility automatically be required to file for a rate reduction? If so, how soon should it be required to file? What criteria will separate the need to file from situations that aren’t material enough to require filing?
What if the utility under-forecasts various items? That is, if as suggested above, the utility must file for rate reductions if it over-collects on significant items, should the utility be allowed to file for quick rate relief if its forecasts are significantly wrong in the other direction? Some intervenors would argue no, because the utility’s greater knowledge of its cost and markets already gives it an advantage over regulators and intervenors. This proposed asymmetry of treatment would require the utility to accept the risk of forecasting too low, but give up the benefit of forecasting too high.
Should updates be allowed during the rate-case proceeding, and if so, should a statutory time clock governing the length of a rate case restart? 6 Does the PSC develop various adjustment mechanisms to account for missed forecasts, as often is done with fuel purchases? What does this do to company incentives to manage costs to be as low as prudently possible?
These are some of the questions that regulators, utilities and intervenors have grappled with. Some of these issues are a kind of mirror image of the regulatory lag issues raised with historical test periods. Instead of a lag, the regulators might accept forecasts of some, perhaps major, elements that are significantly too high. Alternatively, fearing that the forecasts are too high, regulators might order much lower-than-requested cost recovery that might leave the utility no better, or perhaps, worse off, under a forecast test period than it was with a historical test period.
Process problems typically are of three kinds. If there are delays in determination of the forecast test period, then the utility and the intervenors may be disadvantaged as they work off of a different test period than was finally decided. This can be a significant problem in Utah given that the PSC has 240 days to decide the rate case after it’s filed. If the first 60 or 90