Power Cost Filings Get More Difficult
Posted on June 2, 2016 by Bob Jenks
Tags, Energy
A number of years ago, the PUC began allowing electric utilities to update variable power costs like fuel for power plants, and wholesale power prices. However, over time, those cases have become more complicated and utilities are now adding costs that were never contemplated in the originating cases.
Background:
About 17 years ago, Oregon passed a law that allowed large industrial customers to get deregulated electric service. This means they could buy their electricity from someone other than the utility and have the utility deliver the power over its transmission lines to the industrial customer. In order to ensure that residential and small commercial customers were not subsidizing these industrial customers, the industrial customers are required to pay transition charges to account for the utility investments that were made on their behalf.
In order to do this the utilities asked to be able to update power costs annually, so that they could base those transition charges on the most up-to-date information possible. As a bit of an afterthought, they also proposed that they be allowed to apply those updated power costs to residential and small customers. Thus, we got annual power cost cases. These cases are shorter than normal general rate cases and are supposed to be much more straightforward.
Originally, power cost cases were limited to net variable power costs – things like the fuel that runs power plants, and the power they buy and sell on the market to balance their system. However, utilities have increasingly been trying to expand these annual rate cases to include items that were never supposed to be part of the mechanism and are not variable power costs.
Last year Pacific Power successfully got permission to add a cost to compensate for any market purchases that the company has made over the last three years but were not forecasted. This means that if there are poor hydro conditions one year and Pacific Power has to make additional wholesale power purchases, each year for the next three years, there will be an adjustment to flow through a portion of these unanticipated market purchases. CUB believes this is unfair, because there is a separate regulatory mechanism, the Power Cost Adjustment Mechanism (PCAM) that allows the utility to recover some costs associated with a bad water year – though the utility is required to absorb some costs before asking the customers for more money.
This year, PGE is proposing to add a 30-year capital investment in natural gas reserves and extraction. Rather than purchase fuel from one of the many natural gas sellers, PGE wants to buy into the gas fields and extract the gas. This is a large investment, comparable to building a new power plant. It requires a prudence review to determine whether that is the right investment over the next 30 years. Other large capital investments are reviewed first in an Integrated Resource Plan and then are examined in a General Rate Case. Taking a similar investment and running it through a much shorter annual power cost case is unprecedented.
Finally, in Idaho Power’s annual power cost case, they proposed changing the way some of the costs are forecast related to two coal plants they share with a Nevada utility. In examining this issue CUB realized that the costs in question relate to the Nevada utility’s use of the coal plant, not Idaho Power’s. CUB is concerned that the operating agreement between the two utilities may require that Idaho Power customers subsidize customers of another utility. CUB did successfully get these costs removed from Idaho Power’s forecast.
CUB is pushing back. If we are going to have shorter annual rate cases for a set of costs that are considered more “straightforward,” then Oregon needs to limit the utilities’ ability to expand these annual cases to include things that are clearly anything but straightforward.
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12/27/16 | 0 Comments | Power Cost Filings Get More Difficult