John Ferguson, CDP, comments on Joe Rosebrock’s article in April issue and Mr. Rosebrock responds.
Depreciation Shell Game
Accounting reforms might force regulators to abandon their live-now, pay-later practices.
most common action for nuclear units was retirement—usually well prior to the 40 years allowed by their operating licenses—and today the most common action is to recondition through operating license renewal.
Regulation frequently responds to these actions in ways that defer recording and recovery of depreciation costs, generally to minimize the immediate effect on electricity tariffs. Deferral reduces near-term revenue requirements, which makes rate-case decisions appear more palatable to electricity customers. Unfortunately, the regulatory process tends to obscure the total revenue requirements resulting from depreciation deferral over the life of the assets. In addition to increased life-span costs, depreciation deferral—and its potential eventually to become denial—creates risks that increase the utility’s cost of capital, further increasing costs imposed on ratepayers.
The accounting implication is a consequence of deferral mechanisms causing regulatory accounting to be in conflict with the financial accounting dictated by GAAP. The cost implication is a consequence of the way depreciation affects the utility’s balance sheet. Annual depreciation expenses are a positive component of revenue requirements, and annual expenses accumulated in the book reserve are a negative component. The typically long life of energy and water utility assets causes the negative component to eventually overwhelm the positive component, which means the apparently beneficial initial ratepayer impact of any depreciation change will reverse itself within a few years.
The determination of depreciation rates is essentially an effort to predict the future, commonly by analyzing past experience. But such analyses for power plants are unlikely to provide a reasonable indication of the future, unless the company has retired at least one station with unit life spans similar to those expected for the remaining units. Nevertheless, power plant depreciation rates frequently are based on predicted retirement dates.
Forty years ago, the typical generation planning horizon was about five years, which required utility planners to conduct special studies to predict the retirement dates needed for depreciation purposes. This horizon since has expanded substantially and many planners now incorporate retirement date predictions in their regular activities, thereby eliminating the need for special studies for depreciation purposes. Even when special studies were needed, station operators commonly predicted retirement dates to determine whether large capital expenditures or maintenance projects are justified. Whether predicted by planners or by operators, the resulting retirement dates provide a suitable basis for determining depreciation rates, but are sometimes rejected by regulators and replaced with longer lives based on industry data not demonstrated as being comparable—initially due to a lack of station retirement experience and more recently due to life spans being extended through reconditioning.
For example, Missouri regulators 2 don’t accept depreciation rates based on predicted retirement dates for steam plants, but they do for nuclear units. Consequently, steam-plant depreciation rates are based on analyses of past experience. Lacking sufficient experience with station retirements leads to rates that presume unit life spans that are unrealistically long. For example, one Missouri case authorizes depreciation rates for turbogenerator units that assume life spans of 120 and 200 years. 3
While it’s not unusual to encounter steam plant equipment more than 100 years