New Customers and Rate Increases

So how do rates adjust over time? Do they always go up?

Electric rates are designed by customer classes (e.g., residential, commercial, industrial, town street lighting, etc) with the regulator, for the investor-owned electric utility, and by the municipal managers for the publicly-owned utility. The rates decided upon (in formal public hearings by state regulatory commissioners, or in public meetings by city or town managers of a publicly-owned utility) must be adequate to cover actual costs. Much is made of the fact that investor-owned utilities have to pay equity investors and repay bondholders out of the rates charged. But few realize that publicly owned utilities also repay their bondholders and typically pay their governmental owners something called “payment in lieu of taxes.” Municipal utilities may also have to supply electric service in public facilities at no cost to their municipality, even though there is an opportunity cost of not selling the electricity to paying customers. For publicly owned utilities, these “in lieu of tax” and free service arrangements are nothing more than an indirect tax to support the operations of municipal government. It is a cost of doing business.

Let us return to the procedure for setting base retail electric rates by state regulatory commissions for investor owned utilities. These rates are adjusted only after formal proceedings before the state regulator. This is not an annual occurrence but at intervals 3 to five to ten years or longer. During those intervals, new investments can be made, frequently with regulatory pre-approval, but the new assets do not affect rates until they are included as a useful utility asset in the next utility rate case. If an area experiences rapid population growth, the utility must expand its distribution grid to supply service as required by its statutory obligation to serve. Of course, there is a cost of building out new electric poles, wires and transformers. The utility will hope to recover certain unique costs in part from the developers (cost causality), in some cases, but also from other ratepayers whenever the next rate case comes around. When rate cases are resisted by state commissions (due to broader policy, utility commitments under price caps, or legislative and state executive politics), it may be years before the costs of all the investments needed can be recovered (“regulatory lag”) from customers in rates. In the interim, the utility’s actual ROE may be less than what the regulators allowed years before when the last rate case was concluded.

Many utilities have limited-term, monthly adjustment clauses to pass though very short term changes in fuel expenses from those used in base rates. These changes are reviewed and approved by regulators on an ad hoc basis. Similarly, extraordinary and hard-to-predict expenses on storm recovery, wildfires, or other catastrophes are often based on ex ante estimates (guesses?) based on a past year’s experience. If the recovery amounts previously approved in rates prove insufficient, utilities may make a limited request for a midyear rate adjustment to recover these disaster recovery expenses. In a following year, it may be the case that the utility requires no midyear adjustment at all, and retail rates remain the same.

Turning now to the rate setting process in a rate case, base utility rates are set by regulators by first estimating the annual revenue requirement. This revenue requirement consists of four annual expense estimates adding up to the Total Annual Revenue Requirement, also called the “Cost of Service”:

$ Operating and maintenance expense (O&M)
+ $ Depreciation
+ $ Taxes
+ $ Return

= $ Total Annual Revenue Requirement , or the “Cost of Service”

 

The O&M expense includes an estimate of the future costs of fuel for power plants, and an estimate of extraordinary costs associated with natural disasters. As mentioned earlier, where these estimates may eventually prove inaccurate, very limited adjustments may be considered in due course. New investment in assets will also begin depreciating once the utility assets put into service, and so will enter the calculation of the annual depreciation expense.

Rates are set for the various customer classes which give the utility an opportunity to recover the four annual expense estimates plus earn a reasonable return. The rate of return discussed ex ante in rate cases is an allowed rate of return, determined to be reasonable if the utility management can run operations well and keep unnecessary expenses to a minimum. However, there is no promise that the electric utility will ever earn the allowed return, and in fact, most often the electric utility has an actual return on equity less than what was allowed in the rate case. Should the utility manage to earn more than the allowed return on equity, there will be hearings called by the regulator to investigate the cause of over-earning and if needed, lower the rates paid by customers.

Additionally, consider that even current customers require new investment when the equipment (poles, wires, transformers, power plants) which served them is retired. Customer rates are not increased when a new meter is installed to replace a faulty old one or when the local distribution system is upgraded due to age or obsolescence. This rate making system seems complicated but in truth it isn’t. It’s just unique.

Thus, investments made for new customers normally will not affect rates for a number of years. The new investment in assets is included on the balance sheet as new “plant in service.” The plant in service account less the accumulated depreciation makes up the majority of the utility’s rate base. The utility rate base multiplied by the annual rate of return (a small decimal value) is the “return” component of the revenue requirement. That “return” includes the interest on debt and return on equity or “profit.”

Please note that at the same time depreciation and return might increase for a particular year, the annual operating and maintenance expense that year could decrease or the annual sales might increase. Either one could offset the new higher return and depreciation requirements. This means that there may be no need for a rate increase, and in some instances, rate decreases might be ordered when better than expected results happen.

To answer our question at the outset, no, rates do not necessarily go up when new customers are added. Regulators can use a “cost causer is cost payer” policy which allocates costs, old and new, to the customer causing the costs, although the utility is obligated to serve that customer. We also mentioned that there are times when a benefit from an investment reaches many ratepayers, not just a single customer, and there be a general rate increase put in place by the state regulatory commission. This is sometimes referred to as “those who benefit from the cost should be allocated the cost” principle. In the “benefit” case there can be controversy when some customers dispute the alleged “benefit” attributed to them.