Cost-of-service ratemaking sets rates based on forecasted costs of providing service plus a “reasonable” rate of return on the equity invested by shareholders to build the capital facilities necessary to provide service. This form of ratemaking can be broken down into the following key steps:
Determining the authorized rate of return
The first step is a determination of the utility’s authorized rate of return. This is set by the regulatory commission, sometimes as part of the rate case and other times in a separate proceeding called a cost of capital proceeding. The regulator looks at the current investment marketplace and determines how much return investors must be offered to ensure they invest in utility stocks or debt as opposed to other investment opportunities. Separate rates of return will be set for utility debt and for equity, which is the money invested by stockholders. The utility’s return on equity is set such that it is similar to returns investors would receive on alternative investments with similar risk profiles. The two rates, weighted by the amount of debt and the amount of equity, are used to determine the overall authorized rate of return (this is also called return on investment).
Forecasting usage
The second step is to forecast how much gas or electricity customers will need over the rate case period. This information is important because it will determine the amount of capital and expense dollars that will be required to provide reliable service and the revenue that the utility will collect. Forecasts are made using historical usage data, expected growth or decline in population, and business activities and other societal trends. The forecast will be broken down by customer class so that costs and revenues can be determined on a per-class basis.
Determining a revenue requirement
A revenue requirement is defined as the total amount of money a utility must collect from customers to pay all its costs, including its return on investment. A utility’s revenue requirement is determined by forecasting expenses (operating and maintenance, administrative and general, fuel costs for power generation, taxes, and depreciation) and then adding to that the return on rate base plus any amounts (positive or negative) outstanding in balancing accounts. Forecasts are typically based on a 12-month period called a test year (TY). The rate base is the depreciated value of all the capital facilities the utility has constructed in order to provide services to its customers. The return on equity multiplied by the portion of rate base financed through shareholder investment (equity rate base) is the primary component of profit for a monopoly utility.
Potential shareholder profit =
Equity rate base x Authorized return on equity
A balancing account is an accounting mechanism that keeps track of the difference between projected expenses and actual expenses or projected revenues and actual revenues. Any differences covered by the balancing account are added to or subtracted from future revenue requirements, thus insulating the utility and its customers from risks of revenue deviations. Typical portions of the revenue requirement covered by balancing accounts include fuel costs and revenue fluctuations due to energy use that differs from the forecast for utilities with revenue decoupling.
Allocating revenue to customer classes
Once an overall revenue requirement for a utility service is established, it must then be determined what portion will be paid by each class of customer. This process is called revenue allocation. Various allocation methods are used in different situations. The most simple method (equal cents per kWh) allocates costs based on usage. While simple, this approach is not necessarily an accurate way of assigning costs. Since many of the costs of a gas or electric system are fixed, actual costs caused by customers are more likely to be based on the maximum demand that a customer puts on the system and not on the amount of kWh or therms used. Thus, a more common — though more complex — method is to allocate costs based on the estimated cost of service to each customer category (cost-of-service). This allocation can take into account demand-based costs as well as usage-based costs. An even more complex method (equal proportionate marginal costs or EPMC) allocates costs based on the marginal cost of serving each customer category. The marginal cost methodology looks at the cost of serving one additional increment in each class rather than using the average cost as is done in the cost-of-service methodology. Actual determination of revenue allocation can be complex and is commonly one of the most highly contested issues in regulatory proceedings.
Determining rate design
Once a revenue requirement has been determined and allocated to the various customer classes, the rates that each customer class will pay are determined in the rate design phase of the proceeding. But before actual rates can be set, the rate structure must be determined. Rates are structured in any number of ways, but typically they are divided into three distinct components:
-
- Customer charges — A per-customer charge independent of usage.
- Demand charges — These charges are based on the maximum demand (kW) placed on the system during a specified period of time and are usually applied only to larger customers (due to the prohibitive cost of metering demand for small customers).
- Usage charges — These charges depend on actual usage during a period of time. For many customers the rates used to calculate usage charges stay the same no matter when the energy is used. For larger electric customers, however, it is common to charge a different rate for different periods of the day. This methodology is called time-of-use rates. In some cases gas or electric rates may also differ by season (i.e., summer vs. winter rates).
During the rate design process, the method of allocating revenue between the different types of rate charges is also determined.
Allocating revenue to charge types
Once the rate structure is set, another allocation must occur. This is the allocation within a customer class that determines how much revenue will be applied to customer charges, demand charges, and usage charges. Once this has been done, we now know how much revenue the utility is expected to collect from each charge type within each customer class.
Determining the rate
Finally, the rates for each customer type are calculated by dividing the allocated revenue by the appropriate forecasted factor. For instance, a residential customer class that is allocated $1 million per month to customer charges and has 100,000 customers forecasted would have a monthly customer charge of $1 million divided by 100,000 customers, which equals $10 per customer per month.