ABSTRACT: The primary purpose of a cost of service study is to allocate a utility’s overall revenue requirements to the various classes of service in a manner that reflects the relative costs of providing service to each class. A cost of service study is an analysis of costs that assigns to each class of customers its proportionate share of the utility’s total cost of service, i.e., the utility’s total revenue requirement. The results of these studies can be utilized to determine the relative cost of service for each customer class and to help determine the individual class revenue responsibility.
PART I. Read more of this Discussion: Part II
I. Purpose and Basis of Cost Service Studies
The primary purpose of a cost of service study is to allocate a utility’s overall revenue requirements to the various classes of service in a manner that reflects the relative costs of providing service to each class. A cost of service study is an analysis of costs that assigns to each class of customers its proportionate share of the utility’s total cost of service, i.e., the utility’s total revenue requirement. The results of these studies can be utilized to determine the relative cost of service for each customer class and to help determine the individual class revenue responsibility.
In general, cost of service studies can be based on embedded costs or marginal costs. Marginal costs can be thought of as the incremental change in costs associated with a one-unit change in service (or output) provided by the utility. As a result of using an incremental change, capacity additions tend to be lumpy – meaning that they may add more capacity than required to serve the increment of load assumed in the analysis. To avoid this issue requires that the computation of the unit cost be based on the amount of capacity added rather than on the level of load that can be served.
Embedded cost studies analyze the costs for a test period based on either the book value of accounting costs (an historical period) or the estimated book value of costs for a forecast test year or some combination of historical and future costs. Where a forecast test year is used, the costs and revenues are typically derived from budgets prepared as part of the utility’s financial plan. Typically, embedded cost studies are used to allocate the revenue requirement between jurisdictions, classes, and between customers within a class.
Marginal cost studies can reflect actually incurred costs but often rely on estimates of the expected changes in cost associated with changes in utility service. Marginal cost studies are forward-looking to the extent permitted by available data. Marginal cost studies may be particularly useful for rate design and can also be used as a guide to determine how a utility’s total revenue requirement should be allocated to its classes of service. Where it is important to send appropriate price signals associated with additional energy consumption by customers, an understanding of marginal cost may be informative.
The cost of service study is useful in identifying cost causation that is a critical element of the allocation of costs between classes and customers within the class, and for adjusting rates to reduce or eliminate cross subsidies that result in rates that are not just and reasonable. A fully unbundled cost of service study provides critical information for the design of just and reasonable rates.
II. Theoretical Principles Of Cost Allocation
A. Cost Causation
Cost studies are a basic tool of ratemaking. Just and reasonable rates must avoid undue discrimination and must reflect the principle of “user pays,” also known as “cost causation,” which is another way of saying that those who cause the costs should pay the costs. Undue discrimination occurs when customers receiving the same service pay different amounts for the same service. The development of unbundled costs permits regulatory review of the costs that are the same on average for customers in the class. We use the term “on average” because no two customers are exactly alike. Therefore, we determine costs and set cost-based rates for “typical” customers grouped by similar demand and usage patterns.
If those customer-related costs are not recovered in the customer charge or basic service fee as they should be, the customers with more than average energy consumption subsidize the customers who use less than average. The cost of service study that unbundles customer costs provides a benchmark to assess the rates to determine if they are just and reasonable and do not discriminate based on the rate design.
In order for rates to be efficient the concept of customers being charged for the distinct services they use is important since different customers use different services. Further, the costs of those services may be different because of the different load characteristics of customers in a class. Both cost allocation and rate design play a role in efficient rates.
A properly developed cost of service study represents an attempt to analyze which customer or group of customers cause the utility to incur the costs to provide service. Understanding cost causation requires an in-depth understanding of the planning, engineering, and operations of the utility system, as well as the basic economics of the unbundled components of the utility system.
B. Characteristics of Utilities’ Costs
The requirement to develop cost studies results from the nature of utility costs. Utility costs are characterized by the existence of common and joint costs . In addition, utility costs may be fixed or variable costs . Finally, utility costs exhibit significant economies of scale. These characteristics have implications for both cost analysis and rate design from a theoretical and practical perspective. The development of cost studies requires an understanding of the operating characteristics of the utility system. Further, as discussed below, different cost studies provide different contributions to the development of economically efficient rates and the cost responsibility by customer class.
Utilities are unusual in the relationship between fixed and variable costs. The only variable costs for an electric utility are the costs of fuel, purchased power, fuel handling and some limited amount of variable O&M. All other costs are fixed. The fixed costs represent the sunk costs of the utility for capacity to produce and deliver capacity and energy and other services to customers. The portion of fixed and variable costs to the total cost of service varies among the customer classes based on the types and quantity of the services used by the customer.
As a practical matter, failure to recover fixed costs in fixed charges results in unreasonable outcomes for classes that are not almost perfectly homogeneous by creating subsidies within the classes. It can also result in the utility recovering either more than or less than the authorized revenue requirement, based on whether consumption is higher or lower, respectively, than the levels used in the determination of the structure of utility rates.
C. Allocation of Costs through a Class Cost of Service Study
The cost of service study provides a reasonable starting point for policy makers to decide the portion of common costs borne by each class of service. In addition, it must be remembered that other constraints impact policy decisions, such as the concept of just and reasonable rates and non-discriminatory rates. We must rely on who causes costs and how those costs are recovered within a class of customers as the basis for determining rates that result from the cost of service study.
It is a practical reality of regulation that common costs be allocated among jurisdictions, classes of service, rate schedules, and customers within rate schedules. The key to a reasonable cost allocation is an understanding of cost causation. Under the traditional embedded cost allocation, the process follows three steps: functionalization, classification, and allocation. This three-step process underlies the determination of cost causation.
By identifying the functions of utility service – production or generation, transmission, distribution, and customer for electric or natural gas service – and the costs of these functions, the foundation is laid for classifying costs based on the factors that cause the utility to incur these costs – energy, demand, and customers. The development of allocation factors by rate schedule or class uses principles of both economics and engineering to develop allocation factors appropriate for different elements of costs. If these factors properly reflect cost causation, the fully unbundled cost of service study is a reasonable tool for use in assigning revenue requirements to each class of service and for determining the cost of each service provided by the utility.
In many cases determining cost causation is as simple as asking the question of whether a particular cost changes when some potential allocation factor changes. If a factor causes costs, costs will vary with changes in that factor. For example, if the number of electric utility kilowatt hours (kWh) increases, does the cost of some input such as miles of conductor increase with more kWh? Since the miles of conductor do not change with kWh either monthly or annually, energy consumption is not a cause of conductor costs. What we do know is that miles of conductor increase for customers added to the periphery of the system, thus customers are a cause of the cost. We also know that the miles of conductor increase with the growth of the peak load on the conductor and that load may be met by paralleling the system, looping the system, or networking the system. It may also mean building added capacity through expanding the system to a three-phase conductor. This means that some of the cost of conductors is also caused by the demand on the conductor. In any case, the factors driving the cost of conductor are customers and a measure of non-coincident peak demand. Following this logical process allows one to determine cost causation for each element of the system.
There are three elemental cost classifications that are the basis for cost causation: customers, demand and energy. Essentially, all costs incurred by the utility are directly or in some cases indirectly related to one of these three factors. That is a utility incurs costs based on (1) the number, size and type of customers, (2) a combination of several measures of customer demand or (3) a measure on the energy used by customers. Within these three classifications there may be different measures of the factor based on how costs are incurred when allocation factors are developed.
The National Association of Regulatory Utility Commissioners (“NARUC”) Electric Utility Cost Allocation Manual identifies three fundamental methods for allocation of demand related costs: Coincident Peak (CP) methods, Non-Coincident Peak (NCP) methods and Average and Excess Demand (AED) methods. Within each of these categories, there are numerous specific formulations of the methods. Further, to reflect the cost of an electric system, a complete cost of service study requires application of more than one demand category of these allocation factors. For example, class non-coincident peaks drive the allocation of part of the distribution system capacity while it is some combination of coincident peaks and demand and energy methods for generation. Within each classification category, there may be multiple specific methods. Under the CP allocation category options include a single CP, 4 CP, 12 CP, winter/summer CP and so forth. In addition to the AED allocation method, there are a number of methods that consider both demand and energy such as peak and average, and other hybrid methods. These methods are all described in the NARUC Manual.
The choice of methods relies on the concept of cost causation to choose the most appropriate method that best reflects those costs. NCP methods may use a variety of peaks other than the actual system peak based on the peaks of individual service classifications or individual customers. Cost causation requires the determination of the cost to serve each class of customers in a way that recognizes apparent cost responsibility and reflects the engineering and operating characteristics of the utility system. It is not unusual that a cost study includes all of the methods for allocating demand and potentially more than one of the variants of the methods.
III. Class Cost of Service Process
A. The Functionalization Step
A systematic process for identifying functions is used based on the traditional categories of production, transmission, distribution and customer. To the extent permitted by the accounting data, this functionalization may include subcategories such as electric primary distribution and secondary distribution and directly assigned dollars based on unique facilities that need to be assigned rather than allocated. The process of functionalization has become a more robust and simplified process with the use of accounting data as reported under a utility uniform system of accounts. That is not to say that all of the issues have been resolved. Certain accounts such as intangible plant still require some analysis to functionalize individual cost elements in the account for some utilities.
B. The Classification Step
Cost classification is driven by as detailed an analysis as the accounting data permits. As discussed earlier, costs are classified as demand, energy and customer. Only costs that vary with energy are classified as energy. The costs classified as demand are those costs that are a function of some measure of demand. Customer costs are those costs that vary with the number of customers. For some of the costs associated with the distribution system, costs must be split between the portion that is demand related and the portion that is customer related. That split is based on the principles of cost causation as discussed above. The functionalized and classified costs are then allocated among the various rate classes. Cost are functionalized and classified in the study based on data from the Uniform System of Accounts (USOA). Allocation is based on the factors that cause costs to be incurred.
C. The Allocation Step
Cost studies use two types of allocation factors: external factors and internal factors. External allocation factors are based on direct knowledge from data in the utility’s accounting and other records such as the load research data. Generation is functionalized to production accounts and allocated based on both an external capacity and energy allocation factor depending on the nature of the account. Energy allocation factors are based on the class energy consumption and adjusted for losses to equate to total energy production. Another example of an external allocation factor is allocation of distribution system costs, both the demand and customer components. The costs of electric distribution facilities are known and assigned directly to the distribution function as substations, poles, towers and fixtures, overhead and underground conductors, transformers, service lines and meters.
Once assigned to distribution, the poles and conductors are allocated using the minimum system to classify the costs between demand and customer related costs and then are allocated on external allocation factors. Electric demand allocation factors are based on load research data that is used to calculate the demand for the sampled rate classes and is adjusted to equal system peaks. For some classes the peak data for the class comes from billing data and represents the sum of actual customer loads occurring at the system peak. As smart meter technology becomes widely available, the need to estimate the class load will no longer be necessary as meter data will be available. Internal allocation factors are based on some combination of external allocation factors, previously directly assigned costs, and other internal allocation factors. For example, the allocation factors for property insurance costs are based on plant investment amounts assigned to each function; therefore, it is necessary to compute the amount of plant by function before property insurance costs can be assigned.
The electric production demand allocation factor must recognize both the role of capacity requirements (based on the full demand on system capacity) and the role of minimizing the total cost of production including the cost of energy. The concept of total demand on capacity is critical to developing a cost study that reflects cost causation. The rationale for understanding the total demand on the system is grounded both in theory and the operating realities of an integrated power system.
The operating realities of a power system include the impact of external factors such as weather, mechanical and operating issues, and legal restraints that impact the operation of the power system. In addition, to these external factors, there are operating procedures and requirements that must be considered such as planned maintenance outages, unplanned maintenance outages (including forced outages), unit de-ratings and so forth.
From an operating perspective, these events must be added to the system load to reflect the full demand on capacity. Implications of these considerations effectively alter the load duration curve for the utility by raising the demand requirements in otherwise low customer load periods. In considering these factors as part of the demand on capacity the planning for capacity additions may be driven by periods outside of the peak customer load period. For example, a company that experiences its peak customer load in the winter may determine that capacity additions are driven by load conditions in the summer when the effect of unit de-ratings and system outages have a significant impact on the capacity requirements of the system. It may also be the case that utilities with a high customer demand load factor may need to add capacity solely for having the required flexibility to schedule maintenance for large base load units. In any case the practical operating requirements of any system directly impact not only the required capacity but the optimal mix of system capacity.
On a theoretical basis, these practical issues require that the allocation of capacity reflect these operating realities to mirror cost causation. This is so because both the mix of generation and the absolute required level of capacity to provide a reliable and economically efficient system are caused by more than the peak load requirement of customers.