PA Future Utility Part I: Background on Electric Utility Regulation

PA Future Utility Part I: Background on Electric Utility Regulation

July 14, 2015

Welcome to the first digest in the Kleinman Center for Energy Policy’s Pennsylvania Future Utility policy series.  These digests aim to provide readers with the basic background information to help understand various facets of the future utility discussion. Part I in the digest series provides a very brief overview of historic and current approaches to electric utility regulation.

A Brief History of Electricity Regulation

Today’s economy has been built upon a system of wires, switches, pipes and power stations that have enabled electric power to profoundly transform society, since the patent of the incandescent light bulb in 1880. This complex and capital intensive infrastructure system has been built and maintained under an equally complex regulatory construct.  According to the National Bureau of Economic Research (NBER), regulation of electric utilities evolved over four distinct phases:[1]
  • Franchise Regulation (through 1899) – Characterized as a form of weak municipal control, utilities paid fees to receive a franchise, a long term (20-50 years) contract to dig up streets and install and operate power system equipment.  Franchises often included service thresholds and (often, functionally non-binding) price ceilings.
  • Municipal Regulation (1900 – 1909) – Some states passed laws authorizing municipalities to directly regulate utility rates, so that once a utility’s franchise expired the city could unilaterally dictate rates without the consent of the electric company.
  • State Regulation (1907-1977) – States began to create regulatory commissions to regulate public utilities statewide.
  • Limited State and Municipal Control with Competition (1978 to present) – Congress passed the Public Utilities Regulatory Policy Act (PURPA) in 1978, with the majority of provisions related to wholesale (i.e. power generation) electric markets, as opposed to retail electricity distribution.  The 1992 Energy Policy Act, which required transmission networks to act as common carriers for generation supplies, brought further competition to wholesale markets.

The electric distribution network is considered a natural monopoly, meaning it is most cost efficient for production to be concentrated in a single firm rather than offered competitively. For example, consumer costs would increase if multiple firms built duplicative electricity systems into each home, and in such an environment, the viability of multiple, competitive firms would be unstable. Although federal and state legislation has enabled the formation and evolution of competition in wholesale power markets, the fundamental economics underpinning the distribution utility’s natural monopoly status remain.


Basics of Cost of Service Regulation

Government oversight of the distribution utility sector has developed for three basic reasons, 1) electric utilities provide essential services, 2) the industry and its services significantly impact the public interest, and 3) in order to correct for the market failure inherent in a natural monopoly.  Aspects of distribution utility regulation that extend to the public interest include, for example, the utilities obligation to serve, adherence to safety standards, and ensuring reliability of service. Economic regulation of the utilities was created to replace establishment of market prices through competition.  Regulators developed a “cost of service” approach to economic regulation where regulatory proceedings determine fair prices, including a reasonable return on and of investment, for electric service to each customer class (i.e. residential, commercial, industrial).  The term regulatory compact is often used to describe the relationship between the utility and its government regulator, where the utility accepts the obligation to serve the public in exchange for the government’s agreement to set rates in amounts to fully compensate the utility for its service obligation.

In basic terms, the cost of service approach to regulation follows these basic steps, that are included as part of a regulatory “rate case”, a proceeding where the utility’s tariff of allowable rates are established:[2]

  • Jurisdictional Cost Allocation – Analysis to determine what costs (e.g. investments and expenses) are eligible for recovery.  This can become complex if a company operates across multiple states, are part of larger corporations or have non-regulated affiliates, or offer both electric and gas services. The goal of the analysis is to determine what costs are associated with providing the service being investigated under the rate case.
  • Revenue Requirement – Given specific assumptions about costs and sales, the revenue requirement is the amount of revenue the utility needs in order to have the opportunity to earn a fair rate of return on its investment.  The revenue requirement determination has 4 key steps:
    • Test Year – establishment of a test year, either in past or future, for which utility’s annual costs and revenues can be measured and compared on a consistent basis.
    • Rate Base – a measure of the total long-term investments made by the utility in order to serve customers, net of depreciation and other adjustments.
    • Rate of Return – establishment of specific annual rates of return on the rate base, depending upon sources of funding used by the utility.  For example, a utility’s capital structure may rely on a mix of sources (e.g. different classes of equity and debt) to fund its activities. Debt will receive lower regulated rates of return, compared to equity, because of reduced risk exposure.
    • Operating Expenses – calculation of regular, necessary and prudent operating costs associated with providing service (e.g. labor, professional fees, insurance, power purchases), in addition to certain taxes and depreciation.  This may also include irregularly occurring expenses (e.g. associated with storm damages) or periodic adjustments (e.g. fuel price adjustments to correct for commodity volatility).
  • Allocation of Cost to Customer Classes – this process determines how each class of customer (e.g. residential, commercial, industrial) will contribute to supporting the revenue requirement. There are a variety of complex cost of service studies that are used to make these determinations, but in general, factors such as overall energy usage, number of customers and peak demand per customer type are considered.
  • Rate Design Within Customer Classes – in this step, the structure or design of rates for specific customer classes is determined.  For example, rates can include energy charges (i.e. fee based on amount of energy used), demand charges (i.e. fee based on the customer’s highest usage in a specific period of time), fixed customer charges (i.e. a basic service charge covering metering, meter reading, billing and other costs that do not vary with usage), and other fees.  The design of these rates and the portfolio of rates used impacts customers and customer classes in different ways.

Perspectives on Cost of Service Regulation

It is generally accepted that the cost of service model of regulation has successfully enabled the growth and maintenance of a functional electric distribution system.  However, there are various criticisms of this model, owing from different perspectives.  Some stakeholders believe that the cost of service model creates economic inefficiencies that benefit the utilities.  For example, the Averch-Johnson effect, where utilities are incented to overbuild in order to maximize capture of returns of and on investment, in other words, a utility could increase profits by increasing its rate base.[3] The throughput incentive, where utilities can increase profits by increasing sales of electricity, is another potential inefficiency that is referenced as a disincentive to energy efficiency programs. On the other hand, utility stakeholders identify regulatory lag, the time between when costs change and regulators adjust revenues, as a key issue with the cost of service model especially in times when rate increases don’t keep up with cost increases.  Regulators have been able to develop creative ways to ameliorate concerns regarding cost of service model shortcomings.  For example, developing prudence and used and usefulness reviews for major investments to combat the Averch-Johnson effect, or decoupling utility revenues from sales to address the throughput incentive.  Similarly, balancing or true-up mechanisms, cost adjustment mechanisms and riders have been used to address regulatory lag. 

Please review the next policy digest in the PA Future Utility Series, entitled “Part II – Electric Utility Challenges and Opportunities”, which provides a general overview of national trends experienced by electric distribution utilities.

Christina Simeone is Director of Policy and External Affairs at the Kleinman Center for Energy Policy at the University of Pennsylvania.

[1] Troesken, Werner, “Regime Change and Corruption: A History of Public Utility Regulation”, a published volume from the National Bureau of Economic Research, Glaeser and Goldin’s “Corruption and Reform: Lessons from America’s Economic History” (University of Chicago Press, March 2006)

[2] Lazard, Jim, “Electricity Regulation in the U.S.: A Guide” (Regulatory Assistance Project, March 2011)

[3] Averch, Harvey, Johnson, Leland, “Behavior of the Firm Under Regulatory Constraint” (The American Economic Review, Vol. 52, No. 5, Dec. 1962), pp. 1052-1069,


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