Regulation of electricity rates, asset ownership, and concerns over intergenerational equity, customer class cross-subsidization, and retail competition and the suite of service offerings available do not easily lend themselves to traditional “cost-of-service” regulation. The role of regulation and of regulated utilities in supporting grid-edge distributed energy resource (DER) technologies—large-scale renewable on- and offshore wind and electric vehicle charging stations, among other technologies and initiatives—need to be settled. Recognizing that vertically integrated utilities might face different regulatory challenges than utilities owning transmission and distribution infrastructure only, both utility business models need a fresh look from regulators. More explicitly, a realignment of regulatory practices and policies and, to the extent necessary, legislation to address franchise rights need to be reviewed and realigned to incent desired investments and behaviors, and to penalize predatory business practices and unfair monopolistic behaviors.
The general principles and tenets underlying the current regulatory paradigm and guiding investment decisions and rate structures need to be revisited to accommodate new technologies, market structures, and competitors and consumer behaviors. Utilities still have exclusive geographic franchise areas and the obligation to serve all customers requesting service. Regulated utilities are the provider of last resort even in regulatory jurisdictions having retail competition in recognition of the “public good” nature of electricity. Electricity is a ubiquitous fact of modern society. As a result, utility regulators approve rates and rate structures, and rule on the prudency of capital investments for cost recovery.
Utilities are regulated under a cost-of-service model, whereby all costs associated with the provision of electricity are recovered through rates charged. These costs include a return on investment. It is a misnomer to say utilities generate a profit; rather, the return on equity provided by regulators reflects an administratively determined cost of raising capital in the form of stock offerings.
Over the years, many regulatory agencies have introduced modifications to traditional ratemaking with “decoupling” and “performance-based” rates. This practice is not new, yet many regulatory jurisdictions do not offer either of these alternatives. Decoupling, the process of allowing a utility to recover all costs, regardless of sales, as incentive-based ratemaking, has been in existence since the late 1980s. Performance-based rates reward or penalize a utility based on its performance in meeting policy objectives or performance targets. To date, both schemes have proved successful in supporting attainment of aggressive energy efficiency (EE) goals and cost reduction strategies. Performance incentives, together with decoupling, proved very successful in driving utility investments in EE improvements and reducing costs in support of performance targets.
While utilities still have exclusive rights to provide electric service in their franchise area and a monopoly over delivery, states with retail competition and robust DER programs allow entities other than the franchise utility to provide electricity as a commodity, thereby bypassing the distribution system for some or all of a customer’s electricity needs.
Different rate structures have been put in place to allow utilities to charge exit fees or higher backup power rates. Recognizing that as customers leave the utility distribution system, remaining “captive” customers have to pay more for the same service, unless customers leaving the distribution system pay their fair share of having the utility serve as backup when needed.
The utility industry flourished after World War II with home ownership rising, while white-goods sales increased for refrigeration and washing and drying, air conditioning, and electronics in the limited form of televisions and radios. Demand for electricity was growing post-war and economies of scale for larger centrally located power generation continued to drive down the cost of electricity (on a per kilowatt-hour basis). Power plants were capital-intensive and expensive when placed in service. Rates increased for a given period until they gradually decreased (on a per unit of electricity basis) as plants ramped up to full capacity to meet ever-increasing demand.
Nuclear power plants and large coal plants proliferated, as nuclear power was touted as “too cheap to meter” and coal was plentiful and cheap. Large scale hydroelectric generating plants were also in vogue. All three plant types were, and continue to be, base load generation, providing the underpinnings for the reliability of service still enjoyed today. Fast forward to today. Peak demand is flat and commodity sales are flat or marginally increasing. This is a result of significantly improved building codes and appliance efficiency standards, utility- and government-sponsored energy efficiency and demand management programs, and third-party energy service companies offering competitive energy services and DER sales to customers.
The late 1980s saw electricity prices increasing due to high fossil fuel prices and high inflation. Construction of central station nuclear and fossil fuel–fired power plants was being canceled as demand slowed and prices rose. Nuclear power plant disasters like Three Mile Island caused government, consumers, and the industry to reconsider the risks associated with nuclear power. Global warming was being discussed in the scientific communities and spilling over into the public media. Coal and oil power generation were coming under fire. As a result, regulators in some jurisdictions required utilities to “go-to-market” to competitively procure new electricity supplies and energy efficiency and demand-reduction resources.
No longer was the utility able to simply build new generation without considering energy efficiency and demand management (DM) as nontraditional solutions.2 Utilities and state energy offices were also offering their own EEDM programs. Through analysis and experience, it was determined conclusively that the incremental cost of a unit of energy saved was cheaper than a unit of energy generated.
Recognizing there existed large potential for reducing energy use and waste in all sectors of the economy, and an ability to reduce the total cost of electric service, regulators began modifying their approach to regulation considering longer rate cases (from one-year to three- or even five-year), annual pass-throughs, and incentive (performance-based) ratemaking.
Recall that regulation is intended to protect consumers from monopolistic behaviors of utilities having an exclusive franchise to deliver services to customers. Regulation is necessary to ensure business practices and price-setting of a monopoly mimic those one might expect to see in a competitive market.
Utilities are being challenged to meet ever more stringent reliability and resiliency goals, deliver greater choice and value to customers, and meet ever-more-aggressive public policy goals. Public policy goals include clean energy portfolio standards, carbon-reduction goals, and opening their market to competitive energy suppliers, to name a few. At the same time, they are required to serve all customers and be the provider of last resort.
Couple these pressures with the utilities’ core business being threatened by customers’ self-generating or receiving electricity directly from third-party providers, and, in some cases, selling excess electricity back to the utility or bypassing the utility entirely by disconnecting from the grid or staying connected and requiring service if their primary supply is unavailable. The first-order effect of these pressures is a reduction in sales associated with these alternatives and, as a result, a reduction in revenue. In such a case, unless traditional cost-of-service regulation is challenged, the regulatory compact fails. The compact of course is that in exchange for being required to serve and being the provider of last resort, utilities are allowed to recover all costs necessary and prudently incurred to deliver service.
Nevertheless, customers remaining with the local distribution utility whether they choose to engage in the alternatives or are unable to avail themselves of self-generation and other services will see higher costs. Such captive customers must bear the brunt of all costs associated with the transmission and distribution system if they remain utility customers while others leave.
Compare this situation to landline telephone service, where customers remaining with legacy landline service providers pay for the entire cost of the network, while customers choosing to abandon landline service and use only mobile service pay none of the legacy costs.
The fact that mobile service is more expensive than landline service reflects consumers’ preference for the added functionality mobile devices make available and their willingness to pay for the added functionality.
DeCotis, Paul A. (June 2019). “Innovations in Utility Rate Regulation.“ Natural Gas & Electricity 35/11, ©2019 Wiley Periodicals, Inc., a Wiley company.
This is Digital, Episode 20: Can the Nation's Largest Utility Company Match Amazon's User Experience?
Growing smart grid investments call for new asset performance management strategies
Prioritizing Governance, Risk, and Compliance to Build a Lasting Impact in Banking
New regulatory requirements are coming for banks—how and why they should prepare now