The operation and regulation of electric utilities is fundamentally different from most other businesses. Almost all other sectors of the economy have free competition, where companies can innovate on products, services, and prices to attract and retain customers and earn profits. Those that succeed can grow, those that fail go out of business. Competitive forces help keep prices in line and prevent companies from acquiring and exercising excess market power.

Utilities are unique in that they are not subject to these competitive forces but are instead granted a state-authorized monopoly over a set of customers in a geographic area. In order to prevent the utility from abusing this monopoly position, state regulators closely control what types of business the utility can conduct, approve the costs that it incurs, and even decide how much revenue and profit it is authorized to collect and earn.

The traditional form of utility regulation is “cost of service” regulation. Under this structure, the utility is authorized to build assets and earn a return of and on their capital. Imagine a utility spends $100 million on a new substation. The “return of” means they will get paid back this $100 million, typically spread over the useful life of the asset. The “return on” means they will earn a profit, typically around 10-11%, on the shareholder equity that was used to build the substation. The utility also is refunded for all normal operating expenses, such as interest payments, salaries, and fuel, as well as collecting additional money to pay for their federal, state, and local taxes. The total amount of money the utility is allowed to collect is called their “revenue requirement”, and this revenue is spread over the total amount of sales to create the rate that individuals and businesses pay for their electricity.

Cost of service regulation contains an obvious and highly problematic flaw.  By paying utilities based on how many assets they build, and by charging customers based on how much electricity they sell, utilities have every incentive to build more stuff and sell more electricity.  Unfortunately, this “throughput incentive” runs counter to policy goals such as reducing electricity use and increasing access to alternative generation such as distributed PV systems.  When faced with technologies and programs that can reduce their earnings, utilities’ responses have often been predictable.

Fortunately, it is possible to design utility revenue policies and rate structures so that utilities and their shareholders are rewarded for working with their customers to encourage conservation and distributed generation of electricity, while at the same time sending price signals that more closely reflect the real-time supply and demand of energy on the grid. The goal is to provide more options for utilities and consumers; no one solution is perfect for every situation.  Smart policy and informed public utility regulators can structure utility rates to provide win-win approaches for utilities, their customers, and their shareholders. Three such approaches are Revenue Decoupling, Time-of-Use Rates and Performance-Based Ratemaking. 

Revenue Decoupling

Under current regulation, most utilities’ revenue generation is tied directly to retail sales, and therefore any reduction in energy consumption directly reduces the companies’ profitability. This creates a powerful financial disincentive for utilities to support energy efficiency and clean and renewable distributed generation, such as solar.

The purpose of a decoupling mechanism is to remove this disincentive, by eliminating the link between electricity sales and profits. Under decoupling, instead of higher-than-expected sales leading to higher and higher revenues, the utility would only be authorized to recover their pre-approved revenue requirement. A simple system of periodic "true-ups" in base electricity rates would either restore to the utility or give back to customers the dollars that were under- or over-collected as a result of fluctuations in electric consumption and retail sales. This corrects for disparities between revenue requirements approved by utility regulators and the revenue that would have been collected based on the approved rates and actual sales.

Time-of-Use Rates

The cost to generate electricity can vary dramatically at different times of the year and of the day. Hot summer afternoons, when everyone has their air conditioners on high, require utilities to run less efficient, more expensive power plants to meet demand. By contrast, mild spring weekends often have substantial spare capacity, requiring only the most cost-effective generators to meet load. Wholesale power prices can range between $25/MWh in these mild times to more than $1,000/MWh during times of peak demand. 

However, most utility customers pay the same price for electricity regardless of when it is used. This is contrary to the basic principles of supply and demand, and as a result, homeowners and businesses have no real incentive to minimize their use of grid-supplied electricity during peak demand hours. Absent a price signal to tell customers to control their usage during specific times, a utility might have to build or buy more generation, transmission, or distribution capacity, which will increase everyone’s costs.

If consumers instead received price signals that more accurately reflected the supply and demand of electricity, they might choose to conserve energy or generate their own. Time of use (TOU) rates send this price signal by charging more during times of peak demand and less during times of low demand. By managing the amount of power that all customers consume on the hottest afternoons, TOU rates can reduce the peak demand and prevent utilities from building costly generation assets that sit idle during non-peak demand hours.

Under most conditions, utilities face very different costs for generating electricity at different times. However, in most places utility customers pay the same price for electricity regardless of when it's purchased. These markets are divorced from the basic principles of supply and demand. As a result, homeowners and businesses have no particular incentive to minimize their use of grid-supplied electricity during peak demand hours. If consumers received price signals that more accurately reflected the supply and demand of electricity, they might choose to conserve energy or generate their own. As the demand for peak energy grows, utilities are forced to build costly generation assets that sit idle during non-peak demand hours. These generation assets impose unnecessary costs on ratepayers.  

Performance-Based Ratemaking  

While decoupling policies remove the disincentive to support energy efficiency and solar energy, and TOU rates can provide customers price signals to control their usage, these policies may not be enough to actively engage utilities to support and achieve policy goals. Instead, decoupling and rate design should be complemented through Performance-Based Ratemaking (PBR). PBR sets specific targets for metrics such as customer service, energy efficiency, reliability, distribution generation, and others, and create rewards for utilities for achieving environmental targets beyond their mandates.

A well-designed PBR structure does not shift risks from utilities to consumers, but instead shifts the variables that determine utilities’ financial health. Instead of increasing profits by increasing sales or building more assets, utilities should be able to increase profits by improving performance, reliability and service.

SEIA supports PBR mechanisms that:

• Eliminate the link between utility profits and utility sales
• Reward utilities for improving customer service and system reliability
• Encourage maximum energy efficiency and solar energy penetration
• Are developed in conjunction with a system that sets specific energy efficiency and clean distributed generation targets, and rewards utilities for achieving those targets