M-RCBG Associate Working Paper No. 58

Assessing How Utility Rate Design Affects the Income Distributional Impacts for Residential Customers With and Without Solar PV

Michael Alter and Jason Peuquet



The long-held practice of utilities generating revenues from customers only through fixed and volumetric charges is in the midst of being redefined. Utilities are seeking alternatives to standard electricity rates with net energy metering (NEM) that will more effectively recover the costs of serving particular customers. However, it is very difficult to determine the costs of serving individual residential customers. The expansion of distributed generation at the residential level, including solar photovoltaic (PV) systems, has further complicated the process of determining the cost of service for this class of customers. Recent regulatory developments in various states demonstrate the emphasis utilities and regulators have put on transitioning to alternative residential rate structures, including higher fixed charges, minimum monthly bills, time-of-use (TOU) rates, demand charges, and a combination of both.

One of the considerations that goes into rate design is how it impacts customer equity, or fairness. Utilities and regulators across the country define equity in different ways, with some placing more emphasis on the scale of bill impacts on a dollar and percentage change basis, while others place emphasis on a concept of gradualism that seeks to prevent large bill increases for certain customer segments in a short timeframe or overall progressivity. Almost any decision on rate structure design will impact equity among customers, but it is unclear how different rate structures will impact equity considerations across the entire utility customer base, both those with and without residential PV systems. This study seeks to add much-needed clarity into this policy discussion around equity by analyzing the following question:

What are the income distributional impacts of transitioning from standard rates (with NEM) to alternative rate structures for residential customers with and without PV systems?

This analysis relies on the National Renewable Energy Laboratory’s (NREL) System Advisor Model (SAM) to model annual utility bills for residential customers with and without PV systems in five geographical areas: California (PG&E), Arizona (APS), Nevada (NV Energy), Colorado (PSCo), and Massachusetts (Eversource). The rate structures examined included a standard rate (which enabled NEM) as a baseline along with a $30 fixed monthly charge, $30 minimum monthly bills, a multi-period TOU rate, a $10/kilowatt (kW) demand charge, and a combination TOU rate and demand charge. Additionally, battery storage is included for additional simulations under the TOU rate, the demand charge, and the combined TOU rate and demand charge. Battery storage functionality in the SAM software does not impact customers who do not have PV systems and customers under standard rates, fixed charges, and minimum monthly bills all with NEM (see Methodology section). All rate structures were modeled with three varying load profiles for each specific geographic area: high, base, and low-usage levels. This study uses electric load as a proxy for income, albeit with notable caveats to that assumption (see Methodology section for more discussion). Even if the findings of this study are not extrapolated to make conclusions about income distributional impacts, the results offer useful insights on how alternative rate structures can have different impacts on annual electric bills for households with varying levels of electricity consumption.

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