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Introduction

Net metering (net energy metering or NEM) is a policy adopted in many states to encourage the deployment of clean, distributed generation by residential, commercial, and industrial electricity customers, on the customer side of the meter known as “behind the meter” (BTM). Policymakers implemented NEM to help achieve clean energy resource diversity, financing assistance, carbon reduction goals, and in some instances to encourage economic development, increase resilience, and reduce system costs.¹ For example, Rhode Island’s net metering law states that its purpose is:

Net metering is receiving increasing amounts of attention, support, and scrutiny today as greater quantities of distributed generation (DG) and distributed energy resources (DER) are connected to the electricity grid, spurred not only by policy but also by economic, technology, and social developments. Net metering policies have been a key determinant in the adoption of DG and have generally succeeded in encouraging deployment of BTM clean DG, primarily rooftop solar. The technical requirements for an electric power system with these distributed elements are detailed in Chapters 2 and 6. Broad decarbonization and resilience objectives, as well as economic development and job growth goals, are also driving increasing interest and uptake in distributed and grid-scale technologies for renewable electricity generation, grid-connected storage, and demand management. This growth in DG and the number of assets connected to the electricity grid that are subject to net metering and related policies highlight the need to understand the economic, equity, environmental, and technology implications of net metering to help decision makers make informed choices about this and related policies in the future.

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¹Wan, Y.H., and H.J. Green. 1998. “Current Experience with Net Metering Programs.” CP-500-24527. Golden, CO: National Renewable Energy Laboratory. Paper presented at WINDPOWER ‘98, Bakersfield, CA. https://www.nrel.gov/docs/legosti/old/24527.pdf.

² Rhode Island General Laws. “Title 39, Chapter 26.4, Net Metering.” State of Rhode Island General Assembly. http://webserver.rilin.state.ri.us/Statutes/TITLE39/39-26.4/39-26.4-1.htm.

The committee’s statement of task (Box 1-1) asks it to evaluate NEM’s potential to contribute to a decarbonizing, equitable, and resilient electricity system in the context of alternative transactional mechanisms and incentives. The statement of task further instructs the committee to assess the “medium-to-long term impacts of net metering on the electricity grid and consumers.” In response to this charge, the committee has developed this report which presents guiding principles for rate design, technology, and regulation, among other relevant factors in order to inform prudent, adaptable, and forward-thinking policy for net metering, its variants, and alternatives. To begin, the committee considers “medium-term” to encompass a time period of approximately 5 to 10 years, where there is some foresight of changes in conditions, technologies, and policies affecting net metering and DG deployment. The “long-term” refers to 10 to 20 years or more following this report’s publication (in 2023), where additional changes can be expected but their nature and scope cannot yet be fully foreseen.

The committee also considered near-term changes that are already under way or in process. The evolution of net metering policy can be viewed as corresponding to the growth in customer adoption of BTM DG. In the early stages, the objective of net metering was to encourage adoption. The incentives it provided had little impact on customer rates, including “non-participants” (i.e., those customers who did not adopt BTM DG). As deployment of BTM DG increased, net metering policies were modified – both to support DG growth by lifting caps on eligibility and by modifying the incentives

provided to reduce their impact on rates. As DG adoption continued to grow, net metering policy variants were introduced, including time-varying and other modifications to rates to better align incentives with the value BTM DG could provide. As this occurred, the objective of net metering policy began to evolve toward facilitating optimization of system design encouraging DG more in certain locations and at certain times than others. Looking forward as the electricity system itself continues to evolve with increased focus on decarbonization, equity and resilience, net metering policy should continue to evolve with it toward a sustainable structure that benefits the system and all customers (see Figure 1-1). The shift to pricing based on avoided costs shown in Figure 1-1 has ranged from wholesale prices to estimates of the value of DER to the system, including externalities; Chapter 4 describes the elements involved in estimating that value.

NET METERING DEFINED

The committee recognizes that the term “net metering” is often employed with varying intended meanings and assumptions. To limit confusion and potential misunderstanding

in the context of this report, the committee presents the following definitions of the term “net metering” and its variants, reflecting the most-common meaning of these terms.

The committee defines net metering as a billing mechanism that (1) offsets customer electricity consumption on a volumetric (kilowatt-hour [kWh]) basis with production from BTM DG, effectively crediting production at the retail rate applicable at the time of consumption; and (2) similarly credits customers at the retail rate for electricity exported to the electricity grid. As initially implemented using a single, analog utility meter for each participating customer, a utility customer’s billing meter ran backward as electricity was exported to the electricity grid, and forward as electricity was consumed from the grid.³

This definition of net metering refers to traditional net metering, where at the end of each billing period the net amount of energy (measured in kWh) consumed or exported to the grid would be recorded. The customer would either owe a payment to the utility for the net energy consumed, or a credit would be calculated, based on the net energy exported to the grid. Such a credit might carry forward for application in a subsequent month. In traditional net metering program designs, participating customers might be eligible for payment for any net excess generation, usually at the end of a year or the end of 12 consecutive billing cycles, with payment for this generation credited at either the full retail rate for consumption or another rate. Implementation details have varied by jurisdiction. In some cases, program design differences reflected variations in the capabilities of pre-existing utility metering and billing systems.

The committee notes that the time period over which credits are calculated (or netted) can affect the level of compensation for customers who are producing or generating electricity and participating in net metering. Other policy choices or conditions on net metering can also affect the compensation provided to customers for their BTM DG. These can include:

• Limits on the size of systems eligible for net metering (e.g., no more than 125 percent of customer load) to encourage matching the DG capacity to historic or anticipated levels of customer consumption.
• Caps on the overall amount of generation eligible for net metering on a utility’s system (e.g., number of megawatts [MW] or a percentage of a utility’s overall

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³ Adapted from Gilliam and Stanton, p. 9. Stanton, T., and D. Phelan. 2013. “State and Utility Solar Energy Programs: Recommended Approaches for Growing Markets.” NRRI 13-07. Silver Spring, MD: National Regulatory Research Institute. https://pubs.naruc.org/pub/FA86BBED-D69F-C1EC-D308-0BB2CDAF5E37. Quoting from Gilliam, R. 2013. “Net Metering.” p. 5, PowerPoint presentation. The Cost, Benefits and Equity Issues of Net Energy Metering. February 5. Washington, DC: NARUC Winter Committee Meetings.

• load) to reduce the potential impact of increasing amounts of DG on the electricity system.
• The ability to cash out credits at the end of the netting period will also affect the level of net metering compensation.

The level of compensation also affects non-participating customers and the host utility. Timing of output from on-site generation can affect the electricity system (distribution, transmission, and generation), particularly where the timing of production does not match the timing of use by others on the electric system. The location of distributed generation (e.g., on constrained distribution circuits) can also affect the electricity system. Some of these impacts may lead to costs to the system and other customers (e.g., where DG increases constraints), and other impacts may result in assistance to the grid and benefits to other customers (e.g., where DG relieves constraints). These impacts, and methods for influencing them, are examined in this study. (See Chapter 4 for a discussion of economic impacts and Chapter 6 for a discussion of physical and technological impacts.)

In addition to traditional NEM, state policymakers and regulators have developed and are exploring NEM variants and alternatives that may better accomplish decarbonization, equity, and resilience objectives. This report uses the term net metering variants to refer to refinements to the ratemaking approach or design that underlies traditional net metering and the term net metering alternatives to refer to policies and programs outside ratemaking that have been implemented or are under consideration. The report uses the term net metering and its variants and alternatives when referring to traditional net metering, ratemaking-related refinements, and alternatives to it.

NET METERING VARIANTS

Variants for Customers with On-Site Generation

Prominent examples of net metering variants that largely rely on the underlying utility ratemaking or rate design structure include the following:

• Net Billing: A tariff designed to compensate customers with distributed generation for exported production at a netting interval (a defined time period) that may be shorter than the usual monthly billing period (e.g., daily, hourly, time-of-use window, or even instantaneously) and/or at a rate which may differ from the retail rate (e.g., an administratively determined avoided cost rate or wholesale market price; essentially netting charges and credits on the bill rather

• than imports and exports during a specific time interval). With this type of net metering, customers may not be able to use credits accrued during one time period in a future billing cycle or apply them to all elements on the bill, such as customer or system benefit charges.
• Inflow/Outflow Rates: A variation on net billing where a customer avoids paying for electricity at the retail rate when the customer’s own generation is consumed onsite and offsets that consumption, but outflow to the grid is credited at a rate different from the retail rate.
• Buy-All, Sell-All Rates: Customers with distributed generation purchase electricity from the utility at the same rate as those without, and sell electricity back to the grid at a rate that could be administratively determined, set at avoided cost or wholesale market price. With buy all, sell all rates, customers are not treated as if they directly consume any of the energy generated by their solar or other BTM DG.

Two common ways to set the price or compensation level for solar production under Net Billing and Buy-All, Sell-All Rates include administratively determined rates intended to reflect the value to the electric utility system or feed-in tariffs (FIT) intended to produce a reasonable return on investment based on the installed cost of DG and its production. Administratively determined rates range widely in different service territories, from average annual wholesale prices for energy at the low end, through prices reflecting the estimated value of solar (VOS) or value of distributed energy resources (VDER) to the system (including externalities) at the high end.

• Value-of-Solar (VOS, or Value of DER [VDER]) Tariff: Customers are compensated for their behind-the-meter generation at a rate based on the value of the solar (or other DER) to the utility, the distribution grid, the electric system, and/or society, rather than the retail rate. The VOS rate may be applied to (1) all generation, including both generation that offsets consumption and generation that is exported; or (2) only exported generation. The value of solar, or method to calculate it, is generally determined through an administrative proceeding.
• Feed-In Tariff (FIT): Customers are compensated for generation sold to the grid under a tariff at prices set administratively, which may be intended to achieve certain deployment goals or based on cost estimates.

This list is not exhaustive but instead represents prominent net metering variants. A visual depiction of the relationship between net metering, its variants, and their definitions is included in Figure 1-2.

Virtual Net Metering

Another approach to NEM is virtual net metering (VNM). Virtual net metering extends the net metering billing and crediting mechanism beyond the meter of the location where electricity is produced to allow the assignment of credits to customers in another location. VNM distributes the credits for DG production among multiple owners or subscribers, or with multiple service addresses for a single utility customer, regardless of whether the DG is co-located with every, or any, member. For example, a solar developer could build a project (sometimes characterized or structured as a community solar project) and assign net metering credits to several customers, for instance in a housing project.⁴ Another form of virtual net metering is when a business, university or hospital campus, or municipality installs a DG project behind the meter at one building or location and assigns credits to other buildings or municipal facilities with their own meters. Under virtual net metering, credit value may be set as it is for net metering generally: (1) at the retail rate; (2) at an administratively determined rate (which can range from an avoided cost rate, a wholesale market price, or a VOS rate); or (3) at a rate, such as a FIT, intended to produce a reasonable return on investment for the installed equipment.

Virtual net metering evolved to enable customers to participate in DG adoption when they do not have suitable conditions for installing DG behind their own meters. For example, their homes or buildings may be heavily shaded and not appropriate for rooftop solar, or they may live in apartment buildings with one meter. VNM enables them to essentially “use solar PV even though it is installed on another building or site.”Through VNM, these customers receive credits on their bills that reflect the energy the DG system generates and provides to the grid. When credited at the retail price for billing purposes, it is as if the customer’s electricity meter is running backward.

There are two primary types of virtual net metering. The first is where a single organization or customer owns both assets (the DG and the load). For example, a municipality may have a solar PV farm on its landfill and use the credits generated to offset the bills of municipal buildings and streetlights on their accounts with their electric utility. In this type of virtual net metering all the meters for the systems owned by a single entity are summed (with DG generation being negative) and the municipal customer pays the net amount used.⁵

The second type of virtual net metering allows for multiple customers to offset their electricity bills using a separately located and shared DG system. An example of this approach would be a community solar project. A community solar project could be owned by the

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⁴ Some jurisdictions call this “remote” net metering.

⁵ Some jurisdictions call this “aggregate” net metering.

electric utility, which would provide customers with local green power or credits from the solar facility. The credits from the virtually net metered solar system reduce customers’bills without their having to incur the generally higher cost of installing and operating their own rooftop solar system. In this configuration, the utility generally owns the solar project and continues to generate the electricity provided to customers. Community solar projects can also be built and owned by solar and storage developers who assign net metering credits to customer“off-takers.”In this situation, the electricity is generated by projects not owned by the utility, reducing its sales to customers.⁶

NET METERING ALTERNATIVES

Net metering (including its rate-related variants) is one way to encourage the deployment of BTM DG. There are also several alternative policies and mechanisms, designed to encourage the deployment of distributed clean generation, which go beyond compensation through utility rates. They include:

• Renewable portfolio standards (RPS) or clean energy standards (CES), particularly when specifying quantities or percentages for distributed generation
• Rebates or financial incentives funded outside of utility rates, for example through federal or state budgets that authorize and appropriate funds to programs (Note: does not include utility program funds which would be recovered from ratepayers)
• Tax credits (state or federal, or both) for use by individual households and businesses
• Building codes (e.g., that require the installation of rooftop solar on certain new construction)

This report will discuss some of these alternatives in relation to net metering, where they may complement, substitute for, or enhance the efficiency and effectiveness of net metering and its variants.

RATE DESIGN AND NET METERING

As noted in the definition above, net metering is a billing mechanism intrinsically tied to the retail electricity rate structure. Compensation for BTM DG provided by net metering

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⁶ Community solar owned by entities other than the utility can have similar impacts to individual rooftop solar on the utility system and for other customers. These impacts are discussed in Chapter 4 (Economic Considerations Related to Net Metering).

can and has been set and modified through changes to the underlying rate structure independently of any changes to net metering per se. (See Chapter 3 discussion.) Refinements or changes to retail rate design will affect the level of the credits (or compensation) net metering provides to BTM DG customers, as well as impacts on other customers and the electricity system. These refinements involve (1) changes to the structure of rates, including the level of monthly customer charges or other fixed charges; (2) changes in energy charges, such as time-of-use or other time-varying rates for consumption (cents per kWh); and (3) a charge tied to the level of the customer’s peak demand during a period; and/or mechanisms such as minimum bills. To understand the implications of these changes on customers with and without BTM DG, as well as the utility, it is important to understand how rates are set.

Mechanics of Traditional Ratemaking and Rate Design

There are multiple goals of traditional utility regulation and ratemaking, including revenue sufficiency and stability for utilities, consumer protection, understandability of rates and bills, administrative feasibility, and pricing efficiency. Regulators must balance among them, using their judgment. (See Chapter 7 for further discussion.) That said, traditional utility ratemaking begins with a calculation of what it costs the utility to provide service to customers, including both embedded capital investments, and expenses such as operations, maintenance, and fuel. The total cost of service is also referred to as a utility’s revenue requirement. The revenue requirement is then translated into the rates customers pay so that the utility is given a reasonable opportunity to recover the costs it prudently incurs to provide service to customers. This is a multi-step process:

• First, costs in a particular time period (e.g., a year in the past or a forecasted year in the future) are identified by function, such as generation, transmission, distribution, and customer connection.⁷ Some of the costs may be fixed over a period of time (such as the depreciation and interest expenses for the capital

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⁷ Note that this description of ratemaking mechanisms reflects the costs of a vertically integrated utility that provides bundled generation, transmission, and distribution service. Where a utility provides distribution service alone and either purchases generation and transmission service from an all-requirements supplier, that utility’s own rates reflect their costs of the distribution function (and generation and transmission costs they pay are passed through to customers as part of the electricity bill). Similarly, in parts of the country where a customer can elect to have a competitive supplier other than the utility provide commodity supply, the distribution utility’s rate will reflect its costs to provide “wires” service (its own distribution costs and its own or passed-through transmission costs), and the customer’s bill will typically reflect the passed-through price of the competitive supplier. See Chapter 7 (Regulatory, Legal, and Market Considerations) for a discussion of organizational types of utilities.

• costs of a generator, or distribution and transmission investment, or labor costs over a year). Other costs are variable, changing with usage (such as fuel and some operating and maintenance expenses).
• Next the cost of service is allocated to rate classes (based on the different types of costs to serve them). Rate classes are similarly situated customers; similarly situated means that on average across a group of customers their usage levels and patterns are roughly similar. Common rate classes are residential, commercial, and industrial. Any individual’s usage may differ from the average of its class.
• Rates are then designed to collect the costs to serve from these different groups of customers based on projections or estimates of their class consumption and other factors.
• Historically, rate design recovers different types of costs through different types of charges or billing components on the customer bill:
  • Customer charges ($/month) cover the costs to connect a customer to the electricity system. Traditionally, these include the service drop (wire from distribution system to house, commercial building, or industrial facility) and costs associated with billing, metering, and collections. In some jurisdictions, the customer charge includes a minimum level of distribution investment needed to provide service to a customer. Recently, other fixed monthly charges have been considered or included in customer bills.⁸
  • Energy charges (cents/kWh) cover the costs that vary with consumption or usage, such as fuel costs associated with generating the kWh consumed. In rate designs without demand charges or customer charges reflecting only the costs to connect, energy charges have also typically included what may be considered fixed (capital) costs of generation, transmission, and distribution, which have been amortized over a period representative of the life of the investment. (This can be thought of as similar to a bakery including the relatively fixed costs of its building, ovens, and other equipment, in addition to the costs of flour, eggs, and butter, which clearly vary with the volume of baked items provided and sold.)⁹

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⁸Prehoda, E., J.M. Pearce, and C. Schelly. 2019. “Policies to Overcome Barriers for Renewable Energy Distributed Generation: A Case Study of Utility Structure and Regulatory Regimes in Michigan.” Energies 12(4):674.

⁹ In restructured states, the utility bill may include supply charges separately from transmission and distribution charges. These supply charges include the generation or energy purchased to serve customers. The transmission and distribution charges include the costs of poles and wires and other transmission and distribution equipment. All are usually billed on a volumetric basis (characterized as an energy charge) rather than as a “demand” charge.

• • Demand charges ($/kW) cover the costs associated with putting in place the capacity needed to provide the maximum amount of power a customer may consume at a defined point of time (e.g., a 15-minute interval) in a month. Historically, residential and small commercial customers’ rates have not included demand charges; these demand charges have been part of large commercial and industrial rates. Demand charges recover a portion of fixed charges associated with capacity costs (i.e., investments in generation, transmission, and distribution) to ensure that the utility has the capability to meet customers’ peak demand even if that capacity is not used every hour. While demand charges vary with peak usage, they may be considered fixed charges for some period (e.g., during a period established in the tariff that sets the demand charge equivalent to a customer’s highest usage during a month, season, or year, after which the demand-charge level may be reset to reflect the customer’s new peak usage during that operative period).
  • Other charges on a customer’s bill might include a system benefit charge to recover the costs of utility energy efficiency programs, low-income discounts (from non-low-income customers), or other mandated public policies. System benefit charges are generally assessed on a cents/kWh basis but are also sometimes included in the $/month customer charge. System benefit charges are sometimes included in the rates for all customers, even where customers have the option to purchase generation service from an entity other than the utility.
• Once costs are assigned to a category, they are divided by a forecast or estimate of the number of units expected to be sold in that category (billing determinants) in order to determine the rate. The billing determinants are the number of customers for the customer charge, kWh of usage for the energy charge, and kW of demand (peak usage at a point in time) for the demand charge.

Decisions about whether to recover costs in customer, energy, or demand charges are policy choices based on how customers use the electricity system, the costs incurred to serve those uses, and other factors—such as, customers’ ability to respond to and modify their usage in response to the price signals sent by rates. (For example, large electricity users, particularly large commercial and industrial customers, have historically been more sophisticated with respect to billing and energy management, especially where electricity costs are a significant portion of their budgets.) While kWh usage/consumption and costs are clearly interrelated in some instances (e.g., consumption levels driving fuel costs associated with producing power), the association between consumption and

costs is less clear in other instances (e.g., usage levels that affect distribution investments which tend to be relatively capital intensive and thus fixed over a period).

Mechanics of Net Metering and Variant Options

Under traditional net metering, customer-sited generation offsets usage or consumption, effectively crediting the generation at the retail energy rate (cents/kWh) and excess generation exported to the grid is similarly credited at the retail rate. In a number of jurisdictions, customers can use these credits to offset their customer charge ($/month) and any other charges on their bill, further reducing payments they would have otherwise made to the utility. In some jurisdictions, under traditional net metering, the credit for BTM DG production may be reduced by system benefit charges so that it is not equal to the full retail rate, with the intent that net metering customers contribute to paying for these system benefits.

As customer electricity usage and, in the case of BTM DG, production changes the utility’s cost recovery will change absent a change in rate structure, both in terms of the amount collected and from which customers it is collected. If a customer reduces their consumption from the utility because they install solar (or undertake energy efficiency), the utility’s revenues (and cost recovery)¹⁰ will similarly be reduced. With the increasing deployment of BTM DG under traditional net metering, customer consumption, and therefore utility revenues, have been declining.¹¹ There are a number of rate design options to address declining (or increasing) cost recovery. Ideally, increased BTM DG has also decreased the utilities’ costs. In most cases, the change in the costs have not matched the changes in the revenues from the associated customers, creating a new challenge in the standard calculation of rates needed for cost recovery.

• Decoupling: Decoupling is a mechanism that utilities can use to adjust rates to align cost recovery between rate cases and has been widely adopted related to energy efficiency.¹² It de-links or “decouples” revenues from sales,¹³ allowing

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¹⁰ While increased BTM DG may also decrease the utilities’ costs, in many cases, the change in costs has not matched the change in revenues from the associated customers.

¹¹ Conversely, other changes in the evolving electricity system, such as electrification of transportation and buildings, will lead to increased consumption and utility revenues. This suggests that any rate mechanism to account for consumption levels that differ from forecasts should operate in both directions.

¹²Subramanian, S., W. Berg, E. Cooper, et al. 2022. “2022 State Energy Efficiency Scorecard.” American Council for an Energy-Efficiency Economy. https://www.aceee.org/sites/default/files/pdfs/u2206.pdf. See pp. 46, 49–51, table by state including both electric and natural gas decoupling yes or no for each state.

¹³ Ratemaking approaches such as performance-based regulation can also be viewed as de-linking revenues from sales because they base rates or adjustments to rates on outputs or performance, unlike traditional regulation that bases rates on inputs or costs.

• rates to adjust with changes in sales to achieve a revenue level previously approved in a rate case. When usage or sales are declining, these adjustments increase the cost per kWh and can have a differential impact on bills for different customers. Customers without BTM DG will experience increased bills (all else equal) compared to customers with BTM DG. (In fact, under traditional net metering, customers with BTM DG will see an increase in their credit value as rates increase.)
• Net Billing, with reduced credits for the exported generation: Another way to reduce the impact on utilities of reduced revenues resulting from net metering BTM DG is to credit excess generation exported to the grid (or outflow) at a rate that differs from the retail rate. This rate could be administratively determined, based on avoided costs, wholesale market prices, or the value of solar. Depending on how avoided costs are calculated (including wholesale, retail, and other utility costs) to arrive at a credit, then rates and costs could be aligned. An administratively determined rate or wholesale market price that is less than retail rates will reduce the cost to the utility of net metering credits. If the value of solar is less than the retail rate, the cost of credits to the utility will be reduced. If the value of solar includes societal costs (e.g., health and climate benefits) that are external to the utility, its cost of credits may increase. (See Chapter 3 for a discussion of net billing adoption and Chapter 4 for a discussion of impacts on the utility, society, and customers with and without DG.)
• Increased Customer or Other Fixed Charges: As an alternative to increasing energy rates, utilities can mitigate the cost recovery effect of declining usage by recovering more of their costs in another charge on the bill. Options include the monthly customer charge or another new fixed charge. In states with significant increases in BTM DG, these options have received increasing attention in net metering policy discussions. (They are discussed further in Chapter 3.)
• Minimum Bill: An alternative to an increased or new fixed charge is a minimum bill. Customers would pay a minimum amount to the utility every month regardless of their level of consumption. The level could generally be set such that average monthly bills for customers without BTM DG would exceed the minimum so that they would not see bill increases. For customers with BTM DG, the minimum bill might exceed their new level of usage. To the extent that customers cannot use credits from net metered BTM DG, the credits could be carried over to future months or cashed out at the end of a year or another time period. Minimum bills can be tiered by average usage level or income to ensure that they do not increase costs for low usage, low income, or otherwise disadvantaged customers. (See Chapter 5 for further discussion of the importance of addressing these equity concerns.)

• Time Varying or Time-of-Use Rates: To the extent that utility costs vary by time of day or season of the year, the energy charge can be based on time of use to better align rates with costs. With time-varying rates, customers who reduce their consumption through BTM DG and export excess generation to the grid during time periods with high costs may not reduce utility cost recovery to the degree that they would with flat energy charges because the reduction in utility revenues is aligned with the reduction in utility costs. Consequently, the utility would not have to increase rates to maintain revenues, which can shift costs from customers with BTM DG to customers without. (See further discussion in Chapters 4 and 5.)
• Standby or GridAccess Charges: Another rate design option that introduces fixed charges applicable only to customers with BTM DG is a standby or “grid access” charge. It is a fixed monthly charge for the ability to connect to and rely on electricity from the grid when BTM DG is not producing and results in revenues to the utility to offset those lost due to reduced usage or consumption. Standby charges have been applied to large commercial and industrial customers with their own generation (often cogeneration) for some years. Grid access charges have been proposed more recently in nine states but have generally not been implemented. (See Chapter 3 for further discussion.)

Further Considerations Affecting Rate Design

Setting rates to recover utility costs of service is a key principle guiding ratemaking. It can help to avoid negative impacts and inaccurate price signals for all customers. However, as noted earlier, rate design requires balancing several considerations in addition to cost recovery, including rate simplicity, fairness, and gradualism, among others. These are discussed further in Chapter 7 and should be considered as policymakers look at net metering and ratemaking variants. Net metering alternatives, outside of ratemaking, also warrant consideration.

REPORT STRUCTURE

Based on the committee’s statement of task, this report addresses numerous issues associated with net metering. These include trends in the deployment and costs of on-site DG and the use of net metering policies; economic, equity, technology, and regulatory policy considerations relevant to net metering and its variants; and the committee’s perspectives on the roles that net metering, its variants, and other alternative policies may play in the future.

The committee recognizes that coordinating the evolution of net metering with broader electricity system changes will lead to a vastly superior outcome than addressing net metering without due consideration of its context. Therefore, the committee began its exploration by establishing a common understanding of net metering terms and its relationship to rates, how BTM DG with net metering works, and past and recent policy trends. With this background, the committee analyzed the economic, equity, technology, and regulatory considerations that policymakers should take into account as they develop and modify net metering and other policies to enable customer adoption of BTM DG and other distributed energy resources (DER). The committee then summarizes its finding and recommendations for the evolution of net metering to advance a decarbonizing, equitable, and resilient electricity system. Briefly,

• Chapter 1, Introduction, begins with the committee’s statement of task, definitions, and basic ratemaking.
• Chapter 2, Net Metering 101, explains the mechanics of the system to the lay reader.
• Chapter 3, Background and History, Current Status, and Near-Term Future of Net Metering, lays out the current state of and trends pertaining to DG technology adoption, costs, and net metering policies.
• Chapter 4, Economic Considerations Related to Net Metering, addresses economic and rate design considerations.
• Chapter 5, Equity Considerations of Net Metering, discusses the equity outcomes associated with net metering.
• Chapter 6, Net Metering and Distributed Energy Technologies, then provides an overview of the effect on the grid of relevant technologies influenced by net metering and grid technologies to integrate, manage, or control them.
• Chapter 7, Regulatory, Legal, and Market Considerations, presents a discussion of the legal and regulatory context and considerations for net metering policy.

The committee presents possible futures and outcomes and lists all recommendations from the report in Chapter 8, The Future of Net Metering in an Evolving Electricity System.