7

Regulatory, Legal, and Market Considerations

Prior chapters have focused on several important considerations in the design of net metering and variant ratemaking approaches to meet a range of short- and long-term objectives of policymakers, consumers, and others. Chapter 3, for example, explains the trends in adoption of net metering and in state regulators’ consideration of whether to modify net metering design over time and, if so, how. Chapter 6 described technical issues associated with the grid’s ability to function reliably with the injection of power from behind the meter distributed generation (BTM DG) and the need for investment in the distribution system to capture the benefits it can potentially provide. Chapter 4 discussed the importance of economic efficiency principles in designing utility rates generally and in establishing levels of compensation for BTM resources’ exports to the grid. Chapter 5 addressed key equity considerations that need to be taken into account in designing rates for BTM resources while assuring the affordability of basic electricity services and access to DG benefits for all, including those not able to adopt such BTM resources themselves.

In practice, utility ratemaking takes technology, efficiency, and equity issues into account while also balancing other and sometimes competing goals.¹ Indeed, legislatures and regulators make policy decisions about electric utility services and rates, including net metering approaches, that often rely on considerations other than efficiency, equity, and technical issues in setting rates.

This chapter examines the range of legal and regulatory considerations that, among other things, affect the pace and character of adoption and evolution of net metering policies across states and across utility service territories even within a state. The focus here is on understanding these regulatory and legal topics from the vantage point of their interaction with net metering issues, and to help identify policy considerations that can enable technology deployment and competitive markets for innovative

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¹Solar Electric Power Association. 2013. “Ratemaking, Solar Value and Solar Net Energy Metering—A Primer,” pp. 5–6. Washington, DC: Solar Electric Power Association. https://www.energy.gov/sites/prod/files/2015/03/f20/sepa-nem-report-0713-print.pdf.

technologies, and that support a decarbonizing, equitable, economically efficient, and resilient electricity system.

This discussion begins with an explanation of federal versus state regulatory jurisdiction over the electricity industry and BTM resources, and then explores several regulatory, legal, and market considerations relating to net metering, largely at the state level. This chapter includes:

• The jurisdictional split over the regulation of wholesale versus retail sales of electricity.
• Status regarding federal regulation of net metering.
• State regulation and net metering policy, including traditional electric utility ratemaking principles, power acquisition principles, and other policies pertaining to the evolving relationships between electricity customers, their utility service providers, and non-utility electricity product and service providers.
• The electric utility’s traditional obligation to serve and its implications for the provision of utility service to customers that adopt technologies that provide part of their power needs.²
• Issues related to rights and responsibilities of different entities (e.g., the owner of on-site equipment that feeds supply into the grid; the utility that interconnects BTM resources onto the system; and regulators that set net metering rates) involved in DG that feeds into the grid, given different contractual or tariffed services.
• Insights about how net metering interacts with local circumstances, including the penetration levels of BTM resources on a local system, different electric utility ownership forms, electric industry structure, the presence or absence of different regulatory policies (e.g., revenue decoupling), and the existence of complementary federal and state policies affecting the adoption of BTM resources.
• Principles for the constructive design of policies that aim to launch and invigorate markets for the supply and demand for new technologies, including clean DG.³
• Findings and recommendations.

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² The committee’s statement of task includes “The committee will consider how new technologies and their attendant new capabilities alter the roles of the participants in the system, the requirements of each participant to fulfill those roles, and the challenges and opportunities present.”

³ The committee’s statement of task includes “The study will give recommendations on key principles for policymakers when considering net metering and alternative policies.”

THE JURISDICTIONAL SPLIT OVER REGULATION OF WHOLESALE VERSUS RETAIL SALES OF ELECTRICITY

In the United States, regulation of the electricity industry is split between federal, state, and local governments, and by activity:⁴

• Retail sales: State and local regulation and control. The prices, terms, and conditions of sales to end-use electricity customers are subject to state regulation for services provided by investor-owned electric utilities and to the decisions of elected or appointed boards of directors of publicly owned electric utilities.⁵
• Wholesale sales: Federal regulation. The Federal Power Act authorizes and directs the Federal Energy Regulatory Commission (FERC) to regulate, among other things, the prices, terms, and conditions of sales of electricity (i.e., sales for resale; wholesale sales) and transmission service in interstate commerce.⁶

This means that the design of rates for the purchase of electricity by customers with BTM resources is subject to pricing decisions of state regulators for investor-owned utilities and of boards of publicly owned distribution utilities. Exports of power for sale or for compensation (e.g., to the utility or an independent power supplier or other entity) tend to be subject to state and local regulation and decisions rather than federal, except potentially (as discussed further in this chapter) where such exports take on the characteristics that create conditions resembling a relatively persistent export of electricity to the grid—and thus, a sale for resale.

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⁴ For a detailed discussion of federal versus state regulatory jurisdiction and policy in the electric industry, see NASEM (National Academies of Sciences, Engineering, and Medicine). 2021. Chapter 3 in The Future of Electric Power in the United States. Washington, DC: The National Academies Press. https://doi.org/10.17226/25968 (hereafter NASEM, The Future of Electric Power).

⁵ Here, “publicly owned utility”refers to utilities that are not owned by investors. Publicly owned utilities thus include municipal utilities, cooperative utilities, and utilities that are public special purpose districts. There are a few states (e.g., Vermont 30 V.S.A. § 203 Jurisdiction of Certain Public Utilities) where the state regulatory agency has some jurisdiction of publicly owned utilities.

⁶ 16 U.S.C., 824(a). “The Federal Power Act (FPA) authorizes the Federal Energy Regulatory Commission (FERC) to regulate ‘the sale of electric energy at wholesale in interstate commerce,’ including both wholesale electricity rates and any rule or practice ‘affecting’ such rates.” 16 U.S.C. §§ 824(b), 824d(a), 824e(a). But it places beyond FERC’s power, leaving to the states alone, the regulation of “any other sale” (i.e., any retail sale) of electricity. § 824(b). FERC (Federal Energy Regulatory Commission). 2016. Federal Energy Regulatory Commission v. Electric Power Supply Association, et al. U.S. Supreme Court, No. 14-840. https://www.justice.gov/sites/default/files/osg/briefs/2015/01/28/ferc_v._epsa_app.pdf (hereafter FERC v. EPSA). Note that because most of Texas (i.e., the part known as the Electric Reliability Council of Texas [ERCOT]) is electrically isolated from other states’ electricity systems, wholesale electricity in Texas does not trigger the “in-interstate-commerce” provision of the Federal Power Act, and FERC does not have jurisdiction over the terms and conditions of sales for resale in the ERCOT portions of Texas.

FEDERAL RATE REGULATION AND NET METERING

To date, relatively few, narrow circumstances exist where FERC may—and does—regulate rates for exports into the grid from BTM resources. For example, where distributed energy resources (DER) (e.g., demand response; rooftop solar) are offered as supplies in organized wholesale competitive markets,⁷ prices (and, thus, compensation for exports) in those markets are FERC-regulated and established through market-based mechanisms, even though the resources can be located on and interconnected with the distribution system.⁸

FERC regulates the rates of BTM generation as “qualifying facilities”(QFs) under the Public Utility Regulatory Policies Act (PURPA)⁹ where that generating capacity (e.g., rooftop solar or combined heat and power cogeneration facilities) is sized larger than the host end-use-customer’s loads and thus causes that electricity customer to be a chronic, net-exporter to the grid.¹⁰ Under PURPA, QFs must be paid a price set at the avoided cost of the purchasing utility.¹¹ The PURPA avoided cost rate is determined by the state public utility regulatory authority.¹²

That said, a customer seeking to add on-site solar and storage equipment that exceeds the on-site loads for some period of time—say, 2 years ahead of purchasing an electric vehicle which would then increase on-site electricity demand—could unwittingly trigger

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⁷ “Organized markets” is the term used to describe wholesale power markets established in and administered by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs). All of the nation’s RTOs operate mandatory centralized, bid-based, security-constrained wholesale electric energy markets, while a few RTOs (i.e., New England ISO-NE, New York Independent System Operator NYISO, and PJM Interconnection) also operate centralized wholesale electric capacity markets. FERC. 2021. “Electric Power Markets.” https://www.ferc.gov/electric-power-markets.

⁸FERCv. EPSA; Rossi, J. 2016. “Federalism and the Net Metering Alternative.” The Electricity Journal 29:13–18 (hereafter Rossi 2016). Note that FERC Order 2222 requires RTOs and ISOs to allow entities that pool or aggregate capabilities from multiple DER to offer those resources directly into the wholesale markets as capacity, energy, and/or ancillary services. This change may make it more attractive for DER and DG aggregation as a viable business, as compared to relying on net metering alone. Zhou, Q., M. Shahidehpour, A. Paaso, S. Bahramirad, A. Alabdulwahab, and A. Abusorrah. 2020. “Distributed Control and Communication Strategies in Networked Microgrids.” IEEE Communications Surveys and Tutorials 22(4):2586–2633.

⁹ For additional information on Public Utility Regulatory Policies Act qualifying facilities, see https://www.ferc.gov/qf.

¹⁰ The federal 2005 Energy Policy Act “catalyzed distributed generation under net metering … by encouraging state adoption of net metering policies.” Revesz, R.L., and B. Unel. 2016. Managing the Future of the Electricity Grid: Distributed Generation and Net Metering. Public Law Research Paper No. 16-09. New York: New York University School of Law. https://policyintegrity.org/files/publications/Managing_the_Future_of_the_Electricity_Grid.pdf (hereafter Revesz and Unel 2016).

¹¹Revesz and Unel 2016.

¹²NRRI (National Regulatory Research Institute). 2022a. “PURPA Tracker.” https://www.naruc.org/nrri/nrri-activities/purpa-tracker.

becoming a FERC-regulated QF under PURPA during that interim period, with potential tax consequences associated with the production and sale of power to the local utility and with different compensation consequences for the power exported to the grid (if the net-metering and net billing compensation differs from the posted avoided cost PURPA rate offered by the utility). Currently this is more of a theoretical possibility rather than something that happens in practice, but it could become more of an issue, depending on the relationship(s) between on-site use and total BTM outputs (and net exports).

To date, FERC has otherwise declined to regulate rooftop solar and some other BTM DER¹³ and has taken what one legal expert has characterized as a “hands-off approach to state net metering.”¹⁴ FERC’s hands-off policy was tested as recently as 2020 when a group asked FERC to exercise its jurisdiction over exports from BTM resources, but the agency declined to deviate from prior positions.¹⁵ Given the intensity of interest in the question of FERC jurisdiction over net metering, it would not be surprising to see this matter raised again in the future, either at FERC itself or in the courts. That said, given the current state of play on these federal and state jurisdictional issues, the committee has focused attention on actions by states and electric distribution utilities.

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¹³ “FERC decisions consistently disclaim federal jurisdiction over net metering credits, based on the principle that there is no wholesale sale of energy unless a customer consistently produces sufficient excess energy over the netting period to become a net seller rather than purchaser. Rossi 2016, p. 14. See also Hempling, S., C. Elefant, K. Cory, and K. Porter. 2010. Renewable Energy Prices in State-Level Feed-In Tariffs: Federal Law Constraints and Possible Solutions. Technical Report NREL/TP-6A2-47408. Golden, CO: National Renewable Energy Laboratory. https://www.nrel.gov/docs/fy10osti/47408.pdf.

¹⁴ Ari Peskoe at the Harvard Law School has stated that the “bottom line is that in 2001 FERC determined it had no jurisdiction over energy transfers between a retail customer and her utility so long as the consumption was greater than production” over some state-determined period. They reiterated it as recently as 2018 and 2019 in its landmark storage orders that require RTOs to provide participation models for energy storage,” pp. 2–3. Peskoe, A. 2020. “Ari Peskoe, Director of the Electricity Law Initiative, on Comments Filed in Opposition to Net Metering Petition, June 10, 2020.” Environmental and Energy Law Program, Harvard Law School. http://eelp.law.harvard.edu/wp-content/uploads/Transcript-of-Ari-Pesko-on-FERC-filing-6-10-20.pdf.

¹⁵Raskin, D.B., and R.L. Roberts. 2020. “Petition for Declaratory Order of New England Ratepayers Association Concerning Unlawful Pricing of Certain Wholesale Sales.” United States of America before the Federal Energy Regulatory Commission. New England Ratepayers Association, Docket No. EL20-42-000. https://s3.documentcloud.org/documents/6843679/Nera-Proposal.pdf; TFERC dismissed the petition on procedural grounds; FERC. 2020c. Order Dismissing Petition for Declaratory Order. 172 FERC 61,042. New England Ratepayers Association, Docket No. EL20-42-000. https://www.ferc.gov/sites/default/files/2020-08/EL20-42-Order.pdf.

STATE RATE REGULATION, SUPPLY ACQUISITION, AND NET METERING

Most of the action on net metering policy thus resides at the state and local level—at state legislatures and/or before state utility commissions, or at the boards of publicly owned utilities that set policy directions, rates, and resource procurements of retail electric utilities.

State Action on Net Metering

States’ net metering policies—whether driven by legislative or regulatory actions—ultimately stem from the statutory authorities in a state. As described in Chapter 3, a handful of states started to experiment with adopting net energy metering requirements in the early 1980s. By the end of the 1990s, net metering programs were offered to some or all electricity customers in 22 states.¹⁶ By that point, 6 states had passed laws explicitly addressing net metering while another 14 states adopted net metering by regulation and thus through their pre-existing statutory authorities.¹⁷ As of 2021, 60 percent of the states and the District of Columbia had net metering policies or successor tariffs in place (see Chapter 3). Most of the remaining states had policies requiring compensation for distributed generation exports to the grid.

Clearly, decision makers in those local venues have to make ratemaking decisions—about net metering and about the design of other rates—that attempt to balance a number of objectives relating to utility service. As the 2021 National Academies’ study on The Future of Electric Power in the United States observed,

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¹⁶Wan, 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.

¹⁷ Across the states, where a state statute requires net metering, this requirement tends to apply to all utility service territories in that state; where regulatory agencies require net metering, the policy typically only applies to investor-owned utilities in the state. See Wan, 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.

This ongoing need to balance various considerations sets the context in which state policymakers make decisions about net metering.

Principles of Regulation of Retail Rates and Net Metering

Regulatory decisions with regard to net metering tariff design also need to fit within the larger context in which utility rates are set and approved by regulators (for investor-owned utilities) and by boards of publicly owned and member-owned distribution utilities.

With regard to overall ratemaking policy, over the last century of electric utility regulation in the states, regulators have generally adhered to a number of principles as they review utilities’ rate proposals. Traditional utility ratemaking principles were explained decades ago in the seminal book on utility regulation by James Bonbright and colleagues,²⁰ and

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¹⁸ Jim Lazar of the Regulatory Assistance Project describes the regulatory compact like this: “Effectively, regulation constitutes an agreement between a utility and the government: the utility accepts an obligation to serve in return for the government’s promise to approve and allow rates that will compensate the utility fully for the costs it incurs to meet that obligation. This implied agreement is sometimes called the regulatory compact.” Lazar, J. 2016. Electricity Regulation in the US: A Guide. 2nd ed. Montpelier, VT: The Regulatory Assistance Project. https://www.raponline.org/wp-content/uploads/2016/07/rap-lazar-electricity-regulation-US-june-2016.pdf.

¹⁹ NASEM, The Future of Electric Power, pp. 118–119.

²⁰Bonbright, J.C., A.L. Danielsen, and D.R. Kamerschen. 1988. Principles of Public Utility Rates. 2nd ed. Dumfries, VA: Public Utility Reports, Inc.

include not only economic efficiency,²¹ equity, and fairness²² (discussed at length in Chapters 4 and 5 of this report), but also ensuring financial sustainability for the utility,²³ providing rates that are simple to understand and relatively stable over time,²⁴ and supporting electricity system goals (e.g., reliability and resource conservation).

As utility service has evolved from a unidirectional flow of power from the utility to customers in exchange for their payments for utility service, to the current bi-directional situation where some utility customers may not only consume power from the grid but also produce power and inject it into the electric system, there have been many attempts to adjust some traditional ratemaking principles so that they adapt to the new conditions.²⁵

Table 7-1 offers an example of an update of such principles and compares traditional ratemaking principles (by Bonbright and colleagues) with those offered by e-Lab experts

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²¹ According to the economic-efficiency principle, rates should be designed so that they signal to customers the full social marginal costs associated with providing them with service and create incentives for customers to make their own decisions about using electricity in ways that are aligned with short- and long-term costs of the system. (However, rates are generally set based on a utility’s cost to serve, which does not usually include externalities such as health and environmental costs of the electricity system, and thus would not be economically efficient.)

²² The equity and fairness principle incorporates several elements. On the one hand, similarly situated customers (e.g., residential customers with basic usage patterns) should face nondiscriminatory rate structures, such that they have the same opportunities to purchase electricity service under common rates, terms, and conditions, as compared to other sets of customers with different usage patterns (e.g., residential customers with large seasonal electrical demands, or industrial customers with flat usage patterns). But, on the other hand, due discrimination in ratemaking may be needed to ensure that all consumers—even those with low incomes—can access basic electricity service.

²³ This principle addresses the need for the local utility to be financially sound, able to recover its costs of providing service to consumers, and capable of attracting capital at reasonable cost (including through a fair rate of return on investment).

²⁴ The simplicity principle has long been a feature of rate design, especially for small electricity customers, and is one of the reasons why states have adopted net metering to compensate residential customers that adopt BTM resources. The principle of rate stability is sometimes called gradualism, such that changes in rates should be introduced gradually over time rather than through changes that are either sudden or shocking to consumers.

²⁵ See Lazar, J. 2016. Electricity Regulation in the US: A Guide. 2nd ed. Montpelier, VT: The Regulatory Assistance Project. https://www.raponline.org/wp-content/uploads/2016/07/rap-lazar-electricity-regulationUS-june-2016.pdf.

TABLE 7-1 Principles of Public Utility Rate Regulation

SOURCE: Electricity Innovation Lab, 2014, “Rate Design for the Distribution Edge: Electricity Pricing for a Distributed Resource Future,” Mountain Institute, https://rmi.org/insight/rate-design-for-the-distribution-edge-electricity-pricing-for-a-distributed-resource-future. CC BY-SA 4.0.

at the Rocky Mountain Institute.²⁶ These long-standing rate-design principles, informed by an updated interpretation of the future grid’s conditions, are relevant for understanding the balance of considerations needed to shape the evolution of net metering and successor policies.

In the context of net metering, traditional ratemaking principles can create tension across objectives, depending on a number of considerations. For example, as BTM technologies with declining costs provide customers with the opportunity to better manage their electricity bills with on-site generation and those customers take advantage of net metering, the utility may not recover from that customer all of the costs to serve them under some net metering rate designs and service-territory conditions.²⁷ In that case, the ratemaking goal of “revenue sufficiency” will mean that other customers will have to pick up some of the costs to serve the customer who has BTM generation (see Chapter 4). Such an outcome could raise equity and fairness concerns for non-participating customers, particularly if they tend to be otherwise historically disadvantaged, such as lower income (see Chapter 5).²⁸ The timing and character of ratemaking reforms to address these outcomes will be influenced in many instances by the principles of simplicity and gradualism, and other considerations (e.g., the extent to which utility rates capture environmental externalities of electricity production).

Principles of Retail Regulation of Utility Payments for Power Supply

As noted above, the adoption of BTM resources creates circumstances in which the customer that adopts the technology ends up producing more power than its on-site electricity consumption and exports power to the grid. In effect, the utility is purchasing such power supply and compensates the customer/supply for those exports. State

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²⁶ See p. 38 in Glick, D., M. Lehrman, and O. Smith. 2014. Rate Design for the Distribution Edge: Electricity Pricing for a Distributed Resource Future. Boulder, CO: Electricity Innovation Lab, Rocky Mountain Institute. https://rmi.org/wp-content/uploads/2017/04/2014-25_eLab-RateDesignfortheDistributionEdge-Full-highres-1.pdf. Table 7-1 appeared in Tierney, S.F. 2016. The Value of“DER”to“D”: The Role of Distributed Energy Resources in Supporting Local Electric Distribution System Reliability. Denver, CO: Analysis Group, Inc. https://www.analysisgroup.com/globalassets/content/news_and_events/news/value_of_der_to-_d.pdf.

²⁷ Such a situation might occur where the following combination of conditions exists: where the utility’s retail rate design recovers a significant portion of the utility’s fixed costs through charges that vary with customer usage (e.g., energy [per-kWh charges]), where the variable energy charge is higher than the utility’s avoided cost, and where other charges (e.g., customer charge, any capacity or grid access charge, and back-up charges) that are not part of the tariff and possibly are not set at cost.

²⁸ If the BTM DG does not provide benefits to the system as a whole. Additionally, increasing the price of electricity could work counter to a jurisdiction’s electrification goals if it has them.

regulators typically review and approve the terms and conditions under which a utility purchases power from third parties.

Utilities rely on various resources to supply electricity to consumers: from the large and small generating facilities they own; through contracted-for power supply obtained through competitive procurements; through as-available PURPA power supplies; and through resources located on customers’ premises that export power.²⁹ With regulatory approval, supplies of electricity thus tend to be paid for through either: cost-based approaches (e.g., for utility-owned assets), market-based prices (e.g., prices arrived at in competitive procurements, or competitive wholesale markets), or set at the utility’s avoided cost (e.g., for PURPA purchases).³⁰

In the committee’s judgment the utility’s compensation to suppliers is thus tied to assets owned by the utility or supplied by an independent non-utility party.³¹ In the latter case, the utility’s compensation to the power supply tends to be tied to the attributes of the supply and their value to the utility: whether the energy is dispatchable or supplied on an as-available basis (with the former often valued more highly); whether the resource can provide black start or other ancillary services; whether the utility gets the benefit of relying on the resource’s capacity when it is of value to the electric system; whether the facility provides other energy services (such as ability to adjust output in response to changes in utility demand, or the ability to provide local reliability value on the transmission or distribution system); whether the resource has environmental attributes such as renewable energy credits (RECs) or zero-emissions credits (ZECs) that are sold to the utility (at a price) or retained by the facility owner. Often, such electricity services (i.e., electrical energy and capacity, RECs, and ZECs) are supplied at market-based prices or paid for at avoided cost.

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²⁹Rea, J., and O. Ugwu-Oju. 2022. “Why Purchased Power Is Such a Big Deal to Better Understand US Utilities’ Climate Impact.” https://rmi.org/why-purchased-power-is-such-a-big-deal-to-better-understand-us-utilities-climate-impact.

³⁰Cleary, K., and K. Palmer. 2022. US Electricity Markets 101. Washington, DC: Resources for the Future. https://www.rff.org/publications/explainers/us-electricity-markets-101.

³¹ Allen, N., A. Clair, M. McNaul, R. Shelton, and J. Williams. 2021. PURPA: Title II Compliance Manual 2.0. Thompson Coburn LLP. https://pubs.naruc.org/pub/47AD30DC-1866-DAAC-99FB-975A60906D6B; Edison Electric Institute. 2000. “Master Contract.” April 25. https://www.eei.org/resources-and-media/master-contract.

THE UTILITY’S OBLIGATION TO SERVE AND ITS RELATIONSHIP TO CUSTOMERS THAT ADOPT TECHNOLOGIES THAT PROVIDE PART OF THEIR OWN ELECTRICITY NEEDS

In the traditional utility business, legal, and regulatory model, a single electric distribution utility enjoys the exclusive right to provide service within the boundaries of a given service territory (sometimes called the franchise area) in exchange for that utility having the requirement to provide electricity service to any and all existing and new customers within that service territory. This combination—of the obligation to serve and exclusive franchise conditions—applies to both investor-owned utilities and publicly and member-owned utilities. All types of utilities operate with the long-standing expectation³² that rates will be set to recover the cost of providing service to customers. Investor-owned utilities also expect the opportunity to earn returns allowed by the regulator. This obligation to serve at predictable prices or rates is a foundational principle of the standard regulated monopoly utility model.³³

The advent of BTM DG technologies affords electricity customers the option to have some or all of their electricity supply provided by some entity (e.g., themselves) other than the local distribution utility or a power marketer. This opportunity to self-supply using BTM generation gained some prominence several decades ago as large industrial customers installed cogeneration systems that could provide power and steam to their industrial facilities, and in effect bypass the local utility for some of that customer’s electricity needs. That technology helped to spawn the development of independent power facilities that could sell some or all of their output into the grid—which in turn was enabled by the enactment of PURPA, which gave QFs the right to sell their output to the utility at its avoided cost. (That movement also spurred the adoption of retail electricity choice in approximately a third of the states.³⁴) More recently, net metering policy has similarly supported the ability of a customer to adopt BTM DG technology to self-supply part or all of their demand and to inject surplus power into the grid.

Under the standard utility model with its obligation to serve, the local distribution utility holds the requirement to supply any, and in many instances all, of a customer’s power needs whenever that customer’s onsite technology is not providing those services.

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³² For additional information see https://emp.lbl.gov/webinar/recovery-utility-fixed-costs-utility.

³³ NASEM, The Future of Electric Power, pp. 117–118.

³⁴ This includes the following states (plus the District of Columbia) that adopted full or partial retail electricity choice: California, Connecticut, Delaware, District of Columbia, Georgia, Illinois, Maine, Maryland, Massachusetts, Michigan, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Texas, and Virginia. NREL. n.d. “An Introduction to Retail Electricity Choice in the United States.” https://www.nrel.gov/docs/fy18osti/68993.pdf.

Unless a customer with on-site generation (and/or storage) fully and completely disconnects from the grid, the utility continues to face the requirement to plan for, invest in, and operate the system to meet whatever needs those customers have from the grid.³⁵

This latter condition means that the utility incurs costs to serve the customer with onsite generation; this arises where the customer relies on the grid to import power when needed or to export power when it exceeds on-site loads, as occurs with net metering. Under the standard utility cost-recovery model, rates are set to cover the cost of the utility’s prudent³⁶ investments and expenses to provide that service. Under standard rate design principles, rates to a particular set of customers are designed to collect the costs incurred to serve those customers.

But, as illustrated in the example described above and discussed in Chapter 4, circumstances may exist³⁷ where net metering customers’ payments to the utility do not cover the costs to provide them with electricity service, and those costs may need to be recovered from other customers. In such situations, there is an asymmetrical obligation to serve and obligation to pay, where the utility has to be ready to serve whenever the customer needs or wants to either withdraw power from the grid or inject surplus electricity into the grid from the BTM resources. This is one of the reasons why, at least in utility service territories with relatively high levels of deployment of rooftop solar, there has been pressure from low-income consumer advocates in some instances, and from utilities, to reform rates for customers with on-site generation so that they pick up more, if not all, of the utility’s costs to provide them with service (see discussion in Chapters 3 and 4).³⁸

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³⁵ Note that in many jurisdictions where customers with cogeneration facilities have the ability to generate their own power, the utility is allowed to charge standby and back-up rates to cover the utility’s cost to be ready to serve those customers’ needs when their own generation is not available.

³⁶ In traditional electric utility regulation, the concept of “prudence” is a key ratemaking concept and refers to a standard of review to determine whether a utility’s investments and expenditures may be recovered in rates charged to consumers. A prudency determination examines whether the utility’s costs were reasonable at the time they were incurred, in light of the circumstances and what was known or knowable at the time.

³⁷ This could occur, for example, where the utility’s retail rate design recovers a significant portion of the utility’s fixed costs through variable energy charges, where those charges are higher than the utility’s avoided cost, and where other charges are missing or not set at costs, or both. There are also circumstances in some places where the customer taking service under net metering ends up paying the full cost the utility incurs to provide it with service.

³⁸ Note that customers with BTM DG who participate in net metering may be providing benefits for all customers (e.g., reducing carbon and pollutant emissions) but these externalities are generally not factored into or able to offset costs utilities incur.

CONSIDERATIONS FOR CONTROL OF NET METERING CUSTOMERS’ DER ASSETS

The existence of customer-sited generation, which may be facilitated or supported by net metering, with the potential to export power to the grid poses ownership and control challenges while also enabling new ways to manage and supply the grid.

Using rooftop solar, with and without storage, as an illustrative example, consider the following: The equipment on the roof and the storage system may be owned by an entity different from the customer, including the building owner, the utility, or an independent vendor that has the approval to install the equipment on the premises, with a contractual relationship to the building owner. The BTM equipment interconnects to a distribution system owned by the utility. Under net metering arrangements in most jurisdictions to date, a customer with a BTM DG resource has the option to rely on that resource when it is available and to call on power from the grid when it is not. Depending on the terms of the tariff through which the electricity customer buys electricity service from the utility, the customer (or the owner of the BTM equipment) has ultimate control when it injects power produced or stored into the local grid unless they cede it to the utility.³⁹

A project where the customer prefers (and has the technical means) to maintain full control over when to draw power from the grid and when to inject it into the grid may have different operational and cost implications for the utility’s operations than a project where the customer has an agreement with the utility for the latter to control when to inject energy into the grid. The former maintains the customer’s private option value to use the grid at will; the latter may limit some of the customer’s own private value proposition in owning or hosting DG equipment but increases the value proposition to the utility and its other customers (thus meriting greater compensation to the customer or equipment owner, which can offset any loss of private value).

The interactions among (1) BTM technologies and the local distribution system, (2) the customer’s ability to determine whether they maintain the ability to control exports to the system at different times and levels of output, and (3) the need for the utility to maintain reliable and resilient service to all of its customer base, together mean that the utility may need to invest in communications and control technologies on the distribution

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³⁹ In most jurisdictions, the utility maintains the ability to disconnect the customer’s equipment to prevent it from injecting power into the grid for emergency safety and potentially other reasons. Note that there is some interchangeability between direct utility control over DG assets located on the customer’s premises and price signals that either incentivize or commit the customer to operate its system in the same manner. The most clear-cut example is direct load control programs versus DR call options (in which the utility has a service agreement with a customer that allows the utility to call on the customer to provide the demand reduction when a particular price or other condition occurs).

system so that the utility has visibility into conditions on its system. Regulators, in turn, will need to view these investments as critical elements of the transitions occurring at the grid edge and in many cases enabled by net metering policy, and approve recovery of their costs (see further discussion in Chapter 6).

INTERACTIONS OF NET METERING WITH LOCAL REGULATORY POLICIES AND CONDITIONS

As described in Chapter 3, the pace of deployment of DER across the country varies considerably, in part due to differences in local conditions affected by state regulatory policies, the structure of the electric industry in the state, the current generation mix, the maturity of the local DG market, and other drivers such as the quality of solar resources, the price of electricity,⁴⁰ and vulnerability to extreme weather events. Of these, legislative and regulatory directives to implement net metering policies—or to block them—play significant roles.

For example, the corporate character of electric utilities can sometimes play a role in either impeding or enabling the adoption of both net metering as well as BTM DG and other DER, such as rooftop solar. Most end-use and retail electricity customers in the United States are served by an investor-owned utility (IOU) whose rates are subject to regulation by state public utility commissions even though most local utilities are actually publicly owned—because they are either part of a local municipal government or a member-owned cooperative electric utility, or even a special-purpose utility district (e.g., an irrigation district) that evolved historically to supply power to local constituents.⁴¹ Most of these publicly owned utilities provide only distribution service, with their power supplied by publicly owned generation and transmission utilities (e.g., the Tennessee

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⁴⁰ For example, among states that offer net metering at or close to retail rate, rooftop solar adoption per capita is higher in states with higher electric rates. See Davis, L. 2020. “Putting Solar in the All the Wrong Places.” Energy Institute Blog. Berkley, CA: Energy Institute at HAAS. https://energyathaas.wordpress.com/2020/02/03/putting-solar-in-all-the-wrong-places.

⁴¹ “In 2018, even though there are fewer than 200 investor-owned utilities (compared to approximately 2,900 publicly owned utilities (including cooperatives, municipal utilities, and special-purpose utility districts), approximately three-quarters of all retail power went through the local distribution systems of these investor-owned utilities (EIA 2019a,b). Because cooperatives serve rural areas, the geographic footprint of their systems is often large … and more of their sales are to residential customers (over 50%) as compared to other distribution utilities (whose residential sales account for about a third of all retail sales).” (Footnotes in the original have been omitted.) EIA (U.S. Energy Information Association). 2019a. “861 Electric Data.” https://www.eia.gov/electricity/data/eia861; EIA. 2019b. “Electric Sales, Revenue, and Average Price.” October. https://www.eia.gov/electricity/sales_revenue_price; NASEM, The Future of Electric Power, pp. 96–98.

Valley Authority and Tri-State Generation and Transmission Company) or investor-owned utilities.

As explained in the National Academies’ 2021 study The Future of Electric Power in the UnitedStates, the varied institutional, financial, and governance structures of these many types of utilities create different systems of incentives and constraints on their willingness and ability to innovate as they carry out their public service obligations.⁴²

For example, an IOU with a traditional rate design that collects the utility’s fixed costs (including return of and on investment) largely through variable energy charges and whose rates are set through traditional general rate cases without revenue decoupling will likely experience erosion of electricity sales and revenues with customers’ adoption of BTM generation. This may position that utility’s financial interests in tension with customers’ interests in the adoption of BTM, and this tension may be exacerbated where a net metering policy compensates those customers’ exports at a rate higher than the utility’s avoided costs. Under these circumstances, and all else equal, this utility will lose revenues and profits until rates are reset in another rate case (see further discussion in Box 7-1).

Under a similar set of assumptions, a publicly owned utility will not face the exact same financial outcomes (because it has neither shareholders nor profits), but even that utility could face financial tensions with lost sales and lost revenues resulting from net-metered BTM generation: All else equal,⁴³ that utility must eventually collect sufficient revenues to cover its costs, and must adjust rates to all of its customers over time to assure revenue adequacy.⁴⁴

A second dimension which might affect utilities’ appetite for customers’ adoption of BTM DG through the design of net metering policies and their potential impact on cost recovery is the structure of the electric industry combined with rate design in a particular place. Using the prior example, an IOU that is vertically integrated—owning generation, transmission, and distribution facilities—and has rates that are not subject to revenue decoupling and recovers fixed costs substantially through variable energy charges, will experience revenue erosion for its entire bundled rate. By contrast, an IOU that provides only “wires”service to its customers will not be exposed to erosion of revenues associated

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⁴² NASEM, The Future of Electric Power, p. 93.

⁴³ Electrification of some building end uses and vehicles over time could be expected to increase sales of electricity and may mitigate the timing or need to adjust rates to address these lost revenues from BTM generation.

⁴⁴ Also, many electric distribution coops have long-term contracts for generation and transmission service from another coop, in which there may be terms and conditions that restrict the former’s savings on variable costs.

with some or all of the generation portion of the customers’ rates (because that portion of their electricity service is supplied by a retail marketing company or default service where the utility passes through the costs it incurs).⁴⁵ The loss of profits will nonetheless may be viewed as a disincentive to customer-adoption of BTM generation (and other DER).

Wires-only IOUs operate in about a third of the United States. (Most rural electric cooperatives also only own and operate distribution facilities and buy power on an all-requirements basis from third parties, which often includes a generation-and-transmission cooperative.)⁴⁶ Thus, a utility’s attitude toward net metering is a function of many factors, including the potential impact of net metering on the utility’s earnings and the impact of net metering on non-participating customers (if their rates need to be adjusted to recover lost revenues).

As noted, net metering does not directly impact earnings, or profits (versus cost recovery), for all utility types. Publicly owned and municipal utilities are not profit-driven, although they do need to be able to finance investment and recover their costs. Not all IOUs earn profits through energy sales due to the wide adoption of revenue decoupling which is a policy mechanism through which IOU earnings are made independent of (or decoupled from) the amount of electricity they sell.⁴⁷ IOUs that do not have decoupled rates⁴⁸ are more likely to view net metering-enabled exports from BTM generation negatively because they directly impact electricity sales from utility-owned generation assets.

Profits for revenue-decoupled utilities, such as IOUs in California, Massachusetts, and New York, are not directly affected by the amount of energy sales through net metering. The profits for these companies may be indirectly affected to the extent net

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⁴⁵ Also, in states with retail choice, net metering rates often credit the customer’s exports to the grid at the generation portion of the overall rate, which further dampens the revenue erosion for the distribution utility.

⁴⁶ EIA 861 data, Sales_Utl_Customer_2021.xlsx. That spreadsheet allows for toggling, and when you toggle “service type” to show delivery only (i.e., wires) and toggle “ownership” to show investor owned, you get the following states identified (in column g): California, Connecticut, Delaware, District of Columbia, Illinois, Maine, Maryland, Massachusetts, Michigan, Montana, Nevada, New Hampshire, New Jersey, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Virginia, and Washington. EIA (U.S. Energy Information Association). 2019a. “861 Electric Data.” https://www.eia.gov/electricity/data/eia861.

⁴⁷ As of 2019, approximately half of the states had adopted revenue decoupling for at least some if not all of their electric utilities. National Governors Association. n.d. “State Energy Efficiency Policy in a New Era: A Toolkit for Governors.” https://www.nga.org/wp-content/uploads/2021/10/Energy-Efficiency-Toolkit.pdf.

⁴⁸ As of 2019, states with IOUs and without decoupling for electric utilities included Florida, Kentucky, Louisiana, Mississippi, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Carolina, South Dakota, and West Virginia. See p. 4 in Cleveland, M., L. Dunning, and J. Heibel. 2019. “State Policies for Utility Investment in Energy Efficiency.” National Conference of State Legislatures. https://www.ncsl.org/Portals/1/Documents/energy/Utility_Incentives_4_2019_33375.pdf?ver=2019-04-04-154310-703.

metering-enabled distributed generation changes the amount of grid infrastructure investments a utility needs to make, in one direction or another. For example, but for the deployment and operation of this DG resource (which could be enabled by net metering and/or other regulatory policies), the distribution utility would need to make investment on which it would be able to earn a return. In other circumstances, net metering-enabled BTM generation could trigger the need for distribution-system or infrastructure upgrades with the IOU having the opportunity to invest in and earn a regulated rate of return on that new infrastructure.⁴⁹

Estimating whether and to what extent net metering-enabled BTM generation impacts the need for infrastructure upgrades is location—and time-dependent, such that one cannot conclude a priori that it will create tensions with an IOU’s own financial incentives. Additionally, the design of any net metering variant, in combination with other regulatory tools (e.g., identification of available or constrained hosting capacity for DGs on distribution systems or policies that enable a utility to share in any avoided distribution-system costs) may affect such incentives as well, in positive or negative ways.

DG can provide benefits to the system, and thereby reduce costs, by enhancing system resilience⁵⁰ and reducing externalities associated with electricity production (as explained in Chapters 4 and 5). This consideration should be taken into account in designing net metering variant policies to compensate the supplier of BTM resources for any such resilience value supplied or externalities avoided, thus providing additional benefits to the grid and other customers or avoiding the utility’s alternative investments and associated costs to achieve that outcome.⁵¹

However, DG can introduce costs to the system for the interconnection and integration of many more devices to the grid (as discussed in Chapter 6). Such costs may include the additional controls needed to be added to the operations of the local distribution system and increased risks of cyber-attacks. These costs may increase as the penetration rates of

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⁴⁹ See Technology Chapter 6. See also Wolak, F.A. 2018. The Evidence from California on the Economic Impact of Inefficient Distribution Network Pricing. Cambridge, MA: National Bureau of Economic Research. https://www.nber.org/papers/w25087.

⁵⁰ See, for example, Converge Strategies, LLC. 2019. “The Value of Resilience for Distributed Energy Resources: An Overview of Current Analytical Practices.” Prepared for the National Association of Regulatory Utility Commissioners. https://pubs.naruc.org/pub/531AD059-9CC0-BAF6-127B-99BCB5F02198; NREL (National Renewable Energy Laboratory). 2018. “Valuing the Resilience Provided by Solar and Battery Energy Storage Systems.” https://www.energy.gov/sites/prod/files/2018/03/f49/Valuing-Resilience.pdf; Van Nostrand, J.M. 2019. “Quantifying the Resilience Value of Distributed Energy Resources Quantifying the Resilience Value of Distributed Energy Resources.” Journal of Land Use 35(1):15–34.

⁵¹ The discussion here focuses on the role of BTM DG to the grid, rather than the value BTM DG provides to the customer that puts it in place. From a customer’s point of view, the private resilience value of BTM DG (including storage) may be an important consideration in the decision to add it.

DG systems increase. Utility regulators should take into account the full range of positive and negative implications as they consider policies to support BTM DG, to compensate DG suppliers for their exports to the grid, and to allow the recovery of utility investment to integrate increasing amounts of DG into the electricity system. Otherwise, customers may forego the potential benefits of BTM DG to the system and remaining customers may need to bear costs to make sure that the operations of the grid remain reliable.

Utility regulators have a critical role to play in ensuring that net metering (or its variants) provides fair compensation that reflects the value of DG to meet energy needs and relevant policy goals (e.g., resilience and emissions reductions) while also covering the utility’s costs to provide service. Because financial considerations may create disincentives for utilities in collecting data and conducting analyses, regulators should make sure that the utility conducts the analyses necessary to determine reasonable estimates of both avoided costs and delivered benefits or make the utility’s data available to the public so that others can provide such reasonable estimates.

Additionally, policymakers, utility regulators, and boards of publicly owned utilities that seek to promote BTM generation should also recognize the importance of the distribution utility’s investment in grid technology and other enhancements to provide visibility of DG output and other communications and control technologies (as explained further in Chapter 6).

Accounting for Clean Energy and Environmental Mandates in Net Metering

Many states have some form of clean energy or environmental mandates with which utilities need to comply (see Chapter 3 for further discussion).⁵² When customers install clean DG on their premises, their power providers have to contract with or build fewer resources that qualify to meet their regulatory clean energy requirements. Therefore, customer-adopted clean DG may provide a benefit to all utility customers by deferring utility procurement of supply-side clean resources in jurisdictions with clean energy

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⁵² This can arise, for example, where BTM generation consumed onsite reduces the load-serving entity’s supply (because the grid sees the customer’s demand as having been reduced by the on-site generation) and therefore reduces the amount of renewable generation the supplier needs to arrange in order to meet RPS standards that are based on a percentage of load. In many but not all states, BTM generation—whether consumed onsite or exported to the grid—can qualify for producing renewable energy credits. Those RECs may be owned by the customer or the owner of the BTM system, depending on the terms of contractual arrangements where the customer does not own the system. If the BTM system produces RECs for the full output, then there could be double counting of the renewable generation. States may wish to ensure accounting methods take this possibility into account that appropriate accounting for the net value of such resources.

requirements (or enabling the utility to procure fewer overall clean resources). In jurisdictions where such a benefit exists, regulators (and boards of publicly owned utilities) may reflect this benefit in the compensation arrangements for DG resources.

Regulators thus seeking to assure that compensation for exports of on-site generation are valued properly may do so in ways that are consistent with other ratemaking policies and public policy considerations. For example, in principle, regulators in states with carbon-reduction commitments need to establish the carbon-reduction value of on-site DG consistent with the incremental costs to comply with their state’s clean energy policy and/or consistent with subsidies or incentives provided to other sources of zero-carbon electricity supply. Symmetrically, it would be appropriate for policymakers to also charge polluting sources for the carbon and other pollutants they emit. Box 7-2 gives an example of one state’s net metering journey.

PRINCIPLES FOR THE DESIGN OF POLICIES THAT AIM TO LAUNCH AND INVIGORATE MARKETS FOR NEW TECHNOLOGIES

The history of net metering indicates the important role that it has played in helping to support customers’ adoption of BTM technologies and to build a market for rooftop solar, in particular, where it had previously not existed. Since the first formal net metering program was put in place nearly 40 years ago,⁵³ conditions in the market for renewable BTM technologies have evolved substantially, as described in detail in the Chapter 3. The installed costs of solar panels (both rooftop and supply side) have dropped 60 percent over the past decade,⁵⁴ due in part to demand driven by states’ renewable portfolio standards (RPS) and net metering compensation arrangements, manufacturing efficiencies, and other factors. The benefits of these economic improvements have accrued not just in the states that were early adopters of net metering, but also in other states as well. Additionally, net metering has been especially successful in stimulating customer adoption of BTM technologies in the states where retail prices were high and net metering

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⁵³ Minnesota was the first state to enact a net metering program in 1983. Solar Electric Power Association. 2013. “Ratemaking, Solar Value and Solar Net Energy Metering—A Primer,” pp. 5–6. Washington, DC: Solar Electric Power Association. https://www.energy.gov/sites/prod/files/2015/03/f20/sepa-nem-report-0713-print.pdf.

⁵⁴Solar Energy Industries Association. 2022. “Solar Industry Research Data.” https://www.seia.org/solar-industry-research-data. Wood Mackenzie and Solar Energy Industries Association (SEIA) indicate that during 2022, there was an uptick in the pricing of installed solar systems to all customer segments due to a variety of factors (e.g., international trade considerations and price increases in polysilicon and other raw materials). Wood Mackenzie and SEIA. 2022b. “U.S. Solar Market Insight Report: Executive Summary—Q3 2022,” p. 16. https://www.woodmac.com/industry/power-and-renewables/us-solar-market-insight.

rate design provided an attractive financial incentive to install residential photovoltaic (PV) systems.

Thus, some of the original rationales for the adoption of traditional net metering—such as animating customer demand to help increase private investment in BTM technologies, help drive down the costs of rooftop solar, and help build the supply-side of the marketplace—have been demonstrably successful in some parts of the country.

This success after decades of experience provides an opportunity to assess the conditions under which policymakers can design second- or third-generation successor

tariffs in places where net metering has been in place for years and can fashion variant or alternative approaches where markets are less mature (see Chapter 3 which provides insights into the ways in which net metering and its variants have adapted to changing conditions over time). As with traditional regulation of utilities, one of the consequences of putting a policy incentive in place is that the constituencies that have benefitted from the current incentive become accustomed to its presence, with utilities and firms sometimes building business models designed around the incentive and with customers expecting to continue to enjoy the incentive even when changed conditions may no longer warrant the continued availability of the incentive in its original form.⁵⁵

The literature⁵⁶ on the use of economic incentives in public policies to stimulate market development for the adoption of new technologies suggests conditions under which a policy should be permanent versus “transient.” In other words, policy design (e.g., for a policy like net metering) might take into account conditions in the market and the appropriateness of temporary versus permanent incentives to encourage demand for and adoption of a technology over time.⁵⁷ Technology learning curves are relevant for aligning policy design with the accomplishment of policy objectives over time, and for identifying appropriate policy instruments—such as net metering versus net metering successor tariffs versus alternative funding mechanisms (e.g., programs supported by public budgets rather than electricity rates)—to accomplish the policy goals.⁵⁸

The National Academies’ Committee on the Future of Electric Power in the United States made this point in discussing the importance of designing policy so that it evolves over time as conditions change:

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⁵⁵ See, for example, NASEM, p. 139, “Reducing Reliance on Less-Efficient Policies May Face Opposition,” in The Future of Electric Power; Stavins, R.N., T. Schatzki, and R. Scott. 2019. “Transitioning to Long-Run Effective and Efficient Climate Policies.” M-RCBG Faculty Working Paper Series 2019-01. https://www.hks.harvard.edu/sites/default/files/centers/mrcbg/files/FWP2019-01.pdf.

⁵⁶ This literature sometimes refers to the role of technology adoption, economic and market learning curves, and “learning by doing.” See, for example, Speelman, L., and Y. Numata. 2022. “Harnessing the Power of S-Curves: How S-Curves Work and What We Can Do to Accelerate Them.” https://rmi.org/insight/harnessing-the-power-of-s-curves.

⁵⁷ See, for example, Gillingham, K., and J.L. Sweeney. 2010. “Chapter 5: Market Failures and the Structure of Externalities,”in Harnessing Renewable Energy in Electric Power Systems: Theory, Practice, Policy. New York: Earthscan; also in Researchgate. “Market Failures and the Structure of Externalities,”p. 28 of 32, and p. 85, Table 2. https://www.researchgate.net/publication/228345632_Market_Failure_and_the_Structure_of_Externalities.

⁵⁸ An example of state regulators evolving their ratemaking instruments over time is the case of energy efficiency and revenue decoupling.

That committee made a finding that is relevant for the future of net metering as a tool for advancing the development of a market for BTM technologies:

Also, state policymakers (notably, legislators and governors) should consider the value of using other policy approaches (e.g., investment incentives and other programs supported through taxpayer-funded public budgets,⁶¹ or changes in building codes⁶²) rather than electricity rates as a means to advance policy objectives relating to economic and market development, such as incentives to leverage private investment and climate-friendly energy supplies with no greenhouse gas emissions. Ultimately, such goals are societal goals rather than electricity system goals, which merit support by a broad-based funding source—and one with fewer inequitable impacts on low-income electricity customers.

FINDINGS

Finding 7-1: The design of rates for the purchase of electricity by customers with BTM DG and other DER and for compensation for their exports to the grid is subject to pricing decisions of local decision makers (i.e., state regulators for investor-owned utilities and boards of other distribution utilities). To date, relatively few, narrow circumstances exist where FERC regulates compensation or rates for net exports into the grid from behind-the-meter resources.

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⁵⁹ NASEM, The Future of Electric Power, p. 129.

⁶⁰ Ibid, p. 130.

⁶¹ The 2022 federal Inflation Reduction Act includes tax credits for homeowners that install rooftop solar, or solar + storage. See EERE (Office of Energy Efficiency and Renewable Energy). 2022a. “Homeowner’s Guide to the Federal Tax Credit for Solar Photovoltaics.” https://www.energy.gov/eere/solar/homeowners-guide-federal-tax-credit-solar-photovoltaics.

⁶²California Energy Commission. 2022. “Solar PV Systems and Solar Ready.” https://www.energy.ca.gov/programs-and-topics/programs/building-energy-efficiency-standards/online-resource-center/solar.

Finding 7-2: Decision makers have to make ratemaking decisions—about net metering and the design of other rates—that take into account not only economic efficiency and fairness considerations, but also other important principles such as revenue sufficiency for the utility, simplicity of rates, and gradualism in rate changes over time. In some jurisdictions, other important ratemaking considerations include providing rate discounts for low-income customers, clean energy, economic development, and other factors.

Finding 7-3: Because the local distribution utility has an obligation to serve, the utility has to plan for and be ready so that the electricity system can meet the needs of a customer even when that customer has BTM DG and/or storage. For example, the utility has to be able to serve the customer when they use the grid and import power or when BTM power exports to the grid. Thus, the utility incurs costs to serve such needs.

Finding 7-4: Circumstances may exist where net metering customers’ payments to the utility do not cover the costs to provide them with electricity service, and those costs need to be recovered from other customers, leading to pressure to reform rates for customers with on-site generation so that they cover more, if not all, of the utility’s costs to provide them with service. In other circumstances, the utility’s compensation to the customer for its exports to the grid may be lower than the value of the services those exports provide to the grid.

Finding 7-5: Estimating whether and to what extent net metering-enabled BTM generation impacts the need for infrastructure upgrades is location- and time-dependent, such that one cannot conclude a priori that it will create tensions with an IOU’s own financial incentives.

Finding 7-6: Utility regulators play a key role in enabling distribution system infrastructure investments where needed to integrate and manage DG technologies and installations by allowing recovery of these costs to capture the benefits of BTM DG for other customers and the system as a whole. Regulatory standards and policies that support the adoption of DG and DER technologies and systems need to be accompanied by regulatory decisions to approve investments to integrate those technologies and enable the grid to operate reliably with them in place. Such investments may take place on the utility’s, customers’, or non-utility entities’ assets.

Finding 7-7: Some of the original rationales for the adoption of net metering—such as animating customer demand to help increase private investment in BTM technologies, to help drive down the costs of rooftop solar, and to help build the supply-side of the

marketplace—have been demonstrably successful in some parts of the country where net metering has been adopted.

Finding 7-8: The success of net metering in many states provides an opportunity to assess the conditions under which policymakers can design second- or third-generation successor tariffs (or net metering variants) in places where net metering has been in place for years and can fashion alternative approaches where markets are less mature. Good policy design should build in opportunities to change incentives when objectives are met or change.

Finding 7-9: Rather than using a ratemaking tool like net metering or other programs whose costs are recovered in electricity rates in order to advance public policy goals, policymakers have the option to adopt other policies (e.g., tax-funded incentives and programs) to accomplish important societal goals. Over-reliance on net metering (as compared to other policy tools like taxpayer-funded incentives) to accomplish these objectives may lead to unintended consequences (e.g., cost shifts or lack of access to BTM technologies by low-income consumers). Because electricity rates are generally more regressive than income taxes, using taxpayer funded programs or other policy tools (e.g., regulation or performance standards) may provide more equitable outcomes than using electricity rates to accomplish and pay for these programs.

RECOMMENDATIONS

Recommendation 7-1: Decision makers about electric utility rates—including state legislators and utility regulators and governing boards of publicly owned electric utilities—should take into account that DG technology costs and market maturity are at a stage, both technically and economically, where traditional net metering policies to support the deployment of DGs need to be assessed and revisited. This recommendation applies both to instances where a utility operates in a state that previously adopted net metering and regulators are considering variants to it, as well as in parts of the country that have not yet adopted net metering and seek to advance BTM technologies, and have the option to leapfrog beyond net metering and adopt other ratemaking variants.

Recommendation 7-2: Decision makers should rely on important traditional ratemaking principles as updated to reflect the application of new technologies and service offerings. These updated principles include cost-causation, rate simplicity,

fairness, revenue adequacy, a simple customer experience even if underlying rate structures become significantly more sophisticated, and compensating resources based on their value.

Recommendation 7-3: Decision makers should design compensation approaches for the export of power from BTM generation according to principles that are consistent with how the utility values other sources of power that offer comparable energy, capacity, and other grid services to the system (which may vary by time and location). External impacts (such as pollution) from some sources of power are unpriced impacts, and in many jurisdictions there are constraints on the ability of regulators to reflect externalities in utility planning and/or ratemaking. Sound economic principles would support the consideration of such externalities in utility regulation; policymakers should consider how to address such impacts in utility and other energy policies.

Recommendation 7-4: Given the economic and equity challenges associated with using net metering—and with financial incentives and programs recovered in electricity rates more generally—to promote investment in and deployment of DG technologies, policymakers should also consider, and where appropriate use, other policy instruments such as tax incentives, building codes, attractively priced loans (or even grants) to low-income households, and other complementary policies.