8

The Future of Net Metering in an Evolving Electricity System

A confluence of changes in technology, policy, economics, and customer expectations have driven fundamental shifts in the electricity system over the last two decades. Amid the global imperative to reduce greenhouse gas (GHG) emissions, innovations in and rapidly declining costs of distributed generation (DG) and distributed energy resource (DER) options have made the demand-side of the electricity system much more dynamic. Customers can choose among more and different energy products and services and can actively manage their electricity use and even generate their own electricity. These changes are precipitating the need for innovation in utility business models and regulatory frameworks to keep pace.

In this context, net metering has played an important role in increasing the deployment of behind-the-meter (BTM) DG. Distributed solar has proliferated over the last two decades to a degree that may not have been easily imagined 20 years ago. Net metering, a billing mechanism to credit and compensate customers for production from clean BTM DG that offsets consumption and is exported to the grid, was established when costs of solar and other BTM DG were high and deployment was low. However, rapid technological change and cost reductions over the last decade combined with a range of supporting policies, including net metering compensation rates, have led to a rapid growth in the proliferation of DG. As a result, DG technologies are at a stage, both technologically and economically, where net metering policies need to be revisited and evolved in considering how to support DG deployment in the context of the evolving electricity system.

This report explores the evolution of net metering and the changes needed to continue to support and advance BTM DG in a way that leads to a decarbonizing, equitable, and resilient electricity system. This chapter builds on the detailed consideration of economic, equity, technological, regulatory, and market factors presented in the earlier chapters. In considering the recommendations in this report, which are summarized in this chapter, it is important to bear in mind that many of the efficiency and equity issues that arise in the context of BTM DG can be addressed either by adjusting the rate designs that underlie net metering compensation or by changes directly to net metering and its variants, and by consideration and potential adoption of alternative support mechanisms. While the focus of this report has been on net metering, its variants, and alternatives, broader changes to underlying rate designs would establish a more level playing field for how

changes to net metering and its variants manifest in terms of a decarbonizing, equitable, and resilient electricity system.

EVOLVING NET METERING FOR THE FUTURE ELECTRICITY SYSTEM

Net metering was instituted in the 1980s, both for its technical simplicity and customer ease of understanding, for supporting DG, especially rooftop solar, with a view to encourage private investment in renewable energy resources, among other objectives.¹ Measured against these original objectives, net metering has been quite successful.

In fact, net metering has been so successful that some states have achieved threshold levels of BTM DG that are raising tensions with the traditional approaches of planning, designing, funding, and maintaining the electricity system. These tensions must be addressed. There is a growing recognition that the value of DG and the ability to capture it for the benefit of the system and all customers depends on the timing, location, and the nature of service (e.g., energy, demand response, and resilience) that DG provides, as well as the degree to which the DG is integrated (not just interconnected) and inter-operated with the distribution grid. DG’s impact is also affected by the specific utility context, public policy, and rate structures and levels.

The committee envisions and supports the evolution of net metering policies in a way that addresses both the value and equity aspects of DG. DG offers potentially multiple value streams, from energy to demand response, to decarbonization, to backup-based resilience, to reduced mortality and morbidity by offsetting generation from central fossil-fuel power plants, and more. It is also clear that DG introduces variability into the demand-side of the equation—on the one hand increasing the complexity of system operations, potentially raising their cost; and on the other hand, with the right control and management technologies, potentially offering options to reduce system costs. DG at scale has both benefits and costs, which arise from the same source: the flexible and distributed nature of DG. The committee believes that the future of net metering lies in creating a rate and system architecture that appropriately recognizes both the benefits and costs of DG—commensurately rewarding BTM DG when it provides value for the system and charging DG customers when the system delivers value to them.

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¹ Quoted from Chapter 3: “According to a 1998 study by National Renewable Energy Laboratory (NREL) researchers: ‘The main objective for states implementing net metering programs is to encourage private investment in renewable energy resources. Other goals include[d] stimulating local economic growth, diversifying energy resources, and improving the environment. Since then, other objectives have been added, including giving consumers options to produce their own power and manage their electricity bills, driving down the costs of renewables as the market expands, and producing power with no carbon emissions.’”

The treatment of DG must adjust with future conditions, ensuring fair compensation for customers who invest in BTM DG and reflecting its contribution to system decarbonization and resilience.

In addition to revisiting net metering policy and exploring its variants and alternatives based on the value or benefits DG can provide, a review of net metering policy offers an important opportunity to address equity concerns that should be addressed in all policymaking. From the equity lens, BTM DG supported by net metering engenders a complex landscape of positive and negative impacts. On one hand, BTM DG positively affects communities in fossil fuel–dominated supply systems because of pollutant reductions and the associated health benefits; on the other, BTM DG can fail to address or even exacerbate historical issues of access to programs and technologies for low-income communities and cost implications for net metering non-participants. Policymakers need to focus attention on equity issues to make certain that equity will be enhanced through net metering policy for BTM DG. Unleashing the true power and promise of DG for a more resilient, equitable, and decarbonized electricity system will require a more intentional and integrated approach than traditional net metering policies.

Distributional aspects of net metering are complex and are affected by the underlying context set by electricity rates. Although different rate designs directly or indirectly have provisions to limit the adverse impact of rates on low-income and disadvantaged communities, given that rates try to balance many different factors, maximizing equity and access is generally not the primary goal. The proliferation of new technologies, such as DG, under the aegis of older rate designs further complicates this relationship between rates and their equity impacts. New rates and net metering and its variants should be rigorously evaluated for directly addressing equity issues and adjusted, if appropriate, to address these issues before broad implementation. Furthermore, the need for balance between the economic efficiency and the distributional impacts of net metering and its variants should be recognized upfront, and parallel incentive and support mechanisms to directly improve the equity and resilience outcomes for low-income and disadvantaged communities should be put into place in tandem with both new and existing net metering policies.

PILLARS OF NET METERING REDESIGN

The evolution of net metering needs to build on three core foundational pillars:

1. It needs to recognize that the future electricity system is and will become even more interdependent among its constituent parts (including DG at the grid edge), not less, and should accordingly support the integration of those parts.

2. It needs to build on the generally accepted principles of electricity system regulation: efficiency, simplicity, stability, fairness, and revenue adequacy.
3. It needs to be informed by the electricity system context, policy objectives related to decarbonization, equity, and system resilience, among others, and be sensitive to the locational, temporal, and scale impacts of DG.

DG as Part of an Interdependent, Synergistic Evolving Electricity System

The committee believes that through better coordination, better system outcomes may be achieved. Certainly, in the medium term (5–10 years), but even more so in the long term (20 years and beyond), the committee foresees a more interdependent future for customers and utilities and other energy product and service providers, as well as distributed and grid-scale generation. This integrated system will deliver greater value for customers overall. While there may be some customers, in certain circumstances, who may choose to disconnect from the grid, such an outcome applied to the entire or even large parts of the customer base is not likely or desirable.² It would destabilize and disintegrate the larger system of electricity service delivery, without guaranteeing better reliability or economics for customers individually or en masse. Rather, the committee envisions a pathway that integrates DG with the rest of the electricity system and leverages valuable features of the integrated system for the benefit of all customers.

Indeed, as highlighted throughout this report, DG offers a new set of value-driven uses such as customer savings, backup power, demand response, and lower emissions. These value streams enable better electricity service experience for customers with and without DG and offer new avenues for building a cleaner, more resilient, and more equitable electricity system. That value is dependent on time and location; estimating it and operating to achieve it will be essential. To estimate and capture this value data relating to utility and system costs must be made available and accessible to customers and DG providers. Similarly, DG can lead to increased system costs due to its variability and technical characteristics (e.g., loss of system inertia, among others), adding operational challenges at the distribution level, and the need for system investment to address them. BTM DG supported by net metering can also have distribution impacts, potentially raising equity concerns, due to cost shifts from net metering to non-net metering customers, or vice versa. Where BTM DG value is less than net metering compensation, costs will shift to non-net metering customers; where value exceeds compensation, costs may be

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² These circumstances could occur if customers can meet their own electricity needs with BTM DG, storage and possibly backup generation, at a cost that is less than they would otherwise pay the utility. Net metering compensation for exported power can offset some of the customer’s total cost and can influence the decision to remain connected (and receive such compensation) or disconnect.

shifted to net metering customers. Benefits and costs of DG also depend on the scale of DG penetration.

While the exact balance of benefits and costs is system-dependent, there is value on both sides (BTM and grid-side), even with costs and uncertainties on both sides as well. For BTM DG customers, uncertainties arise from changing prices, rate structures, and reliability and resilience of supply, whether self-generated or grid supplied. For grid operators and utilities, uncertainties come from variable demand, hard-to-predict operational conditions, changing customer and policymaker expectations, and evolving regulatory and utility business models. All of these are affecting utilities’ operations, conventional revenue collection, and system and financial planning. DG evolution challenges the top-down, conventional model of the distribution grid, where decisions of operators may be at odds with customer behavior. Given the continued adoption and deployment of BTM DG, that is also increasingly combined with storage, higher levels of variability in demand are a reality. Utilities need to continue to plan for, invest in, and operate the system to meet increasingly variable customer needs and wants from the grid. Utilities also need to leverage DG attributes for building a more resilient electricity system.

Redesigned Rate Structures and Net Metering Need to Be Consistent with the Basic Principles of Electricity Rate Design

New rate structures and net metering need to build on the generally accepted regulatory principles of efficiency, simplicity, stability, fairness, and revenue adequacy. Achieving the right balance is a challenging and changing goal, yet one that makes explicit the multiple higher-level objectives that need to be balanced. Acceptable rate designs have always required tradeoffs or balancing among ratemaking principles and objectives that have been weighted differently in different locations and at different times. The committee expects that to continue as part of net metering policy evolution. In fact, because of the opportunities and challenges associated with DG at varying levels of deployment, the contours of those tradeoffs are expanding. At the heart of this new balancing act is the ability to integrate DG more completely into the electricity system for the benefit of the system and all customers while enabling private choice and flexibility. Where the customer maintains full control over the timing and duration of power drawn from or injected into the grid, the DG is operationally uncontrollable from the grid’s viewpoint and is of less value to the grid and other customers. Where DG resources offer control to the utility—either directly or indirectly through price signals or contracts—to help maximize value for the grid, they provide more value and thus merit greater compensation.

BTM DG offers multiple value streams (e.g., lower costs, lower pollution, and higher resilience) for both the customer and the grid. At higher levels of penetration, it also introduces new challenges for the distribution system related to demand variability and power flows. Capturing these value streams and reflecting the values in compensation through net metering or its variants while addressing the emerging challenges will entail sustained investments in the distribution grid in order to integrate—not just interconnect—BTM DG (and other DER) into the grid. When those investments are best made by the utility, ratemaking should enable the utility to earn a reasonable return on them. However, the committee also recognizes that some investments for integrating BTM DG into the grid, for example through demand aggregation or virtual power plant mechanisms, could also be made by non-utility market participants.³

Thus, 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. Solutions that account for system- and context-specific nuances will be needed and can be achieved through consultation and coordination. Coordination mechanisms and processes will be key, placing emphasis on distributed decision making under uncertainty and distributed control systems. Moreover, regardless of the complexities of the technical systems, the rate structures and net metering compensation for BTM DG should be straightforward and easy for customers and other stakeholders to understand.

System Context and History Should Inform Net Metering Redesign

Good net metering redesign will need to be situated in the respective system context, policy objectives, and history. The committee does not believe that there is just one net metering model that is categorically superior for all systems and contexts. Important elements of context could include DG resource and potential, relevant policies (carbon and pollution reduction, resilience, equity, and others), current DG deployment levels, and expected system stressors (due to climate change and other factors). Important elements of system history could include current electricity infrastructure and near- and medium-term revenue requirements due to historical grid investments. In fact, even for the same system or utility, elements of net metering design that appropriately balances different tradeoffs will likely vary over time and as DG deployment changes. The benefits and costs of BTM DG, supported by net metering, at lower levels of deployment can

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³ It will be important to ensure that non-utility participants do not face barriers to making these investments and providing these services (e.g., standardized interconnection and interoperability requirements would reduce those barriers).

be quite different from when DG deployment is greater and increasing. As the costs of BTM DG systems and storage continue to decline, the potential for greater numbers of customers to adopt these technologies must be considered. While the core lessons and insights of net metering policy evolution and redesign will be applicable across different systems, each system will nonetheless need to grapple with its unique set of context, history, and aspirations.

“BEYOND DG” APPROACH NEEDED FOR NET METERING REDESIGN

The proliferation of BTM DG is happening within a larger set of changes in the electricity system and interconnected systems (e.g., telecommunications). Maximizing the benefit for all customers through the evolution of net metering will entail successfully engaging with these broader systems and issues and co-evolving with them.

One of the major underlying trends has been the digitization of the electricity system over the past few decades.⁴ This is not unique to the electricity industry, rather it is part of what has been broadly dubbed as Industry 4.0—the coming together of objects (e.g., machines) in the physical infrastructure, their virtual representations, and services enabled through the use of data and analytics by leveraging that physical-virtual combination.⁵ Digitization within the electricity distribution system, including an intertwined array of smart hardware (e.g., meters and sensors) and software (e.g., DG performance dashboards and automated fault detection), has played a central role in making BTM DG and DER integration possible.^6,7 Expected to further deepen in the future, digitization will be central to the emergence of coordinated, hierarchical multi-agent systems helping better integrate DER into the grid, further enabling the robustness of microgrids, energy hubs, intelligent energy management, and system-level optimization.⁸

The committee notes that, among others, the following areas are especially worthy of continued attention in the context of net metering policy evolution:

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⁴IEA (International Energy Agency). 2017. Digitalisation and Energy. Paris: IEA. https://www.iea.org/reports/digitalisation-and-energy.

⁵Drath, R., and A. Horch. 2014. “Industrie 4.0: Hit or Hype? [Industry Forum].” IEEE Industrial Electronics Magazine 8(2):56–58.

⁶Bañales, S. 2020. “The Enabling Impact of Digital Technologies on Distributed Energy Resources Integration.” Journal of Renewable and Sustainable Energy 12(4):045301.

⁷Venugopalan, S., and V. Rai. 2015. “Topic Based Classification and Pattern Identification in Patents.” Technological Forecasting and Social Change 94:236.

⁸Howell, S., Y. Rezgui, J.L. Hippolyte, B. Jayan, and H. Li. 2017. “Towards the Next Generation of Smart Grids: Semantic and Holonic Multi-Agent Management of Distributed Energy Resources.” Renewable and Sustainable Energy Reviews 77:193–214.

• An expanding array of economic technology solutions including photovoltaic (PV) + storage + generator, combined heat and power (CHP), and Plug-and-Play (BTM DG) will be available to customers
• The rapid evolution of DG, storage, and generation options, along with microgrid technologies, that may enable system resilience through distributed capabilities (in addition to any private resilience value afforded to adopters of these technologies)
• Increasing electrification of transportation, homes, and buildings, with accompanying consumer demand response capabilities and technologies
• The emergence of new customer groups and assets (e.g., through community choice aggregation and demand response aggregation)
• The need to reinforce and expand system communication technologies and infrastructure
• The increasing challenges to cybersecurity on a power grid with increasing numbers of distributed and interconnected devices

Exploration and implementation of good net metering policy redesigns, especially in electricity systems with relatively high or soon-to-be high DG penetration, will need to maintain a holistic look at this “integrated DG frontier.” Focusing on the singular question of benefit and cost for BTM customers vis-à-vis the grid operator and the utility will miss the larger set of intertwined questions that are at play.

ELECTRICITY RATES AND NET METERING POLICIES ARE NOT A SUBSTITUTE FOR ADDRESSING SOCIETAL NEEDS MORE BROADLY

The nature and extent to which different externalities associated with the production and supply of electricity may be included in rates are governed by relevant state and federal legal provisions applicable within the jurisdiction in which a utility operates. At present, most jurisdictions in the United States do not require relevant externalities (e.g., GHG emissions) to be priced into utility rates. This reality poses a fundamental constraint for ratemaking processes, continuing the gap between pricing at social marginal cost, based on economic theory, and electricity rates, which balance economic efficiency and other objectives. In this sense, the regulatory ratemaking framework and processes establish the bounds for net metering (and other policies). Updating that framework through policymaking that enables the valuation and internalization (i.e., inclusion in prices) of the relevant externalities will be important for leveling the playing field for various grid resources and appropriately valuing them through rates. However, there will be limits to this. Consequently, it is vital to consider and support non-electricity system

goals (such as economy-side carbon reduction, technology innovation, and low-income support) outside the rate design arena.

SUMMARY

Thanks to rapid technological advancements and cost reductions, DER generally, and BTM DG (especially distributed solar) more specifically are playing a more central and active role in the electricity system than was thought possible a couple of decades ago. Net metering has successfully supported the growth of BTM DG during this period. Moving forward, to enable the integration of BTM DG into the electricity system to maximize benefits for all customers, traditional net metering needs to be revised to align value streams, costs, and compensation. This would be the first key priority of regulatory action in this area. Second, it would be critical to ensure that revisions to net metering also improve equity, an outcome that cannot be taken for granted, rather one that must be achieved through a continual, intentional approach. Achieving these dual objectives of greater economic efficiency and equity would require careful attention to and balancing of contextually informed factors that often vary across different electricity systems. Fully integrating BTM DG into the electricity system portends a more resilient electricity system, but achieving this goal would entail systematic, coordinated, and sustained investments across distribution systems. Policies and regulations must support the creation of a framework and market conditions that enable utility and, as applicable, non-utility participants to invest in the distribution system for integrating BTM DG into the grid, with an opportunity to earn a reasonable rate of return on their investment. Finally, not everything can or should be achieved through electricity rates. Broader social goals may be best pursued through non-rate approaches, and additional supporting mechanisms that go beyond ratemaking will likely be necessary for attaining certain key objectives, especially equity. With a more open, transparent, deliberate, and intentional approach that leverages the locational, temporal, and contextual value streams of BTM DG, an evolved net metering policy could enable an electricity system that is more sustainable, equitable, and resilient.

RECOMMENDATIONS

Trends

Recommendation 3-1: Utility regulators and decision makers of publicly owned utilities should work with stakeholders to explore and implement solutions to technical, legal, proprietary, or privacy concerns about the collection and release of

information about the performance of behind-the-meter technologies and their interactions with the grid.

Recommendation 3-2: Data about participation in net metering and alternative and supplemental DG policies should be collected and reported so that policymakers can monitor how policies are interacting with energy market conditions in wholesale and retail, as well as regulated and unregulated, energy markets.

Economics

Recommendation 4-1: Regulators should strive to develop retail rate structures—for both DG and non-DG customers—with usage-based energy prices that correspond as closely as possible to the social marginal cost of producing and delivering electricity, inclusive of time- and location-specific environmental or other externality costs (insofar as they are not already internalized), while recognizing other competing rate-design objectives. Under this condition, net metering will generally result in economically efficient levels of investment in DG technologies, albeit with some rate impacts to non-participating customers.

Recommendation 4-2: In the absence of economically efficient rate structures for all customers, the alternative solution may be to implement changes to the net metering mechanism—either buy-all and sell-all or net billing tariffs—for DG customers, with DG compensation levels set at or near the social marginal cost of electricity production and delivery.

Recommendation 4-3: When evaluating the economic implications of current or proposed changes to net metering rules, decision makers should consider specific conditions in their jurisdiction (e.g., the generation mix and costs, DG penetration levels, clean energy policies, etc.), while also anticipating how those conditions may evolve over the lifetime of DG resources. Environmental benefits should be carefully weighed alongside any rate impacts to non-participating customers.

Recommendation 4-4: In some cases, additional compensation for DG customers may be warranted above and beyond what can be provided through net metering or other DG tariffs. In these circumstances, any additional incentives for DG customers should be provided through transparent incentives designed to achieve a

specified outcome (e.g., to encourage adoption by low-income customers, to relieve constraints in specific localized regions of the grid, to meet legislative DG targets, etc.) and, if appropriate, funded from sources outside of electricity rates.

Recommendation 4-5: In determining DG compensation, policymakers should explicitly account for the environmental and other externalities that DG reduces when it displaces fossil fuel generation. To fairly compensate DG for this clean energy attribute, policymakers should consider whether to do so based on the monetary value of the environmental externalities that the DG is likely to abate or the cost to achieve the same reduction in environmental harms through alternative technologies or policies.

Recommendation 4-6: Utilities should work with regulators and stakeholders to identify the types and formats of information (such as heat maps and avoided-cost calculations) that the utility should provide publicly about their distribution systems and their provision of electricity service so that suppliers and potential customers of behind-the-meter generation can see the benefits and costs that behind-the-meter technologies can provide to the local electric system. Regulators and decision makers of publicly owned utilities should ensure that such information is provided to the public in easily understandable and accessible ways.

Recommendation 4-7: To the extent possible, BTM DG compensation rates should be location- and time-based, tied to available distribution capacity, to indicate where that DG would have the greatest value (e.g., in relieving or avoiding distribution constraints and/or displacing local generation with high emissions). Considering the locational value of solar can have particular value to low-income customers who often live in areas with emitting generation and poorer air quality.

Equity

Recommendation 5-1: Rates should be designed consistent with updated ratemaking principles, with particular attention to the equity impacts for customers least able to afford them. To help accomplish this, utilities and policymakers should ensure that information about utility rates is easily available to all customers (e.g., not just through postings on websites), and that all customers have a voice and can participate in the design of rates.

Recommendation 5-2: Decision makers on electricity rates should consider both the impacts of the distribution of benefits and costs, as well as total benefits and costs when designing net metering policies, and ensure that adequate data are collected and made publicly available to do so. These benefits and costs should include and balance, among other things: public health impacts, job impacts, land use impacts, and the future options that will be enabled or precluded.

Recommendation 5-3: Fair ratemaking should allow for affected consumers to have a meaningful voice in the process (so as to ensure procedural equity) and take into consideration (among other things) the potential impacts of rates on various customer segments (from an economic efficiency and equity point of view), and on customers’ decisions about adopting BTM technologies or load or grid defection in the context of technology trends. Regulators and decision makers of publicly owned utilities should ensure that such information is provided to the public and is easily understandable and accessible.

Recommendation 5-4: Investments to reverse historic structural inequities, such as grid upgrades in historically disinvested communities to increase hosting capacity, should be considered to enable broader adoption of BTM DG and participation in net metering.

Recommendation 5-5: Policymakers should consider expanding community and government-funded programs, such as low- or no-interest financing, to expand access to BTM DG by low- and medium-income customers and their participation in net metering. In addition, incentives that focus on income-qualified customers and renters can help reduce inequities due to lack of access.

Technology

Recommendation 6-1: There need to be direct investments in the distribution system to integrate increasing amounts of BTM DG such as rooftop solar, as well as other DER including smart buildings management systems, electric vehicles, and charging infrastructure, to ensure the continued safe and reliable operation of the grid and provision of grid services. Investments will also be required to improve grid visibility to suitably site and operate BTM DG, as well as provide efficient price signals, such that the DG can provide system benefits, particularly local and grid resilience when normal service is disrupted. These investments in the distribution grid have to occur simultaneously with BTM DG deployment.

Recommendation 6-2: In order to make the best use of DG and DER, utilities must make investments to integrate these technologies, increase their visibility, manage them (either directly or indirectly through price signals), and reduce barriers to their management by customers and DG providers. With either utility or non-utility control, or intelligent management, DG can provide greater value. The corresponding compensation through net metering and its variants could reflect this higher value. Overall, the democratization of the grid, with increased public and private partnerships, can be very valuable.

Recommendation 6-3: Investments in distribution system technologies aimed toward integration of DG and DER must be accompanied by revisions in policies and state and federal utility regulations to facilitate cost recovery of these investments.

Regulatory and Policy

Recommendation 7-1: Decision makers about electric utility rates—including state legislators, 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, 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.