The debate surrounding net energy metering (NEM) and the appropriate way to reform this policy is under scrutiny in many U.S. states. This is highly warranted since NEM policies do indeed need reforming because NEM often results in subsidies to private (rooftop) solar owners and leasing companies. These subsidies are then “paid for” by non-NEM customers (customers without private rooftop solar installations). The fundamental source of the NEM subsidy is the failure of NEM customers (customers with private rooftop solar installations) to pay fully for the grid services that they use 24/7. These subsidies are well-documented and underpin much of the regulatory reform efforts underway across the United States.[1]

In a recent Brookings paper, “Rooftop solar: Net metering is a net benefit,” Mark Muro and Devashree Saha contend that net metering is a net benefit for non-NEM customers.[2] I fundamentally disagree with their findings, and argue that NEM is not a net benefit; it is, in fact, a tariff that much of the time results in a subsidy to NEM customers and a cost shift onto non-NEM customers. As Executive Director of the Institute for Electric Innovation, a non-lobbying organization focused on trends in the electric power industry, I have followed this debate and written about it for several years.

Much of the talk about NEM focuses too often on the “value” of the energy that is sold back to the grid by a NEM customer. In reality, the amount of energy sold back to the grid is relatively small. The real issue is the failure of NEM customers to pay fully for the grid services that they use while connected to the grid 24/7, as shown in Figure 1.[3] Customers need to constantly use the grid to balance supply and demand throughout the day, and the cost of these grid services can be sizeable. In fact, for a typical residential customer in the United States with an average electricity bill of $110 per month, the actual cost of grid services can range from $45 to $70 per month–however, the customer doesn’t see that charge.[4] That means, in the extreme, if a customer’s energy use “nets” to zero in a given month because the customer’s private solar system produced exactly what the customer consumed, that customer would pay $0 even though that customer is connected to the local electric company’s distribution grid and is utilizing grid services on a continuous around-the-clock basis.[5]

Although exactly netting to zero energy in a month is highly unlikely, this example demonstrates the point that the customer would pay nothing, despite using grid services at a cost ranging from $45 to $70 per month. Over the course of one year, this customer could receive a subsidy resulting from NEM of between $540 and $840. Over the life of a private rooftop solar system, which ranges from 20 to 25 years, this is a significant subsidy resulting from NEM.

Granted, this is an extreme example, and most NEM customers will pay for some portion of grid services. However, the fundamental source of the NEM subsidy is the failure of NEM customers to pay fully for the grid services that they use 24/7, and the cost of these services can be quite substantial. When a NEM customer doesn’t pay for the grid, the cost is shifted onto non-NEM customers.[6] It is a zero-sum game; plain and simple. This is the elephant in the room.

This issue was directly addressed by Austin Energy when the company implemented a “buy-sell” arrangement for the private rooftop solar customers in its service territory. The rationale for the buy-sell approach is that the customer buys all of the energy that is consumed on-site through the electric company’s retail tariff and sells all of the energy produced by their private rooftop solar system at the electric company’s avoided cost. This addresses the “elephant in the room” because, by buying all energy consumed at the retail tariff, the customer does pay for grid services that are largely captured through the retail tariff. It is an unfortunate fact that under ratemaking practices today in the United States, the majority of fixed costs (i.e., grid and other costs) are captured through a volumetric charge.

Hence, I fundamentally disagree with the Muro/Saha paper–NEM does need to be reformed. NEM is not a net benefit; it is a tariff that the much of the time results in a cost shift onto non-NEM customers. One of the first studies to quantify the magnitude of the NEM subsidy was conducted by Energy+Environmental Economics (E3) for the California Public Utilities Commission (CPUC) in 2013. There was no mention of this analysis for the CPUC in the Muro/Saha paper. The E3 study estimated that NEM would result in a cost shift of $1.1 billion annually by 2020 from NEM to non-NEM customers if current NEM policies were not reformed in California.[7] A cost shift of this magnitude–paid for by non-NEM customers–was unacceptable to California regulators. As a result, California regulators set to work to reform rates in their state; many other states followed suit and conducted similar investigations of the magnitude of the NEM subsidy.

In reviewing NEM studies, Muro and Saha chose to focus on a handful of studies that show that net metering results in a benefit to all customers. In this small group of NEM studies, they included a study that E3 conducted for the Nevada Public Utilities Commission (PUC) in 2014–perhaps the most well-known and cited of the five studies included in the Muro/Saha paper. Very soon after the E3 Nevada study was published, the cost assumptions for the base-case scenario which showed a net benefit of $36 million to non-NEM customers (assuming $100 per MWh for utility-scale solar) were found to be incorrect, completely reversing the conclusion. The $36 million benefit associated with NEM for private rooftop solar turned into a $222 million cost to non-NEM customers when utility-scale solar was priced at $80 per MWh.[8] Today, based on the two most recent utility-scale contracts approved by the Nevada PUC, utility-scale solar has an average lifetime (i.e., levelized) cost of $50 per MWh, meaning that the NEM cost shift would be far greater today. In February 2016, the Nevada PUC stated that “the E3 study is already outdated and irrelevant to the discussion of costs and benefits of NEM in Nevada…”[9] Hence, because the E3 study for the Nevada PUC that the Muro/Saha paper included has been declared outdated and irrelevant to the discussion and because costs for utility-scale solar have declined significantly, that study does not show that NEM provides a net benefit.

No doubt there is an intense debate underway about NEM for private rooftop solar, and much has changed in the past two years in terms of both NEM policies and the growth of private solar projects:

• First, several state regulatory commissions now recognize that the NEM cost shift is both real and sizeable and that all customers who use the grid, including NEM customers, need to pay for the cost of the grid. As a result, many electric companies have proposed and state regulatory commissions have approved increases in monthly fixed charges over the past few years; this partially addresses the issue of NEM customers paying for the cost of the grid services that they use.
• Second and related, getting the pricing right for distributed energy resources of all types is important because we expect those resources to grow significantly in the future. Work is underway in this area and it is one focus of the New York Reforming the Energy Vision proceeding; but there is still much to be done.

By focusing on a select group of studies that show that NEM benefits all customers (as stated by the authors); by excluding the E3 study for the CPUC which was fundamental to the NEM cost shift debate; and by not providing an update on the NEM debate today, I believe that the Muro/Saha paper is misleading.

In the second part of their paper, Muro and Saha suggest some helpful regulatory reforms such as moving toward rate designs that “can meet the needs of a distributed resource future” and moving “toward performance-based rate-making (PBR).” Some electric companies have already implemented PBR or some type of formula rate and PBR is under discussion in several states.[10] Lawrence Berkeley National Labs is looking closely at this and related issues in its Future Electric Utility Regulation series of reports currently underway.[11]

Mura and Saha also suggest decoupling as a way forward–I disagree. In my view, decoupling is a not solution for private rooftop solar. Revenue decoupling is currently used to true-up revenues that would otherwise be lost due to declining electricity sales resulting from electric company investments in energy efficiency (EE). Decoupling explicitly shifts costs from participating EE customers to non-participating EE customers causing the same cost-shifting problem that is created by NEM. However, a fundamental difference is that the magnitude of the cost shifting onto non-NEM customers is on a much larger scale than the cost shifting due to EE. A recent study revealed that decoupling rate adjustments for EE are quite small–about two to three percent of the retail rate.^[12] In contrast, as described earlier in this paper, a NEM customer could shift a significant cost onto non-NEM customers (and the NEM cost shifting is essentially invisible to customers, which is one reason that NEM customers do not believe they are subsidized).[13]

Finally, Muro and Saha suggest that electric companies should invest in a more digital and distributed power grid. In fact, electric companies across the United States are doing just that. In 2015, electric companies invested $20 billion in the distribution system alone and this is expected to continue. Over the past five to six years, electric companies invested in the deployment of nearly 65 million digital smart meters to about 50 percent of U.S. households. In addition, electric companies are investing in thousands of devices to make the power grid smarter and more state-aware. Today, in states such as California, Hawaii, and Arizona, electric companies are investing to enable and integrate the distributed energy resources that are growing exponentially. And, in some states–where regulation allows–electric companies are offering rooftop solar or solar subscriptions to their customers.

No doubt, the electric power industry is undergoing a period of profound transformation–our power generation resource mix is getting cleaner and more distributed; the energy grid is becoming more digital; and customers have different expectations.[14]

Collaboration, good public policy, and appropriate regulatory policies are critical to a successful transformation of the power sector. In the context of this paper, this means reforming NEM so that private rooftop solar customers who use the energy grid pay for the grid. One straightforward approach is to require NEM customers to pay a higher monthly fixed charge thereby reducing the cost shift.[15] Ultimately the challenge is to make the transition of the electric power industry–including the significant growth in private rooftop solar and other distributed energy resources–affordable to all customers.

Lisa Wood is a nonresident senior fellow in the Energy Security and Climate Initiative at Brookings. She is also the executive director of the Institute for Electric Innovation and vice president of The Edison Foundation whose members include electric companies and technology companies.

Renewable energy is an important source to tackle against climate change, as the latest IPCC report has pointed out. However, due to the existence of multiple market failures such as negative externalities of fossil fuels and knowledge spillovers of new technology, government subsidies are still needed to develop renewable energy, such as solar photovoltaic (PV) cells. In the United States, there have been various forms of subsidies for PV, varying from the federal level to the state level, and from the city level to the utility level. California, as the pioneer of solar PV development, has put forward the biggest state-level subsidy program for PV, the California Solar Initiative (CSI). The CSI has planned to spend around $2.2 Billion in 2007–2016 to install roughly 2 GW PV capacity, with the average subsidy level as high as $1.1/W. How to evaluate the cost-effectiveness and incentive pass-through of this program are the two major research questions we are pursing.

Our cost-effectiveness analysis is based on a constrained optimization model that we developed, where the objective is to install as much PV capacity as possible under a fixed budget constraint. Both the analytical and computational results suggest that due to a strong peer effect and the learning-by-doing effect, one can shift subsides from later periods to early periods so that the final PV installed capacity can be increased by 8.1% (or 32 MW). However, if the decision-maker has other policy objectives or constraints in mind, such as maintaining the policy certainty, then, the optimally calculated subsidy policy would look like the CSI.

As to the incentive pass-through question, we took a structural approach and in addition used the method of regression discontinuity (RD). While in general, the incentive pass-through rate depends on the curvature of the demand and supply curve and the level of market competition, our two estimations indicate that the incentive pass-through for the CSI program is almost complete. In other words, almost all of the incentive has been enjoyed by the customer, and the PV installers did not retain much. Based on the RD design, we observe that PV installers tend to consider the CSI incentive as exogenous to their pricing decision.

The relative good performance of the CSI in terms of both the cost-effectiveness and the incentive pass-through aspect are tightly related to its policy design and program management. International speaking, the biggest challenge for the design of any PV subsidy program is the quick running out of the budget, and in the end, it looks like customers are rushing for the subsidy. Such rushing behavior is a clear indication of higher-than-needed incentive levels. Due to the policy rigidity and rapid PV technological change, the PV subsidy policy may lag behind the PV cost decline; and as a result, rational customers could rush for any unnecessarily high subsidy.

Due to the high uncertainty and unpredictability of future PV costs, the CSI put forward a new design that links the incentive level change and the installed capacity goal fulfillment. Specifically, the CSI has designed nine steps to achieve its policy goal; at each step, there is a PV capacity goal that corresponds to an incentive level. Once the capacity goal is finished, the incentive level will decrease to the next lower level. Furthermore, to maintain the policy certainty, the CSI regulated that every step-wise change in the incentive level should not be higher than $0.45/W, nor smaller than $0.05/W, together with other three constraints.

A good subsidy policy not only requires flexible policy design to respond to fast-changing environment, but also demands an efficient program management system, digitalized if possible. For the CSI, the authority has contracted out a third-party to maintain a good database system for the program. Specifically, the database has documented in detail every PV system that customers requested. Key data fields include 22 important dates during the PV installation process, customers’ zip code, city, utility and county information, and various characteristics of the PV system such as price, system size, incentive, PV module and installer. All information is publicly available, which to some extent fills in the information gap held by customers and fosters the market competition among PV installers. For customers to receive the incentive, their PV systems have to pass the inspection of the local government, and also to be interconnected to the grid. On the supply side, the CSI has also certified and created a list of PV installers that every customer can choose from.

Although the CSI has ended in 2014 due to fast PV cost reduction starting from 2009, its experience has been transferred to other areas in the United States and in Europe. It is highly possible that other similar new technologies and products (e.g. the electric car and the battery) can adopt the CSI policy design, too. In summary, a good and successful policy may need to be simply, clear, credible, foreseeable, flexible, end-able, and incentive-compatible. The PV subsidy policy in China still has a long way to go when compared to the CSI.