The Battles Over Net Energy Metering1

Under net energy metering (NEM), the buying and selling of electricity occurs at the same price. NEM is a pricing arrangement that applies to consumers of energy that have installed rooftop solar panels on their premise, allowing them to both buy power from the grid and to sell power to the grid. Such consumers are often called prosumers. When they have paired battery storage with their solar panels, they are called prosumagers.

NEM is widespread in the US, as shown in Figure 1.

Figure 1: States with NEM Policy as of June 2020

Source: DSIRE NC Clean Energy Technology Center. States in dark blue indicate the presence of NEM for residential solar PV customers.

The practice of NEM has evolved over the years. In most cases, the simplest form exists. It generally, although not always, applies in areas with relatively low saturation of solar panels. Dubbed as NEM 1.0, it refers to a situation where the utility compensates rooftop solar customers for their exports to the grid at the full retail rate on a one-on-one basis. Most residential rates are volumetric rates based upon embedded costs — not marginal costs — that do not vary with time, come with a modest fixed charge and are high in order to recover most of the fixed system costs. These high volumetric rates motivate some consumers to install solar panel. NEM shortens the payback on the investment in solar panels and helps accelerate the conversion of consumers into prosumers. According to utilities, NEM creates a cost shift from solar to non-solar customers and needs to be remedied. Consumer advocates and some environmental advocacy groups have also put forward this argument, while solar industry representatives believe no such cost shift occurs.

Attempts to reform NEM have been met with stiff opposition in every instance. Hawaii has succeeded in eliminating NEM in its entirety, saying the power system does not have the capacity to take on any more exports from solar panels. It has replaced NEM with self-supply or grid-supply. In the former, prosumers just use solar panels to meet their own needs. They do not supply power to the grid. Essentially, they behave like highly energy efficient consumers who drastically cut their purchases from the grid by installing efficient end use equipment. In the latter case, they supply their excess power to the grid but are only compensated for their power at the wholesale cost of power.

In other cases, such as Michigan, NEM has been replaced with an inflow/outflow model where purchases of electricity occur at the retail rate and exports occur at the wholesale rate. Still other states, such as Arizona, Nevada, Utah and Vermont have instituted net billing.

Some states have gone back and forth on the need to change NEM and decided in the end to leave things as they exist today. These states include Idaho, Kansas and Montana. In these cases, the solar industry argued that there was no cost shift between prosumers and consumers.

Finally, other states have left the general concept of NEM unchanged but have considered making changes to the underlying rate design by doing one or more of the following: raising the fixed charge, instituting a minimum bill, introducing a time-varying energy charge, introducing a demand charge or introducing a grid access charge. In these states, the solar industry has argued that charging different rates to prosumers from consumers is discriminatory and has no justification.

Most recently, in the state of South Carolina, one of the utilities has arrived at a settlement with the solar industry. The terms include a higher fixed charge, a time-of-use energy charge, a minimum bill, a grid access charge for panels that are above 15 kW in size. Customers will be provided an incentive of 39 cents per watt to install solar panels — approximately $2,500 on a 6 kW panel — if they agree to sign on to a critical-peak pricing rate of 25 cents per kWh for up to 60 hours in the winter season if the customer also installs a smart thermostat. The details of the rate design are shown below.

Table 1: Duke Energy’s proposed rate design for NEM customers in South Carolina[2]

Solar Time-of-Use
Solar Time-of-Use
1 Basic Facilities Charge per month $ 14.630 $ 13.090
2 Energy Charges
Critical Peak (per kWh) $ 0.253 $ 0.250
On-Peak (per kWh) $ 0.162 $ 0.152
Off-Peak (per kWh) $ 0.099 $ 0.088
Super-Off-Peak (per kWh) $ 0.073 $ 0.060
3 Non-bypassable Charge per month $ 0.490 $ 0.420
4 Grid Access Fee per month (per kW above 15 kW) $ 3.950 $ 5.860
5 Customer and Distribution Energy Charges
On-Peak (per kWh) $ 0.029 $ 0.037
Off-Peak (per kWh) $ 0.023 $ 0.025
Super-Off-Peak (per kWh) $ 0.019 $ 0.018
6 Minimum bill $ 30.000


As a rule, whenever changes are proposed to NEM, the intention is to extend the payback to potential future prosumers and to thus lower the probability that customers will become prosumers. The logic driving modifications to NEM is to reduce the cost shift that utilities say exists between NEM and non-NEM customers and to ensure that consumers receive good price signals for energy consumption and solar PV deployment.

The state of play in California

California is home to roughly half of the US’s 2.2 million rooftop solar installations. Since 2016, NEM 2.0 has been in effect. Under that policy, solar customers are on a mandatory TOU energy rate which is also accompanied by a minimum bill of roughly $10 a month. The price at which they import power from the grid varies by time of day but it is the same price at which they export power to the grid. Financially, all that matters is net usage by pricing period. The peak period is late in the day, reflecting the duck curve phenomenon. On one of those rates, it runs from 4 pm to 9 pm, a period during which clean energy is generally not available from the grid.

By contrast, consumers who are not prosumers have until recently been on a flat volumetric rate for all three investor-owned utilities. For two of the three utilities, there has been no fixed charge at all. For the third one, the fixed charge has been around a dollar per customer per month.

The California Public Utilities Commission (CPUC) has initiated a proceeding to consider replacing NEM 2.0 with NEM 3.0.[3] Its staff has published a “Look Back Study” which has concluded that there is a cost shift of $3 billion from prosumers to consumers. On March 15, 2021 several parties filed reports with the CPUC. The investor-owned utilities filed a joint report centered on the following points[4]:

  • NEM 2.0 is too generous. Solar installation costs have gone down and thus NEM compensation has gone up. They contend that the payback period is now down to 3-4 years but the NEM compensation continues for 20 years.
  • NEM 2.0 shifts cost to non-participants. Higher prices for non-participants leads to decreased electricity usage.
  • It is disproportionately high-income customers that adopt solar and it creates an affordability issue for income-qualified customers.
  • NEM does not provide price signals to promote electrification.

The utilities proposed a multi-pronged change to NEM 2.0 that would substantially reduce export compensation for prosumers and levy three new charges on them: a fixed charge, a higher minimum bill, and most notably a grid access charge. In comparison to proposals submitted by utilities elsewhere, this is the most far-reaching by far. It will adversely affect the economics of rooftop solar. According to the utilities’ own computations, the payback period will likely be lengthened by ten years.[5]

NEM 3.0 in the utilities proposal will be designed to:

  • Eliminate subsidies for new customers that do not need them.
  • Encourage solar customers to pair the panels with battery storage.
  • Eliminate cost shift to non-participants by basing export values on CPUC’s calculation of avoided costs and having customers pay their share of customer costs, grid costs, and public purpose programs.
  • Encourage distributed solar adoption among under-represented communities through transitional subsidies and a discount on the Grid Benefits Charge.
  • Eliminate annual true-ups, provide transparency on export compensation and responsibility for grid maintenance.
  • Provide an optional Value of Distributed Energy tariff compensation.
  • Impose a uniform pricing structure across utilities.
  • Promote solar-paired storage systems by providing higher compensation produced at higher value times of days.
  • Provide neutrality among load serving entities by defining which credits and charges are set by the load serving entity and which by the distribution utility.
  • New distributed generation (DG) customers take service on default cost-based rates, based on elements such as non-tiered TOU rates and customer charges.

As expected, the solar industry and clean energy advocates are strongly contesting both the magnitude and at times even the existence of a “cost shift.” The solar industry intends to show that the cost shift from the 10 GW of existing NEM 1.0 and 2.0 rooftop systems is no larger than the above-market costs of the utility-scale generation developed to date under the Renewable Portfolio Standard (RPS) program. So if California did not have a rooftop program, it would have been required to do more utility-scale RPS renewables that would have produced a comparable “cost shift” of above-market costs. Ratepayers would not have escaped these above market costs either way! These above market costs — for both RPS and rooftop solar — are largely the result of rapidly declining renewable technology costs over the last 15 years.

The solar industry is agreeable to dropping the export compensation by 50 per cent over five years and moving future NEM customers to TOU rates but not to making any additional changes. Specifically, they have proposed the following elements[6]:

  • Under new proposed tariff, customers with renewable DG would pay a different rate for energy received from utility than for the excess generation exported to utilities.
  • Customers of PG&E and SDG&E would be required to take service from one of the utility’s available un-tiered TOU rates, which will provide stronger incentive for customers to include storage. SCE customers can continue using the residential default TOU rates and the electrification rate.
  • Five-year stepdown in compensation, focused on reducing the export rate.
  • Use of TOU rates recently adopted by the Commission. Large differences between on- and off- rates closer to marginal costs resulting in lower compensation for solar-only systems which will encourage customers to include on-site storage.
  • Incorporation of other types of distributed energy resources (DERs). Base program on a TOU rate platform that is not solar or NEM-specific.
  • Continued application of secondary customer benefits. Exemption from departing load charges, standby charges, and interconnection upgrade costs.
  • Terms and billing rules. Update the net surplus compensation rates to use a 12-month rolling average of the adopted Avoided Cost Calculator values. Customers allowed to oversize their solar systems by up to 50 per cent with excess output compensated at the avoided cost-based net surplus compensation (NSC)rates.
  • Using monthly bill as a default with an annual true-up in April.

The solar industry contends that their analysis looks at the lifecycle costs and benefits of rooftop solar, unlike the investor-owned utilities proposal. A summary of the utility and solar industry proposals is provided in Table 2 and 3.

Table 2: PG&E Proposed Charges[7],[8]

Summer Winter Grid Benefit Charge Customer Charge Net Surplus Cost
Type of Rate On Peak Part Peak Off Peak On Peak Part Peak Off Peak
$/kWh $/kWh $/kWh $/kWh $/kWh $/kWh $/*kWh/month $/month $/kWh
Export Compensation Rate 0.13 0.08 0.06 0.06 0.05 0.05
Residential Default Rate (E-DER) 0.40 0.27 0.22 0.23 0.21 0.20
Other Charges 10.93 20.66 0.03


Table 3: Vote Solar and SEIA Proposed Charges for PG&E Customers[9]

Summer Winter California Climate Delivery Minimum Net Surplus Cost
On Peak Part Peak Off Peak On Peak Part Peak Off Peak
$/kWh $/kWh $/kWh $/kWh $/kWh $/kWh $ $/day $/kWh
Export Compensation Rate, 2023 0.50 0.39 0.18 0.37 0.35 0.18
Export Compensation Rate, 2027 0.25 0.19 0.09 0.18 0.18 0.09
Residential Default Rate (EV2A) 0.50 0.39 0.18 0.37 0.35 0.18
Other Charges (17.20) 0.33 0.059

Note: The California Climate Credit is a semi-annual payment per household
The Delivery Minimum Bill Amount is charged per meter.

The CPUC held a two-day workshop on March 23–24 to review the proposals. Evidentiary hearings will be held in the late July, early August timeframe.

What will be the likely impact of the utilities’ proposal on customer adoption of rooftop solar panels?

We have estimated econometric demand models for predicting solar adoption using data from 27 states over the 2008–2018 frame.[10] We find that the cross-price elasticity of demand for solar installations with respect to the price of electricity is high. According to our analysis, a 10 per cent decrease in the price of electricity would reduce the demand for solar installations by anywhere between 10–20 per cent. We also find evidence of a high-income elasticity of demand for solar installations, and that the existence of NEM provides a significant boost to solar installations. In terms of payback, we find that a one-year increase in the payback period drops solar installations by 6 per cent. Thus, a 10-year increase in the payback period, such as that being proposed by the utilities, will drop solar installations by more than half.


California spends $1.5 billion annually on its energy efficiency programs. The money is provided in the form of financial incentives such as rebates and low interest financing to homeowners to lower the payback period on their potential adoption of energy efficient equipment. Once that equipment is installed, it reduces their energy consumption significantly. Since marginal costs are lower than average costs, such a reduction in energy consumption creates a cost shift from non-energy efficient customers to energy efficient customers. Surprisingly, no voices have been raised asking for a Look Back Study to be done to quantify the cost shift and to modify the states energy efficiency policies to reduce the incentive for customers to engage in energy efficiency.


Net metering started in Canada on March 9, 2004, when the British Columbia Utility Commission established the first tariff[11]. It was prompted by the publication by the BC government in November 2002 of its 2002 energy plan called Energy for the Future. That document stated in part that the British Columbia Hydro Power Authority known as BC Hydro will develop policies such as net metering to support the voluntary goal of acquiring 50 per cent of new electricity supply from clean sources in British Columbia over the next 10 years. Ontario followed two years later. Today all nine provinces and three territories in Canada offer net metering. In Alberta and the Yukon it is called microgeneration not net metering. In Alberta and Ontario, the program is fixed by provincial government regulations.

Generally, net metering is the same across the country. Customers can operate their own generation facility provided it is renewable energy and sell excess power to the grid at the same prices they buy it. The size of the generating equipment varies. In Manitoba it is limited to 200 kW, in Ontario to 500 kW and in Nunavut to 10 kW. There is one exception, however. In 2020 British Columbia broke rank and removed the quantity restriction after an extensive consultation and report. Prior to that the BC nameplate capacity restriction was 100 kW compared to 500 kW in Ontario.

Set out below is a detailed description of the net metering programs in British Columbia, Ontario, and Alberta written by experts in those jurisdictions. These three provinces account for 95 per cent of the solar generation in Canada. Ontario itself, accounts for 85 per cent.

A British Columbia Perspective[12]

The British Columbia Utilities Commission (BCUC) has significant experience in Net Metering (NM), having approved its first NM program in 2004. Prior to that date, on warm sunny days when a customer’s rooftop solar panels were generating more electricity than the customer needed, the customer received no compensation for energy fed back into the grid (it was, in effect, ‘gifted’ to the utility). This obviously put small-scale distributed generation (DG) at a disadvantage compared to larger grid-connected generation and was a problem that we wanted to address.

A NM rate offered a simple solution to this problem — energy fed into the grid by a customer would be offset against volumes they purchased from the utility, and the customer would only be charged for the net difference. This simplified billing approach did not result in a subsidy as the residential retail rate (6.05 c/kWh) at this time approximated the market value of generation (5.4 c/kWh). In addition, under the NM rate, if a customer generated more electricity than they had used in the year, they were compensated at the price value (5.4 c/kWh) for the excess.

The BCUC recognized that these key inputs could change over time, and so stated that the NM rate was conditional on development and implementation that does not incur any substantial cost on the utility, and that does not impose any inordinate barrier to ratepayers seeking to Net Meter. Generator size to participate in the program was capped at 50 KW. [13]

A few years later, in 2009, the BCUC considered a request by an intervenor to increase the price paid to customers under the NM rate to further encourage investment in distributed generation. This request was denied as it was considered within the scope of Government policy:

The Province has not yet issued a directive to the Commission with respect to incentive pricing and the specific role of the Net Metering program in achieving conservation objectives. Until the time that such a direction is issued, the Commission cannot presume the details of potential Government policy. The Commission is therefore not persuaded that it should order BC Hydro to include an incentive component into the Net Metering price at this time.[14]

In 2012, British Columbia Hydro and Power Authority (BC Hydro) filed an application to amend the NM rate. The BCUC reconfirmed the objectives for the program in the resulting decision, stating:

In order for the Net Metering program to contribute in a more meaningful way to help BC Hydro meet its obligations, there should be clear objectives for the program that focus on economic effectiveness and efficiency… The Panel considers it to be important to clearly define success in order to evaluate progress and make necessary changes… [T]he Panel is of the view that unnecessary economic and other barriers to investment in small‐scale clean DG should be mitigated, provided that to do so does not incur a substantial cost on the utility or unnecessarily shift costs to other ratepayers.[15]

By 2012, there had been changes in both the estimated wholesale value of energy and the retail rate. The wholesale value of energy had increased from 5.4 c/kWh to 9.99 c/kWh (based on BC Hydro’s Standard Offer Program (SOP)[16]). The NM rate was therefore updated to use this higher value to compensate customers for any generation fed into the grid in excess of their annual consumption.

However, the residential retail rate (previously 6.05 c/kWh) had also increased — it was now a stepped rate, with the first block at 6.67 c/kWh and the second block expected to increase to 12.96 c/kWh. It was therefore not clear whether the NM program was over or undercompensating the 116 customers on the NM program for energy fed into the grid and used to offset against a customer’s own consumption. The Decision stated:

This gives rise to two concerns for the Panel. The first is that paying a price that is higher than the SOP price [the price paid to larger generators] to Net Metering customers means that potentially the price paid for energy under the Net Metering program may be unduly preferential, and in contravention of section 59 of the Act. Why should Net Metering customers receive a greater rate for their energy than SOP producers? However, in this regard, the Commission stated in Order G‐26‐04 that “limited cost‐shifting to non‐ participating customers was warranted to support the implementation of Net Metering for distributed renewable generation.” The second concern is that customers receiving a price that is lower than the SOP are subsidizing the energy that they supply to BC Hydro, thereby facing a disincentive, compared to other DG producers that are not in the same situation.[17]

To address this concern, the BCUC directed BC Hydro to provide an analysis of the estimated Energy Credit paid to NM customers in its next Net Metering Evaluation Report.

In addition, the BCUC considered a request by a customer to increase the generator size limit from 50 kW to 100 kW, so that these larger generators could also be compensated for energy fed into the grid. The BCUC recognized that the NM program was not the only potential solution to this problem, and therefore directed BC Hydro to consult with affected market participants to identify barriers to entry for small-scale clean distributed generation less than 2 MW, develop and evaluate options to address those barriers and provide the result of this consultation in their next Net Metering Evaluation Report.[18]

BC Hydro subsequently increased the size of generators that could participate in the net metering program from 50 kW to 100 kW.[19]

A more recent development to the NM program occurred in 2020 — by this time the market had fundamentally changed. BC now expects to be in a surplus energy position for many years and so the NM price paid for generation in excess of annual consumption was adjusted to reflect the annual value of BC Hydro’s energy exports (4.0 c/kWh in 201), with a 5-year phase in for existing NM customers. The BCUC also directed BC Hydro to submit an updated Net Metering Evaluation Report to estimate, amongst other things, cost shifting between participants and non-participants and to provide options to address the cost shifting.[20]

The BCUC also considered a request by BC Hydro to limit the size of the generation facility to the customers’ annual consumption. This request was rejected, with the BCUC finding that the proposed restriction could prevent customers from installing the most economically efficient sized generator and that the market-based energy price paid for generation in excess of annual consumption would sufficiently mitigate any cost-shifting concerns.

This 2020 NM Evaluation report recently filed by BC Hydro shows that the value of energy fed into the grid has now dropped from 9.99 c/kWh in 2012 to 3.2 c/kWh for F2020, while the average retail rate received by customers under the NM program for this energy has increased to 10.71 c/kWh (F2019). In addition, there had been a substantial decline in the cost of solar PV Panels over the past decade, and participation in the NM program had grown substantially — from 116 customers in 2011 to over 2,600 in 2021. BC Hydro’s NM report concluded that, as participation in the NM program is expected to grow, there is a need to change the NM rate to address cross-subsidization and set an economically efficient rate. [21]

In summary, the NM program has changed over time as the fundamental inputs have changed — there have been changes in retail rates, the value of generation fed into the grid, the number of individuals on the net metering program, and the maturity of the DG industry. In addition, metering and billing improvements have also mitigated the simplicity benefits achieved when the program was first put in place.

However, in reviewing the history of BC’s NM program since its inception in 2004, it can be seen that the key objective of the rate remained unchanged — to provide efficient pricing signals to customers looking to invest in distributed generation.

It should therefore not be surprising that different jurisdictions have different approaches to Net Metering — the situation in Hawaii or Ontario is different than in BC. It should also not be surprising that a NM program changes over time, and there may be further changes as the industry develops.

Throughout these changes, the BCUC remains committed to its role as an economic regulator — policy and technology neutral — with a focus on the benefits to ratepayers. To promote economic efficiency, distributed generation should be on a level playing field with other options such as grid-connected generation and energy efficiency, and the NM rate was put in place to help us achieve this. Our aim is to continue to identify and address market barriers and support innovation so that all customers can benefit from the energy market transformation.

An Ontario Perspective[22]

Ontario’s net metering program came into force in 2006 with enactment of the Net Metering Regulation.[23] The Regulation required electricity distributors to allow eligible customers to generate and deliver electricity to the distributor and receive a refund. The customer would only pay for his or her net consumption of electricity commodity. In this way, the compensation for electricity delivered to the grid would be the same as the cost to receive electricity from the grid. Participants would not be compensated for generated power supplied to the grid in excess of the amount received from the grid at other times. Eligible customers were those producing electricity solely from renewable sources (solar, hydro, biomass or wind) for the purpose of the customer’s own consumption with a capacity of less than 500kW.

A second — and more popular — option for consumer generators was the microFIT program. The microFIT program was launched in 2009, following the passage of the Green Energy and Green Economy Act. Under the microFIT program, consumer generators are compensated under a tariff system where all electricity generated by the participating consumer is sold to the electricity grid. The program’s popularity could be explained by the generous pricing (as high as $0.80.2/kwh for rooftop solar and $0.44.3/kwh for ground mounted at program inception).[24] The consumer does not directly use any electricity generated. The microFIT program, like the existing net metering program, is for small-scale projects (less than 10kW) which rely solely on renewable sources. The microFIT program was closed to new participants in 2017, however, those with ongoing microFIT contracts (which have terms of up to 20 years) continue to be compensated for electricity generated.

After the end of the microFIT program, Ontario indicated that it would expand and enhance its net metering program. Several changes have been made in amendments to the Net Metering Regulation implemented in recent years.[25] Among the key items of note are the following:

  • The capacity restriction of 500 kW has been eliminated to enable larger customers to “right-size” their renewable energy systems to their load. To be eligible for net metering, customers are still required to generate power primarily for their own use.
  • Net metering generators continue to be compensated at the same rate that they are charged for consumption of electricity as consumers. While consideration had been given about crediting consumers at a “value-based” compensation rate, stakeholders expressed concern that such a rate would not be as transparent as using retail rates.[26]
  • Net metering program participants will be permitted to carry forward credits, for up to one year, where the amount of electricity sent to the grid exceeds consumption from the grid in a given billing period. In the result, a participant cannot generate more than its own consumption in a year, but can do that during periods of the year.
  • A net metering program participant can use energy storage in combination with renewable generation, and can convey electricity from either the generator or the storage device to the grid.

Recent proposed changes to the Net Metering Regulation posed by the Ontario Ministry of Energy would, if enacted, allow for “community net metering demonstration projects.”[27] Community net metering would be an arrangement allowing the transfer or sharing of credits from generation facilities within a community across multiple metered accounts. Embedded renewable generation and potentially energy storage facilities would be used to supply the community as well as send any generation that exceeds the community’s needs to the grid. The supply to the grid would result in electricity bill credits for participating accounts in the community, which could be used to offset costs of electricity consumption from the grid.

At this time, there is no indication about whether or when Ontario will proceed with community net metering demonstration projects, or about the specific rules and requirements that will apply.

Net Billing in Alberta[28]

Under the provisions of the Micro-generation Regulation[29], the net billing method, rather than net metering, is used to calculate energy credits and delivery charges. Net billing is the method prescribed by Alberta legislation for compensating customers for excess electrical energy delivered to the distribution system and for charging customer for consumption of electrical energy from the system.

The Micro-generation Regulation enables a customer to receive a credit on its electricity bill for the electrical energy it delivers to the distribution system (generation) during their billing period (usually one month). The credit is equal to the amount of electrical energy delivered to the distribution system minus the amount of electrical energy used by the customer over the billing period, multiplied by the customer’s energy rate. This rate may vary depending on whether the customer is on a regulated retail rate or a competitive contract provided by its retailer.

To facilitate the calculation, a bi-directional meter having two separate register is required; the first register measures the total amount of electrical energy delivered to the customer from the distribution system, the second measures the total amount of electrical energy delivered to the distribution system from the customer’s site during the billing period. The delivery charges are calculated using the total amount of energy measured in the first register.

After the retailer provides the credit to the customer, the Micro-generation Regulation obligates the Alberta System Operator (AESO) to compensate the retailers for credits provided to the retailers’ customers. In turn the AESO collects the amount paid out in compensation to retailers through its transmission tariff. In this way, all ratepayers provide the funding for net billing credits.

Net billing is in contrast to net metering which would allow a customer to reduce the meter’s measurement of the customer’s consumption by the amount of generation supplied to the distribution system, resulting in greater savings of both energy and delivery charges.

According to the Alberta Electric System Operator, who collects the provincial micro-generation data, there were approximately 6,700 sites with micro-generation of which 95 per cent were solar. The total installed capacity was approximately 103,000 kW. The Micro-generation Regulation sets the limit at 5 MW. However, the micro-generation unit must be sized to meet all or a portion of the customer’s total annual energy consumption at the customer’s site, i.e., the total nameplate capacity cannot exceed the lesser of 5 MW or the customer’s annual consumption. There is no limit as to the amount of energy that the micro-generation can sell to the grid provided the micro-generation unit was properly sized at the time of approval and construction.

The maximum capacity is 5 MW, and it has to be sized to the consumption of the site (i.e., it cannot be oversized, so it is constantly spilling onto the grid). Technically, a home solar panel could sell up to 5 MW if that is the consumption that happens at the site. There is no hard limit to the maximum power. There is a difference in how it is compensated depending on the size of the microgeneration. For a unit less than 150 kW, the site gets a bi-directional cumulative meter and gets the retail energy rate. For sites 150 kW and greater, the site gets a bi-directional interval meter and receives the pool price applicable to the billing period. The installed capacity for the 6,630 solar sites is 94,572 kW. This works out to be 14 kW per site. Accordingly, many of the residential sites are less than 150 kW in size.

The National Picture

Net metering in Canada has not been a roaring success. A recent decision of the BCUC[30] states at page 13 that between 2004 and 2014 only 400 customers were signed up with an installed capacity of 2.5 MW. As of March 1, 2019, total participation had increased to 1850 customers with an installed capacity of 13 MW.

BC Hydro on its website explains, in part, the reason for the slow growth. A typical British Columbia residential customer consumes 11,000 kWh per year. A typical solar installation on a residential roof is 4 kW in size with 16 panels which in BC generates 4400 kWh of electricity over a year. An average solar system this size costs $14,500 which, under the BC rate structure, yields a payback on the investment that takes 23 years.

At the end of 2020 there were 43,000 solar installations in Canada compared with 2 million in the United States in the same year. The US had an installed capacity of 75,000 MW in 2020 compared to 3000 MW in Canada.

Over half of the American installations were in the state of California while 90 per cent of the Canadian installations were in the province of Ontario. The Ontario numbers were driven by the FIT program that the government of Ontario introduced in 2009 and continued until discontinued in 2016.

When the FIT program first started in Ontario, Ontario was a world leader in wind. In October 2010, the largest solar farm in the world with 97 MW was located in Sarnia, Ontario. In recent years the Canadian solar production has been fairly stagnant. In 2018 the Canadian solar capacity was 3115 MW which crept up to 3325MW by 2020. The United States by comparison had a solar capacity of 53,184 MW in 2018 which rose to 75,572 MW in 2020. By 2019 Canada had fallen to 19th in the world in solar capacity.

The Reform Efforts

Regulators in both Canada and the United States have tried to reform net metering. A major objective was to determine if net metering could be expanded from a single customer to a group of customers. The political attraction to net metering was that it could promote renewable energy and reduce the cost of electricity to ratepayers at the same time. The opposition came from utilities that were not eager to lose demand or customers.

The most ambitious program took place in British Columbia. On April 20, 2019, BC Hydro submitted an application to the British Columbia Utilities Commission (BCUC) to amend its net metering program. This resulted in interventions by 14 parties, over 200 letters of comment, and a 52-page final decision a year later in June 2020.[31] The most contentious part from the preceding was BC Hydro’s request to limit the size of the generation facility to the customers’ annual load. Utilities throughout North America have long argued that customers engaging in net metering should not be able to generate a profit. The basic concept was that customers should be able to offset the cost of electricity they bought from the utility with the revenue they received from selling electricity to the utility. The BC evidence was that some customers were making a significant profit, but it was a small percentage of the total. In the end the BCUC rejected the BC Hydro proposal and refused to adopt a maximum generation volume.

In 2014 the Ontario Energy Board began a consultation to determine if all residential distribution rates should be change to a fixed charge. Previously that had been divided between a fixed charge and a variable charge. The rationale was that the growing desire for customers to generate their own electricity could create problems for electricity distributors. The Board made it clear that it supported the new self generation technology that customers wanted to use.

After the decision to move all residential distribution rates to a fixed charge on April 2, 2015 the Ontario Energy Board started a process to move net metering to community net metering. On August 19, 2016, the Ontario government proposed a form of community net metering or virtual net metering. This arose from the government’s 2013 Long-term Energy Plan where the government indicated it would examine the potential for the micro generation program to evolve from a generation purchasing program to a net metering program. The August 19 proposal included the following:

  • The requirement that the equipment used to generate electricity be no greater than 500 KW based on the rated maximum capacity of equipment will be removed.
  • Storage and remittance of electricity from the electricity distributions system and from a renewable energy system will be permitted.
  • Generators will be compensated on the same basis as they are charged for consumption of electricity as consumers.
  • Single entity virtual net metering credit transfers between multiple electricity accounts held by the same person or corporation will be allowed subject to the account leaders being located within the same electricity distributors service territory and within a maximum distance of a 3 km radius.

The government stated that the proposed revised regulation would come into force on July 1, 2017. However, on December 22, 2016, the government decided to remove the community net metering proposal.

On October 8, 2020, the Ontario government again started a consultation to consider virtual net metering stating:

We are proposing amendments to Ontario net metering regulation that will allow for demonstration for community net metering project building on the current net metering framework. Community net metering will support the development of innovative projects such as net zero communities using distributed energy resources.

The government asked interested parties to make submissions by November 22, 2020, addressing such questions as: What constitutes a community? How should the credits be structured? and How should utilities recover any costs incurred? To date no report has been issued by the government or the Ontario Energy Board.

A Wake-Up Call

On April 22, 2021 at an international climate summit Canada pledged that it would reduce carbon emissions by 40 to 45 per cent below 2005 levels by 2030. The previous Canadian goal set at the Paris climate talks in 2015 was 30 per cent by 2030 At the same meeting the Biden administration committed to cutting US emissions by 50 to 52 per cent below 2005 levels by 2030. That was twice the level President Barack Obama had committed to for the same time period.

In December 2020 Canada had announced a new climate plan entitled A Healthy Environment and a Healthy Economy, to accelerate climate change initiatives throughout the country.[32] The plan included 64 different programs to cut pollution and build a clean economy at a cost of $15 billion. In April 2021, the Biden administration announced that it would spend $2 trillion on clean energy investment over the next four years.

Global investment in renewable energy will reach a record high in 2021 and spike to $16 trillion by 2030. What does this mean for net metering? The short answer is that it means the days of delay are over. Provincial regulators and the government’s those regulators report to will focus on original rationale for this policy instrument — carbon reduction. They will abandon the artificial restrictions put in place over the last decade.

On May 18, 2021, the International Energy Agency or IEA released a major Report [33] called Net Zero by 2050: A Roadmap for the Global Energy Sector. It outlined what the world has to do to get to zero emissions by 2050. it conveys a strong message which is this: It is not going to be easy. It is harder than most people think. With respect to solar electricity generation the Report had this to say in part:

In the near term the report describes a net zero pathway that requires the immediate and massive deployment of all available clean and efficient energy technologies combined with a major global push to accelerate innovation. The pathway calls for annual additions of solar PV to reach 630 gigawatts by 2030 and those of wind power to reach 390 gigawatts. Together this is four times the record level set in 2020. For solar PV it is equivalent to installing the world’s current largest solar park every day.

The Real Solution

If the IEA is correct and a rapid increase in solar generation is critical if Canada hopes to meet its decarbonization target, we need a new solar strategy. Community generation is not going to get us there. What could get us there is LDC solar. Why not let local electricity distributors provide solar generation. Not all generation — just solar generation. For the last hundred years there has been a hard line between generation and distribution. That is because in the beginning generation was a natural monopoly. It consisted of huge hydro plants and later huge nuclear plants.

Solar generation is not a natural monopoly. It is local generation. It does require local distribution network but it does not, for the most part, require transmission. The local electric distributors have extensive resources in their communities. If LDCs were allowed to own and operate solar generation, they will put capital to work. Just recently the Ontario Energy Board agreed to let LDCs put electric vehicle charging into rate base. That was because they declared it to be a competitive offering.[34] Solar generation is equally competitive.

A National Solar Policy

The fragmented approach resulting from the net metering policies across Canada has not been successful. Canada continues to fall behind other countries in solar production. If Canada wants to increase its solar generated electricity it will require a consistent national policy. That is not that difficult. It must however address four issues — Who are the major customers? Who are the potential suppliers? What are the regulatory barriers and what are the financial barriers?

The four strategic customers for solar generated electricity are the residential and commercial roof top owners, the EV charging stations, corporate power purchase agreements, and local public utilities.

Rooftop solar: There is nothing wrong with rooftop solar. It is not a bad concept. The roofs are already there and underneath them is a customer. What is missing is the proper financial support. Net metering is clearly not doing the trick. There are too many regulatory restrictions and not enough financial return.

EV charging: No one questions the rapid move to electric vehicles. Gasoline burning cars, buses, and trucks contribute significantly to the amount of carbon in the atmosphere. EV charging stations are being built across the nation. They will need electricity. That electricity can be provided by solar generation.

Power purchase agreements: Large companies are now making commitments to purchase their electricity from renewable energy sources within 10 or 20 years. These are 20 year power purchase agreements. These companies whether it is Bloomberg, Amazon, or Microsoft do not want to own or operate a wind farm or solar farm. They would like to purchase solar energy under a long term contract from a reputable supplier.

Public utilities: In every market in Canada there is a public utility that distributes electricity. It is called a LDC or local distribution company. In every province they are regulated by a provincial energy regulator. Soon the shareholders that own these utilities, whether they are provincial governments or municipalities or private investors, will issue directions to the utilities that they should purchase most of their electricity from renewable energy sources. Why not let those utilities own and operate their own solar electricity generation?

The next question a national solar policy must address is — who is going to be the supplier of the solar generation? One possibility is the LDC serving the territory where a customer resides. Today that is prohibited by regulation.

The next question is what are the regulatory barriers? The regulatory barrier to solar generation is that the logical supplier, the local distribution company or LDC, is prohibited from providing the service. This is based on the age-old view that there is a red line between distribution and generation.

Solar generation requires a different treatment. Unlike large hydro or nuclear facilities, solar generation is not a natural monopoly. It is small, local generation offered in a competitive market. That competition in fact could be increased with the new policy.

The Regulatory Barriers

The production of electricity by solar power would increase dramatically in Canada if two regulatory barriers were removed. The first is the prohibition on LDCs owning and operating solar generation and the related storage facilities. The second is the refusal of the LDCs to provide access to their local distribution network to other solar electricity generators at a fair and reasonable access charge.

Provincial energy regulators have refused to remove these barriers over the last 20 years. They are unlikely to change in the near future. They would likely change their policy however if the LDCs were allowed to own and operate solar generation facilities themselves and supply that electricity not only to themselves but to other third parties.

There is nothing new about access charges. In the Ontario electricity sector we have long experience them in the form of pole access charges. First it was a cable TV companies.[35] Then came the cellular telephone companies.[36] The first decision in Ontario relied on a competition law principle that first took place in the electricity industry. It is called the essential facilities principle as set down in Otter Tail Power decision[37] of the Supreme Court of the United States. The principle is that those that control essential facilities must provide access at just and reasonable prices.

This is not a question of allowing competitors to the LDCs into their market. The LDCs never provided cable television or cellular service. The same issue arose in telecommunications when competitive private line services developed in both Canada and the United States. The regulator granted access to the local distribution network of the monopoly carrier, whether that was Bell Canada[38] or AT&T[39]. There is not much difference between local telephone company and a local electricity distributor.

The existing solar installation companies may complain about unfair competition. But that can be addressed by the regulator. The California Public Service Commission decision in 2015[40] created that regime when they enacted the first Distributed Energy Resource Services tariff. The utility, Southern California Gas, known as SoCal, was allowed under this tariff to own and operate a generation technology called combined heat and power or CHP on or near customer premise.

The utility was also allowed to provide the output to customers at a regulated rate.[41] The SoCal gas application began by referring to a California policy that established a target for new CHP installations of 4000 MW statewide by 2020.[42] The utility pointed to the California Energy Commission study which concluded that CHP development in California had been stagnant for some time and state was expected develop less than half of the goal originally set. Using various reporting and rate setting requirements the regulator made sure that SoCal was not going to engage in predatory pricing that would give SoCal an unfair competitive advantage. This is not a difficult model to duplicate.

Financial Barriers

Regulatory barriers are one thing but there are also financial barriers. Any attempt to reach Canada’s carbon reduction goal will require the federal government to spend a lot of money. No one questions that significant investment to reduce the amount of carbon in the atmosphere is in the public interest.

While net metering has not been successful in Canada there is no doubt that the solar FIT contracts in Ontario and Alberta were. Financial support can produce more solar generation.

A national solar policy should consider underwriting some of the construction costs of solar panels on roofs, solar panels and storage in EV charging stations, and solar farms that can serve both major customers and public utilities. The public utilities are important. Utility scale solar generation is one of the most efficient forms of solar generation. The regulator in the state of Georgia has been able to significantly reduce energy costs by encouraging the utility, Georgia Power, to move to large scale solar generation.


The IEA rightly suggests that solar is the “go to” renewable energy to address the new climate goals. New technology has an important role. But it takes time and is not certain. Solar generation costs have fallen dramatically. Recent studies show that 34 per cent of new solar installations are now paired with battery storage which significantly increases its efficiency. [43]

Solar is local generation and for the most part does not require the expensive and difficult to build transmission that wind does. Most important, the solar market has shifted to utility scale solar which is 20 per cent more cost-effective than rooftop solar.

What is necessary is a new strategy. There is no reason why rooftop solar cannot continue. But roof top solar is not growing and that is not going to change. It is important to address the solar market that is growing. That is utility scale solar. That product is now by far the dominant solar generation in the United States. The federal government should focus on utility scale solar generation.

The federal government should create an incentive for the local distribution companies in Canada to invest in utility scale solar. The LDCs are in every Canadian market. They are largely owned by municipal and provincial governments. Those governments will shortly establish aggressive requirements that these local utilities purchase only renewable energy as some US states have done.[44] It should be added if the municipal and provincial owners of the LDCs join forces in purchasing capital equipment there would be substantial economies.

In the United States the federal tax credit has been instrumental in developing solar installations. A similar policy could be developed in Canada. An alternative would be federal contributions to initial construction costs. This would be a much more cost effective strategy than the FIT contracts in Ontario and Alberta. They produced a lot of solar but they were very expensive.

A national commitment by the federal government to finance the construction of a national solar generation network will not only help Canada meet its carbon reduction goals, it will also help restore employment to pre-Covid levels.

  1. We are grateful to Shivangi Pant for research assistance in the preparation of this paper. An earlier version was presented on March 29,2021, to the Bank of America Securities Group.
    *Ahmad Faruqui and Agustin J. Ros are economists with The Brattle Group where they serve as principals. Agustin J. Ros is also Adjunct Professor at Brandeis University. The views expressed here are entirely their own and not those of their employers. Gordon Kaiser is an arbitrator and counsel at Energy Arbitration LLP in Toronto and Washington DC. He is a former vice chair of the Ontario Energy Board. Please direct your comments to
  2. Ahmad Faruqui, “Rebuttal Testimony of Ahmad Faruqui for Duke Energy Carolinas, LCC and Duke Energy Progress, LLC” (22 February 2021) at 18, online (pdf): Public Service Commission of South Carolina <>.
  3. Re Order Instituting Rulemaking to Revisit Net Energy Metering Tariffs Pursuant to Decision D.16-01-044, and to Address Other Issues Related to Net Energy Metering (3 September 2020), R.20-08-020, online (pdf): California Public Utilities Commission <>.
  4. “Joint Proposal of Pacific Gas and Electric Company (U 39-E), San Diego Gas & Electric Company (U 902-E) and Southern California Edison Company (U 338-E)” (15 March 2021), online (pdf): California Public Utilities Commission <>.
  5. The Natural Resources Defense Council has proposed reducing the export compensation to a level that would leave the payback period at 10 years.
  6. “Proposal of the Solar Energy Industries Association and Vote Solar for a Net Energy Metering Successor General Market Tariff” (15 March 2021), online (pdf): California Public Utilities Commission <>.
  7. PG&E, “Electric Schedule EV2” (21 June 2019), (last accessed 5 May 2021), online (pdf): <>
  8. “Joint Proposal of Pacific Gas and Electric Company (U 39-E) San Diego Gas & Electric Company (U 902-E) and Southern California Edison Company (U 338-E)” (15 March 2021), online (pdf): California Public Utilities Commission <>
  9. Supra note 6.
  10. The results we cite in this sections is from consulting work performed to date as well as a working paper entitled, “Residential Rooftop Solar Demand and the Impact of NEM Compensation and Residential Electricity Prices.” Please contact the author for a copy of the paper.
  11. Re British Columbia Hydro and Power Authority (10 March 2004), G-26-04, online: British Columbia Utilities Commission <> [BC Hydro].
  12. David Morton, Chair and CEO, British Columbia Utilities Commission.
  13. BC Hydro, supra note 11.
  14. Re British Columbia Hydro and Power Authority (29 January 2009), G-4-09, Appendix A at 2, online: British Columbia Utilities Commission <>.
  15. Re British Columbia Hydro and Power Authority (14 May 2012), G-57-12, Appendix A at 12, 20–21, online: British Columbia Utilities <> [BC Hydro 2].
  16. The Sanding Offer Program (SOP) provides a simplified energy purchase contract for eligible clean generators between 100 kW to 15 MW. The program was suspended in 2019.
  17. BC Hydro 2, supra note 15, Appendix A at 7, 44, 48, 50.
  18. Ibid, Appendix A at 43–50.
  19. Re British Columbia Hydro And Power Authority (23 June 2020), G-168-20 at 7, online: British Columbia Utilities <> [BC Hydro and Power].
  20. Ibid at 29, 32, 35, 47, 53.
  21. BC Hydro, “Net Metering Evaluation Report No. 5” (30 October 2020) at 4, 18, 42, 64; BC Hydro 2, supra note 15, Appendix A at 16.
  22. David Stevens, Partner, Aird & Berlis, Toronto
  23. O Reg 541/05 under the Ontario Energy Board Act, 1998, SO 1998, c 15, Schedule B.
  24. This pricing is substantially higher than the amount credited for net metering, which is based on a system-wide price for all electricity (including relatively low-cost hydroelectric and nuclear generation).
  25. See Environmental Registry of Ontario, “Proposed amendment of Ontario Regulation 541/05: Net metering, or a new regulation (to be determined), to be made under the Ontario Energy Board Act, 1998” (8 May 2018), online: <>.
  26. See e.g. Ontario Sustainable Energy Association (OSEA), “RE: Feedback to the Ministry of Energy’s Consultation on Net Metering/Self-Consumption Concept Proposal” (23 October 2015), online (pdf): <>.
  27. See Environmental Registry of Ontario, “Changes to Ontario’s Net Metering Regulation to Support Community-Based Energy Systems” (8 October 2020), online: <>.
  28. Bob Heggie, Chief Executive, Alberta Utilities Commission.
  29. Micro-generation Regulation, Alta Reg 27/2008.
  30. BC Hydro and Power, supra note 19.
  31. Ibid.
  32. The Right Honorable Justin Trudeau, “Prime Minister Announces Canada’s Strengthened climate plan to protect the environment, create jobs, and support communities” (11 December 2020), online: <>.
  33. International Energy Agency, “Net Zero by 2050: A Road Map for the Global Energy Sector” (May 2021), online (pdf): <>.
  34. Ontario Energy Board, Bulletin, “Electric Vehicle Charging” (7 July 2016), online (pdf): <>.
  35. Re Canadian Cable Television Association (7 March 2005), RP-2003-0249, online: Ontario Energy Board <>; In re Ottawa Cablevision Ltd. et al. and Bell Canada, (1973) CTC 522 leave to appeal refused (1974) 1 FC 373; Re Bell Canada, Tariff for Use of Support Structures by Cable Television Licensees (27 May 1997), Telecom decision CRTC 77-6.
  36. “Report of the Ontario Energy Board Wireline Pole Attachment Charges” (22 March 2018), EB-2015-0304, online: Ontario Energy Board <>; Rogers Communication Canada Inc. v Ontario Energy Board, 2020 ONSC 6549.
  37. Otter Tail Power Co. v United States, 410 US 366 (1973); see also United States v Terminal Railroad Association US 383 (1912).
  38. Re CNCP Telecommunications, Interconnection with Bell Canada (1979), CRTC 79-11 at 277–78.
  39. MCI Communications v AT&T, 708 F.2d 1081 at 1132-33 (7th Cir) Cert. denied 464 US 891 (1983).
  40. Re Application of Southern California Gas Company, Distributed Energy Resource Tariff (22 October 2015), 14–08-007, online: California Public Utilities Commission <>.
  41. See Gordon Kaiser, “The Southern California Gas Decision: The First Distributed Energy Resource Service Tariff” (2015) 3:4 Energy Regulation Q 55.
  42. ICF International, Inc., “Combined Heat and Power: Policy Analysis, and 2011-2030 Market Assessment” (February 2012), online (pdf): <>.
  43. At the end of 2020 462 GW of solar generation had applied for interconnection to the bulk power system along with 200 GW of storage capacity. 34% of the solar (159 GW) was paired with storage in a hybrid application. A year earlier 28% of the proposed solar generation was paired with storage; Joseph Rand et al, “Characteristics of Power Plants Seeking Transmission Interconnection at the End of 2020” (May 2021), online (pdf): <>.
  44. The Clean Energy Transformation Act passed by the State of Washington requires all electric utilities in the state to be carbo neutral by 2030 and to source electricity that is 100% clean by 2045.

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