Net-Metering in Ontario: Current Issues and Challenges

I recently attended a conference call held by the Ontario Sustainable Energy Association (OSEA) on the state of the policy discussions with the OEB. This blog will outline some of the main issues and concerns surrounding net-metering currently being discussed by energy companies, consultants, energy co-operatives, and businesses and industry looking to offset their energy consumption, as well as provide a short discussion on the pros and cons of net-metering value models.

With the termination of the FIT and microFIT programs by the end of 2017, the net-metering regulation remains the sole program for procurement of renewable energy in Ontario. First established in 2005, part 1 of recent regulatory amendments have now come into effect as of July 1st 2017, which most significantly include removing the 500 kW equipment capacity restriction, allowing energy storage to be used in conjunction with renewable energy systems, and allowing credits to be carried over to subsequent billing periods within a 12 month period. However, the Ontario Energy Board (OEB) is still in policy consultations with stakeholders regarding the impact of these policy changes, as well as part 2 of the regulatory amendments.

Third Party Ownership and Virtual Net-Metering

One of the most important discussions underway is allowing for third-party ownership, as well as single and multiple entity virtual net-metering in the regulations; something OSEA has been advocating for since it emerged from consultations in 2015. These two polices remove barriers to participation in the program by giving opportunities to property owners that might not otherwise have a chance due to financial constraints, or poor site conditions. Currently, both policies are not possible due to the clause that electricity generated under the net-metering program can only be used for the generator’s own use.

Third-party ownership would allow a third-party entity to own and operate the equipment and then sell that power to customers. This has the benefit of removing the burden of upfront capital costs, and allows third-party providers to partner with municipalities, homeowners, institutions, industry and indigenous communities to generate electricity for their properties. Since power purchase agreements to send electricity across the property line is not allowed under net-metering policy, a possible work around is for a third party to instead lease the equipment across the property line and have them do the net-metering.

Single entity virtual net-metering refers to the ability of a single entity (e.g. individual, corporation, business) with multiple meters and a system sized for multiple buildings at different locations to distribute credits among their accounts. Multiple entity net-metering is the same principle, but allows for electricity generated by an installation to be distributed by the local distribution company (LDC) to multiple customers, such as entire communities or neighbourhoods, based on their ownership shares of the installation. This reduces costs through economies of scale, but could entail increased administrative costs to utilities through having to distribute and transfer credits among many accounts. As it stands these policies are still under discussion with a decision not likely until 2018.

Other issues raised in the call included the presence of a termination clause in the contract that allows the LDC to terminate the contract with only 30-days notice, something that has already served to deter some investors. Also, since CHP is considered load displacement by the OEB definition, it is only eligible for incentives under the IESO’s conservation programs, rather than receiving credit on a per kWh basis for electricity delivered into the grid in excess of their consumption.

Another concern that arose was the prevalence of false, inaccurate, or misleading information being disseminated to customers regarding savings, use of credits, and the effect on rates after getting into the net-metering program. Part of this problem is the uncertainty involved with regulatory changes coming down the line. One example, is that many customers are unaware that upon entry into the net-metering program they will be moved from a time-of-use rate (TOU) structure to the tiered structure.  The reason to switch to tiered rates given on OSEA’s net-metering FAQ, is the need for additional investments in the IESO’s Meter Data Management and Repository and in the communication, billing systems of LDCs to collect and transmit the generation data if they were to remain on TOU. Since the net-metering program has seen limited uptake to date, it has been more cost effective for LDCs to switch customers to tiered pricing for manual billing, however, interest in net-metering is expected to rise as a result of the new regulatory changes to the net-metering program and the FIT cancellation.

How Should Distributed Generation be Valued?

Overall, many LDC’s have been positive and supportive in moving forward the net-metering discussions, but still others have been rather pessimistic regarding the potential financial impacts of the program to them. While the current policy discussions with the OEB have produced agreement among LDCs on standardization of billing and credits, there has been a lack of focus on one of the biggest problems: the potential for stranded assets that LDCs face with high uptake of net-metering. In certain cases, a consumer may have zero draw from the grid in a month but still receive a delivery charge from the LDC. This has been identified as one of the biggest deterrents to more participation in the program, as this charge results in longer payback times for projects.

In order to make net-metering more attractive to investors fixed charges need to be minimized. However, there are still costs associated with maintaining grid connection, as the grid essentially acts as a giant battery, storing electricity during surplus production and providing back up when self-production falls short of demand. A possible solution could be to amortize fixed charges across the province; but this may raise issues of cross-subsidization, where traditional customers are forced to pay higher rates as distributed generators become less reliant on the grid. Another solution is to purchase meters, cables or transformers rather than to keep leasing them.  As this may not be possible for many consumers, exploring the range of options to find out how to best value the costs and benefits of distributed generation and what the appropriate fixed-charge and pricing structure is to allow LDCs to maintain their assets and the grid services they provide, while making net-metering financially viable for customers is essential.

A key consideration is that the payback and value to the owner of a net-metering system may be better off under a TOU structure compared to a tiered structure. TOU also sends better and more transparent price signals. Under the Ontario regulation the value of the electricity conveyed into the LDC’s distribution system is calculated on the same basis as the owner’s consumption of electricity. Tiered pricing sets a fixed rate up to a certain threshold of kWh consumed, and another higher rate for each kWh consumed over that threshold. For example, for residential the first 600 kWh used in a month are priced at 9.1 cents/kWh and anything over 600 kWh is priced at 10.6 cents/kWh. For net-metering this means the first 600 kWh produced is priced at 9.1 cents/kWh and anything over will be at 10.6 cents/kWh, potentially creating an incentive to oversize systems to take advantage of the higher rate.

However, solar has peak production at noon, which corresponds to the on-peak period in the TOU pricing structure. With an on-peak rate of 13.2 cents/kWh, the payback time of net-metering systems could significantly be improved. But this depends on the size of the system installed. Since there has been an absence of FIT policies in the U.S. there is much research and experience to draw on regarding the design of net-metering policies as each state has jurisdiction of their own net-metering policies.  The figure below shows the results of a study conducted in California based on data from two utilities.

From Darghouth, et al. 2011 [1]
The number of customers that TOU pricing was the least cost option for increased with the percentage of consumption that their PV production offset (the PV-to-load ratio), compared to customers on a tiered rate structure. This is because someone with a low PV-to-load ratio will have more usage at expensive on-peak times, whereas someone with a higher ratio, and thus bigger sized system, will have reduced net consumption during on-peak times, therefore driving down their electricity bill faster. Customers with higher consumption during on-peak times will also have better bill savings. A TOU pricing structure for net-metering could also more accurately reflect the value that solar systems provide in terms of offsetting the need for natural gas peaker plants during on-peak periods, particularly during high cooling demands in the summer.

A big part of the discussion is also whether retail rates fairly compensates customer generators. Rather than base the value of self-generation on retail electricity rates, another option often discussed is to base TOU rates on the avoided wholesale cost. That is, the costs the utility would have incurred had it needed to deliver the electricity to the customer. In this model, consumption of electricity is still priced at TOU retail rates, but excess generation sent to the grid is priced at the cost of generation that was avoided at that time [2]. In order to provide stable investment conditions, the avoided cost rates could be based on a long-term dynamic pricing model that can adapt to future cost uncertainty [2]. While providing lower prices than the retail rate, this model could provide a middle-ground between LDCs and distributed generators, by mitigating the potential need of LDCs to increase their rates to recover their costs from a smaller customer base.

As electricity bills rise and costs of renewable energy fall the transition to distributed generation seems inevitable. Rather than have LDCs find themselves in turmoil in the future, there is real need for the OEB in the ongoing policy discussions to work together with consumers, industry, government, and LDCs to address these issues and find the best solution for Ontario.


[1] Darghouth, R., Barbose, G., & Wiser, R. (2011). The impact of rate design and net metering on the bill savings from distributed PV for residential customers in California. Energy Policy, 39, 5243–5253.

[2] Barraco, J. V. (2014). Distributed energy and net-metering: Adopting rules to promote a bright future. Journal of Land Use & Environmental Law , 29 (2), 365-400



Date Published: July 20, 2017
Written by: Adlar Gross
Category: Blog