Over the past year, the Ontario Energy Board has run two of the more consequential reviews for battery storage in the province: the DSO Roadmap released in December 2025, and the Valuation of Distributed Energy Resources report released this past March. Both followed extensive stakeholder consultation, and both are still working through recommendations rather than finished rules. That matters, because it means the OEB is still listening, and so far, what it’s proposing points in a consistent direction: toward a market that pays batteries closer to what they’re actually worth, and away from rules that were written before distributed storage was a serious part of the grid.
Four of these proposals stand out. One would fix a cost that battery projects shouldn’t be paying in the first place. The other three would open new ways for a battery to earn. None of them are locked in yet, and most don’t have a firm implementation date, but taken together, they’re a clear signal of where the regulatory winds are blowing.
Connection Costs Show Where Today’s Rules Still Work Against Batteries
Connection costs are one of the clearest examples of where existing rules still work against batteries, and a useful place to start, since the reform under discussion here would be a relatively easy one.
When a new generation or storage project is being proposed, the local utility will check to see if the local grid can support the project. If not, the project will be asked to pay to upgrade the local grid before the project can be greenlit. These costs can be significant, and can ruin the economics of many projects.
Ontario Regulation 330/09 lets electricity distributors recover part of the cost of connecting a generation facility from all electricity customers in the province, not only from the customer building the project. The logic is straightforward: a new renewable generator on a distribution system tends to benefit more than just the customer who built it, so it’s reasonable to spread part of the cost across everyone who benefits.
The catch is that this recovery is only available to a “renewable energy generation facility” as defined in the Electricity Act, 1998. Storage doesn’t meet that definition, even when it’s paired with an existing renewable project and delivers the same grid benefit. A battery, in other words, pays the full cost of connecting to the grid on its own, while a solar array next door gets partial help from the system as a whole.
What makes this worth fixing quickly is how small the existing program actually is. In 2026, the total amount distributors will recover under this provision, across all of Ontario’s electricity customers, is about $9 million. Total distribution revenue in 2024 was $4.7 billion. Extending the same treatment to storage would be a rounding error at the system level, but it would meaningfully change the upfront economics of a new battery project.
The OEB has laid out three options for the Ministry of Energy and Mines to consider: keep the current, renewable-only framework in place; extend the same cost-recovery treatment to storage; or build one harmonized connection-cost framework that applies to all distributed energy resources (DERs). Given how modest the existing spend is relative to total distribution revenue, there’s a straightforward case for either of the latter two options.
Distributors Are Positioning to Become a Second Customer for Your Battery
The next three items are all about new ways for a battery to get paid, starting with who’s doing the paying.
Electricity distributors already have the authority to buy DER services, including from batteries, to meet local distribution needs instead of building new infrastructure. If a growing neighborhood is approaching its local capacity limit, a distributor can contract with nearby batteries to shave the peak rather than spend years and tens of millions of dollars upgrading a substation. This is sometimes called a non-wires solution, and the OEB describes it as still fairly uncommon in practice today.
That’s likely to change. The OEB recently updated the Distribution System Code to add a clearer incentive, a margin on payments, for distributors that procure third-party owned non-wires solutions instead of building traditional infrastructure. Combined with the value-stacking reforms the OEB is pursuing elsewhere in the same report, which would let a single battery earn from multiple mechanisms at once rather than being limited to one, the OEB expects distributor-led procurement to become meaningfully more common over the next few years, and eventually to evolve into more standardized, interoperable markets at the distribution level.
For a battery owner, the practical implication is a second buyer for the same asset. A battery already earning revenue from demand response or the wholesale market could, in the years ahead, also get paid directly by its local utility for being available when the local grid needs it, a new revenue stream stacked on top of the ones that already exist rather than a replacement for them.
A Backwards Rate Signal for Class B Customers Is Under Review
For Class B customers not on a regulated price plan, there’s a structural quirk in how the Global Adjustment (GA), the largest component of most commodity bills, gets set. The Class B GA rate moves inversely to average monthly demand: it’s highest in months when wholesale electricity prices are low and supply is abundant, and lowest in months when wholesale prices spike and supply is tight. That’s the opposite of the signal you’d want a battery to respond to. A storage system that avoids grid consumption during a genuinely tight, expensive period is compensated at the lowest point of the GA rate, exactly when the value of what it’s doing is highest.
The OEB has already tested a fix: an optional, time-varying GA price plan for non-RPP Class B customers. Before recommending it, the OEB modeled the impact on customers who choose not to opt in, using data covering more than half of this customer segment from 2021 through 2023. The impact on non-adopters came out to 0.3 percent of the GA portion of their bill or less, low enough that the province is now actively considering rolling out an optional pricing plan along these lines.
If it goes ahead, a Class B battery’s demand-shifting behavior would finally be rewarded for when it actually helps the system, rather than penalized by a rate structure that currently has it backwards.
Net Billing Would Open a New Door, Not Just Improve an Old One
Net billing is the one item on this list that changes not just how much a battery gets paid, but what it’s able to do in the first place.
Ontario’s net metering program today is built around renewable generation: to participate, a facility has to be generating its own renewable electricity, and any credit earned for electricity sent to the grid can only be used to offset the customer’s own future consumption. A stand-alone battery, one that isn’t paired with its own on-site renewable generation, generally doesn’t qualify. In practice, that means most behind-the-meter batteries don’t export power to the grid at all today. What they can do instead is reduce how much the site draws from the grid, discharging to avoid consumption rather than pushing power out. Since Ontario’s commodity charges already vary hour to hour, timing that avoided consumption well already captures some real-time value, in effect, a form of self-arbitrage against the spot price. What it can’t do is get paid for actually exporting power onto the grid, because today, for most stand-alone batteries, that isn’t happening at all.
The OEB’s recommendation is to replace net metering with net billing: a tariff that compensates electricity injected into the distribution system based on its actual time- and location-based value, built from components like a dynamic energy price, generation and transmission capacity value, and distribution capacity value. Notably, the OEB frames this change as a way to enable the broader expansion of behind-the-meter DERs, not only renewable generation facilities specifically. If that framing holds through implementation, net billing would do more than improve the price a battery gets for exporting. It would give many behind-the-meter batteries an actual paid export pathway that most don’t have today.
This won’t happen overnight. The OEB has recommended a staged rollout with legacy protection for customers already on net metering, and the exact eligibility rules for net billing still need to be worked out through the regulatory process. But it’s the clearest sign yet that Ontario intends to pay batteries for something they currently aren’t compensated for at all, not just adjust the price on something they already do.
The Longer-Term Picture: A Real Market Structure Is Being Designed
Beyond these four items, the OEB’s DSO Roadmap lays out a much longer-term project: redesigning how distribution-level markets work altogether. Its first phase, targeted for completion around mid-to-late 2027, is meant to define exactly which services a distributor can buy from a resource like a battery, and to standardize the mechanisms, whether rules, programs, or local markets, used to activate them. Later phases would tackle bigger questions still: whether distributors should be required to formally plan for DER capacity the way they plan for wires and substations today, and what role a distributor, an independent system operator, or some hybrid model should play as these markets mature.
None of this changes anything for a battery operating today. But it’s the clearest evidence yet that the province is planning for a grid where a meaningful share of capacity comes from distributed resources like batteries, rather than treating them as a temporary exception to be managed around.
Bottom Line
None of the four items above are finalized, and outside of the Class B pricing plan, none currently have a fixed implementation date. The connection cost example is a useful reminder that today’s rules weren’t built with batteries in mind, and in places, it still shows. But the pattern across all of these proceedings, how exports get valued, how Class B rates are structured, who’s allowed to buy a battery’s services, and what it costs to connect one, points the same way. And this isn’t a single ruling that could get reversed with the next policy cycle. It’s the product of a multi-year, evidence-based process, with real stakeholder input at every stage, the kind of process that tends to produce durable rules rather than temporary ones.
For anyone already running a battery in Ontario, or thinking about it, that’s a meaningfully better multi-year outlook than the rules describe today.
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