In June 2025, Ontario released Energy for Generations, its Integrated Energy Plan (IEP or Plan), setting a 25-year roadmap for a coordinated energy strategy. At the core of the Plan is a vision to make the grid more resilient, power more affordable, and electricity distribution more reliable across the province. Notably, it places local distribution companies (LDCs) – the local electricity utilities serving communities across the province – at the frontline of this energy transition. As the Plan notes, "Ontario's 59 local distribution companies are the face of the electricity system for most Ontarians."1 These local utilities are the direct link to consumers, responsible for delivering power to millions of customers and maintaining "last-mile" infrastructure.
In the IEP, the Ontario government positions LDCs as central to achieving a modern, high-performing grid. Chapter 4 of Energy for Generations ("Ontario's Future Electricity Grid") highlights their role in unlocking the full value of emerging energy resources and addressing local energy needs. Yet, while LDCs are placed at the centre of this vision, they are also expected to shoulder a growing array of responsibilities, many of which bring significant operational and financial strain. They must navigate growing operational pressures and make strategic decisions with a clear understanding of the shifting, and dynamic, legal, financial and regulatory landscape.
Key points:
- Ontario's IEP places LDCs at the centre of the province's electricity transition, tasking them with enabling complex grid modernization, resilience, electrification, and the integration of distributed energy resources (DERs).
- LDCs face growing operational and regulatory pressures, including rising expectations around outage response, cyber security readiness, electric vehicle (EV) infrastructure, and capital-intensive grid upgrades, all while coping with ever-evolving financial and governance capacities.
- The IEP opens a window of opportunity ranging from shared services, better capacity allocation and voluntary consolidation to targeted regulatory reform and tax incentives that ease barriers to capital deployment and modernization.
- Municipalities, investors and LDC operators must approach this moment strategically, balancing governance, risk, and long-term planning to ensure that Ontario's distribution sector can meet its expanded mandate and responsibilities effectively and sustainably.
The increasing pressures on Ontario's local utilities
The IEP sets an ambitious course for the province's electricity future, but it also reveals the growing burden on Ontario's LDCs. From infrastructure demands to evolving regulatory obligations, LDCs face mounting pressures on multiple fronts.
Enhanced protection mandates
One immediate pressure is the mandate to harden grid resilience, both against physical storms and cyber threats. Recent indications from the Province make clear that LDCs must improve outage response and cyber security preparedness. The IEP calls for distributors to "respond more quickly to storms and major events" as well as bolster their cyber defences, recognizing the rising threat of cyber-attacks on critical infrastructure.2
This policy direction has teeth: as of October 2024, the Ontario Energy Board (OEB) implemented a new "Cyber Security Standard" requiring all electricity distributors to meet specific cyber security controls and participate in sector-wide threat monitoring (the IESO's "Lighthouse" program).3 Obligations include the use of independent (external) cyber security assessments. Compliance is now a condition of LDCs' operating licences, enforceable by OEB orders and steep penalties of up to $1 million per day for non-compliance. In effect, even the smallest utilities must rapidly develop capabilities in cyber security governance and workforce training, real-time threat sharing, and data privacy. This requirement is underscored by the OEB's directive to complete a sector‑wide Distribution System Operator (DSO) capabilities roadmap by December 2025, which will embed cyber security standards and broader modernization objectives into LDC planning frameworks.4 Failure to act promptly could risk not only customer safety and grid reliability, but also regulatory sanctions.
This new cyber security mandate adds to the operational burden on LDCs: many must now invest in IT upgrades and expertise previously beyond their scope. It also underscores the broader expectation of resilience, with distributors now expected to anticipate and withstand severe weather events and cyber incidents in a way that was not contemplated a decade ago.
Electrification and EV integration
The electrification of sectors like transportation and heating is another policy priority that lands squarely on LDCs' doorstep. Connecting the surge of EV demand, from home chargers to public fast-charging stations and electrified transit infrastructure, will require major distribution system upgrades and process improvements. The Province has explicitly flagged this pressure by directing the OEB to review LDC connection timelines for EV customers and report on the reasonableness of those processes by the end of 2025. The clear message is that connection of new EV load must be faster and frictionless. In line with this expectation, the OEB has been directed to review LDC EV connection processes and deliver proposed improvements by December 2025, a timeline that will require distributors to overhaul customer connection procedures quickly.5
In practical terms, going forward LDCs will have to rapidly expand feeder capacity and build new transformer stations in high-growth areas, deploy smart charging management to mitigate peaks, and streamline their customer connection processes; all while avoiding backlogs that could frustrate EV adoption.
While it is not yet clear who will ultimately bear all the costs for capital infrastructure upgrades beyond the service upgrades themselves (transformers, primary/secondary wires, etc.), if the LDC itself does there will be an impact on its rate base.
Customers and policymakers alike now expect LDCs to enable EV charging growth without lengthy delays or reliability issues. Crucially, transportation electrification is accompanied by broader "fuel-switching" in other sectors (e.g., home heating, industrial processes), multiplying the load growth on local grids. Many smaller utilities may struggle to keep pace with this demand surge. Meeting these expectations will test the limits of some distributors' technical bandwidth and capital programs. Accelerating electrification can be seen as a welcome sign of progress on achieving climate and economic goals, but it will add a significant operational strain on the local grids that must power that progress over the next decades.
Integrating distributed energy resources (DERs)
At the same time, LDCs are contending with a proliferation of DERs, from rooftop solar panels and battery storage systems to small-scale generation and emerging technologies. These DERs offer a more decentralized and resilient grid but integrating them is complex. The Plan acknowledges that DERs "have the potential to reduce costs, enhance resilience, and enable consumers to participate in the energy system," but also notes that regulatory changes are needed to realize their value.6 In other words, the frameworks for managing DER implementation are still catching up. The OEB is working to improve DER valuation, connection processes and cost-recovery models, and the IESO has been tasked with developing a program to procure small-scale local generation.7
Until these efforts mature, however, LDCs are operating in a fluid environment, expected to facilitate DER connections and even use them for grid support, yet often without full clarity on rules or cost recovery. The OEB and IESO have now been tasked with finalizing new DER valuation methodologies, incentives and enhanced data‑sharing frameworks by mid‑2026, but until these rules settle, LDCs must navigate an uncertain cost‑recovery landscape.8 These expectations will create a pressure to innovate on the fly.
Capital squeeze
Perhaps the most daunting challenge highlighted by the IEP is the sheer scale of capital investment needed in local distribution infrastructure. The Plan makes clear that Ontario's aging and capacity-constrained distribution grid requires a massive infusion of capital. It estimates on the order of $103–$120 billion will be needed to support local grids over the next few decades.9 This level of investment for new substations, stronger and smarter power lines, digital grid management tools, and general rebuild of the "last mile" dwarfs the current spending trajectory of most LDCs. By way of context, the province's LDCs together currently invest about $2.5 billion annually in their systems;10 the IEP will require a ramp-up that will have to be sustained over many years.
For smaller municipal utilities in particular, finding the capital for transformative upgrades is a looming concern. These utilities have relatively small rate bases and limited ability to shoulder debt while keeping rates affordable. Even with regulated cost recovery, the timing mismatch between upfront investment and gradual payback through rates can strain utilities' finances. There is also a risk of inequity: customers in a small LDC's territory could face sharper rate increases if that utility must spend disproportionately to upgrade aging infrastructure or accommodate new industry. This dynamic is a strong motivator behind the Plan's hints that greater scale (through consolidation or resource-sharing) may be needed to spread costs. The capital challenge means LDC executives, directors and municipal owners must now actively consider exploring external funding sources, partnerships, shared services arrangements and creative financing models to afford to build the grid of the next decades.
Regulatory and compliance complexity
Adding to this set of challenges, Ontario's multiform approach to energy regulation is layering on new requirements as the landscape evolves. LDCs must navigate evolving OEB mandates on everything from outage management and customer service standards to regional planning and third-party access to their grids.
The IEP itself launches several new planning and consultation processes – for instance, a five-year integrated planning cycle that will require extensive LDC input, and various OEB/IESO initiatives on grid innovation and DER frameworks. While each initiative (better outage prevention plans, more transparent connection rules, etc.) may be warranted and will improve the grid, the cumulative administrative overhead is not trivial. Compliance filings, stakeholder meetings and pilot programs all demand dedicated staff time and expertise that smaller utilities may not have in abundance.
These demands will intensify as the OEB launches a new planning forum in early 2026 and requires distributors to build multiple demand‑scenario analyses into all applications filed after April 2027.11 LDCs may feel that the Plan's ambitious "do more, and faster" imperative could stretch their organizations too thin. For instance, an LDC might at once be implementing new billing for EV charging companies (as enabled by recent OEB code amendments), adjusting to updated reliability standards, and piloting a battery storage project, all with the same limited pool of engineers and managers.
As the Electricity Distributors Association noted in commenting on the government's energy vision, a stable policy and planning framework is welcome and indeed "required for an orderly transition," but it must also "prioritize the needs of the distribution sector," including adequate support for local grid modernization and funding access.12 If not managed carefully, there is a risk that heavier compliance workloads and the myriad new programs could divert attention from the LDCs core mandate of keeping the lights on day-to-day. In any event, it seems clear that LDCs will need access to additional and enhanced resources. Historically, though, intervenors in rate applications and the OEB itself have resisted increases in head count, at least to the extent that the cost is to be recovered in rates. The perpetual conundrum of coping with higher rates versus lower LDC profits will be more challenging now than ever.
The Province's challenge will be to ensure that regulation and reporting do not become a bottleneck, and that utilities get the guidance needed to navigate heightened expectations from the multilayered regulatory process.
Looking ahead: Opportunities for strategic actors
While Ontario's IEP sets out an ambitious agenda for the distribution sector, it also undoubtedly opens new avenues for transformation. The mounting demands (cyber security, electrification, DER integration, among others) have prompted a policy and regulatory environment more supportive of strategic change than ever before.
- Scaling and collaboration The Plan highlights the need for greater scale and financial capacity in the sector, nudging LDCs toward consolidation, partnership or shared service models. While full mergers are encouraged, models such as cooperative alliances, like the Cornerstone Hydro Electric Concepts (CHEC), allow smaller utilities to pool resources without giving up local control. These models can unlock operational efficiencies, shared cyber security infrastructure, and talent retention advantages.
- Access to capital The provincial government has reduced structural barriers to investment: the transfer tax and capital gains taxes on LDC transactions have been suspended, offering municipalities a window to explore mergers or bring in private capital without a tax penalty. While the federal 90% municipal ownership threshold remains a constraint, discussions are underway to relax it. Doing so would be a potential game-changer for long-term infrastructure financing. LDCs are also considering the use of creative financing instruments such as convertible securities and tapping into the recently established Building Ontario Fund. There may also be a role for the Canada Infrastructure Bank.
- Innovation and expanded roles The IEP places LDCs as central players in enabling new energy models: managing DERs, supporting EV adoption, and contributing to economic development. It marks a shift in role, from passive distributors to active system integrators. Some LDCs are already piloting local storage, smart charging, and grid-responsive programs. These innovations, once marginal, are quickly becoming essential.
- The new capacity allocation model
Another shift in the operating model of LDCs comes through the introduction of a new Capacity Allocation Model (CAM), which aims to distribute the cost of grid upgrades across multiple operators, rather than "overburdening" the first developer.13
Amidst a set of challenges, this development offers positive perspectives for energy distribution in Ontario: by spreading the cost of new distribution infrastructure across multiple stakeholders, the CAM lowers the entry barrier for new developments. For example, under traditional rules, if an LDC needed to build a new $10 million line for a subdivision, the first developer may have had to pay most of that cost upfront (recovering only partial refunds if others connected within a short window). That "first mover pays" paradigm often delayed or deterred developments.
Now, under the CAM, that same first developer would pay only their proportionate share of the capacity they need (for example, 1/3 of the line's capacity), dramatically lowering their upfront cost, while developers who connect later contribute based on their allocated share. In addition, late-comers will also need to pay a financing charge to "compensate distributors (and ultimately ratepayers) for the carrying costs of the expansions."14 Of course, particularly for smaller LDCs, such a model can exacerbate financing challenges since cost recovery is spread over a longer time horizon. Moreover, LDCs will need more regulatory resources to track developments over a protracted period to ensure that they will receive the cost recovery.
The CAM represents a real shift from the "growth pays for growth" framework to a "we all pay for growth" approach, away from the beneficiary pays principle since current ratepayers are not benefitting from the CAM expansion projects.
In summary, while Ontario's LDCs face rising expectations, they have also been given tools to adapt, scale, as well as a clear policy mandate. The coming years represent a chance to reshape the sector's future role in powering Ontario's growth.
Footnotes
1. Government of Ontario, Energy for Generations, (June 12, 2025) at p. 80.
2. Ibid at pp. 82—84.
3. Ibid at p. 84.
4. Ontario Energy Board, Minister's Directive 802-2025, (June 11, 2025) at p. 9.
5. Ibid at p. 6.
6. Energy for generations, supra note 1at p. 87.
7. Ibid at p. 89.
8. Minister's Directive, supra note 4 at p. 7.
9. Ontario Energy Board, Notice of Amendments to the Distribution System Code, (June 16, 2025) at p. 93.
10. Ontario Environmental Registry, Electricity Distributors Association - Comment on Ontario's Integrated Energy Plan, (November 22, 2024).
11. Minister's Directive, supra note 4 at p. 5.
12. Ibid.
13. Ibid at p. 85.
14. Supra note 6 at p. 2.
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