Articles

Caution Before Convergence: Reflections on the OEA’s Ontario DSO Roadmap

Author:  | July 2026 – Volume 14, Issue 2, 2026

Institutional roles, regulatory sequencing, and the economics of DER value

ABSTRACT

The Ontario Energy Association’s Ontario DSO Roadmap[1] (“the Roadmap”), prepared by Capgemini, is a detailed and thoughtful contribution to the ongoing debate over the future role of Distribution System Operators (“DSOs”) in Ontario. It sets out a coherent, phased pathway toward a Market Facilitator DSO (“MF-DSO”) model, positioning local distribution companies as neutral coordinators of local flexibility markets. The Roadmap is an important sector intervention, and a useful prompt for clarifying how distribution level coordination might evolve in Ontario.

Based on recent work on non-wires solutions and flexibility initiatives, I am not yet convinced that early commitment to a specific DSO market form is warranted. My perspective reflects three related concerns: the risk of blurring longstanding institutional boundaries between energy coordination and network capacity responsibility; the fragile economics of many distributed energy resources (“DER”) enabled non-wires portfolios, even when energy system benefits are included; and the challenge of translating promising pilot activity into rate-funded programs that can be sustained through adjudication. In this context, I focus on the Ontario Energy Board’s dual role as both policy-setting body and adjudicative tribunal, and on how the pace of decision-making is shaped once proposals move from experimentation to precedent. I conclude by outlining a capability-first path forward that preserves regulatory optionality while allowing practical progress to continue.

1. INTRODUCTION: A SERIOUS CONTRIBUTION — AND WHY IT MERITS CAREFUL REFLECTION

The Ontario DSO Roadmap, released early 2026, is a substantial contribution to the debate. It is well-resourced and thoughtfully constructed, reflecting international experience and the practical perspectives of Ontario distribution utilities. Its emphasis on readiness, phased implementation, governance, shared services, and workforce capability distinguishes it from earlier, more speculative DSO discussions.

The Roadmap advances a clear preference for a Market Facilitator DSO, positioning local distribution companies as neutral coordinators of DER participation and local flexibility markets in structured interface with the Independent Electricity System Operator (“IESO”). This is coherent and defensible, particularly for larger distributors already grappling with DER integration. It is also a sector-led proposition.

My observations are informed by recent work on non-wires solutions (“NWS”) and flexibility initiatives undertaken with distributors, customers, developers, and aggregators, including projects carried out under regulatory innovation frameworks. That experience has highlighted both the promise of stronger distribution-level coordination and the practical constraints that emerge once initiatives transition from pilots to rate-funded programs. I focus here on those constraints, and on how they shape the pace and form of institutional change.

Two concerns motivate my perspective.

The first concern is institutional. Ontario’s system has evolved around a functional division: the IESO is responsible for energy system operation and optimization, while distributors are responsible for local reliability, capacity planning, and asset stewardship. A Market Facilitator DSO places distributors closer to dispatch-adjacent, market-facing coordination. Even with safeguards, that can blur accountability — especially under stress conditions — between energy management and capacity provision.

The second concern is economics. Part of the pro-market facilitator narrative assumes DERs will reveal sufficient value, once coordinated, to support durable business cases. Experience to date is more mixed. Distribution-driven NWS cases often have thin margins and high sensitivity to assumptions about growth, timing, and performance. Even when energy system benefits are included, portfolios may depend on stacking value streams whose settlement and governance remain uncertain. Markets can reveal value where it exists, but they do not create it.

These concerns help explain why model neutrality can be a strength at this stage. Neutrality preserves regulatory optionality, emphasizes capabilities over institutional form, and allows evidence to accumulate before commitments are locked in. By contrast, the Roadmap moves from capability development to end-state advocacy — understandable from a sector perspective, but consequential for a regulator acting in the broader public interest.

This discussion is not intended to diminish the value of distributor-led innovation; the focus is on how those ideas translate — or struggle to translate — once they are brought before the Board for approval.

The Roadmap can be read as an important provocation — one that sharpens the questions the regulator must ask — rather than as a blueprint to adopt wholesale. The discipline of phased readiness, shared services, and governance rigor should be retained. But the choice of market form, the allocation of coordination authority, and the institutional treatment of DER value should remain open until the economics and accountability implications are better established.

This article proceeds as follows: the Roadmap is first summarized, then the case for model neutrality is examined, followed by discussion relating to the governance boundary between energy coordination and network responsibility, and the economics of DER-enabled NWS. The article concludes with a capability-first path forward that avoids early lock-in.

2. WHAT THE ROADMAP PROPOSES

The Roadmap is best understood as a sector-led response to a perceived gap between the pace of DER growth and the pace of regulatory and institutional adaptation. It argues that distributors are being asked to make operational and investment decisions using tools and frameworks not designed for a more decentralized system.

2.1. Purpose and orientation

The Roadmap is framed as an input to the Ontario Energy Board’s DSO Capabilities[2] consultation and is intended to accelerate decision-making. It argues that pilots and utility-specific initiatives risk fragmentation without a clear target state and mandate, and that model clarity is a prerequisite for efficient sector investment in systems, skills, and processes.

Importantly, the Roadmap does not present itself as neutral. It advances a clear preference for a specific end state and organizes its analysis around what would be required to reach that state in a disciplined, phased manner.

2.2. The preferred end state: A Market Facilitator DSO

At the center of the Roadmap is an explicit endorsement of a Market Facilitator DSO model. Under this model, local distribution companies would act as neutral facilitators of local flexibility, coordinating DER participation at the distribution level and interfacing with the Independent Electricity System Operator to ensure alignment with bulk-system operations. The MFDSO is presented as a way to unlock DER value efficiently while maintaining system reliability and neutrality.

The report emphasizes safeguards — governance structures, neutrality rules, and clear accountability — to manage conflicts of interest and ensure fair access. Nonetheless, the MFDSO is treated as the preferred evolution of distributor responsibilities in a high-DER future, rather than one option among several.

2.3. A three-phase roadmap to implementation

To move from today’s environment to the MFDSO end state, the Roadmap proposes a three-phase path, with indicative timelines reflecting early adopters rather than a uniform mandate across all distributors.

  • Phase I: Decision and Enablement (2026–2028) affirms the MFDSO model, clarifies roles and neutrality, and begins capability investment.
  • Phase II: Building and Scaling (2029–2034) institutionalizes capabilities and scales beyond pilots, tailored to differing utility maturity.
  • Phase III: Full Integration (2035+) envisions interoperable platforms, standardized services, and ongoing performance monitoring.

The Roadmap is careful to note that these timelines are indicative and that readiness will vary, but the direction of travel is unambiguous.

2.4. Alignment with the OEB’s DSO Capabilities framework

The report maps its recommendations to the four workstreams in the OEB’s DSO Capabilities[3] consultation and presents the MFDSO model as a concrete answer to the regulator’s own questions.

This framing is part of the Roadmap’s core move: to translate an open consultation into a preferred institutional destination.

2.5. Strengths of the Roadmap’s approach

Even viewed critically, the Roadmap has notable strengths. It treats DSO development as institutional change, not just technology deployment, and gives sustained attention to workforce capability, cybersecurity, governance, and shared services. It also acknowledges distributor heterogeneity and the potential role of shared or “DSOasaservice” arrangements for smaller utilities.

These strengths help explain the Roadmap’s traction: it offers clarity and momentum at a time when many stakeholders are frustrated by uncertainty.

Precisely because the Roadmap is coherent, it warrants careful examination. The sections that follow question whether convergence on a Market Facilitator DSO — and the implied sequencing — is justified by current economics, institutional roles, and empirical experience in Ontario.

3. WHY MODEL NEUTRALITY IS A DELIBERATE AND NECESSARY DESIGN CHOICE

3.1. Neutrality as regulatory discipline, not indecision

At the center of the Roadmap is the question of model neutrality. The Roadmap advances a clear preference for a Market Facilitator DSO end state.

An argument for neutrality on the ultimate institutional form of the DSO should not be seen as accidental, nor as a failure to take a position. It should be seen as a conscious design choice rooted in regulatory discipline.

There are practical questions to be asked — where flexibility is viable, what functionality is required, and how readiness can be demonstrated within existing OEB processes — before a commitment is needed to any single end-state DSO model.

In practice, neutrality has been less about withholding judgment and more about keeping sequencing manageable. In projects where distributors, customers, and developers are working through real system needs, the immediate questions tend to be practical ones: Is flexibility actually available in the constrained area? What level of visibility and control is required? How would performance be verified if the solution were relied on in planning?

Deferring decisions about market form has allowed that work to proceed without forcing agreement on institutional end states before the evidence is ready. Where coordination approaches prove workable and economic, the case for expanded authority can then be tested in adjudication. Where they do not, the system avoids having locked itself into structures that are difficult to unwind.

3.2. Capabilities first, market form later

Separate the question of what needs to be done from the question of who ultimately does it, and through what market structure. Basic work must happen — needs assessment, customer availability, functional assessment, and economic assessment — before it can be determined whether flexibility is a viable alternative to traditional infrastructure in any given context.

3.3. Preserving regulatory degrees of freedom

From a regulatory perspective, early convergence on a single DSO model carries significant risk. Institutional design choices in electricity systems tend to create path dependency: once market rules are codified, platforms are funded, and organizational roles are formalized, changing direction becomes difficult even if underlying assumptions change. Neutrality in early frameworks helps preserve degrees of freedom at a stage when uncertainty remains high.

This concern is particularly acute in the DSO context because multiple elements are evolving simultaneously: DER technology, economics, customer participation, data availability, coordination with bulk-system markets, and incentive structures. An orientation that is bottom-up and evidence-based, focusing on implementation feasibility rather than top-down policy positioning, supports learning across this uncertain terrain.

Neutrality also allows for differentiation across distributors. Ontario’s local distribution companies (“LDCs”) vary widely in size, system complexity, and DER penetration. A neutral, capability-focused framework enables some distributors to move quickly on specific use cases while allowing others to proceed more cautiously, without forcing all participants into a single institutional trajectory.

3.4. Avoiding premature institutional lock-in

The practical effect of neutrality is to delay institutional lock-in until the system has demonstrated that it can support it. This does not mean delaying action. On the contrary, regulators should encourage distributors to act — to integrate flexibility into planning, to test non-wires solutions, and to build operational experience — but to do so in a way that generates evidence rather than commitments.

Neutrality functions as a sequencing device: capability before authority, learning before locking in. The risk of drift is real only if neutrality is mistaken for inaction; in practice, structured frameworks can accelerate experimentation by decoupling near-term work from end-state agreement.

4. A CENTRAL GOVERNANCE TENSION: ENERGY COORDINATION VS. CAPACITY AND NETWORK RESPONSIBILITY

4.1. Two coordination problems that are often conflated

At the heart of the DSO debate lies a distinction that is easy to blur in conceptual discussions but difficult to ignore in practice: the difference between energy coordination and capacity (or network adequacy) responsibility. These are related but distinct coordination problems, with different temporal characteristics, economic signals, and institutional implications.

Energy coordination is primarily about balancing and optimization in real and near-real time, producing marginal price signals and managing system-wide constraints — naturally suited to the bulk system.

Capacity and network responsibility is about adequacy over time: whether local infrastructure (or alternatives) can reliably serve load under peak or stressed conditions, and how discrete investments are made, deferred or avoided. These questions are local, planning-driven, and episodic.

The challenge for DSO design is not that these domains interact — they clearly do — but that they require different coordination logics and different accountability structures.

4.2. Ontario’s institutional structure and why it matters

Ontario’s electricity system has evolved around a relatively clear institutional structure. The IESO is responsible for bulk-system operation, energy market administration, and system-wide reliability. LDCs are responsible for the planning, operation, and maintenance of their networks, including decisions about capacity investments and alternatives to traditional infrastructure.

This division is not arbitrary. It reflects differences in scale, information, and risk. Energy markets benefit from centralized optimization and common price signals; distribution planning benefits from localized knowledge, engineering judgment, and long-term asset stewardship. Importantly, this structure also clarifies accountability: when something goes wrong, it is generally clear which institution is responsible and under what regulatory framework it is held to account.

Any redefinition of DSO roles must therefore be assessed not only in terms of efficiency or innovation potential, but also in terms of how it affects this accountability structure.

4.3. Where the Market Facilitator DSO introduces tension

The Market Facilitator DSO model advanced in the Roadmap moves distributors closer to market-facing coordination roles. Market facilitation, even when carefully circumscribed, entails activities such as accepting offers, sequencing activation, and managing interactions between local resources and broader system needs. These activities sit uncomfortably close to the domain of energy coordination, particularly when local flexibility is also expected to participate in bulk-system markets.

The Roadmap acknowledges neutrality safeguards and interfaces with the IESO. But facilitating a market is not the same as administering a program: it entails sequencing, prioritization, and settlement choices that resemble energy-management decisions, even if framed as local.

The risk is less deliberate overreach than boundary erosion as complexity grows. Under stressed conditions — when local constraints and system-wide shortages coincide — responsibility can become harder to assign.

4.4. Accountability under stress: the real test of institutional design

Institutional arrangements are rarely tested by average conditions; they are tested by extremes. In the DSO context, this raises practical questions that a Market Facilitator model must answer convincingly. When local flexibility is scarce, prices spike, or DERs fail to respond as expected, who is accountable for the outcome? If local activation to address a distribution constraint conflicts with bulk-system dispatch priorities, whose decision prevails, and under what rules?

These questions go to the core of regulatory oversight and dispute resolution. From a regulator’s perspective, preserving clear lines of accountability can be as important as improving coordination efficiency.

4.5. Capacity provision is not energy management by another name

A recurring theme in DSO discussions is the assumption that local flexibility can be treated symmetrically with energy resources, simply at a smaller scale. This assumption underpins much enthusiasm for local markets. Yet many capacity-driven use cases do not behave like energy markets. They are activated infrequently, targeted to specific assets, and valued primarily for their option value rather than continuous marginal production.

In such cases, the logic aligns more with procurement and contracting than market clearing. The distributor’s task is to ensure dependable capability when needed, not minute-by-minute optimization.

4.6. Why role clarity should precede role expansion

The argument here is not that distributors should never play an expanded coordination role, nor that local markets are inherently inappropriate. It is that role clarity should precede role expansion, particularly when new roles blur longstanding institutional boundaries.

The neutrality embedded in the OEB’s default framework reflects an awareness of this risk. By focusing on capabilities rather than end states, distributors can build experience in identifying, procuring, and operating non-wires solutions without assuming that market facilitation is the inevitable destination. This sequencing preserves the ability to assess, with evidence, whether expanded market roles actually improve outcomes or simply redistribute responsibility.

4.7. Implications for regulators

For regulators, the central implication is straightforward: decisions about DSO roles should be evaluated through the lens of institutional coherence and accountability, not solely through the promise of innovation or alignment with international models. The question is not whether local flexibility should be coordinated — it clearly must be — but how that coordination is best achieved.

The sections that follow build on this governance concern by examining whether the economic characteristics of DERs and non-wires solutions support the level of market sophistication implied by a Market Facilitator DSO, and whether shared platforms can deliver many of the same benefits without prematurely reallocating authority.

5. ECONOMIC REALITY CHECK: DERS, NWS, AND THE DIFFICULTY OF A STANDALONE BUSINESS CASE

5.1. Why “distribution cost avoidance” is a hard foundation to build on

Ontario’s regulatory architecture for non-wires solutions is designed to force economic clarity. The OEB’s Benefit-Cost Analysis (“BCA”) Framework[4] requires a mandatory Distribution Service Test (“DST”), with an optional Energy System Test (“EST”) for system-wide impacts. In practice, the DST is where most distribution-justified NWS proposals rise or fall, because the central quantified benefit is typically distribution capacity deferral or avoidance.

Distribution deferral value is often location-specific and episodic, becoming material only during certain hours or under certain growth scenarios. As a result, DST results are sensitive to assumptions about load growth, the timing of avoided investments, and portfolio performance during binding hours. Even when avoided costs are real, the value available to pay for dependable flexibility can be modest relative to the actual acquisition and integration costs of the kilowatts.

5.2. “Who ultimately pays” is not a footnote — it is the business case

A recurring feature of distributor-led NWS concepts is that much of the capacity sits behind the meter. Where the NWS capacity is customer-sited, the implication is that the ultimate funder of NWS is the customer itself. This is more than a modelling detail: it highlights the central economic challenge that many DER options require customers to bear upfront capital and operational burdens that are not naturally aligned with the distribution value being pursued.

In addition, the BCA Framework’s emphasis on symmetrical treatment affects how “who pays” is reflected in regulatory tests. The BCA Framework notes that host (customer) costs and benefits are excluded from the DST and EST to avoid asymmetry and bias, referencing the Framework’s “symmetrical treatment” principle. This approach is analytically disciplined for regulatory comparisons — but it also means that a large portion of the real economic burden of behind-the-meter options can sit outside the formal tests, surfacing instead as the practical requirement for incentive payments large enough to make participation rational.

5.3. Energy system benefits can be large — and that both helps and complicates matters

One response to the thinness of distribution deferral value is to broaden the lens and include energy system impacts. The OEB’s framework anticipates this by allowing an optional EST that considers generation and transmission impacts from the Ontario system perspective. In principle, layering energy system benefits onto an NWS portfolio should make the overall economics appear substantially stronger.[5]

Energy system benefits are in fact frequently far larger than distribution deferral value. This matters: DER portfolios may be socially efficient even when the distribution-only case is marginal or negative.

But large system-wide benefits create a mandate problem: who procures, dispatches, and funds value that sits outside the distributor’s direct accountability? The EST is optional in distributor filings precisely because many energy system benefits are not within a distributor’s control.

5.4. The “value stacking” fragility problem: plausible on paper, uncertain in practice

In practice, many DER portfolios are viable only when value streams are stacked (distribution deferral, reliability, and energy system impacts, potentially alongside other programs). The OEB NWS Guidelines and BCA Framework acknowledge this complexity and set expectations for evidentiary discipline in presenting such cases.

Stacking, however, requires workable arrangements for settlement, verification, and cost responsibility. When value is assembled from multiple components, the investment case can become sensitive to methodological and institutional choices, not just engineering performance.

5.5. The hidden cost driver: treating NWS capability as “incremental”

A further challenge is that the cost of making NWS operable — data, customer acquisition, contracting, monitoring and verification, and operational workflows — can dominate early economics if attributed to a single project. These fixed and organizational costs do not scale linearly with kilowatts procured, so early benefit-cost ratios can look weak even when the underlying concept is sound.

There is not yet a single settled template for what a proportional evidentiary package should look like under the OEB’s NWS Guidance[6] and BCA Framework. That flexibility creates room for learning — but it also means early NWS cases will be sensitive to methodological choices about enabling costs, baselines, and performance assumptions.

5.6.  Implications for the DSO debate: markets do not manufacture value

The argument is not that DERs lack value. It is that the economic base for many DER-enabled NWS cases is thinner and more conditional than DSO narratives sometimes imply — especially when distribution deferral is modest and the remainder depends on benefits outside a distributor’s mandate. The OEB framework reflects this: the DST is mandatory and distribution-anchored; the EST is optional and system-wide.

If underlying value is localized and episodic, continuous local markets should be treated as a hypothesis to test, not a default. Capability building and interoperability should proceed; market authority should remain proportionate to demonstrated opportunity.

6. MARKET FACILITATION VS. SYSTEM COORDINATION: MARKETS ARE NOT FIRST PRINCIPLES

6.1. Markets can reveal value, but they do not define the problem

The Roadmap’s preference for a Market Facilitator DSO implicitly treats “market-making” as the natural endpoint for distribution-level flexibility. A counterweight view begins from the opposite direction: the coordination problem comes first, and the choice of solution — including whether a market is warranted — comes second. In the Ontario context, this distinction is more than semantic. The functionality required for distributors to integrate non-wires solutions is not necessarily analogous to what would be required to “stand up” a full flexibility market; it depends on whether acquisition and activation are program-based or market-based.

This framing distinguishes between a “market” as an economic context and a “marketplace” as a specific platform or venue for transactions. The difference matters because a marketplace is an institutional choice — one with fixed costs, governance implications, and a need for sufficient participation — whereas many distribution service needs can be addressed economically through more direct forms of coordination without requiring continuous price discovery or frequent transactions.

6.2. Distribution service needs often favour targeted coordination over continuous market clearing

Distribution service needs are typically local, constraint-driven, and time-bounded: manage peak loading on a specific element, often to defer a discrete investment. That profile does not automatically imply a standing local market platform. If an NWS can be dispatched against the binding hours, simpler procurement and activation coordination approaches may be sufficient.

Before Ontario commits to an institution whose raison d’être is market facilitation, it should be confident that the predominant near-term coordination problems actually require market infrastructure rather than operational and contractual coordination.

6.3. “Flexibility” frequently includes resources that are not naturally market-procured

A further caution arises from what Ontario policy and guidance already count as “flexibility” or NWS-eligible resources. The OEB’s Non-Wires Solutions Guidelines provide examples that include dispatchable resources such as demand response and storage, as well as longer-term components like efficiency or managed load that reduce exposure to peak conditions over time. The IESO’s electricity demand-side management (“eDSM”) framework[7] targets many of the same customers and technologies, but for system-level resource adequacy objectives — highlighting that similar customer actions may be pursued for different reasons, and that not all resources labelled “flexibility” are intended to be dispatchable or locationally responsive from a distribution system perspective.

This matters because many of these options do not behave like classic market commodities. The variation of customer size and type, and available combinations of technology, creates a diverse supply chain. Intermediate agents (aggregators) can play an important role in customer participation and price formation. Technology manufacturers and metering providers also participate in setting prices for dispatchable control.

Long-term assets such as retrofits for mechanical, thermal, and electrical upgrades can permanently reduce peak demand — high upfront costs followed by ongoing reductions — but might not be procured in a real-time flexibility market. The conclusion is not that markets are irrelevant, but that treating market facilitation as the default end state risks overfitting institutional design to a small subset of dispatchable, short-duration resources, where simpler, more durable, and more cost-effective opportunities may be available over time.

6.4. Program-based and bilateral approaches are not second-best; they are often fit-for-purpose

Ontario’s current NWS landscape has been shaped more by programmatic and bilateral approaches than by formal market constructs. Flexibility does not always mean running a local market or auction, and where a need can be met by a few known resources or a long-term demand reduction, a full market platform might be overkill.

This is not an argument against sophistication. It is an argument for sequencing and proportionality: use the simplest mechanism that reliably delivers the required service, while building the capability base that could support more complex arrangements later if and when conditions warrant.

6.5. When do flexibility markets make sense? Competition, not coordination, is the differentiator

A defensible role for local flexibility markets emerges when the underlying conditions support genuine competition and repeated transactions. Flexibility markets are most useful when multiple providers can compete to provide the service at least cost; otherwise, traditional programs or direct contracts may achieve the goal more straightforwardly.

This perspective also helps reconcile the “market” and “marketplace” distinction. A marketplace can be designed to engage customers in a simple, accessible way, and aggregators can help translate customer-sited capabilities into transaction-ready offerings. But these are design opportunities, not proofs of necessity. If the distribution problem is primarily one of local constraint management with episodic dispatch needs and thin distribution deferral value — as discussed in Section 5 — then the bar for standing up new market institutions should be correspondingly high.

6.6. Implication for the DSO debate: capability first, market form later

The near-term priority should be to strengthen coordination capabilities — planning integration, customer targeting, data visibility, operational procedures, and interface management. For many use cases, modest extensions of business-as-usual processes can be enough to identify candidates, procure availability, and dispatch and verify performance when needed.

This is the sense in which markets are not first principles. The first principles are: define the system need, identify feasible alternatives, ensure accountability and operational reliability, and only then choose the institutional mechanism — market, program, bilateral contract, or hybrid — that fits both the economics and the governance context.

7. SHARED PLATFORMS WITHOUT PREMATURE MARKET AUTHORITY

7.1. Where there is broad alignment: platforms, interoperability, and shared services

One of the strongest and least controversial elements of the Roadmap is its emphasis on shared platforms, interoperability, and common services. On this point, there is substantial alignment across the sector. Few would dispute that Ontario’s distributors face growing challenges related to DER visibility, data access, telemetry, monitoring and verification, cybersecurity, and settlement-grade record-keeping. These are not hypothetical future needs; they are already constraining the ability of distributors to plan, assess, and operate non-wires solutions under existing regulatory expectations.

Importantly, the case for shared platforms does not depend on the adoption of a specific DSO market model. Common data standards, interoperable systems, and shared service arrangements can support a wide range of coordination approaches, from program-based NWS procurement to bilateral contracts and, eventually, more market-like approaches. In this sense, the Roadmap’s platform agenda is best understood as foundational infrastructure, not as an implicit endorsement of market facilitation as the default operating role.

This distinction matters because platform investments are costly, long-lived, and difficult to unwind. Regulators should therefore be attentive to what functions those platforms are enabling, and who is granted authority to use them for price formation, dispatch sequencing, and settlement.

7.2. Platforms are not markets — and data exchange is not price formation

A recurring risk in DSO discourse is the quiet conflation of platforms with markets. Data exchange, visibility, and coordination are often discussed in the same breath as bidding, clearing, and settlement, even though these are conceptually and institutionally distinct activities. The key point is that data-sharing infrastructure can enable multiple coordination approaches; it does not, by itself, require distribution-level price formation or market-clearing authority.

A shared registry, telemetry backbone, and monitoring and verification service can materially improve planning and operational confidence without conferring market authority. Market clearing and local price formation, by contrast, raise governance and accountability questions and require explicit interfaces with bulk-system operations.

Where DER value is thin or capacity-driven, the incremental benefit of continuous price formation may be limited. Platforms that support contracted availability, targeted dispatch, and auditable performance may deliver most benefits with less institutional complexity.

7.3. The danger of coupling platform build-out to a single end state

The Roadmap understandably seeks to provide clarity and direction after years of pilot activity. However, coupling the development of shared platforms too tightly to a single DSO end state risks narrowing regulatory options prematurely. Once platforms are designed around market-clearing logic — specific bidding formats, settlement rules, and dispatch hierarchies — it becomes difficult to repurpose them for alternative coordination models without significant re-engineering.

Heterogeneity amplifies this risk. Larger utilities may justify more complex tools sooner; smaller utilities may not. A platform strategy that assumes universal readiness for market facilitation can impose unnecessary costs. Shared platforms should be treated as modular and role-agnostic and let evidence determine where markets add value.

7.4. A modular architecture: coordination without role confusion

A modular platform architecture allows Ontario to separate three questions that are often collapsed into one:

  1. What information and control capabilities are required? (e.g., DER registration, visibility, telemetry, monitoring and verification, cybersecurity)
  2. How customer and technology portfolios are constructed and managed for a given use case in terms of the combinations involved, and how those resources are assembled and relied on (for example, targeted customer segments, specific technology portfolios, or contracted resource groupings)?
  3. Which institution is accountable for which decision? (e.g., distributors for local capacity adequacy; the IESO for energy dispatch and system-wide optimization)

This enables distributors to procure capacity-oriented services and verify performance using shared tools while the IESO retains energy market operation and balancing. Where dual participation is needed, interfaces can be specified explicitly rather than assumed.

This approach is consistent with the phased, “simplified DSO model” articulated in the OEB DSO Capabilities report[8]: build the minimum viable capabilities needed to act on near-term opportunities, while avoiding early commitments that prejudge the eventual institutional structure.

7.5. Shared services as a hedge against uncertainty, not a shortcut to markets

Shared services can be a hedge against uncertainty, rather than a shortcut to market sophistication. Cybersecurity operations, data governance, analytics, and even elements of customer engagement and aggregation support can be pooled across distributors to reduce duplication and manage risk. None of these functions require, or imply, that distributors must also act as market facilitators.

Seen in this light, the most durable contribution of the Roadmap may lie not in its preferred end state, but in its insistence that Ontario stop treating coordination capability as an abstract future requirement. The challenge for regulators is to ensure that the means — shared platforms and services — do not quietly determine the ends by embedding market authority before the economic and institutional case has been made.

The guiding principle should therefore be simple: build platforms that enable coordination first and decide later — on the basis of evidence — where markets are truly warranted.

8. POLICY DIRECTION, ADJUDICATION, AND THE NEED FOR REGULATORY PACE TO KEEP UP

8.1. The OEB’s dual role: policy development and adjudication

A further reason for caution before convergence lies in the institutional structure of the OEB itself. The OEB operates with a deliberate separation between its policy-setting functions — including guidelines, frameworks, consultations, and staff-led reports — and its adjudicative role, exercised by commissioners through contested proceedings and reasoned decisions.

Recent policy instruments — the NWS Guidelines, BCA Framework, DSO Capabilities consultation, and related innovation initiatives[9] — signal a clear direction: lower barriers to DERs, require proportional NWS consideration, and strengthen coordination. They are necessary enablers, but they do not replace adjudicative determinations on cost recovery, authority, and accountability.

Policy direction alone is not determination. Commissioners must decide contested cases on evidence; end-state claims that ignore this risk overstating the feasible pace of institutional change.

8.2. Provincial priorities matter — but they do not substitute for adjudication

The momentum behind DSO concepts is also reinforced by broader provincial government priorities: electrification, reliability, affordability, economic growth, and decarbonization. These priorities are expressed through ministerial directives, long-term planning frameworks, and funding programs that emphasize flexibility, demand-side resources, and efficient use of infrastructure.

The Roadmap aligns well with these objectives, particularly in its focus on enabling DER participation and avoiding unnecessary capital investment. That alignment strengthens the Roadmap’s policy relevance. But alignment with government priorities does not eliminate the need for careful regulatory sequencing. The OEB’s statutory role is not to implement policy preferences directly, but to translate them into outcomes through evidence-based decisions that withstand scrutiny.

This distinction is especially important in the DSO context, where changes to roles, market authority, and coordination responsibilities would have far-reaching implications for cost allocation, risk assignment, and customer outcomes.

8.3. Why adjudicative pace — not policy ambition — sets the real tempo

From the perspective of Commissioners, the challenge is not whether DSOs are conceptually attractive, but whether specific proposals can be decided, justified, and defended within the confines of an adjudicative record. Decisions must be grounded in demonstrable need, clear statutory authority, and evidence of net benefit to customers. They should aim to be sufficiently generalizable to serve as informative frameworks for policy discretion, rather than bespoke accommodations for early movers.

Once proposals move from externally funded pilots to rate‑funded programs, the conversation changes materially. The questions that matter in adjudication are not whether an approach aligns with policy objectives, but whether it can be justified in comparison to alternatives, supported by evidence, and relied on to inform decisions in the specific circumstances of a case. In that setting, ambitions about end states tend to meet very concrete tests around scope, cost, accountability, and risk allocation.

This is why the pace of adjudication often becomes the binding constraint — not because of resistance to change, but because institutional decisions have to be durable once made. Moving too quickly to define roles or authority can narrow options before the evidence base is strong enough to support them.

8.4. The value of guidelines as “enablers,” not substitutes

Seen in this light, the OEB’s recent policy instruments serve an important but bounded role. Guidelines and frameworks are enablers: they clarify expectations, reduce friction, and create space for experimentation. They are not substitutes for adjudication, nor are they mandates for specific institutional forms.

Focusing on capabilities, feasibility, and proportionality supports the adjudicative process rather than preempts it, allowing evidence to accumulate before asking for broad change.

8.5. Keeping policy, government direction, and adjudication aligned

The risk, therefore, is not that the OEB will fail to act, but that policy ambition, sector advocacy, and government priorities move faster than the adjudicative machinery can responsibly follow. When this happens, pressure builds for regulatory shortcuts: endorsing end states “in principle,” embedding assumptions in platforms or codes, or allowing early decisions to harden into de facto regulatory policy.

A more durable approach keeps roles aligned but distinct:

  • Government articulates priorities and long-term objectives.
  • OEB policy creates frameworks that enable innovation and learning.
  • OEB adjudication determines, case by case, which tools, roles, and authorities are justified.

8.6. Implications for the DSO debate

Applied to the DSO question, this perspective reinforces the case for restraint. The issue is not whether Ontario will need stronger distribution-level coordination — it will — but whether the evidentiary record is yet sufficient for Commissioners to endorse a Market Facilitator DSO as the default institutional form.

Until that record exists, the most constructive role for policy-makers and sector leadership is to feed the adjudicative pipeline with credible, well-bounded cases, rather than to seek early endorsement of an untested end state.

8.7. Moving beyond pilots means entering the adjudicative arena

A recurring argument advanced by distributors is that Ontario must “move beyond pilots.” As a statement of intent, this is uncontroversial. As a regulatory proposition, it has a precise and demanding meaning.

Most flexibility-related pilots over the past several years have been supported by external funding — through innovation challenges, government programs, or system-level innovation funds. These pilots have been valuable in surfacing technical, operational, and customer-engagement insights. But critically, they have required little if any adjudicative review, and the business case has been conditional on the third-party funding. They have not been fully funded through rates, nor tested against the evidentiary standards that typically apply when distributors seek to recover costs from customers.

In practice, moving beyond pilots has meant something quite specific: shifting from learning under external funding to proposing initiatives that rely on ratepayer support. That shift brings different evidentiary expectations, and experience suggests it is often where otherwise promising concepts are most rigorously tested.

Moving beyond pilots is to change the regulatory footing of these activities. Once distributors propose to fund flexibility programs, platforms, or markets with ratepayer dollars, they must bring those proposals before the OEB. At that point, the relevant question is no longer whether an approach is innovative or aligned with policy objectives, but whether it meets the evidentiary tests required for approval: demonstrated need, proportionality, cost-effectiveness, clear accountability, and net benefit to customers.

This distinction matters because pilots are, by design, insulated from the full discipline of adjudication. They allow learning under conditions of reduced risk and simplified governance. Adjudicated programs do not. They must be justified in comparison to alternatives, subjected to cross-examination, and capable of informing reasoned decisions. The burden shifts decisively onto the proponent.

From this perspective, calls to move beyond pilots need to acknowledge the central role of adjudication: the transition from pilot to program is not a matter of confidence or readiness; it is a matter of evidence. In this sense, adjudication is not a brake on momentum but the mechanism through which momentum becomes durable.

For Commissioners, that means sequencing matters. Pilots can inform judgment, but institutionalized roles and rate-funded programs require a record robust enough to withstand scrutiny and meaningfully inform panel deliberations.

9. A CONSTRUCTIVE PATH FORWARD: CAPABILITY FIRST, ORTHODOXY LATER

9.1. Retaining what the Roadmap gets right

A constructive response to the Roadmap begins by retaining its strongest elements: phased progression, readiness assessment, shared services, workforce capability, and attention to governance and cybersecurity. These foundations matter regardless of how the DSO question ultimately resolves.

Equally important is the roadmap’s recognition that Ontario’s distributors are heterogeneous. Differences in size, system topology, DER penetration, and organizational capacity mean that a one-size-fits-all implementation path would be both inefficient and inequitable. Any credible path forward must therefore allow for differentiated adoption speeds while preserving system-wide coherence where it matters most.

9.2. What should remain explicitly open

Caution is warranted in the transition from capability development to institutional prescription. Three questions, in particular, should remain explicitly open in the near term.

First, how local coordination is executed. Whether a given need is best met through programmatic incentives, bilateral contracts, operating envelopes, auctions, or some hybrid approach should be determined by the nature of the need, the economics of the solution, and the number of credible providers — not by a presumption that markets are the default solution.

Second, where price formation occurs. Energy price formation and system-wide optimization remain the core responsibility of the IESO. Introducing local price signals may be useful in some contexts, but doing so raises questions about interaction effects, accountability, and dispute resolution that should be addressed through evidence and testing rather than assumption.

Third, how local and bulk-system signals are reconciled. Dual participation, residual flexibility, and coordination under constrained conditions all require carefully designed interfaces. These interfaces can be explored through sandbox testing, tabletop exercises, and targeted pilots without committing to permanent market authority at the distribution level.

Keeping these questions open is not indecision; it is disciplined sequencing. Nothing in this approach precludes a Market Facilitator DSO where evidence supports it; it simply avoids assuming that outcome in advance of an adjudicated evidentiary record and decision.

9.3. A capability-first regulatory posture

A capability-first posture offers a practical way to reconcile momentum with caution. Under such an approach, the regulator would require distributors to demonstrate competence in a defined set of functional areas — planning integration, customer targeting, data access and visibility, operational procedures, and performance verification — before granting additional authority. Evidence, rather than aspiration, would determine when and where more complex coordination approaches are warranted.

This posture aligns with existing guidelines and frameworks in Ontario. The NWS Guidelines, BCA Framework, and DSO Capabilities consultation emphasize demonstrated need, feasibility, and proportionality — what distributors must be able to do, not a single end state.

9.4. Conditional decisions instead of binary choices

One of the implicit pressures in the DSO debate is the perception that Ontario must choose between decisive convergence and indefinite delay. In practice, regulators have a wider menu of options. Conditional decisions — authorizing specific activities subject to defined evidentiary thresholds — are a familiar and effective regulatory tool.

Applied here, this could mean endorsing shared platforms and services, approving targeted pilots where markets appear promising, and setting criteria that must be met before broader market-facilitation authority is granted, such as economic durability, sufficient participation, interoperability, and clear accountability.

9.5. Reframing the central question

The most productive way to reframe the DSO debate is to shift the focal question. Instead of asking “Which DSO model should Ontario adopt?”, regulators and stakeholders might ask: “Which coordination problems must be solved, through which portfolios of customer-sited resources, and by which accountable institution?” This reframing keeps attention on outcomes — reliability, affordability, and system efficiency — rather than on institutional labels.

From this perspective, market facilitation becomes one possible tool among many, rather than the defining feature of a future DSO. It may prove appropriate in some contexts and unnecessary in others. The task of regulation is not to pick the winner in advance, but to ensure that whatever level of coordination is required is justified by evidence and aligned with clear accountability.

Ontario can move decisively on capability building, shared services, and governance reform while postponing firm decisions about market form until economics and institutional interfaces are better understood. This respects the Roadmap’s leadership without allowing early advocacy to harden prematurely into architecture.

10. CONCLUSION: CAPABILITY BEFORE COMMITMENT

The Roadmap arrives at a moment when Ontario’s electricity system is under real pressure to adapt. Its call for momentum is understandable, and many of its recommendations — particularly those related to phased readiness, shared services, workforce development, and governance discipline — are timely and well founded.

There is an argument to be made, however, that the Roadmap’s call for early commitment to a specific DSO market form is premature. The core issue is not whether Ontario should enhance distribution-level coordination, but how that coordination should be structured, sequenced, and governed. DER economics are often thin, highly contextual, and sensitive to assumptions; in such conditions, market facilitation should be treated as a tool to test in bounded settings — not as an organizing principle.

Institutional clarity matters as much as economic realism. Ontario’s longstanding separation between bulk-system energy management and local network capacity responsibility has served the system well. Blurring this boundary through early assignment of market-clearing or dispatch-adjacent authority at the distribution level risks creating ambiguity precisely where accountability must be most robust. The challenge is not intent or competence, but durability under stress.

A more resilient path forward is therefore capability-first. Ontario can move decisively to build the functions required to plan for, procure, and operate non-wires solutions — data visibility, customer targeting, operational procedures, performance verification, and secure interfaces — without predetermining the eventual market form. Shared platforms and services should be designed to enable coordination across a range of acquisition models, not to embed market authority by default. Conditional decisions, phased permissions, and clear evidentiary thresholds can provide momentum without locking in.

Reframed this way, the central question is not “Which DSO model should Ontario adopt?” but “Which coordination problems must be solved, with which coordination approach, and by which accountable institution?” Answering that question requires patience as well as resolve. It requires regulators to move more slowly than advocates, not out of caution for its own sake, but to preserve optionality while learning accumulates.

The Roadmap is best read in this spirit: not as a destination, but as a well-argued proposal that sharpens the regulator’s questions before it narrows the regulator’s choices.

 

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