This bill rewrites the Electric Power Act to require regulators and utilities to plan, compare and report on alternatives to traditional wires investments and to tie utility financial incentives to service reliability and least‑cost outcomes. It adds a policy preamble aligning utility regulation with provincial climate and emissions objectives and creates new statutory tools for planning, budgeting and performance measurement.
For utilities and regulators, the bill shifts the decision framework away from capital‑first solutions toward a comparable evaluation of supply‑ and demand‑side options, and it makes part of a utility’s allowed return contingent on meeting published reliability metrics and successfully implementing cost‑effective non‑wires alternatives. That combination is likely to reshape capital approval, procurement and reporting practices across the province’s electric sector.
At a Glance
What It Does
Directs the Island Regulatory and Appeals Commission to set annual interruption performance targets and requires utilities to produce multi‑year integrated resource plans and public interruption reports. It forces a formal non‑wires alternatives assessment for large capital projects and authorizes a performance‑based earnings adjustment tied to reliability.
Who It Affects
Public utilities operating in Prince Edward Island, the provincial regulator, independent distributed energy resource providers, energy service companies and firms that design or build transmission and traditional generation assets.
Why It Matters
The bill embeds least‑cost and emissions considerations into utility planning and budget approvals and creates explicit financial levers to reward reliability and the deployment of non‑wires solutions — a structural change to how investment decisions and ratepayer costs will be evaluated.
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What This Bill Actually Does
The bill adds specific operational measures the regulator must implement and the utilities must follow. It requires utilities to publish detailed annual interruption reporting using standard industry reliability metrics so that performance can be compared across similarly sized Canadian distributors.
Utilities must prepare multi‑year integrated resource plans at prescribed intervals that analyze both supply‑side options (generation and transmission) and demand‑side measures (efficiency, demand response), plus distributed resources and storage, all on a consistent economic basis.
For larger capital projects, utilities must file a disciplined non‑wires alternatives (NWA) assessment alongside their budgets. That assessment must translate the identified need into hourly load terms, screen potential NWA options, compare economics across the expected asset life, and consider the risk and value of deferring or avoiding stranded assets.
The regulator gets explicit authority to withhold approval for projects where a non‑wires option is demonstrably more cost‑effective for ratepayers.The bill also creates a service performance incentive scheme the regulator must design and publish. That scheme sets the reliability parameters and how they are valued, including dollar‑per‑unserved‑MWh values derived from customer engagement.
The scheme allows measurable upward or downward adjustments to a utility’s allowed return based on performance. The regulator may additionally authorize shareholder incentives to encourage utilities to implement cost‑effective non‑wires solutions, and it treats expenses for approved non‑wires measures comparably to traditional investment costs in rate calculations.Procedurally, the bill gives the regulator explicit approval and enforcement tools: it can hold hearings on integrated resource plans, require plan revisions, demand information on implementation, and publish the performance scheme and customer‑value methodology on a set timetable.
Finally, the bill removes an existing small fine provision for avoidable short interruptions, signaling a move from single fines toward systemic performance measurement and incentive adjustments as the primary enforcement mechanism.
The Five Things You Need to Know
The Commission must establish and monitor SAIDI, SAIFI, CAIDI and MAIFI‑based interruption targets for each public utility and require public reporting that compares utilities to similar Canadian distributors.
Every public utility must submit an integrated resource plan for Commission approval at least once every three years that evaluates supply‑ and demand‑side options on a consistent, least‑cost basis and assesses non‑wires alternatives.
When a proposed capital improvement exceeds a set threshold, the utility must include a non‑wires alternatives assessment with hourly load characterization, option screening, lifecycle economic comparison and stranded‑asset risk analysis.
The service performance incentive scheme will translate reliability into dollar values per unserved megawatt‑hour via customer engagement, and it allows the Commission to adjust a utility’s annual return upwards or downwards within defined bounds.
The Commission may authorize shareholder incentives for successful, cost‑effective non‑wires projects and will treat expenses tied to approved non‑wires alternatives in the same way as traditional approved property costs for rate purposes.
Section-by-Section Breakdown
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Preamble: Aligning utility regulation with climate and least‑cost outcomes
The bill augments the Act’s preamble to state that utility regulation should support climate and emissions goals, integrate renewable and distributed resources cost‑effectively, and align utilities’ financial incentives with reliable, affordable and sustainable service. This is a policy signal that will shape interpretive decisions by the Commission and give statutory cover to weighing emissions and avoided infrastructure costs in regulatory determinations.
Interruption targets and public interruption reports
This new section requires the Commission to set annual system interruption targets and forces utilities to publish an annual interruption report using industry standard metrics (SAIDI, SAIFI, CAIDI, MAIFI). The requirement to compare against comparable Canadian distributors means the Commission will need to set comparability parameters (system size, geography, climate, customer mix) and the utilities will need systems to capture and reconcile interruption data for public disclosure.
Integrated resource planning (IRP) with least‑cost analysis
The Act now requires utilities to submit an IRP for Commission approval at least every three years. Plans must evaluate all feasible supply‑ and demand‑side options consistently — including renewables, efficiency, demand response, storage and distributed generation — and perform a least‑cost analysis that factors reliability, safety, environmental costs, carbon pricing and avoided infrastructure costs. The Commission can hold hearings on IRPs and require revisions, making IRP approval a substantive regulatory milestone before implementation.
Non‑wires alternatives (NWA) assessments tied to capital budgets
The bill inserts a mandatory NWA assessment for proposed property improvements exceeding the budget threshold. That assessment must include an hourly load profile, screening of possible NWAs, a lifecycle economic comparison, and consideration of stranded asset risk. The Commission must not approve a project subject to an NWA assessment unless it is satisfied the proposed investment is the most cost‑effective solution for ratepayers, effectively elevating NWAs to a required comparator in capital approval.
Earnings adjustments, shareholder incentives and expense treatment
The Act is changed to make a utility’s allowed return subject to performance‑based adjustments tied to a published service performance incentive scheme and to permit shareholder incentives for implementing cost‑effective NWAs. Expenses associated with approved NWAs are treated in the same manner as expenses for approved property additions. The scheme must set parameters, dictate relative importance of interruption duration versus frequency, value customer reliability in $/MWh, and allow the Commission to exclude certain severe weather or exceptional events when measuring performance.
Repeal of short‑interruption fine
The bill repeals the existing penalty provision that imposed a small fine for avoidable service interruptions over a short duration. Removing this discrete penalty shifts enforcement emphasis toward the broader performance incentive framework and plan compliance tools introduced elsewhere in the bill.
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Explore this topic in Codify Search →Who Benefits and Who Bears the Cost
Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- Residential, commercial and industrial customers — They gain clearer public reporting on reliability and a statutory process intended to identify least‑cost options, which could lower long‑run rates and improve outage transparency.
- Distributed energy and energy service providers — The mandatory comparison of NWAs and the IRP process create market opportunities for demand response, efficiency, storage and local generation projects that can compete with traditional infrastructure.
- Utilities that adopt cost‑effective NWAs — The Commission can authorize shareholder incentives and allow expense treatment comparable to capital projects, creating a pathway for utilities to earn returns on alternative solutions.
- The regulator (Commission) — Gains explicit statutory tools and criteria (targets, IRP approval authority, NWA tests and a performance scheme) to evaluate projects against provincial policy objectives and to make regulatory trade‑offs more transparent.
Who Bears the Cost
- Public utilities generally — Must develop new reporting systems, prepare periodic IRPs, perform NWA studies and potentially rework capital planning processes; small incumbents may face significant upfront compliance costs.
- Ratepayers in the short term — Implementation costs for planning, studies and possible incentives could be passed through in rates before long‑term savings from NWAs materialize.
- The regulatory body — The Commission will need additional analytical resources and stakeholder engagement capacity to set targets, determine customer reliability values, scrutinize complex IRPs and adjudicate contested NWA comparisons.
- Traditional infrastructure vendors and contractors — May face reduced demand if NWAs delay or avoid transmission and distribution investments, shifting revenue toward distributed solutions and services.
Key Issues
The Core Tension
The bill balances two legitimate goals that pull in different directions: driving utilities and the regulator to prioritize least‑cost, low‑carbon, distributed solutions, while keeping the lights on reliably and preserving financial stability for utilities. Pushing hard toward non‑wires and performance incentives can lower long‑term system costs and emissions, but it requires contested assumptions, new regulatory capacity and careful incentive design to avoid perverse outcomes or under‑investment in essential infrastructure.
The bill forces a switch from project‑by‑project capital approvals dominated by engineering standards toward comparative economic planning that depends heavily on assumptions: load forecasts, technology cost trajectories, carbon prices and the valuation of avoided costs. Those inputs are politically and technically contested; small differences in assumed parameters can flip a decision from wires to non‑wires.
Regulators will need methodologies for consistent valuations and for adjudicating disputes between utilities and third‑party NWA proponents.
Translating customer outage values into dollars per unserved MWh requires careful design: the bill mandates customer engagement, but implementation choices (segmentation by customer class, treatment of reliability events, exclusion of severe weather) will materially affect incentive outcomes. The introduction of shareholder incentives and earnings adjustments also creates an incentive architecture that can be gamed — utilities may structure projects or timing to maximize incentives rather than minimize total system cost — and the Commission’s capacity to monitor outcomes will be crucial.
Operationally, a few implementation risks stand out. The capital‑project threshold can create artificial incentives to split work or reclassify costs to avoid NWA review.
The IRP and NWA analyses add time and cost to project delivery and may delay necessary investments if approval processes are not resourced. Finally, removing the narrow short‑interruption fine while relying on a broader incentive scheme shifts enforcement from a punctual deterrent to a system requiring continual measurement and calibration; that system is only effective if the regulator has the data, expertise and independence to apply it consistently.
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