Nova Scotia Power must show future rate impacts of capital spending

Nova Scotia Power must explain how its next annual capital plan would affect different customer classes’ rates in 2028, 2029 and 2030, under new directions accompanying approval of most of its 2026 spending plan. The Nova Scotia Energy Board’s September 2, 2026 reasons in Nova Scotia Power Incorporated, 2026 NSEB 19 also strengthen scrutiny of recurring spending and significant project changes.

The board had issued its initial approval on June 18, with reasons to follow. It approved the plan except for an $8.32-million remote-terminal-unit deployment, which it declined to approve at that time because benefits were insufficiently quantified and a separate reliability-plan review was expected to inform the decision. The September reasons set out broader reporting requirements; they did not impose a new customer rate or a penalty.

The approved individual projects listed in Schedule A have a combined project total of about $68.4 million, with about $48.1 million budgeted for 2026. Those amounts are distinct from the approximately $207.3-million routine-capital program considered in the plan. They should not be confused with the utility’s entire capital-spending program or the cost of every future energy-transition project.

Affordability needs more than a project-by-project view

Industrial customers asked for a clearer picture of the combined effect of capital spending on bills. Nova Scotia Power said a general rate application was the proper forum because reliable rate estimates depend on load forecasts, financing, depreciation, service allocations and when assets enter operation. The board had previously stopped requiring a narrower revenue-requirement estimate because of uncertainty about its usefulness.

The board revisited that position in light of growing spending on reliability, climate resilience and decarbonization. It accepted that a utility must have an opportunity to recover necessary, prudently incurred costs and a reasonable return. Affordability does not excuse meeting legal service or environmental requirements. But the timing and amount of investments may still allow choices, and the board wanted a clearer indication of the pressures ahead.

The required analysis belongs in the 2027 capital plan. It must estimate the effect of proposed capital approvals on rates for 2028 through 2030, by customer class, relative to 2026–2027 rates while holding other assumptions constant. It is intended to show the approximate scale of potential impacts, not produce the precise rate forecast expected in a general rate application.

For that first analysis, the board limited the exercise to proposed annual-plan capital expenditures, plus the already-approved New Brunswick intertie project, which had an approved cost and a projected late-2028 service date. It considered it premature to require every possible decarbonization project whose cost remained at an early stage. The framework can be refined after the first filing.

The board declined a structural ceiling on the annual capital plan, warning that an arbitrary cap might prevent necessary safety or reliability work or defer costs into larger increases later. It preferred scrutiny of whether a project is needed, needed now and based on the least-cost option. It nevertheless warned that rate increases and deferral accounts cannot expand indefinitely without consequences for affordability, financial flexibility and future customers.

Recurring spending cannot justify itself simply by recurring

The utility’s 2026 routine-capital budget was 9.6 per cent above its actual 2025 spending. Nova Scotia Power attributed increases to more work, higher input costs, reliability investment, customer-driven demand and supply-chain conditions. Industrial customers questioned whether activities that had grown substantially still belonged in the streamlined routine category.

The board accepted that recurring work need not cost the same every year and that replacing assets to current standards can properly include improvements. It did not find that Nova Scotia Power deliberately maintained an artificial spending target. Its concern was that temporary pressures, such as backlogs, unusual overtime or elevated material prices, could become embedded in future forecasts simply because forecasts start from historical spending.

Beginning with the next capital plan, each routine must have a rolling five-year comparison of budgets, actual spending or latest forecasts, work volumes and appropriate unit costs. The utility must explain material changes and distinguish effects such as volume, inflation, contractor rates, productivity and expanded work. Reporting must include regular and overtime labour information where internal labour is used.

The board also required comparable information on planned and reactive equipment replacement, so it can assess whether more preventive investment is reducing failures, emergency work or related costs. It directed review of the routine-expenditure rules for the 2028 capital plan, including whether major growth or changes in a program should trigger enhanced justification.

Major changes need a chance for advance review

A separate dispute concerned when an approved project has changed enough to return to the regulator. Nova Scotia Power proposed defining a scope change primarily by a change in the project’s stated intent. It argued that requiring updated applications for minor changes would be inefficient and that overspending and final-cost processes already capture financial variances.

The board accepted the proposed definition but added a notification requirement. When changes to deliverables, boundaries or detailed tasks may increase the budget above twice the project’s authorization-to-overspend threshold, the utility must send a brief letter describing the change, its estimated budget effect and any new alternatives. The board then decides whether a formal scope-change application is required.

That is not an automatic application for every change, nor a universal dollar threshold. The board recognized that some urgent work cannot sensibly await review, but rejected the idea that after-the-fact overspending scrutiny always replaces prospective oversight. Unapproved spending remains at shareholder risk, and the board said it would monitor the new process’s usefulness and administrative burden.

Reliability benefits must be demonstrated

The deferred remote-terminal-unit proposal would have added remote visibility and control at 21 substations. Nova Scotia Power said it could improve emergency disconnection and outage response. The board did not dismiss those benefits, but noted that existing protection equipment performs immediate electrical-fault clearing and that a substation can remain protected without a remote terminal unit.

The proposed installations served roughly 3.6 per cent of customers, and the board found that the utility had not quantified their dollar benefits or provided historical examples showing the expected value. The reasons permitted the company to refile after the separate five-year reliability review, with a quantified assessment. This reports the disposition in these reasons, not a verified later outcome of that separate review or any renewed application.

The board approved other reliability investments but warned that this year’s approval did not assure similar approvals later. It shared intervenors’ concerns about whether vegetation management and grid-hardening expenditures were producing sufficient measurable benefits. The utility responded that reliability improvements emerge over time and may appear as fewer or shorter outages rather than direct cost savings; the board wanted a clearer connection between spending and outcomes.

Cyber-related costs require explicit explanations

The reasons also addressed the effect of the utility’s 2025 cybersecurity incident on capital planning. The board found that no additional restoration-related capital costs had been identified in the 2026 plan and no listed capital project had been identified as costing more because of a cyber-related delay. That limited finding was not a conclusion that the incident had no costs or that future projects could never contain them.

For every IT or cyber-related capital application in 2026, 2027 and 2028, including annual plans, the board required a specific explanation of whether cost variances were caused or contributed to by the incident. The required examination includes delays, vendor costs, lost data and additional complexity. Separate proceedings were addressing technical, operational, billing, privacy and governance issues; this ruling did not resolve those inquiries.

Approval did not settle every long-term project

The board also required better coordination with the Nova Scotia Independent Energy System Operator, including discussion of a joint panel for the next update on the path to 2030. It declined to decide whether the operator had exclusive procurement rights over certain resources, because no synchronous-condenser project was before it. Its concern was avoiding duplicated effort or delay during the transition in responsibilities.

For the Mersey hydro system, the board accepted an update but required another comprehensive comparison of redevelopment and decommissioning options in the next capital plan. The cost estimates used different levels of detail and did not constitute a complete system-level economic evaluation. The decision did not select redevelopment or decommissioning, or approve all projects described in long-term forecasts.

The result preserves most of the 2026 plan while making future filings more demanding. The central change is evidentiary: capital spending must be supported by clearer explanations of customer impacts, changing work and costs, measurable benefits and when further regulatory approval is needed. The reasons do not establish that the new reporting duties have since been fulfilled.