NB Power wins retroactive Lepreau approval but loses $5.8-million deferral

NB Power has won retroactive approval for the Point Lepreau generator rewind, but New Brunswick’s energy regulator rejected a $5.8-million depreciation deferral after finding the utility’s failure to seek advance approval unreasonable.

In its October 16, 2026 decision in Matter EL-001-2026, the New Brunswick Energy and Utilities Board found that both the work and the selected timing were prudent. That did not excuse NB Power’s decision to complete the project before applying for the approval required by the Electricity Act.

The distinction produced a split result: the capital project was approved with retroactive effect, while the proposed PLNGS Generator Rewind Deferral Account was denied. The ruling also explains how the board will assess requests for retroactive capital approval and why it expects a more rigorous comparison of project alternatives.

A necessary project, completed before approval

The project replaced 144 stator bars in Point Lepreau’s main generator after a fault was discovered during a 2024 maintenance outage. A temporary repair allowed the station to operate again, but NB Power concluded that a full rewind was necessary.

The board recorded a final capital cost of $66.36 million. Replacement electricity was a separate expense: actual replacement-power costs were $156 million for 2025, while the 2026 amount was not yet known when the decision was issued. The earlier $324-million replacement-power estimate covered both 2025 and 2026, not the capital work alone.

NB Power selected a schedule intended to complete the rewind by August 2025, before another winter. The station actually returned to service on November 29, 2025. The board held a two-day hearing in June 2026, with NB Power, the Public Intervener and board staff participating.

Section 107 required approval before NB Power incurred more than 10 per cent of the expected costs of a capital project estimated at $50 million or more. The utility acknowledged that it had not complied with that advance-approval requirement. The board emphasized that the section 107 proceeding concerns whether a project is prudent, not a general determination of which costs may be recovered through rates.

Retroactive approval is available only if a statutory precondition is met, followed by the board’s discretionary decision to grant it. NB Power relied on paragraph 107(4)(a), concerning expenditures necessary for the reliability, adequacy or safety of the electricity system or the utility’s generation or distribution facilities. It did not rely on the separate financial-hardship route.

The board accepted that the rewind met that threshold. Expert evidence supported Point Lepreau’s importance to winter electricity supply and the difficulty of finding replacement capacity. The Public Intervener’s expert also considered the project a reasonable balance of reliability, risk and cost. The board rejected the suggestion that a potential outage presented only an economic concern.

Prudence despite weaknesses in the comparison

Prudence was assessed using what a reasonable utility could have decided on the information available at the time, rather than hindsight. NB Power did not have to prove that its choice was the only reasonable option. But it still had to demonstrate serious consideration of plausible alternatives and sound planning, governance and procurement processes.

All four options involved the same generator work; timing drove much of the difference in replacement-power costs. The earliest option was not feasible because the necessary parts and expertise could not be obtained in time. NB Power chose the next-earliest option, which was the most expensive of the four in the cost comparison before the board.

That choice drew substantial criticism. NB Power had not asked its engineering expert how long the temporary repair might remain effective, including whether it could last until spring 2026. The board said that seeking advice only on the preferred option impeded a meaningful comparison and expected future applications to include stronger risk assessment and consideration of alternatives.

The comparison suggested that delaying the rewind could have reduced replacement-power costs by $132 million to $158 million. Those were prospective differences between options, not a finding of proven waste or realized savings. The board noted that some additional costs for one delayed option were absent from the chart, and the possibility of safely extending the temporary repair had not been adequately assessed.

Despite those shortcomings, the board found the selected schedule prudent. It accepted that limiting the time the generator operated with the temporary repair favoured earlier completion and that the engineering evidence supported replacing the affected bars as soon as possible. The finding rested on the evidence available, not acceptance of the chosen schedule at any cost.

Delay, ratepayer exposure and good faith

For the separate retroactivity decision, the board identified potentially relevant considerations: the length and reasons for delay, whether the project was necessary or optional, the consequences for ratepayers, and good faith. It declined to turn those considerations into a fixed checklist for every case.

NB Power had told the board in April 2025 that it intended to seek retroactive approval but did not file its application until January 22, 2026. It cited staffing shortages and possible effects on a third-party business relationship, with staffing the primary explanation. The board rejected ordinary competition for staff time as sufficient justification, absent very unusual circumstances.

The interaction with the Regulatory Variance and Deferral Account Regulation made the delay more serious. As the board explained it, the regulation guarantees recovery of differences between forecast and actual fuel and purchased-power costs. It therefore prevented the board from disallowing replacement-power costs it might otherwise have considered imprudent. That conclusion concerned replacement power, not blanket approval of all project costs.

Applying in advance could have left an opportunity to avoid additional replacement-power costs if a different option had been required. However, because the board ultimately found the chosen option prudent, it expressly acknowledged that the potential negative impact it identified had not materialized. It also found no evidence that the filing delay increased the overall capital cost, which came in below budget.

The board accepted that NB Power acted in good faith, even though it rejected the staffing explanation as sufficient. The utility honestly believed it could not complete both the project and regulatory filing in time. Balancing that finding with the project’s necessity and the prudence of the selected timing, the board granted retroactive approval.

Depreciation deferral refused

The depreciation request failed separately. NB Power sought a $5,801,659 deferral account for depreciation in the 2025/26 and 2026/27 fiscal years. Those amounts were not being recovered because the project had not been approved when rates for those years were set.

Although section 117.5 permits regulatory deferral accounts for prudently incurred costs, approval is discretionary. The board declined to create this account because NB Power’s own filing decisions had left the depreciation outside recovery in the relevant years. Retroactive approval of the work therefore did not entitle the utility to the requested accounting remedy.