Nova Scotia electricity customers, not Nova Scotia Power’s unregulated business, must receive the benefit of payments made when a renewable-power seller falls short of its local-spending commitments. The Nova Scotia Energy Board imposed that requirement while approving a revised Green Choice Program power-purchase agreement in its October 30, 2026 decision, Procurement Administrator, 2026 NSEB 24.
The approval is conditional on amendments to the standard contract, not an award to any wind project or approval of a particular electricity price. Power Advisory LLC, the province’s procurement administrator, must submit a compliant version by November 6, 2026. The board said an order would follow that filing.
The Green Choice Program gives large electricity consumers a route to subscribe for local renewable supply. The anticipated procurement targets up to 1,200 gigawatt-hours annually, described in the reasons as approximately 350 megawatts of onshore wind capacity. Those are procurement targets, not quantities authorized for construction by this decision. Nova Scotia Power would be the buyer under contracts lasting 25 years after commercial operation.
The board reviewed whether the contract form, taken as a whole, was reasonable. Its statutory role did not extend to reviewing the procurement administrator’s solicitation process, the prices offered or the amount of capacity and energy to be acquired. Consumer, small-business and industrial representatives, renewable-energy organizations and developers, and Nova Scotia Power made written submissions.
Local promises must be measurable and benefit customers
The previous Green Choice contract did not enforce commitments to local spending on development and construction, even though bidders could earn evaluation points for those commitments. The new form requires an independent report on expenditures where a seller has promised local benefits, with a payment to Nova Scotia Power for any shortfall.
Developers warned that a report and payment within 20 business days after commercial operation would be unrealistic for large projects. Some construction and interconnection costs are billed months later, and contract reconciliation and supplier verification take time. The board rejected the administrator’s suggested extension to 40 business days as inadequate and set a deadline of 12 months after commercial operation for both the report and any shortfall payment.
The board also removed the requirement to submit the local-benefits report before a project could achieve commercial operation. Making the report a start-up condition conflicted with allowing a year to establish the final expenditure figures. The commitment to local benefits remains optional at the bidding stage, but a seller that makes one must meet the resulting reporting and payment requirements.
Nova Scotia Power remains the party receiving and enforcing the reports and payments because it is the buyer under the contract. The board accepted independent verification and contractual confidentiality protections for supplier information. It did not order private supplier prices to be made public.
But the utility cannot treat shortfall money as unregulated income. Since customers pay the power-purchase costs, the board directed that funds received, net of any set-off, be credited to ratepayers through the Fuel Adjustment Mechanism. Allocation among customer classes must follow the same basis as the contract’s energy charges. No present dollar credit or individual refund was awarded.
Tariff protection goes both ways, with limits
The contract provides a process for a seller to seek a higher energy rate if tariffs imposed after the proposal deadline increase capital costs by more than 7.5 per cent. Developer representatives asked for a lower threshold or full protection. The board retained the threshold, accepting that bidders could price smaller risks into their offers and that a lower trigger could produce repeated adjustments for minor fluctuations.
The board also retained Nova Scotia Power’s ability to seek a lower energy rate when tariffs fall or disappear. It accepted different timing rules: the seller’s adjustment notice must be given no later than six months before the scheduled commercial-operation date, while tariff reductions can be considered before or within six months after that scheduled date. The board reasoned that long-lead equipment costs should be known earlier and customers should not bear inflated prices throughout a long contract after relevant tariffs decrease.
Disputes over revised tariff-related rates can go to an independent expert. The board rejected a proposal to deem the seller’s requested rate accepted merely because Nova Scotia Power’s 20-business-day response period expired, recognizing that verification may need more information. These contractual mechanisms do not establish the tariffs in force today or a guaranteed increase in any project’s price.
Inflation and early completion affect payments
The board accepted inflation indexing before commercial operation and annual indexing of 20 per cent of the energy rate after operation begins. It rejected requests both to restrict the ongoing indexing and to expand the indexed share. Its reasoning was that sharing inflation risk could reduce the risk premium bidders would otherwise include in a fixed price; it did not establish that every resulting bid would be cheaper.
The contract also retains payment at 75 per cent of the energy rate during the interim period before all commercial-operation requirements have been satisfied. The board rejected a developer’s request for full payment, treating the reduced interim amount as an incentive to meet the remaining requirements.
A new early-completion incentive increases the applicable energy rate by 25 per cent until December 31, 2030, excluding excess energy, where both the scheduled commercial-operation date and commencement date occur before December 31, 2029. The board declined to make actual early commencement alone sufficient: it accepted that system planners need advance commitments about which projects will be ready.
Industrial and small-business representatives questioned the incentive’s cost and value. The administrator compared an illustrative year of premium payments with the contract’s late-delivery damages. The board accepted that comparison as essentially cost-neutral between the benefit of early delivery and cost of delay, and as supporting the province’s 2030 objectives. It was not a finding that the incentive costs customers nothing.
For compensation when generation is curtailed, Nova Scotia Power proposed calculating amounts at month-end and paying in the month following the month in which the associated energy was billed. The administrator adopted that change, but the board found an annual-payment reference and unclear cross-reference elsewhere in the form. It required consequential revisions in the compliance filing, or an explanation why further changes were unnecessary.
Developers retain federal financing risks
The board refused to restore a termination protection for sellers unable to obtain anticipated Canada Infrastructure Bank financing or Smart Renewables and Electrification Pathways funding. Developers argued that losing such support could make projects unviable or increase bids. The board accepted that concern as part of the allocation of risks but held that neither funding source was mandatory for participation.
It likewise declined broader protection against changes in federal law and refused to treat changes to federal investment tax credits as a new force-majeure event. The contract excludes relief for economic hardship or lack of funds. The board recognized that risks left with sellers may be reflected in higher offers, but found no compelling reason to change the balance adopted in the earlier procurement.
Other terms ease or clarify development requirements. The board accepted pre-operation security of $35,000 per megawatt, reduced from $125,000, despite concerns about abandonment risk, because the lower amount was within the range used elsewhere. It also accepted changes protecting lender-enforcement rights and an energy-resource-only interconnection approach for this procurement, rather than retaining a network-resource option.
Compliance remains the next step
The board retained the requirement for a cybersecurity plan at least six months before scheduled commercial operation and rejected a proposed rapid deemed-approval rule. It accepted removal of a separate equipment-certification requirement because of mature wind technology and continuing contractual performance obligations. Those changes do not excuse compliance with the remaining operating and security requirements.
The administrator may make non-substantive changes, but the directed local-benefits and curtailment revisions still require the November 6 compliance filing. The decision balances customer protection and development risk within a contract form; it does not establish that the filing has been accepted, a project has been selected or built, or any customer saving has already occurred.
