FingerMotion, Inc.

In addition to the information contained in our Annual Report on Form 10-K for the fiscal year ended February 28, 2026, and this Quarterly Report on Form 10-Q, we have identified the following material risks and uncertainties which reflect our outlook and conditions known to us as of the date of this Quarterly Report. These material risks and uncertainties should be carefully reviewed by our stockholders and any potential investors in evaluating the Company, our business and the market value of our common stock. Furthermore, any one of these material risks and uncertainties has the potential to cause actual results, performance, achievements or events to be materially different from any future results, performance, achievements or events implied, suggested or expressed by any forward-looking statements made by us or by persons acting on our behalf. Refer to “Cautionary Note Regarding Forward-looking Statements” as disclosed in our Annual Report on Form 10-K for the fiscal year ended February 28, 2026.

There is no assurance that we will be successful in preventing the material adverse effects that any one or more of the following material risks and uncertainties may cause on our business, prospects, financial condition and operating results, which may result in a significant decrease in the market price of our common stock. Furthermore, there is no assurance that these material risks and uncertainties represent a complete list of the material risks and uncertainties facing us. There may be additional risks and uncertainties of a material nature that, as of the date of this Quarterly Report, we are unaware of or that we consider immaterial that may become material in the future, any one or more of which may result in a material adverse effect on us. You could lose all or a significant portion of your investment due to any one of these material risks and uncertainties.

Risks Related to Our Alberta Data Center and Powered-Land Business

We have limited operating history in data centers, generation, or powered land, and the Alberta program may never generate material revenue.

Our historical business is mobile payments and related services in China. The Alberta program—owning project companies that hold land, permits, on-site generation, and modular data halls, and contracting capacity to AI/HPC customers—is a new line of business. As of the date of this report, we have not energized a commercial 9.9 MW site, have not recognized operating revenue from this business, and have not executed binding long-term offtake for the ten-site program. Failure to complete permitting, gas supply, construction, or customer contracts on acceptable terms would leave us with holding costs and impairment risk and could cause the strategy to fail.

Our model depends on completing and operating many small, separately permitted 9.9 MW sites rather than a single large campus.

Each site is intended to stay below the 10 MW individual power-plant threshold under Alberta Utilities Commission Rule 007 and to operate behind the meter under an Industrial System Designation (or equivalent self-supply structure). That structure is designed to avoid transmission interconnection queues and large-load regulation that applies to facilities of 75 MW or more. It also means we must repeat land control, gas interconnection at the parcel, municipal and AUC permitting, construction, commissioning, and operations across ten sites and four campus zones. Delay or denial at one site does not automatically stop the others, but it also means we do not obtain the single-campus scale, shared electrical infrastructure, or customer “campus” branding of a hyperscale facility. If the 9.9 MW envelope is later interpreted more restrictively, or if aggregation of nearby sites is treated as a single large facility, we could lose the permitting path on which the program is built.

We may be unable to obtain or maintain the permits and designations our sites require.

Each site is expected to require, among other things, municipal development approval, Alberta Environment and Protected Areas authorizations, AUC Rule 007 power-plant approval for a facility under 10 MW, and an Industrial System Designation or other lawful self-supply arrangement. Timelines we have disclosed (including a target of fully permitted sites within a defined period after release to work, and program-wide permitting by the end of the first quarter of 2027) are targets, not approvals. Conditions, appeals, information requests, changes in Rule 007 practice, or denial of an Industrial System Designation could delay energization, increase cost, or make a site uneconomic. Because generation and load are intended to remain on site, we do not face Alberta Electric System Operator large-load interconnection allocation in the same way as grid-connected hyperscale projects; we remain exposed to changes in provincial self-supply, emissions, methane, and industrial-system rules.

We depend on BlueFlare (and a small number of Alberta vendors) for development, construction, and field operations.

Development, construction, and site operations are expected to be performed by BlueFlare Group Holdings Inc. or its affiliates, which is not expected to take title to project assets. We do not have a large internal Alberta construction or plant-operations organization. If BlueFlare is unable or unwilling to perform, if the commercial arrangements are not documented on the terms we expect, or if we cannot replace that capability at comparable cost and speed, sites will be delayed or stranded. Concentration of technical know-how in one development partner is a material risk for a distributed 9.9 MW fleet.

Natural gas supply, local delivery, and fuel price are core operating risks, even though we do not depend on the Alberta power grid.

Sites are planned next to producing or recently producing gas infrastructure so that fuel can be delivered at or near the parcel boundary and electricity generated and consumed on site. That design is intended to avoid grid interconnection, transmission tariffs, and the AESO large-load queue. It substitutes gas-market and midstream risk: wellhead or plant outages, gathering or lateral constraints, commodity-price spikes, producer insolvency, take-or-pay imbalance, quality specifications, and winter deliverability. A 9.9 MW site has a smaller absolute fuel requirement than a hyperscale campus, but it has little on-site fuel diversity. Interruption at a single adjacent facility can take a whole site offline. We may not have fully executed, long-tenor, fixed-price gas contracts for the program.

Equipment lead times and cost inflation apply to modular generation and halls, not only to large turbines.

Global tightness in gas generation equipment is most acute for large frame turbines used by hyperscalers. Our sites are expected to use multiple smaller generating units, modular data halls, switchgear, cooling skids, and battery or bridging equipment. Those categories also face lengthening lead times, price increases, and commissioning risk. A missed genset or hall delivery can idle an entire 9.9 MW site. We may be required to place deposits long before offtake and project financing are closed.

Modular construction reduces some civil-works risk and creates others.

Halls and generation are intended to be factory-built or skid-mounted and assembled on prepared pads. That can shorten field construction relative to a poured hyperscale hall, but it introduces factory-slot risk, transport of oversized modules on Alberta roads (seasonal weight restrictions, weather, permitting), interface risk among vendors, and warranty complexity. Site work in Brooks, Coronation, Fox Creek, and Vulcan still requires foundations, gas and electrical interconnects, fiber laterals, security, and winter-capable access. Modular does not eliminate construction delay.

We may be unable to contract capacity on take-or-pay or other terms that support construction capital.

Our stated approach is to contract capacity before committing construction capital to a site. Customers are expected to provide their own GPUs, servers, network gear, and software; we provide powered land, generation to the rack, cooling, white space, security, and operations. That splits capex but also means utilization, density, and thermal design depend on customer equipment we do not control. Enterprise and mid-market AI/HPC buyers may demand shorter terms, higher SLAs, or more redundancy than a single 9.9 MW islanded plant can offer. If offtake lags permitting, we will hold permitted land at carrying cost. If we build ahead of contracts, we take merchant or Bitcoin-flex utilization risk.

Each 9.9 MW site has a smaller addressable customer set than a hyperscale campus.

A site of this size is generally better suited to inference, enterprise HPC, or partitioned colocation than to frontier model training that seeks hundreds of megawatts in one hall. Customers that require massive contiguous clusters, diverse utility feeds, or multi-building campuses may not use our product. Conversely, if inference demand is weaker or more price-sensitive than expected, we may not fill ten sites. Campus grouping (several separately permitted 9.9 MW sites under one field organization) is intended to offer expansion without a single 75 MW+ regulated facility; customers may still view the product as fragmented.

Alberta climate and operating conditions differ from the heat- and water-constrained markets oftendescribed in data-center risk factors; they create a different set of physical risks.

Our sites are in Alberta. Mean summer temperatures and humidity are lower than in many U.S. Sun Belt data-center markets, which reduces—but does not eliminate—the need for high-capacity evaporative or adiabatic cooling and the associated water withdrawals that characterize large campuses in arid regions. We do not currently expect water scarcity or extreme heat derates to be the primary physical constraint on these 9.9 MW plants. Material physical risks instead include extreme cold, freeze-off of gas supply or cooling circuits, snow and ice limiting access and maintenance, chinook-driven temperature swings, wildfire smoke affecting air-cooled equipment and filters, and spring road bans that delay module delivery. Cooling design, winterization, and spare-parts logistics must be specified for that climate. A design copied from a hot climate hyperscale campus would be mismatched.

Political and permitting opposition of the kind seen against some large U.S. or coastal hyperscale campuses is not the principal near-term risk we identify in rural Alberta, but it is not zero.

Alberta policy has been explicitly oriented toward attracting data-center investment on a “bring your own power” basis, and our sites are sized and sited as small industrial plants next to existing gas activity rather than as multi-hundred-megawatt campuses on the edge of major cities. We therefore do not treat organized political shutdown or water-rights campaigns as the base-case permitting risk. Residual risks remain: municipal land-use conditions, Indigenous consultation and treaty-related process, federal impact-assessment or methane/carbon rules, changes in government, and local nuisance, noise, or flaring concerns. Any of those can add time and cost. A change in Alberta’s self-supply or data-centre regulation could be more consequential than activism.

Fiber, latency, and remote-site operations may limit the product.

Rural or semi-rural Alberta parcels that are attractive for gas may be less attractive for carrier diversity and low-latency paths to U.S. or Toronto/Vancouver interconnects. Identified fiber routes can fail to materialize on schedule or at the capacity customers require. A 9.9 MW islanded plant still needs reliable transport; without it, the hall is stranded generation.

Project-level ownership and financing may not close on acceptable terms.

Each site is expected to sit in a dedicated Alberta project company that we own, with BlueFlare providing services and taking no title. Construction capital is expected to attach at the project level against contracted cash flows. We are a small-cap issuer with limited parent liquidity relative to a ten-site, 99 MW program. If lenders require more sponsor equity, completion guarantees, or offtake quality than we can provide, sites will stall after permitting. Cross-default or parent support, if given, could transmit project risk to the listed company.

Regulatory, tax, and cross-border structure risk.

Project companies, land, and operations will be in Canada; the parent is a Delaware corporation with a historical China operating footprint. We will be exposed to Canadian federal and Alberta tax, withholding, transfer-pricing, GST, carbon-pricing or output-based allocation rules, and any future border or investment-review measures. Currency mismatch (CAD costs and, potentially, USD customer contracts) can move project IRRs. Our China businesses continue to require management attention and capital and remain subject to PRC regulatory risk; that distraction or a need to fund China operations could slow Alberta execution.

Insurance, environmental, and operational incidents at a small unmanned or lightly staffed site can take the entire plant offline.

A 9.9 MW islanded site has less internal redundancy than a multi-hall hyperscale campus with multiple substations. Generator failure, fire in a modular hall, gas leak, or control-system fault can interrupt all critical IT load at that site. Insurance for generation-plus-compute in rural Alberta may be costly or limited. Environmental liability for spills, emissions, or noise sits with the project company and, depending on structuring, could reach the parent.

Competition and technology change.

Other developers are pursuing Alberta BTM and grid-tethered capacity. Hyperscalers that obtain scarce AESO allocations or build large tethered plants may set price and SLA expectations we cannot match at 9.9 MW. Modular hall and cooling standards will change with rack density. If customer GPU thermal design outruns our permitted envelope or cooling plant, we may need new permits or stranded halls.

Bitcoin or other flexible load, if used to firm a site before AI offtake, introduces commodity and policy risk.

Some early concepts contemplated co-located Bitcoin mining as a load-following sink. Bitcoin hash price, equipment cost, and any future Alberta or federal treatment of digital-asset loads could make that buffer uneconomic, leaving generation without a customer.

Forward-looking timelines we have announced are subject to substantial uncertainty.

Disclosed targets—permitting of ten 9.9 MW sites by the end of the first quarter of 2027, first energization as early as late fourth quarter 2026, data-hall turnover on the order of 18 months from permit award—depend on counterparties, regulators, equipment vendors, weather, and financing that we do not control. Failure to meet those targets would not necessarily indicate a defect in the 9.9 MW BTM concept, but it would delay revenue and could impair investor confidence and project finance.