The Math Behind the Meter
Nuclear Energy and current utility cost math
John Ihle — iSolar MN — April 2026
My last four posts have been about the same thing: the gap between what electricity costs to generate and what ratepayers actually pay. That gap — driven by capacity obligations, transmission build-outs, and a planning model that excludes local resources — is why rates are rising faster than inflation — even as installing batteries and generating kilowatt-hours of locally owned wind or solar continues to fall.
For commercial and industrial ratepayers, the window to act is narrowing. The federal Investment Tax Credit that makes solar and storage projects pencil is set to step down, and once it does, the economics shift. What can be locked in today at zero risk will cost much more soon.
A conversation is taking shape in Minnesota, and it could make that gap much wider.
The Minnesota Rural Electric Association has been increasingly vocal about nuclear power — particularly small modular reactors — as part of the state’s energy future. Not as a distant idea. As a planning direction.
The argument has merit in one respect. The grid needs firm, dispatchable, carbon-free capacity. Intermittent renewables alone cannot meet reliability requirements. Coal retirements are creating a real gap. Those are not controversial statements.
Where the argument breaks down is not the need. It is the cost — and specifically, which cost, and what other options there are. The other option might be a hybrid through DG, that can be deployed now, with Small Modular Reactors, that when ready, and have proven themselves, can take their place alongside DG. This could help keep rates lower, more manageable, with lower risk. This “utility takes all” or almost all is not sustainable.
The number that gets quoted — and the one that matters
Nuclear advocates point to projected SMR costs of $60 to $80 per megawatt-hour. That number reflects busbar cost: the price of electricity at the plant gate, before transmission, distribution, financing, or delivery. If you blend DG with SMR it would mitigate transmission and new generation costs.
Ratepayers do not buy electricity at the plant gate. They buy it at the meter.
Minnesota already demonstrates this gap clearly. Wind energy in North Dakota can have a generation cost around 2.5 cents per kilowatt-hour. By the time that energy is transmitted, balanced, integrated, and delivered, retail rates in many Minnesota communities fall between 12 and 17 cents. The difference is the system — transmission, capacity, reliability, capital recovery, and inflation. That system cost will only increase as new infrastructure is added.
If wind at 2.5 cents delivers at 12 to 17 cents, what does nuclear at 6 to 8 cents deliver at?
In communities like Hawley, rates are already trending toward 17 cents per kilowatt-hour. A new nuclear plant does not replace those existing costs. It layers on top — new capital recovery, new transmission, financing over decades. When those layers are added to an already elevated rate base, delivered costs to ratepayers, in 10 years, those costs move into the mid-20-30-cent range. We don’t know because the utilities don’t know.
There will be rate hikes, and the question is not what nuclear costs at the plant. The question is what does all this do to utility bills that are already under pressure.
A pattern, not an outlier
Cost projections for nuclear deserve skepticism because the track record demands it.
Vogtle Units 3 and 4 in Georgia — the first new nuclear construction in the United States in decades — were estimated at $14 billion. The final cost approached $35 billion. The reactor vendor, Westinghouse, entered bankruptcy during the project. Those costs were transferred to ratepayers and will be recovered over decades.
This pattern is not limited to large coastal projects or investor-owned utilities. Spiritwood Station in North Dakota — a 99-megawatt coal-fired generator developed within the cooperative system, with Great River Energy as the driver — was projected at roughly $250 million and came in closer to $400 to $440 million. Those costs are financed and recovered through the same ratepayer-backed framework.
Cost overruns in capital-intensive utility projects are not exceptions. They are features.
Who carries the risk
In a cooperative structure, capital costs are financed and recovered through member rates. If a project exceeds its estimate, the overrun is absorbed by the membership.
That matters most for those with the fewest options.
Low-income households already spend a disproportionate share of income on energy. Renters and fixed-income residents cannot install systems or finance alternatives. They absorb the increase. When they cannot, programs like LIHEAP step in — effectively converting a utility’s capital decision into a public subsidy funded by taxpayers.
That subsidy then becomes a political target. Energy assistance gets characterized as a handout rather than a consequence of rate-setting decisions ratepayers had little voice in. The cycle is familiar: institutions make capital commitments, costs are socialized, and the assistance programs created to manage the fallout become contested — not the original decisions that made them necessary.
This has played out before, with nuclear and with coal. The Spiritwood overrun didn’t come with a public reckoning. The costs just showed up in rates, quietly, over time.
This is closer than you think
The nuclear conversation in Minnesota is not hypothetical.
X-energy is building a TRISO fuel fabrication facility in Oak Ridge, Tennessee. Fluor has signed on to manage the Xe-100 SMR project at Dow’s Seadrift facility in Texas — four 80-megawatt units. The infrastructure being positioned is not for a single demonstration plant. It is for a fleet.
Somebody is going to sell this to Upper Midwest cooperatives. When that happens, ratepayers deserve to see a projected bill impact — not a busbar cost, not a capital estimate, but what their monthly rate looks like in year five, year ten, and year twenty, including financing, overruns, and inflation. That projection never happens. Utilities will show you the generation cost. They will not show you what your bill looks like in year eight when construction overruns hit the rate base.
This is fraught with risk and if the numbers are wrong — as they have been, repeatedly — there should be consequences that fall somewhere other than on the membership. In private-sector contracting, developers absorb overruns beyond a defined threshold. In cooperative generation decisions, ratepayers absorb 100 percent. That is not a technical limitation. It is a choice — and the time to change it is before the commitment, not after.
The data center argument
The strongest case for nuclear is not coming from utilities alone. It is coming from projected load growth — particularly data centers that require hundreds of megawatts of continuous, firm power. Companies like Microsoft and Google are exploring nuclear agreements to meet that need.
That demand signal is real. But so is the risk allocation.
A private company entering a power purchase agreement assumes its own risk. A cooperative building generation on behalf of its members distributes that risk across the rate base — whether or not the projected load materializes. Those are not the same bet.
A comparison in real time
While these long-term decisions are debated, a different set of choices is being made every day with 0 risks if done correctly.
School districts, cold storage facilities, and municipal buildings are installing solar paired with battery storage behind the meter. On a levelized basis, those systems commonly deliver energy at 12 - 8 cents per kilowatt-hour or less while also reducing demand charges. They are deployable now, financed privately, and paid off within 7 to 15 years, depending upon how they are financed — continuing to produce energy at minimal marginal cost thereafter. DG costs can be locked in today. A school or a business can sign a contract this year and know what their energy costs will be for the next 20 to 30 years. That is not a projection. It is a price. Compare that to a utility-financed generation project that may not be paid off for 50 years or more.
A nuclear plant approved in the early 2030s may not deliver power until the late 2030s. It will be financed over decades. Its costs are estimates — and the track record on those estimates is not encouraging. Those trajectories do not converge. They diverge.
A careful approach would be to lock in distributed resources now — at known costs — while taking the time to evaluate whether and how SMRs could be deployed in a way that makes economic sense for ratepayers. But that requires utilities to treat distributed generation as a real alternative, not a nuisance. And it requires an honest comparison — not one where the centralized project goes into the rate base and the distributed alternative is measured against an avoided cost that was designed to make it look uncompetitive.
What should be required
None of this means nuclear has no role. The grid requires firm, carbon-free capacity. But before any large-scale nuclear investment is made on behalf of cooperative ratepayers, three things should be established.
Full delivered-cost transparency. Total cost at the meter — not just generation cost. Ratepayers deserve to see the same number they will pay, not the number that makes the project look viable. DG must do this, why is there a double standard.
Distributed alternative analysis. A clear evaluation of what local solar, storage, and demand response could displace before committing to centralized capital. If cheaper capacity exists closer to load, that should be part of the record.
Cost overrun accountability. A defined mechanism for sharing risk so that ratepayers are not the only ones exposed when — not if — costs exceed projections.
Minnesota does not need to reject nuclear. It needs to evaluate it with the same rigor it should apply to any multi-billion-dollar, multi-decade commitment made on behalf of people who will carry the cost long after the decision-makers have moved on.
Math matters. The risks are real. And the people paying deserve to understand both before commitments are made — not after.
John Ihle is a Master Electrician and co-founder of iSolar MN / Three Rivers Electric and Abaris, veteran-owned electrical contractors and distributed energy integrators based in Minnesota. He has worked in renewable energy and electrical construction for more than 40 years and writes about distributed generation, storage, and the economics of Minnesota’s electric grid.