nuclear-news

Ontario’s Nuclear Rate Shock Reveals a Deeper Affordability Problem

Michael Barnard, Clean Technica, 4 Feb 26

Ontario Power Generation (OPG) has asked the Ontario Energy Board to approve a sharp increase in regulated nuclear payment amounts, including a year over year jump of more than 40% in 2027. The weighted average regulated payment amount rises from about $78/MWh in 2026 to roughly $110/MWh in 2027, driven by the nuclear payment amount increasing from around $111/MWh to about $207/MWh, almost doubling. For a typical household, this does not mean a 40% increase in the electricity bill. OPG’s own consumer impact analysis shows an increase of roughly $8 per month on a typical bill of about $142, or around 5.6%, mostly because a lot fewer MWh are being delivered at the much higher price. The difference between those two figures is the starting point for understanding what is happening and why it matters for affordability and system design.

An electricity bill is a bundle of charges layered together. Generation is only one part of what households pay. Transmission, local distribution, system operations, and regulatory charges make up a large share of the total. Nuclear sits inside the generation portion, and OPG’s regulated nuclear sits inside nuclear. When the regulated payment amount for OPG’s nuclear fleet rises sharply, the overall bill moves much less because the other layers do not change at the same rate. This does not make the nuclear increase less real. It means the effect is diluted across a broader bill structure.

Importantly, the more Ontario is electrified with good demand management and batteries smoothing peaks, the more that the additional costs of transmission, local distribution, system operations, and regulatory charges are spread across more units of electricity, lowering their portion of the final bill. Expensive nuclear begins to dominate bills in that scenario causing higher rates than necessary, just as inexpensive renewables would lower rates.

Ontario’s nuclear system also has an important institutional split that needs to be clear early.
There are two major nuclear operators. OPG is publicly owned and regulated on a cost of
service basis. The other, Bruce Power, is privately owned and operates under a long term
contractual structure with more exposure to performance and market discipline. The current
rate application applies only to the public operator’s regulated nuclear fleet. System wide
visuals and energy flows, however, reflect the combined output of both operators. Keeping that
distinction clear avoids confusion when comparing rate case numbers to province wide
generation totals.

What is increasing in this application is not spending that OPG failed to anticipate. It is the
amount the regulator allows OPG to recover in a given year under cost of service regulation.
The revenue requirement includes operating and maintenance costs, depreciation of capital
already spent, return of capital, return on capital, taxes, and nuclear liability accruals. These
costs were planned, forecast, and approved years ago. The regulatory question is not whether
OPG expected them, but how and when they are recovered from ratepayers. A large increase in
a payment amount can occur even when nothing unexpected has happened on the ground.

The key mechanical driver of the 2027 spike is a drop in output from OPG’s nuclear fleet, not a
sudden surge in total nuclear spending. OPG’s filing shows production from its regulated
nuclear facilities falling to roughly 18.7TWh in 2027, compared with values in the high 20s or
low 30s TWh in surrounding years. This reflects planned refurbishment outages at Darlington
combined with conservative assumptions about Pickering availability as those units operate
under life extension conditions. Nuclear plants are expensive to own and relatively inexpensive
to operate, while still having costs of operations above the cost of new wind and solar. When
nuclear reactors are offline, most costs continue while output falls. Fixed costs are spread over
fewer kWh under the regulatory structure, and the $/MWh figure rises quickly.

This is why outages matter so much in a nuclear heavy system. A large portion of Ontario’s
electricity comes from a small number of very large units. When one or more of those units is
offline, there are limited alternatives ready to scale up at the same cost. Gas generation can fill
gaps, but that introduces fuel price exposure and emissions. Imports can help at the margin,
but intertie capacity is finite. The result is that nuclear outages show up as price volatility even
when total system costs remain within expected ranges…………………………………………………………………………………………………………………………………………………………………………………………………………………………………………

The decision to pursue small modular reactors adds another layer to this picture. The SMRs at
Darlington are being developed by the publicly owned utility, OPG, under a cost of service
framework. Development and early construction costs are already flowing into the nuclear
revenue requirement, even though the units won’t be producing electricity for years, likely
many more years than the current schedule projection. Ratepayers are paying financing and
development costs today, with much larger construction and depreciation costs to come later
in the decade.

The contrast with the private nuclear operator, Bruce Power, is instructive. The private
operator has chosen to focus on refurbishing existing large reactors rather than building SMRs.
That choice reflects exposure to cost, schedule, and performance risk. First of a kind nuclear
projects have long lead times, uncertain costs, and limited flexibility. In addition to first of a
kind risks, the SMR reactor designs, operations and fuel cycle are completely unfamiliar to
Ontario’s nuclear operators. Ontario has no nuclear reactor construction experience left, as the
last reactor was turned on a generation ago, so there are no master builders and experienced
teams. Ontario knows how to run existing nuclear and occasionally refurbish the CANDU fleet,
but that’s it. Without guaranteed cost recovery, private capital won’t proceed under those
realities. In Ontario, the reason SMRs are moving forward is that risk can be socialized to
Ontarians through regulation and the current Administration refuses to accept the global
lessons on renewables, not that SMRs are the lowest cost or most flexible option.

This distinction matters for rates. When SMR costs rise above current projections, and they will,
those overruns will flow into rate base if deemed “prudent” by the regulators. That increases
depreciation, return of capital, and return on capital for decades, and Ontario ratepayers or
taxpayers will be paying those costs. Overruns also raise financing costs during construction,
which affects rates before any electricity is delivered. If delays accompany overruns, fixed costs
are spread over fewer kWh for longer, worsening the same denominator problem seen in the
2027 refurbishment year, but stretched across many years.
It’s worth pointing out that Ontario still carries the legacy financial burden of the massive
nuclear build-out undertaken by Ontario Hydro in the 1970s and 1980s, and that burden has
persisted for decades. When Ontario Hydro was reorganized in 1999, its assets were valued at
roughly $39.6 billion while its long-term debt was about $26.2 billion, with a large portion of
that debt tied directly to nuclear construction, cost overruns, and related liabilities.

Much of that stranded debt was transferred to the Ontario Electrical Financial Corporation to
manage and service, rather than being absorbed by investors, and it has been paid down only
gradually over the years. As of 2024, that successor entity still carried about $12.1 billion in
debt originally associated with the old nuclear program, and it was paying roughly $626 million
in interest charges in that year alone. That debt does not mature until 2050, which means
Ontario taxpayers and ratepayers will continue servicing obligations from past nuclear build
projects well into the middle of this century. Current discussions about new, expensive and

untried SMRs should be occurring in context of that still very high debt that Ontario taxpayers
and ratepayers are funding.

It is also important to separate refurbishment from new nuclear. Refurbishment creates short
term price volatility because of outages, but the assets already exist and return to service,
assuming refurbishment goes well. New nuclear creates long term cost commitments. In OPG’s
own filings, the Darlington New Nuclear Program already accounts for hundreds of millions of
dollars per year in revenue requirement. By the end of the decade, new nuclear is likely to
represent roughly one quarter to one third of the incremental increase in nuclear costs. These
commitments are locked in early and recovered over decades. Extending the life of nuclear
reactors instead of more aggressively ramping up wind and solar is a trade off, and at present
Ontario is making the decision to refurbish very old reactors, with the intent of running them to
ages no nuclear reactor in the world has ever seen. This doesn’t mean geriatric nuclear reactors
will necessarily be unsafe, but they get increasingly expensive to maintain, operate and
refurbish………………………………………………………………https://cleantechnica.com/2026/02/02/ontarios-nuclear-rate-shock-reveals-a-deeper-affordability-problem/#google_vignette

February 8, 2026 - Posted by Christina Macpherson | business and costs