1. Manitoba doesn't need another gas plant. It needs heat that works twice.
The cold morning test: gas failed 3 of 10.
On the mornings that matter, furnaces do not wait. Winnipeg Free Press reporting put in public view what Public Utilities Board testimony had already shown: Manitoba Hydro's Brandon gas turbines failed or had to reduce output during three of the ten busiest winter periods of the last five years. This included 22-23 January 2024, when demand reached 5,096 MW PD. That morning is the exam a Manitoba energy plan is not allowed to fail.
Despite that record, Hydro seeks on the order of $3 billion for new Brandon turbines. The sales pitch is near-perfect reliability. The operating history is not. New machines can be more modern, but they cannot repeal physics. Gas supply chains freeze when the cold arrives. They also miss the real shape of Manitoba's crunch: our highest demand is heating. Electrify homes without care at -35 °C and air-source heat pumps fall back on resistance coils, creating the very shortage Hydro proposes to solve by burning more gas.
Manitoba already owns the multi-day answer: northern reservoirs, roughly 4,800 MW firm even in drought conditions PD A. What the system lacks is not weeks of energy but a few hundred megawatts of power on the coldest mornings and evenings. The projected ~600 MW drought-year shortfall by 2030 is real PD. The dispute is not whether to act. It is what to buy.
2. Two $3-billion choices, one wastes heat forever
Two $3-billion choices sit on the table. Only one recovers the heat.
The province debates a $3-billion gas plant in Brandon. Winnipeg is spending more than $3 billion modernizing the North End Water Pollution Control Centre—the largest capital project in the city's history. NEWPCC already treats about 70% of Winnipeg's wastewater. Sewage carries low-grade heat every hour of every season. Vancouver's False Creek has heated buildings this way for more than a decade. On a −35 °C morning, every megawatt of that heat that reaches a radiator is one less megawatt Hydro must generate for electric heating. Same energy, twice.
Miss the window and Winnipeg gets a plant that treats water well and wastes heat forever. Act while contracts are open and the North End can host low-carbon heat for a generation—without asking ratepayers to fund another fossil plant.
| Decision | Brandon gas | NEWPCC clean hybrid |
|---|---|---|
| Capital cost | $3.0B | $1.95B gross ($1.50B if ITC confirmed) |
| Firm capacity | 750 MW nameplate; 525 MW scenario only | 413 / 761 / 861 MW electric by accreditation |
| District heat | None | 145 MWth thermal; ≤111 MW net electric credit |
| 20-year total | $4.5-6.9B | $1.5-1.8B; saves $2.7-5.4B |
Our plan saves ratepayers $2.7–5.4B over twenty years E A
That is a heat-pump answer to a heat problem, not a gas-plant answer to a spreadsheet problem.
3. Our plan: sewage heat, batteries, demand response, interties
What "use every electron twice" means
Manitoba already stores the energy in its reservoirs. The waste happens at the point of use, where an electron is spent once on one job and its work ends there. At the hub, the same electron works twice. With heat pumps achieving a coefficient of performance near 3.2, each unit of electricity moves roughly three units of heat from warm treated effluent, delivering a multiple of itself as heating. This efficiency—using every electron twice—forms the core of a plan that could replace 600 MW of winter capacity without building new fossil generation.
On a -35°C morning in Winnipeg, when the grid is stretched to its breaking point, Manitoba's new energy hub will make every electron work twice. First it drives a heat pump or powers a compute node, then its waste heat keeps warming buildings that would otherwise draw expensive electric resistance heat. This isn't a single giant machine replacing Brandon's gas station—it's five modular pieces working together: sewage heat recovery, batteries, demand response, interties, and optional public compute.
Brandon's gas plant: $3.0B for 750 MW nameplate, derating to 525 MW in cold events, failing 3 of 10 critical winter mornings, with no heat recovery. Manitoba's hybrid hub: modular components that can be deployed incrementally, with honest winter electric capacity of 413–861 MW depending on intertie delivery, plus 145 MWth of district heating that eliminates peak electric demand. The math favors the hybrid—but only if you understand how the dual ledger works.
Think of five pieces working together, not one giant machine replacing Brandon.
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Sewage heat at NEWPCC (the base).
Treated effluent stays warm in January—with or without compute. Heat pumps lift it into a district loop. This is the civic heart of the case. The warm treated water is already there; the heat is already being generated and wasted.
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300 MW batteries (4 hours).
Cover the 7-9 a.m. and 5-7 p.m. spikes. The reservoirs already hold the multi-day energy; batteries supply the hours.
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150 MW demand response.
Pay willing customers—especially baseboard stock—to shed the worst hours. This is grid muscle that can be called on when needed.
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Interties up to 300 MW.
Counted cautiously; zero in the conservative case until deliverability is proven. This is capacity that exists but must earn its place in the ledger.
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Small public compute, optional upside.
Not a private hyperscale warehouse—clean, publicly accountable nodes (10–20 kW), heat-first. Eligible today: 0 MW. The effluent heat does not depend on them; they are optional upside that earns its keep through heat first, computation second.
One hub, two ledgers
Heat megawatts are not electricity megawatts. We never add them. The honest winter electric range is 413 / 761 / 861 MW. This separation keeps the accounting clear and defensible.
Thermal ledger (megawatts of heat): NEWPCC effluent heat (50 MWth) + compute reject, gated (95 MWth) = 145 MWth hub. This credits the electric ledger as ≤111 MW net.
Electric ledger (megawatts of power): Batteries (300 MW) + demand response (150 MW) + interties (0–300 MW) + hub net electric credit (≤111 MW) = accredited firm capacity of 413 / 761 / 861 MW.
Conservative (413 MW) is the stress floor: interties at zero and the effluent-stage hub only, so the Board can see what fails if optimism is stripped out. It is not the recommended build. Reference (761 MW) is the planning case and covers the shortfall by +161 MW. Full (861 MW) covers it by +261 MW. Modular batteries and demand response can close gaps without pouring a single-station foundation.
4. Winter modelling: reference covers the shortfall, +161 MW
Manitoba is winter-peaking: load climbs as the thermometer falls. An unmanaged heat-pump rollout steepens that curve. The hybrid flattens it by moving heat off the electric peak and covering the two daily spikes.
This matters because winter planning must account for the exact hours when demand peaks. The hybrid shows it can handle those critical hours by shifting heat away from electric demand and using batteries to cover the morning and evening spikes.
Claimed
- Reference covers the shortfall, +161 MW.
- Full widens the margin, +261 MW.
- Conservative shows what fails when optimism is stripped out.
Not claimed
- Summer cooling megawatts as winter firm.
- A flat 30% gas derate as proven ELCC.
- Hybrid availability above 98%.
5. Money: $1.5-1.8B beats $4.5-6.9B before any credit
The simple comparison first: gas costs $3.0B in capital. The hybrid costs $1.95B gross, or $1.50B net if the federal Clean Technology ITC is confirmed A. We show both because credits are a fact to prove.
Looking deeper, at reference accreditation the hybrid delivers a firm kilowatt for $2,562 gross and $1,971 net. Gas delivers $4,000/kW at nameplate and $5,714/kW under the derate scenario. The structure of the argument matters: when every contested assumption resolves against the hybrid at once, it roughly ties. When any one resolves in its favour, it wins.
Twenty-year all-in bands do not overlap: gas $4.5-6.9B, hybrid $1.5-1.8B. The cheapest defensible gas future still costs $2.7B more than the most expensive defensible hybrid future in this model.
For ratepayers. Three billion dollars of rate-based fossil capital, plus fuel and carbon, shows up on bills. A smaller, fuel-free package shows up more gently, and a North End heat utility can attract clean-energy capital that a compliance sewage plant alone cannot. Heat taps missed at NEWPCC are wasted for a generation.
6. Reliability: audit both plans, assert neither
We ask the Board to commission an independent ELCC study based on the 3-of-10 cold-event record. This is better than asserting a flat 30% derate as proven fact, or treating near-perfect reliability as settled. Hydro's 91% start-reliability figure answers a different question: annual averages blend mild months into the average that peak planning must ignore. The Board's concern is conditional availability in the top load hours, under identical accreditation treatment for gas, storage, demand response, interties, and thermal displacement.
Against the multi-day vortex objection: reservoirs supply the days; batteries and demand response supply the hours; district heat and dual-fuel shrink the need itself. A four-technology, multi-site portfolio has no single component whose loss removes most of its capability. A single station on a single fuel line does.
7. The ask: six orders before the concrete pours
The ask is not approval of our plan. It is a fair exam for both plans, before the concrete is poured.
- Head-to-head modelling of the NEWPCC clean hybrid portfolio against Brandon gas before any capital certificate.
- Independent cold-weather reliability audit with unit-level records at or below -30 °C and identical ELCC treatment for both plans.
- Machine-readable economic models from both parties, with named assumptions.
- Disclosure of interconnection headroom near screened anchor sites, and extreme-event performance logs.
- Preserve the NEWPCC trench option for thermal headers during the plant rebuild.
- Measured pilot: effluent-stage hub plus a 10-20 kW compute band, with public metered filings.
8. What would change our mind
A case that cannot say what would change its mind is advocacy. We commit in advance to updating this filing if any of the following appears.
- An ELCC study finding gas tail-hour availability above roughly 95% and battery accreditation materially below its four-hour rating would collapse the reliability differential.
- Verified capital quotes pushing the portfolio far above $1.95B gross, or gas below $3.0B, would compress the delivered-cost gap.
- A twenty-year gas scenario landing below $4.5B under filed fuel and carbon curves would break the non-overlap of the cost bands.
- District-heat uptake stalling below the effluent stage would cap the hub at 38 MW net, which is why the conservative scenario already prices that world.
None of these falsifiers has occurred. Each is checkable. We have not seen symmetric candour offered for the gas plan to date.
9. Beyond winter: summer PDRC, a ground battery, and gated compute
The core case is winter firm capacity. The same system can deliver more.
The Brandon fight is winter firm capacity. But the same stewardship logic can address summer cooling, offer compute upside, and contribute to water quality. These are separate ledgers, honest accounting, and optional extensions—not substitutes for the winter case.
Summer potential: PDRC and a ground battery
Manitoba's winter case is heating. Its summer problem is cooling. The other-season potential is a pair, not a single gadget.
PDRC — passive daytime radiative cooling films on large commercial and institutional roofs — rejects heat to the sky even under direct sun, so those roofs stop dumping load into air conditioning. On an illustrative 2.4 million m² rooftop envelope at about 75 W/m² of net radiative cooling, that is roughly 180 MW shaved from a +35 °C peak E. Roof area already paid for; physics that works hardest when the sun is worst.
A ground battery — borehole thermal energy storage (BTES) at the heat hosts — is the underground half of the same idea. It banks reject heat in the ground for winter and avoids about 70 MW of parasitic chillers in summer E. Sky cools the roofs; ground stores the heat. Together the summer add-on is about 250 MW against an illustrative heatwave anchor near 3,514 MW inside a 3,800-4,200 MW summer peak band E.
The Brandon fight is still winter firm capacity. PDRC plus the ground battery is the same stewardship logic applied to the other season — registered in its own ledger block, tested so it can never migrate into the 413 / 761 / 861 MW winter range. It is not winter firm.
Data center potential: heat-first, public, and accountable
Small public compute is optional upside. The heat recovery does not depend on it.
The same stewardship logic that drives heat recovery can extend to data centers — but with strict limits and clear gates. Any compute at the hub must be small, public, and heat-first. Eligible capacity today is exactly 0 MW until three gates clear for a real site: a contracted heat customer, demonstrated grid headroom, and a contracted buyer C.
This is not a private hyperscale warehouse that treats clean power as a discount coupon. It is clean, publicly accountable nodes in the 10-20 kW band that earn their keep through heat first, computation second. The three gates ensure that compute only proceeds when it can demonstrate real value to Manitoba's grid and communities.
10. Soil & water: honest phosphorus arithmetic
The heat hub is an energy case. The remediation math is separate.
The environmental analysis stands on a binational Red River basin evidence base: 17,629 Canadian and 137,540 American water-quality observations at 3,574 stations, 121 active U.S. streamflow gauges, and 902 paired phosphorus-and-flow load calculations at the Emerson border gauge O C. The border objective is 1,400 t P/yr at Emerson O.
NEWPCC solids recovery represents roughly 4% of the required phosphorus reduction. Surplus-funded remediation bands address agricultural sources, and a full stack of measures would close the external load gap. No single measure—including the hub's heat recovery—solves the phosphorus problem alone. The arithmetic requires honest accounting of what each intervention delivers.
Because no single measure closes the gap, this filing attaches a binding surplus rule the Board can require: at least 35% of heat-recovery and gated-compute surplus flows to Lake Winnipeg phosphorus remediation as a first lien, changeable only by a 75% supermajority governance amendment with public notice — intergenerational equity as a lock, not a press release E.
This is a water-quality case separate from the winter firm capacity argument. The energy hub proceeds on its own merits. The remediation work requires its own evidence base and its own ledger.
11. Take action
Share the case, write a two-minute letter, or take a formal seat at the hearing.
The master filing PDF contains the full technical case. You can download it below, along with the math addendum for Board staff who need to verify the calculations.
Master filing PDF: Download the master filing. Also the math addendum for Board staff.
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STEP 1 (30 SECONDS)
Share
Send the case to someone who should see it — text, WhatsApp, email, or your socials. Same link, same arithmetic.
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STEP 2 (2 MINUTES)
Write your letter
One Manitoban's written comment enters the official record with no coordination: the Public Utilities Board, your MLA, or your councillor.
Take Action -
STEP 3
Stand as an intervener
For community groups and formal participants: apply under the Board's Rules of Practice and use the master filing as an evidence pack.
Intervener starter kit
Supplementary whitepapers
Deep dives behind single claims in the master filing, rebuilt in the same format.
- Real total cost forensic accounting: the 20-year lifecycle ledger, line by line.
- Trenchless and HDD piping civil analysis: how the district loop goes in fast, without open trenches.
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