What this tool shows: if a D-T tokamak is upsized to sell both firm industrial heat and grid electricity, then —
(1) what plant size is optimal for a given heat-to-power price ratio (Costheat/Costelec), and
(2) how much extra NPV do thermal storage + smart dispatch buy when the power price swings on a ~24 h cycle? Move the sliders; LCOE and NPV update live.
Fixed heat at a constant price — industrial heat is bought on long-term firm contracts, so the 200 MWth offtake and its $/MWhth price are held constant and delivered 24/7, whatever the power market does. The electricity price, by contrast, is yours to set indirectly — the heat-to-power ratio slider fixes its average level (Costelec = Costheat/ratio) and the volatility slider sets how far it swings over the day.
Power added on top of the heat — the reactor is sized to supply the heat contract plus a net electric output you choose, so electricity capacity is added on top of the heat, not carved out of it.
4 h thermal energy storage (TES) — lets the reactor run flat-out baseload while the turbine shifts electricity into the daily evening price peak; the store discharges to keep the heat firm. ~4 h matches the width of a typical evening peak — longer storage would sit idle most of the day.
Capacity revenue — grid capacity markets pay $/kW-yr for firm, dispatchable capacity a plant can guarantee at peak. It is real, non-electricity revenue, so it is credited against cost and lowers the net LCOE, exactly like the heat sales.
Price-taker — the grid is assumed large enough that the plant's throttling doesn't move market prices; the turbine is upsized to convert the full thermal stream during peaks, while the TES covers the heat.
Baseline model — reactor capital and physics-based power balance and scaling are taken from 1costingFE's D-T tokamak model (ηgen = 0.40, 85% availability, CRF 7%/30 yr).
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Revenue levers — toggle to isolate each effect
NOAK cost levers — stack aggressive Nth-of-a-kind assumptions on the tokamak capital & financing; each scales the underlying 1costingFE accounts and re-derives indirect, IDC, and capital recovery. All off = the tuned baseline above. All lever percentages are reductions from that baseline (e.g. −35% ≡ 0.65× baseline); systemic & financing levers instead show absolute before → after values.
Model assumptions
Price-taker: the plant sells at the market clearing price regardless of how much it exports (no price-maker / grid-congestion effect on price).
Firm heat: 200 MWth delivered 24/7 at the price set by the Costheat slider (default $40/MWhth ≈ $11.7/MMBtu — firm clean high-grade heat + modest carbon adder; the $20–100 range spans gas-parity up to premium high-grade heat that, in deep-decarbonization scenarios, can meet or exceed the cost of clean-firm electricity). The Costheat/Costelec ratio slider then sets the electricity price Costelec = Costheat/ratio, so raising Costheat lifts both heat and (at fixed ratio) power price.
Price shape: a representative US duck-curve day (evening peak); the volatility slider scales the hourly deviation about the mean while holding the mean at Costelec.
Plant scaling: reactor + turbine capital and recirc-correct net electric interpolated from 1costingFE D-T tokamak points (100–2000 MWe); ηgen=0.40, availability 0.85.
Sizing: the reactor delivers the 200 MWth heat and the chosen net power — thermal ≈ 200 + (Pnet+recirc)/ηgen — so the slider adds capacity on top of the heat (full-power net = Pnet+80 MWe; the heat draw brings it back to Pnet). With smart dispatch the turbine is sized for full-thermal conversion (net Pnet+80) so it can peak while the TES covers heat; the rigid case uses a smaller turbine sized to Pnet.
Smart dispatch: 4 h TES firms the heat while the plant throttles to full net power in the 4 highest-price hours; the store is recharged off-peak, so annual energy is conserved (smart only re-times it).
Capacity market (when on): $88/kW-yr on the peak net capacity.
Costs: TES $30/kWhth; heat-export BoP $200/kWth; O&M ≈ 1.47%/yr of capital; heat BoP + TES added to the 1costingFE plant capital.
Economics: CRF at 7% / 30 yr (0.081); NPV = level annual profit × 12.4 (30-yr annuity).
Net LCOE credits heat + capacity revenue against cost; the captured price is the dispatch-weighted realized electricity price (this is where TES/dispatch value shows, not in the cost-LCOE).
Effective LCOE (heat + capacity credited)
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Plant NPV (30 yr)
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Path to 1¢/kWh ($10/MWh net LCOE)
TL;DR — heat sales alone cannot bridge the LCOE gap.