Economics
What PDEC earns, what it costs to build and run, and how the numbers hold up when the assumptions move. All figures in Canadian dollars.
Annual value
Each year at full build PDEC creates value three ways: direct revenue and fuel savings, carbon credits and by-products, and cleaner air and a cooler climate.
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Value streams at full build in three groups: direct value (PDEC cash flows plus offtaker fuel savings), biomass co-products and regulated credits, and broader societal value. Together they come to $136.4M a year. Rows are rounded; every subtotal and the total come straight from the model, so a column of rounded rows can differ from its subtotal by $0.1M.
Direct value
| Value stream | Basis | Annual value |
|---|---|---|
| Avoided diesel fuel cost | 33.2M L at $1.60/L (offtaker saving) | $53.1M |
| Solid carbon co-product | 8,212 t at $1,000/t target in a carbon offtake contract; July 2026 carbon black spot about CAD $2,585/t | $8.2M |
| Electrolysis oxygen byproduct | 8 kg O2 per kg H2; 55% sold at $150/t, 45% vented until contracted | $2.7M |
| District heat | Electrolyzer waste heat, 55,845 MWh/yr at $75/MWh | $4.2M |
| Grid services / BC Hydro demand response | Electrolyzer load flexibility | $3M |
| FortisBC hydrogen blending offtake | No separate premium: the 500 kg/day FortisBC offtake is paid through hydrogen sales. Upside if a purchase program opens | $0.00 |
| BC LCFS credits | About 50,000 t of credits at $170/t (August 2026 average), held flat for 20 years | $8.5M |
| Subtotal, direct value | $79.7M | |
Biomass co-products and regulated credits
| Value stream | Annual value |
|---|---|
| Clean Fuel Regulations dispensing credits | $5.2M |
| BC OBPS credits | $5M |
| BC Ports Property Tax Act cap | $2.6M |
| BECCS CO2 credits | $2.6M |
| Biomass tipping fees | $1.2M |
| Property tax abatement | $750K |
| Pyrolysis cogen | $694K |
| Biochar | $548K |
| Subtotal, co-products and credits | $18.5M |
Social value
| Value stream | Basis | Annual value |
|---|---|---|
| Social cost of carbon | 89,018 t at $294/t (2030 federal SCC) | $26.2M |
| Health savings | PM2.5, NOx and SOx reduction, $135 per tonne CO2 displaced | $12M |
| Air quality improvement | NOx, SOx, ground-level ozone reduction | Included above |
| Subtotal, social value | $38.2M | |
Total
| Direct value | $79.7M |
| Biomass co-products and regulated credits | $18.5M |
| Social value | $38.2M |
| Total annual value | $136.4M |
Operator economics
As a business, PDEC sells hydrogen for more than it costs to make and keeps about 30% of its revenue as operating profit.
From revenue to operating profit, Burrard at full build
| Line | Annual amount |
|---|---|
| Revenue | $101.1M |
| Less production cost | $39.9M |
| Less maintenance | $11.1M |
| Less staffing | $8.2M |
| Less insurance | $5M |
| Less land lease | $2M |
| Less admin and other | $2M |
| Less stack replacement reserve | $1.7M |
| Less surety bond | $500K |
| Less compliance | $250K |
| Less water | $100K |
| EBITDA | $30.4M |
See the detail
Financial model for PDEC as a hydrogen producer and seller. Hydrogen is sold at a blended $6.50/kg ($5.75/kg gate for bulk buyers, $7.63/kg delivered to urban fleets), under take-or-pay contracts with a price floor at 80% of list. BC retail hydrogen sells at $16.50/kg today (HTEC, 2026), and diesel costs about $7.52 per kg-of-hydrogen equivalent at $1.60/L bulk. PDEC's blended price is about 60% below today's retail hydrogen and about 13% below the diesel it replaces, so offtakers save from the first day.
Hydrogen pricing
| Sales price (blended) | $6.50/kg |
| Less blended production cost | $4.63/kg |
| Gross margin per kg | $1.87/kg |
Revenue (annual at full build)
| Hydrogen sales (8,623,955 kg at $6.50/kg) | $56.1M |
| BC LCFS credits | $8.5M |
| CFR dispensing credits | $5.2M |
| BC OBPS credits | $5M |
| Solid carbon co-product | $8.2M |
| District heat | $4.2M |
| FortisBC blending premium (volume is in hydrogen sales) | $0.00 |
| Grid services | $3M |
| BC Ports Property Tax Act cap | $2.6M |
| Oxygen byproduct | $2.7M |
| BECCS CO2 credits | $2.6M |
| Biomass tipping fees | $1.2M |
| Property tax abatement | $750K |
| Pyrolysis cogen | $694K |
| Biochar | $548K |
| Total revenue | $101.1M |
Operating costs (annual at full build)
| Production cost (LCOH x volume) | $39.9M |
| Maintenance (3% of capex) | $11.1M |
| Staffing (55 staff) | $8.2M |
| Insurance | $5M |
| Land lease | $2M |
| Admin and other | $2M |
| Stack replacement reserve (2% of electrolyzer) | $1.7M |
| Surety bond | $500K |
| Compliance | $250K |
| Water | $100K |
| Total operating costs | $70.8M |
Profitability and payback
| Revenue | $101.1M |
| Less operating costs | $70.8M |
| EBITDA | $30.4M |
| EBITDA margin | 30% |
| Payback on effective capex ($110.3M after ITCs, grants and tax benefits) | 3.6 yr |
| Payback with ramp-up (same capex, year-by-year cash flows over a 7-year ramp) | 6.2 yr |
| Payback on gross capex ($368.4M before any credit or grant) | 12.1 yr |
How to read payback. All three figures use full-build EBITDA of $30.4M. (1) 3.6 years divides the $110.3M effective capex (gross capex plus interest during construction, less the Clean Hydrogen, CCUS, Clean Technology and Clean Electricity ITCs, $50M in grants, the PST exemption, the accelerated CCA tax shield and the Indigenous loan guarantee benefit) by EBITDA. The ITCs are legislated; the grants and the Indigenous partnership are not yet awarded or signed. (2) 6.2 years is when cumulative EBITDA on the model's year-by-year cash flows, with the 7-year ramp and escalation, passes $110.3M. (3) 12.1 years divides the gross $368.4M by EBITDA with no credits at all. On narrower evidence the model gives 10 yr (Research case, Tier A+B) and 42 yr (Ironclad, Tier A only, at published power rates and a $188/t carbon price). Upside not in these figures: LCFS at $15M/yr gives 3.0 years, carbon at $1,500/t gives 3.2 years, and Phase 3 industrial demand from green steel offtake at 250,000 t/yr HBI lifts combined EBITDA to $46.1M.
Cost to make hydrogen
Three production methods share the work. At this first-plant size, splitting natural gas costs more to run than making hydrogen from power and water, but selling its solid carbon brings its net cost well below that, and the wood-waste process earns carbon-removal credits.
Cost per kg by method, weighted by share of output
- Electrolysis$4.32/kg47% of output
- Pyrolysis$5.50/kg31.7% of output
- Biomass gasification$4.00/kg21.2% of output
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Three production pathways blend to one production cost. Methane pyrolysis and biomass gasification each produce saleable byproducts (solid carbon, biochar, sequestered CO2), booked as separate revenue lines rather than netted against production cost. At first-plant scale pyrolysis costs more to run than electrolysis ($5.50 vs $4.32/kg); its carbon sales at $1,000/t bring it to $2.50/kg net. Electrolysis adds flexibility and grid services.
Electrolysis ($4.32/kg)
| Component | $/kg H2 |
|---|---|
| Energy (55 kWh/kg at $0.055/kWh, BC Hydro RS 1830 off-peak/curtailable) | $3.03 |
| Capex amortization (30 MW at $2,870/kW, 25-yr, 85% utilization) | $0.85 |
| Operations and maintenance | $0.45 |
| Electrolysis LCOH | $4.32 |
Pyrolysis ($5.50/kg gross)
| Component | $/kg H2 |
|---|---|
| Gross production cost (7.5 t/day first-of-a-kind) | $5.50 |
| Carbon co-product (3 kg C per kg H2) | -$3.00 |
| Carbon price (carbon offtake contract target; July 2026 carbon black spot about CAD $2,585/t) | $1,000/t |
| Pyrolysis LCOH (net) | $2.50 |
Production split: 47% electrolysis, 31.7% methane pyrolysis, 21.2% biomass+BECCS. Blended LCOH = $4.63/kg, weighting gross pathway costs ($4.32 electrolysis, $5.50 pyrolysis, $4.00 biomass) by actual output. Pyrolysis carbon credit + biochar + sequestered CO2 credits appear in revenue as separate co-product lines ($8.2M carbon, plus biochar and BECCS CORC), not as cost offsets.
Electricity rate sensitivity
Electrolysis LCOH scales with the BC Hydro rate. Rate Schedule 1830 applies (RS 1823 was consolidated into it on April 1 2026; RS 1894 has been capped and waitlisted since August 2023). The RS 1830 energy charge is 4.914 cents/kWh. The model uses $0.055/kWh all-in, an off-peak and curtailable supply to be secured in the BC Hydro supply agreement. At the published $0.065/kWh, blended LCOH is $4.89/kg and EBITDA $28.1M; across the range tested ($0.055-$0.075/kWh), blended LCOH moves from $4.63 to $5.16/kg and EBITDA from $30.4M to $25.8M, because pyrolysis + biomass (53% of production) are unaffected by electricity pricing.
Build cost and 20-year value
Federal tax credits, grants and other offsets cover most of the Phase 1 build cost, leaving PDEC a much smaller share to finance.
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Phase 1 costs $368.4M gross, itemized line by line, including a 25% contingency ($73.7M) on the other lines, the low end of the AACE range for a pre-FEED first-of-a-kind plant. After legislated ITCs, grants and tax benefits, the equity requirement is $110.3M. The Burrard Thermal brownfield is leased rather than bought and already has a FortisBC gas pipeline, rail access, industrial zoning and deep-water frontage; those savings are built into the capex lines. A new 230 kV substation ($28.5M) and a new dock are still required and are included.
Build cost
| Phase 1 capex, gross | $368.4M |
| Phase 1 capex, effective (after ITCs, grants and tax benefits) | $110.3M |
| Land acquisition (leased brownfield) | $0 |
Net 20-year value
| Parameter | Value |
|---|---|
| Discount rate | 5% |
| Projection period | 20 years |
| Ramp period | 7 years (linear to full build) |
| Annual value at full build | $136.4M |
| 20-year value before capex (gross NPV) | $1.34B |
| Less effective capex | $110.3M |
| Burrard brownfield savings | In capex lines |
| Net 20-year value (net NPV) | $1.23B |
Both 20-year figures are total-value (cost-benefit) figures: they count offtaker fuel savings, co-product and credit revenue and monetized social value, with no escalation and no value after year 20 (the plant is modelled on a 25-year life). Deducting the full gross capex plus interest ($401.5M) with no credits at all still leaves $938.3M. PDEC's own cash return clears its capital: discounting its year-by-year EBITDA gives $398.9M, or $288.6M after the $110.3M effective capex.
Sensitivity
The model moves one input at a time: hydrogen price, power price, carbon price, credits and how much of the time the plant runs. PDEC stays profitable across every range tested.
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Total annual value response to variation in key parameters, each tested independently while holding others at base case. The chart below loads data from the economic model and renders the impact of each parameter variation.
Parameters varied independently around the base case: solid carbon price ($188-$1,500/t; total value $129.8M-$140.5M, EBITDA $23.8M-$34.6M), utilization (75%-95%; $130.3M-$142.6M) and BC LCFS credits ($0-$20M/yr; $127.9M-$147.9M, EBITDA $22.0M-$42.0M). H2 sales price ($4.00-$6.00/kg) and BC Hydro rate ($0.055-$0.075/kWh) show as flat lines because they move operator EBITDA, not total annual value: EBITDA runs $8.9M-$26.2M across the price range (base $6.50/kg: $30.4M) and $30.4M-$25.8M across the rate range. EBITDA stays positive in every single-input sweep. The contract price floor at 80% of list ($5.20/kg) keeps EBITDA at $19.3M. Even at the top of the carbon range, the model's price is below July 2026 carbon black spot (about CAD $2,585/t).
Capex sensitivity
Operator payback on effective capex as gross capital cost varies from 0.85x to 2.0x of the $368.4M base (which already carries a 25% contingency): 2.6 years at 0.85x, 5.2 at 1.2x, 8.3 at 1.5x and 16.3 at 2.0x. Maintenance scales at 3% of capex. Net 20-year value stays above $1.05B across the range.
Grant precedents: CIB $337M to HTEC (hydrogen infrastructure), LCFS $133M. The model counts $50M in grants; a larger Clean Fuels Fund award would lower effective capex further.
Scenarios
The base case earns $30.4M a year. Counting only revenue backed by law, or selling at the lowest contract price with a 30% cost overrun, PDEC still covers its operating costs but earns little. That is why PDEC signs four contracts before it builds.
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Four runs of the economic model: the anchor-offtaker Phase 1 case, the full-build base case, the model's upside run and its downside run. Each changes the inputs listed below the table and holds everything else at the base case.
| Run | Daily H2 | Annual value | EBITDA | Net 20-year value | 20-year value before capex |
|---|---|---|---|---|---|
| Phase 1 anchors only | 8,890 kg | $87.2M | $10.0M | $781.8M | $856.3M |
| Full build (base case) | 23,627 kg | $136.4M | $30.4M | $1.23B | $1.34B |
| Upside | 24,936 kg | $158.2M | $45.1M | $1.47B | $1.55B |
| Downside | 23,627 kg | $126.3M | $1.3M | $1.02B | $1.24B |
- Phase 1 anchors only. 5 anchor offtakers, capex at 80%; payback 7.4 years.
- Full build. Plant sold out; demand is about 2x capacity; payback 3.6 years.
- Upside. 95% utilization, carbon $1,500/t, capex 0.85x, LCFS $20M, $0.058/kWh (at a $6.00/kg price); payback 1.8 years.
- Downside. $5.20/kg (contract floor), capex 1.3x, ITC 25%, LCFS $5M, carbon $188/t, $0.072/kWh. Covers operating costs; payback beyond 20 years.
All scenarios use a 5% discount rate over 20 years with a 7-year linear ramp. Each run's net 20-year value deducts that run's own effective capex. Phase 1 anchors are transit buses, harbour tugs, port equipment, SeaBus and West Coast Express; that run keeps fixed annual lines such as LCFS at full-build values, so it is an upper bound. The 20-year values are total-value figures that include offtaker fuel savings and social value, so they stay high even when PDEC's own margin is thin; EBITDA is the operator view. Demand churn does not reduce output: addressable demand (47,090 kg/day) is about twice capacity, and the model's resilience run at 72% of demand leaves EBITDA and net 20-year value unchanged. On narrower evidence the model gives EBITDA of $14.8M (Research, Tier A+B; net 20-year value $785.5M) and $4.1M (Ironclad, Tier A only; net 20-year value $723.9M).
What makes PDEC investable
Four contracts, signed before construction, lock in the base case. Each value below is the EBITDA difference against the model's earlier assumptions.
- Take-or-pay hydrogen offtakes at a blended $6.50/kg with a price floor at 80% of list: worth $6.0M a year against $5.80/kg. At the $5.20/kg floor, EBITDA is still $19.3M.
- BC Hydro supply agreement for off-peak and curtailable power at about 5.5 cents/kWh under RS 1830: worth $2.4M a year against the published 6.5 cents.
- Solid carbon offtake at $1,000/t or better: worth $3.7M a year against $550/t, with July 2026 spot about CAD $2,585/t.
- Anchor volumes that keep the plant at 85% utilization: worth $0.7M a year against 82%.
Together the four are worth $12.7M a year: without them EBITDA would be $17.8M. The downside run above already assumes the price falls to the $5.20 floor, costs run 30% over and credits shrink; it still covers its operating costs.
What depends on policy
Of PDEC's $101.1M operator revenue, $18.7M comes from credit programs: BC LCFS $8.5M, federal Clean Fuel Regulations $5.2M and BC OBPS $5M. Hydrogen sales, solid carbon, oxygen, heat and grid services are commercial revenue. With LCFS removed and no Clean Hydrogen ITC, the model gives EBITDA of $22.0M: the plant still earns, and payback lengthens to 10.3 years because effective capex rises to $226.2M without the ITC. The Clean Hydrogen ITC is law (Bill C-59), and LCFS is a standing BC regulation; the model already holds LCFS at a low $170/t with no growth. The $38.2M in social value (avoided carbon and healthcare costs) is a public benefit and is not an input to EBITDA.
Phase 3: green steel
If a green iron plant is built in the Elk Valley, it would buy hydrogen at scale by rail and more than double PDEC's size. This is upside, not part of the base case.
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Global steelmakers are shifting from coal-fired blast furnaces to hydrogen-based direct reduced iron (DRI). BC's Elk Valley is one of Canada's largest metallurgical coal regions, with 5,400 workers and operations owned by Glencore (77%), Nippon Steel (20%), and POSCO (3%). PDEC can supply green hydrogen to a future Elk Valley HBI (Hot Briquetted Iron) facility via the same CP Rail corridor that carries coal today. CPKC's hydrogen locomotives already operate this route.
These scenarios model what happens to PDEC's economics when industrial hydrogen demand is added on top of the base case. The combined EBITDA in each column is the total across both the base case ($30.4M) and the new industrial offtake. All three scenarios are additive: they do not replace the base case.
| Phase 3 scenario | Conservative | Base case | Optimistic |
|---|---|---|---|
| Combined EBITDA (base + industrial) | $36.5M | $46.1M | $62.1M |
| HBI production | 100,000 t/yr | 250,000 t/yr | 500,000 t/yr |
| Industrial H2 | 14,795 kg/day | 36,986 kg/day | 73,973 kg/day |
| Total H2 | 38,422 kg/day | 60,614 kg/day | 97,600 kg/day |
| Additional capacity | 43 MW | 107 MW | 214 MW |
How the model works
| Industrial H2 sold at | $5.00/kg |
| Solid carbon sold at | $2K/t |
| H2 needed per tonne of iron | 54 kg |
| Industrial demand starts | Year 8 |
Industrial H2 is priced below the $6.50/kg blended rate as a volume discount for baseload offtake. The solid carbon co-product from pyrolysis commands a premium as EAF steelmaking carburizer. Source: Algers & Bataille (2025)
Why Elk Valley
| Mine owners | Glencore 77% |
| Built-in Asian buyers | Nippon 20%, POSCO 3% |
| Workers to retain | 5,400 |
| Canada's HBI cost rank | #2 globally |
Nippon Steel and POSCO already hold equity in the coal mines. As their steelmaking shifts to hydrogen DRI, they become the natural buyers of green HBI produced with PDEC hydrogen.
What this means
PDEC's base case generates $30.4M EBITDA. If a green HBI facility is built in the Elk Valley, PDEC would expand production to supply industrial hydrogen at $5.00/kg (a volume discount from the $6.50/kg blended price). The added demand would turn PDEC from a regional supplier into an industrial one. Expansion costs scale sub-linearly: doubling production does not double capital or staffing requirements. Phase 3 adds an estimated 107 MW of electrolyzer capacity and $186.4M in capex for $15.7M/yr additional EBITDA at the 250K t/yr HBI midpoint.
Funding
Most of the build cost is covered by programs that already exist. The Clean Hydrogen tax credit, now law, returns up to 40% of eligible equipment.
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Capital assembly draws on federal and provincial instruments with precedent in Canadian clean energy and hydrogen infrastructure. Phase 0 seed funding enables feasibility and permitting, while Phase 1 capital combines public financing with private equity.
Phase 0: seed ($500K to $1M)
| Source | Instrument |
|---|---|
| NorthX Climate Tech | Non-dilutive grants and repayable investments |
| NRCan Clean Fuels Fund | Low-carbon fuel production support, co-sponsor with BC Hydro and VFPA |
| UVic | IESVic NSERC funding, PICS fellowship, Gustavson MBA resources |
Key numbers for applications
| Net 20-year value | $1.23B |
| CO2 displaced a year | 89,018 t |
| Operations jobs | 55 |
| Construction jobs | 1,105 |
Phase 1: capital ($110.3M effective, $368.4M gross)
| Source | Instrument | Precedent |
|---|---|---|
| Canada Infrastructure Bank | Loan for clean energy and trade corridor infrastructure | $337M loan to HTEC H2 Gateway |
| BC LCFS Initiative Agreements | Low Carbon Fuel Standard credits for H2 production and use | $133M across 4 BC hydrogen projects |
| Canada Public Transit Fund | Federal transit capital for SeaBus, WCE and transit bus conversions (replaced ZETF, which closed to intake July 2025) | $663.7M to TransLink, 2026-2036 |
| ISED Strategic Response Fund | Large-scale projects in strategic sectors ($5B; succeeded the Strategic Innovation Fund, Sept 2025) | $420M to Algoma (green steel) |
| PacifiCan | Regional economic development | $3.6M to Ekona Power (pyrolysis) |
| Budget 2025 instruments | Productivity Super-Deduction, $5B Trade Diversification Corridor Fund, Major Projects Office | |
| Industry equity | Ballard, Corvus, BC Hydro, Indigenous equity participation, private infrastructure investors |
What PDEC needs next
Four contracts lock in the economics before anything is built. If you could sign one of them, or help find who will, a short call is the next step.
Customer contracts
Fleet, marine, port and industrial hydrogen buyers. They commit to buy a set volume at $6.50/kg, and the price never drops below $5.20/kg.
Off-peak power
BC Hydro. A supply agreement at about 5.5 cents a kilowatt-hour, with the plant running when power is cheapest.
Carbon buyer
Makers of steel, batteries, tires and building materials. They buy the solid carbon left when the plant splits natural gas, at $1,000 a tonne or better.
Anchor volumes
Transit, ferry and port operators. Committed volumes that keep the plant running at 85% of capacity.