$141.4M annual value at full build
Complete economic model for the Pacific Decarbonized Energy Corridor. Revenue streams, cost analysis, capital requirements, sensitivity modelling, and funding pathways. All figures in $CAD.
Annual Value Breakdown
Eight distinct value streams at full build, separated into direct cash flows to PDEC and broader societal value.
Direct Economic Value
| Revenue Stream | Basis | Annual Value |
|---|---|---|
| Avoided diesel fuel cost | 32.7M L at $1.60/L | $52.3M |
| Solid carbon co-product | Ekona range $800-$1,500/t, modelled at blended | $4.5M |
| Electrolysis oxygen byproduct | 8 kg O2 per kg H2, industrial sale | $2.6M |
| District heat | Electrolyzer waste heat recovery | $4M |
| Grid services / BC Hydro demand response | Electrolyzer load flexibility | $3M |
| FortisBC hydrogen blending offtake | Pipeline blending revenue | $4M |
| BC LCFS credits | Low Carbon Fuel Standard, $350/t CI reduction | $15M |
| Subtotal - Direct | $85.4M | |
Social and Externality Value
| Value Stream | Basis | Annual Value |
|---|---|---|
| Social cost of carbon | 87,538 t at $294/t (2030 federal SCC) | $25.7M |
| Respiratory health savings | PM2.5 particulate reduction in urban harbour | $11.8M |
| Air quality improvement | NOx, SOx, ground-level ozone reduction | $4.6M |
| Subtotal - Social | $37.6M | |
PDEC as Operator
Financial model for PDEC as a hydrogen producer and seller. Hydrogen priced at $5.80/kg, competitive against diesel-equivalent cost of $10-12/kg for heavy-duty applications.
Hydrogen Pricing
Revenue (annual at full build)
| Hydrogen sales (6.6M kg at $5.80/kg) | $49.5M |
| Solid carbon co-product | $4.5M |
| Oxygen byproduct | $2.6M |
| District heat | $4M |
| Grid services | $1.5M |
| FortisBC blending | $1.5M |
| LCFS credits | $15M |
| Total Revenue | $100.8M |
Operating Costs (annual at full build)
| Production cost (LCOH x volume) | $33.2M |
| Staffing (55 staff) | $8.2M |
| Maintenance (2% of CapEx) | $9.5M |
| Insurance | $5M |
| Land lease | $2M |
| Admin and other | $2M |
| Total OpEx | $62.5M |
Profitability
Why effective payback is 5-8 years: Simple payback (2.4 yr) divides CapEx by annual EBITDA and ignores three factors. (1) Grant offsets: CIB, LCFS, SIF, PacifiCan, and Budget 2025 instruments could cover 30-50% of CapEx. At 40%, CapEx drops to $127.5M. (2) Escalation: Diesel prices (+2%/yr) and carbon prices (+5%/yr) grow EBITDA over the 20-year horizon. (3) Phase 3 industrial demand: Green steel offtake at 250,000 t/yr HBI lifts combined EBITDA to $63.6M, further accelerating payback.
Levelized Cost of Hydrogen (LCOH)
Three production pathways blend to a competitive LCOH. Methane pyrolysis + biomass gasification each produce valuable byproducts (solid carbon, biochar, sequestered CO2) captured as separate revenue lines rather than netted against production cost. The blend leans on pyrolysis + biomass for lower-cost baseload and electrolysis for flexibility + grid services.
Electrolysis ($3.27/kg)
| Component | $/kg H2 |
|---|---|
| Energy (52 kWh/kg at $0.048/kWh) | $2.50 |
| CapEx amortization (30 MW PEM, 20-yr) | $0.37 |
| Operations and maintenance | $0.40 |
| Electrolysis LCOH | $3.27 |
Pyrolysis ($2.50/kg gross)
| Component | $/kg H2 |
|---|---|
| Gross production cost | $2.50 |
| Carbon co-product (3 kg C per kg H2) | -$4.50 |
| Carbon price assumption (modelled upper) | $1,500/t |
| Pyrolysis LCOH (net) | -$2.00 |
Production split: 46.2% electrolysis, 32.3% methane pyrolysis, ~22% biomass+BECCS. Blended LCOH = $3.91/kg. Pyrolysis carbon credit + biochar + sequestered CO2 credits appear in revenue as separate co-product lines ($4.5M carbon, plus biochar and BECCS CORC), not as cost offsets.
Electricity rate sensitivity: Electrolysis LCOH scales with BC Hydro industrial electricity rates. Across the full sensitivity range tested ($0.040-$0.065/kWh), electrolysis LCOH moves within a bounded range. The blended LCOH remains competitive because pyrolysis + biomass (~54% of production combined) are unaffected by electricity pricing. Sensitivity analysis confirms the project remains NPV-positive across the full electricity rate range tested.
Capital Requirements and Net Present Value
Phase 1 capital requirements benefit from $10-20M in savings by reusing existing Burrard Thermal infrastructure (grid interconnection, water intake, industrial zoning, rail access) rather than building greenfield.
| NPV Parameter | Value |
|---|---|
| Discount rate | 5% |
| Projection period | 20 years |
| Ramp period | 5 years (linear to full build) |
| Annual value at full build | $141.4M |
| CapEx midpoint | $212.5M |
| Burrard infrastructure savings | $15M |
| Net 20-year NPV | $1.30B |
Sensitivity Analysis
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 base case: demand scale (70%-120%), diesel price ($1.20-$2.00/L), social cost of carbon ($200-$400/t), utilization (60%-95%), solid carbon product price ($1,000-$5,000/t). H2 sales price ($5-10/kg) and electricity rate ($0.040-$0.065/kWh) affect operator EBITDA but not total annual value, which measures system-wide economic impact including offtaker savings.
CapEx Sensitivity
Operator payback response to capital cost variation, including grant offsets (0.6x) and construction overruns (1.3-1.5x). Maintenance cost scales at 2% of CapEx.
Grant precedents: CIB $337M to HTEC (hydrogen infrastructure), LCFS $133M. Budget 2025 instruments (SIF, PacifiCan) could cover 30-50% of CapEx.
Scenario Modelling
Four scenarios ranging from Phase 1 initial deployment through full build with potential export demand. Conservative scenario assumes 80% offtaker participation across all applications.
Phase 1 includes West Coast Express, SeaBus, transit buses, and port cranes at 40% of base demand. All scenarios use a 5% discount rate over 20 years with a 5-year linear ramp to target capacity.
Technology, not policy dependency
PDEC's operator EBITDA ($38.2M, 38% margin) derives entirely from direct revenue streams: hydrogen sales at $5.80/kg, solid carbon co-product, oxygen byproduct, district heat, grid services, and FortisBC blending. None of these require carbon pricing, carbon taxes, or emissions trading systems to generate returns. The $37.6M in social value (avoided carbon and healthcare costs) is a public benefit, not an input to the business case. If carbon pricing were frozen or eliminated, PDEC's commercial economics are unchanged.
Phase 3: Green Steel Strategic Demand
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 existing transit and marine base case. The "Combined EBITDA" in each card is the total across both the base case ($38.2M from transit/marine) and the new industrial offtake. All three scenarios are additive - they do not replace the base case.
How the model works
Why Elk Valley
What this means: PDEC's base case (transit and marine offtakers) generates $38.2M 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 $5.80/kg retail price). The additional demand transforms PDEC's economics from a viable regional project to a nationally significant industrial hydrogen supplier. 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 $25.4M/yr additional EBITDA at the 250K t/yr HBI midpoint.
Funding Pathways
Capital assembly draws on proven federal and provincial instruments with strong 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 - $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
Phase 1: Capital ($160M - $265M)
| 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 |
| Transport Canada ZETF | Zero Emission Transit Fund for SeaBus, WCE, transit bus applications | $2.75B program (Budget 2022) |
| ISED Strategic Innovation Fund | Large-scale clean energy project support | $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 |
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