No, despite Iran oil shock, Canada still doesn’t need more pipelines

Key data: Trans Mountain expansion (TMX) cost $34.2B and currently collects roughly a US$10/barrel toll; Trans Mountain is studying upgrades to raise capacity from 0.89m to 1.19m bpd by 2027–2030 (+~0.3m bpd). Author argues short-term oil spikes (spot >US$100/bbl) are priced back toward ~US$70/bbl on futures, so billion-dollar new pipelines lack a compelling long-term business case and face regulatory and Indigenous opposition. Recommendation: prioritize electrification, EV adoption and renewable/clean LNG projects (long-term contracted LNG more viable) rather than public funding of new oil pipelines.

Analysis

The current political-driven oil price spike is a short-duration signal layered over a multi-decade investment horizon for midstream assets; that mismatch is the core structural risk to new-build pipelines. Infrastructure economics are highly convex: a moderate mean-reversion in crude (20–30% from peak) can flip multi-decade IRRs to negative for capacity-heavy projects once financing costs and multi-year schedule risk are baked in.

LNG is the outlier: project-level cashflows are commonly locked into 15–20 year contracts, creating a much lower execution-risk/price-risk profile than open-market crude pipelines. A credible green-premium for lower‑carbon LNG (even a 10–15% contract premium) materially improves the NPV of coastal liquefaction trains, and creates upstream demand for electrification and grid-scale renewables near terminals.

Second-order winners include grid/renewables developers, battery-metal producers, and long-duration power storage providers who will see incremental CAPEX as liquefaction electrifies; losers are specialty pipeline contractors and steel/equipment suppliers whose orderbooks are lumpy and visible only in multi-year horizons. Political and Indigenous litigation risk remains a high-probability timing tail — approvals can be delayed for years, turning headline-driven price spikes into stranded-capex scenarios and pressuring Canadian sovereign and provincial credit metrics if public capital is deployed.

Key Decisions for Investors

• Long Cheniere Energy (LNG) — buy shares or 12–24 month call spread (e.g., 12–18 month ATM/1.2x strike). Rationale: contracted LNG cashflows benefit from Asian demand re-anchoring and FIDs toward 2026; target +30–60% if LNG export utilization and SPOT vs contract spreads widen. Stop: 20% below entry; risk: global gas demand collapse or major U.S. feedgas constraints.
• Pair trade — short SNC-Lavalin (SNC:TSX) or Aecon (ARE:TSX) / long Brookfield Renewable (BEP:NYSE) in equal notional size. Timeframe 6–24 months. Rationale: contractors face deferred/cancelled pipeline capex and litigation delays while renewable build-out and grid upgrades are firming; expect relative outperformance of BEP by 20–40%. Stop pair at 15% adverse move.
• Short CAD via forwards or FXC put options (or long USDCAD) — horizon 12–36 months. Rationale: structural headwinds to oil-derived export earnings as transition + demand flattening pressure terms of trade; a 5–10% CAD depreciation is plausible if pipeline capex is deferred. Hedge/stop if WTI sustains >$100 for 6+ months.
• Long Shell (SHEL:NYSE) or integrated major with LNG exposure — buy for 12–36 months to capture green-LNG premium and project optionality. Rationale: majors can finance low‑carbon liquefaction and capture higher contract pricing; target 20–35% upside vs sector. Risk: slower-than-expected Asian demand recovery or carbon-policy costs.