BMO Capital sees oil sands output hit by NGTL pipeline outage

TC Energy reported an unplanned outage on March 7 on the NPS 36 Fort McKay Mainline, leaving firm shippers limited to ~42% of contracted natural gas deliveries and fully curtailing interruptible service — Suncor’s cogeneration at Fort Hills and MacKay River is at zero and Base Plant/Firebag power output is below 50% of three-month averages. Suncor still reported Q4 2025 EPS CAD 0.8057 vs CAD 0.732 forecast and revenue CAD 8.82B vs CAD 8.77B, trades near a 52-week high of $58.63 (shares +67% Y/Y) and received TSX approval to buy back up to 118.7M shares (~10% of float). The outage is likely to move individual oil sands names (Suncor, Imperial, Cenovus proximity risk) and create short-term supply uncertainty, while corporate results and a sizable buyback are supportive for Suncor’s equity.

Analysis

The incident highlights a structural sensitivity in oil-sands economics: short-lived gas delivery shocks can materially lift operating costs and force either diesel substitution or curtailed throughput. As a rule of thumb, a sustained local gas basis widening of $1–$3/MMBtu for 2–8 weeks typically raises steam‑injection driven cash costs by roughly $1–$6 per barrel of bitumen-equivalent depending on asset intensity, tightening near-term free cash flow for the most steam‑dependent producers.

On the capital-markets side, buybacks and EPS-supporting actions amplify idiosyncratic upside for companies that can continue running at scale, while simultaneously concentrating float and reducing natural sellers — a 5–12% reduction in tradable float materially lowers the liquidity threshold at which technical squeezes occur around operational news. That creates asymmetric shorter-term reward for equities with active repurchase programs but increases tail risk if a production restart is delayed and commodity prices slip.

Key catalysts and reversal channels are operational (firm restart timelines from pipeline operators), regional gas basis normalization, and the pace of inventory or export destocking; any of those clearing within 1–6 weeks would remove the premium on “on‑site power” optionality. Watch TC Energy operational notices, first-quarter production guidance, and short‑term Canadian gas forwards for early signals to adjust positioning.

Key Decisions for Investors

• Long SU equity (6–12 months) with a protective hedge: buy shares up to a 5% intraday pullback from current levels and hedge with 6–9 month puts (cost ~3–6% of position) — reward: potential 20–35% upside from EPS accretion + buyback support; downside: ~10–15% if gas/cash flow shock persists.
• Tactical long CNQ call exposure (3–6 months): buy near-dated OTM calls (~25–35% OTM) as a low-cost convex play if market re-allocates volumes to less-constrained operators — target 2:1 to 3:1 payoff if physical tightness persists; max loss = premium paid.
• Pair trade (3–6 months): long SU (size 1.0) / short TRP (size 0.4) — rationale: corporate buyback-driven equity support vs. midstream operational/regulatory re-risk. Hedging: keep 30–60 day puts on the pair to cap Black‑Swan downside. Expect asymmetric alpha if gas basis stays elevated.
• Short IMO or buy short-dated IMO puts (0–3 months) as a volatility play: size small (≤3% portfolio) — thesis: names with single-point generation exposure will rerate sooner on restart clarity; payoff if restart timelines slip, R/R asymmetry ~4:1 given low cost of puts.