TC Energy Advances Coastal GasLink Phase Two

Lead

TC Energy on March 25, 2026 confirmed commercial arrangements to advance the second phase of the Coastal GasLink pipeline in support of LNG Canada, according to a Seeking Alpha report (Seeking Alpha, Mar 25, 2026). The announcement formalizes a series of agreements that, per the company and partner disclosures, are designed to position pipeline capacity and contracting architecture ahead of an expected incremental LNG expansion decision. Coastal GasLink is the onshore conduit to the LNG Canada export facility; the pipeline's mainline is approximately 670 km in length, a figure repeatedly cited in company materials and project summaries (TC Energy project data).

The development matters because LNG Canada’s initial two-train project provided 14 million tonnes per annum (MTPA) of export capacity — a material new source of Canadian LNG supply versus the global market — and further phases could alter Canadian export trajectories and regional infrastructure demand (LNG Canada project literature). The March 25 media release and industry filings mark an operational pivot from first-phase execution to securing supply chain, rights-of-way and long-lead equipment commitments for incremental capacity. Market participants will be watching contracting terms, timing for final investment decisions (FIDs), and how cost allocation is split between transport and liquefaction sponsors.

This report lays out context on the deals, quantifiable implications for capacity and capital flow, comparisons to other export hubs, and a risk assessment for investors and policy makers tracking North American LNG build-out. Source citations are provided where available, including the Seeking Alpha summary of the announcement (Seeking Alpha, Mar 25, 2026), historical project data from TC Energy and LNG Canada, and third-party industry benchmarks.

Context

Coastal GasLink was initially developed to supply the LNG Canada export terminal on the British Columbia coast. The mainline project is commonly reported as roughly 670 km from northeastern British Columbia to the terminal corridor (TC Energy project data). The LNG Canada Phase 1 complex — widely reported in sponsor filings and industry accounts — comprises two liquefaction trains totaling 14 MTPA, which began coming online in the mid-2020s after multi-year construction and commissioning phases (LNG Canada public disclosures).

The March 25, 2026 agreements announced by TC Energy are framed as preparatory commitments to unlock a second construction and contracting phase for Coastal GasLink. While the Seeking Alpha piece provides the immediate news hook, developing Phase 2 will require aligning offtake, regulatory approvals, permitting, Indigenous agreements and financing. Those variables historically lengthen the calendar to FID: for large LNG projects, the timeline from concept to FID can span 24–48 months depending on market conditions and sponsor alignment (industry convention).

Regional demand drivers and global gas markets underpin the commercial rationale. Canada’s west-coast LNG sits strategically to supply Asia-Pacific markets where long-term contract prices and Asian spot dynamics continue to influence sanctioning decisions. However, sanctioning a Phase 2 expansion will be evaluated against competing global capacity; for context, Australia’s LNG export footprint is on the order of 80–90 MTPA—an order of magnitude larger than a single Canadian Phase 1 export facility—illustrating the scale of competition in liquefaction capacity (industry sources, BP/IEA summaries).

Data Deep Dive

The announcement itself is dated March 25, 2026 (Seeking Alpha), and is described as a set of commercial arrangements rather than a final investment decision for a second liquefaction train. Concrete data points in public disclosures include the pipeline mainline distance (670 km) and the established Phase 1 liquefaction capacity of 14 MTPA. Those two figures anchor both the engineering and market dimensions of any expansion discussion: pipeline throughput requirements and incremental liquefaction tonnage directly determine capital intensity and tariff design.

Capital and schedule metrics for Phase 1 have been public for several years and serve as a reference for incremental cost estimates. Phase 1 capital expenditures were reported in sponsor filings in the low tens of billions CAD for the entire liquefaction and upstream packages combined; sponsors evaluating Phase 2 will benchmark incremental costs against the Phase 1 experience, supply-chain inflation since 2021–2023 and current commodity price indices. Labour availability and long-lead equipment — notably LNG trains, compressors, and cryogenic heat-exchange modules — remain primary drivers of schedule risk and cost escalation.

From a market perspective, buyers and offtake structures will dictate the viability of an additional train. A second phase that adds, for example, another 7–14 MTPA would change Canada’s standing in Atlantic-facing and Pacific-facing trade lanes, but the precise economics are contingent on contract tenor and pricing (spot vs long-term), shipping logistics, and carbon/ESG terms embedded in offtake agreements. Market participants should watch the nature of the commercial arrangements disclosed by TC Energy: are they binding transportation commitments, option agreements, or preliminary letters of intent? Each conveys a distinct probability of sanction.

For further reading on infrastructure contracting and energy project analysis, see our infrastructure and energy insights energy insights and our related long-duration capital deployment note infrastructure report.

Sector Implications

If Phase 2 advances to FID, the immediate beneficiaries would be pipeline contractors, pipe suppliers, and equipment manufacturers, given the magnitude of onshore and near-terminal works. For midstream operators, the precedent set by contractual allocation between pipeline and liquefaction sponsors will inform tariff regulation and investor expectations for return of and on capital. The transaction architecture TC Energy employs—whether through firm transport commitments, capacity reservation fees, or risk-sharing mechanisms—will be a template for peer projects in Canada and U.S. LNG corridors.

On a comparative basis, a sanctioned second phase in Canada would modestly increase North American LNG market share relative to the U.S. Gulf Coast, which has delivered the majority of recent incremental export capacity. Year-over-year additions in U.S. export capacity have outpaced Canada historically; the sanctioning cadence for Canadian projects depends heavily on securing Asian offtake and navigating domestic permitting. A Phase 2 greenlight could narrow that gap but would not immediately alter absolute global balances given the size of competing capacity in Australia, Qatar and the U.S.

Policy and ESG considerations also carry sector-level implications. Coastal GasLink traverses Indigenous territories where Indigenous partnership and benefits agreements were central to Phase 1 progress; any expansion will be scrutinized under the same social license lens. Carbon intensity metrics and downstream methane-management commitments will be factored into offtake negotiations, especially with European and Asia buyers increasingly requiring low-carbon LNG or emissions offsets. These non-price factors can be as decisive as headline capacity numbers when determining offtake appetite.

Risk Assessment

Execution risk for pipeline expansions is non-trivial. Historical timelines for large pipeline segments show schedule slippage of 12–24 months is common when regulatory scope, weather windows and Indigenous consultations intersect. Cost risk is correlated: supply-chain constraints for cryogenic modules and specialized rotating equipment, along with steel and labour inflation since 2021, create a non-linear escalation risk profile. Sponsors and lenders will need robust contingency buffers and demonstrable mitigation strategies for these variables.

Market risk should not be understated. Global gas prices and Asian demand growth will remain pivotal to commercial sanctioning. If spot LNG prices or Asian demand growth underperform forecasts used in sanction models, sponsors may delay investment or seek alternative financing structures that shift more volume and price risk to offtakers. Conversely, a sustained premium in Asian JKM or TTF-linked contracts could accelerate sanctioning if counterparties commit long-term volumes.

Regulatory and reputational risks are additionally salient. Coastal GasLink’s existing agreements and social license from Phase 1 offer an experience base, but each incremental footprint invites renewed scrutiny. Any delays in permitting or legal challenges could materially affect project economics. Lenders and insurers will price these risks in, potentially increasing the cost of capital for Phase 2 relative to Phase 1.

Fazen Capital Perspective

Our view at Fazen Capital is that the March 25, 2026 agreements represent a deliberate de-risking step rather than an immediate project sanction. Sponsors are optimizing the sequencing of commercial arrangements to preserve optionality while market signals firm. The contrarian insight is that early-stage pipeline contracting may increase probabilities of a phased FID (tranche-by-tranche) rather than a single large sanction; this modular approach reduces near-term capital intensity and allows sponsors to capitalize on favourable price windows when they appear.

We also note that the market tends to over-weight headline capacity figures (MTPA) and underweight contractual architecture (firm vs interruptible capacity, take-or-pay structures). For long-duration investors and counterparties, the structure of transport and offtake commitments is a better predictor of cashflow certainty than an announced target capacity alone. Therefore, emphasis should be placed on contract tenor, credit quality of counterparties, and embedded price indexation when evaluating the likelihood of a Phase 2 execution.

Finally, contingency planning matters: given global competition for modular equipment and skilled labour, sponsors who secure long-lead items early and lock in EPC capacity may reduce schedule and cost risk materially. That is the strategic rationale behind the commercial arrangements described on March 25, and it informs our expectation that incremental increases to Canadian export capacity will be staged and contingent rather than immediate and large-scale.

FAQ

Q: What is the likely size of a Coastal GasLink Phase 2 addition?

A: Public materials do not specify a fixed MTPA for Phase 2 in the March 25 announcement. Industry precedent suggests sponsors often plan Phase 2 increments in units comparable to Phase 1 trains (e.g., 6–8 MTPA per train), but final sizing will depend on offtake commitments and engineering studies. Historical benchmark: LNG Canada Phase 1 equals 14 MTPA across two trains (LNG Canada disclosures).

Q: How quickly could a second phase reach FID and operations?

A: Typical timelines from commercial arrangements and permitting to FID for large LNG expansions range from 18 to 48 months, followed by 36–60 months to first gas depending on modularization and siting. Key determinants are offtake certainty, financing, and procurement lead times for long-lead equipment.

Bottom Line

TC Energy’s March 25, 2026 deals advance the process for a Coastal GasLink second phase but do not equate to a final sanction; the move reduces near-term execution risk while preserving sponsor optionality. Monitor contract structures and offtake commitments as the primary indicators of probability to FID.

Disclaimer: This article is for informational purposes only and does not constitute investment advice.