Why Pakistan Should Not Underwrite a US$4.4 Billion LNG Terminal and Pipeline
1. Pakistan’s gas challenge is no longer simply a shortage of LNG import infrastructure. It is a mismatch between rigid contracted supply, uncertain physical deliverability and shrinking commercially viable demand. The proposed US$4.4 billion LNG terminal, storage facility and 1.2 BCFD pipeline must therefore be assessed against demonstrated market requirements, not historical assumptions of continuously rising gas consumption. Before any public commitment, the central questions are who will purchase the gas, at what delivered price, and who will bear the financial risk of unused capacity.
2. The underlying demand outlook raises substantial concerns. SNGPL’s May 2026 baseline projected approximately 368 surplus LNG cargo-equivalents during 2027–2031, reflecting a significant mismatch between projected supply availability and downstream consumption. Although sensitive to future demand, pricing and contractual adjustments, the forecast cannot be disregarded. Pakistan has already deferred, diverted and cancelled LNG cargoes and curtailed indigenous production to accommodate imported gas. Additional infrastructure should not be justified without first reconciling existing commitments and demonstrating incremental, commercially viable demand.
3. The 2026 Hormuz disruption does not invalidate this assessment. Pakistan experienced a shortage of physically deliverable LNG while remaining exposed to substantial projected contractual surpluses in subsequent years. The disruption demonstrates the importance of supplier diversification, shipping-route security, strategic inventory and contractual optionality. It does not independently establish the need for another 1,100 km transmission pipeline. A new terminal at Port Qasim would not eliminate Hormuz exposure for LNG sourced from Qatar; supply security would depend on cargo origin, delivery routes and available inventories.
4. The pipeline investment requires separate economic justification. The proposed 560,000 m³ LNG storage system represents approximately 11.9 BCF of gas-equivalent inventory. The proposed storage facility could support seasonal inventory management and short-term supply security, subject to procurement economics, available storage capacity and operating constraints. Its commercial value should be assessed against actual seasonal price differentials, inventory carrying costs and alternative flexibility arrangements. One full inventory could theoretically support approximately 397 MMCFD for 30 days or 1,190 MMCFD for ten days, subject to usable inventory and regasification capacity. Storage capacity alone does not establish the need for the US$2.7 billion, 1,100 km pipeline with 1.2 BCFD design capacity. That investment should be justified by independently verified peak and sustained transportation requirements, demonstrated hydraulic constraints in existing transmission capacity, and additional firm gas supply backed by bankable transportation commitments, and should be tested against potentially lower-cost alternatives, including network optimisation, compression upgrades and targeted reinforcement.
5. The proposed tariffs raise additional concerns about delivered-gas competitiveness. Reported initial charges of US$4.93/MMBtu for terminal and storage services and US$1.91/MMBtu for transmission total US$6.84/MMBtu where both services apply. At an illustrative LNG commodity price of US$10/MMBtu, the resulting subtotal is US$16.84/MMBtu before other applicable downstream costs. Although the proposed infrastructure charges decline after the first decade, their initial impact is material. Seasonal price arbitrage must also be evaluated against storage costs, inventory financing, boil-off management and actual price spreads. Additional infrastructure costs could further discourage industrial consumption in a market already experiencing demand erosion.
6. Strategic storage is the most defensible component of the proposal, but its economic value must be assessed independently. The Hormuz disruption demonstrated the importance of holding physical inventory ahead of seasonal peaks and geopolitical interruptions. Approximately 11.9 BCF could provide a useful short-duration buffer, although actual deliverability would depend on usable inventory and regasification capability. Storage also offers potential commercial value through seasonal procurement, inventory optimisation and flexibility in cargo scheduling. However, the case for strategic inventory does not automatically justify an integrated US$4.4 billion investment. Storage, regasification and transmission should undergo separate least-cost assessments, including alternatives involving existing terminals and pipeline capacity.
7. Pakistan’s LNG demand profile has changed materially. Coal, nuclear, hydropower and rapidly expanding distributed solar have reduced the continuous baseload requirement originally envisaged for RLNG-fired power generation. LNG increasingly serves winter demand, evening ramps, periods of low hydrology, system balancing and emergencies. The corresponding supply portfolio should therefore combine a commercially justified contracted core with seasonal flexibility, standby arrangements, cargo diversion and resale rights, and geographically diversified supply. The economic value of flexibility and reliability must take precedence over additional nominal import capacity.
8. Pakistan’s LNG demand exhibits distinct winter and summer peaks, whose magnitude is materially influenced by administered pricing, cross-subsidies and gas allocation policies. The winter peak, particularly during December–February, is driven by residential and commercial space and water heating, with gas supplied at tariffs substantially below its marginal replacement cost, particularly that of imported RLNG. This price distortion weakens incentives for conservation, energy efficiency and substitution towards solar water heating, heat pumps and other cost-effective alternatives, resulting in residential consumption that may exceed economically justified levels. Preferential allocation of lower-cost indigenous gas to households shifts the marginal supply requirement towards RLNG for power generation and industry, while the associated subsidies and diversion costs are transferred through industrial cross-subsidies, fiscal support and gas utility revenue requirements. The summer peak is driven by electricity cooling demand, although hydropower, solar, coal and nuclear generation limit the corresponding requirement for RLNG-fired power. Consequently, observed seasonal gas demand should not automatically be treated as commercially sustainable demand for new infrastructure, particularly where consumption depends on below-cost tariffs and administrative allocation. Cost-reflective pricing, complemented by targeted protection for vulnerable households, would moderate price-sensitive residential heating demand and encourage more efficient energy choices, although essential consumption and residual seasonal requirements would remain. Committing US$4.4 billion to additional LNG infrastructure carrying initial charges of US$6.84/MMBtu before addressing these distortions risks embedding higher costs into an already price-sensitive market. The appropriate approach is to correct residential price signals, establish the economically sustainable demand profile, optimise existing LNG contracts and infrastructure, and assess strategic storage and additional transmission capacity against independently demonstrated residual requirements.
9. A similar distortion is emerging in the electricity market. Rapid distributed solar and net metering reduce daytime grid purchases, but a large share of generation, transmission, distribution and capacity costs remains fixed. Where net-metered consumers offset retail-priced imports with exported solar energy while continuing to rely on the grid during non-solar hours, part of those fixed costs can be shifted onto consumers with lower ability to self-generate. At the same time, the expansion of the protected-consumer base increases the amount of electricity sold at subsidised tariffs and enlarges the cross-subsidy requirement borne by industrial, commercial and other paying consumers. This creates a reinforcing volume-price distortion: high tariffs encourage solarisation and reduced grid offtake; lower sales leave fixed costs to be recovered from fewer units; tariffs and cross-subsidy burdens rise further; and more creditworthy consumers reduce grid dependence. The result is not simply lower electricity demand, but a progressively weaker commercial demand base for both the power and gas systems. Before using administered electricity or gas demand as justification for new infrastructure, Pakistan should correct tariff distortions, target subsidies transparently, redesign net-metering compensation around actual system value, and establish the level of demand that remains commercially sustainable under cost-reflective pricing.
10. Industrial demand must be addressed before new infrastructure is built around assumptions of future consumption. High gas tariffs, cross-subsidies, captive-power restrictions and transition levies have encouraged industrial consumers to adopt solar, batteries, alternative fuels or reduce production. Reduced captive gas consumption should not be equated with a successful grid transition without evidence that corresponding productive energy demand has migrated to reliable and economically efficient alternatives. High-efficiency combined heat and power facilities, particularly those integrated with renewable energy and useful process-heat recovery, should not be treated as equivalent to inefficient electricity-only generation. Policies that destroy commercially viable industrial gas demand while simultaneously encouraging major new infrastructure investments are economically inconsistent.
11. Gas-market reform should precede further large-scale infrastructure commitments. Pakistan should optimise its LNG portfolio, separate the transportation and gas-sales functions of SNGPL and SSGCL, supported by neutral network operation and enforceable third-party access, permit competitive private LNG imports and direct upstream sales, and publish transparent transportation charges and available network capacity. Existing transmission systems should be assessed for hydraulic optimisation, compression upgrades and targeted reinforcement before constructing another long-distance pipeline. Investment should respond to demonstrated network constraints and bankable demand rather than preserve the existing vertically integrated market structure.
12. The principal safeguard is transparent allocation of commercial and financial risks. A genuinely merchant project may proceed at investors’ own commercial risk, subject to applicable regulatory, technical and environmental approvals. However, any sovereign guarantee, mandatory utility commitment or recovery of unused capacity from regulated consumers must be supported by independently demonstrated public benefits and transparent risk allocation. Long-term tolling, ship-or-pay, take-or-pay and minimum-revenue arrangements must be examined for their ultimate financial incidence, including any transfer of private commercial risk to public utilities, taxpayers or gas consumers. Private investment should be facilitated, but public financial protection against commercial underutilisation should not be provided without a defensible public-interest justification.
CONCLUSION
Pakistan can be structurally long LNG and seasonally short of deliverable gas at the same time. This requires a more flexible supply portfolio, diversified import routes, strategic storage and effective market reform, not an automatic commitment to another terminal and 1.2 BCFD pipeline.
The appropriate sequence is:
Optimise contracts → Liberalise the gas market → Restore productive demand → Establish genuine network constraints → Evaluate strategic storage → Invest in additional infrastructure only where economically justified.
Pakistan needs a functioning, competitive gas market, not another layer of infrastructure capacity searching for consumers.
