Stranded gas, strangled industry

While the current decline in global energy prices would benefit most manufacturing economies, it poses a serious challenge for Pakistan’s export industry.

Over the past few weeks, Brent crude has dropped from ~$75 to ~$65 per barrel, expected to decline even further. As global energy prices fall, regional competitors are gaining access to gas at much lower rates—between $5–7/MMBtu. In contrast, gas for captive power generation in Pakistan is Rs. 4,291/MMBtu ($15.38), including the misplaced levy of Rs. 791/MMBtu. This puts Pakistan’s exporters at a severe disadvantage.

Countries like Bangladesh, where—per an ADB survey—80% of the industry runs on gas-based captive power, will benefit greatly from cheaper gas prices. Similarly, industries in India, China, Bangladesh and Vietnam are paying just 5–9 cents/kWh for electricity, while Pakistani industrial consumers face 11–13 cents/kWh from the grid.

For an energy-intensive and low-margin sector like textiles, this energy cost differential makes it extremely difficult to compete internationally.

China’s recent imposition of a 34% tariff on US LNG, effectively pricing American cargoes out of the Chinese market—will significantly alter global LNG trade flows. With landed costs rising to $9.75–$12.50 per MMBtu—compared to Qatar’s $7–$9 and even cheaper Russian pipeline gas—US LNG becomes commercially unviable for Chinese buyers. As a result, cargoes are being rerouted to Europe, where the sudden supply influx has already triggered a 7.5% drop in TTF prices.

This shift tightens the US–EU LNG arbitrage window, strains regasification infrastructure, and underscores how geopolitical tariffs can rapidly reshape market dynamics. The move also reinforces China’s long-term strategy to diversify supply through stable, lower-cost alternatives like Qatar and Russia, while minimizing exposure to volatile spot markets.

A sustained decline in Brent crude prices towards $50 per barrel could create significant headwinds for the U.S. liquefied natural gas (LNG) industry, which operates on a pricing structure based on Henry Hub gas prices plus liquefaction and shipping costs. This model becomes less competitive when oil-indexed LNG—especially from low-cost producers like Qatar—becomes more attractive in a low-Brent environment.

The global LNG market is poised for significant structural change by 2030, with approximately 170 MTPA of new liquefaction capacity expected to come online, led by the U.S. and Qatar, with additional volumes from Russia and Canada. Concurrently, over 65 MTPA of long-term contracts are set to expire, and 200–250 MTPA of LNG—more than half of today’s global trade—will need to be re-marketed or re-contracted by 2030.

Given these factors, LNG prices are expected to further decline in coming months and sustain at low levels.

Meanwhile, Pakistan’s LNG market is dominated by state-owned enterprises which hold long-term Sale and Purchase Agreements (SPAs) under take-or-pay terms. These entities also control import terminals and pipeline infrastructure, creating high entry barriers for private sector participation.

Pakistan currently imports 7.5 million tonnes per annum (MTPA), or approximately 1,000 MMCFD, through long-term LNG contracts. SNGPL is the primary off-taker for PSO’s contracts, while K-Electric has taken over PLL’s ENI contract. The main contracts are:

Table 1. Pakistan Long-Term RLNG Contracts

Contract	% of Brent	End Date	Million mt/year
PSO-QG	13.37	Jan-31	3.75
PSO-QP	10.2	Dec-32	3
PLL-ENI	12.14	Nov-23	0.75

The RLNG sector faces persistent challenges due to poor demand forecasting, lack of downstream take-or-pay commitments, and an absence of a competitive gas market. These structural gaps have led to growing mismatches between supply and demand. Currently, SNGPL is dealing with surplus RLNG volumes equivalent to 18 unutilized LNG cargoes annually—projected to exceed 40 cargoes as gas demand for captive power generation, the largest off-taker of RLNG after the power sector, is being destroyed through prohibitive pricing to increase utilization of the national grid.

LNG was envisaged to replace high-speed diesel (HSD) and furnace oil (FO) in power generation (FGE 2015), with government-owned RLNG power plants as the primary off-takers. Over time, however, the power sector has significantly reduced its reliance on RLNG, opting instead for cheaper alternatives such as coal, nuclear, hydro, and solar. Moreover, RLNG demand is inherently volatile—affected by seasonal variations, transmission constraints, plant availability, and shifting merit order priorities.

The four major RLNG-based power plants—Bhikki, Balloki, Haveli Bahadur Shah, and Trimmu—initially operated under 66% take-or-pay clauses in their Power Purchase Agreements (PPA) and Gas Sale Agreements (GSA). These terms guaranteed a minimum payment to SNGPL, ensuring revenue even if full gas volumes were not used. In 2021, the Economic Coordination Committee (ECC) waived the 66% requirement, allowing monthly dispatch flexibility (0–100% capacity) based on demand. This was partially reinstated in 2023, with a minimum 33% take-or-pay threshold introduced for financial assurance. However, these revisions were never formally integrated into the contracts, leading to ongoing billing disputes between plant operators and SNGPL.

These RLNG power plants remain underutilized due to high generation costs—around Rs. 26 per kWh—with current offtake down to 286 MMCFD, well below contracted volumes. As a result, SNGPL is left managing stranded RLNG volumes, while incurring rising financial liabilities. To absorb surplus gas, RLNG is diverted to low-revenue domestic consumers at a subsidy of approximately $12.19/MMBtu. This is a key driver of the gas sector’s circular debt, which now exceeds Rs. 2.7 trillion (IMF, 2024).

Compounding the issue is the ongoing decline in indigenous gas production, with major fields like Sui and Qadirpur reduced by a combined 200 MMCFD. To accommodate surplus RLNG under take-or-pay constraints, indigenous gas production is being curtailed—disrupting merit order dispatch and increasing electricity costs via fuel cost adjustments (FCA). The structural oversupply of RLNG is projected to persist well beyond 2024.

In this context, phasing out captive power plant consumption through prohibitive pricing, including the ill-conceived and mis-calculated grid transition levy, will exacerbate the imbalance. Captive users currently account for roughly 20% of RLNG offtake within the Sui network. Removing this demand will intensify surplus volumes, trigger take-or-pay penalties, increase unaccounted-for gas (UFG), and create operational bottlenecks. These penalties are passed on to end-consumers under existing policies, further inflating gas tariffs and undermining affordability.

The financial burden is not limited to SNGPL. As surplus grows, storage constraints and high pipeline pressure (line-pack) create a risk of forced indigenous gas curtailment. This threatens the financial viability of local Exploration and Production (E&P) companies and risks stranding recoverable reserves.

If elimination of gas-fired captive power generation proceeds as planned, the RLNG surplus could exceed 40 LNG cargoes annually—creating a structural oversupply that jeopardizes the entire gas value chain (Figure 1). In such a scenario, the financial sustainability of state-owned entities in the petroleum division may come under serious threat.

Figure 1. Projected RLNG Surplus in SNGPL Network from Crowding Out of Captive

This is already reflected in the Sui companies’ demand to raise consumer gas prices. In their revenue requirements for FY26, SNGPL has proposed increasing the prescribed price of natural gas from approximately Rs. 1,750/MMBtu to Rs. 2,485/MMBtu, citing the RLNG diversion cost of over Rs. 300 billion as a key driver. Similarly, SSGC has requested a steep hike to Rs. 4,137/MMBtu.

These losses are occurring while domestic gas demand is being deliberately curtailed—particularly from industrial and captive power consumers—creating further inefficiencies. At the same time, policy decisions have also curtailed 200-400 MMCFD of low-cost indigenous gas priced at less than $4/MMBtu, undermining local exploration and production (E&P) activity and deepening reliance on expensive imported LNG.

The ridiculousness of the situation can be gauged by that we are importing LNG at $10-12/MMBtu, while curtailing domestic production that costs less than $4/MMBtu in an extremely tight balance of payments situation.

In the years ahead, the global LNG market is expected to loosen due to upcoming liquefaction capacity expansions in the U.S. and Qatar. By then, Pakistan will be obligated to take delivery of previously deferred long-term cargoes—likely at prices well above prevailing market rates. Currently, the government is selling those same cargoes below market value, locking in a loss both now and in the future. This approach reflects poor sequencing and undermines energy affordability and fiscal stability.

Pakistan’s long-term LNG contracts offer pricing stability and volume security, protecting buyers and sellers from market volatility. However, clauses like “Net Proceeds” in Qatar Gas (QG) and Qatar Petroleum (QP) contracts allow the seller to resell cargoes and retain any excess earnings if the buyer does not take delivery. While contractually permissible, this mechanism heavily favours the seller in oversupply scenarios. There is a strong case for Pakistan State Oil (PSO) to review and renegotiate such clauses in future SPAs to ensure a more equitable allocation of gains and risks.

Figure 2. Pakistan LNG Contracts vs. International Spot Market

Moreover, this has enabled foreign companies to capture arbitrage profits of over $300 million—approximately $100 million from 5 Qatar cargoes and $200+ million from 11 ENI cargoes. This was driven by high TTF prices in a tight global spot market, as Europe competes with Asia this year (Figure 2). For instance, selling cheap ENI cargoes in a tight global LNG market results in about $19 million arbitrage, TTF went $17+ per MMBtu in February 2025.

It is concerning that Pakistan deferred 5 cargoes in a tight global LNG market when next year’s spot LNG prices are expected to be cheaper than long-term contracts, as the US and Qatari liquefaction waves hit the market. This year’s term contracts were already much cheaper, before the brewing U.S.-China trade was further weighed down on energy markets.

At a Brent crude price of $60 per barrel, LNG import prices under existing SPAs are approximately $6.12/MMBtu (Qatar Petroleum, 10.2% slope), $8.02/MMBtu (Qatar Gas, 13.37% slope), and $7.28/MMBtu (ENI, 12.14% slope).

At a time when global Brent and LNG prices are in decline—and Pakistan remains locked into long-term LNG contracts—the government is compounding policy errors by pricing gas-fired captive power generation out of the market and undermining industrial competitiveness.

It is one of many self-inflicted wounds. Instead of leveraging long-term LNG contracts Pakistan is wasting them. At $60 Brent, delivered LNG under current SPAs is priced between $6 and $8/MMBtu. These volumes should be directed to industries to enable self-generation of competitive power, not offloaded at a loss or used to subsidize low-efficiency consumption. The decision to penalize industrial captive use during a window of favourable global pricing reflects a serious misalignment between procurement strategy and downstream policy.

The government must urgently revisit its gas pricing framework. RLNG should be supplied to industrial captive cogeneration consumers at its full actual cost—excluding the burden of cross-subsidies to other sectors, extraneous surcharges like the grid transition levy, and inflated UFG assumptions. Doing so would restore a rational basis for industrial input pricing, improve power system efficiency, and reduce fiscal stress on the gas chain.

Longer term, Pakistan must accelerate liberalization of the LNG and downstream gas markets. This includes immediate implementation of transparent Third Party Access (TPA) protocols that allow private buyers and sellers to engage in B2B arrangements and utilize pipeline capacity and regasification terminals on a non-discriminatory basis. Continued reliance on opaque G2G deals through Pakistan LNG Limited (PLL)—such as recent engagements with SOCAR—only entrenches inefficiencies and exposes the system to non-market risks, including rent-seeking behaviour.

A liberalized market structure, grounded in competitive procurement and infrastructure access, will drive investment, improve price discovery, and provide a foundation for supply security through diversified sourcing.