Shahid Sattar and Asim Riaz
Pakistan’s energy policies have become a master-class in economic self-sabotage. Designed to force industry off captive generation and onto the national grid, the off-grid levy has failed to deliver its intended transition. Instead, it has accelerated demand destruction as industrial users migrate to cheaper alternatives, created a structural surplus of RLNG that has pushed the gas sector further into fiscal chaos, and penalized export-oriented industries that invested in clean, high-efficiency cogeneration to secure lower-emission, reliable, and affordable energy.
Against expectations of 1,500 to 2,000 MW, only about 600 to 800 MW of captive load has shifted to the national grid, following the levy on captive gas in March 2025. The projected benefit of reducing the capacity cost burden by nearly Rs. 0.75 per kWh for all consumers did not materialize, as the modest captive shift was offset by massive solarization. Consequently, system demand remained stagnant in FY25Q4 and fell 10 percent below benchmark in July 2025. Massive solarization has reshaped power sector demand, with 17 GW imported in 2024 displacing around 25 TWh annually, and 13 GW imported to date in 2025 reducing demand by a further 19 TWh. The combined effect of net-metered, behind-the-meter, and off-grid solar PV has suppressed power demand.
In parallel, captive gas consumption collapsed by nearly 90 percent year-on-year, worsening the RLNG surplus by 300 to 350 MMCFD. This surplus, contracted at USD 12 per MMBtu under take- or-pay LNG SPAs, has been diverted to households at USD 4 per MMBtu. The remaining USD 8 per MMBtu gap, amounting to USD 1.1 billion annually, must now be financed by industrial consumers, taxpayers, or absorbed into circular debt: a textbook case of trying to rob Peter to pay Paul in a way that further eroded confidence in the gas market.
Surplus RLNG in the system has also forced curtailment of around 270 MMCFD of indigenous gas production, with OGDCL estimating losses at USD 378 million per annum. The move also disincentivizes exploration and production activities, creating additional long-term pressure on domestic gas supply. The outcome is a liquidity crunch across the gas chain, an increasing depletion rate of 7–9 percent in indigenous supply within the Sui intake, and a lock-in of Pakistan into higher long-run reliance on imported fuels.
As if the irrationality of the captive gas levy weren’t damaging enough, the government doubled down with an equally ill-conceived policy on furnace oil. A petroleum development levy of approximately Rs. 80,000 per tonne was slapped onto domestic furnace oil, pushing its price from about Rs. 130,000 to over Rs. 200,000 per tonne, collapsing local demand almost overnight.
Industries that once relied on FO as a backup energy source were priced out, the government failed to collect any revenue, and refiners were left with no choice but to export it at distressed prices around Rs. 80,000 per tonne, absorbing losses on each shipment while killing the goose, the export industry, that lays the golden eggs. Rather than capturing value, the policy eroded energy security, weakened industrial competitiveness, and turned a viable fuel stream into a stranded liability.
The Captive Power Transition Levy has failed to deliver the International Monetary Fund’s stated objectives. The record shows the IMF’s premise was flawed. Cogeneration (CHP) captive power plants extract the highest value from scarce gas molecules and should have been preserved as priority demand. Using premium pipeline-quality gas only for low-grade steam and process heat is a poor allocation of a scarce resource, when cheaper alternatives are available for process heat (i.e., biomass: rice/wheat straw/kutle, low-GCV coal, wood chips/logs, and used clothes etc.). This can also lead to the misdeclaration of process gas, which could otherwise be utilized in the captive power plant, given that the captive tariff is nearly double the process tariff.
Enacted as the Off the Grid (Captive Power Plants) Levy Act, 2025, the CPL imposes over and above Ogra-notified gas prices, a levy on all CPP gas consumption, set by the gap between Nepra’s B3 industrial tariff and each plant’s self-generation cost at Ogra’s tariff. The premium steps up to 5 percent immediately, 10 percent by July 2025, 15 percent by February 2026, and 20 percent by August 2026. Collections by SNGPL/SSGC are remitted to the federal government and used to reduce electricity tariffs.
The levy’s design keeps the spark spread of captive power plants at grid parity or above it for B3 industrial consumers, which distorts the price signal, drives demand destruction, and limits potential RLNG offtake. However, the grid absorption did not materialize; demand destruction did. Captive offtake collapsed, a structural RLNG surplus emerged, cargoes were deferred, and CPPA-G purchases did not rise to compensate.
Nepra’s Q4 FY2024-25 Quarterly Tariff Adjustment shaved PKR 53.393 billion from non-fuel charges, led by capacity-charge relief. The biggest drivers were the Neelum Jhelum outage, about PKR 18 billion, and IPP contract changes, about PKR 17 billion, with smaller gains from true-up reversals and financing tweaks, while captive-to-grid shifting contributed only around PKR 13 billion for the quarter. Annualized, that captive shift is PKR ~52 billion, trivial next to the gas-chain loss from diverting surplus RLNG to households, about PKR ~560 billion per year, approx. USD 2 billion.
Far from achieving its stated objectives of boosting grid demand and reallocating scarce gas to the most efficient generators, the Captive Power Transition Levy enacted under the Off the Grid (Captive Power Plants) Levy Act, 2025 has destabilized market balance and fiscal discipline. The IMF-supported design prices all CPP gas at the industrial-grid equivalent with a rising premium to 20 percent by August 2026, and earmarks monthly levy proceeds to the grid to fund tariff relief, alongside cost-recovery gas and power tariffs and a gas circular debt management plan, measures explicitly intended to shift captive load to the grid and preserve scarce gas resources for higher-efficiency plants.
In practice, the levy weakened industrial competitiveness, eroded confidence in price signals, and failed to allocate gas to its highest-value uses. Captive offtake collapsed, while LNG cargoes were offloaded at distressed prices, diverted to residential consumers at below-cost tariffs, or triggered curtailment of indigenous fields, undermining fiscal efficiency and security of supply. Despite this, policy continuity has hinged on hopes of negotiating a substantial reduction in long-term LNG volumes contracted with Qatar. Given airtight contracts and little supplier incentive to cut volumes, this is highly unlikely. The realistic path is domestic absorption of contracted RLNG.
A one-size-fits-all approach to captive users contradicts the Cabinet Committee on Energy (CCoE) framework set out in Case No. CCE-14/4/2021 (21 January 2021) and has derailed the policy. The CCoE had adopted a tiered pathway rather than a blanket treatment: disconnect single- cycle captive plants already connected to the grid, require DISCOs to certify they can serve sanctioned load and fast-track load enhancement before any cut-off, and keep gas flowing to non-connected units until grid links were arranged. For cogeneration, the policy directive was verification, not disconnection.
NEECA translated this into measurable rules on 18 August 2020. Captive units were required to achieve at least 45 percent net electrical efficiency up to 50 MW, and 50 percent above 50 MW. Cogeneration had to meet a minimum of 60 percent combined electrical and thermal efficiency, verified through independent audits with time-bound upgrades where needed. Yet none of this was implemented, reinforcing the perception that NEECA operates as another rubber- stamp regulator, appearing busy while doing nothing.
The result is a policy that penalizes compliant CHP. It challenges CBAM readiness and environmental goals. It strands efficiency investments and triggers a rush to import about 134 standalone boilers. These boilers waste scarce gas, whereas cogeneration is far more efficient than both boilers and the national grid, and also saves foreign exchange. This shift displaces CHP’s 60–90 percent total fuel utilization with roughly 41 percent end-use efficiency. Once electricity is routed through the grid and boilers provide process heat, emissions and costs rise. Affordability and reliability decline. Industrial competitiveness, energy security, and environmental security are all undermined.
Combined Heat and Power (CHP), or cogeneration, captive power plants simultaneously generate electricity and useful heat from the same fuel, achieving efficiencies of up to 90 percent, compared to around 36–55 percent in the centralized power generation IPPs (around 45 percent in conventional setups). Cogeneration CHPs thus reduce overall energy use for manufacturing, lower costs and emissions, and enhance competitiveness, aligning with Pakistan’s energy security and export goals. It also provides flexible backup to intermittent renewables like solar and wind, improving grid stability and resilience, supports compliance with global climate targets and regulations like CBAM, and reduces reliance on costly imports.
This makes it an international gold standard in terms of sustainable, efficient, and strategic solutions for energy-intensive industries. Moreover, with global LNG prices expected to fall in the coming months and years, regional competitors will secure gas/RLNG at these cheap rates. In contrast, Pakistani exporters are charged USD 13–16/MMBtu (Rs. 3,500/MMBtu + levy) for inefficiencies of the power grid by linking prices to its tariffs, placing them at a significant competitive disadvantage in export markets.
SNGPL’s own numbers show operating costs rising while profits and returns jump, which is why KPIs must pivot to throughput, UFG reduction, collections, and reliability, and why tariffs must stop socializing inefficiency through the TPA framework. SNGPL’s filings make the incentive mismatch tangible: distribution throughput has collapsed while the tariff’s fixed leg ballooned. Average volumes fell from ~1,230 MMCFD (FY2020/21) to ~693 MMCFD (FY2025/26, petition), yet the distribution capacity charge rose from ~Rs. 92/MCF (FY2019/20) to ~Rs. 281.52/MCF (FY2025/26), a jump driven mainly by a shrinking denominator rather than new “used and useful” capacity. Compounding this, SNGPL’s profit and returns increased despite declining volumes; its FY2023/24 profit rose by ~Rs. 16.5 billion, showing how a return-on-asset posture combined with throughput-backstopped “capacity” pricing rewards under-utilization rather than efficiency.
Another aspect of the levy was to free up gas/RLNG resources for diversion from supposedly inefficient captive power plants to purportedly high-efficiency government power plants. However, the government-owned RLNG plants, with a specific cost of ~Rs. 19.5/kWh, rank well below imported coal plants like Port Qasim with a specific cost of Rs. 11.8/kWh. They are highly unlikely to get dispatch without a significant boost in grid demand, which has been stagnant for the last several months, with further downward pressure from the proliferation of captive solar.
This would institute, first, defining captive CHP as “an energy service that co-produces electricity and process heat from a single molecule, with eligibility anchored in measured Energy Utilization Rate and verified heat recovery.” As a check, there should be mandatory independent efficiency audits every five (5) years for eligibility, including through accredited verifiers, calibrated fuel and heat meters, a heat and mass balance, and documentary evidence of operational availability. A minimum Energy Utilization Rate may be set at 60 percent, consistent with best practice, as well as corrective action plans for non-compliance, including time-bound remediation and revalidation.
There is around 200 MMCFD of immediate RLNG demand for captive CHP in the textile sector alone, which can be mobilized without subsidy. No other sector apart from industrial captive CHP users is positioned to absorb these volumes without a government subsidy. Gas may be offered to these users at the full RLNG cost-of-service, but without any additional surcharges and with actual UFG. This reflects marginal and import-parity cost, strengthens price signals, curbs cross-subsidy leakage, and facilitates absorption of LNG volumes in industry rather than diversion to subsidized segments that exacerbate circular debt. The adjustment will enable offtake of around 200 MMCFD of RLNG, equivalent to USD 936 million annually at a price of USD 12 per MMBtu, and reduce RLNG diversion costs currently being borne by the government by USD 585 million.
The government ignored repeated warnings and pressed ahead with the irrational levy; months later, the results are plain for all to see: no improvement in grid dynamics, no reduction in power tariffs, no improvement in industry or exports, and a worsening crisis in the gas sector. The experiment has run its course; it is time to fix the damage. Reclassifying high-efficiency CHP to the industrial process category is the only realistic solution to absorb surplus RLNG, support exports, and restore coherence to energy policy.
