Pakistan’s Power Paradox: Paying For Plenty, Living With Shortage |
In a recent post on X, Atif Mian argued that Pakistan could, by following China’s path and rapidly shifting to electric motorbikes and rickshaws, effectively drive petrol costs down to the equivalent of Rs 30 per litre. The claim, striking in its simplicity, has gained traction in a country weary of high fuel prices and repeated external crises.
But the proposition rests on a comparison that collapses under scrutiny. China’s transition to electric mobility was not a response to fuel prices alone; it was the outcome of a deeply industrialised ecosystem—domestic battery manufacturing, integrated EV supply chains, reliable and scalable power infrastructure, and dense urban charging and battery-swapping networks. Pakistan, by contrast, is struggling to supply electricity reliably even to its existing demand base, with persistent outages, high system losses, and severe financial stress across the power chain.
The issue is not whether petrol is expensive or whether electric alternatives exist. It is that Pakistan’s energy system is structurally incapable of delivering affordable, reliable power at scale. Without fixing that system—its transmission bottlenecks, distribution failures, and unsustainable financial architecture—shifting transport from petrol to electricity risks simply relocating the crisis rather than resolving it.
Pakistan’s power crisis is still being described as a shortage of electricity. It is not. It is the failure of a system that cannot convert installed capacity into dependable, deliverable power at the hour it is needed—and cannot afford the capacity it has already built, nor efficiently move or collect payment for it.
The stress visible in April 2026 reflects this contradiction with unusual clarity. Across much of Punjab and Khyber Pakhtunkhwa, outages have averaged six to eight hours a day, extending far longer on weaker feeders. At the system level, the evening deficit has typically ranged between 2,500 and 4,000 MW.
The immediate causes are straightforward: RLNG-based generation, which in normal conditions can contribute 4,000–6,000 MW during peak periods, has at times fallen below 1,000 MW due to supply and pricing constraints. Hydropower, which can exceed 10,000 MW in high-flow months, has been running several thousand megawatts lower due to seasonal water availability and reservoir management decisions. These shocks are real—but they become crises only because of how the system is structured.
Seasonality is a critical but underappreciated fault line. Hydropower—one of Pakistan’s largest and cheapest energy sources—fluctuates sharply across the year because it is fundamentally a flow-dependent system with storage constraints. In peak summer months, when snowmelt and monsoon inflows are high, hydro can contribute roughly a quarter or more of total generation.
Cheap coal and renewable generation in the south cannot be fully dispatched, while the north relies on more expensive or fuel-constrained plants—or experiences load-shedding when those plants are unavailable
Cheap coal and renewable generation in the south cannot be fully dispatched, while the north relies on more expensive or fuel-constrained plants—or experiences load-shedding when those plants are unavailable
In winter, output can fall by more than half, removing several thousand megawatts of low-cost supply from the system. This seasonal decline coincides with rising gas demand for heating and tighter LNG availability, forcing a structural shift toward more expensive and imported fuels. The result is not a cyclical inconvenience but a predictable annual tightening of the entire energy balance that the system has never designed around through storage, diversification, or demand shaping.
On paper, Pakistan has roughly 45,000–46,000 MW of installed capacity. In practice, that number is misleading because it reflects engineering nameplate capacity rather than economically and physically dispatchable power.
The more relevant question is how much electricity the system actually produces—and from which sources.
Thermal generation remains dominant, but its composition has shifted significantly. Gas and RLNG together now contribute roughly a fifth of total electricity in many months, down from higher levels earlier in the decade, reflecting both fuel constraints and declining utilisation. Coal—split between imported coal and Thar lignite—has risen to roughly a quarter to nearly a third of generation, becoming the system’s primary marginal and increasingly baseload replacement fuel. This shift is critical: Pakistan has moved from gas-flexibility to coal-inflexibility, replacing a volatile but responsive fuel with a cheaper but geographically and operationally rigid one.
Nuclear contributes around 15–18%, providing a stable baseload, although subject to periodic maintenance and refuelling cycles that can temporarily reduce output. Hydropower contributes roughly 20–25% annually but remains structurally seasonal and hydrology-dependent rather than dispatchable. Wind, solar, and bagasse together provide a modest share of grid electricity, typically in the mid-single digits. However, this understates the real system impact of solar, which reduces grid demand rather than adding measurable generation.
Compared with the previous year, three structural shifts stand out. RLNG-based generation has become significantly more volatile and less reliable as a balancing fuel, reducing system flexibility precisely when variability has increased. Coal has expanded its role as the dominant fallback source of baseload electricity, particularly in the south, increasing geographic concentration of generation. And distributed solar has materially reshaped demand, flattening daytime grid consumption while intensifying evening peak ramps.
These shifts would be manageable in a well-integrated system. In Pakistan’s case, they collide with deep structural weaknesses in transmission, distribution, and governance.
Once fuel constraints, maintenance outages, transmission bottlenecks, and system stability limits are applied, dependable capacity during the critical evening window typically falls into the low-30,000 MW range. Demand in that same window can approach or exceed those levels even outside peak summer. The system therefore operates with minimal reserve margin, meaning any disruption—fuel, water, or transmission—translates immediately into load-shedding.
Yet even as the country struggles to meet peak demand, it is paying for far more capacity than it uses.
Over the past two decades, Pakistan has built much of its generation fleet through long-term contracts with independent power producers. These contracts guarantee fixed capacity payments indexed to plant availability, regardless of whether electricity is generated. This design was intended to solve investment scarcity in a capital-intensive sector, but over time, it has created a rigid fixed-cost structure that is largely insensitive to actual system utilisation.
As capacity expanded rapidly after 2015—particularly in coal, RLNG, and large infrastructure projects—the fixed payment burden rose sharply.
Today, capacity payments form one of the largest components of the entire electricity tariff structure. The system is effectively paying for over 40,000 MW of contracted capacity while utilising significantly less, particularly during off-peak hours and increasingly during daylight due to distributed solar. The gap between contracted capacity and actual dispatch has widened structurally, not cyclically.
This creates a structural double burden. Consumers pay for the electricity they consume, and they also pay for capacity that remains idle.
High-capacity payments inflate tariffs even when fuel costs decline, because fixed obligations dominate marginal pricing. This reduces affordability, suppresses demand, and accelerates the shift toward self-generation through solar and captive systems. As more consumers exit the grid during daylight hours, the fixed cost burden is distributed over a shrinking consumption base, pushing tariffs higher still. The system increasingly exhibits the characteristics of a utility trapped in a slow structural “death spiral,” where rising tariffs accelerate demand erosion.
At the same time, contractual rigidity undermines operational efficiency. The merit-order principle—dispatching the lowest-cost available generation first—is frequently distorted by fixed capacity obligations, fuel constraints, and transmission bottlenecks. Plants are either dispatched sub-optimally or constrained from running even when economically justified, because system liquidity, fuel availability, and grid capacity are not aligned.
Nowhere is the underlying misalignment clearer than in the physical geography of the grid.
Most new generation over the past decade has been built in the south. Coal plants near Thar, imported coal facilities along the coast, nuclear stations, and most wind and solar installations are concentrated in Sindh and Balochistan. In aggregate, well over 15,000 MW of relatively low-cost capacity sits in the southern corridor.
Demand, however, is concentrated in the north.
The principal link between the two systems is the high-voltage direct current transmission line from Matiari to Lahore—a ±660 kilovolt, roughly 900-kilometre HVDC corridor. Its nominal rating is 4,000 MW, defined by converter station capacity and conductor thermal limits under stable operating conditions.
However, that figure is a technical ceiling rather than a guaranteed system flow.
The HVDC system feeds into an alternating current network in Punjab that has its own physical constraints. If downstream transmission lines, transformers, or substations are congested, power injection must be reduced to maintain system stability. Voltage stability, reactive power requirements, inertia constraints, and contingency margins further limit throughput. As a result, actual transfers fluctuate significantly—at times approaching the upper limit, but often operating materially below it when the wider grid cannot absorb additional power safely.
Pakistan does not need a significant new generation in the near term. It needs transmission expansion, distribution reform, and financial restructuring that restores liquidity across the chain
Pakistan does not need a significant new generation in the near term. It needs transmission expansion, distribution reform, and financial restructuring that restores liquidity across the chain
This distinction between nameplate and effective transmission capacity is critical. The bottleneck is not only the HVDC line; it is the entire receiving network.
Against a southern generation base exceeding 15,000 MW, even full utilisation of 4,000 MW would be structurally insufficient. At lower effective utilisation levels, the mismatch becomes severe. Cheap coal and renewable generation in the south cannot be fully dispatched, while the north relies on more expensive or fuel-constrained plants—or experiences load-shedding when those plants are unavailable. The system continues to pay capacity charges for idle plants while failing to deliver electricity from operating ones.
Financial stress reinforces this physical imbalance. Circular debt, now approaching two trillion rupees, reflects a system in which revenues do not cover costs and payments are delayed across the chain. Distribution losses remain high, often in the mid-teens at the system level but significantly higher in certain high-theft or weak-governance feeders. Recovery is uneven across regions and consumer classes. The result is chronic liquidity stress: generators are not paid on time, fuel suppliers tighten credit, and even available capacity cannot always be dispatched because working capital is constrained.
But the most structurally neglected part of the system lies between generation and consumption: the distribution companies.
Pakistan’s DISCOs are the weakest operational link in the entire electricity value chain. They are responsible for billing, recovery, and last-mile delivery, yet they operate with weak governance, underinvestment, and persistent technical and commercial losses. These losses are not marginal inefficiencies; they are a structural drain that feeds directly into circular debt accumulation.
Technically, part of the losses are due to outdated networks, overloaded transformers, and voltage drop over long rural feeders. Commercially, a significant portion arises from theft, meter tampering, and incomplete metering coverage. Institutionally, enforcement is uneven, with politically sensitive areas often exempt from strict recovery action. The result is a fragmented distribution system where performance varies dramatically across regions and feeder categories.
These inefficiencies are central to the persistence of circular debt. Even when generation is efficient, and transmission is available, weak distribution prevents revenue recovery, which then cascades upstream into liquidity shortages that constrain generation itself.
Against this backdrop, the recurring policy prescription of privatising DISCOs is often presented as a structural fix. In theory, private ownership is expected to improve efficiency, reduce losses, and enhance accountability. In practice, however, the constraint is not ownership alone but the scale and nature of required investment.
First, DISCO reform requires massive capital expenditure in network modernisation, transformer upgrades, metering infrastructure, and enforcement systems. These are not marginal upgrades but multi-billion-dollar, multi-year investments across heterogeneous urban and rural systems.
Second, privatisation does not eliminate structural constraints in tariff setting, political interference, or regulatory uncertainty. Without credible cost-reflective tariffs and enforcement autonomy, private operators inherit the same revenue-expenditure mismatch that currently cripples public DISCOs.
Third, the assumption that domestic private capital can absorb these requirements at scale is uncertain. Even large business groups, while financially strong in industrial sectors, are not structured as long-duration regulated utilities with deep infrastructure capital pools. Recent experience in other sectors has shown that ownership transfer alone does not guarantee capital-intensive transformation if underlying risk allocation remains unresolved.
In other words, privatisation may change the operator, but not necessarily the economics of operation.
Fuel allocation adds another layer of distortion. LNG remains critical for flexible generation but is subject to global volatility and contract rigidity. Domestic gas, which could partially offset shortages, is not always prioritised for power due to competing demands from fertiliser and industrial users. The result is a system exposed to external shocks precisely when internal flexibility is most needed.
Solar energy adds a further structural shift. It is highly effective at reducing daytime grid demand but contributes little to evening peak consumption, which typically occurs between 7 pm and midnight. The result is a pronounced “duck curve”: suppressed daytime net load followed by steep ramping requirements after sunset.
Battery storage offers a theoretical solution, but its scale remains constrained by global supply chains and competing demand. Contemporary Amperex Technology Co. Limited, the world’s largest battery manufacturer, ships hundreds of gigawatt-hours annually, yet this capacity is distributed across electric vehicles, consumer electronics, and grid applications globally. Lithium supply remains geographically concentrated, and grid-scale storage at the level required to materially shift multi-gigawatt evening peaks remains capital-intensive and not yet systemically deployed in most developing grids.
The more viable pathway to system stability lies in structural rebalancing. Nuclear power provides a reliable baseload and is already expanding with additional units under development. Pumped hydro storage, particularly in northern Pakistan, offers a scalable and technologically mature mechanism to shift surplus daytime energy into evening peaks. Most critically, transmission expansion and grid modernisation remain the binding constraints. Without a stronger north–south corridor and a more capable receiving network, lower-cost southern power will continue to be stranded while higher-cost generation fills the gap.
Taken together, these elements define Pakistan’s power sector today. It is not short of generation capacity. It is burdened by the cost of that capacity, constrained by transmission bottlenecks, weakened by distribution inefficiencies, and misaligned with a rapidly changing demand profile.
The immediate response must focus on utilisation: prioritising gas for peak power generation, enforcing merit-order dispatch, and maximising the practical limits of existing transmission assets.
But the deeper solution lies in structural alignment. Pakistan does not need a significant new generation in the near term. It needs transmission expansion, distribution reform, and financial restructuring that restores liquidity across the chain. It also needs to confront the accumulated burden of capacity payments, which now sit at the centre of the system’s affordability crisis.
Finally, it must adapt to seasonality and solar-driven demand shifts through storage and demand management. Without that, the gap between what the system can generate and what it can deliver will continue to widen.
Pakistan’s electricity problem is no longer about building more power plants. It is about fixing a system that has become too expensive to run, too fragmented to balance, and too constrained to deliver.
Until that alignment is achieved, the country will continue to live with a defining contradiction: paying for power it cannot afford to use, and experiencing shortages it does not need to have.