ISLAMABAD: Ill-planned surplus generation capacity, low plant utilisation, high fixed costs and inefficient generation dispatch have become a permanent source of high consumer-end power tariffs, as well as a financial drain on the power sector and the federal budget, says the power regulator’s annual report.

The National Electric Power Regulatory Authority’s (Nepra) Annual Report on the Performance of Power Plants in Pakistan FY2024-25 said: “Overall, the [power] sector’s high fixed costs, low utilisation, and inefficient dispatch of generation resources collectively resulted in higher electricity tariffs and financial stress on the power system.”

It further said, “In summary, achieving an economically sustainable power sector requires thorough evaluation of the financial and economic consequences before adding new generation capacity. Simply expanding capacity without assessing its cost-effectiveness and expected utilisation can result in inefficiencies such as under-used assets and increased electricity costs for consumers.”

It added that a balanced strategy that considered long-term financial factors — including capacity purchase price (CPP), energy purchase price (EPP), and overall grid stability — was crucial to ensuring generation capacity matched actual demand, optimising the use of available resources and incorporating flexible solutions, such as renewable energy, alongside more cost-efficient technologies.

By carefully analysing the economic impact of each new capacity addition, the power sector could minimise unnecessary financial strain, improve efficiency, and help reduce electricity tariffs for consumers, the report said.

During FY2024-25, the overall utilisation of thermal power plants stood at 42.5 per cent of capacity while renewable energy plants operated at an average utilisation of 36.6pc.

“This underutilisation, coupled with excess installed capacity, led to a significant rise in per-unit electricity costs, primarily due to higher capacity payments”.

The total power purchase cost during the fiscal year — excluding electricity imported from Iran — was recorded at Rs2.943 trillion, of which 61pc comprised CPP and 39pc EPP. The per-unit CPP averaged Rs14.3/kWh and the EPP Rs9/kWh.

“The elevated CPP stemmed mainly from surplus capacity and low plant utilisation, whereas the EPP was driven higher by dependence on costly imported fuels such as regasified liquefied natural gas (RLNG), residual furnace oil and imported coal”.

Conversely, plants based on indigenous fuels — such as nuclear, Thar coal, and local gas — offered substantially lower generation costs but remained underutilised. Among these, Uch Power and Uch-II Power Plants, both operating on dedicated gas fields, demonstrated low generation costs of around Rs13.4/kWh during FY2024-25, yet their utilisation factors remained modest at 80.9pc and 71.6pc, respectively, against their availability factors of 92.4pc and 95.7pc, the report stated.

These plants are ranked among the top in the economic merit order and represent some of the most economical generation sources in the national fleet; however, their limited utilisation restricts potential cost savings for the system. This underutilisation has led to increased reliance on expensive imported-fuel power plants, ultimately raising consumer-end tariffs through higher monthly fuel price adjustments, according to the report.

Furthermore, it said, depletion of the Uch Gas Field — a mature reservoir — poses a risk to the future sustainability of these plants. Ensuring optimal utilisation of these cheaper indigenous gas plants and managing their fuel supply proactively are therefore critical to reducing overall system costs and maintaining energy security.

Similarly, Thar coal-based power plants — another category of indigenous and cost-effective generation sources — operated at an average utilisation factor of only 72.9pc during FY2024- 25, despite their highly competitive energy cost. These plants are also ranked among the top in the economic merit order; however, their underutilisation has resulted in the dispatch of expensive imported-fuel power plants, thereby increasing the consumer-end tariff through monthly fuel price adjustments, Nepra noted in its report.

In parallel, it said, the transition of Lucky Electric Power Company Limited (LEPCL) from imported to indigenous Thar coal mainly depended on the availability of coal supply from the Thar coal mines and the timely completion of the Thar Rail Link Connectivity Project being implemented by Pakistan Railways.

LEPCL has expressed its concerns regarding delays in the rail link project. While Segment-I of the project — linking the Thar coalfield to the main railway network — is expected to be completed by June/July 2026, Segment-II, which includes the branch line and the common coal unloading facility at Port Qasim, remains pending and has not yet entered the construction phase.

According to LEPCL, the potential delay in Segment-II could hinder the transport of 10–12 kilotonnes per day of Thar coal required for its plant operations, thereby necessitating continued reliance on imported coal until both segments are fully operational. The company has conveyed that the absence of synchronised completion of both segments may result in underutilisation of investment in Segment-I and defer the intended transition from imported to local coal.

Transmission bottlenecks and grid constraints restricted the dispatch of cheaper power from the southern region to demand centres in the north, resulting in greater reliance on expensive imported fuel–based plants.

The prolonged outages of the Neelum Jhelum Hydropower Plant and Guddu 747 megawatt unit further weakened cost efficiency, the report stated. Renewable energy sources, it said, also faced curtailments due to intermittency and evacuation limitation, resulting in non-project missed volume payments exceeding Rs13 billion.

The report highlighted that varying load and the intermittent renewable generation led to increased part-load operations of thermal plants, adding Rs44.6bn in partial load adjustment costs during FY2024-25.

It confirmed the technical feasibility of drawing 2,000 MW power from the National Grid under the existing configuration but pointed out that K-Electric’s operational and commercial arrangements, including the “Take-or-Pay” RLNG Gas Supply Agreement for Bin Qasim Power Station-III and related part-load operation charges, continue to influence its generation mix and power drawl patterns.

To achieve long-term sustainability, the regulator emphasised the need for optimising generation capacity in line with actual demand, prioritising the use of low-cost indigenous fuels, expediting transmission upgrades to remove regional constraints, restoring non-operational low-cost plants, and carefully evaluating the economic implications of future capacity additions. A balanced generation mix and enhanced system efficiency are imperative for reducing electricity costs, improving reliability and ensuring a financially sustainable and resilient power sector, Nepra concluded.