NEPRA Flags Rising Electricity Cost Due To Low Plant Utilization

The National Electric Power Regulatory Authority (NEPRA) said under-utilisation of power plants and excess capacity pushed up per-unit electricity costs in the fiscal year 2024–25.

NEPRA’s performance evaluation found that many large thermal and renewable plants operated well below capacity. This gap between installed capacity and actual generation raised fixed capacity costs charged to power buyers, contributing to higher tariffs for consumers nationwide.

According to the report, thermal plants operated at around 42.5% of reference capacity, while renewable facilities averaged just 36.6% utilisation. This shortfall, combined with higher payments for maintaining idle capacity, inflated the overall cost of electricity procurement.

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NEPRA’s figures show that total power purchase costs — excluding imports from Iran — hit roughly Rs 2.94 trillion in FY 2024–25. Of that, about 61% was capacity purchase price (CPP), averaging Rs 14.3 per kilowatt-hour, and 39% was energy purchase price (EPP) at roughly Rs 9 per kWh. The high CPP share reflects surplus capacity and low utilisation.

The regulator noted that reliance on imported fuels such as RLNG, furnace oil, and imported coal also kept generation costs elevated, especially as cheaper domestic resources were not fully dispatched.

For example, the Uch and Uch-II gas power plants — typically among the most cost-effective in the national fleet — operated at around 80.9% and 71.6% respectively, despite being available over 92% of the time. Their moderate use forced greater dependence on pricier imported fuel plants.

NEPRA also highlighted sustainability concerns, warning that depletion of the Uch gas field could strain future power costs. Coal-based plants in Thar, which offer competitive energy costs, also saw limited dispatch due to supply chain constraints, including delays in the Thar Rail Link Connectivity Project needed to transport coal efficiently.

Transmission bottlenecks were cited as another issue. They restricted flow from cheaper southern plants to northern demand centres, further raising costs. Major hydro units such as Neelum Jhelum and the 747 MW Guddu plant experienced prolonged outages, reducing availability of low-cost power.

Renewables faced curtailment because of grid constraints and intermittent output, leading to penalties that added over Rs 13 billion in missed revenue. Fluctuating system loads and partial loading also triggered roughly Rs 44.6 billion in additional adjustment costs.

Within the K-Electric system, average plant utilisation was only about 34.6%, with continued dependence on expensive LNG supplies under take-or-pay contracts, including for BQPS-III. A new interconnection with the National Grid, energised in July 2025 with up to 2,000 MW capacity, aims to improve flexibility, but high cost pressures persist.

NEPRA concluded that aligning generation capacity with demand, prioritising indigenous fuels, upgrading transmission systems, and restoring cheaper plants to service are critical to reducing costs, improving reliability, and easing financial stress in Pakistan’s power sector.