Generation capacity of at least 62,000MW needed by 2035 to support economic growth

This is part of the revised Indicative Generation Capacity Expansion Plan (IGCEP) 2025-35 and the Transmission System Expansion Plan (TSEP) 2025-35 prepared by the Independent System and Market Operator (ISMO) — a power division entity — in consultation with all the relevant stakeholders, including the National Electric Power Regulatory Authority (Nepra). The two plans cover the entire power network, including those of distribution companies and K-Electric.

A distinguishing feature of the revised IGCEP is the consideration of Least Cost Violation (LCV) for Diamer-Bhasha, and ACWA solar power plants.

The plan also considers the impact of solarisation on the end-consumer tariff, the inclusion of strategic power plants using LCV, the induction of a significant quantum of net metering (8,120 MW), and the consideration of an 800 MW market-based solar quantum.

The revised IGCEP covers a 10-year time frame from 2025 to 2035, encapsulating power generation additions required to meet the country’s future energy and power demand, including the National Grid Company and KE systems.

Three scenarios of long-term load forecast were prepared, including low (business as usual), medium and high at gross domestic product (GDP) growth projections of 3.52 per cent, 4.95pc and 6.37pc for the next ten years, respectively.

The plan is based on studies that found that the historical load factor of 70-73pc had gradually declined to 58-60pc. Therefore, another load forecast scenario also incorporates demand side management (DSM) activities to gradually raise the current Load Factor (LF) of around 58pc up to 70pc till the end of the horizon.

The least costly, long-term generation expansion plan for the power system was developed using state-of-the-art generation planning software, PLEXOS, with rigorous data modelling and an optimisation exercise based on the existing and future generation power projects, existing policy framework, existing contractual obligations, natural resource allocations, relevant legal conditions, the ISMO said.

The IGCEP also considered a transmission line for the national grid system from South to Centre and North, and another line from NGC to the KE system has also been modelled to assess the requirements of any new transmission line.

The results showed a shift in the energy mix from imported fuel to indigenous ones, i.e., with a dominating share of renewables and hydropower. The reference rationalised scenario incorporating all of the policy interventions and other constraints, showed a major contribution from renewables, i.e., 34pc of hydropower and 27pc of variable renewable energy in the overall capacity mix by the year 2035.

There is minimal reliance on imported fuels, with residual furnace oil (RFO) having no contribution at all in the capacity mix, whereas imported coal and re-gasified Liquefied Natural Gas (RLNG) are contributing just 7pc and 13pc in the total capacity requirements, respectively. The share of indigenous fuels stands 15pc, i.e. 5.2pc of local coal, 2.6pc of local gas and 7.5pc of nuclear in the overall capacity mix.

As such, the capacity addition in the low growth case has been projected at 62,657MW, followed by 66,459MW for medium growth and 70,720MW for high growth (6.4pc) rate. In all cases, the generation capacity expansion has been estimated at 4,680MW for imported coal, 3300MW for local coal, 8,224MW for LNG, 1433MW for local gas, 4730MW for nuclear, 21400MW for hydropower, 819MW for furnace oil and 400MW for bagasse-based plants.

The solar power capacity expansion has been projected at 11,544MW for low GDP growth and 13,200MW for high growth. Wind-based generation is the only area where capacity expansion has been kept variable at 5,133MW for low GDP growth, 8,935MW for medium and 11,500MW for high GDP growth.

Therefore, the plans assured sufficient firm or base capacity in the form of hydro (existing, committed and optimised), RLNG, nuclear and local coal-based (existing) power projects are available 24/7 in the system till 2035 to meet the given hourly system demand whilst catering for renewable energy (REs) intermittency and system reserve requirements. The Present Value (PV) of the power generation operations and investments of existing and future power projects by 2035 is computed based on the objective function for the optimisation exercise and ranged between $46bn and $54bn. This will need transmission expansion cost of $4.6bn to $6bn.

The revised IGCEP 2025-35 also facilitates structural changes in the power sector planning process with an enhanced role of distributed generation and a reduction in the large projects distant from the load centres. Further, indigenisation of RE technologies through local manufacturing is also suggested to lower the basket price, for the provision of relief to the end consumer as well as saving precious foreign exchange while maximising the nature’s endowment bestowed upon Pakistan.

The plans reported that the Discos have observed a steep decline in their network-connected consumption owing to prevailing economic conditions, and a drastic increase in net-metering and rooftop solar PV. In this regard, the long-term planner is of the view that this sudden decline is a short-term phenomenon and it should not impact long-term expansion decisions at this stage. Nevertheless, this trend warrants close monitoring over the coming years, and if it persists, appropriate adjustments may be incorporated into future network expansion and investment planning.

The needs assessment conducted under the revised IGCEP 2025–2035 identified a significant change concerning power exports from National Grid to K-Electric. Subsequently, the export to K-Electric is envisaged to reach 3,456 MW by 2035, compared to 2,050 MW contracted.

Therefore, a detailed cost comparison analysis between generation from KE’s already planned 620 MW of REs and increased export from National Grid will be carried out by the power utility in due course of time.