How WACC financing drives up consumer tariffs, why solar and BESS must be central to the next plan, and what affordability-first planning looks like

 

IGCEP 2027: A Real Opportunity to Get Power Planning Right

How WACC financing drives up consumer tariffs, why solar and BESS must be central to the next plan, and what affordability-first planning looks like

Business Recorder reported today that ISMO has begun collecting data for IGCEP 2027, covering the decade 2027 to 2037, with stakeholder submissions due by September 14. This is genuinely good news. Pakistan needs a long-term generation plan. The country's infrastructure requires investment, its grid needs upgrading, and its energy mix must evolve. A new indicative plan, built thoughtfully on updated data, is exactly what the sector needs.

The opportunity is real , and so is the risk of repeating the same mistakes. IGCEP 2025-35 has not yet been approved; NEPRA raised questions about it in May 2026 that remain unanswered. If IGCEP 2027 is built on the same planning framework , starting with how much generation can be added and working forward to a consumer tariff , it will arrive at the same conclusion its predecessor reached on Page 52 of its own document: electricity will become unaffordable for a common person. The chance to do it differently is right now, before a single project data form has been submitted.

That different approach has a simple starting point: the plan must begin with what electricity must cost the consumer by 2035 , and work backward from there to determine which technologies, at which locations, can deliver that price. This is not a radical idea. It is how any serious infrastructure plan that serves its users should be designed.

To understand why the current approach produces the wrong result, it helps to understand how a power project's cost actually lands on an electricity bill , and why it keeps rising long after the project is built.

Every power plant in Pakistan is paid a Capacity Purchase Price , a fixed monthly charge the system pays to the plant owner whether the plant runs or not. It covers the plant's capital cost, debt repayments, and equity return. Today this charge accounts for 52.6 percent of every electricity bill , Rs.17.55 out of every Rs.33.38 paid per unit. More than half of what a consumer pays is not the electricity itself. It is a fixed commitment to capacity that may be sitting idle.

The CPP per unit is calculated as a fraction: total capacity payments divided by total units sold. Add new plants , the numerator grows. Consumers install rooftop solar and leave the grid , the denominator shrinks. When both happen at once, as they are happening in Pakistan right now, the CPP per unit rises regardless of how efficiently the plants themselves run. This is the trap IGCEP walks into with every new committed project it adds to an already-surplus system.

Under Pakistan's NEPRA regulatory framework, the financing cost of every WAPDA project is recovered from consumers through the Capacity Purchase Price. The rate applied in this recovery is derived from the project's Weighted Average Cost of Capital , WACC , which IGCEP 2025-35 sets at 10 percent. In practice this means the allowed revenue WAPDA earns on its regulatory asset base is determined by this WACC rate. When a project overruns its approved cost, the additional expenditure is assessed for inclusion in that regulatory asset base, and if included, it generates additional allowed revenue recovered from consumers. An overrun does not automatically mean the developer earns a full 10 percent return on every additional rupee , the regulatory process determines what is admissible , but the structural incentive is clear: a larger asset base produces a larger allowed revenue, and consumers fund the difference.

Neelum-Jhelum demonstrates the end result of this structure. The project overran from Rs.15 billion in 1989 to Rs.507 billion by 2018. The tunnel collapsed in 2022. The project generates no electricity. Yet the Neelum-Jhelum surcharge, which services the project's outstanding debt obligations, remains on every Pakistani electricity bill today. This is not an anomaly. It illustrates what happens when the cost of a project , regardless of whether it performs , continues to flow through the tariff structure.

The identified additional costs on the four major committed projects in IGCEP 2025-35 , Dasu, Tarbela 5th Extension, Mohmand, and Bhasha , total approximately Rs.2,341 billion above original approved figures, of which Rs.1,841 billion is confirmed through official ECNEC and CDWP records and Rs.500 billion is a minimum estimate for Bhasha where the revised PC-I has not been formally submitted (see Table 1). Applying a capital recovery factor of approximately 10.09 percent , which is the correct annualised figure at 10 percent WACC over 50 years, not simply 10 percent multiplied by the principal , this identified additional cost generates roughly Rs.236 billion per year in additional capacity charges, adding approximately Rs.2 per unit to every electricity bill in the country.

Dasu Hydropower Project shows how these numbers build into a delivered consumer tariff. The revised capital cost is Rs.1,737 billion , USD 6.2 billion at IGCEP's base exchange rate of Rs.278.1 per dollar. Using the correct capital recovery factor of 10.09 percent at 10 percent WACC over a 50-year project life, the annual capital recovery is approximately USD 625 million , not simply 10 percent of USD 6.2 billion, which would be USD 620 million, but the annualised figure that accounts for compounding. Adding fixed O&M at 1.5 percent of capital gives an annual fixed cost of approximately USD 718 million. Against the project's expected annual output of 12,222 gigawatt-hours, this gives a generation cost of approximately Rs.16 to Rs.17 per unit , roughly 6 cents (see Table 2).

But Dasu's electricity does not arrive at a consumer's meter at the generation busbar. The 765-kilovolt transmission line from Dasu to the national grid costs approximately USD 900 million and adds roughly Rs.2.5 per unit. Grid access charges add Rs.2.2. Interest accumulated during the approximately eight-year construction period from project start to expected generation , capitalised into the regulatory asset base under standard NEPRA methodology , adds an estimated Rs.1.4 per unit. The all-in levelised cost over 50 years is approximately Rs.22 to Rs.23 per unit , about 8.3 cents. The official estimate of USD 0.08 per unit covers generation only; the additional Rs.1 in this table comes from adding the transmission line and grid access costs.

The problem is the timing of debt repayment. The levelised figure is an average across 50 years. In the first 15 years , when loan instalments are largest , the annual CPP contribution from Dasu will be materially higher than the levelised average. Based on the structure of IDA and IBRD loans, which typically carry higher early repayment schedules, this initial-period cost is estimated at Rs.30 to Rs.35 per unit , between 10.8 and 12.6 US cents. This is an estimate, not a NEPRA-determined tariff; the actual figure will depend on the final financing structure. But the direction is clear: the initial period cost is significantly above the 9-cent affordability threshold.

For consumers in Karachi, distance compounds the cost. Dasu is in Upper Kohistan , 350 kilometres north of Islamabad through mountain terrain , and Pakistan's largest demand centre is approximately 1,500 kilometres further south. Electricity loses energy over long transmission distances, and Use of System charges increase with the volume and distance of power being moved. A unit of Dasu electricity costs more to deliver to Karachi than it does to a consumer in northern or central Pakistan. Meanwhile, Karachi sits within reach of the Gharo-Jhimpir wind corridor and Sindh's solar resource. Distributed generation built close to the load would face shorter transmission distances, lower system losses, and no equivalent construction delay. IGCEP does not calculate the delivered cost per unit at major load centres. It selects the cheapest generation at the busbar. These are not the same thing, and for a city like Karachi the gap between them matters significantly.

If the next plan is to arrive at a genuinely affordable tariff, it must honestly account for one of the most significant shifts in energy economics of the past decade: the dramatic and continuing fall in the cost of solar generation and battery energy storage. In 2015, utility-scale solar cost approximately USD 300 per megawatt-hour to generate. Today it is under USD 30 in many markets. Pakistan's solar irradiation levels are among the highest in the region, and the country imported 22 gigawatts of solar panels in 2024 alone. Battery energy storage , which makes solar dispatchable rather than only available when the sun shines , has fallen from USD 1,000 per kilowatt-hour of capacity in 2015 to approximately USD 100 to 130 today, with credible projections placing it at USD 60 to 80 per kilowatt-hour by 2030. These are not speculative numbers. They reflect what is being priced and contracted in energy markets around the world right now.

IGCEP 2025-35 assumes only 8,120 megawatts of net-metered rooftop solar over the entire ten-year planning period , a figure Pakistan exceeded in a single year of panel imports. The plan contains no substantive modelling of utility-scale solar-plus-storage as an alternative to committed centralised hydro, and no sensitivity analysis showing what the consumer tariff looks like if battery storage costs reach USD 70 per kilowatt-hour by 2030 , which independent analysts consider likely. A 500-megawatt battery storage system combined with local solar or wind, built near a major load centre, can now deliver dispatchable electricity at a delivered cost that competes with , and in many scenarios beats , the cost of generating electricity in Kohistan and transmitting it 1,500 kilometres south. IGCEP 2027 must model this explicitly. Not as an afterthought under net-metering assumptions, but as a genuine competing option to large centralised hydro for meeting load growth in southern and central Pakistan.

IGCEP's own Scenario 3 , the base case , projects the consumer end tariff rising from Rs.33 today to approximately Rs.43 by 2035. That is a 30 percent nominal increase. It also assumes every project comes in on time at revised PC-I cost with no further overruns, and that demand recovers to a base year figure 19.5 percent above actual FY2025 sales.

On top of IGCEP's own S3 projection, three factors push the tariff higher in a more realistic scenario. First, applying the identified additional costs of Rs.2,341 billion through the WACC-based capital recovery mechanism adds approximately Rs.2 per unit. Second, rupee depreciation adds an estimated Rs.3 per unit across fixed and variable charges; at 5 percent per year, the rupee falls from Rs.278 to approximately Rs.431 per dollar by 2035, raising the rupee cost of USD-indexed loan repayments. Third, if grid sales in 2035 are closer to 115,000 gigawatt-hours than IGCEP's inflated 133,233 gigawatt-hour assumption, fixed capacity charges spread over fewer units, adding approximately Rs.3.5 to the CPP. These are the author's modelled additions to IGCEP's S3 baseline, not IGCEP's own projections. Combined, they produce an estimated 2035 consumer end tariff of approximately Rs.51 to Rs.52 per unit, or roughly 18 to 19 cents. The target for a competitive economy is 6 to 9 cents (see Table 3 for the full methodology).

IGCEP 2027 must be required to address this before the first project is included. What is the consumer tariff ceiling, meaning the maximum delivered cost per unit at major load centres, that this plan must not exceed by 2035? Every project should be stress-tested at 50 and 100 percent above its revised PC-I cost, not its original estimate. If that risk pushes the consumer tariff above the affordability ceiling, the project should not enter the plan unless the government is prepared to absorb the excess cost through PSDP rather than passing it through the capacity payment mechanism.

Generation expansion planning should be about making electricity affordable. IGCEP 2025-35 acknowledged on Page 52 of its own document that the tariff will reach its highest ever levels and become unaffordable for a common person. IGCEP 2027 data collection starts in four days. The question is whether anyone will require it to arrive at a different answer.

Planning that does not begin with what people can afford to pay will always arrive at a price they cannot afford to use.

Rehan Javed

 Karachi, Pakistan

rehanjawed@gmail.com | 0345-8256891

Note: This article has been written with the assistance of AI. However, the views expressed, the data analysis, and the cost calculations are entirely my own. My core objective is to simplify complex power sector issues into plain language so that every citizen, every industrialist, and every policymaker can understand what is being planned in their name and what it will cost them.

Disclaimer: The views and calculations in this article are solely those of the author in a personal capacity and do not represent the position of any organisation, institution, or chamber. All figures are drawn from publicly available official sources and the author's independent analysis; readers are encouraged to verify data from primary sources before drawing conclusions or making decisions.