A solid game plan for our energy needs is more than just a smart move; it is essential. Energy isn’t just another industry; it is the foundation of our economy and the key to keeping our country functioning smoothly.

That’s why it’s so important to pin down how much it will cost to generate the power we rely on. We’ve got to be spot on with these numbers because they will help us handle our growing hunger for energy without making it too costly for the average person and industry.

The Integrated Generation Capacity Expansion Plan, or IGCEP for short, shapes Pakistan’s plan for future energy needs. This plan is about figuring out how much energy the country will need down the line and determine the best options to generate it. The goal is to ensure moving towards an energy future that makes technical sense and won’t cost an arm and a leg.

The IGCEP has a big job: it has to select energy projects that are the most cost-effective to build, based on how much energy we determine that we will need. After these projects get the green light from IGCEP, they go to Nepra, which is like the energy referee in Pakistan.

Nepra’s role is to ensure that the costs for these projects are fair and that the price people will end up paying for electricity makes sense. They do this by digging into the claimed costs and ensuring everything adds up.

But here’s where things get tricky. Sometimes, the cheapest cost that IGCEP comes up with doesn’t quite match what the project ends up costing when it’s time to get started. This mismatch between IGCEP’s estimates and the actual costs that Nepra sees can cause a lot of head-scratching and trouble.

The glaring disparity between IGCEP and NEPRA tariff calculation procedures is the most significant turmoil of the time. The annualised cost calculated by the IGCEP ignores many mandatory parameters for the actual development and operations of the project. Some of the essential items skipped in the IGCEP tariff are as follows.

• The project developers provide costs to the NTDC for the IGCEP iteration based on those projects’ feasibility or pre-feasibility studies. However, the feasibility study costs become outdated within a year due to inflation in construction and equipment costs. Although the IGCEP attempts to mitigate this issue by inflating the feasibility costs to a standard cutoff date, the index used for inflation is not very relevant.

The NTDC uses the National CPI and US CPI to index the onshore and offshore feasibility study costs, but these indices do not accurately reflect the actual cost increases during the indexation period. On the other hand, Nepra uses cement, steel, labour, and fuel rates to index project costs. As a result, there is a considerable difference between the costs indexed by IGCEP and those indexed by Nepra.

• The IGCEP assumes that all project costs will be incurred during year zero (the year before the start of commercial operations). However, these costs are spread over 2-4 years of development and 4-8 years of construction. As a result, costs such as interest and ROE during construction are not considered by the IGCEP tariff. These costs become significant components of the tariff when determined by Nepra.

It is worth mentioning that Nepra calculates the project’s tariff based on the actual cash flows incurred during the development and construction periods to calculate the Interest during Construction and ROE during Construction.

• The IGCEP tariff mechanism does not separate the total project cost into a proposed capital structure for the project. This information is not requested in the IGCEP pro forma distributed to project developers to obtain project data.

As a result, the IGCEP methodology for calculating annualised costs disregards the debt service and return on equity (ROE) components calculated by Nepra in determining the tariff. The actual weighted average cost of capital is much higher than the 10% standard discount rate assumed in the IGCEP.

• Specific additional costs, such as insurance during operations, variable O&M, SPV overheads, equity redemption and water use charges, are not considered when calculating the annualised cost in the IGCEP. However, Nepra allows for the inclusion of these costs when calculating the tariff for the projects.

• Finally, the IGCEP distributes all project costs to the economic life of the project (between 50-80 years for hydropower projects); however, Nepra assumes that all project costs must be recovered during the concession period of the project (30 years).

The consumer is supposed to pay the project’s financial tariff, not the IGCEP’s economic tariff, and therefore, when NEPRA observes a vast difference in IGCEP and its tariff, the whole planning seems to be failing.

The financial tariff increases further due to the inclusion of taxes, transmission and distribution margins, and other adjustments. Therefore, policymakers, regulators, and other sector stakeholders must stop and understand these analogies in the planning process and address them as soon as possible.

The implications of these methodological differences are far from abstract. Not enough data is available for all projects in the IGCEP to quantify and demonstrate the financial difference; however, the author has found reasonable data on candidate hydropower projects in the approved IGCEP. To illustrate the severity of disagreements between the two methodologies, the author has exploited the available data and analysed fifty-five candidate hydropower projects. The missing costs are assumed per Nepra-approved guidelines to fill in the blank data for tariff calculation.

On average, the Nepra methodology calculates the tariff, which is ~47% higher than the IGCEP annualised cost. The IGCEP’s calculations suggest that these hydropower projects would require US$ 2.54 billion annually to generate about 46,319 GWh of energy, averaging a cost of US cents 5.48 per kWh. However, when the lens of Nepra’s methodology is applied, the cost balloons to US$ 3.74 billion per annum, translating to an approximate US cent8.07per kWh. This difference isn’t merely a discrepancy; it’s a gaping financial chasm that points to the understated costs in IGCEP’s projections. Moreover, this more than US$ 1.2 billion annual underestimation is based on only 55 hydropower projects. The shortfall shall increase if we include other technology projects in this analysis.

The economy braces for impact when energy planning does not accurately reflect generation costs. The understated figures in IGCEP’s estimates can lead to a series of dominos tumbling down.

The consumer, already grappling with economic pressures, may face a steep hike in electricity tariffs once Nepra’s more comprehensive tariffs are enacted. Policymakers, who base subsidy allocations and fiscal budgets on IGCEP’s figures, could find themselves in a budgetary quagmire, with a deficit that may spiral out of control.

The projected annual shortfall, conservatively estimated at US$ 1.2 billion, could surpass the US$ 2.5 billion mark, should all IGCEP projects be considered.

The consequences of such misunderstanding in energy costing are multi-faceted and far-reaching. Energy infrastructure development, a critical component of growth, maybe misdirected towards projects that seem financially viable on paper but are unsustainable in reality.

Both domestic and international investors may shy away as project feasibility comes into question under NEPRA’s scrutiny. The energy sector’s trust fabric, delicately woven between the government, regulatory bodies, investors and consumers, risks being torn apart as the actual tariffs unveil the true cost of energy projects.

Bridging the gap between IGCEP and Nepra’s cost estimation approaches is not just a technical adjustment—it’s an essential stride towards transparency, economic stability, and the nation’s energy security.

Copyright Business Recorder, 2023