Mismatch Of Renewables

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Only 15 per cent — or 2,100 megawatts — of the planned hydropower capacity of 14,000MW by 2030 is expected to come online in time, with cost overruns estimated to rise from the current $31 billion to $49–61 billion, says the :contentReference[oaicite:0]{index=0}.

Out of the planned hydropower capacity, 51pc has achieved financial closure, but only 39pc had begun physical construction as of September 2022. The fact sheet also mentions that almost 70pc of the pipeline capacity requires partial or complete funding by either the Water & Power Development Authority or provincial government bodies.

The coalition, a group of allied organisations and individuals assisting in accelerating the growth of renewables in the country’s energy mix, is apprehensive that delays in pipeline realisation are likely to increase power outages and load shedding in :contentReference[oaicite:1]{index=1}, prompting a switch back to fossil-fuel power to bridge shortages.

Moreover, Pakistan and the government’s hydropower development wing have been downgraded by all three global credit rating agencies: :contentReference[oaicite:2]{index=2}, :contentReference[oaicite:3]{index=3}, and :contentReference[oaicite:4]{index=4}, increasing the likelihood of delays in implementing hydropower projects. Industry analysis shows that it is not economically viable to select hydro plants for the next 10 years since solar and wind are cheaper options.

The hydropower pipeline is also becoming vulnerable to extreme weather patterns and climate change, the effects of which have been seen across the globe in :contentReference[oaicite:5]{index=5}, :contentReference[oaicite:6]{index=6}, and :contentReference[oaicite:7]{index=7} in the form of drying rivers and lower reservoir levels. In Pakistan, too, the early onset of summers saw record-breaking temperatures and low reservoir levels.

In its comments on the Integrated Generation Capacity Expansion Plan (IGCEP) 2022–31, the coalition has suggested that the plan, updated annually by the :contentReference[oaicite:8]{index=8}, should provide more clarity and detail on cost mismatches in light of historical data and account for renovation and refurbishment costs, schedule overruns, indexation uncertainty, and contingencies such as those experienced in the case of Neelum-Jhelum and Mohmand Dam.

“We request that all such cost considerations should be included and made publicly available to provide further confidence to stakeholders in national power planning processes,” it says.

Analysing the latest IGCEP using the PLEXOS Energy Modelling Software, the coalition has pointed out several issues in national power planning, starting with delayed submission of IGCEP.

“As a result, many ground conditions change. Many plants go offline, exchange rates change, contracts change, etc. Then the committed plants (of capacity of 14,158MW) are fed into the model without capital expenditure on the assumption that they have moved to advanced stages and nothing can be done about them. This, however, is not true. Our model shows that only about half of these projects are economically viable, and even then only because of the urgent need for relatively cheaper electricity,” says :contentReference[oaicite:9]{index=9} of :contentReference[oaicite:10]{index=10}, a partner organisation of PREC.

In his comments on IGCEP, Qaseem points out that transmission costs are also not reflected in the power planning document. “While IGCEP does not claim to model transmission, a truly optimised plan can only be built by incorporating results of both IGCEP and the Transmission System Expansion Plan (TSEP). However, the TSEP is missing and decisions made solely on the basis of IGCEP are not reflective of true costs. IGCEP selects many candidate hydro projects, but our results have shown that it is not economically viable to select any candidate hydro for the next 10 years. Variable renewable energy — solar and wind — is by far the cheapest option.”

Moreover, he underlines that IGCEP models NTDC and :contentReference[oaicite:11]{index=11} as two separate systems connected with a tie line. “The capacity of this tie line is increased from 1,100MW to 2,050MW. Nevertheless, the government has since gone back on this commitment with KE. As a result of this modelling approach, many expensive plants are being run in the KE system, which would not be economically viable if the country was treated as one system — that is, central dispatch. Similarly, many plants such as local coal are being optimised for KE, which would otherwise not be feasible if the country was treated as one system.”

The coalition also questions the authorities circumventing IGCEP, the purpose of which is “to identify generation additions, by capacity and fuel type along with commissioning dates, for a certain plan period, through optimal use of all available generation resources.”

In light of this, it is pertinent to ask how the initiative taken by the :contentReference[oaicite:12]{index=12} to replace 10,000MW of fossil fuel-based generation with solar photovoltaic fits with IGCEP planning.

“Given that such huge fast-track investment can have major financial implications for the power sector and the economy at large, it is important for such investments to be part of IGCEP scenarios in order to ascertain their true cost in the short and long term. Moreover, IGCEP assumptions include provisions for government-to-government projects to be added as committed inputs.

“As previous iterations of IGCEP have shown, projects added in the committed category are removed from least-cost considerations altogether, even if they run contrary to the purpose of IGCEP. It is important to ask why IGCEP allows provisions for committed projects through the G2G channel to be added indefinitely into the future for projects which have not even been conceptualised yet and, when added, will be able to bypass the entire optimisation process.”