While the capacity payments to Independent Power Producers (IPPs) have grabbed major spot light these days, our single-buyer regime remains the real source of ire, where power plants are paid to remain on standby and supply electricity when needed. This idling incurs costs, as these plants are exclusively reserved for use when required.
The power sector is a complex system involving numerous factors that impact the end consumer price. These include the procurement of different generation products like capacity and energy, determining the ideal energy mix, and choosing the appropriate technology and fuel sources.
Further complications arise from transmission and transformation losses, congestion and bottlenecks, curtailment of power due to these bottlenecks, and part-load adjustments resulting from low demand or the integration of solar distributed generation.
Additionally, ancillary services, which ensure the quality of the power supply, add another layer of complexity, as do T&D losses, theft, and non-recovery issues.
Delays in decision-making regarding recovery of actual costs or in completion of projects, further complicate the landscape. Every one of these elements affects the final price paid by consumers. It’s crucial to address these issues comprehensively to identify opportunities for significant savings.
Out of the total generation capacity payments of 2,091 billion rupees for FY 2024-25, 83% is attributed to hydel, nuclear, coal, and RLNG plants. Only 7% is associated with older plants running on RFO and gas, while renewables, including wind, solar, and bagasse, account for 10%.
My previous article, “IPPs: why leaders must lead from the front”, focused on recommendations regarding government-owned plants. Today, I shall discuss issues beyond capacity payments. For instance, the average plant utilization factors for the four Imported Coal Plants—China Power Hub Generation Company, Sahiwal Huaneng Shandong Ruyi Energy, Port Qasim Electric Power Company, and Lucky Electric Power Company—were notably low: 4% in February, 0% in March, 1% in April, and 12% in May.
In contrast, the average Plant Factors for the four Local Thar Coal Plants—Engro Powergen Thar (Pvt.) Limited, Thar Energy Limited, Thar Coal Block-I Power Generation, and Thal Nova Power Thar (Pvt.) Ltd—were significantly better: 59% in February, 48% in March, 50% in April, and 76% in May.
Various factors contribute to the low utilization of these plants, with one of the main reasons being the lack of demand in the system. Another significant factor is the penetration of solar power, which has become a disruptive technology.
Solar energy replaces traditional energy sources during the day, leaving central capacity idle—a scenario not anticipated 7-8 years ago. This situation creates firming costs at the grid level and increases part-load adjustments of plants. According to the CPPA-G, Net Metering Units alone accounted for 100 GWh in April 2024.
Coal plants, which are base-load plants with steam turbine technology, are particularly impacted by low utilization. This situation increases part-load adjustments and raises overall fuel costs particularly with local coal, as some portion of these costs is fixed. Similar issues affect other types of technology plants as well.
Partial Load Adjustment Charges (PLAC) are granted to power plants under their respective Power Purchase Agreements (PPAs) when they operate below full load capacity.
Operating base load power plants at partial load reduces efficiency and increases generation costs, leading to higher monthly Fuel Price Adjustments (FPA) for end consumers. In FY 2022-23, PLAC payments amounted to 46.59 billion rupees, up from 38.20 billion rupees in FY 2021-22, indicating an increasing trend.
NPMV (Non-Project Missed Volume) represents the potential energy that could have been generated by wind power plants but wasn’t, due to factors beyond the control of the power producers. These factors can include grid and transmission constraints, scheduled maintenance, and other operational issues.
In FY 2022-23, the payment obligation for NPMV was Rs 10.517 billion, a significant increase from Rs 1.177 billion in FY 2021-22.
According to the Nepra State of Industry Report, the allowed T&D (Transmission and Distribution) losses for DISCOs in FY 2022-23 were set at 11.7%, but actual losses reached 16.45%, resulting in a financial loss of 160 billion rupees. This trend of increasing financial losses has continued year after year.
Furthermore, the average recovery ratio for Discos was 93% in FY 2022-23, leading to an additional loss of 212 billion rupees. If the actual T&D losses could be reduced to the global standard of 8%, it would result in substantial financial savings beyond what has already been highlighted.
The Energy Price Payment (EPP) component largely consists of fuel costs, alongside variable O&M expenses. Recently, concerns have been raised over inflated fuel prices, particularly on imported coal. From May 2022 to August 2023, the fuel component claim ranged between 28 to 32 Rupees per unit. We will not delve into details as matter is under investigation at different forums.
The average coal prices per ton for Australia, Indonesia, and South Africa are 53.48, 46.09, 91.66, 171.71, 95.95 Rs/ton during 2019 to 2023 respectively, though these figures exclude shipping and landing charges. These trends highlight the critical importance of planning around indigenous fuel sources for ensuring energy security and affordability in any country.
In the upfront tariff conditions, it is stated that local coal plants must maintain a 30-day coal inventory at 100% plant load, and imported coal plants must maintain a 90-day inventory at 100% plant load. Maintaining this inventory incurs working capital costs, which are passed on to consumers. These requirements should be adjusted annually based on the actual utilization plans for the coming year.
Another example of issues within fuel charge components is related to bagasse-based plants. Previously, the indexation for bagasse fuel was linked to imported coal prices. When NEPRA changed this to reflect local fuel costs, plant owners contested the change.
Fuel costs are typically a pass-through item and should be verified against actual market prices. Although a recent decision adjusted the indexation for bagasse to a 5% annual increase, the base price set in 2022 is still significantly higher than the market rate. For instance, the latest approved projection for bagasse prices in FY2024-25 PPP (Power Purchase Price) document is Rs 5,542 per ton, which is almost more than three times the market price.
It should be as clear as water our power sector ills which largely stem from poor& lack of integrated planning require immediate treatment.
Planning takes a central role in creating the right market sentiment for securing attractive capital from the private sector and requires all stakeholder concerns to be catered for on equal footing.
Having two different regulators for power and gas sectors create enormous challenges in day to day operations particularly in Pakistan’s context where the power sector remains the biggest off-taker of Nat-gas/LNG. We will explore solutions in the next write-up.
Copyright Business Recorder, 2024
The writer is an expert in the energy sector. With a passion for energy, sustainability, and emerging technologies. He can be approached at [email protected]
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