A New Approach: CERC revises principles of transmission pricing

CERC revises principles of transmission pricing

The Central Electricity Regulatory Commission (CERC) notified the Sharing of Interstate Transmission Charges and Losses Regulations, 2020 in May, which came into effect from November 1, 2020. The regulations apply to all designated interstate transmission system (ISTS) customers (DICs), interstate transmission licensees, The National Load Despatch Centre (NLDC), regional load despatch centres (RLDCs), state load despatch centres (SLDCs) and regional power committees. The new regulations replace the extant CERC Regulations (notified in 2010), which have been in effect since July 2011 and modify the existing point of connection (PoC) mechanism for tariff computation.

In September 2020, Power System Operation Corporation Limited (POSOCO) notified the procedure for computation and sharing of ISTS charges and losses in compliance with the regulations. The procedure aims to provide a methodology for the computation of transmission losses and accordingly finalise schedules at various state/ regional boundaries. The procedure also aims at ensuring that the computed transmission losses to be applied for scheduling of generation and demand under various contracts are as near to the actual transmission losses as possible. Further, it lays down the modalities to be followed by the implementing agency for the computation of interstate transmission charges for each DIC.

Computation of transmission charges and losses

As per POSOCO’s recently released guidelines, transmission losses for the ISTS will be calculated on an all-India average basis by the NLDC for each week as per the following formula: ([In – Dr/Ir])*100 where “In” denotes the sum of injection into the ISTS at regional nodes for the week; “Dr” denotes the sum of drawal from the ISTS at regional nodes for the week; “Ir” denotes the sum of injection into the ISTS at regional nodes excluding the injection by solar and wind generators (solar projects commissioned or to be commissioned between July 1, 2011 and December 31, 2022 and wind projects commissioned or to be commissioned from September 30, 2016 and December 31, 2022). The drawal schedule of DICs will be prepared as per the provisions of the Grid Code, taking into account the transmission losses of the week preceding the last week.

As per the new CERC Regulations, the total ISTS Monthly Transmission Charges will have four components – national component (NC), regional component (RC), transformer component (TC) and AC system component (ACC). In contrast, the earlier regulations had a one-part tariff structure.

The transmission charges under the NC will be shared by all drawee DICs and injecting DICs with untied long-term access (LTA) in proportion to their quantum of LTA, plus medium-term open access (MTOA) and untied LTA respectively. The NC has two parts – renewable energy and high voltage direct current (HVDC). The NC renewable energy will comprise the yearly transmission charges (YTC) for transmission systems developed for renewable energy projects as identified by the central transmission utility (CTU). The NC HVDC will comprise 100 per cent of the YTC for “back-to-back HVDC” transmission system, 100 per cent of the YTC for Biswanath-Chariali/Alipurduar-Agra HVDC transmission system, YTC of the Mundra-Mohindergarh 2,500 MW HVDC transmission system corresponding to 1,005 MW capacity, and 30 per cent of the YTC for all other HVDC transmission systems.

The RC will comprise the regional component of HVDC (RC-HVDC), which will be calculated as 70 per cent of the YTC of HVDC transmission systems, planned to supply power to the concerned region, except that HVDC transmission systems covered under the C-HVDC RC will also include the YTC for static compensators (STATCOMs), static VAR compensators (SVCs), bus reactors, spare transformers, spare reactors and any other transmission element(s) located in the concerned region and identified by the CTU as being critical for providing stability, reliability and resilience to the grid. The RC will be shared by drawee DICs of the receiving region and injecting DICs with untied LTA in the receiving region, in proportion to their quantum of LTA plus MTOA and untied LTA, respectively.

The TC for a state will comprise the YTC for interconnecting transformers planned for drawal of power by the concerned state. For transformers used for the drawal requirement of more than one state, the YTC will be apportioned to such states in the ratio of number of feeders from such transformers emanating for each state. The TC for a state will be borne and shared by the drawee DICs located in the concerned state in proportion to their LTA plus MTOA. Meanwhile, the ACC will comprise the remaining YTC, which is not covered under the NC, RC and TC. It will contain a usage-based component and a balance component.

The overall transmission charges for DICs will be the sum of the charges computed under the NC, RC, TC and ACC. In case of under/over the recovery of monthly transmission charges, such charges will be scaled on a pro-rata basis.

Impact and utility concerns

Overall, the new CERC Regulations are positive for the sector as they bring in greater transparency in the process of determining transmission charges. As per Care Ratings, the new guidelines are mildly credit positive, for operational and under-construction transmission assets bring in more clarity on the process of clearing bills, encourage better grid discipline and partly mitigate the counterparty credit risk. In addition, they would help ensure proper allocation of transmission charges to various participants with the introduction of granularity in charges, improve grid discipline through precise forecasting and fine-tune the tariff mechanism.

Also, under the old PoC regulations, the states were able to project lower load and higher generation (which led to a lower transmission charge), as there was no penalty for incorrect projections. Hence, now transmission charges would be computed based on the actual load scenario. However, the new regulations are likely to lead to an increase in interstate transmission charges payable by certain states. For instance, for Kerala State Electricity Board Limited (KSEBL), the yearly charges are expected to increase from Rs 5.5 billion to Rs 15 billion, which may eventually lead to an increase in retail supply tariffs by Re 0.50 per unit. Other states such as Odisha, Tamil Nadu and West Bengal are also expected to witness an increase in transmission charges while some states may see a decline. This is mainly owing to the change in the computation method of underutilised interstate transmission lines.

The utilisation rate of several interstate lines constructed in recent years is below 30 per cent. These transmission lines were developed to enable the export of power from large thermal projects, many of which are stranded because of lack of offtakers and, therefore, the transmission connectivity has been relinquished by developers. It is estimated that about 34,000 MW of transmission capacity has so far been relinquished by private generating companies, out of the 83,000 MW allocated by Power Grid Corporation of India Limited.

So far, the charges for underutilised lines were being borne by states through which these lines pass through, as they are the ones that use them. However, as per KSEBL, the new regulations have segregated these charges into “usage” and “balance” components, wherein the former accounts for 22 per cent of the total charges and the latter component that accounts for 78 per cent of the total charges is apportioned among states, irrespective of whether they are using the lines or not. Kerala is using nearly 100 per cent of all lines passing through the state and paying the respective charges. However, these lines are underutilised in several other states and, therefore, the charges for such lines will also be loaded on to states such as Kerala. KSEBL is reportedly planning to approach the high court against the CERC’s Regulations. However, it is yet to be seen whether more states will come forward against these regulations.

To conclude, transmission pricing is a critical issue for utilities and it is necessary for regulators to keep them as balanced as possible.