Initiating the regulatory process for tariff determination for the next control period, apex regulator, Central Electricity Regulatory Commission (CERC), recently issued the draft tariff regulations for the period April 1, 2024, to March 31, 2029. These norms will apply to all thermal and hydropower generation projects and transmission lines regulated by the CERC.
A key highlight of the draft notification is the regulated return on equity (RoE) for thermal plants and run-of-the-river hydro plants, which remains unchanged at 15.5 per cent. However, the RoE for transmission assets has been proposed to be reduced from 15.5 per cent to 15 per cent. Meanwhile, for pumped hydro storage and run-of-the-river with pondage projects, the draft notification increased the RoE from 16.5 per cent to 17 per cent.
Meanwhile, the regulated RoE for capex on emission control equipment will be determined by the marginal cost of the fund-based lending rate (MCLR) of the State Bank of India (SBI) + 350 basis points (bps), with a ceiling of 14 per cent. Further, all thermal plants that have a normative plant availability factor (PAF) of 85 per cent and a normative plant load factor (PLF) of 85 per cent are eligible for an incentive. The normative PAF has been set at 85 per cent for all thermal plants, and a similar normative PLF of 85 per cent has been proposed to qualify for an incentive.
Power Line presents an overview of the draft tariff regulations…
Tariff determination
According to the draft, the tariff for a generating station or transmission system can be determined for the entire facility or specific units/elements. If all units or elements commenced commercial operation before April 1, 2024, a consolidated petition must be filed for the entire facility for tariff determination from April 1, 2024, to March 31, 2029. The tariff for the associated communication system within the transmission system, operational before April 1, 2014, follows the pre-approved methodology. In the case of an emission control system in a coal/lignite-based thermal generating station, the generating company must apply for supplementary tariff determination within 90 days of the system’s operation.
The tariff is determined for the specific identified capacity if only a portion of a generating station’s capacity is committed to a long-term PPA. If the corresponding units cannot be identified, the tariff is calculated based on the entire project’s capital cost and applied to the contracted partial capacity. For expanding existing generating stations, the tariff is determined for the expanded capacity, utilising common infrastructure. The benefits of new technology in the expansion are applicable to the existing capacity, as determined by the CERC. Assets for implementing revised emission standards are considered part of the existing project, and their tariff is determined separately under specific regulations. Energy charges for generating stations receiving coal from integrated mines are based on the coal input price, with the generating company maintaining separate accounts for the integrated mine.
Tariffs for generating stations using coal washery rejects are determined according to regulations, limiting the shareholding of non-government companies to 26 per cent. Energy charges are based on the fixed and variable costs of the coal washery project, with coal rejects’ calorific value measured jointly by the company and beneficiaries.
Further, generating companies or transmission licensees can apply for tariff determination for a new generating station, unit, transmission system, or element within 90 days of actual commercial operation. In the case of a transmission system with multiple elements, the licensee must file an application for tariff determination for a group of elements when the expenditure reaches a minimum of Rs 1 billion or 100 per cent of the cost outlined in the investment approval, whichever is lower at the time of commercial operation.
Tariff structure
The tariff for the supply of electricity from a thermal generating station will comprise two parts, namely, capacity charge (for the recovery of the annual fixed cost consisting of components as specified in Regulation 15 of these regulations), and energy charge (for the recovery of primary and secondary fuel cost, as well as the costs of limestone and any other reagent, where applicable, as specified in Regulation 16).
Return on equity
For existing projects, the RoE is set at 15.50 per cent for thermal generating stations, transmission systems and run-of-the-river hydro stations, and 16.5 per cent for storage and pumped storage hydro projects.
New projects starting from April 1, 2024, have RoE rates of 15 per cent for transmission systems, 15.5 per cent for thermal and run-of-the-river hydro stations, and 17 per cent for storage and pumped storage hydro projects.
Additional capitalisation beyond the original scope, including emission control, change in law and force majeure, the applicable rate is determined based on SBI’s one-year MCLR + 350 bps as of April 1, capped at 14 per cent.
Additional capitalisation on account of renovation and modernisation
Generating companies intending to extend the life of a station through renovation and modernisation (R&M) must submit a petition to the CERC with a detailed project report, encompassing scope, justification, cost-benefit analysis, financial package, phasing of expenditure, and relevant information. Companies seeking R&M are not eligible for a special allowance.
Approval is contingent upon the consent of beneficiaries or long-term customers, and is granted based on factors such as cost estimates, financing plan, technology and duration of life extension. For gas/liquid fuel-based thermal stations after 25 years of operation, additional capex for turbine renovation or obsolescence may be allowed, with prudence checks deducting applicable expenses.
Special allowance for coal-based/lignite-fired thermal generating stations
According to the draft, coal-based/lignite-fired thermal generating stations, after 25 years of commercial operation, have the option to choose a “special allowance” instead of R&M. This allowance compensates for specific additional capex, excluding changes in law or force majeure. The allowance, set at Rs 107.5 million per MW per year, becomes part of the annual fixed cost. This option is not available if R&M has started, if the station operates under relaxed norms or is in a depleted condition. Expenditure from the special allowance must be separately maintained and reported to the CERC. The allowance can also apply to stations that availed it in previous tariff periods.
Computation of capacity charges and energy charges
The fixed cost of a thermal generating station is annually computed based on specified norms and recovered monthly through capacity charges. Beneficiaries share total capacity charges according to their percentage allocation in the station’s capacity. Capacity charges are recovered in two parts: peak hours and off-peak hours, with the regional load despatch centre determining these periods. Shortfall recovery in off-peak hours may offset overachievements in PAF during peak hours. An incentive of 75 paise per kWh is provided during peak hours and 50 paise per kWh during off-peak hours for scheduled energy exceeding the normative annual PLF achieved cumulatively.
Computation and payment of capacity charge and energy charge for hydro generating stations
The fixed cost of a hydro generating station is calculated annually based on specified norms. This cost is recovered monthly through a combination of capacity charge (inclusive of incentive) and energy charge. Beneficiaries pay in proportion to their allocation in the saleable capacity, excluding free power to the home state. During the period between the first unit’s commercial operation and the full station’s commercial operation, the annual fixed cost is provisional, based on the latest completion cost estimate, for determining capacity and energy charge payments during that period.
Sharing of benefits
Generating companies or transmission licensees must calculate gains based on the actual performance of controllable parameters, including station heat rate, secondary fuel oil consumption, and auxiliary energy consumption. Financial gains resulting from these parameters are shared annually between the generating company or transmission licensee and the beneficiaries or long-term customers.
Public procurement through competitive bidding
The generating company for a specific 158 generating station, an integrated mine, or a transmission licensee shall procure equipment, work and services through a transparent process of competitive bidding. However, under exceptional circumstances, procurement of equipment, works and services may be conducted through other methods as outlined in the general financial rules issued by the Government of India and applicable from time to time.
Conclusion
Overall, the draft regulations appear balanced. For hydropower generation companies, the higher RoE for pumped hydro storage and run-of-the-river with pondage projects is a key positive. While there has been a 0.5 per cent reduction in the RoE for power transmission projects under the regulatory tariff mechanism, it applies only to new projects. Additionally, thermal assets will receive a peak-period incentive income of 75 paise per kWh, compared to the previous rate of 65 paise per kWh. For now, CERC is seeking views from stakeholders regarding the proposed regulations, and the final regulations are expected to be ready by March 2024, upon hearing from the stakeholders.
Aastha Sharma