In December 2018, the Central Electricity Regulatory Commission (CERC) released the draft Terms and Conditions of Tariff Regulations, 2019 for the next tariff period from April 1, 2019 to March 31, 2024. While there were indications in the consultation paper, released in May 2018, regarding possible changes in the tariff structure and reduction in the return on equity (RoE) in light of the prevailing market conditions and low interest rates, the draft regulations have maintained the status quo in both cases. This comes as a big relief particularly to central PSUs such as NTPC and Power Grid Corporation of India Limited, which are regulated by the CERC.
Some of the key changes proposed in the draft are linking of fixed cost recovery with the normative quarterly plant availability factor (NQPAF) instead of the normative annual PAF (NAPAF); tightening of working capital norms with receivables reduced to 45 days from 60 days earlier; inclusion of a provision for generators to recover fuel costs through billing on actual gross calorific value (GCV) of coal received; increase in efficiency gains sharing; and change in the definition of bank rate. Once notified, the CERC’s multi-year tariff regulations for the fifth tariff period would be applicable to interstate generation and transmission. The CERC has invited public consultation on the draft regulations till January 15, 2019, while public hearing is tentatively scheduled for January 30 and 31, 2018.
Power Line presents the key highlights of the draft regulations…
Tariff structure: The draft regulations propose to continue with the existing two-part tariff structure for thermal and hydro generation and a single-part tariff for interstate transmission. Broadly, the fixed or capacity charges comprise the five components of depreciation, RoE, operations and maintenance (O&M) expenses, interest on loan capital and working capital. The supplementary fixed cost for additional capitalisation on account of revised emission standards will be determined by the CERC separately.
The variable or energy charges of thermal power stations comprise the landed fuel cost (primary and secondary fuel cost) plus the cost of reagents like limestone, sodium bicarboneate and urea used in the implementation of the revised emission control standards. Further, energy charges include the input price of coal/lignite from the integrated mine. The determination of the input price is dealt with in a separate section of the draft regulations. The GCV of coal received is proposed to be reduced by 85 kCal per kg to account for the loss of calorific value in storage.
For generating stations, the tariff will be determined only for the part of capacity that is tied up in long-term contracts. If the units corresponding to such part capacity cannot be identified, the tariff for the entire station may be determined, but it will be applicable to the contracted part capacity only.
Capital structure: The existing debt-equity ratio of 70:30 has been proposed to be retained in the next tariff period as well.
For generating/transmission systems that will have completed their useful life on or after April 1, 2019, the developers can write off equity and recovered depreciation in excess of debt repayment till that date. The useful life is 25 years for thermal plants and substations; 35 years for transmission lines; 40 years for storage-type hydropower plants (earlier 35 years) and 15 years for communication systems.
For thermal stations that have completed 25 years of operation, the beneficiary and generator may agree to settle the total cost (fixed and variable) based on scheduled generation rather than the current arrangement of separate recovery of fixed cost based on availability and energy charge based on schedule. In addition, the option of availing of a special allowance of Rs 950,000 per MW per year (earlier Rs 750,000 per MW for the first year with 6.35 per cent annual escalation) instead of renovation and modernisation (R&M) expenditure is available to thermal stations. This will help plants meet the required expenditure including R&M expenses without resetting the capital base.
RoE: The current post-tax base rate of 15.5 per cent for generation/transmission projects and 16.5 per cent for storage-based hydropower stations is proposed to be retained. However, the additional 0.5 per cent incentive available for projects completed as per schedule has been removed. Instead, the RoE for additional capitalisation after the cut-off date will be calculated at the weighted average rate of interest on the actual loan portfolio of the generation station/transmission system.
Depreciation: The salvage value of the assets is proposed to be reduced to 5 per cent from 10 per cent, excluding IT equipment and software that have zero salvage value. This will increase the allowed depreciation to up to 95 per cent of the capital cost of the asset.
Working capital: The rate of interest on working capital has been linked to a one-year marginal cost of funds-based lending rate (MCLR) plus 350 basis points, as against the earlier State Bank of India base rate plus 350 basis points. Further, the norms have been tightened for the normative inventory of coal or lignite and limestone for non-pithead stations to 20 days (from 30 days) as well as for receivables of all stations to 45 days (from 60 days).
O&M expenses: For coal/lignite-based stations, the year-wise allowed O&M expenses have been specified for different units. The expenses for 800 MW units have been mentioned separately (earlier these were covered under 600 MW and above units) and at rates lower than those of the 600 MW series, which start at Rs 1.739 million per MW for 2019-20. The rates for the 800 MW series start at Rs 1.565 million per MW for 2019-20, which is almost half of the Rs 3.059 million per MW applicable to the 200-250 MW series. The O&M expenses of gas turbine/combined cycle generating stations have been fixed at Rs 1.624 million per MW for 2019-20 (lower than the Rs 1.872 million for 2018-19) and will be increased to Rs 1.842 million per MW in 2023-24.
For new hydropower stations, which will start commercial operations after April 2019, O&M for the first year has been revised to 2.5 per cent of the original project cost from 2 per cent earlier. The O&M expenses for hydro projects that have not completed three years on April 1, 2019 will be calculated by applying an escalation of 4.7 per cent as compared to 6.04 per cent in the existing order. The same escalation will be applicable during the subsequent years of the tariff period as against 6.64 per cent.
The norms for substation bays have been reduced by more than half and separate norms have been specified for transformers in Rs million per MVA. Meanwhile, the norms for transmission lines have been increased marginally. For communication systems, too, separate year-wise and component-wise (OPGW links, remote terminal units and phasor measurement units) O&M expenses have been specified.
Computation of capacity and energy charges: The fixed cost of thermal generating stations has been proposed to be recovered in two parts – capacity charges for the peak and off-peak periods of the month, with the former being 25 per cent more than the latter. These charges are recoverable if the actual PAF during peak and off-peak periods for the month is equal to the NQPAF for the cumulative peak and off-peak periods respectively during the month (instead of the NAPAF).
Differential incentive has been proposed for peak and off-peak periods at 65 paise per kWh and 50 paise per kWh, respectively, for scheduled generation in excess of ex-bus energy corresponding to normative quarterly plant load factor (NQPLF). Currently, there is only one incentive of 50 paise per kWh linked to the normative annual PLF. The practice of linking incentives to the PLF instead of the PAF was started in the previous tariff period. It is also proposed that generation plants have to declare the day-ahead availability for each fuel source, differentiated in terms of their price and calorific value, and the beneficiaries should have an option to schedule the power based on merit order despatch.
The existing methods for cost recovery of hydro generation units and transmission systems have been retained. Given the importance of communication systems, a separate formula has been mentioned for the recovery of communication charges, calculated by aggregating charges for individual communication systems with reference to the normative availability of communication system to be recovered by long-term customers.
Operation norms: These relate to the recovery of tariff and incentives. For thermal plants, the NQPAF has been lowered to 83 per cent from the earlier annual PAF of 85 per cent. The NQPLF has not been revised and remains at 85 per cent. The gross station heat rate for the existing units of 200 MW, 210 MW and 250 MW has been tightened to 2,410 kCal per kWh from 2,450 kCal per kWh while that of 500 MW subcritical units, and units of 500 MW and above with electrically operated boiler feed pumps (BFPs) has been retained at 2,375 kCal per kWh and 2,335 kCal per kWh, respectively.
For coal/lignite-based plants (with COD after April 2009), the factor with which the design heat rate is multiplied to derive the gross heat rate has been increased to 1.05 (from 1.045). The secondary fuel oil consumption norms have been tightened by 50 per cent. The auxiliary energy consumption of coal/lignite plants has been increased by 0.5 percentage points for higher capacity units (300 MW and above) with steam-driven BFPs to 5.75 per cent and that for combined cycle units by 0.25 percentage points to 2.75 per cent.
For pondage/storage-based hydropower stations, the NAPAF varies from 85 per cent to 90 per cent (unchanged from last time) depending on how significantly the silt affects the plant. The CERC may extend allowance under special circumstances like the abnormal silt problem. Another 5 per cent allowance will be provided for plants in the Northeast.
For transmission systems, the normative annual transmission system availability factor (NATAF) for the recovery of annual fixed charges of AC systems is 98 per cent, and of high voltage direct current (HVDC) bipole links and HVDC back-to-back stations is 95 per cent. AC transmission systems and HVDC systems will be eligible for incentives for NATAF exceeding 98.5 per cent (unchanged) and 97.5 per cent (previously 96 per cent), respectively. In both cases, incentives will not be provided for availability beyond 99.75 per cent.
Rebate and late payment surcharge: The payment of bills of generators or transmitters within two days of issuance should lead to a rebate of 2 per cent. The rebate will be reduced to 1 per cent if payment is made after two days but within 30 days of bill presentation. The late payment surcharge, which will be applicable in case of payment after 45 days of billing (earlier 60 days), has been reduced to 1.25 per cent per month from 1.5 per cent. The generator or transmitter must equally share (50:50) with the beneficiaries any financial gains due to variation in norms, saving in interest owing to refinancing, or non-tariff income.
Miscellaneous: As such, the operational norms and tariff form the ceiling. However, interstate generators and transmission licensees will now be allowed to charge lower tariff for one year at a time on account of lower depreciation based on the requirement of repayment, agreement on deviation from operational parameters, reduction in O&M expenses due to reduction in the despatch level and willingness to charge lower RoE and incentive than that specified in the regulations. This provision will help generators and transmitters increase their competitiveness.
The industry reaction has generally been positive. The status quo on the RoE and the tariff structure will certainly help the central PSUs as well as private generation and transmission companies regulated by the CERC.
India Ratings and Research (Ind-Ra), a subsidiary of the Fitch Group, has termed the draft as favourable for generators. As against Ind-Ra’s expectation of a lower RoE and change in the debt-equity ratio in favour of debt, the regulator has kept these parameters intact. The tightening of working capital norms and linking of the working capital interest rate to MCLR plus 350 basis points are likely to lower the interest on working capital. Ind-Ra expects the energy charge rate to increase by 6 paise per kWh under the new tariff guidelines due to an increase in normative auxiliary energy consumption; an allowance of additional GCV loss to account for variations during storage; and an increase in the normative allowance in transit losses. While the reduction in normative availability is expected to improve fixed cost recovery, the switch to quarterly declaration eliminates the possibility of recovering any under-recoveries in a quarter in the later part of the year. Overall, the decline in the aggregate revenue requirement due to working capital changes is expected to be offset by higher energy charges. According to brokerage firm Motilal Oswal, the write-off of regulated equity assets that have outlived their useful life is expected to impact NTPC, which has about 15 GW of capacity over 25 years, in the near term.
The draft regulations are subject to changes resulting from consultation with stakeholders. The final regulations are expected to be notified before March 2019. While the market conditions have changed considerably since the previous tariff regulations, the CERC has refrained from making major structural changes in view of the current situation of financial stress in the generation sector. As a regulator, it has to strike a balance between the interests of investors and consumers.