CER releases a quarterly newsletter entitled “Regulatory Insights” which targets to bring
insights into key regulatory and policy developments in the power sector, accompanied with an analysis based on CER's Regulatory Database.
Competitive bidding for offshore wind should be the only basis for its development
Cost of dedicated transmission line from offshore pooling station to the CTU/STU network can be supported by viability gap funding from the corresponding Regional Deviation Pool Account Fund. A specific normative amount should be pre-specified in the bid document
NLDC should, in cooperation with IMD and NIWE, set up a dedicated centre for monitoring and forecasting of generation
Amendments to Tariff Policy, 2016 (Draft) released by Ministry of Power
The tariff principles should emphasise competition and efficiency in the sector
To optimise power purchase cost, trade of un-requisitioned power, separately for peak and off-peak hours, should be promoted through competitive bidding
SERCs should have the flexibility to adopt more stringent operational and financial norms than those laid by CEA/CERC. Operational norms should be delinked from past performance
MYT Regulations should continue to provide for sharing of benefits from performance improvement of utilities
A regulatory framework for demand forecasting and efficient power procurement planning should be adopted
To manage the underutilisation of generation capacity resulting in un-requisitioned surplus, the policy should provide for intra- and inter-regional reassignment/swapping of capacity under existing PPAs by DISCOMs
Adoption of RECs as a tool for RPO compliance would deepen the REC market
TOD tariff should be adopted for EV charging by all consumers. A separate category may be created for EV charging stations
Reliability-based tariff and TOD tariff should beimplemented for consumers with load above 10 kWacross all consumer categories
Direct benefit transfer, which would not only help reduce the subsidy burden of the State Government but also address inefficient consumption, should be implemented in a transparent manner
Deployment of smart energy meters should be based on a cost-benefit analysis and follow an implementation strategy targeting large consumers in a stratified manner. Prepaid meters must be mandated for defaulters and temporary users
Distribution utilities should adopt a bottom-up approach by setting distribution transformer level AT&C loss reduction targets
Terms and Conditions of Tariff Regulations (Consultation Paper) by CERC
Incentive on early completion of project should be replaced with penalty for delay as the currentframework places additional burden on consumers but allows full recovery of ROE even in case of delayed projects
Benchmarking of capital and operating costs should be based on best national and international practices
Technical minimum operating capacity and heat rate compensation for operating below normative level should be fixed based on a certified third party assessment
Allowable ROE should be periodically revised as per appropriate risk evaluation approach
Deviation Settlement Mechanism and Related Matters (4th Amendment) Regulations, 2018 (Draft) by CERC
Area-specific Market Clearing Price (MCP) can be used for differentiated DSM price vector in the case of market splitting.
The ultimate goal should be a vibrant ancillary services market that renders DSM 'irrelevant'
The resultant short-term spurt in price vector may need to be smoothened by migrating gradually from the existing deviation price to ACP in a period of 6 months or so
Effectiveness of an inter-state DSM needs to be supported with an analogous and effective intra-state ABT regime that should also be reflected in RE deviations
Volume 01 Issue 02 (Oct 2018)
Additional Draft Amendments to Tariff Policy, 2016 Simplification of Tariff Categories and Rationalization of Retail Tariff by Ministry of Power
In a DBT regime as proposed in the draft amendments to Tariff Policy (May, 2018), low tariff for lower consumption categories should be done away with, else it will diminish the efficacy of DBT
The proposed amendments should mandate time-ofday (ToD) tariff for consumers with load above 10 kW (to be further reduced to 5 kW gradually), with appropriate metering
ToD-based or dynamic tariff should be adopted for all consumers with smart meters to harness their potential especially to manage their electricity demand
A detailed impact assessment of the proposed tariff categorisation on revenue realisation by utilities, and consumers' bills should be undertaken
Reliability-based tariff should be implemented in place of proposed 24×7 electricity supply mandate. Moreover, the 24×7 supply clause leaves room for interpretation without relating it to the 'demand' (contracted/sanctioned load) of the consumer
Penalty for exceeding sanctioned load should be at least twice the fixed charge on additional load for encouraging consumers to get their sanctioned load revised
Central Electricity Regulatory Commission (Planning, Coordination and Development of Economic and Efficient Inter-State Transmission System by Central Transmission Utility and Other Related Matters) Regulations, 2018 by the Central Transmission Utility(CTU)
Transmission planning should also consider the expected impact of cross-border electricity trade
Impact of technological disruptions, on account of uncertain demand for EV charging, smart-grids and storage should also be taken into consideration
Integration of renewable energy resources characterised by intermittency and uncertainty necessitates advances in planning and operation of electricity grid to minimise the adverse impacts of significant variations in RE generation
Disaster management and recovery planning strategy must be in place to reduce the impact of unforeseen events
Amendment of RSPV (Gross & Net Metering) Regulations, 2015 (UPERC Concept Paper) by Ministry of New and Renewable Energy (MNRE)
Solar power banking can have adverse impact on the finances of DISCOMs and on system scheduling. However, a ToD provision for both injection and drawl can help ameliorate such impacts
RSPV installation process should be implemented through an online portal to facilitate its speedy adoption
Volume 01 Issue 03 (Jan 2019)
Regulatory Guidelines and Standards for Electric Vehicle Charging Infrastructure by Ministry of Power (MoP)
The rigidity of the area grids (3 km × 3 km or 25 km × 25 km) for installation of EV charging stations is undesirable. The choice of grid size or distance for setting up PCS should be flexible and based on feasibility studies, considering EV clustering, travel patterns, availability of parking space, vehicle characteristics, economics of ridership, etc. Existing parking stations at public and semi-public places should be identified first for setting up PCS under publicprivate partnership (PPP) framework. This would help avoid high incidence of land cost in initial phases
EV charging roll-out strategy should be flexible and account for expected growth in EV population, capacity of onboard battery, feasibility of battery swapping, ridership, availability of space, etc. It should also be compatible with EV roll-out across vehicle user segments, cab aggregators, food delivery services, postal services, and other logistic services with a predictable range of travel
A study by IIT Kanpur evaluated business models for EV charging infrastructure for two highways and a metropolitan city. The study suggested that bidding parameters based on Viability Gap Funding (VGF) may be used for setting up EV PCS under PPP framework. Furthermore, it was also found that the absence of time-of-day (ToD) based tariff may significantly alter the demand profile in future
Competitive bidding-based PPP framework using VGF as a bidding parameter should be used for setting up EV infrastructure
Tariff (including ceiling tariff) for EV charging should be a part of Tariff Policy. Moreover, EV charging, especially for PCS and fast private charging, should be a separate consumer category with ToD-based tariff to ensure that such infrastructure does not adversely affect the load curve in future
A separate tariff category for EV charging infrastructure would facilitate determination of tariff by ERCs and maintaining a database of PCS. This would also provide for innovation in tariff design, especially ToD tariff
The identified State Nodal Agency should facilitate setting up of EV charging infrastructure under PPP framework instead of taking charge of setting up such infrastructure using public funds
Automobile agencies or industry associations also play a constructive role in the preparation of an integrated and phased development plan for EV charging infrastructure
Requirement of amenities should be applicable for EV charging stations located on highways. For urban locations, adequate amenities may be made mandatory for PCS with large charging infrastructure
National Wind-Solar Hybrid Policy by Ministry of New and Renewable Energy (MNRE)
A hybrid system would improve the overall power generation profile as wind and solar generation profiles can complement one another, moderate the overall variability and economise the CAPEX accounted, thus making it more conducive for grid integration
However, resource intensity for a given or prospective project site may not be optimal for both wind and solar simultaneously, leading to compromise in efficiency. Thus, availability of project sites with optimal wind as well as solar energy might pose a challenge for deploying hybrid systems
A mechanism for apportionment of RPOs and RECs into solar and non-solar needs to be designed. Apportionment of scheduling of power in case of separate PPAs for solar and wind also needs to be addressed, especially for existing plants to be hybridised. This can be done:
¤ As per the Agreement between the two parties of the PPA
¤ As declared by the generator
¤ By adopting normative generation schedule
¤ By installing separate transformers and metering infrastructure
Each of the above methods has its own shortcomings. For instance, provision for separate metering/transformer would dilute the economic gains of hybridisation
Volume 01 Issue 04 (Apr 2019)
Key Features of Central Electricity Regulatory Commission(Cross Border Trade of Electricity) Regulations, 2019
Coordination between system operator and transmission utilities of the interconnected countries, specifically for the grant of short-term, medium-term and long-term open access, needs to be ensured so that two nodal agencies do not end up giving uncoordinated open access for the same interconnection up to the pooling stations of the respective countries
Provisions for determination of tariff for import of electricity in the case of hydro projects located in neighbouring countries need to be clarified in the context of small projects, multiple projects, and less than 100% allocation of a single or multiple hydro projects. The role(s) of intermediaries (like traders) may also be specified
Scope and modalities of dispute resolution, including arbitration, may be pre-specified to avoid conflicts thereafter. For example, in case a legal recourse has been resorted to by any of the affected parties of their respective country, either or both of them getting a favourable outcome may complicate the dispute resolution process unless modalities of arbitration are able to address this beforehand
It is not clear as to which International Arbitration Centre (IAC) is referred to in the regulations, as such IACs are located within India as well as in other locations like Singapore, Hong Kong, London, etc
In the case of CBTE, taxes, duties, etc. may be applicable both within the exporting as well as the importing entity. However, Section 30(3) refers to those applicable within India only
The regulations are designed from the Indian perspective – for both import and export of electricity. However, regulatory provision for ‘transit’ of electricity needs to be detailed out as well
Volume 02 Issue 01 (Jul 2019)
Delhi Electricity Regulatory Commission (DERC) (Group Net Metering
and Virtual Net Metering for Renewable Energy) Guidelines, 2019
Group/Virtual Net Metering guidelines, while being beneficial to consumers, would provide further impetus to the harnessing of RE resources
The scheme could be made more attractive by allowing REC credits in lieu of net RE injected to the grid. These could be accumulated and later sold through the registered members of the power exchanges
Key features of the scheme, particularly sharing of RE credit, should be facilitated through online mode. Further, participation of consumers with respect to RE sharing can be authenticated through consumer's registered mobile number
The guidelines should provide for the determination of incremental cost for replacing a partially or fully depreciated meter, and for writing off a meter which has completed its useful technical life
For consumers with ToD meter, provision for moderating surplus units should be replaced with ToD based price
Peak, off-peak and normal hours should be clearly defined. Given the dynamic nature of system demand profile, seasonal definition for the same may also be adopted
Use of agricultural land for setting up of solar modules (on stilts) in arable land would either lead to encourage unabated conversion of arable land affecting local employment for agricultural labour and long term food production.
Farming activity cannot be effectively continued on the piece of land, used to deploy solar panels (even on stilts). Shadow from fruit plantation would also reduce CUF over the lifetime of the solar plants. These land selections should ensure minimal loss of arable land. GPS boundary marking of the site could be mandated to avoid such land conversion.
DISCOM to publish substation-wise data on location (including GPS), unique asset number, total capacity, available surplus capacity, capacity allocated for REPP, including details of plant location, plant size, date of application, date of LoA, status of EMD & PBG post 30-day limit after LoA and actual date of deposit EMD & PBG, date of installation, date of synchronisation, meter ID etc.
In case the feeding substation is not repaired within the time limit set under SoP, approved by respective SERC, the RPG should be paid for deemed generation of power based on suitable norms for that area.
The enforceability of minimum CUF 15% is questionable as the guidelines do not specify the repercussion of failure to do so. Also, radiation level for identifying low solar radiation zones should be predetermined as the respective SERC may decide levelised tariff otherwise investment for setting up plants in such zones would be inefficient as well as uneconomical.
It should be specified whether EMD/PBG will be applicable on pro-rata basis in case of part MW capacity.
The procedural complexity particularly in the context of PPA, EMD, PBG and PBI needs to be minimized for the farmers/cooperatives/panchayats/FPO/WUA, who would face significant transaction cost in dealing with multiple offices located in urban/semi-urban centres.
The mechanism for enabling replacement of owned/rented diesel pump sets needs to be clearly enunciated.
Given the poor financial state of most of the DISCOMs across the country, payment of PBI should be implemented under a direct benefit transfer scheme on monthly basis.
A large number of states provide rotational power supply to farmers primarily during night hours ensuring adequacy of supply as well as cheaper cost of power purchase. Ensuring the must run status to REPP by keeping feeders ON during day time, in the near term, would impose additional day time system load for which the DISCOM may have to undertake relatively costly power procurement. Presence of single REPP would force the DISCOM to keep the feeders ON during day time, which may not be feasible as feeder separation has been implemented by most states allowing curtailment of power during the day.
Most small and marginal farmers may not use micro irrigation system.
Process of sanction and implementation of the scheme should be streamlined by the respective State Nodal Agencies for RE through a web-/mobile- based system.
UPERC Captive and Renewable Energy Generating Plants(CRE) Regulations, 2019
DISCOMs' concern for the value of banked and drawn power has been addressed adequately by implementing ToD based drawl against banking of energy. Given the reduction in risk exposure of DISCOMs, banking charges may be reduced. Dispatchable RE (excluding solar and wind) should be subjected to same, if not lower the banking charges.
Seasonality of banked energy should also be considered for drawl if power banked during surplus months is to be
drawn during high demand months.
The upper limit of 2/kWh rate for purpose of unutilised banked power by DISCOM, though appropriate for solar
and wind, is low in case of SHP and MSW plants and may be appropriately revised.
Volume 02 Issue 03 (Jan 2020)
MoP: Pre-Payment in the Entire Value Chain of Power Sector
Pre-paid metering is generally adopted to safeguard vulnerable consumers against exceeding their energy budget, and for consumers with poor payment record, the latter being a dominant driver in the Indian context. Phased implementation of pre-paid smart meters, targeting distribution areas with high technical and commercial losses, would bring in greater upfront benefits. In the case of utilities/areas with high collection efficiency, net gains for the distribution utilities and the consumers, estimated on the basis of a cost-benefit analysis, should drive wider adoption.
Financial Impact of Pre-paid Electricity Supply Chain - CER’s quick calculations based on cost structure, rebate on pre-payment and cost of interest on working capital across the electricity supply chain for UP DISCOMs, reveal that any gap resulting from difference in rebate on payment and saving on interest on working capital would be compensated through the truing-up exercise, thus limiting the benefit for the sector. Consumers would benefit on account of pre-payment rebate and, saving on interest on security deposit, if any. Replacement of existing electronic meters, whose economic and technical life is yet to be reaped, would place additional financial burden on DISCOMs.
Apart from rebate for pre-payment, pre-paid consumers would also expect refund of security deposit unless regulatory provisions allow for continuation of payment of interest on such security deposits.
Long-term sustained benefits of pre-paid smart metering would also depend on the development of a smart grid ecosystem. Implementation of a consumer demand response program and increasing the ambit of ToD pricing would further help in monetising additional benefits of pre-paid smart meters.
Further, the consumer's expectations for rebate on pre-payment are likely to be higher to entice their interest. This may not be financially sustainable for the utilities. Wider pre-paid metering should not reduce consumer interface as it not only helps the DISCOMs in providing better customer service but also helps in identifying meter bypassing undetectable to the pre-paid smart meters.
MoP: Revised EV Charging Infrastructure Guidelines
Tariff determination for EV charging infrastructure should either be based on a generic tariff to be determined by the respective SERC or based on a competitive bidding exercise.
In the absence of any specific guidelines, operationalizing the 'priority' for installation of public charging stations given to existing retail outlets of oil marketing companies would be difficult and may result in restrictive environment for the new entrants.
CERC: Draft Methodology for Estimation of Electricity Generated from Biomass Co-fired Thermal Power Plants
CER estimated the biomass consumption across ISGS plants to range from 8.79 MT to 17.58 MT based on 5-10% biomass blending. This seems feasible as agriculture sector produces about 140 MT of surplus biomass. It is estimated that 92 MT of agricultural residue is burnt annually leading to serious environmental implications
Biomass blending will help in reducing stubble burning by providing greater economic benefits for agriculture residue to the farmers if appropriate supply chain is established to ensure higher recovery of agricultural residue and its pelletization. This will eventually reduce air pollution and coal consumption. However, overall fuel cost may increase on account of transportation, pellet conversion and storage of biomass pellets. (Clause 1)
This scheme should be primarily extended to the thermal power plants located in areas with abundance of available agricultural residue to avoid deforestation. Further, pellets based on agricultural residue or biomass waste from industries dependent on commercial plantation should be promoted. (Clause 1)
If energy generated through biomass source is to be used towards RPO compliance, third party inspection and measurement of GCV for biomass used by a NABL approved laboratory should also be considered. (clause 5)
CSERC (Grid Interactive Distributed Renewable Energy Sources) Regulations, 2019
While net metering provides adequate incentive to the consumers by displacing energy from high tariff slabs, it impacts financial health of the DISCOM. Pay-out for excess energy injected at lowest competitively discovered tariff for grid-connected solar PV ameliorates this impact. However, this should be adjusted for network losses (Clause 11(c))
In case of unavailability of competitively discovered tariff by DISCOM for the state, the lowest SECI discovered tariff for such projects across neighbouring states with similar solar insolation should be considered. (Clause 11(c))
Wheeling and banking charges and settlement period should also be specified in the regulation.
Green energy generated and consumed by the consumers, who are not obligated entities, would be counted towards RPO of the DISCOM. The framework does not compensate consumers for value of embedded REC. Given the inherent value of such RE procurement to the DISCOM, and to encourage rooftop RE deployment, DISCOMs should provide 50% of floor price of REC to the consumers as an incentive. (Clause 7.1)
CSERC (Standard of Performance in Distribution of Electricity) Regulation, 2019 [Draft]
Alternatively, the DISCOM may like to demarcate each feeder and consumers connected to it as a business unit, whereby SoPs within the business unit can be monitored. A SoP index for such business units, developed on the basis of key performance parameters, should be used for implementing a penalty/incentive framework for the associated employees. The SoP index should include key performance indicators such as distribution loss, collection efficiency, SAIFI, SAIDI and other parameters reflecting performance against the SoP. (Clause 3.1)
Given that DISCOM would manage a system of complaint registration and follow thereof, such a system should have a mandatory audit trail with due communication (SMS/email) to the consumers. Further, SoP audit by independent third parties such as CPRI, ERDA or other NABL approved laboratories, research institutions would instil consumer confidence. (Clause 4.1)
Compensation recovery from the concerned employees would increase accountability in the system. However, it poses challenges for its implementation, especially in the absence of 100% mapping of roles and responsibilities across the distribution business and amenability of such a database to judiciously fix accountability against individual SoP. (Clause 4.4, 5.1)
A summarized version of SoP should be printed on backside of consumer's electricity bill to spread awareness. (Clause 6)
The commission may periodically review the current level of performance and setup multi-year benchmarks for SoP. (Clause 6.1)
Details of compensation claimed along with that payable/paid to consumers for complaints against failure to meet each type of SoP, should be available on the website of the respective DISCOMs and be reported to the CSERC on a quarterly basis. (Clause 6.1)
DERC Business Plan Regulations 2019
SBI MCLR varies based on the tenure of the loan, and applicability of appropriate MCLR needs to be specified. thFurther, it is now reported on 10 of every month. The regulation, which suggests use of MCLR at the beginning of the month, may like to take this into account and do the needful. (Clause 5, 14, 22)
Any refund towards Advance Taxes paid should be considered while grossing up the RoE in true-up to follow.
Clause 9 (1) offering PLF based incentives cannot be easily operationalized based on normative annual PLF. Thus, differentiation on account of peak and off-peak hours should be avoided. Also, the incentive mandated for excess generation, if continued should be retained at the previous level to reduce burden on consumers. Further, a differential incentive for the peak and off-peak hours may also alters the relative value of plant availability during peak hours with respect to other hours of the day.
In the case of increase in “Scheduled Generation” beyond NAPLF due to the URS scheduled for other beneficiaries or as a result of the outcome of SCED, the above incentive will place additional burden on power procurement cost. (Clause 9(1))
Sharing of gains from improvement in operational parameters, which is ascribed to be specified in BPR Regulation 2019, and clause 149 of the DERC (Terms and Conditions for Determination of Tariff) Regulations, 2017, in turn, refers to BPR 2017. The information gap needs to be addressed. (Clause 10(1))
Introduction of 85% limit in RPO is encouraging for the sector. Flexibility in meeting RPO compliance would bring in economic efficiency to the obligated entities to achieve these targets. Given that the competitively bid tariffs for solar and wind power procurement are converging, this differentiation may be relaxed in future. (Clause 27(1))
Volume 02 Issue 04 (Apr 2020)
CERC: Determination of Forbearance Price and Floor Price for the REC Frameworlx
As the proposed REC floor price for so1ar/non-solar RECs is zero, reference to floor price as a part of REC framework under the principle REC Regulations may be amended.
As the floor price and forbearance price for both solar and non-solar technologies are proposed to be uniform, it is an appropriate time to merge solar and non-solar REC markets.
Given that SERCs are allowing excess solar(non-solar) RPO quantum to be adjusted against non-solar(solar) RPO, fungibility between solar and non-solar RECs is clearly visible and should be institutionalised.
APERC (Terms and Conditions of Open Access) Second Amendment Regulation, 2o20
Consonance with the Electricity Act 2003: Removal of the preferential benefit to RE based generation and open access (OA) would not be in line with the Section 86 of the Electricity Act2003.
Making RE more Accountable to the Grid: Given the intermittency issues with increasing RE injection, which can be addressed by improving forecasting techniques for RE resources along with gradual tightening of deviation settlement mechanism can help ameliorate this impact to some extent. Further, to limit the impact of variability and intermittency, strict band for forecasting error and the associated deviation penalty structure could be adopted under APERC (Forecasting, Scheduling and Deviation Settlement) Regulation, 2017.
Role of Storage: The enhanced framework for RE forecasting and penalty deviation would also provide room for innovation and adoption of grid connected storage, as they become more economical in future..
GERC: Tariff Frameworlx for Procurement of Power by DISCOM and Others from Solar Projects
and Other Commercial Issues
Regulatory Lag in Determining Tariff: Regulated tariff determination often lags to follow the competitive one due to the inherent nature of the regulatory process and the dynamic market situation. Decline in the competitively determined solar bids needs to be reflected in the regulated prices once feasible. Linking of the ’regulated’ price for projects below 5 MW to the competitively derived one would address the underlying lag.The discussion paper lacks sufficient clarity due to multiple confounding statements. Nevertheless, CER concludes that the tariff for the projects below 5 MW is to be linked to the competitively determined tariff for projects above 5 MW during the previous six months (as per defined block of months).
Diseconomies of Scale for Small Projects: Small projects (below 5 MW) have significant diseconomies of scale leading to high cost of installation, financing as well as operation and maintenance (O&M) cost. A decline in tariff for larger projects has primarily been on account of decline in the project cost and the financing costs. Smaller projects have proportionately smaller share of Engineering Procurement and Construction (EPC) cost as compared to larger ones. Hence, a decline in competitively bid prices are not directly replicable for smaller projects.
Linking Regulated Tariff to Competitively Determined Prices: The mark-up between the feed-in-tariffforlarger (> 5 MW) and smaller(ñ 5 MW) Solar PV projects is about 24%. The tariff for small solar PV projects can be pegged a bit higher than the prevailing mark-up, which should be gradually reduced in future to enable project developers to adopt innovative procurement, financing and project management practices.
The 'estimated' regulated price for smaller projects (5 MW) for 2017 (T3.27) would have been less than half of the regulated price. The mark-up relationship may not be linear and,hence, needs to be studiedlater.
An Alternate Solution - Competitive Market for Smaller PV Projects: Considering, the uncertainty associated with the mark-up relationship between regulated and competitively determined tariff, the aim should be to nurture a competitive market by bundling a large number of small scale projects deriving economies of scale in procurement, financing and implementation.