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					</table>The Telangana Electricity Regulatory Commission (<a href="https://www.tgerc.telangana.gov.in/" target="_blank" rel="noopener">TGERC</a>) has issued the Draft Telangana Electricity Regulatory Commission (Framework for Resource Adequacy) Regulations, 2025, outlining a comprehensive 10-year framework for demand forecasting, generation planning, and procurement.
The draft notification sets out procedures for assessing future load requirements and ensuring the state maintains sufficient firm capacity to meet its share of the national peak demand.
Purpose and Scope
The primary objective is to create a uniform Resource Adequacy (RA) framework enabling the state to meet projected electricity demand reliably while integrating renewable energy, storage, and demand response.
The framework mandates a 10-year planning horizon on an annual rolling basis, with distribution companies (DISCOMs) required to prepare long-term distribution licensee resource adequacy plan (LT-DRAP), medium-term (MT-DRAP), and short-term (ST-DRAP) resource adequacy plans.
Demand Assessment and Forecasting
The draft mandates DISCOMs to undertake hourly or sub-hourly demand forecasting using methodologies compliant with Central Electricity Authority guidelines. Forecasting techniques may include trend analysis, end-use and partial end-use models, autoregressive integrated moving-average (ARIMA) models, artificial intelligence/machine learning/artificial neural network-based models, and econometric tools.
The models must disclose parameters, data sources, and algorithmic processes. DISCOMs must select the methods with the highest R², which quantifies the predictive accuracy of a statistical model, and the lowest standard deviation for each consumer category.
Inputs must include weather data, demographic trends, consumption profiles, agricultural patterns, festival impacts, and the load-shifting effects of policies such as demand-side management (DSM), distributed energy resources, electric vehicle charging, open access, and time-of-day tariffs.
DISCOMs must submit the previous year’s category-wise consumption data to the state load dispatch center (SLDC) by April 21 each year, while the SLDC must provide DSM accounts by the same date. DISCOMs must prepare ST, MT, and LT demand forecasts on a rolling basis using historical and policy-linked variables.
The state transmission utility (STU), with SLDC assistance, must estimate state demand and aggregate DISCOM forecasts, submitting annual projections in MW and million units to the CEA, national load dispatch center, and state load dispatch center by May 31 each year.
Generation Resource Planning
Generation resource planning must incorporate technical and operational characteristics of all existing and upcoming plants, including heat rates, auxiliary consumption, generation limits, ramp rates, start-up times, availability factors, capacity utilization factor for renewables, historical forced outages, planned maintenance, gestation periods, and plant lifetimes.
Renewable Purchase Obligation targets, energy storage obligations, and emissions constraints must also be factored in. DISCOMs must provide complete data for all resources to SLDC and STU.
Capacity Crediting
The regulations prescribe a detailed capacity crediting (CC) methodology using a net-load approach based on chronological hourly data. Gross load is arranged in descending order, followed by the computation of net load after subtracting actual solar and wind generation.
Capacity credit is derived from renewable output during the top 250 load hours, averaged over five years after excluding abnormal years involving natural disasters or force majeure. Hydro CCs must reflect water availability, while thermal CCs must account for coal supply and outage rates.
DISCOMs must submit CC calculations and justifications to SLDC by May 21, and SLDC will compute state-specific CC factors and share them with the national authorities by May 31 every year.
Planning Reserve Margin
Planning Reserve Margin (PRM) must comply with CEA reliability indices based on loss of load probability and normalized energy not served. PRM defines additional capacity required beyond the state’s coincident share in the national peak demand.
SLDC will prepare a 10-year LT-DRAP by incorporating constraints and factoring CC values, PRM, planned retirements, forced outages, and unit-wise generation limits.
SLDC must submit the LT-DRAP to the CEA for validation by September 30 and to the Commission within 15 days of CEA approval. The Commission must approve the plan within 30 days.
DISCOMs must demonstrate 100% capacity tie-up for Year 1 and at least 90% tie-up for Year 2 to meet their share of the national peak. Only contracted resources, long-term, medium-term, or short-term, may be counted. For the next three years, DISCOMs must furnish procurement plans for approval.
Procurement Planning and PPA Approval
The draft mandates least-cost optimization modelling for procurement decisions and requires DISCOMs to balance long-term contracts with medium- and short-term sources.
Contracting must consider resource gestation, grid integration, congestion, stranded asset risks, and consumer tariff impacts. Procurement may be through state or central generating stations, IPPs, CPPs, renewable units, traders, aggregators, exchanges, or bilateral arrangements.
Storage procurement must follow the Ministry of Power tariff-based competitive bidding guidelines. All new or modified long-term and medium-term power purchase agreements require prior approval from the Commission, which will assess necessity, cost, efficiency, and equity. DISCOMs may enter short-term contracts during exigencies but must report details within 15 days.
Monitoring and Compliance
SLDC will monitor adherence to resource adequacy plans and short-term DRAPs, reviewing data daily, monthly, and quarterly. The Commission may levy non-compliance charges, with specifics to be notified later.
The regulations impose extensive data requirements, including 10 years of historical consumption, weather, demographic variables, hourly load patterns, and policy-driven adjustments
Monthly, weekly, day-ahead, and intra-day procurement data must be published on DISCOM and SLDC websites within 45 days, along with Merit Order Dispatch stacks.
DISCOMs must set up a resource adequacy planning cell within three months of the regulations taking effect and a 24×7 procurement cell within 45 days. They must coordinate with central and state generators, STU, SLDC, CEA, and NLDC for availability projections and pricing.
Recently, the Telangana Electricity Regulatory Commission <a href="https://www.mercomindia.com/telangana-removes-nighttime-tod-rebate-for-december-march-period" target="_blank" rel="noopener">approved</a> amendments to the time-of-day tariff structure for the Southern Power Distribution Company and the Northern Power Distribution Company.
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Telangana Issues Draft Resource Adequacy Regulations

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					</table>The Telangana Electricity Regulatory Commission (<a href="https://www.tgerc.telangana.gov.in/" target="_blank" rel="noopener">TGERC</a>) has approved amendments to the time-of-day (ToD) tariff structure for the Southern Power Distribution Company and the Northern Power Distribution Company.
Under the revised structure, the 22:00–06:00 ToD tariff over retail supply energy charges will be zero from December 1, 2025, to March 31, 2026, replacing the earlier ₹1.50 (~$0.017)/kWh that was applicable for April–November of the financial year (FY) 2025–26.
Surcharges of ₹1 (~$0.011)/kWh during the 06:00–10:00 and 18:00–22:00 peak time slots remain unchanged for the full FY 2026.
These ToD tariffs apply to HT-I(A) Industrial and Poultry, HT-II(A) Others, HT-II(B) Wholly Religious Places, HT-III (Airports, Railway Stations, Bus Stations), and HT-IX electric vehicle charging stations.
Background
The two power distribution companies (DISCOMs) had filed petitions in August 2025 seeking changes to the ToD tariffs approved earlier in the retail supply tariff. They requested that the existing night-time incentive be removed, citing higher power purchase costs during night hours, increased reliance on costlier thermal and market purchases, and delays in commissioning units of the Yadadri Thermal Power Station.
They argued that the incentive was resulting in significant revenue outflow and that daytime availability, particularly from solar sources, was substantially higher than nighttime availability.
Stakeholders raised objections on several grounds, including the maintainability of the petitions under Section 62(4) of the Electricity Act, 2003, which ordinarily restricts tariff amendments within a financial year.
They also stated that industries had already planned operations based on the announced tariff structure, that the ToD rebate would support demand-side management by encouraging nighttime usage, and that continuous-process industries would be adversely affected.
Some stakeholders contended that the existing ToD structure was essential for grid stability and that the DISCOMs had not provided adequate technical data to justify the change.
In response, the DISCOMs submitted that the proposal was their first amendment request for the financial year and therefore did not constitute a violation of Section 62(4). They reiterated that nighttime procurement costs were higher than daytime costs, that the rebate was no longer aligned with prevailing system conditions, and that detailed load curves, hourly power purchase data, and technical analyses were placed before the Commission.
The DISCOMs also pointed out that solar generation, comprising nearly 9,800 MW of utility-scale plus around 1,000 MW of rooftop solar, creates surplus daytime availability that can absorb load shifts from night hours.
Commission’s Analysis
The Commission observed that daytime energy availability exceeded demand, while nighttime procurement relied more on costlier sources. It noted that delays in the commissioning of Yadadri Thermal Power Station had reduced expected night-time availability, requiring additional market purchases.
It noted that the earlier incentive of ₹1.50 (~$0.017)/kWh during 22:00 to 06:00 had led to substantial revenue outflows for the DISCOMs. It found that daytime solar generation was sufficient to meet the morning and evening peaks, based on the submitted load curves.
The Commission noted that morning peaks occur around 08:00 and evening peaks around 17:00, both periods adequately served by daytime solar generation. The power purchase cost charts submitted by the DISCOMs showed that the cost per unit during the 22:00 to 06:00 time slot was consistently higher than during the 06:00 to 10:00 and 10:00 to 18:00 time slots.
The regulator held the amendment request did not violate Section 62(4), since the DISCOMs had sought no tariff revision during the original annual revenue requirement filing for FY 2026. It concluded that revising the ToD tariff was necessary to address the mismatch between availability and demand, contain revenue loss, and reduce dependence on high-cost power purchases.
The Commission added that continuing the ₹1.50 (~$0.017)/kWh rebate through March 2026 would result in major revenue deficits that would ultimately be passed on to consumers during the true-up process. It therefore viewed the amendment as both financially prudent and operationally justified.
Accordingly, the Commission approved the amendment to the ToD tariff. The rest of the tariff order issued in April 2025 also remains unaltered.
The Commission directed the DISCOMs to report the consequent revenue impact in their true-up petitions for FY 2026.
The Commission recently <a href="https://www.mercomindia.com/telangana-regulator-issues-rooftop-solar-regulations-2025-2/" target="_blank" rel="noopener">issued</a> the final regulations for grid-interactive rooftop solar, introducing a comprehensive framework governing metering for consumers in the state.
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Telangana Removes Nighttime ToD Rebate for December–March Period

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					</table>The Telangana Electricity Regulatory Commission (<a href="https://www.tgerc.telangana.gov.in/" target="_blank" rel="noopener">TGERC</a>) has issued the final regulations for grid-interactive rooftop solar, introducing a comprehensive framework governing metering for consumers in the state.
The framework titled Telangana Electricity Regulatory Commission (Rooftop Solar Photovoltaic (PV) Grid-Interactive Systems) Regulations, 2025 will apply to distribution licensees, eligible consumers, and third-party owners of rooftop solar PV systems.
Scope and Coverage
The regulations cover all rooftop solar systems operating under net metering, group net metering, gross metering, and virtual net metering. The interconnection must comply with standards specified by the Central Electricity Authority (CEA) under its 2013 connectivity regulations, 2023 safety regulations, and the Telangana State Electricity Grid Code Regulations, 2018.
Capacity Limits and Eligibility
Consumers across categories may install rooftop solar systems under net metering up to 500 kW. Existing consumers with systems above 500 kW will be allowed to continue availing net metering benefits.
Group net metering is permitted for systems below 100 kW, while gross metering is allowed up to 1 MW. Virtual net metering is permitted for less than 100 kW. A consumer cannot simultaneously avail of both net and gross metering or mix net, group, and virtual net metering.
Low tension – category I (domestic) and HT – category IV (townships and residential colonies) are allowed to use gross net metering for system capacities less than 100 kW.
The minimum project size is fixed at 1 kW for net and gross metering, and 10 kW for group and virtual net metering. For residential and government consumers, the maximum rooftop solar capacity under net and gross metering can be 100% of the sanctioned load.
For industrial, commercial, and other consumers, the cap is 80% of the sanctioned load or contracted demand. In group net metering, the capacity limit is the sum of contracted or sanctioned loads of parent and participating connections for residential and government consumers, and 80% of the same sum for commercial and industrial consumers.
In the event of a reduction in contracted demand leading to a mismatch with sanctioned rooftop capacity, the excess injected power is treated as inadvertent power. Consumers with pending arrears to the distribution licensee are not entitled to avail any metering arrangement under the regulation.
Open Access Eligibility
Consumers with net or gross metering are allowed open access. This is provided that the open access capacity, along with the rooftop capacity, is less than the contracted load.
Parent and participating consumers under gross or virtual net metering are also eligible for open access, with a similar cap based on their allocated rooftop capacity.
Exemptions and Charges
Prosumer systems under net and gross metering are exempt from banking charges, wheeling charges, cross-subsidy surcharge, and additional surcharge. Under group net metering, prosumers and participating connections are exempt from banking, cross-subsidy surcharge, and additional surcharge, but wheeling charges and losses will apply to participating connections.
Virtual net metering is exempt from banking charges, but cross-subsidy surcharge, additional surcharge, and wheeling charges will apply to participating consumers, along with wheeling losses.
These wheeling charges and wheeling losses are to be levied per the Wheeling Tariff Order terms.
Duration and Safety Requirements
The net, gross, group, or virtual net metering facility will be applicable for 25 years from the date of grid connection. Projects above 56 kW must be insured and certified for safety by the Chief Electrical Inspector within 15 working days of application.
The consumer can self-certify systems up to 56 kW. Consumers installing systems above 56 kW can connect to 11 kV or 33 kV feeders of their respective distribution licensee.
Distribution
The regulations impose capacity restrictions on distribution transformers and feeders. The cumulative capacity of all rooftop solar systems connected to a distribution transformer cannot exceed 50% of its rated capacity.
For high-tension (HT) consumers on 11 kV or 33 kV feeders, the cumulative rooftop solar capacity cannot exceed 50% of the feeder’s maximum load or the substation transformer capacity to which it is connected.
Distribution licensees must publish available transformer-wise and feeder-wise capacity on their websites within three months of notification and update the data quarterly.
Application Procedure
Net or gross metering applications must be filed in prescribed formats with a processing fee of ₹2,500 (~$29.07) for low tension consumers and ₹15,000 (~$174.42) for HT consumers. Parent consumers applying for group or virtual net metering must submit additional undertakings from participating connections.
The distribution licensee must acknowledge receipt within seven working days and complete the feasibility analysis within 15 working days. The feasibility report will remain valid for four months. Projects up to 10 kW are exempt from feasibility analysis and deemed approved.
Connectivity strengthening up to 5 kW will be borne by the distribution licensee. Consumers must install the system within 180 days of the feasibility report, after which the licensee will inspect and approve commissioning within 15 working days.
Connection agreements must be signed within 15 working days of work completion. Meters must be installed and systems commissioned within 15 working days thereafter.
Grid Interconnection
All systems must comply with CEA connectivity and metering standards and state grid code. Systems must be equipped with automatic synchronization, islanding protection, isolator switches accessible to distribution personnel, and meet International Electrochemical Commission power quality standards, including power factor requirements.
The distribution licensee can disconnect rooftop systems in emergencies or when operation adversely affects the grid. Overall safety responsibility rests with the consumer.
Energy Accounting and Settlement
For net metering, billing will show exported, imported, and net consumption. Surplus energy will be settled per the lowest tariff in the existing power purchase agreements (PPAs) of the distribution licensee. Imported energy will be billed at retail tariffs, and minimum charges will apply.
In group net metering, exports will be adjusted against parent and participating consumption per their agreement, with the surplus amount settled on the same basis. Allocation ratios can be revised once every financial year.
Under gross metering, all energy will be purchased by the licensee at the same lowest tariff benchmark. Consumers must pay a retail tariff for all imports. In virtual net metering, exports will be allocated among participating consumers with the surplus settled at the same tariff benchmark. Allocation can be changed annually.
Renewable Purchase Obligations
The regulation allows electricity consumed under net, gross, group, and virtual metering to be counted toward the renewable purchase obligations of the distribution licensee or obligated entities.
Metering Arrangements
All rooftop solar metering must use smart meters with advanced metering infrastructure and time-of-day capability. Net and group net metering require bi-directional smart meters, while gross and virtual net metering require solar generation meters. Distribution licensees are responsible for meter installation, testing, and maintenance.
Compensation, Incentives, and Inspection
Consumers are eligible for compensation if the distribution licensee fails to meet timelines, as per the TSERC Standards of Performance Regulations, 2016. Subsidies and incentives provided by the Ministry of New and Renewable Energy or the state government must be released within 30 working days by the nodal agency.
The distribution licensee may inspect rooftop systems, and non-compliant vendors can be blacklisted and their systems disconnected. Any panels or equipment additions require prior approval.
CDM Benefits Sharing
The regulation prescribes rules for the clean development mechanism (CDM) benefits. In the first year, 100% of CDM benefits accrue to the prosumer. From the second year, the distribution licensee’s share will increase by 10% annually until it reaches 50%.
Other Provisions
For defective meters, billing will be based on the average of the past three cycles, and they must be replaced within 15 days. Consumers must execute a rooftop solar connection agreement before commissioning.
The Commission can issue directions, remove difficulties, and amend the regulations, which will be reviewed every three years but continue in force until modified.
In April this year, TGERC <a href="https://www.mercomindia.com/telangana-approves-procurement-of-4-gw-solar-power-under-pm-kusum" target="_blank" rel="noopener">approved</a> the procurement of 4,000 MW of solar power and the associated PPAs from projects under Component-A of the Pradhan Mantri Kisan Urja Suraksha evam Utthaan Mahabhiyan.
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Telangana Electricity Regulator Issues Rooftop Solar Regulations 2025

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					</table>The Telangana Electricity Regulatory Commission (<a href="https://www.tgerc.telangana.gov.in/" target="_blank" rel="noopener">TGERC</a>) has issued draft regulations for grid-interactive rooftop solar, introducing a comprehensive framework governing metering for consumers in the state.
The framework titled Telangana Electricity Regulatory Commission (Rooftop Solar Photovoltaic (PV) Grid-Interactive Systems) Regulations, 2025 will apply to distribution licensees, eligible consumers, and third-party owners of rooftop solar PV systems.
Scope and Coverage
The regulations cover all rooftop solar systems operating under net metering, group net metering, gross metering, and virtual net metering. The interconnection must comply with standards specified by the Central Electricity Authority (CEA) under its 2013 connectivity regulations, 2023 safety regulations, and the Telangana State Electricity Grid Code Regulations, 2018.
Capacity Limits and Eligibility
Consumers across categories are permitted to install rooftop solar systems under net metering up to 500 kW. Existing consumers who already have systems above 500 kW will be allowed to continue availing net metering benefits.
Group net metering is permitted for systems below 100 kW, while gross metering is allowed up to 1 MW. Virtual net metering is permitted for less than 100 kW. A consumer cannot simultaneously avail both net and gross metering or mix net, group, and virtual net metering.
The minimum project size is fixed at 1 kW for net and gross metering, and 10 kW for group and virtual net metering. For residential and government consumers, the maximum rooftop solar capacity under net and gross metering can be 100% of the sanctioned load.
For industrial, commercial, and other consumers, the cap is 80% of the sanctioned load or contracted demand. In group net metering, the capacity limit is the sum of contracted or sanctioned loads of parent and participating connections for residential and government consumers, and 80% of the same sum for commercial and industrial consumers.
In the event of a reduction in contracted demand leading to a mismatch with sanctioned rooftop capacity, the excess injected power is treated as inadvertent power. Consumers with pending arrears to the distribution licensee are not entitled to avail any metering arrangement under the regulation.
Restrictions
The regulations bar consumers availing net or gross metering from simultaneously accessing open access under the TGERC Open Access Regulations, 2024.
Consumers under group and virtual net metering are also barred from open access, though wheeling of energy between parent and participating connections is allowed, subject to wheeling charges and losses.
Third-party sale of rooftop power outside such arrangements is prohibited.
Exemptions and Charges
Prosumer systems under net and gross metering are exempt from banking charges, wheeling charges, cross-subsidy surcharge, and additional surcharge. Under group net metering, prosumers and participating connections are exempt from banking, cross-subsidy surcharge, and additional surcharge, but wheeling charges and losses will apply to participating connections.
Virtual net metering is exempt from banking charges, but cross-subsidy surcharge, additional surcharge, and wheeling charges will apply to participating consumers, along with wheeling losses.
These losses will be calculated on the lower voltage level between the parent and participating consumers.
Duration and Safety Requirements
The net, gross, group, or virtual net metering facility will be applicable for 25 years from the grid connection date. Projects above 75 kW must be insured and certified for safety by the Chief Electrical Inspector within 15 working days of application.
The consumer can self-certify systems up to 75 kW. Consumers installing systems above 75 kW can connect to 11 kV or 33 kV feeders of their respective distribution licensee.
Distribution
The regulations impose distribution transformer and feeder level capacity restrictions. The cumulative capacity of all rooftop solar systems connected to a distribution transformer cannot exceed 50% of its rated capacity.
For high-tension (HT) consumers on 11 kV or 33 kV feeders, the cumulative rooftop solar capacity cannot exceed 50% of the feeder’s maximum load or the substation transformer capacity to which it is connected.
Distribution licensees must publish available transformer-wise and feeder-wise capacity on their websites within three months of notification and update the data quarterly.
Application Procedure
Net or gross metering applications must be filed in prescribed formats with a processing fee of ₹2,500 (~$29.07) for low tension consumers and ₹15,000 (~$174.42) for HT consumers. Parent consumers applying for group or virtual net metering must submit additional undertakings from participating connections.
The distribution licensee must acknowledge receipt within seven working days and complete the feasibility analysis within 15 working days. The feasibility report will remain valid for four months. Projects up to 10 kW are exempt from feasibility analysis and deemed approved.
Connectivity strengthening up to 5 kW will be borne by the distribution licensee. Consumers must install the system within 180 days of the feasibility report, after which the licensee will inspect and approve commissioning within 15 working days.
Connection agreements must be signed within 15 working days of work completion. Meters must be installed and systems commissioned within 15 working days thereafter.
Grid Interconnection
All systems must comply with CEA connectivity and metering standards and state grid code. Systems must be equipped with automatic synchronization, islanding protection, isolator switches accessible to distribution personnel, and meet International Electrochemical Commission power quality standards, including power factor requirements.
The distribution licensee can disconnect rooftop systems in emergencies or when operation adversely affects the grid. Overall safety responsibility rests with the consumer.
Energy Accounting and Settlement
For net metering, billing will show exported, imported, and net consumption. Surplus energy will be settled at the lower of the tariff discovered in the solar competitive bidding or the lowest tariff in the existing power purchase agreements (PPAs) of the distribution licensee. Imported energy will be billed at retail tariffs, and minimum charges will apply.
In group net metering, exports will be adjusted against parent and participating consumption per their agreement, with the surplus amount settled on the same basis. Allocation ratios can be revised once every financial year.
Under gross metering, all energy will be purchased by the licensee at the same lowest tariff benchmark. Consumers must pay a retail tariff for all imports. In virtual net metering, exports will be allocated among participating consumers with the surplus settled at the same tariff benchmark. Allocation can be changed annually.
Renewable Purchase Obligations
The regulation allows electricity consumed under net, gross, group, and virtual metering to be counted toward the renewable purchase obligations of the distribution licensee or obligated entities.
Metering Arrangements
All rooftop solar metering must use smart meters with advanced metering infrastructure and time-of-day capability. Net and group net metering require bi-directional smart meters, while gross and virtual net metering require solar generation meters. Distribution licensees are responsible for meter installation, testing, and maintenance.
Compensation, Incentives, and Inspection
Consumers are eligible for compensation if the distribution licensee fails to meet timelines, as per the TSERC Standards of Performance Regulations, 2016. Subsidies and incentives provided by the Ministry of New and Renewable Energy or the state government must be released within 30 working days by the nodal agency.
The distribution licensee may inspect rooftop systems, and non-compliant vendors can be blacklisted and their systems disconnected. Any panels or equipment additions require prior approval.
CDM Benefits Sharing
The regulation prescribes rules for the clean development mechanism (CDM) benefits. In the first year, 100% of CDM benefits accrue to the prosumer. From the second year, the distribution licensee’s share will increase by 10% annually until it reaches 50%.
Other Provisions
For defective meters, billing will be based on the average of the past three cycles, and they must be replaced within 15 days. Consumers must execute a rooftop solar connection agreement before commissioning.
The Commission can issue directions, remove difficulties, and amend the regulations, which will be reviewed every three years but continue in force until modified.
In April this year, TGERC <a href="https://www.mercomindia.com/telangana-approves-procurement-of-4-gw-solar-power-under-pm-kusum" target="_blank" rel="noopener">approved</a> the procurement of 4,000 MW of solar power and the associated PPAs from projects under Component-A of the Pradhan Mantri Kisan Urja Suraksha evam Utthaan Mahabhiyan.
Subscribe to Mercom’s real-time <a href="https://mercomindia.com/product/mercoms-renewable-energy-regulatory-updates/" target="_blank" rel="noopener">Regulatory Updates</a> to ensure you don’t miss any critical updates from the renewable industry.

Telangana Regulator Issues Draft Rooftop Solar Regulations 2025

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					</table>The Telangana Electricity Regulatory Commission (<a href="https://www.tgerc.telangana.gov.in/" target="_blank" rel="noopener">TGERC</a>) has approved the procurement of 4,000 MW of solar power and the associated power purchase agreements (PPAs) from projects under Component-A of the Pradhan Mantri Kisan Urja Suraksha evam Utthaan Mahabhiyan (PM-KUSUM).
Background
The Southern and Northern Power Distribution Company of Telangana filed a petition seeking approval to procure 4,000 MW of solar power under Component-A of the PM-KUSUM program for 25 years.
The Commission conducted a public hearing held on April 17, 2025, attended by 77 stakeholders. Of these stakeholders, 20 submitted their feedback.
A key concern was that the Ministry of New and Renewable Energy initially approved allocating 4,000 MW of decentralized solar power under Component-A of PM KUSUM, but later revised it to 1,000 MW.
Concerns were also raised about challenges in identifying sufficient land to set up substations for larger capacities. Some stakeholders suggested a revision of the prefixed tariff of ₹3.13 (~$0.037)/kWh due to increased project costs, currency depreciation, and financing challenges.
Another concern was about the capacity utilization factor (CUF) of 19%, which stakeholders said was excessive given Telangana’s solar conditions. They sought a more attainable CUF target or flexible penalties.
The stakeholders also requested the Commission grant the expression of interest (EoI) and the Model Lease Agreement to procure the 4,000 MW of decentralized power.
Commission’s Analysis
TGERC acknowledged the stakeholders&#8217; concerns about capacity, land allocation, and the tariff issue. It maintained the prefixed levelized tariff, emphasizing that tariff stability will avoid disrupting ongoing projects.
It observed that since modifying tariffs might disturb stakeholders, it postponed any adjustments.
The Commission also found that Telangana will face an energy deficit from the financial year (FY) 2028 onwards. It noted that although the state had a surplus for FY 25 and FY 26, it was only available in certain blocks.
Regarding procedural and implementation challenges, the Commission directed Telangana Renewable Energy Development Corporation (TGREDCO) and the state’s distribution companies (DISCOMs) to prepare and publish the ‘frequently asked questions’ and ‘standard operating procedures’ addressing all raised issues in English and Telugu on their websites.
It also encouraged forming coordination committees and single-window clearance systems to streamline project implementation and support farmers effectively. The Commission noted that TGREDCO would convene meetings with solar power generators to clarify concerns.
The Commission highlighted the necessity for a comprehensive strategy concerning substation capacity allocation and instructed the DISCOMs to implement measures to effectively absorb generated power, minimize reverse power flow, and ensure grid stability.
TGERC approved the procurement of 4,000 MW solar power and the associated PPAs while denying post-facto approval for the EoI and the Model Lease Agreement since it is outside its jurisdiction.
In December last year, TGERC <a href="https://www.mercomindia.com/telangana-new-procedure-captive-plants" target="_blank" rel="noopener">issued</a> a comprehensive procedure for verifying the status of captive power-generating projects and their associated captive users within the state.
Subscribe to Mercom’s real-time <a href="https://mercomindia.com/product/mercoms-renewable-energy-regulatory-updates/" target="_blank" rel="noopener">Regulatory Updates</a> to ensure you don’t miss any critical updates from the renewable industry.

Telangana Approves Procurement of 4 GW Solar Power Under PM-KUSUM

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					</table>The Telangana Electricity Regulatory Commission (<a href="https://www.tgerc.telangana.gov.in/" target="_blank" rel="noopener">TGERC</a>) has issued a comprehensive procedure for verifying the status of captive power generating plants (CGPs) and their associated captive users within the state.
The Commission <a href="https://www.mercomindia.com/telangana-issues-power-plant-verification" target="_blank" rel="noopener">issued</a> a detailed draft procedure in September.
Key Objectives and Applicability
The primary objective of this procedure is to verify the status of CGPs and captive users located in Telangana.
This procedure applies to:
<ul>
<li>All power plants and end users seeking verification of their CGP and captive user status.</li>
<li>Distribution licensees submitting consolidated annual reports to the Commission by June 30th each year.</li>
</ul>
The procedure is grounded in several key legal provisions, including:
<ul>
<li>Section 2 of the Electricity Act, 2003, which defines critical terms such as &#8220;captive generating plant,&#8221; &#8220;generating company,&#8221; and &#8220;generating station.&#8221;</li>
<li>Section 9 of the Act, which outlines the rights and regulations governing captive generation.</li>
<li>The Electricity Rules, 2005, which set the criteria for a plant to be recognized as a captive generating plant (CGP).</li>
</ul>
Ownership Criteria
<ul>
<li>For a single captive user: Not less than 26% of the ownership with voting rights must be held by the captive user throughout the year.</li>
<li>For cooperative societies: Members must collectively satisfy not less than 26% ownership throughout the year.</li>
<li>For Association of Persons (AoP): Captive users must hold in aggregate not less than 26% of the ownership or paid-up equity share capital with voting rights throughout the year.</li>
<li>For Special Purpose Vehicles (SPV) or companies: Captive users must hold in aggregate not less than 26% of the proportionate paid-up equity share capital with voting rights of the units identified for captive use.</li>
<li>For a partnership firm, the ownership must represent at least 26% proprietary interest and control over the generating station or power plant. Additionally, the consumption of energy generated must be at least 51% on an annual basis, according to this procedure.</li>
</ul>
Consumption Criteria
<ul>
<li>For single captive users: Consumption should not be less than 51% of the net electricity generated annually.</li>
<li>For cooperative societies: Members must collectively consume not less than 51% of the net electricity generated annually.</li>
<li>For AoPs: Captive users shall consume not less than 51% of the electricity generated, in proportion to their ownership contribution, within a variation not exceeding 10%</li>
<li>For SPVs, captive users must consume at least 51% of net electricity generated annually, in proportion to their shares in identified captive units, within a 10% variation. For LLP/partnership firms, captive users must consume at least 51% of net electricity generated annually.</li>
</ul>
Verification Process
<ul>
<li>CGPs must submit an application with requisite documents to the distribution licensee in their area by May 31st each year.</li>
<li>The distribution licensee may seek clarifications from the CGP or captive user regarding the submitted information.</li>
<li>A consolidated report is to be submitted by the distribution licensee to the Commission by June 30th.</li>
<li>TGERC may seek additional clarifications if needed.</li>
<li>The verification process should be completed within two months of receiving the consolidated report</li>
</ul>
Metering and Technical Considerations
<ul>
<li>Each CGP unit must have a separate interface meter with real-time communication capabilities.</li>
<li>Technical losses in the electrical network and energy storage systems are to be included in the energy consumption calculations of captive users.</li>
<li>The aggregate energy generated from a CGP unit is calculated as gross energy generated minus auxiliary consumption</li>
</ul>
If a CGP fails to meet the required conditions in a given financial year, the generating plant will no longer qualify as a CGP, and the captive user will lose its status as a captive user.
However, this cessation is applicable only to the specific financial year in question.
Mercom earlier <a href="https://www.mercomindia.com/regulations-delays-telangana-open-access-solar" target="_blank" rel="noopener">reported</a> that at a time when solar open-access installations are gaining traction across the country, developers with small-capacity projects in Telangana say the inordinate delay in adhering to regulatory frameworks by distribution companies is creating bottlenecks.
Subscribe to Mercom’s real-time <a href="https://mercomindia.com/product/mercoms-renewable-energy-regulatory-updates/" target="_blank" rel="noopener">Regulatory Updates </a>to ensure you don’t miss any critical updates from the renewable industry.

Telangana Unveils New Procedure for Verifying Captive Generating Plants

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					</table>The Telangana State Electricity Regulatory Commission (<a href="https://www.tgerc.telangana.gov.in/" target="_blank" rel="noopener">TGERC</a>) has allowed an additional surcharge of ₹1.09 (~$0.012)/kWh for open access consumers for the second half (2H) of the financial year (FY) 2024-25.
The additional surcharge will be levied on the quantity of electricity scheduled.
The additional surcharge will not apply to open access consumers wheeling power from their captive power projects.
Background
In a suo motu order issued on September 18, 2020, the Commission told distribution companies (DISCOM) to submit filings to determine the additional surcharge for the first half of the year.
Accordingly, the DISCOMs filed a petition to determine an additional surcharge for 2H FY 2025 (October 2024 to March 2025.)
The DISCOMS filed the mechanism for determining stranded capacity, along with the approved methodology and terms and conditions for levying an additional surcharge on open access users, to meet their fixed cost commitment arising from its supply obligations.
The DISCOMs said that the average stranded capacity due to open access consumers for the six months (October 2023 to March 2024) considering the 15-minute block-wise data, is 23.21 MW.
The fixed charges paid to the generators are ₹63.92 billion (~$761.24 million) in 2H FY 2024, and the average long-term available capacity is 9093.12 MW. The average fixed charges are ₹7 million (~$83,365)/MW.
Accordingly, the fixed charges for a stranded capacity of 23.21 MW work out to ₹163.1 million (~$1.94 million).
The transmission charges paid by the DISCOMs for 2H FY 2024  are ₹31.98 billion (~$380.86 million), and the scheduled energy for that period is 46040.41 MU. The actual transmission cost is ₹0.69 (~$0.008)/kWh.
The HT distribution wheeling charges computed per the Commission&#8217;s directions in the additional surcharge order for 2H of FY 2025 work out to ₹0.17 (~$0.002)/kWh.
The total T&amp;D costs are ₹0.87(~$0.002)/kWh.
The demand charges recovered by the DISCOMs from open access consumers are ₹1.61 billion (~$19.17 million).
The Commission directed the DISCOMs to exclude revenue recovery for the LT network since the distribution charges of the LT network are not considered on the expenditure side. Accordingly, net demand charges considered in additional surcharge calculations work out to ₹1.19 billion (~$14.17 million).
The demand charges are to be adjusted/(recovered) from open access consumers for a total of ₹57.3 million (~$682,409).
The net stranded charges of ₹105.9 million (~$1.26 million) are considered for calculating the additional surcharge.
The projected open access sales for 2H FY 2024 are 66.05 MU pertaining to open access sales other than captive transactions for the period between October 2023 to April 2024.
Accordingly, the DISCOMs requested the Commission to approve the additional surcharge of ₹1.60 (~$0.019)/kWh for 2H FY 2025.
Commission’s analysis
The commission approved the long-term available capacity of 9093.12 MW as proposed by the DISCOMs.
The commission observed that the DISCOMs followed the approved methodology of the average 15-minute time-block data over six months.
However, the Commission approves the stranded capacity due to open access as 25.19 MW, against the DISCOMs’ claim of 23.21 MW.
The DISCOMs claimed that the fixed charges paid from October 2023 to March 2024 amounted to ₹63.92 billion (~$761.24 million).
After reconciliation with audited annual accounts and deducting the fixed charges of ₹59.48 billion (~$708.37 million), which were already considered for 1H FY 2025, the Commission considered the fixed charges paid as ₹60.26 billion (~$717.66 million) for 2H of FY 2025. The long-term available capacity is 9093.12 MW, resulting in average fixed charges of ₹6.63 million (~$78,968)/MW.
Accordingly, the fixed charges for stranded capacity have been computed as ₹166.9 million (~$1.98 million).
The Commission refuted DISCOM&#8217;s claims that fixed charges would vary as the fixed charges paid were recruited.
It determined the transmission charges paid by the DISCOMs to be ₹30.66 billion (~$365.14 million) against ₹31.98 billion (~$380.86 million), with the scheduled energy remaining at 46040.41 MU. Consequently, the transmission charges have been calculated as ₹0.666 (~$0.007)/kWh.
The total transmission and distribution charges are ₹0.8396 (~$0.01)/kWh.
The transmission and distribution charges payable by the open access consumers work out to ₹1.1 billion (~$13.10 million).
The commission noted that the DISCOMs&#8217; demand charges from open access consumers amount to ₹1.61 billion (~$19.17 million). Following the Commission’s directions, the DISCOMs excluded the revenue recovery related to the LT network from the total demand charges recovered from open access consumers and claimed ₹1.19 billion (~$14.17 million) as net demand charges.
The demand charges to be adjusted/(recovered) from open access consumers total ₹94.7 million (~$1.12 million).
Based on the changes in the demand charges, the net stranded charges are ₹72.2 million (~$859,859).
The Commission approved the additional surcharge for 2H FY 2025 at ₹1.09 (~$0.012)/kWh.
However, the additional surcharge will not apply to open-access consumers wheeling power from captive power projects. It will not apply if fixed charges have been paid by  Green Energy Open Access (GEOA) consumers. It will not be levied if the power produced from a waste-energy project is supplied to the GEOA consumer, green energy is utilized to produce green hydrogen and green ammonia, and electricity produced from offshore wind projects is provided to the GEOA consumer.
Recently, the Commission <a href="https://www.mercomindia.com/telangana-issues-power-plant-verification" target="_blank" rel="noopener">issued</a> a detailed draft procedure for verifying the captive status of power-generating plants and their users in Telangana.
In March 2024, it also <a href="https://www.mercomindia.com/telangana-for-open-access-power-consumers" target="_blank" rel="noopener">issued</a> an order outlining the process for identifying stranded capacity and terms for imposing an additional surcharge on open-access consumers.

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