‘Vidyut Niyamak Bhawan’, Near I.S.B.T., P.O.-Majra, Dehradun-248171
Shri D.P. Gairola Member (Law) - Chairman (I/c)
Shri M.K. Jain Member (Technical)
In exercise of the powers conferred under Section 181(2) (zd) & (zp) of Electricity Act, 2003 (the Act) the Commission had issued draft Uttarakhand Electricity Regulatory Commission (Tariff and Other Terms for Supply of Electricity from Renewable Energy Sources and non-fossil fuel based Co-generating Stations) Regulations, 2023 for the Control Period from FY 2023-24 to FY 2027-28.
The Uttarakhand Electricity Regulatory Commission had previously notified the UERC (Tariff and Other Terms for Supply of Electricity from Renewable Energy Sources and non-fossil fuel based Co-generating Stations) Regulations, 2018 (hereinafter referred to as “previous Regulations” or “RE Regulations, 2018”). The RE Regulations, 2018 governed all the matters relating to determination of generic tariff and project specific tariff for the renewable energy based generating stations. These regulations had a control period of five financial years from the date of notification. The Commission issued the draft RE Regulations for the ensuing control period inviting comments/objections/suggestions on the same from the stakeholders. Last date of submission of comments/objections/suggestions was 02.06.2023. Comments/suggestions/objections received by the Commission have been duly analysed before considering them or rejecting the same.
The Commission also held a public hearing on 13.06.2023 to facilitate oral submission of the stakeholders and other interested persons. The comments/objections/suggestions of the stakeholders have also been considered. List of stakeholders who submitted comments on draft notification is placed at Annexure-I. List of participants who attended the hearing is also enclosed at Annexure-II.
The Statement of objects and Reasons is being issued with the intent of explaining the rationale which went into finalisation of UERC (Tariff and Other Terms for Supply of Electricity from Renewable Energy Sources and non-fossil fuel based Co-generating Stations) Regulations, 2023 (hereinafter referred to as “RE Regulations, 2023”). However, in case of any deviation/discrepancy in the SOR with respect to RE Regulations, 2023 the provisions of RE Regulations, 2023 shall be applicable. The comments/suggestions/objections received from the stakeholders and public and the views of the Commission on the same are discussed in subsequent paragraphs.
Suggestions and objections of stakeholders and the Commission’s views thereon are discussed hereunder:
The Commission had proposed the following in the draft Regulations:
“Provided that implementation of Canal Bank and Canal Top solar PV Plants by the eligible government organization (as specified by MNRE) and implementation of solar PV plants by eligible government organization shall be done through tariff based competitive bidding process. In such cases PPA for sale of power from these plants shall be signed with distribution licensee at a tariff quoted by L-1 bidder;
Provided further than in no case PPA for purchase of power by the distribution licensee shall be executed at a tariff exceeding the ceiling tariff as specified by the Commission in accordance with the regulations.”
the purpose of other entities for initiating the RE projects would be defeated, therefore, provision of 10% should be kept in line with RE Regulations, 2018.
“‘Eligible Government organization’ means organisation of Government of India or State Government or any Public Sector Undertaking of the Govt. of India or any State Government.”
1.1.4 During the public hearing, UJVNL was directed to submit the details of expenses incurred towards canal based solar power plants. UJVNL Ltd. submitted the expected employee expenses of Rs. 6.75 Lakh for FY 2023-24 towards solar power plants and also submitted the details of expenditure incurred towards consultancy for preparation of DPR and other documents amounting to Rs. 82.88 Lakh. UJVNL Ltd. also submitted the details of O&M expenses incurred for the last five years.
1.1.5 The Commission gone through the given data and observed that total expenses incurred for preparation of DPR and other administration works are amounting to Rs. 89.63 Lakh and considering the total installed capacity of solar power plants of 26.264 MW, per MW expenses incurred by UJVNL Ltd. works out to Rs. 3.42 Lakh/MW which has an impact of approximate only approximately 2% on the tariff. However, considering the fact that with the increase of number of solar power plants, more O&M expenses will be required for paperwork and other official procedures. Further, there shall be no motive for engaging in such activities for installation of Solar power plants if the entire tariff discovered through bidding is transfer to the L-1 bidder. Accordingly, a reasonable return should be there to motivate eligible government organisation to execute such activities to ensure smooth installation and operations of solar power plant. Therefore, the Commission has decided to fix 8% additional tariff over and above tariff quoted by L-1 bidder. However, the same shall be applicable only for implementation of canal bank and canal top solar power plants implemented by eligible Government organisations.
Accordingly, based on the aforesaid discussion, first Proviso to Sub-regulation (3) of Regulation 2 shall be read as follows:
“Provided that implementation of Canal Bank and Canal Top Solar Power Plants by the eligible government organisation shall be done through tariff based competitive bidding process. In such cases PPA for sale of power from these plants shall be signed with distribution licensee at a tariff which shall be 8% higher than the tariff quoted by L-1 bidder, however, the tariff plus a margin of 8% shall not exceed the generic tariff determined by the Commission for the year of commissioning.
Provided further than in no case PPA for purchase of power by the distribution licensee shall be executed at a tariff exceeding the ceiling tariff as specified by the Commission in accordance with the regulations.”
The Commission had proposed as follows in the draft Regulations:
““Captive Generating Plant” means a power plant set up by any person to generate electricity primarily for his own use and includes a power plant set up by any cooperative society or association of persons for generating electricity primarily for use of members of such cooperative society or association where not less than twenty six percent of the ownership is held by the captive user(s), and not less than fifty one percent of the aggregate electricity generated in such plant, determined on an annual basis, is consumed for the captive use.”
solar PV projects’ refers to Solar PV projects designed for self-consumption with reverse power flow relay to ensure that electricity generated from rooftop PV projects is not fed into the network of the Distribution Licensee, then such installation needs to be treated as grid-connected captive plants behind the meter rooftop solar installation which does not exchange electricity with the grid. It is pertinent to mention that such plants are already covered in the definition of captive power plants. Accordingly, the Commission has not used the term ‘Behind the meter solar PV projects’ in the draft regulations. Accordingly, the Commission does not find it prudent to insert the definition of ‘Behind the meter solar PV projects’.
The Commission had proposed the following in the draft Regulations:
“Date of commercial operation or Commissioning (CoD)” in relation to a unit means the date declared by the generator on achieving maximum continuous rating through a successful trial run and in relation to the generating station, the date of commercial operation means the date of commercial operation of the last unit or block of generating station and expression ‘commissioning’ shall be construed accordingly.
Provided that in case of Small Hydro Plants the date of commissioning shall not be linked to achieving maximum continuous rating, nevertheless the generator will have to demonstrate the same within three years of commissioning.
Provided further that in case of Solar PV plant, date of commercial operation or Commissioning (CoD) shall be considered as the date of first injection of power into the licensee’s grid after completion of project in all respect subsequent to compliance of all the following pre-requisites:
Further, such generator has to demonstrate minimum 75% Performance Ratio based on the rated installed capacity in kW or MW at the time of inspection for initial commissioning”
“The date of commissioning of Solar PV plant shall be considered as the date of first injection of power into the licensee’s grid after completion of the project in all respect subsequent to compliance of initial three prerequisites, i.e. (i) installation of energy meter as certified by the concerned Executive engineer of the distribution licensee; (ii) project completion report as verified by UREDA and (iii) issuance of Clearance Certificate by the Electrical Inspector
Provided that minimum 75% Performance Ratio based on the rated installed capacity in kW or MW is demonstrated within Three months from the date of first injection of power into licensee’s grid on compliance of aforesaid three pre-requisites.
Provided further, that if the specified limit of Performance Ratio is not achieved within Three months from the date of first injection of power into licensee’s grid on compliance of aforesaid three pre-requisites, the actual date of demonstration of minimum 75% Performance Ratio, based on the rated installed capacity in kW or MW, shall be considered the commissioning date of the Solar PV plant.”
“Date of commercial operation or Commissioning (CoD)” in relation to a unit means the date declared by the generator on achieving maximum continuous rating through a successful trial run and in relation to the generating station, the date of commercial
operation means the date of commercial operation of the last unit or block of generating station and expression 'commissioning' shall be construed accordingly.
Provided that in case of Small Hydro Plants the date of commissioning shall not be linked to achieving maximum continuous rating, nevertheless the generator will have to demonstrate the same within three years of commissioning.
The date of commissioning of Solar PV plant shall be considered as the date of first injection of power into the licensee's grid after completion of the project in all respect subsequent to compliance of initial three prerequisites, i.e.
Provided that minimum 75% Performance Ratio based on the rated installed capacity in kV or MW is demonstrated within Three months from the date of first injection of power into licensee's grid on compliance of aforesaid three pre-requisites.
Provided further, that if the specified limit of Performance Ratio is not achieved within Three months from the date of first injection of power into licensee's grid on compliance of aforesaid three pre-requisites, the actual date of demonstration of minimum 75% Performance Ratio, based on the rated installed capacity in kV or MW, shall be considered the commissioning date of the Solar PV plant."
"Deemed Generation" means the energy which a generating station was capable of generating but could not generate due to conditions of grid or power system, beyond the control of the generating station resulting in spillage of renewable resources."
The Commission had proposed the following in the draft Regulations:
"Grid interactive roof top solar PV plants (GRPV)" means Solar PV plant installed on the rooftop of a building under net metering arrangement having maximum capacity as specified under these Regulations.
“Grid interactive small solar PV plants (GSPV)” means Solar PV plants installed in the premises of a buildings (either entirely on the land or partly on the land and partly on the roof) and connected to the grid under net metering arrangement having maximum capacity as specified under these Regulations.
“Grid interactive roof top solar PV plants (GRPV)/ Grid interactive small solar PV plants (GSPV)” means Solar PV plant installed on the rooftop of a building and includes plants installed on open contiguous land within the premises and connected to the grid under net metering arrangement having maximum capacity as specified under these Regulations.
“Group Net Meter” means an arrangement whereby surplus energy is generated and injected from a solar power plant through net meter and such surplus energy exported shall be adjusted in more than one electricity service connection(s) of the same consumer either at the same or different premise located within the same distribution licensee’s area of supply.”
"Group Net Metering" means an arrangement whereby surplus energy is generated and injected from a solar power plant through net meter and such surplus energy exported shall be adjusted in more than one electricity service connection(s) of the same consumer either at the same or different premise located within the same distribution licensee's area of supply."
"Prosumer" means a consumer who is also a producer of Solar Power"
"Prosumer" means a person who consumes electricity from the grid and can also inject electricity into the grid of distribution licensee, using same point of supply."
The Commission had proposed the following in the draft Regulations:
"(2) At present, generation from following sources and technologies shall qualify to be covered under these Regulations:
(3) Any new source or technology would qualify as ‘renewable energy’, only after the technology for the same has been approved by MNRE approval. Further, the Commission shall determine tariffs separately for each technology after the approval of the technology by MNRE.”
“(c) Solar PV, Canal bank & Canal top Solar PV, Solar Thermal, Agro-voltaic and GSPV/GRPV – Based on Technologies approved by MNRE.”
The Commission had proposed as follows in the draft Regulations:
“(8) The RE Based Generating Stations and Co-generating Stations shall coordinate with State Transmission Utility/Distribution Licensee for the purpose of planning and coordination relating to intra-state transmission/distribution system as provided under the Act.”
“and the State Transco assess transmission needs and conduct medium to long-term transmission planning in consultation with the discom and UREDA. Transco/Discom(s) of Uttarakhand shall strengthen the upstream system on a priority basis. Supervision charges levied by the Uttarakhand Transco/Discom(s) may be exempted for all solar power plants except utility-scale solar power plants.”
Hence, in the large interest of safety and in the equality of law, it is requested that the obligations and duties of the discom in same context may also be listed out.
The Commission had proposed as follows in the draft Regulations:
“(1) All RE Based Generating Stations and Co-generating Stations shall be allowed to sell power, over and above the capacity required for their own use, to the distribution licensee provided that distribution licensee is willing to enter into a PPA or to local rural grids at the rates determined by the Commission or to any consumer/person within the State or outside the State at mutually agreed rates (provided that such consumer has been allowed Open Access under Open Access Regulations).”
(2) The distribution licensee on an offer made by the said RE based Generating Stations and Co-generating Stations may enter into a power purchase agreement in conformity with these Regulations and relevant provisions of other Regulations and the Act. However, if the distribution licensee intends to purchase power from such generator it shall sign the PPA within two months of offer made by the generating company. Otherwise, if the distribution licensee is not willing to purchase power from such generator it shall intimate the same to the generating company within one month of offer made by it.
Provided further that the application for approval of PPA should be accompanied with an unconditional Technical Feasibility Report and the connectivity agreement signed with the Transmission/Distribution licensee shall form part of the PPA.”
1.10.1 UJVN Ltd. submitted that Uttarakhand State Hydro policy states as follows:
“The entire power generated from the project having capacity upto 25 MW will mandatorily be purchased by UPCL at tariff as determined by UERC. If the appropriate action will not be taken by UPCL within the stipulated time as defined in the regulations issued by the Commission from time to time, then the penalty imposed by the Government of Uttarakhand after due deliberation shall be payable by UPCL.”
1.10.2 The stakeholder requested the Commission to align the above regulation in accordance with the provisions of Hydro Policy. Further, UJVN Ltd. also submitted that there should be clear timeline for providing connectivity by state licensee to ensure that commissioning of RE based project should not be delayed owing to connectivity constraints.
1.10.3 Akshay Urja Association submitted that in context of GRPV and GSPV plants, it may be mentioned that sale of power would also be allowed as per Virtual Net metering and the same may be installed in own or third party premises or at any other location in the State under CAPEX or RESCO model which is covered by discom's distribution area. Further, timeline of 1 month for signing of PPA may be mandated.
1.10.4 M/s Siyangad Hydro Pvt. Ltd., M/s Jalandharygad Hydro Pvt. Ltd. and M/s Kakoragad Hydro Pvt. Ltd. also submitted that it should be binding on Discom to enter into all PPAs offered by SHPs at generic tariff or project specific tariff.
Many stakeholders requested the Commission to make it mandatory for distribution licensee to purchase power generated from upcoming SHPs. In the matter, the Commission is of the view since the current Hydro Policy makes it mandatory distribution licensee to execute PPA with SHP developershence, there seems no need to add any provisions in the Regulations to this regard.
Accordingly, based on the above, regulation is modified to the extent as given below:
Provided that where a GRPV/GSPV plant, is installed in the Premises, by a third party who intends to sell net energy (i.e. after adjustment of entire consumption of owner of the premise) to the distribution licensee, a tripartite agreement will have to be entered into amongst the third Party, the Eligible Consumer and such Distribution Licensee.
Provided further that the application for approval of PPA should be accompanied with an unconditional Technical Feasibility Report and the connectivity agreement signed with the Transmission/Distribution licensee shall form part of the PPA.”
In the draft Regulation, the Commission had proposed as follows:
“(1) xxx
renewable energy, cross-subsidy charges if any, and service charges covering the prudent cost of the distribution licensee for providing the green energy.
(3) xxx
(4) The green energy purchased from distribution licensee or from Renewable Energy sources other than distribution licensee in excess of Renewable Purchase Obligation of the obligated entity shall be counted towards Renewable Purchase Obligation compliance of the distribution licensee."
1.11.1 UREDA requested the Commission to define green tariff and the intent of introducing such tariff to encourage consumers to switch towards green energy and become early mover by announcing economically attractive green tariff rates. This is also in accordance with Solar Policy, 2023. UREDA also requested the Commission to replace the existing clause (4) of regulation 8 with the following so that the benefits of RPO shall only be for energy procured by distribution licensee:
"The green energy purchase from distribution licensee or from Renewable Energy Source other than distribution licensee in excess of Renewable Purchase Obligation of the obligated entity shall be counted towards Renewable Purchase Obligation compliance of the distribution licensee."
1.11.2 With regard to comments of UREDA on the provisions of green energy, it is pertinent to mention that Ministry of Power, GoI has notified Green Open Access Rule, 2022 on 06.06.2022 and Rule 4(2)(C)(c) of Green Open Access Rules, 2022 specifies that the tariff for the supply of green energy by distribution licensee shall be determined by the appropriate Commission. Moreover, Solar Policy, 2023 also specifies that the Commission shall introduce Green Tariff in its Regulations allowing all electricity consumers to opt for green energy.
Further, as far as UREDA comment for allowing benefit of RPO to distribution licensee against the renewable energy procured by it is concerned, it is pertinent to mention that the Commission has incorporated the aforesaid regulation to align with the provisions specified under Electricity (Promoting Renewable Energy Through Green Energy Open Access) Rules, 2022. The Commission does not find it prudent to deviate from the provisions specified by MoP, GoI. Further, to align with the
provisions specified by MoP, GoI under aforesaid rule, the Commission decides to insert the following sub-regulation (2) after sub-regulation (1) of Regulation 8:
“(2) The consumer may purchase on voluntary basis, more renewable energy, than he is obligated to do and for ease of implementation, this may be in steps of twenty five percent and going upto hundred percent.”
In the draft regulations, the Commission had proposed as follows:
“(1) Non-discriminatory Open access in State Transmission/Distribution System shall be allowed to all RE based Generating stations and Co-generating Stations for captive use and to those covered under Regulation 70, which shall be subject to the provisions of the Open Access Regulations.
Provided that the ‘open access’ shall be allowed subject to the availability of surplus capacity in the State Transmission/Distribution System.
Provided that the Captive user shall be required to pay Parallel Operation Charges to Distribution Licensee and Transmission Licensee, as the case may be, for utilization of grid support from Distribution Licensee and/or Transmission Licensee. The Commission shall specify the Parallel Operation Charges in its Tariff Orders for distribution licensee or transmission licensee, as the case may be, on annual basis.
(2) Such open access shall be subject to payment of transmission/wheeling charges and adjustment of average transmission/distribution losses in kind as determined in accordance with the Regulation 41 of these Regulations.
(3) If any question arises as to the availability of surplus capacity in the State transmission system or the State distribution system, the matter shall be adjudicated and decided by the Commission.”
1.12.1 UREDA requested the Commission to insert the following after first proviso of sub-regulation (1):
“Distribution licensee shall update the status of open access application for the intra-state network within 21 days. In the absence of any response of intimation from the distribution licensee to the applicant within 21 days, the application shall be deemed to be approved,
unless the distribution licensee shall seek additional time (maximum upto 15 days) citing the valid reasons for the extension.”
Further, the Stakeholder also requested the Commission to insert following after sub-regulation (2):
“Whereas captive/group-captive solar plants shall be exempted from paying transmission and wheeling charges. Whereas GRPV projects installed by residential, institutional and agricultural consumers shall be exempted from paying transmission charges, wheeling charges, cross subsidy and additional surcharge.”
UREDA and Akshay Urja Association requested the Commission to notify “Green Energy Open Access Regulations and compensation of charges by GoUk due to open access waiver as per Solar Policy, 2023.
The stakeholder also submitted that the Parallel charges may only be levied when power is consumed by industrial loads with co-located generating station. Power consumed by industrial loads with dedicated transmission line or through grid shall not be charged Parallel operation charges because the charges towards grid usage is already recovered in the form of transmissions and wheeling charges. Therefore, it is requested to delete the clause pertaining to imposition of grid support charges.
With regard to notifying 'Green Energy Open Access Regulations', it is pertinent to mention that the Commission has issued draft UERC (Green Open Access) Regulations, 2023 and the same will be notified after public hearing and considering Stakeholders comments. Further, as far as exemption of transmission/wheeling charges to captive/group-captive power plants is concerned, the Commission observes Clause 8.2.3 (II) 'Incentives' of Solar Policy 2023 specifies that grid connected solar captive power Projects (including storage systems) or group captive projects shall attract 100% exemption from transmission and wheeling charges for a period of 5 years from the date of commissioning of the project. The Commission decides to insert a provision to align with the provisions specified under Solar Policy, 2023.
The Commission is of the view that the Parallel operation is an activity where one electrical system operates with the connectivity to another system in similar operating conditions. The captive power plants opt for parallel operations to seek safety, security and reliability of operation with the support of a much larger and stable system as afforded by the grid. Captive power plants, which are designed to meet the electricity needs of a specific entity or facility, often require access to the grid for synchronization and backup power supply. Parallel Operation Charges are imposed to cover the costs associated with granting grid access and providing necessary technical support for parallel operation, including system stability, voltage regulation, and frequency control for grid access and support. Further, Captive power plants, when operated in parallel with the grid, become part of the interconnected power system. Grid operators have to ensure the stability, reliability, and overall performance of the grid even when additional power sources are connected. Parallel Operation Charges contribute to the funds needed to manage the integration of captive power plants into the grid and ensure the system remains balanced and secure.
Accordingly, the Commission decides that second proviso to sub-regulation (1) of Regulation 9 shall be read as follows:
“Provided that the captive power plants shall be required to pay Parallel Operation Charges to Distribution Licensee and/or Transmission Licensee, as the case may be, for utilization of grid support from Distribution Licensee and/or Transmission Licensee. The Commission shall specify the Parallel Operation Charges in its Tariff Orders for distribution licensee or transmission licensee, as the case may be, on annual basis.
Provided that levy of Open Access Charges on captive projects shall be governed by the relevant provisions of the Act and policies issued by Central/State Government from time to time.”
In the draft Regulation, the Commission had proposed as follows:
“(1) In line with the provisions of the Act, National Electricity Policy, the Tariff Policy to promote development of renewable and non-conventional sources of energy, all existing and future distribution licensees, captive users and open access customers, hereinafter referred to as “Obligated Entity”, in the State shall be obliged to procure minimum percentage of their total
electricity requirement for own consumption, as indicated below, from eligible renewable energy sources as defined under Regulation 4. The same shall be called the Renewable Purchase Obligation (RPO) of the Obligated Entities.
| Year | Wind RPO | Hydro Purchase Obligation (HPO) | Other RPO |
|---|---|---|---|
| 2023-24 | 1.60% | 0.66% | 24.81% |
| 2024-25 | 2.46% | 1.08% | 26.37% |
| 2025-26 | 3.36% | 1.48% | 28.17% |
| 2026-27 | 4.29% | 1.80% | 29.86% |
| 2027-28 | 5.23% | 2.15% | 31.43% |
| 2028-29 | 6.16% | 2.51% | 32.69% |
| 2029-30 | 6.94% | 2.82% | 33.57% |
Percentage RPO as stipulated above denotes Minimum Quantum of purchase from non-fossil fuel based co-generation and generation of electricity from renewable energy sources' as a percentage of total energy purchased from all sources/generated by the Obligated Entity during the year for own consumption.
Where, total energy purchased for different obligated entities shall be as under:
Provided that HPO obligation of the Distribution licensee may be met out of the free power being provided to the State from HPPs (including PSPs and SHPs), commissioned after 8th March 2019 as per agreement at that point of time excluding the contribution towards LADE, if consumed within the Discom. Free Power (not that contributed for Local Area Development) shall be eligible for HPO benefit.
Provided that any shortfall remaining in achievement of ‘Other RPO’ category in a particular year can be met with either the excess energy consumed from Wind Power Plants, commissioned after 31st March 2022 beyond ‘Wind RPO’ for that year or with excess energy consumed from eligible HPPs (including PSPs and SHPs), commissioned after 8th March 2019 beyond ‘HPO’ for that year or partly from both. Further, any shortfall in achievement of ‘Wind RPO’ in a particular year can be met with excess energy consumed from Hydro Power Plants, which is in excess of ‘HPO’ for that year and vice versa.
| Financial Year | Storage (on Energy basis) |
|---|---|
| 2023-24 | 1.0% |
| 2024-25 | 1.5% |
| 2025-26 | 2.0% |
| 2026-27 | 2.5% |
| 2027-28 | 3.0% |
| 2028-29 | 3.5% |
| 2029-30 | 4.0% |
1.13.5 Akshay Urja Association has requested the Commission to designate UREDA to ensure implementation and compliance of RPO targets. In the matter, it is pertinent to mention that the Commission has issued RPO Compliance Regulations, 2010 specifying the responsibilities of UREDA. Accordingly, the Commission does not find it prudent to reiterate the responsibilities and duties of UREDA.
1.13.6 Further, Akshay Urja Association suggested if Obligated Entity fails to meet RPO, Obligated Entity may be directed to deposit into a separate fund such amount as the Commission may determine on the basis of shortfall. Further, such RPO fund may be utilised for development of evacuation infrastructure related to RE generating stations.
With regard to a separate fund, this issue has been dealt in UERC RPO Compliance Regulations 2010 and hence, the same is not being reiterated again.
“(1) In line with the provisions of the Act, National Electricity Policy, the Tariff Policy to promote development of renewable and non-conventional sources of energy, all existing and future distribution licensees, captive users and open access customers, hereinafter referred to as “Obligated Entity”, in the State shall be obliged to procure minimum percentage of their total electricity requirement for own consumption, as indicated below, from eligible renewable energy
sources as defined under Regulation 4. The same shall be called the Renewable Purchase Obligation (RPO) of the Obligated Entities.
| Year | Wind RPO | Hydro Purchase Obligation (HPO) | Other RPO | ||
|---|---|---|---|---|---|
| Solar RPO | Other than Solar | Total of Other RPO | |||
| 2023-24 | 1.60% | 0.66% | 5.00% | 19.81% | 24.81% |
| 2024-25 | 2.46% | 1.08% | 5.31% | 21.06% | 26.37% |
| 2025-26 | 3.36% | 1.48% | 5.68% | 22.49% | 28.17% |
| 2026-27 | 4.29% | 1.80% | 6.02% | 23.84% | 29.86% |
| 2027-28 | 5.23% | 2.15% | 6.33% | 25.10% | 31.43% |
| 2028-29 | 6.16% | 2.51% | 6.59% | 26.10% | 32.69% |
| 2029-30 | 6.94% | 2.82% | 6.77% | 26.80% | 33.57% |
Percentage RPO as stipulated above denotes Minimum Quantum of purchase from non-fossil fuel based co-generation and generation of electricity from renewable energy sources' as a percentage of total energy purchased from all sources/generated by the Obligated Entity during the year for own consumption.
Where, total energy purchased for different obligated entities shall be as under:
Provided that HPO obligation of the Distribution licensee may also be met out of the free power being provided to the State from HPPs (including PSPs and SHPs), commissioned after 8th March 2019 as per agreement at that point of time excluding the contribution towards LADE, if
consumed within the Discom. Free Power (not that contributed for Local Area Development) shall be eligible for HPO benefit.
Provided that any shortfall remaining in achievement of 'Solar RPO' category in a particular year can be met with excess energy consumed from eligible HPPs (including PSPs and SHPs), commissioned after 8th March 2019 beyond 'HPO' for that year or with excess energy consumed from eligible 'Other than Solar RPO' under category of 'Other RPO' for that year.
Provided further that any shortfall remaining in achievement of 'Other than Solar RPO' under 'Other RPO' category in a particular year can be met with either the excess energy consumed from Wind Power Plants, commissioned after 31st March 2022 beyond 'Wind RPO' for that year or with excess energy consumed from eligible HPPs (including PSPs and SHPs), commissioned after 8th March 2019 beyond 'HPO' for that year or with excess energy consumed from solar plants beyond 'Solar PRO' for that year or partly from all above three category..
Provided further that any shortfall in achievement of 'Wind RPO' in a particular year can be met with excess energy consumed from Hydro Power Plants, which is in excess of 'HPO' for that year and vice versa.
| Financial Year | Storage (on Energy basis) |
|---|---|
| 2023-24 | 1.0% |
| 2024-25 | 1.5% |
| 2025-26 | 2.0% |
| 2026-27 | 2.5% |
| 2027-28 | 3.0% |
| 2028-29 | 3.5% |
| 2029-30 | 4.0% |
total energy storage in the Energy Storage System (ESS), on an annual basis, is procured from renewable energy sources.
(6) The Energy Storage Obligation to the extent of energy stored from RE sources shall be considered as a part of fulfilment of the total RPO as mentioned under sub-regulation (1) of this regulation.
(7) UREDA will maintain the data related to compliance of RPO Obligation."
The Commission had proposed the following in the draft Regulations:
Provided that the option of seeking project specific tariff shall not be available to the following:
Provided further that if generating company does not give its option to the distribution licensee within above stipulated time, generic tariff shall be applicable based on the date of commissioning of the project or commissioning of the first unit, in case of multiple units.
(3) Project Specific Tariff, on case to case basis, shall be determined by the Commission in the following cases:*
(a) For projects opting to have their tariffs determined on the basis of actual capital cost instead of normative capital cost as specified for different technologies under Chapter 5 subject to 1st Proviso of Regulation 11(2) above, the CUF (generation) for recovery of fixed charges shall be taken as that envisaged in the approved DPR or the normative CUF specified under Chapter 5 for the relevant technology, whichever is higher;
(b) Other hybrid projects include renewable-renewable or renewable-conventional sources, for which renewable technology is approved by MNRE;
(c) Projects having old plant and machinery or equipment;
(d) The RE generating company for meeting the expenditure on Renovation, Modernisation and Up-gradation (RMU) for the purpose of extension of life beyond the useful life of its RE based power plant shall make an application before the Commission for in-principle approval of the proposal alongwith a DPR giving complete scope, cost-benefit analysis, estimated life extension from a reference date, financial package, phasing of expenditure, schedule of completion and other details as required by the Commission and the Commission while fixing their tariffs, shall be guided by the tariff norms specified in the Regulations based on actual capital cost subsequent to the completion of the RMU activities and such other factors considered relevant by the Commission;
(e) Any other new renewable energy technologies approved by MNRE.
Provided that the Commission while determining the Project Specific Tariff shall be guided by the provisions of Chapter 4 & 5 of these Regulations for technologies specifies therein."
of RMU works of the projects keeping in view the cost effectiveness and quantum of investment. However, after certain period say 10-15 year (post RMU) the need of carrying out civil works or replacement of items which were not replaced during RMU of plant may arise due to ageing or technological obsolescence.
Keeping in view the above, the provision of such additional capital expenditure may kindly be made in regulations and additional tariff may be determined at that time.
The Commission had proposed as follows in the Draft Regulations:
“(2) Till fixation of final tariff, a RE Based Generating Station or Co-generating Station may either accept the generic tariff as provisional tariff or make an application for determination of provisional tariff in advance of the anticipated date of completion of the project based on the capital expenditure actually incurred up to the date of making the application or a date prior to making of the application, duly audited and certified by the statutory auditors. The provisional tariff as may be determined by the Commission may be charged from the Commercial Operation Date (CoD) of the respective unit of the generating station.
Provided that the RE Based Generating Stations and Co-generating Stations shall be required to make a fresh application for determination of final tariff based on actual capital expenditure incurred up to the date of commercial operation or commissioning of the generating station within 18 months from the actual CoD.”
1.15.1 Him Urja Pvt. Ltd. submitted that draft Regulation specifies that provisional tariff may be determined based on the actual expenditure incurred upto the date of making the application. The financial institutions are putting up conditions that the provisional tariff should be known to them before more than certain percentage of loan is disbursed. The developer has to move the application to the Commission after getting the expenditure audited when the actual expenditure incurred may be about 30% of the project cost.
Therefore, it is requested that the Commission may determine provisional tariff based on the Capital cost in DPR, Cost taken by financial institution, cost approved by concerned government, cost of other projects being approved by the Commission and all other material facts necessary for determination of the provisional tariff. The Provisional tariff may be determined by the Commission any time after financial closure of the project. This will facilitate the SHPs in getting finances of the project.
1.15.2 The Commission agrees that the financial institutions sanction the loan amount based on the expected revenue from the project. Therefore, the Commission allows the developers to approach the Commission for determination of provisional tariff based on the actual expenditure incurred upto the date of making an application. Initially, the project developers infuse equity and based on the same, financial institutions disburse
proportionate loan amount. However, it is worth mentioning that the Commission provides two options to the developers, either to approach the Commission based on the actual expenditure for determination of provisional tariff or the developer can accept generic tariff as provisional tariff till the fixation of final tariff. Accordingly, the developer may accept generic tariff, if the actual expenditure incurred is not sufficient to get a suitable provisional tariff. Accordingly, the request of the stakeholder w.r.t determination of the provisional tariff based on the Capital cost in DPR, Cost taken by financial institution, cost approved by concerned government, cost of other projects being approved by the Commission is not proper. The Electricity Act, 2003 provides for determination of cost-plus tariff and cost must be actually incurred costs and not projected costs. Hence, the request of the stakeholder in this regard is rejected.
The Commission had proposed as follows in the draft Regulations:
“(1) The tariff for renewable energy technologies shall be single part tariff (in Rs./kWh) and ex-bus, i.e. after auxiliary consumption and transformation losses at the interconnection point as defined in Regulation 3(1)(xxxiv).
Provided that for renewable energy technologies having fuel cost component, like biomass/biogas/biomass gasifier power projects, Refuse derived fuel and non-fossil fuel based cogeneration, tariff with two components, namely fixed cost component and fuel cost component, shall be determined.
(2) The Tariff shall consist of the following fixed cost components:
(3) The generic tariff is being determined separately for each kind of renewable source and for each type of renewable technology for which norms have been specified in these Regulations.
Provided that the generic tariff for supply of electricity from the plant, having more than one unit commissioned during currency of different control period, shall be based on weighted average of the tariffs specified under different Regulations for the total capacity of the plant.
Provided that for renewable energy technologies having tariff (in Rs./kWh) with two components, for fixed cost component tariff may be determined on levelised basis considering the year of commissioning of the project while the fuel cost component shall be specified on year of operation basis.
Provided that where project specific tariff is being determined the revenue generated from infirm power shall be used to reduce the capital cost of the project after giving credit for cost of fuel consumed, wherever applicable;
Provided that any additional expenditure of capital nature which becomes necessary for restoration works only on account of damages caused by natural calamities (but not due to flooding of power house attributable to the negligence of the generating company), after prudence check by the Commission, shall be allowed as additional capitalisation after duly adjusting the proceeds from any insurance scheme for all the generating stations covered under these Regulations. For additional capital expenditure admitted, as above, appropriate adjustment in tariff shall be allowed for balance life of that project based on the norms given in Chapters 4 & 5 of the Regulations;
Provided that additional capitalisation on this account would only be allowed if appropriate and adequate insurance cover was available for the generating station at the time of occurrence of natural calamities referred to above. The generating company shall intimate the Commission and Distribution Licensee within seven days from the occurrence of any such force majeure event resulting into shut down of plant. The Commission may in such case direct the distribution licensee and State nodal agency to visit the damaged plant and assess the nature & type of damages and restoration works required in coordination with the generator/developer."
Further, change in performance as well as financial outputs due to reasons attributable to discom such as grid non connectivity or curtailment or damage to plant due to natural calamities would negatively affect the financial parameters of the project.
even places an undue financial burden on the SHP since it continues to incur various fixed charges and debt even though it has no revenues coming in.
Force majeure clause in PPA approved by the Commission and Implementation Agreement already provides for extension of the time of the agreement, equal to the time period during which the force majeure event subsists, i.e. the period during which the SHP is restored. Under the circumstance, it is submitted that suitable clarification may be provided in the regulations.
Therefore, the developers are advised to bid the rates taking in consideration all the financial and normative parameters and should try to meet the normative CUF which is already lower than that specified in other States. The developers should endeavour to recover the entire cost based on the CUF and other parameters specified by the Commission.
insurance of the power plant. In general practice, generating stations should get the insurance to cover revenue losses as well as loss of assets/project.
Further with regard to clarification in the regulation regarding extension of useful life due to stoppage of plant because of any force majeure event, the Commission in the current regulation while defining the 'Useful Life' of the project inserted a provision to cater to the life in case stoppage of plant due to force majeure event which specifies as follows:
"Provided that where the operation of a plant was stopped due to a force majeure event, the life of the plant shall be extended by the period of such stoppage and accordingly, the PPA shall be extended."
This will extend the life of the project and will compensate to some extent for the loss of revenue incurred by the generator during force majeure event.
The Commission had proposed as follows in the draft Regulations:
Provided that if the delay is not attributable to the generating company and is due to uncontrollable factors, such expenditures may be allowed after due prudence check; Provided further that where the delay is attributable to an agency or contractor or supplier engaged by the generating company, the liquidated damages recovered from such agency or contractor or supplier shall be kept in view while computing the capital cost.
(c) In case individual generating company opts to construct, at its own cost, the evacuation infrastructure from point of inter-connection to the nearest sub-station of transmission or distribution licensee to which the generating station is connected, it shall be allowed a normative levelised tariff of 5 paise/unit over and above the generic tariff determined at the point of inter-connection. However, in case of a solar generating company a normative levelised tariff of 12 paise/unit over and above the generic tariff determined at the point of inter-connection shall be allowed. The said normative tariff for evacuation infrastructure has been arrived at considering the cost of normative line length of 10 kms. (including cost of terminal equipments) for different capacities of generating stations as per normative cost given below:
| (i) Upto 3MW, 11 kV S/C | - Rs. 44 lakh |
| (ii) Above 3MW and upto 13 MW, 33 kV S/C | - Rs. 85 lakh |
| (iii) Above 13 MW and upto 25 MW, 33 kV 2 x S/C or DC | - Rs. 170 lakh |
Provided that in case more than one generating stations construct, at its own cost, a common evacuation infrastructure including pooling switching station, in accordance with Regulation 41 of these Regulations, for evacuation of power of their generation, then the above normative levelised tariff shall be apportioned among all such generating stations on the basis of their installed capacity.
Provided that the distribution licensee will be required to exercise the option within one year from the date of commissioning of the generating station(s)."
Further, in case of project specific tariff cost of power evacuation infrastructure should be allowed on actual basis and not on normative cost basis.
The stakeholders requested to specify normative evacuation infrastructure cost that takes into account the increase in the input costs over the past 13 year.
the State for the entire useful life of the plant and, accordingly, the benefit of the economic useful life of the plant should also be provided to the consumers of the State. Further, with regard to inflation in rupee rates, it is to be noted that the future tariffs are derived considering suitable escalation in the O&M cost on year-on-year basis and then levelised tariff is determined by the Commission based on the time value of money. Hence, inflation will not have any impact on the real tariff. In view of the above discussion, no change is required in the said Regulation.
1.17.10 Many of the stakeholders raised the issue that cost of transmission line has increased.
The Commission had first time provided the RE generators to construct their own evacuation infrastructure at a cost of 5 paisa/kWh in 2010. The cost of material has increased. Supply Code Regulations specify a cost of Rs. 1.25 Crore for a 10 km 33 kV line as against Rs. 85 Lakh specified in draft Regulations. The Commission agrees with the comments of the Stakeholders and decides to revise the cost of evacuation infrastructure. The Commission has considered the base cost of the transmission line as specified under State Grid Code, 2020 which is as follows:
| (i) Upto 3MW, 11 kV S/C | - Rs. 8.00 Lakh/km |
| (ii) Above 3MW and upto 13 MW, 33 kV S/C | - Rs. 12.50 Lakh/km |
| (iii) Above 13 MW and upto 25 MW, 33 kV 2 x S/C or DC | - Rs. 25.00 Lakh/km |
Accordingly, if a generating station opts to construct the evacuation infrastructure from point of inter-connection to the nearest sub-station of transmission or distribution licensee to which the generating station is connected, it shall be allowed a normative levelised tariff specified in the Regulations over and above the generic tariff determined at the point of inter-connection. However, in case of a solar generating company a normative levelised tariff specified in the Regulations over and above the generic tariff determined at the point of inter-connection shall be allowed.
1.17.11 During the proceedings in the matter, it was brought to the notice of the Commission that in several cases, UPCL is paying 5 paisa/kWh or 12 Paisa/kWh as the case may be even where transmission line has not been constructed by generator till the sub-station of UPCL. In the matter, the Commission is of the view that per unit rate may be recovered based on proportionate line constructed by the developer.
Accordingly, based on the above discussions, final regulation shall be read as follows:
(a) The norms for the Capital Cost as specified in the subsequent technology specific provisions in Chapter 5 shall include the expenditure incurred or projected to be incurred, initial spares, interest during construction (IDC) and financing charges, incidental expenditure during construction (IEDC), any gain or loss on account of foreign exchange risk variation during construction on loans arrived in the manner specified in sub-regulation (2) below upto the date of commercial operation or commissioning of the project, as admitted by the Commission after prudence check. The capital cost shall also include the expenditure incurred or projected to be incurred towards the switchyard etc. upto the point of interconnection (i.e. it does not include cost of dedicated line and associated equipment from point of interconnection upto the nearest sub-station of transmission or distribution licensee to which generating station is connected).
(b) In case of additional costs on account of IDC, Finance charges and IEDC due to delay in achieving the Schedule CoD, the generating company shall be required to furnish detailed justification with supporting documents for such delay including the details of IDC, Finance Charges and IEDC during the period of delay and liquidated damages recovered or recoverable corresponding to the delay:
Provided that if the delay is not attributable to the generating company and is due to uncontrollable factors, such expenditures may be allowed after due prudence check;
Provided further that where the delay is attributable to an agency or contractor or supplier engaged by the generating company, the liquidated damages recovered from such agency or contractor or supplier shall be kept in view while computing the capital cost.
(c) In case individual generating company opts to construct, at its own cost, the evacuation infrastructure from point of inter-connection to the nearest sub-station of transmission or distribution licensee to which the generating station is connected, it shall be allowed a normative levelised tariff of 7 paise/unit over and above the generic tariff determined at the point of inter-connection. However, in case of a solar generating company a normative levelised tariff of 14 paise/unit over and above the generic tariff determined at the point of inter-connection shall be allowed. The said normative tariff for evacuation infrastructure has been arrived at considering the cost of line and equipments specified under UERC (The Electricity Supply code, Release of New Connections and Related matters) Regulations, 2020 as per normative cost given below:
| (i) Upto 3MW, 11 kV S/C | - Rs. 8.00 lakh/km |
| (ii) Above 3MW and upto 13 MW, 33 kV S/C | - Rs. 12.50 lakh/km |
| (iii) Above 13 MW and upto 25 MW, 33 kV 2 x S/C or DC | - Rs. 170 lakh/km |
Provided that in case more than one generating stations construct, at its own cost, a common evacuation infrastructure including pooling switching station, in accordance with Regulation 43 of these Regulations, for evacuation of power of their generation, then the above normative levelised tariff shall be apportioned among all such generating stations on the basis of their installed capacity.
Provided further that where the transmission line from inter-connection point to nearest sub-station is partly constructed by distribution licensee and partly by generating company, normative levelised tariff of 7 paise/kWh or 14 paisa/kWh, as the case may be, shall be as per length of the line constructed by the generating company in proportion to the overall length of the line i.e. from inter-connection point to sub-station of the distribution/transmission licensee..
Provided that the distribution licensee will be required to exercise the option within one year from the date of commissioning of the generating station(s)."
The Commission had proposed as follows in the draft Regulations:
For the purpose of computation of project specific tariff, interest rate shall be considered as lower of the actual interest payable to the financial institutions or the average State Bank of India (SBI) Marginal Cost of Funds based Lending Rate (MCLR) (one year tenor) prevalent during the last available six months from the date of Petition plus 300 basis points
The Commission agrees with the comments of the stakeholders that frequent natural calamities and other factors affects the operations as well as the financials of the SHPs which impacts the repaying power of the developers. Taking cognizance of the above factors, the Commission had increased the spread of 200 basis points by additional 100 basis points while finalising the RE Regulations, 2018 which is already higher than the normative interest rate specified by CERC and SERCs of neighbouring states. Hence, the Commission does not find it prudent to increase the spread by 100 basis points once again.
depreciation or actual repayments whichever is higher which will impact the developer whose loan tenure would be less than 15 years, hence, on extra repayments considered it does not get extra depreciation which is fixed at 15 year tenure which is not so in the case of projects opting for generic tariff where loan repayment has been considered as equal to depreciation. Thus, to remove this disparity the Commission has kept the provisions of loan repayment same for both projects opting for generic tariffs and those opting for project specific tariffs, where repayment shall be considered equal to the depreciation allowed.
The Commission had proposed as follows in the draft Regulations:
“(1) The value base for the equity shall be as determined under Regulation 16Error! Reference source not found..
(2) The normative Return on Equity (Post tax) shall be 16% for the Renewable energy source based power projects. The normative Return on Equity shall be grossed up by the latest available notified Minimum Alternative Tax (MAT) rate for the first 15 years of the Tariff Period and by the latest available notified Corporate Tax rate for the remaining Tariff Period to work out the pre-tax RoE.”
The Commission had proposed as follows in the Draft Regulations:
For payment of bills of the generating company through any mode within the specified period below, a rebate shall be allowed to the distribution licensee as follows:
| No. of days from the date of presentation of bill within which payment is credited in generating company account | Applicable Rebate (%) |
|---|---|
| Within 7 days | 1.65 |
| From 8th day to 15th day | 1.50 |
| From 16th day to 23rd day | 1.35 |
| From 24th day to 30th day | 1.25 |
Explanation: The number of days shall be counted consecutively without considering any holiday. However, in case the last day is official holiday, last day for the purpose of rebate shall be construed as the immediate succeeding working day.”
can be pledged as guarantees to developer on behalf of the buyers. This provision may also be included.
comment is rejected.
“For payment of bills of the generating company through Letter of Credit or any other mode within the specified period below, a rebate shall be allowed to the distribution licensee as follows:
| No. of days from the date of presentation of bill within which payment is credited in generating company account | Applicable Rebate (%) |
|---|---|
| Within 7 days | 1.65 |
| From 8th day to 15th day | 1.50 |
| From 16th day to 23rd day | 1.35 |
| From 24th day to 30th day | 1.25 |
”
In the draft regulation, the Commission had proposed the 1st proviso as follows:
“Provided that only 75% of the capital subsidy for the financial year of commissioning as per applicable scheme of MNRE shall be considered for tariff determination.
In the draft regulation, the Commission had proposed as follows:
"Tariff determined under these regulations shall be including direct taxes on income but exclusive of other taxes and duties as may be levied by the appropriate Government.
Provided that the taxes, duties and cess levied by the appropriate Government other than direct taxes shall be allowed as pass through on actual incurred basis."
The Commission had proposed as follows in the draft Regulations:
"Since RE Sources are dependent on vagaries of nature and are of small capacities, the principle of merit order dispatch/purchase shall not be applicable to supply of power from such sources to the distribution licensee or local rural grids within the State, i.e. they shall be treated as must run stations."
details by the RE Generators. UREDA, being a nodal agency for development of renewable power plant in Uttarakhand, is responsible to inform the generators regarding submission of schedule of energy to SLDC in accordance with the provisions of UERC DSM Regulations
In the draft regulation, Regulation 16(8) specifies as under:
"The technology specific parameters for determination of generic tariffs for Small Hydro Generating Stations commissioned or to be commissioned on or after 01.04.2023 of these regulations shall be as follows:
| Project Size | Capital Cost | O&M Expenses for year of commissioning | Capacity Utilization Factor* | Auxiliary Consumption |
|---|---|---|---|---|
| (Rs. Lakh/MW) | (Rs. Lakh/MW) | (%) | (%) | |
| Upto 5 MW | 1150 | 59.43 | Generic Tariff- 40% Project Specific- 45% |
1% |
| > 5 MW & upto 15 MW | 1125 | 53.33 | ||
| > 15 MW & upto 25 MW | 1100 | 47.54 |
* for the recovery of Annual Fixed Charges.
NOTE: For the purpose of this Regulation, normative CUF is based on Energy Sent Out at interconnection point and for tariff purposes energy net of free power to the home State, if any, committed by the developer shall be factored. For generic tariff determination, home State share has been taken as 18% from 16th year onwards."
1.24.1 M/s Siyangad Hydro Pvt. Ltd., M/s Jalandharygad Hydro Pvt. Ltd. and M/s Kakoragad Hydro Pvt. Ltd. submitted that proposed capital cost is very less. It should be enhanced to Rs. 1500 Lakh, Rs. 1475 Lakh and Rs. 1450 Lakh for plants having capacity upto 5 MW, 6 MW to 15 MW and 16 MW to 25 MW respectively. All the inputs have increased. Benchmark cost may be obtained from AHEC-IIT Roorkee and IREDA. The Stakeholders also submitted that Annual escalation for inflation on the assumed benchmark capital costs for levelized generic tariff for SHPs may be allowed. Capital cost for SHPs having COD during FY 2027-28 will be higher than SHPs having COD in FY 2023-24.
The Stakeholders also requested to allow 10% higher generic capital cost and 10% higher levelized tariff for SHPs located at high altitudes of over 2000 m, due to
increased labour, material, construction and transportation costs. SHPs in Uttarakhand are located in high seismic zones and also subject to natural calamities such as earthquakes, cloudburst, floods landslides etc which require to be insured at high insurance premiums. Insurance premium of 1.5% of capital cost should be further added in O&M cost.
Generic tariff may be posted on the website of the Commission. The total average levelized generic tariff recovered at 45% should be allowed even on CUF over 45% as risk for any under recovery of revenue for CUF below 40% is also borne by SHP developers.
The Stakeholders submitted that the Commission has allowed capital cost of Rs. 28.76 Crore for UJVNL's Dunao SHP (1.5 MW) where translates into Rs. 19.17 Crore/MW. Vyasi HEP (120 MW) has a declared capital cost of Rs. 15.80 Crore/MW. Further, cost of reinforcement Steel, MS Steel, Cement, Diesel & Oil, wages has increased which will be more than 5.72% p.a.
The Stakeholder also submitted that silt content in the river of Uttarakhand rivers is very high and this is driving up the maintenance costs of electro-mechanical and hydro-mechanical components of the hydro power projects. As such the O&M costs must be adjusted taking into account the ground realities so that the projects remain viable over the course of their useful life of 35 years.
from 45% to 40% for recovery of Annual Fixed Charges and consequently determination of generic tariff. However, though the Projects with Project specific tariff also face similar challenges but such benefit of reduction of CUF was not extended for them. Therefore, it is requested to the Commission to extend the benefit to project specific tariff also. The CUF linked to DPR may be dispensed with and same CUF of 40% may be allowed to Project Specific Tariff. The stakeholder submitted that in most of the DPRs the PLF is less than 45% PLF, therefore, unlinking CUF as reported in the DPR is of hardly of any consequence.
The stakeholders also submitted that the Commission may revisit the technical parameters of hydropower projects. The cost of the projects is highly inadequate considering the cost of labour and material. The project Lakhwar Vyasi has accepted the capital of Rs. 18 Crore per MW with O&M Expenses claimed at Rs. 72 Lakh per MW. Normally capital cost of small hydro cost is more than the cost of large projects as also the O&M charges of the small projects is more than large projects. Therefore, the capital cost and O&M charges may also be allowed at a rate more than allowed in the case of Lakhwar Vyasi.
M/s Siyangad Hydro P Ltd., M/s Jalandharygad Hydro Pvt. Ltd. and M/s Kakoragad Hydro Pvt. Ltd. submitted that SHPs in Uttarakhand are located in high seismic zones and also subject to natural calamities such as earthquakes, cloudburst, floods landslides etc which require to be insured at high insurance premiums. Insurance premium of 1.5% of capital cost should be further added in O&M cost.
M/s Chamoli Hydro Power P. Ltd., M/s Birahi Ganga Hydro Power Ltd., M/s Himalaya Hydro Pvt. Ltd. and All India Renewable Energy Protection Association that reinforcement Steel, MS Steel, Cement, Diesel & Oil, wages has increase which will be more than 5.72%. M/s Uttar Bharat Hydro Power P. Ltd. submitted that silt content in the river of Uttarakhand rivers is very high and this is driving up the maintenance costs of electro-mechanical and hydro-mechanical components of the hydro power projects. As such the O&M costs must be adjusted taking into account the ground realities so that the projects remain viable over the course of their useful life of 35 years.
| Capacity | Himachal Pradesh (Rs. Lakh/MW)* |
Arunachal Pradesh (Rs. Lakh/MW) |
Assam (Rs. Lakh/MW)# |
|---|---|---|---|
| Upto 500 kW MW | 1100 | 1400 | 1000 |
| Above 500 kW to below 1 MW | 1200 | ||
| 1 kW to 2 MW | Project Specific | ||
| Above 2 MW to 5 MW | 1100 | 900 | |
| Above 5 MW to 25 MW | 1100 |
*as per Draft Regulations issued on 20.07.2023.
#as per RE Regulations 2017
It can be observed from the above table, that the neighbouring State, i.e. Himachal Pradesh has specified the benchmark capital cost lower than the capital cost proposed by this Commission. Further, HPERC has considered the same capital cost as specified by CERC irrespective of installation capacity. Assam ERC has specified benchmark capital cost as specified by Central Commission vide its repealed RE Regulations, 2017. Further, as per Section 61 of the Act, the State Commissions shall be guided by the principles and methodology specified by the Central Commission for tariff determination. Accordingly, the Commission does not find it prudent to change the capital Costs in the final Regulation.
1.24.8 During the finalisation of RE Regulations, 2018, with regard to revision of O&M expenses, most of the SHP developers requested the Commission for revision of the O&M expenses and allow O&M expenses equivalent to the Large Hydro Projects. Accordingly, to bring parity between the O&M expenses for LHP and SHP, the Commission had revised the normative O&M expenses. However, now some of the SHP developers have claimed that the O&M expenses of SHPs are more than Large Hydro Plants. However, supporting documents have not been submitted by the stakeholders to validate their claim. Accordingly, the Commission does not find it prudent to review the O&M expenses.
1.24.9 Further, with regard to the comment of M/s Him Urja Associate regarding equal CUF of 40% for generators opting for generic tariff and generator opting for project specific tariff, since the developers have an option to get their tariff determined based on the actual capital cost, accordingly, their CUF should also be considered to be equal to that provided in the DPR as that would be the close to the actual CUF that can be attained by the project based on the past studies. This dispensation has been allowed since RE Regulations 2010, based on Hon'ble ATE's Judgment dated 18.09.2009 in Techman Infra Ltd. vs. HPERC and others. Hence, no change is warranted in this regard.
In the draft regulation, the Commission had proposed Regulation 34, i.e. Solar PV Power Project, as follows:
“Norms for Solar Photovoltaic (PV) power under these Regulations shall be applicable for grid connected PV systems that directly convert solar energy into electricity and are based on the technologies such as crystalline silicon or thin film etc. as may be approved by MNRE. The technology specific parameters for determination of generic tariffs for Solar PV Power Projects commissioned or to be commissioned on or after 01.04.2023 shall be as follows:
| Capital Cost | O&M Expenses for year of commissioning | Capacity Utilization |
|---|---|---|
| (Rs. Lakh/MW) | (Rs. Lakh/MW) | Factor |
| 360.47 | 16.24 | 19 % |
“
In the draft regulations, the Commission had proposed Regulation 35, i.e. Canal bank Solar PV Plants and Canal top Solar PV Plants, as follows:
“Norms for canal bank Solar PV Power Plants and canal top Solar PV Power Plants under these Regulations shall be applicable for grid connected PV systems that directly convert solar energy into electricity and are based on the technology specific parameters for determination of generic tariffs for such power projects commissioned or to be commissioned on or after 01.04.2023 shall be as follows:
| Type Solar PV Plant | Capital Cost | O&M Expenses for year of commissioning | Capacity utilization |
|---|---|---|---|
| (Rs. Lakh/MW) | (Rs. Lakh/MW) | Factor | |
| Canal Bank Solar PV Plant | 550.00 | 16.24 | 19% |
| Canal Top Solar PV Plant | 575.00 |
“
In the draft regulations, the Commission had proposed Regulation 36, i.e. Solar Thermal Power Project, as follows:
“Norms for Solar thermal power under these Regulations shall be applicable for Concentrated solar power (CSP) technologies viz. line focusing or point focusing, as may be approved by MNRE, and uses direct sunlight, concentrating it several times to reach higher energy densities and thus higher temperatures whereby the heat generated is used to operate a conventional power cycle to generate electricity. The technology specific parameters for determination of generic tariffs
for Solar Thermal Power Projects commissioned or to be commissioned on or after 01.04.2023 shall be as below:
| Capital Cost | O&M Expenses for year of commissioning | Capacity Utilization Factor | Auxiliary Consumption |
|---|---|---|---|
| (Rs. Lakh/MW) | (Rs. Lakh/MW) | ||
| 1200 | 22.14 | 23% | 10% |
“
In the draft regulation, the Commission had proposed Regulation 37, i.e. Grid interactive rooftop and small solar PV plants, as follows:
“(1) The technology specific parameters for determination of generic tariff for GRPV and GSPV commissioned or to be commissioned on or after 01.04.2023 shall be as below:
| Project Size | Capital Cost | O&M Expenses for year of commissioning | Capacity Utilization Factor |
|---|---|---|---|
| (Rs./kW) | (Rs./kW) | ||
| Upto 10 kW | 46709 | 2149 | 19 % |
| >10 kW & upto 100 kW | 42852 | 1912 | |
| >100 kW & upto 500 kW | 40207 | 1735 | |
| >500 kW and upto 1 MW | 39249 | 1624 |
(2) GRPV and GSPV can be installed for injecting power into the distribution system of a licensee by any Eligible consumer:
Provided that the maximum GRPV and GSPV installed capacity at any Eligible Consumer's premises shall be upto a maximum of 100% of consumer's sanctioned load/contract demand;
Provided that in case of Domestic Consumer, such installed capacity of GRPV and GSPV shall be irrespective of consumer's sanctioned load/contract demand;
Provided, the maximum installed capacity of GRPV and GSPV at the premises of eligible consumer shall not be more than 1 MW.
(3) Injection from GRPV and GSPV owned by the Eligible consumer or by third party shall be settled on Net Energy basis at the end of each Billing period.
(4) The tariff, as per tariff orders of the Commission, in respect of the supply of electricity to the consumers by the distribution licensee shall be applicable for the Net Energy supplied by the licensee in a billing period if the supplied energy by the licensee is more than the energy injected by the GSPV and GSPV of the consumer or by third party:
Provided that such eligible consumer shall be exempted from payment of monthly minimum charges/monthly minimum consumption guarantee charges, if any, equivalent to the capacity of GRPV and GSPV installed at the premises;
Provided further that no open access charges including surcharges shall be leviable on such eligible consumers for the captive use of power.
Further, UREDA also requested to add the following after first proviso of sub-regulation (2) of Regulation 37:
“Provided that in case of behind the meter captive rooftop solar system (with or without storage) shall be irrespective of consumer’s sanctioned load/contracted load”
UREDA also requested to replace sub-regulation (5) with the following:
“If in a billing period the supplied energy by the licensee is less than the energy injected by the GRPV and GSPV of the consumer/prosumer or the third party, subject to provisions in sub-Regulation (3) above, the licensee would pay to such prosumer at the generic tariff as may be specified by the Commission or at the rate discovered through tariff based bidding process whichever is lower for such Net Energy supplied to it.”
1.25.2 Akshay Urja Association submitted that module cost has increased due to increase in GST and import duty on cells and modules. Further, circle rate has also gone up. CUF is between 13% to 15% in the state of Uttarakhand. Furthermore, under Mukhyamantri Saur Swarajgar Yojna, GoUk has considered capital cost of Rs. 5 Crore/MW. Due to the above factors, cost of Canal bank and Canal Top Solar PV plants may also increase. The stakeholder also submitted that interest rates have increased significantly, hence, IDC has also increased in same proportion. This hike results in overall increase in the project's capital cost.
The Stakeholder also requested to allow deemed generation provision for GRPV and GSPV in case of interconnection to 11 kV evacuation as they would stand to be classified as must run stations.
1.25.3 UJVN Ltd. submitted that the current average cost of Solar PV plant is Rs. 5 Crore/MW. HPERC has taken project cost of Rs. 4.07 Crore/MW for solar PV plants for FY 2023-24. Design and installation of Solar capacity on DC side should be left to the developer. Therefore, the Commission is requested to consider the minimum escalation of 20% on cost of Solar PV modules on account of AC/DC ratio. Further, UJVN Ltd. also requested the Commission to specify category wise tariff for Solar PV plants on MW basis (i) Less than 5 MW, (ii) 5 MW to 15 MW and (iii) 15 MW to 25 MW.
With regard to Canal Bank and Canal Top Solar PV Plants, UJVN Ltd. submitted that land is available over a lengthy stretch due to various structures and encroachment on the banks in between, land is not available in continuity. Due to which substantial cost is incurred on civil work, water supply pipelines, fencing, lighting security and O&M. Recently, Canal Bank Solar PV DPR are also prepared based on current market survey. The project cost has been worked out to Rs. 6 Crore/MW.
1.25.4 M/s DS Solar Energy Pvt. Ltd and M/s Fairdeal Solar Energy Pvt. Ltd. submitted that GST has increased from 5% to 12% and the cost of other materials including steel & manpower for installation & commissioning work has also increased by 25% to 40%. Capital cost of the project installed is Rs. 4.20 Lakh/MW without GST and Rs. 4.80 Lakh/MW with GST.
the matter, it would be wrong to allow recovery of excess energy injected into the grid at the generic tariff if the solar power plant are allotted to the developer including consumer/prosumer or third party based on competitive bidding. Accordingly, the Commission rejects the proposal. Further, insertion of sub-regulation “Group Net metering framework shall be applicable for all consumers”. The Commission does not find it prudent to enter the same under Regulation 37 as the same has already been dealt in Regulation 40.
| Financial Year | Average Module cost USD/Wp |
|---|---|
| FY 2018-19 | 0.317 |
| FY 2019-20 | 0.241 |
| FY 2020-21 | 0.241 |
| FY 2021-22 | 0.210 |
| FY 2022-23 | 0.218 |
From the above table, it is explicitly clear that with the passage of time, cost of solar technology is declining. There is a decline of 31.50% in the cost of modules in the last five years. Further, in the month of May 2023, the average of module cost was USD 0.193/Wp and now which has further reduced to USD 0.166/Wp.
The Commission in its draft Regulations had considered the cost of Solar PV Module as Rs. 360.47 Lakh/MW considering the exchange rate of Rs. 82.23/USD based on then available exchange rate for the last six months, considering the module cost of 0.193 USD/Wp, degradation of 0.50% and 20% additional cost for duties and other expenses. As per the website of www.pvinsights.com which provides the spot price of modules in international market, the latest Solar PV Module Weekly support Price, as
accessed on 02.08.2023, is as under:-
| Item | Average (USD/Wp) |
|---|---|
| Poly Module | 0.143 |
| Mono PERC Module in China | 0.147 |
| Thin Film Solar Module | 0.209 |
The average of these works out to 0.166 USD/Wp against 0.193 USD/Wp considered in Draft Regulations. Further, average exchange rate for the last six months works out to Rs. 82.28/USD against Rs. 82.23/USD considered exchange rate of last six months. Accordingly, based on the above discussion and considering the degradation of 0.50%, the module cost works out to Rs. 136.69 Lakh/MW. The Government of India has announced levy of import duty, w.r.f. 01.04.2022, on the import of Solar PV cells and Solar PV modules @ 25% and 40% respectively. Moreover, the GST rate for the goods component has also been increased from 5% to 12%. Apart from the above, the Government of India has provided for the production linked incentive of Rs. 4500 Crore, in addition to the production linked incentive of Rs. 19500 Crore provided for the budget proposed for FY 2022-23 which is applicable for current year also. All the factors would have overlapping and diverse effects and may also increase the competitiveness. Such factors shall impact the market rates at which the Solar PV cells and Solar PV modules shall be available from various sources. Moreover, the difference in the cost of Solar PV cells and module as well as taxes thereon, if availed optimally, can also facilitate marginal reduction in the over-all cost of the panels.
After taking all related factors into account and comments of various stakeholders regarding bank charges for conversion of INR to USD, taxes & duties and overheads, the Commission decides to escalate the module cost by 28%. Accordingly, the module cost works out to Rs. 180.04 Lakh/MW.
The Commission would like to clarify that the escalation on account of additional taxes is being provided purely on normative basis after balancing various factors affecting the market conditions as discussed above and shall be applicable irrespective of the actual channel of procurement of the Solar PV modules. In fact, in case of procurement from indigenous sources the BCD/SGD will not be applicable at all. The Commission feels that this approach will not only enable the developers to procure the modules in the most economical manner but may also encourage procurement from indigenous sources.
Further, the Commission decides to retain the CUF specified under the draft regulations as the same is lower than the CUF specified by the neighbouring States and Central Commission. Further, it is pertinent to mention that the CUF of 19% was fixed considering Poly Silicon Solar Module and Thin Film Solar Module. However, in the present Order, the Commission has considered Mono PERC Solar Module which is an advance technology in comparison to Thin film Solar Module and results into higher CUF which in turn reflects higher generation from the said modules. Moreover, the Commission has considered the spot prices which are generally on a higher side, and the developers will have the benefit of economies of scale on bulk purchase as well as enjoy bulk purchase discount. Furthermore, the Commission in the current regulations has retained additional 300 points for interest on normative loan above the average SBI MCLR (one year) prevailing for last available six months in accordance with the provisions specified by CERC which has been reduced to 200 basis points vide RE Regulations, 2020 by CERC. Moreover, the Commission has approved annual O&M expenses on a very higher side in comparison to other States. Accordingly, the solar power developers in the State will gain additional interest benefit of 1% as the Commission has kept the interest rate based on 300 basis points and increased the O&M expenses which may offset the increase under one head by decrease under the other head.
Further, with regard to Land cost, some of the stakeholder submitted that due to increase in circle rates, the land cost will increase. In the matter, it is pertinent to mention that under most of the schemes the projects are proposed to be installed in barren lands of hilly terrain. Further, stakeholders have not submitted any supporting documents to support their claim. The Commission has considered 5 acres of land for Solar PV plant having capacity of 1 MW. However, as discussed earlier, with the change in technology lesser area is required for installation of Solar PV plants. Accordingly, saving in the land cost can be utilized to make the land suitable for installation of Solar PV plant. Moreover, as per Solar Policy, 2023 the detailed guidelines for lease rent determination will be notified by UREDA on their website from time to time in consultation with Uttarakhand Solar Power Land Allotment Committee. Accordingly, the Commission may review the land cost while determining the capital cost for solar energy based projects in ensuing year based on the information of lease rent available with UREDA.
The Commission had earlier approved the cost for other components for FY 2022-23 of Rs. 108.96 Lakh/MW escalating by 20% to factor in the hike in prices and change in technology then. Now for FY 2023-24, the Commission has escalated the said amount based on the average of CPI and WPI of last three years giving equal weightage. Accordingly, the Capital cost for Solar PV plants works out to Rs. 345.11 Lakh/MW.
Further, with regard to capital cost of Canal Bank Solar PV Plants and Canal Top Solar PV plants, on one hand UJVN Ltd is proposing a higher capital cost and on the other, the tariff bidded by its developers in the range of Rs. 4.18 per unit to Rs. 4.26 per unit. Hence, there seems no reason to specify higher capital cost for the same. Further, the land is already owned by it and any increase in other cost components can be offset by the land costs which is a saving to it. Hence, the Capital Cost for Canal Bank Solar PV plant has been specified as Rs. 400 Lakh/MW and Capital cost for Canal Top Solar PV Plant as Rs. 425 Lakh/MW
1.25.9 Accordingly, based on the above discussion, Regulation 34 shall be read as follows:
“Norms for Solar Photovoltaic (PV) power project under these Regulations shall be applicable for grid connected PV systems that directly convert solar energy into electricity and are based on the technologies such as crystalline silicon or thin film etc. as may be approved by MNRE. The technology specific parameters for determination of generic tariffs for Solar PV Power Projects commission or to be commissioned on or after 01.04.2023 shall be as follows:
| Capital Cost | O&M Expenses for year of commissioning | Capacity Utilization |
|---|---|---|
| (Rs. Lakh/MW) | (Rs. Lakh/MW) | Factor |
| 345.11 | 16.24 | 19 % |
“
1.25.10 Based on the above discussion, Regulation 35 shall be read as follows:
“Norms for canal bank Solar PV Power Plants and canal top Solar PV Power Plants under these Regulations shall be applicable for grid connected PV systems that directly convert solar energy into electricity and are based on the technology specific parameters for determination of generic tariffs for such power projects commissioned or to be commissioned on or after 01.04.2023 shall be as follows:
| Type Solar PV Plant | Capital Cost | O&M Expenses for year of commissioning | Capacity utilization Factor |
|---|---|---|---|
| (Rs. Lakh/MW) | (Rs. Lakh/MW) | ||
| Canal Bank Solar PV Plant | 400.00 | 16.24 | 19% |
| Canal Top Solar PV Plant | 425.00 |
“
1.25.11 Based on above discussion, Regulation 37 shall be read as follows:
“(1) The technology specific parameters for determination of generic tariff for GRPV/GSPV commissioned or to be commissioned on or after 01.04.2023 shall be as below:
| Project Size | Capital Cost | O&M Expenses for year of commissioning | Capacity Utilization Factor |
|---|---|---|---|
| (Rs. /kW) | (Rs./kW) | ||
| Upto 10 kW | 47691 | 2149 | 19 % |
| >10 kW & upto 100 kW | 43753 | 1912 | |
| >100 kW & upto 500 kW | 41276 | 1735 | |
| >500 kW and upto 1 MW | 40074 | 1624 |
(2) GRPV/GSPV can be installed for injecting power into the distribution system of a licensee by any Eligible consumer:
Provided that the maximum GRPV/GSPV installed capacity at any Eligible Consumer's premises shall be upto a maximum of 100% of consumer's sanctioned load/contract demand;
Provided that in case of Domestic Consumer, such installed capacity of GRPV/GSPV shall be irrespective of consumer's sanctioned load/contract demand;
Provided, the maximum installed capacity of GRPV/GSPV at the premises of eligible consumer shall not be more than 1 MW.
(3) Injection from GRPV/GSPV owned by the Eligible consumer or by third party shall be settled on Net Energy basis at the end of each Billing period.
(4) The tariff, as per tariff orders of the Commission, in respect of the supply of electricity to the consumers by the distribution licensee shall be applicable for the Net Energy supplied by the licensee in a billing period if the supplied energy by the licensee is more than the energy injected by the Roof-Top Solar PV plant of the consumer or by third party:
(4) The tariff, as per tariff orders of the Commission, in respect of the supply of electricity to the consumers by the distribution licensee shall be applicable for the Net Energy supplied by the licensee in a billing period if the supplied energy by the licensee is more than the energy injected by the GSPV/GSPV of the consumer or by third party:
Provided that such eligible consumer shall be exempted from payment of monthly minimum charges/monthly minimum consumption guarantee charges, if any, equivalent to the capacity of GRPV/GSPV installed at the premises;
Provided further that no open access charges including surcharges shall be leviable on such eligible consumers for the captive use of power.
(5) If in a billing period the supplied energy by the licensee is less than the energy injected by the GRPV/GSPV of the consumer/prosumer or the third party, subject to provisions in sub-Regulation (3) above, the licensee would pay to such prosumer at the generic tariff as may be specified by the Commission or at the rate discovered through tariff based bidding process whichever is lower for such Net Energy supplied to it
(6) Provisions of Deemed Generation shall not be applicable on GRPV/GSPV.
(7) The cumulative capacity of GRPV/GSPV which can be connected to a single transformer shall not exceed the capacity of such transformer.
(8) In case any augmentation is required for the purpose of connecting GRPV/GSPV, Distribution Licensee shall facilitate and bear the capital expenditure on account of such system strengthening/augmentation upto the interconnection point from nearest sub-station.
(9) Virtual Net Metering Framework shall be applicable for consumers under domestic category, offices of Government /Local Authorities."
The Commission had proposed as follows in the Draft Regulations:
“(1) The capacity of the renewable energy plant under Group Net Metering or Virtual Net Metering framework to be installed by any consumer(s) shall not be less than 5 kW and more than 75 kW.
(2) The Procedure for billing and energy accounting of electricity connection(s) under Group Net Metering shall be in accordance with the provision of these regulations.
(3) Where the export of units during any billing period exceeds the import of units at the connection where solar power plant is located, such surplus units injected into the grid shall be adjusted against the energy consumed in the monthly bill of the service connection(s) in a sequence indicated in the priority list provided by the consumer. The
sequence of priority for adjustment shall be deemed to being with the service connection where the solar power plant is located.
(4) The electricity consumption in any time block (eg. Peak hours, off-peak hours, etc.) shall be first compensated with the electricity generation in the similar time blocks in the same billing cycle of the participating consumer(s). Any surplus generation over consumption in any time block in a billing cycle shall be accounted as if the surplus generation/ energy credits occurred during the non-peak time block.
(5) Where the units credited during any billing period of any participating consumer exceeds the import of units by that consumer, licensee would be billed at the generic tariff as may be specified by the Commission or at the rate discovered through tariff based bidding process whichever is lower for such surplus."
1.26.1 UJVN Ltd. submitted that the capacity of RE plants under Group Net Metering or Virtual Net Metering framework to be installed by any consumer shall not be less than 5 kW or more than 1000kW.
1.26.2 Akshay Urja Association submitted that a separate net-metering policy incorporating Virtual Net Metering should be drafted in sync with Solar Policy, 2023. The stakeholder also submitted that provisions w.r.t. Virtual Net Metering and Group as mandated by MNRE and incorporated in Solar Policy, 2023 much be included in the regulations. With regard to Virtual Net Metering, Akshay Urja Association submitted that the provisions of the regulations may be aligned with the provisions of Solar Policy, 2023. No open access charges may be levied for plants installed under Virtual Net Metering for sale to Discom or captive use or third party sale as per provisions of virtual net metering. Further, installation of GRPV and GSPV may be allowed in any location under distribution area in the entire state.
The Stakeholder requested the Commission to increase the maximum limit specified for virtual net metering and group net metering, i.e. from 75 kW to 1 MW. The Stakeholder also submitted that the adjustment of net energy with UPCL under virtual net metering may be allowed in the same financial year instead of one billing cycle.
1.26.3 UREDA submitted that surplus power injected by the prosumer should be billed at the generic tariff as specified by the Commission.
In the draft Regulation, the Commission had proposed as follows:
“(1) Transmission Charges: For non-discriminatory ‘open access’ to the intra-State transmission system for carrying the electricity generated by the RE Based Generating Stations or Co-generating Stations to the destination of use, the RE generator or the consumer, as the case may be, shall have to pay the transmission charges and wheeling charges for use of intra-state transmission system and distribution system which shall be calculated based on the principles specified in UERC (Terms and Conditions of Intra-State Open Access) Regulations, 2015 read with amendments from time to time:
Provided that no Transmission and Wheeling Charges are payable for sale of electricity to distribution licensee or to local rural grid within the State;
Provided further that where a generating company proposes to supply electricity outside the State, such generating company, in addition to transmission/wheeling charges specified above, shall have to bear the transmission/wheeling charges determined by the Commission on case to case basis for the dedicated lines and substation of the transmission/distribution licensee used only for evacuation of such power;
Provided further that where more than one generating company proposes to supply electricity outside the State over common dedicated transmission/distribution system of transmission/distribution licensee for evacuation of their power, such generating companies, in addition to transmission/wheeling charges specified above, shall have to bear the full transmission/wheeling charges determined by the Commission on case to case basis for such dedicated lines and substation of the transmission/distribution licensee used only for evacuation of such power on pro-rata basis of installed capacity.”
The Commission had proposed as follows in the Draft Regulations:
“(1) Distribution Licensees shall provide connectivity to the RE Based Generating Stations having capacity upto 25 MW at its nearest distribution sub-station preferably within a range of 10 kilometers from the location of such generating station. They may further mutually agree to provide connectivity at appropriate voltage level subject to technical feasibility and technical standards for construction of electrical lines and connectivity with the grid as may be specified by CEA.
Provided further that where more than one RE based Generating Stations having cumulative installed capacity less than 25 MW are located in a cluster/area and for the purpose of evacuation, these generating stations agree to pool their generation at a common pooling switching station to be constructed by them at their own cost and further beyond such pooling switching station, the Distribution Licensee shall provide connectivity at its nearest sub-station. They may further mutually agree to provide connectivity at appropriate voltage level subject to technical feasibility and technical standards for construction of electricity lines and connectivity with the grid as may be specified by CEA. However, such generating stations shall be eligible for additional levelised tariff as specified under Regulation 16(1)(c) of these Regulations, only if they construct the line from pooling sub-station to the nearest sub-station at their own costs.
Provided that any RE based Generating Station having capacity upto 25 MW is willing to connect and evacuate power through 132 kV & above transmission system, it may do so subject to consent of the Transmission Licensee.
Provided further that where more than one RE based Generating Stations having cumulative installed capacity more than 25 MW are located in a cluster/area and for the purpose of evacuation, these generating stations agree to pool their generation at a common pooling switching station to be constructed by them at their own cost and further beyond such pooling switching station, the Transmission Licensee shall provide connectivity at its nearest sub-station. They may further mutually agree to provide connectivity at appropriate voltage level subject to technical feasibility and technical standards for construction of electricity lines and connectivity with the grid as may be specified by CEA. However, such generating stations shall be eligible for additional levelised tariff as specified under Regulation 16(1)(c) of these Regulations, only if they construct the line from pooling sub-station to the nearest sub-station at their own costs.
The generators and licensees (both Transmission licensee and Distribution licensee) are advised to discuss amongst them the issues and devise a suitable condition/clause in the connectivity agreement/PPA/TSA specifying the liability of either parties in cases where the generating station is ready for commissioning but due to non-availability of proper evacuation system the generating station is unable to achieve COD and is lying idle and also in cases where construction of generating station is delayed while the evacuation infrastructure is completed and ready to evacuate generation.
The Commission had proposed as follows in the Draft Regulations:
"The eligible consumer shall be solely responsible for any incidents/accident to human being/ animals whatsoever (fatal/nonfatal/departmental/non-departmental/damages to material of the licensee) that may occur due to back feeding from the solar plant when the grid supply is off and such consumer shall not only bear the cost of the damages to the material of the licensee but also compensate for the life of any human being/animals in case of such incidents/accidents. The distribution licensee reserves the right to disconnect the consumer's installation at any time in the event of such exigencies to prevent accident or damage to man and material."
In the draft Regulation, the Commission had proposed as follows:
“(1) Any person, who establishes, maintains and operates a generating station and normally does not need power from the licensee round the year, may purchase electricity from a generating company or a distribution licensee in case his plant is not in a position to generate electricity to meet the requirement of his own use or for start up and consequently power is required to be drawn from distribution licensee:
Provided that in case electricity generated from the plant is being exclusively sold to the State Distribution Licensee, the electricity (in kWh) procured by the Generating Station from the State Distribution Licensee to meet its requirement of his own use or for startup power, will be adjusted from the electricity sold to the Distribution Licensee on month to month basis. The Distribution Licensee shall make the payment for net energy sold to it by the Generating Company, i.e. difference of the total energy injected into the grid and energy drawn from the grid by the Generating Company.
In case the energy supplied by the distribution licensee is more than the energy injected by the generating company, the net energy (in kWh) thereof shall be charged as per the tariff determined by the Commission for temporary supply under appropriate “Rate Schedule of tariff” for Industrial Consumers considering maximum demand during the month as the contracted demand for that month. The Fixed/Demand charges for that month shall be payable for the number of days during which such supply is drawn.
Provided further that in case electricity generated from the plant is sold to third party other than the Distribution Licensee, then such purchase of electricity by the generating company from the distribution licensee, shall be charged as per the tariff determined by the Commission for temporary supply under appropriate "Rate Schedule of tariff" for Industrial Consumers considering maximum demand during the month as the contracted demand for that month. The Fixed/Demand charges for that month shall be payable for the number of days during which such supply is drawn."
"In case the energy supplied by the State Distribution Licensee is more than the energy injected by the generating company, the net energy (in kW) thereof shall be charged at equal rate to the tariff of that generating plant."
In the draft Regulations, the Commission had proposed as follows:
"(1)The Generating Stations shall be allowed to bank power within a period of one calendar month, for the purpose of withdrawal of the banked power in the event of emergency or shut
down or maintenance of the plant, subject to following conditions:
1.31.1 UREDA requested the Commission to add the following provision:
“Excess generation during non-peak hours by distributed solar power plants shall be a deemed purchase by Discom and compensated at the tariff determined by the Commission. Discom shall aggregate the excess generation to create a green pool. This green energy pool shall be made available by the Discom to the consumers at the green tariff rate.”
1.31.5 The Stakeholders requested the Commission to reduce the banking charges stating that the same are too high and banking may be allowed annual basis. In the matter, it is pertinent to mention that the Forum of Regulators issued “Model Regulation on Methodology for calculation of Open Access charges and Banking charges for Green Energy Open Access Consumers” wherein FOR has specified the banking charges and the permitted banking period. Model Regulations specifies that the Banking Charges shall be adjusted in kind @ 8% of the energy banked and banking of energy shall be permitted only on monthly basis as per Calendar month. Accordingly, the Commission decides to reduce the banking charges to 8% whereas the request of the stakeholders for permitting the annual adjustment of banking is rejected keeping in view the Model Regulations issued by FOR.
1.31.6 With regard to the comments of IEX, it is pertinent to mention that the Commission has issued draft Green Open Access Regulations, 2023 which covers banking provisions of green energy in line with MoP Green Energy Open Access Rules.
1.31.7 UREDA has requested the Commission to incorporate the provision to consider the excess energy generation by the Solar Power plant as deemed purchase by the distribution licensee and compensated at tariff determined by the Commission. In the matter, it is pertinent to mention that the Commission vide its draft Green Open Access Regulations, 2023 has provided a provision for energy supplied during non-peak hour. Accordingly, to bring parity among the regulations, the Commission decides to insert the following provision:
“(i) Banking charges shall be adjusted in kind @8% of the energy banked.
(k) The energy banked during non-peak hours (TOD slots) shall be permitted to be drawn during non-peak hours (TOD slots) by only paying the banking charges and from non-peak hours (TOD slot) to peak hours (TOD slot) by paying charges in kind @ equivalent to % of difference between the Peak hours energy charge rate and Normal hours energy charge rate (as defined in the respective Tariff Orders issued by the Commission) of the energy banked in addition to the above banking charges specified under these regulations.”
Further, the Commission decides to insert the definition of ‘non-peak hour’ for more clarity in the above regulation:
““Non-Peak Hour” means other than Peak hours as may be decided by the Commission from time to time.”
In the draft Regulation, the Commission had proposed as follows:
“(Applicable only in case of Small Hydro Generating Plants & Solar PV Plants & Solar Thermal Projects excluding Solar power plants installed under net metering arrangement)
(1) After the COD of the Project, loss of generation at the Station on account of reasons attributed to the following, or any one of the following, shall count towards Deemed Generation:
Provided that the following shall not count towards Deemed Generation:
The distribution licensee shall be required to maintain the voltages at the point of interconnection with the project within the limits stipulated hereunder, with reference to declared voltage:
Any loss in generation due to variations in the voltage beyond the limits specified above shall be reckoned as deemed generation provided such loss of generation results in reduction of more than 25% of capacity output.
(2) The period of outage/interruption on account of such factor(s) specified in sub-Regulation 1 and 2 above, shall be reconciled on monthly basis and the loss of generation at the station towards Deemed Generation after accounting for the events specified under sub-Regulation 1 (i) & (ii) above, shall be computed on following considerations:
(i) The recovery on the above account shall be admissible if the actual energy generated during the year is less than the normative CUF specified in the Regulation for small hydro projects and Solar PV and solar thermal projects (in case of project opting for generic tariff) or the CUF considered for recovery of fixed charges (in case of project specific tariff is applicable) for small hydro projects and solar PV and solar thermal projects. In case the sum of actual energy generated and the deemed generation during the year exceeds the CUF at which the recovery of fixed charges has been envisaged, then the deemed generation alongwith the actual energy generated will be allowed only upto the CUF considered.
(ii) The generation loss towards the Deemed Generation in accordance with sub-Regulation (i) above, if any, during the month shall be considered on the pro-rata basis on the number of hours lost based on the actual average generation achieved during that month divided by the total number of hours available during the month reduced by the number of hours outage/interruption occurred in the system.
(iii) The generation loss towards the Deemed Generation (in MWh) in accordance with sub-Regulation (ii) above, if any, during the month shall be considered as the summation of the product of number of hours the variations in voltage beyond the specified limit existed and the Generation lost (in MW) due to the variation in the voltage beyond the specified limit. The Generation lost (in MW) would be the difference between the following:
(a) Minimum of the generation (in MW) before the variation in voltage occurred and the generation (in MW) achieved after 90 minutes immediately after variation in voltage was restored within the specified limit would be treated as the “Actual Generation” during the period when voltage variations occurred; and
Provided that if such variation in voltage continues for the entire month, generation (in MW) before such variation in voltage occurrence would be treated as the “Actual Generation”.*
(b) The generation achieved during the period when variation in voltages took place.
(3) The distribution licensee shall pay for the saleable deemed generation, on annual basis, for Small Hydro projects and Solar PV and Solar Thermal projects worked out on the basis of the deemed generation on the above lines, at the generic/project specific tariffs as applicable in accordance with the applicable RE Regulations. The settlement of payment towards deemed generation charges shall be carried out within 3 months of the completion of the financial year.
Provided that any charges paid by the distribution licensee towards deemed generation shall not be allowed as an expense to be pass through in tariffs. The distribution licensee will have to bear such charges;*
Provided further that the deemed generation conditions stipulated above shall be applicable only on those Small Hydro projects and Solar PV and Solar Thermal projects who have signed a long term PPA with the distribution licensee;*
Provided also that the deemed generation conditions shall be applicable only on the Small Hydro projects and Solar PV and Solar Thermal projects where the evacuation line is*
connected to 11 kV or higher voltage Grid Sub-station."
With regard to Small Hydro Plants, UPCL submitted that the regulation should explicitly mention that outage of 48 hours shall be excluding force majeure conditions and synchronisation time taken by the generator for synchronising the machines on the grid. Further, no separate time should be allowed on account of the synchronisation time for calculation of the deemed generation loss otherwise generator may be lackadaisical towards prompt and timely synchronisation of the machine and even otherwise it is not technically feasible to examine whether the efforts were made or not. Further, with regard to Solar power plants, UPCL submitted that considering the generation window of 12 hours in a day in case of Solar plants in comparison to 24 hours for SHPs, the duration of outage on proportionate and equitable basis considering same analogy comes out to be 24 hours in a month in place of 50 hours.
"-In case of Below 33 kV Voltage level, +10% and -9%; and,
-In case of 33 kV and above Voltage level as per State Grid Code."
1.32.3 Ashay Urja Association submitted that Separate clause of Solar power plants may be provided as existing clauses are relevant for Hydro. Variation in voltage outage are considered over 90 minutes which does not hold relevance in the case of Solar power plants as power generated is different during different time of the day.
1.32.4 M/s Siyangad Hydro Pvt. Ltd., M/s Jalandharygad Hydro Pvt. Ltd. and M/s Kakoragad Hydro Pvt. Ltd. submitted that the current exclusion of 48 hrs in a month corresponds to 576 hours in a year, i.e. 6.57% of PLF excluded from deemed generation. With the loss of revenue in case of non-generation of power and exclusion from deemed generation upto 48 hrs in a month, the revenue from assumed 45% PLF for levelized generic tariff cannot be met.
1.32.5 M/s Chamoli Hydro Power Pvt. Ltd., M/s Birahi Ganga Hydro Power Ltd., M/s Himalaya Hydro Pvt. Ltd. and All India Renewable Energy Protection Association submitted that in present scenario, the discom appears to have adopted a policy of not complying with the applicable regulations by resorting to vexatious litigating because it is not a pass-through cost. The Calculation of generation losses due to over-voltage is very onerous and virtually impossible since the voltage levels are continuously fluctuating in UPCLs transmission system.
1.32.6 Uttar Bharat Hydro Power Pvt. Ltd. submitted that incurring power generation losses due to grid outages exceeding the allowed 48 hours/month as per RE Regulations. The voltage levels in the distribution licensees 33 kV transmission lines is not maintained in +6% to -9% range as a result of which we are suffering generation losses.
In such situation deemed generation claims are being put to the discom, however discom adopts an approach suggesting that such claims are not provided in the RE policy or the regulations. Under these circumstances, all financial losses are borne solely by SHPs. Suitable changes to the regulations are necessary to restore balance and equity between all stakeholders.
Under present regulations, the calculation of generation losses (due to forced capacity limitation) are being presented as—“due to over-voltage/under-voltage. However, such claims are not acceptable to Discom as they are not as per UERC guidelines.
It would be more appropriate to consider the highest generation recorded in a given 24 hours period, when the voltage was within limits and compute the generation losses for that particular day during the period when the voltage levels were outside the permitted levels.
1.32.7 With regard to multiple evacuation networks to the generator, it is pertinent to mention that the UPCL specifies the connectivity point/Sub-Station, to which the generating plant is to be connected after detailed study of load flow, voltage profile, Sub-station capacity and other technical parameters etc, at the time of execution of PPA with the generator. Besides it is the duty of the distribution licensee to evacuate power and provide connectivity. Further, it is to be noted that deemed generation cannot be disallowed on the basis of connectivity of the plant to independent feeder or mixed feeder. It would be appropriate for distribution licensee to strengthen its distribution network including evacuation system so that the power generated from such plant can be supplied which would in return help the distribution licensee to meet its RPO and also the demand in the State. Accordingly, the Commission does not find it prudent to change the provision of the said regulation in this regard. However, the Commission directs UPCL to strengthen the evacuation systems of that particular area where such plants are connected or proposed to be connected.
Further, force majeure conditions are already excluded from the limit of 48 hours in a month for Small Hydro Plants and such events already are defined in the Regulations. UPCL's comments regarding exclusion of synchronisation time taken by the generator for synchronising the machines on the grid does not find merit as due to outages the generator's machines were forced to stop and no generator would want to delay the synchronization just to claim deemed generation. However, the same can be examined on case to case basis and if in any case it is observed that the generator took exceptionally long time to synchronise the machines the delay may not be allowed.
With respect to UPCL's comments regarding the generation window of 12 hours in a day in case of Solar plants in comparison to 24 hours for SHPs, the duration of outage on proportionate and equitable basis considering same analogy comes out to be 24 hours in a month in place of 50 hours in a year, the Commission accepts the same partially and allows exclusion of 12 hours in a month as force majeure for calculation of deemed generation. Further, the distribution licensee is required to maintain and augment its infrastructure so as to ensure that generation is not lost. Any loss of generation unless due to force majeure conditions would be on account of inefficiency
of the licensee and the same cannot be in any manner allowed to be pass through in tariffs.
1.32.8 In the matter of proposal made by UJVN Ltd. w.r.t. maintenance of voltage range, it is pertinent to mention that the Commission vide UERC (State Grid Code), Regulations, 2022 specified maximum and minimum operating range within which all constituents shall make possible efforts to ensure grid voltage as follows:
| Voltage – (kV line) | Minimum (%) | Maximum (%) | ||
|---|---|---|---|---|
| Nominal | Maximum | Minimum | ||
| 765 | 800 | 728 | 4.58% | -4.84% |
| 400 | 420 | 380 | 5.00% | -5.00% |
| 220 | 245 | 198 | 11.36% | -10.00% |
| 132 | 145 | 122 | 9.85% | -7.58% |
| 66 | 72 | 60 | 9.09% | -9.09% |
| 33 | 36 | 30 | 9.09% | -9.09% |
Further, with regard to 11 kV line, UERC (Standard of Performance) Regulations, 2022 specifies that the licensee shall maintain the voltage in the range of +6% and -9% in case of high voltage.
The proposal made by the UJVN Ltd. may create ambiguity among the developers as “-In case of Below 33 kV Voltage level, +10% and -9%,” covers LT lines also and as per last proviso of this regulation, deemed generation is applicable only if the SHPs, Solar Thermal and Solar PV are connected to 11 kV line or above.
1.32.9 Based on the above discussions, the Commission decides to change the above provision to align with the State Grid Code and Supply Code. Accordingly, the final regulation shall be read as follows:
“(Applicable only in case of Small Hydro Generating Plants & Solar PV Plants & Solar Thermal Projects excluding Solar power plants installed under net metering arrangement)
(1) After the COD of the Project, loss of generation at the Station on account of reasons attributed to the following, or any one of the following, shall count towards Deemed Generation:
Provided that the following shall not count towards Deemed Generation:
The distribution licensee shall be required to maintain the voltages at the point of interconnection with the project within the limits stipulated hereunder, with reference to declared voltage:
Any loss in generation due to variations in the voltage beyond the limits specified above shall be reckoned as deemed generation provided such loss of generation results in reduction of more than 25% of capacity output.
(2)The period of outage/interruption on account of such factor(s) specified in sub-Regulation 1 and 2 above, shall be reconciled on monthly basis and the loss of generation at the station towards Deemed Generation after accounting for the events specified under sub-Regulation 1 (i) & (ii) above, shall be computed on following considerations:
(i) The recovery on the above account shall be admissible if the actual energy generated during the year is less than the normative CUF specified in the Regulation for small hydro projects and Solar PV and solar thermal projects (in case of project opting for generic tariff) or the CUF considered for recovery of fixed charges (in case of project specific tariff is applicable) for small hydro projects and solar PV and solar thermal projects. In case the sum of actual energy generated and the deemed generation during the year exceeds the CUF at which the recovery of fixed charges has been envisaged, then the deemed generation alongwith the actual energy generated will be allowed only upto the CUF considered.
(ii) The generation loss towards the Deemed Generation in accordance with sub-Regulation
(i) above, if any, during the month shall be considered on the pro-rata basis on the number of hours lost based on the actual average generation achieved during that month divided by the total number of hours available during the month reduced by the number of hours outage/interruption occurred in the system.
(iii) The generation loss towards the Deemed Generation (in MWh) in accordance with sub-Regulation (ii) above, if any, during the month shall be considered as the summation of the product of number of hours the variations in voltage beyond the specified limit existed and the Generation lost (in MW) due to the variation in the voltage beyond the specified limit. The Generation lost (in MW) would be the difference between the following:
(a) Minimum of the generation (in MW) before the variation in voltage occurred and the generation (in MW) achieved after 90 minutes immediately after variation in voltage was restored within the specified limit would be treated as the "Actual Generation" during the period when voltage variations occurred; and
Provided that if such variation in voltage continues for the entire month, generation (in MW) before such variation in voltage occurrence would be treated as the "Actual Generation".
(b) The generation achieved during the period when variation in voltages took place.
(3) The distribution licensee shall pay for the saleable deemed generation, on annual basis, for Small Hydro projects and Solar PV and Solar Thermal projects worked out on the basis of the deemed generation on the above lines, at the generic/project specific tariffs as applicable in accordance with the applicable RE Regulations. The settlement of payment towards deemed generation charges shall be carried out within 3 months of the completion of the financial year.
Provided that any charges paid by the distribution licensee towards deemed generation shall not be allowed as an expense to be pass through in tariffs. The distribution licensee will have to bear such charges;
Provided further that the deemed generation conditions stipulated above shall be applicable only on those Small Hydro projects and Solar PV and Solar Thermal projects who have signed a long term PPA with the distribution licensee;
Provided also that the deemed generation conditions shall be applicable only on the Small Hydro projects and Solar PV and Solar Thermal projects where the evacuation line is connected to 11 kV or higher voltage Grid Sub-station."
| Sr. No. | Name | Designation | Organisation | Address |
|---|---|---|---|---|
| 1. | Naresh Kumar | Chief Engineer (Commercial) | Uttarakhand Power Corporation Ltd. | Victoria Cross Vijeta Gabar Singh Bhawan, Kanwali Road, Dehradun. |
| 2. | Sh. Rajeev Gupta | Chief Project Officer | Uttarakhand Renewable Energy Development Agency | Urja Park Campus, Industrial Area, Patel Nagar, Dehradun |
| 3. | Sh. Purushottam Singh | Director (Operations) | UJVN Ltd. | "Ujjwal", Maharani Bagh, GMS Road, Dehradun - 248006 |
| 4. | Sh. Arun Gupta | Chairman-cum-Managing Director | M/s Him Urja Pvt. Ltd. | S-321, Panchsheel Park, New Delhi-110017 |
| 5. | Sh. Manish Kathaith | Secretary | M/s Akshay Urja Association | 47/1, Chakrata Road, Vasant Vihar, Dehradun-248006 |
| 6. | Sh. Vivek Ranjan | Manager (Regulatory) | M/s Amplus Energy Solutions Pvt. Ltd. | Palm Square Building, 6 th Floor, Golf Course Extension Road, Sector-66, Gurgaon, Haryana-122102 |
| 7. | Sh. Jogendra Behera | CRO & Vice President (Regulatory & Market Economics) | Indian Energy Exchange Ltd. (IEX) | Plot No. C-001/A/1, 9th Floor, Max Towers, Sector 16B, Noida, Gautam Buddha Nagar, Uttar Pradesh - 201301. |
| 8. | Sh. Neeraj Kuldeep | Senior Programme Lead | Council on Energy, Environment and Water (CEEW) | ISID Campus, 4, Vasant Kunj Institutional Area New Delhi - 110070 |
| 9. | Sh. Madhav K. Kejriwal | Director | M/s Siyangad Hydro Pvt. Ltd. | 24/73, Birhana Road, Kanpur - 208001, Uttar Pradesh |
| 10. | Sh. Madhav K. Kejriwal | Director | M/s Jalandharygad Hydro Pvt. Ltd. | 24/73, Birhana Road, Kanpur - 208001, Uttar Pradesh |
| 11. | Sh. Madhav K. Kejriwal | Director | M/s Kacoragad Hydro Pvt. Ltd. | 24/73, Birhana Road, Kanpur - 208001, Uttar Pradesh |
| 12. | Sh. Harindra Kumar Garg | Chairman | SIDCUL Manufacturers Association of Uttarakhand | SMAU Office, 4th Floor, Pentagon Mall, SIDCUL, Haridwar. |
| 13. | Sh. B. Sadasiva Reddy | Director | M/s Chamoli Hydro Power Pvt. Ltd. | Plot No. 813, Road No. 41, Jubilee Hills, Hyderabad-500033 |
| 14. | Sh. Sushil Kejriwal | Director | M/s Birahi Ganga Hydro Power Ltd. | 32-33, Nehru Place, Flat No-403, New Delhi-110019 |
| 15. | Sh. Sandip Kumar Singh | - | M/s D S Solar Energy Private Limited | - |
| 16. | Sh. Satyendra | Dy. GM | M/s Fairdeal Solar | Dehradun |
| Sr. No. | Name | Designation | Organisation | Address |
|---|---|---|---|---|
| Kumar | (Finance) | Energy Private Limited | ||
| 17. | Sh. Satyendra Kumar | Dy. GM (Finance) | M/s Divyasky Energy Private Limited | Dehradun |
| 18. | Sh. K.V. Vikram Reddy | Managing Director | M/s Himalaya Hydro Pvt. Ltd. | Plot No. 46, Flat No. 202, MLA & MPs Colony, Road No. 10-C, Jubilee Hills, Hyderabad-500033 |
| 19. | - | - | All India Renewable Energy Protection Association | Pocket A1/658, Sector-6, Room No. 2, Rohini, Delhi |
| 20. | Sh. Naresh Goel | CEO | M/s Uttar Bharat Hydro Power Pvt. Ltd. | Plot No. 37, 3 rd Floor, Saraswati Kunj, Golf Course Road, Sector-54, Gurugram, Haryana-122002 |
| Sr. No. | Name | Designation | Organisation | Address |
|---|---|---|---|---|
| 1. | Sh. Himanshu Awasthi | Executive Director | UJVN Ltd. | “Ujjwal”, Maharani Bagh, GMS Road, Dehradun - 248006 |
| 2. | Sh. S.N. Prajapati | Executive Engineer (Solar) | UJVN Ltd. | “Ujjwal”, Maharani Bagh, GMS Road, Dehradun - 248006 |
| 3. | Sh. S.K. Baunsiyal | Dy. GM | UJVN Ltd. | “Ujjwal”, Maharani Bagh, GMS Road, Dehradun - 248006 |
| 4. | Sh. Sanjeev Upadhyaya | President | M/s Khutani Power | - |
| 5. | Sh. R.C. Sharma | Director | M/s Khutani Power | - |
| 6. | Sh. Akshay Negi | Member | M/s Akshay Urja Association | 47/1, Chakrata Road, Vasant Vihar, Dehradun-248006 |
| 7. | Sh. Sandeep Bhatt | Sr. Project Officer | Uttarakhand Renewable Energy Development Agency | Urja Park Campus, Industrial Area, Patel Nagar, Dehradun |
| 8. | Sh. J.S. Bisht | Director | M/s Ados Renewable Pvt. Ltd. | Office: G-28, Nehru Colony, Dehradun |
| 9. | Sh. Arun Gupta | Chairman-cum-Managing Director | M/s Him Urja Pvt. Ltd. | S-321, Panchsheel Park, New Delhi-110017 |