List of addressee (via mail)

NRPC Members for FY 2023-24

S. No. NRPC Member Category Nominated/ E-mail
Notified/Delegated Member

1 Member (GO&D), CEA Member (Grid Operation & Distribution), Member (GO&D), CEA member.god@cea.nic.in
Central Electricity Authority (CEA)
2 Member (PS), CEA Nodal Agency appointed by the Government Member (PS), CEA memberpscea@nic.in
of India for coordinating
cross-border power transactions
3 CTUIL Central Transmission Utility Chief Operating Officer pcgarg@powergrid.in
4 PGCIL Central Government owned Transmission Director (Operations) tyagir@powergrid.in
Company
5 NLDC National Load Despatch Centre Executive Director scsaxena@grid-india.in
6 NRLDC Northern Regional Load Despatch Centre Executive Director nroy@grid-india.in
7 NTPC Director (Finance) jaikumar@ntpc.co.in
8 BBMB Chairman cman@bbmb.nic.in
9 THDC CGM (EM-Design) rrsemwal@thdc.co.in
Central Generating Company
10 SJVN CMD sectt.cmd@sjvn.nic.in
11 NHPC Director (Technical) rajkumar0610.rkc@gmail.com
12 NPCIL Director (Finance) df@npcil.co.in
13 Delhi SLDC General Manager gmsldc@delhisldc.org
14 Haryana SLDC Chief Engineer (SO&C) cesocomml@hvpn.org.in
15 Rajasthan SLDC Chief Engineer (LD) ce.ld@rvpn.co.in
16 Uttar Pradesh SLDC State Load Despatch Centre Director directorsldc@upsldc.org
17 Uttarakhand SLDC Chief Engineer anupam_singh@ptcul.org
18 Punjab SLDC Chief Engineer ce-sldc@punjabsldc.org
19 Himachal Pradesh SLDC Managing Director mdhpsldc@gmail.com
20 DTL CMD cmd@dtl.gov.in
21 HVPNL Managing Director md@hvpn.org.in
22 RRVPNL CMD cmd.rvpn@rvpn.co.in
23 UPPTCL State Transmission Utility Managing Director md@upptcl.org
24 PTCUL Managing Director md@ptcul.org
25 PSTCL CMD cmd@pstcl.org
26 HPPTCL Managing Director md.tcl@hpmail.in
27 IPGCL Managing Director md.ipgpp@nic.in
28 HPGCL Managing Director md@hpgcl.org.in
29 RRVUNL CMD cmd@rrvun.com
State Generating Company
30 UPRVUNL Director (Technical) director.technical@uprvunl.org
31 UJVNL Managing Director mdujvnl@ujvnl.com
32 HPPCL Managing Director md@hppcl.in
33 PSPCL State Generating Company & State owned CMD cmd-pspcl@pspcl.in
Distribution Company
34 DHBVN Director (Projects) directorprojects@dhbvn.org.in
35 Jaipur Vidyut Vitran Nigam Managing Director md@jvvnl.org
Ltd. State owned Distribution Company
36 Madhyanchal Vidyut Vitaran (alphabetical rotaional basis/nominated by Managing Director mdmvvnl@gmail.com
Nigam Ltd. state govt.)
37 UPCL Managing Director md@upcl.org
38 HPSEB Managing Director md@hpseb.in
39 Prayagraj Power Generation Head (Commercial & sanjay.bhargava@tatapower.com
Co. Ltd. Regulatory)
40 Aravali Power Company CEO SRBODANKI@NTPC.CO.IN
Pvt. Ltd
41 Apraava Energy Private CEO rajneesh.setia@apraava.com
Limited
42 Talwandi Sabo Power Ltd. COO Vibhav.Agarwal@vedanta.co.in
43 Nabha Power Limited CEO sk.narang@larsentoubro.com
44 Lanco Anpara Power Ltd IPP having more than 1000 MW installed President sudheer.kothapalli@meilanparapower.com
45 Rosa Power Supply capacity Station Director Hirday.tomar@relianceada.com
Company Ltd
46 Lalitpur Power Generation Managing Director vksbankoti@bajajenergy.com
Company Ltd
47 MEJA Urja Nigam Ltd. CEO hopmeja@ntpc.co.in

48 Adani Power Rajasthan COO, Thermal, O&M jayadeb.nanda@adani.com

Limited
49 JSW Energy Ltd. (KWHEP) Head Regulatory & Power jyotiprakash.panda@jsw.in
Sales
50 RENEW POWER CEO sumant@renew.com
IPP having less than 1000 MW installed
capacity (alphabetical rotaional basis)

51 UT of J&K Chief Engineer, sojpdd@gmail.com/ cejkpcl2@gmail.com

JKSPDCL/JKPDD
From each of the Union Territories in the
region, a representative nominated by the
52 UT of Ladakh Chief Engineer, LPDD cepdladakh@gmail.com
administration of the Union Territory
concerned out of the entities engaged in
53 UT of Chandigarh Executive Engineer, EWEDC elop2-chd@nic.in
generation/ transmission/ distribution of
electricity in the Union Territory.

54 BYPL Private Distribution Company in region CEO Amarjeet.Sheoran@relianceada.com

(alphabetical rotaional basis)
55 Bikaner Khetri Transmission Private transmission licensee (nominated by Vice-President nihar.raj@adani.com
Limited cetral govt.)
56 Adani Enterprises Electricity Trader (nominated by central Head Power anshul.garg@adani.com
govt.) Sales & Trading
57 Ajmer Vidyut Vitran Nigam Special Invitee Managing Director md.avvnl@rajasthan.gov.in
Ltd.
Special Invitees:
RE Holding companies in NR with installed capacity of more than 1000 MW (provsional members as decided in 59th NRPC meeting)
 Attendance 49th TCC meeting of NRPC Date: 29.03.2024
Sr. No. Organization Name Designation Email
1 Sh. M. M. Matta Chairperson, TCC, NRPC directorprojects@hvpn.org.in
HVPNL
2 Neeraj Hooda Xen, HVPNL neerajhooda1981@gmail.com
3 DEEPAK SARIT XEN SS xenplgss@hvpn,org,in
4 CEA Rishika Sharan Chief Engineer (NPC) rishika@nic.in
5 V K Singh MS vksinghcea@gmail.com
6 D.K. Meena SE dharmendra.cea@gov.in
7 Reeturaj Pandey EE pandeyr.cea@gov.in
8 Pushpa Rani Rao PSO pushprrao@gmail.com
NRPC
9 Praveen Jangra EE praveen.cea@gov.in
10 Vipul Kumar AEE vipul.cea@gov.in
11 Lokesh Agrawal AEE lokesh.cea@gov.in
12 Priyanka Patel Manager priyankapatel@powergrid.in
13 WRPC Sh. Deepak Kumar Member Secretary ms-wrpc@nic.in
14 Dr. Sandeep Singhal MD
15 UJVNL Ajay Kumar Singh Director(O) doujvnl@gmail.com
16 K. K. Jaiswal GM-C kkjaiswal99@gmail.com
17 Amit Pundir DGM amit.pundir@relianceada.com
BYPL
18 Haridas Maity AVP haridas.maity@relianceada.com
19 LPGCL Rudra Narayan Bedi President , O&M rnbedi.ltp@lpgcl.com
20 HPPTCL Rajiv Sood MD rajivsoodhp@gmail.com
21 HPPCL Er. Rohit Sharda GM(E) gm_elect@hppcl.in
22 Sh. Umesh Kumar Aggarwal Director (T) dirtech@hpgcl.org.in
HPGCL
23 Sh. Atul Khanna SE(T) atul.khanna.hpgcl@gmail.com
24 Er. Amarjit Singh Juneja Member (Power) junejaas.aj@gmail.com
25 Er. Ajay Kumar Sharma Special Secretary
BBMB
26 Er. Ruchi Sharma Director (Power Reg) ajrukasa@gmail.com
27 Er. Sanjay Sidana DD(Comm) dydcom@bbmb.nic.in
28 RVPN Sh. S.C. Meena Director (Oper.) mhi4371@gmail.com
29 Sh. Manish Athaiya CE (LD) athaiya.manish@rvpn.co.in
Rajasthan SLDC
30 Smt. Sona Shishodia SE (SOLD) sonashishodia0601@gmail.com
31 JSW Abhay Yagnik Head-BD abhay.yagnik@jsw.in
32 Deepak Kumar CE(TO) cgm.to@uprvunl.org
33 UPRVUNL Brijesh Kumar Singh EE (TO) cgm.to@uprvunl.org
34 Suneel Kumar EE (TO) cgm.to@uprvunl.org
35 Shishir Shrivastava SE (A) to MD ee.shishirupcl@gmail.com
UPCL
36 Pankaj Sharma SIE (A) to MD pankaj.sharma94@gmail.com
37 S Adhikari ED (O&M) & ED (RO, Jammu) sadhikari@nhpc.nic.in
NHPC
38 Amitabh Jha GM (Tech), Director (Tech) Sectt. amitabhjha@nhpc.nic.in
39 S K Mishra GM (O&M) surendramishra@nhpc.nic.in
40 Somara Lakra CGM somara.lakra@grid-india.in
41 NRLDC Sheikh Shadrudn Sr GM shadru786@gmail.com
42 Sunil Aharwal GM, NRLDC skaharwal@grid-india.in
43 T P Verma Chief Manager tejprakash@powergrid.in
44 Narendra Sathvik Mgr vnsathvik@powergrid.in
45 CTU Sangeeta sarkar jana.sangeeta@powergrid.in
46 Atul Agarwal atul.ag@powergrid.com
47 Kashish Bhambhani General Manager (North) kashish@powergrid.in
48 Vibhay Kumar ED, CC-AM vibhay@powergrid.in
49 Ravindra Nath Gupta Chief GM(AM), NR1 ravindrangupta@powergrid.in
50 Navin Shrivastav ED, NR-3
51 POWERGRID Pankaj Sharma CGM
52 Gunjan Agarwal GM
53 A. K. Singh DGM
54 Rakesh Kr. Gupta Chief Mgr. rakeshgupta@powergrid.in

55 DHBVN Er. Suresh Bansal Director/Projects-cum-Operations directorprojects@dhbvn.org.in

56 RPSCL Hirday Tomar Whole Time Director (Plant-Head) hirday.tomar@relianceada.com

57 Rajeev Kumar Tayal CE/SO&Commercial cesocomml@hvpn.org.in
SLDC, Haryana
58 Jai Ram XEN SLDC Op xensldcop@hvpn,org,in
59 MANOJ TAUNK AVP- ENDORSE - P&M manoj.taunk@adani.com
Adani Power Limited
60 Abhishek Kukreja Lead -O&M abhishek.kukreja@adani.com
61 BKTL Nitesh Ranjan Asso. Vice President O&M nitesh.ranjan@adani.com
62 AVVNL Sh. Ashok Kumar Chief Engineer (HQ.) cecomavvnl@gmail.com
63 Shri Mukesh Kumar Sharma Director (Operations) dir.opr@dtl.gov.in
DTL
64 Bharat Lal Gujar AGM(Protection &Metering) bl.gujar@dtl.gov.in
65 SLDC,Delhi Sh Anish Garg GM-SLDC garganish@gmail.com
66 JKPCL Er. Suresh Chander Basnotra Chief Engineer cejkpcl2@gmail.com

67 JKPTCL Vishal Chowhan AEE SLDC J&K jksldccertgo@gmail.com

68 PPGCL-Bara Sanjay Bhargava Head - Comm. & Regulatory sanjay.bhargava@tatapower.com

69 Pankaj saxena UP-STU smart.saxena@gmail.com
70 Piyush Garg UP-STU director _op@upptcl.org
UPPTCL
71 Er. S K Das Director(P&C) director_comm@upptcl.org
72 Er. Satyendra Kumar SE(TP&PSS) setppss@upptcl.org
73 Er. Amit Narain Superintending Eng. sera@upsldc.org
UPSLDC
74 Er. Ram Saran Singh Executive Eng. sera@upsldc.org
75 Sh N S Rao Regional Executive Director (North) NSRAO01@NTPC.CO.IN

76 NTPC Ltd Shankar Saran General Manager(Commercial) SHANKARSARAN@NTPC.CO.IN

Additional General
77 Jitender Malhotra jitendramalhotra@ntpc.co.in
Manager(Commercial)
78 TSPL vedanta Punjab Rakesh Gagrani AGM rakesh.gagrani@vedanta.co.in
79 Er. Rakesh Negi SE sehpsldc@gmail.com
HPSLDC
80 Er. Sunandan Kumar Sr. EE pchpsldcshimla@gmail.com
81 THDC R. P. Mishra AGM rajendrapmishra@thdc.co.in
82 THDC Shailndra Panwar DGM ssinghpanwar@thdc.co.in
83 THDC Aashis Dabral Sr. Mgr. ashishdabral@thdc.co.in
84 THDC Sh. Ganesh Mishra, Sr. Manager(O&M) gnmishra@thdc.co.in
85 Lokendra Singh Ranawat Head Regulatory Lokendra.Ranawat@indigrid.com
IndiGrid
86 Vivek Karthikeyan AGM vivek.karthikeyan1@indigrid.com
87 APCPL-Jhajjar Prashant Jain AGM prashantjain@ntpc.co.in
88 PTCUL H S Hyanki CE (T&C) hitendra0107@gmail.com
89 Aman Katoch aman.katoch@sjvn.nic.in
90 Vikas Marwar v.marwar@sjvn.nic.in
91 J S Nayyar jasjeetnayyar@gmail.com
SJVN
92 Ashok Kumar
93 Harish Kumar Sharma
94 IPGCL Amit Ahujaa amitahujaa@yahoo.com
95 PSPCL Ravi kant Goel Sr. Xen rkgoel.400kv@gmail.com
96 A.K. Mishra Director directorsldc@upsldc.org
UPSLDC
97 SJ Siddqui CE cepso@upsldc.org
98 PSTCL Jasprit jaspritsra@gmail.com
 Attendance 72th NRPC meeting Date: 30.03.2024
Sr. No. Organization Name Designation Email
1 Dr. Amit K. Agrawal Chairperson, NRPC md@hvpn.org.in
2 Sh. M. M. Matta Chairperson, TCC, NRPC directorprojects@hvpn.org.in
HVPNL
3 Neeraj Hooda Xen, HVPNL neerajhooda1981@gmail.com
4 DEEPAK SARIT XEN SS xenplgss@hvpn,org,in
5 CEA Rishika Sharan Chief Engineer (NPC) rishika@nic.in
6 V K Singh MS vksinghcea@gmail.com
7 D.K. Meena SE dharmendra.cea@gov.in
8 Reeturaj Pandey EE pandeyr.cea@gov.in
9 Pushpa Rani Rao PSO pushprrao@gmail.com
NRPC
10 Praveen Jangra EE praveen.cea@gov.in
11 Vipul Kumar AEE vipul.cea@gov.in
12 Lokesh Agrawal AEE lokesh.cea@gov.in
13 Priyanka Patel Manager priyankapatel@powergrid.in
14 WRPC Sh. Deepak Kumar Member Secretary ms-wrpc@nic.in
15 Dr. Sandeep Singhal MD
16 UJVNL Ajay Kumar Singh Director(O) doujvnl@gmail.com
17 K. K. Jaiswal GM-C kkjaiswal99@gmail.com
18 Amit Pundir DGM amit.pundir@relianceada.com
BYPL
19 Haridas Maity AVP haridas.maity@relianceada.com
20 LPGCL Rudra Narayan Bedi President , O&M rnbedi.ltp@lpgcl.com
21 HPPTCL Rajiv Sood MD rajivsoodhp@gmail.com
22 HPPCL Er. Rohit Sharda GM(E) gm_elect@hppcl.in
Sh. Umesh Kumar
23 Director (T) dirtech@hpgcl.org.in
HPGCL Aggarwal
24 Sh. Atul Khanna SE(T) atul.khanna.hpgcl@gmail.com
25 Er. Amarjit Singh Juneja Member (Power) junejaas.aj@gmail.com
26 Er. Ajay Kumar Sharma Special Secretary
BBMB
27 Er. Ruchi Sharma Director (Power Reg) ajrukasa@gmail.com
28 Er. Sanjay Sidana DD(Comm) dydcom@bbmb.nic.in
29 RRVPNL & RREC, Jaipur Shri Nathmal Didel MD md.rvpn@rvpn.co.in
30 RVPN Sh. S.C. Meena Director (Oper.) mhi4371@gmail.com
31 Sh. Manish Athaiya CE (LD) athaiya.manish@rvpn.co.in
Rajasthan SLDC
32 Smt. Sona Shishodia SE (SOLD) sonashishodia0601@gmail.com
33 Jyotiprakash Panda VP-REgulatory jyotiprakash.panda@jsw.in
JSW
34 Abhay Yagnik Head-BD abhay.yagnik@jsw.in
35 Deepak Kumar CE(TO) cgm.to@uprvunl.org
36 UPRVUNL Brijesh Kumar Singh EE (TO) cgm.to@uprvunl.org
37 Suneel Kumar EE (TO) cgm.to@uprvunl.org
38 Shishir Shrivastava SE (A) to MD ee.shishirupcl@gmail.com
UPCL
39 Pankaj Sharma SIE (A) to MD pankaj.sharma94@gmail.com
40 R K Chaudhary Director (Tech) rkchaudhary@nhpc.nic.in
41 S Adhikari ED (O&M) & ED (RO, Jammu) sadhikari@nhpc.nic.in
NHPC
42 Amitabh Jha GM (Tech), Director (Tech) Sectt. amitabhjha@nhpc.nic.in
43 S K Mishra GM (O&M) surendramishra@nhpc.nic.in
44 Somara Lakra CGM somara.lakra@grid-india.in
45 NRLDC Sheikh Shadrudn Sr GM shadru786@gmail.com
46 Sunil Aharwal GM, NRLDC skaharwal@grid-india.in
47 T P Verma Chief Manager tejprakash@powergrid.in
48 Narendra Sathvik Mgr vnsathvik@powergrid.in
49 CTU Sangeeta sarkar jana.sangeeta@powergrid.in
50 Atul Agarwal atul.ag@powergrid.com
51 Kashish Bhambhani General Manager (North) kashish@powergrid.in
52 Vibhay Kumar ED, CC-AM vibhay@powergrid.in
53 Ravindra Nath Gupta Chief GM(AM), NR1 ravindrangupta@powergrid.in
54 Navin Shrivastav ED, NR-3
55 POWERGRID Pankaj Sharma CGM
56 Gunjan Agarwal GM
57 A. K. Singh DGM
58 Rakesh Kr. Gupta Chief Mgr. rakeshgupta@powergrid.in
59 DHBVN Er. Suresh Bansal Director/Projects-cum-Operations directorprojects@dhbvn.org.in
60 RPSCL Hirday Tomar Whole Time Director (Plant-Head) hirday.tomar@relianceada.com
61 Rajeev Kumar Tayal CE/SO&Commercial cesocomml@hvpn.org.in
SLDC, Haryana
62 Jai Ram XEN SLDC Op xensldcop@hvpn,org,in
63 MANOJ TAUNK AVP- ENDORSE - P&M manoj.taunk@adani.com
Adani Power Limited
64 Abhishek Kukreja Lead -O&M abhishek.kukreja@adani.com
65 BKTL Nitesh Ranjan Asso. Vice President O&M nitesh.ranjan@adani.com
66 AVVNL Sh. Ashok Kumar Chief Engineer (HQ.) cecomavvnl@gmail.com
Shri Mukesh Kumar
67 Director (Operations) dir.opr@dtl.gov.in
DTL Sharma
68 Bharat Lal Gujar AGM(Protection &Metering) bl.gujar@dtl.gov.in
69 SLDC,Delhi Sh Anish Garg GM-SLDC garganish@gmail.com
Er. Suresh Chander
70 JKPCL Chief Engineer cejkpcl2@gmail.com
Basnotra
71 JKPTCL Vishal Chowhan AEE SLDC J&K jksldccertgo@gmail.com
72 PPGCL-Bara Sanjay Bhargava Head - Comm. & Regulatory sanjay.bhargava@tatapower.com
73 Pankaj saxena UP-STU smart.saxena@gmail.com
74 Piyush Garg UP-STU director _op@upptcl.org
UPPTCL
75 Er. S K Das Director(P&C) director_comm@upptcl.org
 UPPTCL
76 Er. Satyendra Kumar SE(TP&PSS) setppss@upptcl.org
77 Er. Amit Narain Superintending Eng. sera@upsldc.org
UPSLDC
78 Er. Ram Saran Singh Executive Eng. sera@upsldc.org
79 Sh N S Rao Regional Executive Director (North) NSRAO01@NTPC.CO.IN
80 NTPC Ltd Shankar Saran General Manager(Commercial) SHANKARSARAN@NTPC.CO.IN
81 Jitender Malhotra Additional General Manager(Commercial) jitendramalhotra@ntpc.co.in
82 TSPL vedanta Punjab Rakesh Gagrani AGM rakesh.gagrani@vedanta.co.in
83 Er. Rakesh Negi SE sehpsldc@gmail.com
HPSLDC
84 Er. Sunandan Kumar Sr. EE pchpsldcshimla@gmail.com
85 THDC R. P. Mishra AGM rajendrapmishra@thdc.co.in
86 THDC Shailndra Panwar DGM ssinghpanwar@thdc.co.in
87 THDC Aashis Dabral Sr. Mgr. ashishdabral@thdc.co.in
88 THDC Sh. Ganesh Mishra, Sr. Manager(O&M) gnmishra@thdc.co.in
89 Lokendra Singh Ranawat Head Regulatory Lokendra.Ranawat@indigrid.com
IndiGrid
90 Vivek Karthikeyan AGM vivek.karthikeyan1@indigrid.com
91 APCPL-Jhajjar Prashant Jain AGM prashantjain@ntpc.co.in
92 PTCUL H S Hyanki CE (T&C) hitendra0107@gmail.com
93 PSPCL Ravi kant Goel Sr. Xen rkgoel.400kv@gmail.com
94 PSTCL Jasprit jaspritsra@gmail.com
95 M. Kumar ED/HOD manojgangapuri65@gmail.com
96 Aman Katoch aman.katoch@sjvn.nic.in
SJVN
97 Vikas Marwar v.marwar@sjvn.nic.in
98 Ashok Kumar
Annexure-I
Annexure-II
Annexure-III
Annexure-IV
Annexure-V
 32nd TCC & 36th NRPC Meetings (23rd and 24th December, 2015) – Minutes

NRSS XXXVII
32nd TCC & 36th NRPC Meetings (23rd and 24th December, 2015) – Minutes
 Annexure-VI

भारत सरकार
Government of India
विद्युत मंत्रालय
Ministry of Power
उत्तर क्षेत्रीय विद्युत सममतत
Northern Regional Power Committee

संख्या: उ.क्षे.वि.स./ प्रचालन/106/01/2021/ 10435-10476 दिनांक: 09.11.2021

विषय: उत्तर क्षेत्रीय विद्युत समितत की प्रचालन सिन्िय उप-समितत की 188िीं बैठक का काययित
ृ |

Subject: Minutes of 188th OCC meeting of NRPC.

उत्तर क्षेत्रीय विद्युत समितत की प्रचालन सिन्िय उप-समितत की 188िीं बैठक दिनांक
22.10.2021 को आयोजित की गयी थी। उक्त बैठक का काययित्त
ृ उत्तर क्षेत्रीय विद्युत समितत की
िेबसाइट http://164.100.60.165 पर उपलब्ध है। यदि काययित
ृ पर कोई दटप्पणी हो तो काययित
ृ
िारी करने के एक सप्ताह के अन्िर इस कायायलय को भेिें |

188th meeting of the Operation Co-ordination Sub-Committee of NRPC was

held on 22.10.2021. The Minutes of this meeting has been uploaded on the NRPC
website http://164.100.60.165. Any comments on the minutes may kindly be
submitted within a week of issuance of the minutes.

संलग्नक: यथोपरर

-sd-
(सौमित्र ििूििार)
अधीक्षण अमभयंता (प्रचालन)

सेिा में,

उ.क्षे.वि.स. के प्रचालन समन्िय उप-सममतत के सभी सदस्य

18-ए, शहीद जीत स िंह मार्ग, कटवारिया िाय, नई सदल्ली- 110016 फोन:011-26513265 ई-मेल: seo-nrpc@nic.in वेब ाईट: www.nrpc.gov.in
18-A, Shaheed Jeet Singh Marg, Katwaria Sarai, New Delhi-110016 Phone: 011-26513265 e- mail: seo-nrpc@nic.in Website: www.nrpc.gov.in
12. Proposal to implement additional protection in 220KV lines at NAPS (Agenda by
NAPS)
12.1. NAPS vide email dated 06.10.2021 submitted that on 11.08.2021 at 13:25
hrs, both units (NAPS-1 and NAPS-2) had tripped subsequent to isolation of
NAPS switchyard from grid due to fault caused by R-phase CVT of 220kV
Line-1(Narora-Sambhal). In view of above incident, matter was discussed
with designer, NPCIL, Mumbai and additional protection for the 220kV lines
has been suggested.
12.2. Representative from NAPS also given a presentation of event occurred on
11.08.2021.
12.3. Forum decided that the matter shall be referred to protection sub-committee
group for scrutiny and comment on the proposed scheme.

13. Charging of 400/220 kV Jauljibi substation without 220 kV, 25 MVAR Bus
Reactor. (Agenda by NR-3/POWERGRID)
13.1. NR-3/POWERGIRD presented the matter before the forum and apprised that
in the meeting of 36th Standing committee on Power System Planning of
Northern Region held on 30.10.2015, establishment of 400/220 kV, 7x105
MVA GIS S/S in Jauljibi under ISTS was approved. 400/220 kV S/S in Jauljibi
shall be established by:
1. LILO of both circuits of 400 kV Dhauliganga – Bareilly (presently charged
at 220 kV) at 400/220 kV, Jauljibi (incoming line from Dhauliganga shall
be charged at 220 kV and outgoing to Bareilly shall be charged at 400
kV).
2. 2x63 MVAR switchable line reactors in Bareilly – Jauljibi 400 kV D/C at
Jauljibi end
3. 8 no. of 220 kV bays (Pithoragarh-2, Dhauliganga-2, Almora-2, Jauljibi-
2)
S. N. Elements Status

1 LILO of both circuits of 400 kV Completed

Dhauliganga – Bareilly at Jauljibi
2 2x63 MVAR switchable line reactors in Completed
Bareilly – Jauljibi 400 kV D/C at Jauljibi
end
3 Jauljibi – Pithoragarh 220 kV line Will be completed by
Nov’21
4 220 kV Jauljibi – Almora D/c Under PTCUL Scope
5 220 kV Jauljibi – Jauljibi (PTCUL) D/c Under PTCUL Scope
6 8 no. of 220 kV bays (Pithoragarh-2, Completed
Dhauliganga-2, Almora-2, Jauljivi-2)
13.2. The existing 400 kV Dhauliganga – Bareilly (charged at 220 kV) is approx.
240 kms with 25 MVAr line reactor at Dhauliganga end. After LILO at Jauljibi,
length of Dhauliganga-Jauljibi section becomes approx. 40 kms. Therefore,
this 25 MVAR line reactor is to be shifted to 400/220 kV, Jauljibi and shall be
used as a Bus reactor at 220 kV after LILO of Dhauliganga – Bareilly at
Jauljibi.

कायगवृत:उ.क्षे.सव. .की प्रचालन मन्वय उप- समसत की 188वीिं बैठक

पृष्ठ -11
 13.3. The present status of 400/220 kV Jauljibi S/s is as follows:
The 400/220 kV Jauljibi S/s was scheduled to be charged by Mar’21.
POWERGRID approached BRO in the month of Feb’21 to shift 25 MVAR line
reactor from Dhauliganga as per approved scheme. However, BRO informed
that the road at Dobat (road from Dhauliganga to Jauljibi) washed out due to
heavy rain. BRO created a temporary valley bridge at Dobat which had load
limitation and was not suitable to transport 25 MVAR reactor (weighing 30
MT) to Jauljibi from NHPC Dhauliganga. Further, BRO confirmed that the
road is expected to be repaired in 6 months. Hence, the shifting of reactor
could not be taken up and was postponed till the road to Jauljibi is ready.
Subsequently, the bridge on Pithoragarh-Tawaghat road washed out on 07-
08 July’21 due to flash floods and rolling down of huge stone boulders in the
Kulagad Nallah. After that 170 feet DDR Bailey Bridge with capacity of only
24 MT has been launched at same location on 20 Jul’21 (BRO letter attached
at Annexure-A.V of agenda). As transportation of 220 kV bus reactor at
Jauljibi substation is not possible at present, the reactor shall be shifted and
commissioned after construction of the bridge by BRO.
13.4. Hence, permission may be granted to charge the 400/220 kV Jauljibi S/s
without 220 kV bus reactor.
13.5. CTU representative informed the forum that based on their study, no
significant impact is coming on the system as the reactor is of 25 MVAR only.
13.6. NRLDC reprehensive suggested that a written communication may be sought
by POWERGRID from BRO about the expected timeline of the repair of road
from Dhauliganga to Jauljibi.
13.7. Subsequently, forum granted permission to charge the 400/220 kV Jauljibi
S/s without 220 kV, 25 MVAR bus reactor.

14. Report Preventive maintenance of interface metering CTs and CVTs under STU
ownership. (Agenda by ARPL)
14.1 ARPL submitted that recently on 17.08.2021 failure of Y Phase CT (CT blast
and fire in bay equipment) of 400 kV APMuL – Hadala line and subsequent
line tripping on 17.08.2021 at 18:17 Hrs, was observed. In this regards faulty
CT has been replaced after testing of bay equipments. Blast of CT has also
damaged the other nearby CTs and CVTs. It took 2 days to restore the line
along with cleaning, testing and checking of bay equipments.

14.2 400 kV APMuL – Hadala being critical grid element, after checking of
complete healthiness, the line was charged with ALDC / SLDC and WRLDC
code on 19/08/2021 at 20:48hrs considering the urgency.

14.3 Ownership of the interface meters (meter, CT and CVT) is of either CTU or
STU. STU generally seals all the Secondary TB and JB of CTs, CVTs and
meters terminal covers, including the metering panel.

14.4 As per the standard procedure, preventive maintenance of other bay

equipment’s are performed yearly. Since STU metering CT and CVT are
sealed, it’s Preventive maintenance such as tan delta, loop test and oil check

कायगवृत:उ.क्षे.सव. .की प्रचालन मन्वय उप- समसत की 188वीिं बैठक

पृष्ठ -12
 Annexure-VII

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Annexure-VIII
Annexure-IX
Annexure-X
Annexure-XI
Annexure-XII
 File No.CEA-GO-17-14(13)/6/2023-NRPC Annexure-XIII

 


 
  
   


    
 
 

 



            
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 Annexure-XIV

CENTRAL ELECTRICITY REGULATORY COMMISSION

NEW DELHI

Petition No. 94/MP/2021

Coram:
Shri Jishnu Barua, Chairperson
Shri I. S. Jha, Member
Shri Arun Goyal, Member
Shri P. K. Singh, Member

Date of Order: 27.12.2023

In the matter of:

Petition under Section 79(1)(f) of the Electricity Act, 2003 read with Regulation 111 of the
Central Electricity Regulatory Commission (Conduct of Business) Regulations, 1999
seeking directions for installation of optical ground wire for the 400kV Kurukshetra –
Malerkotla transmission line established under the Northern Region System
Strengthening Scheme XXXI(B).
And

In the matter of:

Central Transmission Utility, ……..Petitioner
(Power Grid Corporation of India Ltd).
B-9, Qutab Industrial Area,
Katwaria Sarai, New Delhi-110016

Versus

1. Sekura NRSS XXXI(B) Transmission Ltd.,

503, Windsor, off CST Road, Kalina, Santacruz (E), Mumbai-400098 (Maharashtra)
2. Northern Regional Power Committee
18-A, Shaheed Jeet Singh Marg, Qutab Institutional Area, New Delhi-110016
3. Central Electricity Authority,
Sewa Bhawan, Rama Krishna Puram, Sector -1, New Delhi-110066
4. National Load Despatch Centre,
B-9, First Floor, Qutab Institutional Area, Katwaria Sarai, New Delhi-110016
5. Northern Regional Load Despatch Centre,
18-A, Shaheed JEET Singh, Sansanwal Marg, Katwaria Sarai, New Delhi-110016
6. Khargone Transmission Ltd.,
F1, The Mira Corporate Suite, Plot No.1 &2, C-Block, 2nd Floor, Ishwar Nagar,

Order in Petition No. 94/MP/2021 Page 1

 Mathura Road, New Delhi-110065
7. NER-II Transmission Ltd.
F1, The Mira Corporate Suite, Plot No.1 &2, C-Block, 2nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
8. East North Interconnection Company Ltd.,
The Mira Corporate Suite, Plot No.1 &2, C Block, 2 nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
9. Bhopal Dhule Transmission Company Ltd.,
The Mira Corporate Suite, Plot No.1 &2, C Block, 2 nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
10. Jabalpur Transmission Company Ltd.,
The Mira Corporate Suite, Plot No.1 &2, C Block, 2 nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
11. NRSS XXIV Transmission Ltd.,
The Mira Corporate Suite, Plot No.1 &2, C Block, 2 nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
12. Purulia & Kharagpur Transmission Co. Ltd.,
The Mira Corporate Suite, Plot No.1 &2, C Block, 2 nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
13. RAPP Transmission Company Ltd.,
The Mira Corporate Suite, Plot No. 1&2, C Block, 2 nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
14. Maheshwaram Transmission Ltd.,
The Mira Corporate Suite, Plot No. 1&2, C Block, 2nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
15. Gurgaon Palwal Transmission Ltd.,
The Mira Corporate Suite, Plot No. 1&2, C Block, 2nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
16. Odisha Generation Phase-II Transmission Ltd.,
The Mira Corporate Suite, Plot No. 1&2, C Block, 2nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
17. Patran Transmission Company Ltd.,
The Mira Corporate Suite, Plot No. 1&2, C Block, 2nd Floor, Ishwar Nagar,
Mathura Road, New Delhi-110065
18. Western Transco Power Ltd.(WTPL)
Achalraj, Opp.Mayor Bunglow, Law Garden, Ahmedabad-380006
19. Western Transmission (Gujarat) Ltd., (WTGL)
Achalraj, Opp. Mayor Bunglow, Law Garden, Ahmedabad-380006
20. Chhattisgarh WR Transmission Ltd.,
Achalraj, Opp. Mayor Bunglow, Law Garden, Ahmedabad-380006
21. Raipur Rajnandgaon Warora Transmission Ltd.,
Achalraj, Opp. Mayor Bunglow, Law Garden, Ahmedabad-380006
22. Sipat Transmission Limited
Achalraj, Opp. Mayor Bunglow, Law Garden, Ahmedabad-380006

Order in Petition No. 94/MP/2021 Page 2

23. Raichur Sholapur Transmission Co. Ltd.,
Patel Estate, S. V. Road, Jogeshwari (West), Mumbai-400102
24. POWERGRID Vizag Transmission Ltd.,
POWERGRID, SR HQ, 6th Floor, D. No. 6-6-8/32 &39/E, Kavadiguda,
Secunderabad-500080, Telangana
25. POWERGRID Unchahar Transmission Ltd.,
765/400/220 KV POWERGRID S/S, Fatehpur-Lalganj-Lucknow Road,
Village- Chauferva, Post & Distt-Fatehpur-212601(Uttar Pradesh)
26. Kudgi Transmission Ltd.,
Mount Poonamallee Road, Manapakkam, P.B. No.979, Chennai-600089
27. Darbhanga Motihari Transmission Co. Ltd.,
503, Windsor, Off CST Road, Kalina, Santacruz (E), Mumbai -40009 (Maharashtra)
28. NRSS XXXVI Transmission Ltd.,
Plot No. 19, Film City, Sec-16 A, Gautam Buddha Nagar, Noida, UP-201301
29. Warora Kurnool Transmission Ltd.,
Achalraj, Opp. Mayor Binglow, Law Garden Ahmedabad-380006
30. POWERGRID Southern Inter Connector Transmission System Ltd (PSITSL),
POWERGRID, SR1 HQ, D.No.6-6-8/32&395/E, Kavadiguda,
Secunderabad-500080, Telangana
31. POWERGRID Parli Transmission Ltd (PPTL),
Sampriti Nagar, Nari Ring Road, Uppalwadi, Nagpur-440026
32. POWERGRID Kala Amb Transmission Ltd.
(PKATL) 400/220KV Barwala Sub-station, Vill-Naggal, NH-73,
Barwala Panchkula, Haryana-134118
33. POWERGRID Warora Transmission Ltd, (PWTL)
WR-1 RHQ, Sampriti Nagar, Nari Ring Road,
PO: Uppalwadi, Nagpur-440026(Maharashtra)
34. Powergrid NM Transmission Limited Southern
Region Transmission system –II, RHQ, Near Driving Test Track,
Singanayakanhalli, Yelahanka Hobli, Bangalore-560064
35. Powergrid Jabalpur Transmission Limited, POWERGID,
Plot No. 54, Jay Ambe School, Sama-Savli Road, Vadodara-390018, Gujarat
36. Alipurduar Transmission Ltd.(ATL)
Achalraj, Opp. Mayar Binglow, Law Garden Ahmedabad-380006
37. KOHIMA-MARIANI Transmission Ltd.,
B-5,Tower-3, 3rd Floor, Okaya Business Centre,
Sector-62, Noida, (Uttar Pradesh) 201306, India
38. POWERGRID Medinipur Jeerat Transmission Ltd.
POWERGRID, Eastern Region II Headquarters, CF-17,
Action Area 1C, New Town, Rajarhat, Kolkata-700156
39. POWERGRID Mithilanchal Transmission Ltd.
POWERGRID, ERTS-I Regional Haed Quarter, Near Transformer Repair Works,
Board Colony, Shastri Nagar, Patna-800023 (Bihar)
40. POWERGRID Ajmer Phagi Transmission Ltd. SCO bay 5 to 10,

Order in Petition No. 94/MP/2021 Page 3

 SECTOR-16A, FARIDABAD, HARYANA- 121002
41. Power Grid Corporation of India Ltd.
Load Dispatch & Communication (LD&C), B-9,
Qutab Institutional Area, Katwaria Sarai, New Delhi-110016 …..Respondents

Parties Present:
Shri Samar Chandra De, NERLDC
Shri M. G. Ramachandran, Senior Advocate, STL
Ms. Suparana Srivastava, Advocate, CTUIL
Shri Tushar Mathur, Advocate, CTUIL
Ms. Astha Jain, Advocate, CTUIL
Shri Shubham Arya, Advocate, STL
Ms. Shikha Sood Advocate, STL
Ms. Reeha Singh, Advocate, STL
Ms. Pallavi Maitra, Advocate R-7 to 12
Shri Venkatesh, Advocate, NRSS XXXVI
Shri Anand Singh Ubeja, Advocate, NRSS XXXVI
Shri Mohit Mansharamani, Advocate, NRXX XXXVI
Shri Hemant Singh, Advocate, WTPL
Shri Chetan Garg, Advocate, WTPL
Shri Swapnil Verma, CTUIL
Shri Ranjeet S. Rajput, CTUIL
Shri Priyansi Jadiya, CTUIL

ORDER

Central Transmission Utility (CTU) has filed the present Petition under Section
79(1)(f) of the Electricity Act, 2003, read with Regulation 111 of the Central
Electricity Regulatory Commission (Conduct of Business) Regulations, 1999,
seeking directions for installation of optical ground wire for the 400kV Kurukshetra
– Malerkotla transmission line established under the Northern Region System
Strengthening Scheme XXXI(B).

2. The Petitioner has made the following prayers:

i. Issue appropriate directions to Respondent No.1 for allowing OPGW installation on the
400kV Kurukshetra-Malerkotla D/c line under the Reliable Communication Project
approved for the Northern Region by Northern Region Power Committee to ensure early
completion of the link.
ii. Issue further appropriate directions to Respondent No.1 for facilitating and allowing OPGW
installation in the transmission elements implemented by transmission licensees in line with
the mandate of Central Electricity Authority (Technical Standards for Communication
System in Power System Operations) Regulations, 2020; any other applicable
Regulations/Procedure in this regard, orders and directions of this Hon’ble Commission and

Order in Petition No. 94/MP/2021 Page 4

 the decision of coordinated meetings between entities such as Regional Power Committees
(RPC), Central Electricity Authority (CEA), Central Transmission Utility (CTU),
National/Regional Load Despatch Centres (NLDC/RLDC) and other statutory/regulatory
stakeholders.
iii. Pass such further and other order(s) as this Hon’ble Commission may deem fit and proper
in the facts and circumstances of the present case.

Submission of Petitioner

3. Petitioner has made the following submissions:

(a) Communication systems are essential to facilitate the secure, reliable and economic
operation of the grid and are an important pre-requisite for the efficient monitoring,
operation and control of the power system. The provisions relating to
communication systems for the power sector have been initially spelt out in the
Central Electricity Regulatory Commission (Indian Electricity Grid Code)
Regulations, 2010 (hereinafter “Grid Code, 2010”) and the Central Electricity
Authority (Technical Standard for Connectivity to the Grid) Regulation, 2013
(hereinafter “Grid Standard for Connectivity”) whereunder, all requesters, users,
Central/State Transmission Utilities are obligated to provide systems to telemeter
power system parameters. Thereafter, on 15.5.2016, this Commission notified the
Central Electricity Regulatory Commission (Communication System for inter-State
transmission of electricity) Regulations, 2017 (hereinafter “Communication System
Regulations, 2017"), which lay down the rules, guidelines, and standards to be
followed by various persons and participants in the system for the continuous
availability of data for system operation and control including market operations.

(b) Petitioner has been entrusted with the responsibility for the development of an
efficient and coordinated communication system on a regional basis, which is to be
connected to provide a backbone communication system spread across India as
per the Manual of Communication Planning Criteria of the Central Electricity
Authority, 2019. CEA has further notified the Central Electricity Authority (Technical
Standards for Communication System in Power System Operations) Regulations,
2020 (hereinafter “Communication Standards Regulations, 2020”), laying down the
requirements for planning, implementation, operation and maintenance and up-
gradation of a reliable communication system for all communication requirements
including exchange of data for power system at the national level, regional level,

Order in Petition No. 94/MP/2021 Page 5

 inter-State level and intra-State level. The Regulations envisage planning of
backbone regional and national communication network using ISTS transmission
lines by the Petitioner as per requirement.

(c) The Communication Standards Regulations, 2020, envisage planning of backbone

regional and national communication network using ISTS transmission lines by the
Petitioner as per requirement. Regulation 26 of the said Regulations necessitates
the construction of wideband communications using fibre optic communication.

(d) Optical Ground Wire (OPGW) is an optical fibre embedded in the earth wire, which
is used in overhead power lines. In furtherance of the regulatory mandate, the
Petitioner has established the backbone communication network in the Northern
Region as part of various projects such as the Unified Load Despatch &
Communication (ULDC) Project, Microwave Replacement Project and Fiber Optic
Expansion Projects, apart from other transmission projects.

The Reliable Communication Scheme under the Central Sector for Northern Region
was proposed by the Petitioner in the 35th Technical Coordination Committee
(TCC) Meeting held on 1.5.2017, which was approved in the 39th Meeting of the
Northern Regional Power Committee held on 2.5.2017.

In this manner, the scheme for the installation of OPGW based reliable
communication system with a network size of 7248kms (including OPGW
replacement of ULDC Phase –I) by the Petitioner in the Northern Region was
approved for its implementation. In accordance with the above approval, which was
reiterated in the 40th Meeting, the Petitioner proceeded with the installation of
around 7248 km of OPGW along with the communication equipment under the
central sector in the Northern Region.

(e) The implementation of an additional network with the Reliable Communication

Scheme under the Central Sector for the Northern Region was approved in the 47th
Meeting of the Northern Regional Power Committee held on 11.12.2019 and in the
44th Meeting of the Technical Coordination Committee held on 10.12.2019.
Accordingly, the revised network size of the Reliable Communication Project will
become 7398 Km. As a part of the above scheme, OPGW was also agreed to be
installed on the 400kV Kurukshetra-Malerkotla line (180km) by replacing the
existing earth wire.

Order in Petition No. 94/MP/2021 Page 6

(f) The Petitioner has taken up implementation of the project wherein OPGW is to be
installed on ISTS transmission lines by replacing existing earth wire. For that
purpose, the Petitioner has entered into a contract dated 31.1.2019 with M/s Apar
Industries Ltd. (APAR) after the selection of the same based on an open tender.

(g) The 400kV ISTS transmission line connecting Kurukshetra-Malerkotla had been
implemented by Respondent No.1 as part of the transmission scheme in the name
of “Northern Region System Strengthening Scheme XXXI (B)” through the TBCB
route as follows:

i. 400 kV Kurukshetra-Malerkotla D/c line

ii. 400 kV Malerkotla-Amritsar D/c line

(h) In view of the regulatory mandate for implementing the national backbone
communication system, including for the Northern Region, the Petitioner
approached Respondent No.1 for the installation of OPGW on the 400kV D/c
Kurukshetra- Malerkotla line built by the Respondent. Further, vide email dated
15.9.2020, the Petitioner clarified certain queries raised by Respondent No.1

(i) Respondent No.1 vide letter dated 5.10.2020 raised issues with respect to the
installation of OPGW on the 400kV Kurukshetra-Malerkotla transmission line and
stated that it was unable to understand the regulatory provision which allowed that
part of TBCB asset could be removed/dismantled and adjusted against the capital
cost of other cost-plus assets in order to achieve tariff optimization in cost plus
project. As such, Respondent No.1 declined to grant its consent “to take away NTL
earth wire including hardware & fittings by M/s. APAR Industries Ltd. after
dismantling for executing OPGW Work”. Respondent No.1 also sought clarifications
from the Petitioner with respect to the following:

i. The available regulatory provisions and contractual provisions under the TSA
under which implementation of OPGW ULDC scheme through its asset would
not entail any impact on the revenue of the asset.

ii. Petitioner to hand over the verified quantity of earth wire, including accessories
to Respondent No.1 after proper re-rolling on drums at its Patiala store.

Order in Petition No. 94/MP/2021 Page 7

 iii. Whether any damage to the assets of Respondent No.1 during the installation
of OPGW by the Petitioner would be rectified by the Petitioner at its own to the
level of satisfaction of Respondent No.1.

iv. Petitioner to provide schedule of work execution, planning, details of executing

agency etc., to Respondent No.1 prior to mobilizing the work at the site for joint
discussion purposes.

v. Whether the Petitioner would indemnify Respondent No.1 towards:

a. Outage/tripping of line implemented by Respondent No.1, which might

reduce transmission line service availability.

b. Any perspective dispute, litigation or (RoW/crop) compensation claims raised

by any of the landowners.

vi. From the lifetime operation and maintenance perspective after the completion,
commissioning and capitalization of the OPGW work, clarification with respect
to:

a. Ownership of the transmission line, particularly in view of the substitution of

earth wire by the Petitioner and if the asset was to be handed over to
Respondent No.1 for ease of its operation and maintenance in future.

b. Whether the Petitioner intended to utilize the transmission line commercially

in any manner.

(j) Petitioner vide letter dated 12.10.2020 informed Respondent No.1 that live-line
installation of OPGW was field proven and more than 70,000 kms of installation
had been completed by the Petitioner. As regards the return of earth-wire and other
issues raised by Respondent No.1, the Petitioner stated that the same could be
dealt with in line with the decision taken during the Meeting chaired by the Member
Secretary, Northern Region Power Committee on 5.3.2019 on similar issues raised
by M/s Parbati Koldam Transmission Company Limited (PKTCL) for OPGW
installation on their lines. Petitioner’s prayers are liable to be seen in the context
and perspective of the obligations of Respondent No.1 in terms of the Transmission
Service Agreement dated 02.01.2014.

(k) Respondent No.1 is also obligated in terms of the provisions of the CERC
(Procedure, Terms and Conditions for grant of Transmission License and other

Order in Petition No. 94/MP/2021 Page 8

 related matters) Regulations, 2009, to maintain the project in accordance with the
prudent utility practices and applicable directions passed by competent authorities.

(l) The OPGW requirement on the said line under the Reliable Communication Project
is vital for providing reliable and redundant communication of Malerkotla 400kV
ISTS sub-station to the Northern Region Load Despatch Center and the Malerkotla
400 kV ISTS sub-station is important for evacuation of bulk power to Punjab through
the downstream of 800 kV Champa-Kurukshetra HVDC line.

(m) Respondent No.1 or any similarly placed transmission licensee may have inter alia
the following concerns or issues, on which the Commission may be pleased to issue
appropriate guidance and directions:

i. Change in value (if any) of their assets upon replacement of existing earth-
wire with OPGW (optical ground-wire) when such installation is being carried
out at the behest of CTU/POWERGRID.

ii. Impact of this change in assets on the tariff (if any).

iii. Impact of tripping and shutdowns on their system availability (if any)

iv. Ownership of OPGW.

v. Permission for the licensee to use OPGW for any commercial purpose.

(n) The Commission may issue directions and guidance in general governing the
installation of OPGW wherever so required in accordance with the mandate of
Communication Standards Regulations, 2020, Communication System
Regulations, 2017 or any other applicable Regulations/Procedure in this regard;
orders and directions of this Commission and the decision of coordinated meetings
between entities such as Regional Power Committees (RPC), Central Electricity
Authority (CEA), Central Transmission Utility (CTU), National/Regional Load
Despatch Centres (NLDC/RLDC) and other statutory/regulatory stakeholders.

Hearing on 25.06.2021

4. Petition was admitted on 25.06.2021, and the Commission observed that the issues
raised by CTUIL in the instant matter may arise in the case of other TBCB projects.
Therefore, the Commission directed CTUIL to implead all the transmission

Order in Petition No. 94/MP/2021 Page 9

 licensees implementing transmission projects under the TBCB route as
respondents so that all of them may be heard and suitable directions could be
issued in one order instead of deciding the issues in multiple petitions. The
Commission further directed the Petitioner to implead PGCIL as a party to the
proceedings. The Commission also directed STL to discuss with CTUIL and firm up
the issues that may arise in the installation of OPGW in place of earth wire in various
TBCB projects for smooth and proper adjudication of the issues involved.

Submission of Petitioner

5. Petitioner vide affidavit dated 30.11.2021 and dated 08.03.2022 has filed an
“Amended Memo of parties” impleading other transmission licensees.

6. Petitioner vide affidavit dated 08.03.2022 submitted the Minutes of Meeting dated
14.07.2021 between CTU, NRSS XXXI(B) Transmission Ltd (NTL) & Powergrid and
Minutes of the Meeting held on 13.08.2021 with ISTS licensees to discuss issues
related to OPGW installation on Malerkotla - Kurukshetra line & LILO of Fatehgarh
– Bhadla line at Fatehgarh-II. There were divergent opinions with respect to the
implementation, ownership, maintenance and operation of OPGW and no
consensus was arrived at in these meetings.

Hearing on 10.03.2022

7. The Commission directed CTUIL to hold a further meeting(s) with the transmission
licensees and come out with a suitable proposal for smooth and proper adjudication
of the issues involved.

8. The Commission directed the Petitioner to submit the list of transmission assets
along with the transmission licensee’s name wherein this replacement of earth wire/
old OPGW is planned and any other issues being faced by CTUIL related to
modifications required to be carried out in TBCB assets keeping in view the
integrated nature of ISTS.

Order in Petition No. 94/MP/2021 Page 10

 Submission of Petitioner

9. Petitioner vide affidavit dated 29.03.2022 has submitted as follows:

(a) The list of the transmission assets along with the transmission licensee’s name
wherein the replacement of earthwire/old OPGW is planned (as on 29/03/2022) has
been submitted comprising of majority assets of Powergrid and one line Western
Transmission Power Ltd (Adani).

(b) In case the replacement of earth wire/old OPGW is planned in additional

transmission assets in future, the same would be informed to the Commission by
the Petitioner.

(c) The issues (including issues other than replacement of earth wire/old OPGW) being
faced by the Petitioner related to modifications required to be carried out in TBCB
assets is tabulated as below:

Sr. Name of Name of lines Issues raised by owner Comments

No. Owner Utility Utilities/likely to arise
(TBCB/JV/
IPTC)
1. M/s. NTL 400kV Kurukshetra – a. Impact on tariff and revenue after POWERGRID has
(NRSS Malerkotla TL (139Km) replacement of Earthwire with communicated that it has no
XXXI(B) OPGW (POWERGRID ownership). objection if the implementation of
Transmission b. Handing over the Earthwire. the laying of OPGW is
Limited) c. Rectification of any damaged asset undertaken by M/s Sekura NRSS
M/s Sekura in the process of OPGW XXXI(B) Transmission Ltd (STL)
Ltd. installation.
d. Prior intimation of any work and
responsible contractor.
e. Indemnification of any outage or
claimed compensation by any
landowner.
f. Ownership of OPGW and its O&M.
g. Any commercial use of OPGW.
2. M/s. PKTCL i. 400kV S/C Parbati a. Rectification of any damaged asset POWERGRID has
(M/s. IndiGrid) III(HEP) – Parbati in the process of OPGW communicated that M/s PKTCL
Pooling (7Km) installation. may do the installation of OPGW
(JV with ii. 400kV S/C Parbati b. Return of earthwire on their own, as discussed during
POWERGRID) II(HEP) – Parbati III c. Any commercial use of OPGW. the meeting with Licensees on
(12Km) 13.08.21.
iii. 400kV Parbati Pooling
– Koldam (65Km)
3. Torrent Power (i) LILO of Pirana (PG) – a. Long shutdown is required for the As such no issue has been
Limited Pirana (T) 400kV D/c execution of reconductoring and raised by owner/implementer.
line at Ahmedabad S/s bay upgradation work. This may However, the implementation
with twin HTLS along work through TBCB for bay

Order in Petition No. 94/MP/2021 Page 11

(TBCB) with reconductoring of affect the availability of other bays upgradation works and
Pirana (PG) – intermittently. reconductoring in the existing
Pirana(T) line with twin b. Commercial issues may be raised line of Torrent Power will require
HTLS conductor by the owner for the modification. dismantling, breakage, and
(ii) Bay upgradation removal of existing infrastructure
work at Pirana (PG) & in the premises of Torrent Power
Pirana (T) by the new TSP.

(d) The Ministry of Power vide its Order No. 15/3/2017-Trans-Pt(1) dated 09.03.2022
has issued the “Guidelines on Planning of Communication System for Inter-State
Transmission System (ISTS)”. The Guidelines define the categories of
Communication System Schemes for ISTS as Category (A) and Category (B) and
provide their corresponding approval procedure. The categories A and B have been
defined under the Guidelines as follows: -

➢ Category (A): Communication system directly associated with new ISTS as well
as incidental due to implementation of new ISTS elements (e.g. LILO of existing
line on new/existing S/s where OPGW/terminal equipment are not available on the
existing mainline/substations etc.)

➢ Category (B): Upgradation/modification of existing ISTS Communication system

pertaining to the following:

• Missing Links Redundancy/ System Strengthening

• Capacity upgradation (Terminal equipment)

• Completion of life of existing communication system elements

• Other standalone project e.g. Cyber Security, Unified Network Management

System (UNMS)

• Adoption of New Communication Technologies

(e) Under the Guidelines, the requirement for a communication system linked with the
new ISTS, shall be included in the new ISTS package and the combined proposal
shall be approved as per the directions contained in MoP’s Office Order dated
28.10.2021 regarding the Re-constitution of the “National Committee on
Transmission” (NCT). In the case of Category (B), Communication
Schemes/Packages proposed by CTUIL for the upgradation/modification of the
existing ISTS Communication System, standalone projects, and adoption of new
technologies shall be put up to RPC for their views, and RPC has to provide their
views on the Schemes/Packages proposed by CTUIL within 45 days of receipt of

Order in Petition No. 94/MP/2021 Page 12

 the proposal from CTUIL. The Schemes/Packages, along with the views of RPC
shall be approved by NCT. Subsequent to communication received from
POWERGRID that it has no objection if the implementation of laying of OPGW is
undertaken by M/s Sekura NRSS XXXI(B) Transmission Ltd (STL), the installation
of OPGW on 400kV Kurukshetra-Malerkotla Transmission Line in the instant
petition may be undertaken as per the procedure prescribed for category (B)
communication systems under the Guidelines.

(f) The Guidelines formulated by the Ministry of Power settle the divergent opinions
with respect to implementation, ownership, maintenance and operation of OPGW
between the transmission licensee and CTUIL and therefore, difficulty/disputes
which are under consideration in the present Petition are not likely to recur in near
future.

Submission of Respondent Western Transco Power Limited (WTPL)

10. Respondent No.18 Western Transco Power Limited (WTPL) vide affidavit dated
29.04.2022 has mainly submitted as under:

(a) Respondent No. 18, Western Transco Power Limited, is a Transmission Licensee
and the 765/400kV Pune (PG) (GIS) – 400kV Parli (PG) was constructed by
Respondent No. 18, which was commissioned on 01.12.2013.

(b) If the Commission allows some other party to lay OPGW on the transmission asset
owned and operated by another licensee, the same would necessarily entail the
following issues, which need to be considered by this Commission:

i. The ownership of the OPGW shall remain uncertain as the transmission asset will
belong to one entity, and the OPGW shall be owned by another entity.

ii. The OPGW which shall be installed may be utilized for commercial purposes such
as communication etc., which cannot be allowed to an entity which is not the owner
of the transmission asset, and the said entity cannot be permitted to make undue
monetary gains by using the said asset.

iii. During installation of the OPGW, there may be damage to the existing asset of the
Applicant.

Order in Petition No. 94/MP/2021 Page 13

 iv. The suitability of OPGW to the existing transmission asset is an important factor,
which also requires consideration by this Commission.

v. Issues as regards the Right of Way (“RoW”) during the extraction of the existing
wire.

vi. The Applicant will be liable to be compensated in case of any damage caused by
the licensee during the installation of OPGW.

vii. Deemed availability/ compensation of financial loss in case of tripping, breakdown,

maintenance etc., due to the reason not attributable to the transmission licensee
which owns the transmission line in question.

viii. Whether O&M will be carried out by the transmission licensee which owns the
transmission line in question.

11. The Commission is precluded from granting a license or permission to any other
party qua a transmission asset which is owned by t Respondent No. 18.

Submission of other Respondents

12. The other Respondents NER-II Transmission LTD. (NERII), Parbati Koldam
Transmission Co. LTD. (PKTCL), Gurgaon Palwal Transmission Co. LTD. (GPTL),
Jabalpur Transmission Co. LTD. (JTCL), Maheshwar Transmission Co. LTD. (MTL),
RAPP Transmission Co. LTD. (RTCL), Bhopal Dhule Transmission Co. LTD.
(BDTCL), Odisha Generator Phase-II Transmission Co. LTD. (OGPTL), East North
Interconnection Transmission Co. LTD. (ENICL), Patran Transmission Co. LTD
(PTCL) and Purulia & Kharagpur Transmission Co. LTD (PKTCL), vide their
individual affidavit dated 29.05.2022 have submitted the similar submission, which
are as under:

(a) The present Petitioner is obligated to comply with the provisions of Communication
System Regulations, 2017, which requires the Petitioner to undertake only the
planning of the communication system and not undertake installation of OPGW and
communication system on the assets of the other transmission licensees.

(b) Section 17 of the 2003 Act has a bar on the Petitioner to acquire the transmission
assets of any other licensee by any arrangement. The prayers made by the
Petitioner are tantamount to the Petitioner acquiring the transmission assets of the

Order in Petition No. 94/MP/2021 Page 14

 Respondent Licensee for installing OPGW. This is clearly stated in negative
language in clause 1(a) of section 17 of the 2003 Act.

(c) The “Guidelines on Planning and Communication System for Inter State
Transmission System” do not mandate the CTUIL or PGCIL to install OPGW on the
transmission lines/transmission projects owned by other transmission licensees.
The said Guidelines state that the proposal made by the Petitioner for the
upgradation/modification of the existing ISTS communication system, etc., shall be
put up to RPCs for their views.

(d) The following substantial issues arise in the present matter:

(A) Proposal may entail modification of license conditions:

i. In the event that the Petitioner is to replace the earth wires of other
transmission licensees, there may be an issue attracting license amendment,
which inter alia requires prior permission of the Lenders. Moreover, if the
ownership of OPGW is to remain with the Petitioner, then two different
transmission licensees will have ownership over one TBCB asset, which will
lead to complexities in terms of operation and maintenance of the asset,
leveraging of the assets for another business, RoW/crop compensation,
outage and availability related claims, etc.

(B) The issue of Deemed Availability.

(C) The issue of CTUIL engaging in “Other Business” under section 41 of the 2003
Act:

i. The proposal of the Petitioner to install OPGW on the transmission assets of

another Transmission Licensee entails the Petitioner to recover capital
expenditure and other expenditure on installing the OPGW from the point of
connection, transmission charges from the base of customers of the Petitioner.

ii. Section 41 only allows the transmission licensee to engage in any business for
“Optimum Utilization of its assets.” Therefore, under section 41 of the 2003 Act,
one transmission licensee cannot engage in another business for utilization of
another transmission licensee’s assets.

iii. There is no basis in fact or in law based on which the Respondent No.1
transmission licensee or any other transmission licensee would permit the

Order in Petition No. 94/MP/2021 Page 15

 Petitioner or PGCIL to utilize their own transmission assets for CTUIL/PGCIL to
derive revenue from installing the OPGW.

iv. Under section 41, the Second Proviso thereto prohibits the Respondent No.1
licensee or other transmission licensees from providing their own transmission
assets to CTUIL/PGCIL because that would be tantamount to encumbering its
transmission assets for the loans/financial assistance that CTUIL/PGCIL would
incur for the expenditure on OPGW installation.

v. Respondent No.1 licensee/other transmission licensees cannot be deprived of

return on investment on their own transmission assets by depriving them of
installing the OPGW on their own assets.

(D) The issue of Indemnification: The transmission licensees will be exposed to

disputes on account of right-of-way issues with locals, outages, decrease in
availability of transmission system, loss of revenue, etc., if the OPGW is installed
by CTUIL/PGCIL and hence transmission licensees should be indemnified by
CTUIL and/or PGCIL, as the case may be.

(e) The dismantled earth wires will have to earn scrap value which will be amenable to
treatment under the sharing of non-tariff income between the beneficiaries and
LTTCs and transmission licensees. Can CTUIL nor PGCIL be permitted to replace
the existing earth wires of the transmission assets of the Answering
Respondent/other transmission licensees?

Submission of Petitioner

13. Petitioner vide affidavit dated 12.05.2023 has submitted that in compliance with
the directions of the Commission, a meeting was held between CTUIL & ISTS
Transmission Licensees on 08.05.2023, and the minutes of the same have been
submitted.

Hearing on 15.05.2023

14. During the hearing on 15.05.2023, following has been recorded:

“3. Learned counsel for CTUIL informed that pursuant to the direction of the Commission
given in the instant petition vide Record of Proceedings dated 10.3.2022, a meeting was
held between CTUIL and ISTS transmission licensees on 8.5.2023, wherein it was recorded
that in the earlier meeting held on 13.8.2021, between CTUIL and the transmission
licensees, it was agreed by general consensus that unless otherwise requested, the work

Order in Petition No. 94/MP/2021 Page 16

 regarding installation of OPGW shall be awarded to the asset owner. She further informed
that a meeting was also held on 13.3.2023, amongst CTUIL, Powergrid and Sekura
pursuant to the directions of the Commission vide RoP dated 10.3.2022 to discuss OPGW
installation on 400 kV D/C Malerkotla- Kurukshetra line owned and operated by Sekura
wherein Sekura suggested that OPGW work should be awarded to them as additional work
being change in the original transmission line scope and cost of the same shall be
recovered by revision in their existing TBCB tariff. Learned counsel for the CTUIL submitted
that the work shall be awarded in RTM mode and tariff of the same shall be determined by
the Commission as per the applicable regulations.
4. Learned counsel for Respondent No.18/WTPL submitted that while passing order in
present petition, the Commission may bear in mind that the matter in issue is of
Communication System and to what extent the powers under the Electricity Act, 2003 can
be used in allowing revenue or in approving or determining tariff of Communication System
which is not part of the transmission. In response, learned counsel for the CTUIL submitted
that the Communication System is part of the transmission system CTUIL submitted that
the work should be awarded in RTM mode and tariff of the same shall be determined by
the Commission as per the applicable regulations.”

15. After hearing the Petitioner and Respondents, the Commission reserved the order
in the matter on 15.05.2023.

Written Submission of Respondent No. 1, SEKURA NRSS XXXI(B) Transmission

Ltd

16. Respondent No.1, SEKURA NRSS XXXI(B) Transmission Ltd has made written
submissions dated 05.06.2023 as under:

(a) CTUIL has proposed the following in view of MoP “Guidelines on Planning of
Communication System for lnter-State Transmission System (ISTS)” dated
09.03.2022 and recent approvals of OPGW on existing lines:

(i) OPGW installation work under ISTS Communication requirement shall be

awarded to the transmission line asset owner.
(ii) Terminal equipment associated with OPGW cable shall be awarded to bay
owner/s of the transmission line on which OPGW is proposed for installation.

(b) A consensus has emerged that Respondent No. 1 can undertake the
implementation of OPGW in the transmission assets owned by it and further that
such OPGW cables will form part of its transmission assets, which ownership would
also lie with Respondent No 1.

(c) The NRSS project has been developed and operated by Respondent No. 1 as a
Tariff based Competitive Bidding licensee. All transmission assets forming part of
the NRSS XXXI B Project are subject to the tariff that has been arrived at pursuant
to competitive bidding in accordance with the guidelines issued by the Ministry of

Order in Petition No. 94/MP/2021 Page 17

 Power (“MOP”). Accordingly, the regime that governs the tariff of the NRSS XXXI B
project falls under Section 63 of the EA 2003.

(d) OPGW cables do not constitute a standalone asset. It is only a part of the
transmission assets of a transmission licensee. The NRSS XXXI B Project is
regulated under Section 63 of the EA 2003, it may not be appropriate to apply a
separate regulated tariff mechanism for the upcoming OPGW cables of the NRSS
XXXI B Project.

(e) In view of the above, the OPGW cables forming part of the communication system
would form an integral part of the transmission lines owned and operated by
Respondent No. 1.

(f) In the context of factoring in the implementation of the Reliable Communications

Scheme in the tariff of the TBCB licensee, implementation of the Communication
System as part of the NRSS XXXI B project by replacing the earth-wire with OPGW
cables is an additional requirement under the mandate of law. Considering that the
said requirement has cropped up after the bid deadline, the implications of the
above should be considered under the Change in Law provision of the Transmission
Service Agreement (TSA).

(g) The consequences of the Change in Law and, in particular, the computation of the
impact thereof upon the tariff have been set out in detail under the TSA. Considering
that the TSA governs the tariff for the entire transmission assets in the NRSS
project, any change in such tariff would fall within the purview of the TSA.

(h) There is precedent for allowing additional expenditure incurred on account of a

Change in Law to be passed through in the tariff. Reliance is placed on Talwandi
Sabo Power Limited vs Punjab State Electricity Regulatory Commission
[MANU/ET/0054/2020], wherein the Tribunal held that the MoEF and CC
Notification constituted a Change in Law event and any additional expenditure
incurred on account of the installation of flue-gas desuphurisation system was to be
included as Additional Capital Cost. Reliance is also placed on the judgment of the
Tribunal in NRSS XXXI (B) Transmission Limited vs Central Electricity Regulatory
Commission [MANU/ET/0071/2021]. In this case, the Appellant has claimed
compensation on account of the increase in the length of the transmission lines due
to a change in the Gantry Coordinates from the one indicated in the Survey Report.

Order in Petition No. 94/MP/2021 Page 18

(i) Further, vide its Final Order dated 13.05.2022 in remand proceedings in Petition no.
195MP2017, it was decided as follows:

“16. Accordingly, NTL shall recover from LTTCs the IDC and IEDC incurred for the extended
period of SCOD and compensation for the actual change in the length of the Transmission
lines as against the length of the Transmission lines in case the Gantry Coordinates would
have been same as indicated in the Survey Report in accordance with Article 12.2.1 of the
TSA i.e. increase in non-escalable transmission charges at the rate of 0.313% for a
cumulative increase of capital cost of Rs.1.158 crore incurred up to the extended SCOD of
the project.”

(j) Procedurally and administratively, it would be quite difficult and challenging for the
TSP, CTUIL & other stakeholders involved actively in the ISTS transmission
charges billing, collection & disbursement (BCD) process from a viewpoint that parts
of the same transmission asset owned & operated by same Transmission Licensee
would be treated under two different tariff regimes i.e. part asset under TBCB Tariff
and part asset under RTM mode. The commission may please consider the single
tariff regime under the available provision of the TSA for all such similar cases of
OPGW laying in the existing transmission TBCB assets.

Analysis and Decision

17. We have considered the submissions of the Petitioner, and Respondents and
perused all relevant documents on record. The following issues arise for our
consideration:

Issue No. 1: Who shall be responsible for implementing the installation

of optical ground wire (OPGW) to strengthen the communication network
by replacing the earth wire on the existing transmission line owned by a
transmission licensee?

Issue No. 2: What other factors need to be considered while such

replacement is carried out, such as the impact on discovered tariff,
availability, loss due to damage, etc. for the transmission licensee?

The above issues have been dealt with in succeeding paragraphs.

Order in Petition No. 94/MP/2021 Page 19

Issue No. 1: Who shall be responsible for implementing the installation of optical
ground wire (OPGW), to strengthen the communication network by replacing the
earth wire on the existing Transmission Line owned by a transmission licensee?

18. Petitioner has submitted that the Reliable Communication Scheme under Central
Sector for Northern Region for installation of OPGW based reliable communication
system with a network size of 7248 kms (including OPGW replacement of ULDC
Phase–I), by the Petitioner, was approved in the 39th Meeting of the Northern
Regional Power Committee held on 2.5.2017, which was revised to 7398 Km in the
47th Meeting of the Northern Regional Power Committee held on 11.12.2019.

19. Petitioner has taken up the implementation of the project wherein OPGW is to be
installed on ISTS transmission lines by replacing existing earth wire for which it has
entered into a contract dated 31.1.2019 with M/s Apar Industries Ltd. (APAR) as per
which dismantled earth wire shall be taken away by the contractor.

20. Petitioner has approached Respondent No.1 for installation of OPGW on the 400kV
D/c Kurukshetra-Malerkotla line, which was opposed by Respondent No. 1 seeking
clarifications on the regulations under which Petitioner has proposed to take away
part of its asset and the ownership of new OPGW among other queries.

21. Respondent Western Transco Power Limited (WTPL) has submitted that the OPGW
which shall be installed may be utilized for commercial purposes such as
communication etc., which cannot be allowed to an entity which is not the owner of
the transmission asset, and that the said entity cannot be permitted to make undue
monetary gains by using the said asset. Further, during the installation of the
OPGW, there may be damage to the existing assets of the Applicant. WTPL.
Further, the concerns on Deemed availability/ compensation of financial loss in case
of tripping, breakdown, maintenance, etc., due to the reason not attributable to the
transmission licensee which owns the transmission line in question need to be
handled besides who will carry out O&M of such OPGW.

22. The Respondents NER-II Transmission LTD. (NERII), Parbati Koldam

Transmission Co. LTD. (PKTCL), Gurgaon Palwal Transmission Co. LTD. (GPTL),
Jabalpur Transmission Co. LTD. (JTCL), Maheshwar Transmission Co. LTD. (MTL),
RAPP Transmission Co. LTD. (RTCL), Bhopal Dhule Transmission Co. LTD.
(BDTCL), Odisha Generator Phase-II Transmission Co. LTD. (OGPTL), East North

Order in Petition No. 94/MP/2021 Page 20

 Interconnection Transmission Co. LTD. (ENICL), Patran Transmission Co. LTD
(PTCL) and Purulia & Kharagpur Transmission Co. LTD (PKTCL) have opposed the
replacement of earth wire by any other licensee such as Petitioner.

23. Subsequent to the filing of the instant Petition, several rounds of meetings were
undertaken by CTUIL with transmission licensees wherein consensus emerged
during the meetings held on 13.3.2023 and 8.5.2023 regarding modalities for
implementation of OPGW raised in the instant Petition.

24. We have considered the submissions of the Petitioner and Respondents and have
also perused the facts on record.

25. The relevant extracts of the 39th Meeting of the NRPC held on 2.5.2017, and 47 th
Meeting of the NRPC held on 11.12.2019 are as under:

39th Meeting of the NRPC held on 2.5.2017

“NRPC Deliberations
B.6 Reliable Communication Scheme under Central Sector for Northern Region
B.6.7NRPC approved the proposal by POWERGRID for installation of 5474 kms. of OPGW
based communication scheme, at an estimated cost of Rs.137 Crs.”
“B.17 Replacement of OPGW installed under ULDC Phase-I
B.17.6 POWERGRID informed that 24-F OPGW would be considered as per the existing
philosophy and along with communication equipment for which the estimated cost would
be Rs.59 Crs. The scheme would become part of existing Commercial Agreement signed
for ULDC Project and would be implemented as part of Reliable Communication Scheme
under Central Sector for Northern Region.
B.17.7 After detailed deliberations NRPC approved the proposal of replacement of old
OPGW installed under ULDC phase-I…”

47th Meeting of the NRPC held on 11.12.2019

"B.6.4 After detailed deliberations, the following links were agreed upon:
SI. Name of Link Route Purpose
No. Length
(km)
1 400kV Panchkula- 65.494 Physical Path Redundancy & route diversity
Patiala for Panchkula S/s
2 400kV Jallandhar 85.15 Physical Path Redundancy & route diversity
Moga for Jallandhar (PG) through Central Sector
links.
3 400kV Parbati PS - 250.53 Path Redundancy & route diversity of
Amritsar Parbati PS (Banala) & Hamirpur 4 through
4 LILO of Parbati – 6.7 Central sector network.
Amritsar at Hamirpur

Order in Petition No. 94/MP/2021 Page 21

 5 400kV Kurukshetra- 180 Path Redundancy of Malerkotla (PG)
Malerkotla PG through central sector network.
6 765kV Meerut - Moga 337.15 Route diversity of Moga S/S & creation of
reliable ICCP link between Punjab,
Rajasthan (through upcoming 765kV
Bikaner Moga under GEC Part D & NRLDC.
7 400kV Dehradun- 165 Physical path Redundancy & for route
Bagpat diversity of Bagpat S/S
8 400kV RAPP B -Jaipur 226 Redundancy of Kota & RAPP through
South with LILO at Kota Central Sector network
9 400kV Allahabad- 200 Redundancy of Singrauli
Singrauli
10 400kV Allahabad- 130 Strengthening of Inter Regional
Fatehpur 765 Connectivity (WR-NR). (400kV Fatehpur –
Mainpuri is under implementation under
Reliable Communication scheme)
11 400kV Kanpur - 370 Redundancy of old Agra-Kanpur link which
Ballabhgarh has reached the end of its useful life of 15
years.
12 Chittorgarh 400kV 07 Redundancy of Chittorgarh 220/132
RVPN to Chittorgarh through Central Sector network
220kV RVPN
13 400kV Lucknow – 156 Redundancy of Network and avoiding
Kanpur multiple sub-stations
TOTAL 2179.024

B.6.5 POWERGRID further informed that in accordance with 39 th & 40th NRPC meeting,
implementation of 7248 Km OPGW is under execution. POWERGRID also informed that
around 2031 km OPGW network is not coming up in the original reliable scheme (as
approved in 39th NRPC) as some of the IPPs are not coming up and also connectivity for
some were covered in different schemes. Considering the same and additional requirement
of 2180 km as proposed for taking care of contingencies as per Communication Planning
Criteria, the overall network size approved in 39th & 40 th NRPC will increase by only 150
km considering new requirement of 2180 km in lieu of 2031km network not coming up as
brought out above.
B.6.6 Accordingly, TeST sub-committee members have agreed for the implementation of
2180 Km of OPGW network under on-going Reliable Communication Project (7248 km) so
that the same can be implemented within the same time period. The revised network size
of Reliable Communication Project will become 7398 Km.
B.6.7 TCC recommended for the approval of the modified scheme as agreed by TeST
subcommittee.
NRPC Deliberations
B.6.8 NRPC concurred with TCC deliberations.”

As per the above, the proposal of the petitioner for the installation of OPGW based
communication network for Reliable Communication Scheme under the Central
Sector for Northern Region was approved in 39 th Meeting of NRPC held on
02.05.2017 and 47th Meeting of NRPC held on 11.12.2019, wherein the installation
of OPGW on 400kV Kurukshetra - Malerkotla line (180km) by replacing the earth
wire was agreed in 47th meeting of the NRPC.

Order in Petition No. 94/MP/2021 Page 22

26. Clauses 7.1.1 and 7.1.2 of the Transmission Service Agreement dated 02.01.2014
of Respondent No.1, as submitted by the Petitioner, provide as under:

“7. OPERATION AND MAINTENANCE OF THE PROJECT

7.1.1 The TSP shall be responsible for ensuring that the Project is operated and maintained
in accordance with the Indian Electricity Grid Code (IEGC)/State Grid Code (as applicable),
Transmission License, directions of National Load Despatch Centre/RLDC/SLDC (as
applicable), Prudent Utility Practices, other legal requirements including the terms of
Consents, Clearances and Permits and is made available for use by the Transmission
Customers as per the provisions of applicable regulations including but not limited to the
Central Electricity Regulatory Commission (Open Access in Inter-state Transmission)
Regulations, 2004, Central Electricity Authority (Installation and Operation of Meters)
Regulations, 2006, and the Central Electricity Authority Grid Standards of Operation and
Maintenance of Transmission Lines (as and when it comes into force) as amended from
time to time and provisions of this Agreement.
7.1.2 The TSP shall operate and maintain the Project in an efficient, coordinated and
economical manner and comply with the directions issued by the National Load Despatch
Centre, RLDC or the SLDC, as the case may be, in line with the provisions of the Electricity
Act 2003 and Rule 5 of the Electricity Rules, 2005, and as amended from time to time.”

As per the above, the TSP (i.e. Transmission licensee) is responsible for ensuring
the operation and maintenance of the project in an efficient, coordinated and
economical manner and in compliance with the Indian Electricity Grid Code
(IEGC)/State Grid Code (as applicable), Transmission License, directions of
National Load Despatch Centre/RLDC/SLDC (as applicable), Prudent Utility
Practices, other legal requirements.

Further, the “Prudent Utility Practices” defined in the TSA are as under:

““Prudent Utility Practices” shall mean the practices, methods and standards that are
generally accepted internationally from time to time by electric transmission utilities for
the purpose of ensuring the safe, efficient and economic design, construction,
commissioning, operation, repair and maintenance of the Project and which practices,
methods and standards shall be adjusted as necessary, to take account of:
(i) operation, repair and maintenance guidelines given by the manufacturers to
be incorporated in the Project,
(ii) the requirements of Law, and
(iii) the physical conditions at the Site
…………………………”

As per the above, the TSP (i.e. Transmission licensee) is obligated to adopt the
practices, methods and standards that are generally accepted internationally from
time to time by electric transmission utilities for the purpose of ensuring the safe,
efficient and economic design, construction, commissioning, operation, repair and
maintenance of the Project and to take into account the guidelines given by the
manufacturers, requirements of law and physical conditions at the site.

Order in Petition No. 94/MP/2021 Page 23

27. Regulation 7.2 of the Communication System Regulations, 2017, provides as under:

“7.2 Role of CTU (i) The CTU shall in due consideration of the planning criteria and
guidelines formulated by CEA, be responsible for planning and coordination for
development of reliable National communication backbone Communication System among
National Load despatch Centre, Regional Load Despatch Centre(s) and State Load
Despatch Centre(s) and REMCs along with Central Generating Stations, ISTS Sub -
Stations, UMPPs, inter-State generating stations, IPPs, renewable energy sources
connected to the ISTS, Intra-State entities, STU, State distribution companies, Centralised
Coordination or Control Centres for generation and transmission. While carrying out
planning process from time to time, CTU shall in addition to the data collected from and in
consultation with the users consider operational feedback from NLDC, RLDCs and SLDCs.
(ii) The CTU shall plan the communication system comprehensively and prospectively for
users considering the requirement of the expected nodes in consultation with Standing
Committee to be constituted by CEA.”

As per the above, CTUIL shall be responsible for planning and coordination for the
development of a reliable National communication backbone Communication
System among the National Load despatch Centre, Regional Load Despatch
Centre(s) and State Load Despatch Centre(s) and REMCs along with Central
Generating Stations, ISTS Sub -Stations, UMPPs, inter-State generating stations,
IPPs, renewable energy sources connected to the ISTS, Intra-State entities, STU,
State distribution companies, Centralized Coordination or Control Centres for
generation and transmission.

28. Clause (aa) of Regulation 2(i) and Regulation 7.8 of the Communication System
Regulations, 2017, provide as under:

“2(i) aa) “User” means a person such as a Generating Company including Captive
Generating Plant, RE Generator, Transmission Licensee [other than the Central
Transmission Utility (CTU) and State Transmission Utility (STU)], Distribution Licensee, a
Bulk Consumer, whose electrical system is connected to the ISTS or the intra-State
transmission system.
…………..
7.8 Role of Users:
(i) The Users including renewable energy generators shall be responsible for provision of
compatible equipment along with appropriate interface for uninterrupted communication
with the concerned control centres and shall be responsible for successful integration with
the communication system provided by CTU or STU for data communication as per
guidelines issued by NLDC.
(ii) Users may utilize the available transmission infrastructure for establishing
communication up to nearest wideband node for meeting communication requirements
from their stations to concerned control centres.
(iii) The Users shall also be responsible for expansion /up-gradation as well as operation
and maintenance of communication equipment owned by them.”

Order in Petition No. 94/MP/2021 Page 24

 As per the above, Users, inter-alia including transmission licensee, may utilize the
available transmission infrastructure for establishing communication up to the
nearest wideband node for meeting communication requirements and shall also be
responsible for expansion /up-gradation as well as operation and maintenance of
communication equipment owned by them.

29. Regulation 26(1) of the Communication Standards Regulations, 2020 provides as

under:

“26. Requirements of fibre optic communication. (1) All wideband communications shall
be established using fibre optic communication consisting of underground fibre optic cable,
optical ground wire (OPGW) or underground fiber optic cable (UGFO) and all dielectric self
supporting (ADSS).”

As per the above, all wideband communications shall be established using fibre
optic communication.

30. The Guidelines on Planning of Communication System for Inter-State Transmission

System (ISTS) issued by MoP on 09.03.2022 provides as under:

“Guidelines on Planning of Communication System for Inter-State Transmission

System (ISTS)
1. Introduction
In order to achieve safe, secure, stable and reliable operation of the grid as well as its
economical and integrated operation, communication system plays a critical role. The
communication system may be treated as an integral part of the transmission system.
Therefore, it is imperative to carry out the planning for Communication System in Power
Sector.
For planning, and coordination for development of communication system for inter-State
transmission system, Central Transmission Utility is designated as the nodal agency.
Ministry of Power has formulated this guidelines named as “Guidelines on Planning of
Communication System for Inter-State Transmission System (ISTS)”. This guidelines
defines the categories of Communication System Schemes for ISTS and their
corresponding approval procedure.
2. Objective
Considering the critical role of Communication System in ISTS, a separate guidelines for
its planning is essential. This guideline on Planning of Communication System for Inter-
State Transmission System (ISTS) is being formulated with the objective to help in efficient,
coordinated, smooth, economical and uniform planning of Communication System for ISTS.
3. Applicability
i. This guideline shall come into force from the date of its issuance by the Ministry of
Power.
ii. The guidelines shall be applicable for communication system for ISTS only.
4. Categorization of Communication Schemes/Packages

Order in Petition No. 94/MP/2021 Page 25

 Communication Schemes/Packages under this policy are categorized as Category (A) and
Category (B). The description of categories is as under:-
Category (A): Communication system directly associated with new ISTS as well as
incidental due to implementation of new ISTS elements (e.g. LILO of existing line on
new/existing S/s where OPGW/terminal equipment are not available on the existing main
line/substations etc.)
Category (B): Upgradation/modification of existing ISTS Communication system pertaining
to following:
• Missing Links
• Redundancy/ System Strengthening
• Capacity upgradation (Terminal equipment)
• Completion of life of existing communication system elements
• Other standalone project e.g. Cyber Security, Unified Network Management System
(UNMS)
• Adoption of New Communication Technologies
5. Procedure for approval of Communication Schemes/Packages
Category (A): As planning of ISTS Communication System is an integral part of planning
of new Inter-State Transmission System, the requirement for communication system linked
with new ISTS shall be included in new ISTS package and combined proposal shall be
approved as per the directions contained in MoP office order dated 28.10.2021 regarding
Re-constitution of the “National Committee on Transmission” (NCT).
Further, Communication requirements which are incidental due to implementation of new
ISTS elements (e.g. LILO of existing line on new/existing S/s where OPGW/Terminal
Equipment are not available on the existing main line/substations etc.) are also to be
approved alongwith that of respective transmission system package.
Category (B):
Communication Schemes/Packages proposed by CTUIL for upgradation/modification of
existing ISTS Communication System, standalone projects, adoption of new technologies
shall be put up to RPC for their views. RPC to provide their views on the
Schemes/Packages proposed by CTUIL within 45 days of receipt of the proposal from
CTUIL.
The Schemes/Packages alongwith the views of RPC shall be approved by NCT.
6. Communication system shall be planned in accordance with Central Electricity Authority
(Technical Standards for Communication System in Power System Operations)
Regulations, Central Electricity Regulatory Commission (Communication System for inter-
State transmission of electricity) Regulations, Manual of Communication System Planning
in Power System Operation published by Central Electricity Authority and other relevant
regulations/guidelines/orders/policies issued by Government of India for development of
reliable communication system for the power system.”

As per the above, Communication Schemes shall be proposed by CTUIL for the
upgradation/modification of the existing ISTS Communication System, standalone
projects, and adoption of new technologies, respectively.

31. We observe that the modalities of implementation of the said OPGW by the existing
transmission licensee or POWERGRID are not covered specifically in the MOP

Order in Petition No. 94/MP/2021 Page 26

Communication Guidelines. However, on the direction of the Commission,
Petitioner has convened meetings on 14.07.2021,13.08.2021,13.03.2023 and
8.05.2023 with the ISTS licensees to come out with a suitable proposal for smooth
and proper adjudication of the issues involved. Consensus for the installation of
OPGW by replacing the existing earth wire has been reached in the meetings held
on 13.03.2023 and 08.05.2023. The relevant extracts of the same are as follows :

Minutes of the Meeting held on 13.03.2023 between CTU, POWERGRID &NRSS

XXXI (B) Transmission Ltd./ Sekura

“…..………………..
3. CTU added that a compliance affidavit was submitted before CERC after receiving
communication from POWERGRID that it has no objection if the implementation of laying
of OPGW is undertaken by M/s NRSS XXXI (B) Transmission Ltd. / Sekura on its 400kV
D/C Malerkotla - Kurukshetra line. Subsequently M/s NRSS XXXI (B) Transmission Ltd.
/ Sekura submitted a proposal to CTU via letter dtd. 23.01.2023 for OPGW installation
on its 400kV Malerkotla - Kurukshetra line as well as on 400kV Malerkotla – Amritsar
line of 48F OPGW on both the lines.
4. CTU further informed that after reviewing the proposal of M/s NRSS XXXI (B)
Transmission Ltd. / Sekura, the 400kV D/C Malerkotla – Amritsar line was not found to
be required at present for OPGW installation. Moreover, the OPGW fibre capacity of 24F
is sufficient at present. In view of this CTU has put up an agenda in 63rd NRPC for
OPGW installation on the 400kV D/C Malerkotla - Kurukshetra line with 24F OPGW.
NRPC after deliberations, was of the view that Hon’ble CERC should be apprised about
the proposal before reviewing in RPC and getting approved in NCT. If M/s NRSS XXXI
(B) Transmission Ltd. / Sekura wants to install OPGW on its 400kV D/C Malerkotla –
Amritsar line and 48F in place of 24F in both 400kV D/C Malerkotla - Kurukshetra line &
400kV D/C Malerkotla – Amritsar line, the cost of the OPGW with 48F on 400kV
Malerkotla – Amritsar line and additional fibers of 400kV D/C Malerkotla - Kurukshetra
line shall be borne by the M/s NRSS XXXI (B) Transmission Ltd. / Sekura.
5. CTU further stated that the various issues raised earlier by M/s NRSS XXXI (B)
Transmission Ltd. / Sekura viz., impact on tariff and revenue after replacement of
earthwire with OPGW (POWERGRID Ownership), handing over the earth wire to
POWERGRID, rectification of any damaged asset in the process of OPGW installation,
prior intimation & work planning of OPGW laying work and; details of responsible
contractor, indemnification on of any outage or claimed compensation by any landowner,
issue related to the ownership of the OPGW and its O&M, and issue related to any
commercial use of OPGW etc. shall get resolved as the OPGW laying work shall be
awarded to NRSS XXXI (B) Transmission Ltd. / M/s Sekura after NCT approval under
RTM mode, and M/s Sekura being the Owner of this ISTS transmission line the
ownership of this OPGW would also remain with them.
6. NRSS XXXI (B) Transmission Ltd. / M/s Sekura suggested that this OPGW work shall
be awarded to them as additional work by change in the original transmission line scope
and cost of the same shall be recovered by revision in their existing TBCB tariff.
However, CTU stated that as the TBCB asset has already lived its prominent life so this
work shall be awarded in RTM mode and tariff of the same shall be determined by the
applicable RTM regulations of CERC.
7. CTU stated that deliberations of this meeting shall be communicated to CERC as part of
Petition no. 94/MP/2021.

Order in Petition No. 94/MP/2021 Page 27

 …………………..”

As per the above, NRSS XXXI(B) Transmission Ltd / M/s Sekura suggested
installing 48 F OPGW in place of 24 Fibre suggested by CTUIL. Further, Sekura
suggested that OPGW work may be awarded to them as additional work by a
change in the original transmission line scope, and the cost of the same may be
recovered by a revision in their existing TBCB tariff. However, CTU stated that this
work shall be awarded in RTM mode, and the tariff of the same may be determined
as per RTM regulations of CERC. Further, CTU also stated that various issues
raised earlier by M/s NRSS XXXI (B) Transmission Ltd. / M/s Sekura shall also be
resolved by awarding the OPGW work to them.

Minutes of the Meeting held between CTU & ISTS Transmission Licensees on
08.05.2023

“7. With reference to above ROP and MOP guidelines, CTU proposed below mentioned
methodology for deliberation during the meeting:

Sr. No. CTUIL proposal for deliberations

(i) In view of MoP “Guidelines on Planning of Communication System for lnter-

State Transmission System (ISTS)” dtd. 09.03.2022 and recent approvals of
OPGW on existing lines, following is proposed:
(i) OPGW installation work under ISTS Communication requirement shall
be awarded to the transmission line asset owner.
(ii) Terminal equipment associated with OPGW cable shall be awarded to
bay owner/s of the transmission line on which OPGW is proposed for
installation.
If the Asset owners refuses the work same shall be deliberated in the NCT and
awarded to other party with consent of existing asset owner/s.

(ii) Other views of Transmission licensees on the above

8. Sekura agreed for the methodology put up by CTU, however they raised the concern of
provision of Fibre Optic Terminal equipment (FOTE) at bays level for their line, 400kV
Kurukshetra- Malerkotla. POWERGRID confirmed they shall provide FOTE as the bays are
owned by them as suggested by CTU.
9. Indigrid enquired about the modalities of using OPGW for ISTS communication which is
provided by the TSP which was not originally in the scope of RFP of a transmission line.
CTU informed that such issues shall be dealt on case-to-case basis in the RPC forum, in
view of ISTS system requirement.
10. Other licenses also agreed to the CTU proposal.
…………..”

As per the above, it was agreed that OPGW installation work under ISTS
Communication requirement might be awarded to the transmission line asset

Order in Petition No. 94/MP/2021 Page 28

 owner, and if the asset owners refuse the work, same may be deliberated in the
NCT and awarded to another party with the consent of existing asset owner(s).

32. We observe that Communication systems are essential to facilitate secure, reliable
and economic operation of the grid and are an important pre-requisite for the
efficient monitoring, operation and control of the power system CTU, has been
entrusted with the responsibility of planning and coordination for the development
of an efficient and coordinated communication system on a regional basis to provide
a backbone communication system for the ISTS under various Regulations of CEA
and CERC and Guidelines of MOP.

33. We observe that during the meetings held on 13.03.2023 and 8.5.2023, Petitioner
CTUIL and Respondent No.1Sekura have agreed on the modalities of
implementation of OPGW on instant transmission asset of Malerkotla-Kurukshetra
line. Further, during the hearing on 15.05.2023, CTUIL based on the meeting held
on 08.05.2023 between CTU and various transmission licensees, submitted that the
OPGW work may be awarded to the transmission line asset owner. Accordingly, the
work of replacement of earth wire under instant case may be allowed to be executed
by the transmission licensee owning such earth wire following the required
procedure with the approval of the competent authority.

Issue No. 2: What other factors need to be considered while such replacement is
carried out, such as impact on discovered tariff, availability, loss due to damage
etc, for the Transmission licensee?

34. During the Meeting held on 13.03.2023 and during a hearing on 15.05.2023, CTU
has submitted that the work may be awarded in RTM mode and the tariff of the
same may be determined by the Commission as per the applicable regulations.

35. Respondent No.1 has submitted that the implementation of the Communication
System by replacing the earth-wire with OPGW cables is an additional requirement
under the mandate of law, and the same may be considered under the Change in
Law provision of the Transmission Service Agreement (TSA). Further, the
consequences of Change in Law and, in particular, the computation of the impact
thereof upon the tariff have been set out in detail under the TSA, and any change
in tariff would fall within the purview of the TSA.

Order in Petition No. 94/MP/2021 Page 29

36. We observe that installation of OPGW is a requirement which has emerged at a
stage after the TBCB project has been declared commercial. Further, we observe
that the tariff of the TBCB Project is governed in terms of TSA and are of the view
that appropriate compensation needs to be provided for recovery of additional
expenditure towards OPGW installation and its maintenance by the licensee.

37. We have perused the TSA signed on 02.01.2014 between NRSS XXXI (B)
Transmission Limited and LTTCs, submitted in another Petition No. 89/TT/2014,
which provides the treatment of Change in Law as under:

“12 CHANGE IN LAW

12.1 Change in law
12.1.1 Change in law means the occurrence of any of the following after the date, which is
seven (7) days prior to the Bid Deadline resulting into any additional recurring/ non –
recurring expenditure by the TSP or any income to the TSP:
• The enactment, coming into effect, adoption, promulgation, amendment,
modification or repeal (without re-enactment or consolidation ) in India, of any Law,
including rules and regulations framed pursuant to such Law;
• a change in the interpretation or application of any Law by any Indian Governmental
Instrumentality having the legal power to interpret or apply such Law, or any
Competent Court of Law:
• the imposition of a requirement for obtaining any Consents, Clearances and Permits
which was not required earlier;
• a change in the terms and conditions prescribed for obtaining any Consents,
Clearances and Permits or the inclusion of any new terms or conditions for obtaining
such Consents, Clearances and Permits;
• any change in the licensing regulations of the Appropriate Commission, under which
the Transmission License for the Project was granted if made applicable by such
Appropriate Commission to the TSP;
• any change in the Acquisition Price; or
• any change in tax or introduction of any tax made applicable for providing
Transmission Service by the TSP as per the terms of this Agreement
………………
12.2 Relief for Change in Law
12.2.1 During Construction Period
During the Constriction Period, the impact of increase/decrease in the cost of the Project in
the Transmission Charges shall be governed by the formula given below:
- For every cumulative increase/decrease of each Rupees One Crore Fifteen Lakhs
Eighty Thousand Only (Rs. 1.158 Cr) in the cost of the Project up to the Scheduled
COD of the Project, the increase/decrease in Non-Escalable Transmission Charges
shall be an amount equal to Zero Point Three One Three percent (0.313%) of the Non-
Escalable Transmission Charges.
12.2.2 During the Operation Period:
During the Operation Period, the compensation for any increase/decrease in revenues shall
be determined and effective from such date, as decided by the Appropriate Commission
whose decision shall be final and binding on both the Parties, subject to rights of appeal
provided under applicable Law.
Provided that the above mentioned compensation shall be payable only if the
increase/decrease in revenues or cost to the TSP is in excess of an amount equivalent to
one percent (1%) of Transmission Charges in aggregate for a Contract Year.

Order in Petition No. 94/MP/2021 Page 30

 12.2.3 For any claims made under Articles 12.2.1 and 12.2.2 above, the TSP shall provide
to the Long Term Transmission Customers and the Appropriate Commission documentary
proof of such increase/decrease in cost of the Project/ revenue for establishing the impact
of such Change in Law.
12.2.4 The decision of the Appropriate Commission, with regards to the determination of
the compensation mentioned above in Articles 12.2.1 and 12.2.2, and the date from which
such compensation shall become effective, shall be final and binding on both the Parties
subject to rights of appeal provided under applicable Law.”

We observe that the instant case of replacement of earth wire with OPGW is a work
which was not part of the original scope of TSA. Since the OPGW has not been
provided with a separate transmission licence, we are not inclined to consider the
suggestion of CTU to consider the instant work of replacement under RTM. We
observe that TSA provides for treatment of additional expenditure under “Change
in Law”. We are of the considered view that additional expenditure on account of
the replacement of earth wire after adjusting the buy-back or the scrap value of that
earth-wire shall be treated in the manner as expenditure under Change in Law so
that its recovery is simplified. The transmission licensee is directed to follow a
transparent process of competitive bidding while implementing such work. After
implementation of the work, the transmission licensee is required to approach the
Commission for approval of such expenditure along with audited data of the
expenditure and details of competitive bidding carried out by it. The transmission
licence shall not be required to be amended to include OPGW since the
transmission licence issued to Respondent No.1 does not specifically provide the
specification of earth wire, and OPGW shall be considered within the same
transmission licence.

38. Further regarding the treatment of deemed availability for the period when such
replacement is carried out, we have perused the TSA signed on 02.01.2014
between NRSS XXXI (B) Transmission Limited and LTTCs, submitted in another
Petition No. 89/TT/2014, which provides the provision for availability of the project
as under:

“8 AVAILABILITY OF THE PROJECT

8.1 Calculation of Availability of the Project:
Calculation of Availability for the Elements and for the Project, as the case may be, shall
be as per Appendix IV of the Central Electricity Regulatory Commission (Terms and
Conditions of Tariff) Regulations, 2009, as applicable seven (7) days prior to the Bid
Deadline and as appended in Schedule 9.
…………….

Order in Petition No. 94/MP/2021 Page 31

 Schedule 9
Appendix IV of Central Electricity Regulatory Commission (Terms and Conditions of
Tariff) Regulations, 2009
Procedure for Calculation of Transmission System Availability Factor for a Month
”
………….
5. The transmission elements under outage due to following reasons shall be deemed to
be available:
i. Shut down availed for maintenance or construction of elements of another transmission
scheme. If the other transmission scheme belongs to the transmission licensee, the
Member-Secretary, RPC may restrict the deemed availability period to that considered
reasonable by him for the work involved.
ii. Switching off of a transmission line to restrict over voltage and manual tripping of switched
reactors as per the directions of RLDC.
…………………….”

As per the above, the transmission elements under outage due to shutdown availed
for maintenance or construction of elements of another transmission scheme, which
may be of the same transmission licensee also, shall be deemed to be available.
Hence the issue of deemed availability shall be handled accordingly.

39. Considering the above we are of view that the treatment of deemed availability
during the period of OPGW installation work by replacing the exiting earth wire, shall
be treated in terms of the provisions under TSA.

40. CTUIL is directed to follow similar principles for facilitating and allowing OPGW
installation by other transmission licensees.

41. The Petition No. 94/MP/2021 is disposed of in terms of the above.

Sd/ Sd/ Sd/ Sd/

(P. K. Singh) (Arun Goyal) (I. S. Jha) (Jishnu Barua)
Member Member Member Chairperson

CERC Website S. No. 563/2023

Order in Petition No. 94/MP/2021 Page 32
 Annexure-XV

INDIGRID
POWERGRID
HPCL
 HP POWER TRANSMISSION CORPORATION LIMITED Annexure-XVI
(A State Government Undertaking)
DGM Photection &Communication), Chow Ai Jamw alan, Hamirpur (HP)
HPPTCL Email- dgmprot teiahpmail.in
No:
To
HPPTCUDGMP&CVLahalPC-67/2024- s 771 Dated: /3/>34
The Surerintending Engineer.
Northern Regional Power Committee.
New Delhi - 100l6.

Subject: Approval for sharing of Fiber Pairs on OPGW of 400 kV Lahal-Rajera

(Chamera Pooling) and 220 kV Lahal-Budhil for redundant for Chamera-l
(NHPC)& Budhil(GreenCo.).
Sir,
With reference to the subject cited matter. the competent authority of HPPTCL has
given the approval with some ternms and conditions vide letter no. HPPICL Proj. F-]43 23-24
1327258 2024 dated 23.01.2024 (Copy attached).
This is for vour kind intormation and further necessary action. please.

Yours faithfully.
DA: As Above.

Dy. GenertManager (P&C).

HPPTCL, Chow ki Jamwalan.
Hamirpur (HP).
Copy to following for kind information & necessary action, please: -
1. The GM (Projects). HPPTCL, Himfed Bhawan, Shimla-s.
2. The GM (C&D), HPPTCL, Himfed Bhawan. Shimla-5.
3. The DGM (Projects). HPPTCL, Chamba (H.P.).
4. The Sr. Manager (Proj.). HPPTCL, PIULahal Distt. Chamba (H.P.).

Dy. Genr Manager (P&C),

HPPTCL, Chow ki Jamwalan,
Hamirpur (HP).
 HPPTCL-PRJOF143/1/2022-Project Cell-HPPTCL
1327258/2024
H. P. PoWER TRANSMISSION
CORPORATION
(AState Govt. Undertaking)
LTD.
HPPTL
Web: - www.hpplc.com
Regd. O1fice: Himfed Bhawan, New 1SBT Road, Panjari, Shimla-171005
Ph.: 0177-2831283, 2831284 FAX -0177-2831284
(CIN): U40101HP2008SGC030950
(GSTIN) 02AACCH1548M1Zp

No. HPPTCL/Proj./F-143/23-24- L/322 2 S8/2o2 4 Dated: 23loll2o24.

To
The DGM (P&C), HPPTCL,
Chowki Jamwalan,
Hamirpur(H.P.)
Subject: - Approval for sharing of Fiber Pairs on OPGW of 400kV Lahal
Rajera(Chamera Pooling) and 220kV Lahal-Budhil for redundant
for Chemra-III(NHPC) & Budhil(Green Co.).
Ref: Letter no.
HPPTCL/DGM(P&C)/PC-67/2023-491-493, dated:
07/10/2023.
Dear Sir,
With reference to your letter dated 7/10/2023 on the subjcct matter,
it is hereby conveyed thal he capilal investment made by HPPTCL for
establishing its transmission and associated communication infrastructure is or
will be recovered from the users of its transmission system. The users hold the
rights of usage of the transmission system under the regulatory framework. Whle
there are regulatory guidclines for sharing transmission assets, this office is not
aware of any Central or Stale regulalory provision permitting or requiring
HPPTCL (STU-HP) to share dark fibers in its transmission network for non
commercial usage by other agencies.

However, considering the nature of the request-establishment of aredundant

communication system for Lahal-Budhil-Chamera-III, as discussed in the 23rd
Meeting of the Tclecommunication, SCADA, & Telemetry Sub-Comnittee on
21/09/2023-the competent authority of HPPTCL hasapproved the provision of a
total of 3 pairs (6 fibers) to PGCIL/ULDC on the 1. 220kV Lahal(HPPTCL)
Budhil(GreenCo) and 2. 400 kV Lahal(HPPTCL) Chamera Pooling(PGCIL)
Transmission Lines. This approval is subject to the following conditions:
1. The fibers shall be strictly used for the Non-Commercial Grid
Telemelry Communication System for the transmission of

Er.
electricity.
Abhsdh
SA
(Pror

U.No.3

yalan Hamirçu
 HPPTCL-PRJOF143/1/2022-Project Cell-HPPTCL
/327258/2024

2. HPPTCL reserves the right to withdraw the approval of sharing

with aone-month notice at its discrelion.
3. Any policy/regulation from statutory bodies regarding the
sharing of OPGW on transmission lines shall override this
approval.
4. Any charges payable for sharing dark fibers, if deternmined by the
appropriate authorily, shall apply.
This is lor your kind informaion and further necessary action please.
Signed by
Anil Gautam
Date: 23-01-2024 10:48:58

General Manager (Projects),

HPPTCL, Himfed Bhawan,
Panjari Shimla, 171005
Copy to:
1. The General Manager(C&D), HPPTCL, Himfed Bhawan, Shimla-05.

General Manager (Projects),

HPPTCL, Himfed Bhawan,
Panjari Shimla, 171005
 Annexure-XVIIa

Minutes of Meeting for Planning of Communication system for Inter-State Transmission

system (ISTS) among RLDCs, POWERGRID, CTUIL and CEA held in Virtual Mode on
05.04.2023.

Meeting started with opening remarks from Sr. GM (CTUIL). He welcomed all the participants
in communication planning meeting for deliberating the planning aspects common to all regions
for which the agenda has been circulated.

List of participants is attached at Annexure-I.

1) Dual reporting of RTU, PMU, VOIP, AGC etc applications on dual channel to
RLDC and Back up RLDC.

Presently, all the data channels and voice channels are reporting in main and backup
mode with a main channel to RLDC and protection channel to Backup RLDC. It is
suggested by ERLDC &WRLDC that for increase of redundancy in the system both main
and protection channels should report to RLDCs as well as back up to RLDCs in dual
mode considering the criticality of real time grid operations by the ERLDC.
Deliberation:
NRLDC stated that as per communication regulation/IEGC dual channel reporting for all
communication applications from each ISTS station is required for both main and back
up RLDCs. This requirement has also been conveyed by ED, NLDC to ED, GA & C vide
letter dtd.16.03.2020
It is stated that present channel configuration operational at different RLDCs for main
and back up CC respectively is as follows:
a) NRLDC:1+1 & 2+1(for few stations)
b) SRLDC:1+1
c) WRLDC:2+1
d) ERLDC:1+1
e) NERLDC:1+1
POWERGRID stated that they are designing the ISTS Communication system with 1+1
channel configuration i.e one channel for main and the other for back up.
CTUIL finally stated that NRLDC/CEA shall suggest the requirement of channel/s for
each communication application based on the available communication
regulation/standards etc.
CEA/NRLDC agreed for the same and shall provide the information in this regard within
a week.
2) Frequent failure of VOIP exchange/ voice communication at ERLDC

Page 1 of 6
ERLDC representative informed in the 12th TeST meeting that for last few months it has
been observed that VOIP exchange at ERLDC was down around 6 to 7 times in odd
hours and restoration of the same took long hours. ERLDC suggested that an additional
voice communication channel need to be configured and integrated with NLDC VOIP
exchange from all ISTS and SLDC in 1+1 mode configuration with NLDC /ERLDC.

ERPC suggested that a standard format regarding backup of communication equipment

and their configuration at SLDC/ERLDC/NLDCs etc shall be evolved as per
requirement.
Deliberation:
ERLDC stated that as of now the present system is running smoothly but the new VOIP
system may be planned in 1+1 mode configuration.
POWERGRID stated that for the present VOIP system, AMC extension for one year is
being taken up. They also informed that this issue will affect multiple regions & utilities,
as OEM of PABX has expressed its inability in extending further AMC support for the
existing systems due to old version. Further, they also stated that upgradation of VOIP
system is required for maintaining it for another five years. POWERGRID requests
CTUIL & Grid-India to take advance action for planning of upgradation or replacement
of PABX system for all utilities. In this regard, POWERGRID has provided letter from
OEM which is attached at Annexure II.
CTUIL suggested that POWERGRID shall convene a meeting with POSOCO and
CTUIL along with OEM for discussing the upgradation features of PABX.
CTUIL stated that many TSPs have also requested for their requirement of voice
connectivity as stated in the agenda at Sr. no. 6 which was taken up in NRPC and yet
to be decided. This aspect may be also taken up while deliberating for upgradation of
VOIP system by POWERGRID.
3) Unified approach for IP addressing and proper documentation of
communication system of ISTS and STU network:
All the applications like RTU, VOIP, PMU, AMRs, Firewalls, Data Center equipment etc
are going to use TCP/ IP model (some of applications already using) architecture
including associated communication system gradually. In such scenario, unified IP
addressing scheme is very much required for all the users of inter connected system for
avoiding IP conflicts and ensure proper maintenance of network.
Deliberation:
Grid-India stated that a uniform IP addressing scheme for ISTS and STU communication
assets needs to be prepared to avoid IP conflicts, which have occurred in the past.

Page 2 of 6
At present, IP addresses for SCADA, AGC & PMU assets are being allotted by GRID
INDIA for all ISTS TSPs,ISGS,RE generators etc where as for voice communication
assets i.e exchange etc. POWERGRID is doing the same for all ISTS TSPs and STU
control centres. CTUIL requested CEA to give their inputs for the same.
CTUIL stated that the uniform IP addressing scheme shall be taken up by Grid-India for
all assets stated above.
POWERGRID agreed to share IP address details with GRID INDIA for formulating the
addressing scheme.
CTUIL further suggested that the agenda may be put up in TeST meeting forum by Grid-
India.
4) UNMS Console at RLDCs:
ERLDC & NRLDC requested the console for monitoring of ISTS Communication
Network. Because, without this console it would not be possible to monitor the network
by RLDC.
POWERGRID informed in 3rd Communication Planning Meeting (CPM) that as of now
provision of console at RLDCs is not in the scope of project.
Deliberation:
POWERGRID informed that UNMS project is not having provisions for consoles at
RLDCs & NLDC. They stated that amendment in contract after RPC/NCT approval (as
applicable) may be done for requirement of console at RLDCs and CTUIL. Approval on
said requirement may be given to POWERGRID before June to incorporate through
amendment under the awarded packages. POWERGRID also agreed to provide cost
estimate for provisioning of console at RLDCs and CTUIL before TCC/RPC.
CTUIL stated that different regional LDCs may give their agenda for requisition of
separate console so that it may be taken up in respective regional TeST meeting and
subsequently approval of RPC/NCT.
5. Redundancy philosophy in case of availability of only one transmission line
from one ISTS/ISGS station to the DCP:
In many cases, especially in the case of terminal nodes, it is observed that they are
connected to only one transmission line and protection path via alternate OPGW on
separate transmission line is not feasible. In this scenario, for providing protection path
following options may be explored:
a) OPGW on same transmission line on second peak.

Page 3 of 6
 b) VSAT
c) Lease line
Deliberation:
POWERGRID expressed concerns on “Communication Availability” in view of OPGW
on same tower on second peak, VSAT & leased line. POWERGRID requests CTUIL &
Grid-India to clarify on the communication availability in case both OPGW outages occur
(same tower having two OPGWs or OPGW-ADSS) & in case downtime of VSAT due to
weather conditions.
Grid-India replied that NPC has already released the Communication Availability
criterion & POWERGRID’s concerns will be considered at the time of planning.
Further, Grid-India (ERLDC) suggested that VSAT or leased line both being third party
networks are not recommended due to the following considerations:
1. Cyber security issue.
2. Monitoring of VSAT link at the service provider’s hub only.
3. Latency issues.
CTUIL stated that for such cases,OPGW on second peak of same transmission line is
sufficient as a redundant path. Further,ADSS may be opted for where second peak for
the same transmission line is not available.
6. Voice connectivity to TSPs control centre with Grid-India control centres:
Some TSPs have requested for such requirement for their upcoming control centres in
NCR. They have stated that from these control centres they will monitor their ISTS
assets throughout the country.
Deliberation:
Deliberation for agenda Sr. no. 2 may be referred.
7. Updation of ISTS communication map:(agenda by NRLDC)
NRLDC stated that updated map of ISTS communication system is required for proper
monitoring and supervision of communication system.
Deliberation:
CTUIL agreed to update the ISTS communication system map and share it with GRID
INDIA. CTUIL also stated that ISTS links in the ongoing projects under NERPSIP and
Comprehensive scheme can only be updated in map on receipts of inputs by
NERLDC/POWERGRID.
NERLDC agreed to provide the inputs within one week.
8. Redundant fiber connectivity to ERLDC and SLDCs (agenda by ERLDC):

Page 4 of 6
ERLDC requested CTUIL to plan for redundant fiber connectivity to SLDCs and ERLDC.
Further, such connectivity are also required in other regions also.
Deliberation:
CTUIL stated that planning of redundant fiber path connectivity of various SLDCs of ER
with ERLDC shall be taken up by CTUIL in regular communication planning meetings
after receiving inputs of such links by ERLDC. Moreover, other regions shall also provide
these inputs to be taken up in communication planning meeting of their regions.

Meeting ended with a vote of thanks from CTUIL.

Page 5 of 6
 Annexure-I
The list of participants is listed below:

CEA
Ms Prium Srivastava D.Dir

CTUIL
Sh H.S. Kaushal Sr.GM
Sh S.K Gupta Sr. DGM
Sh T P Verma Ch. Mgr
Sh Kaushal Suman Manager

POWERGRID
Ms Shyama Kumari DGM
Sh Sundeep Gupta Ch. Manager

NLDC
Sh Harish Kr Rathour GM

SRLDC
Sh M.K Ramesh CGM
Sh Abdullah Siddique Ch. Mgr
Sh Sudeep. M Mgr

ERLDC
Sh L Muralikrishna Sr.DGM
Sh D. Biswas Sr.DGM
Sh B. Mondal Mgr

WRLDC
Sh M M Mehendale CGM
Sh Sanjeev Chandrakar GM

NERLDC
Sh S P Burnwal Sr.GM
Sh Akhil Singhal DGM
Sh Sakaldeep Asst. Mgr
Sh Pouminlal Dongel Engr

NRLDC
Sh M M Hassan CGM
Sh Ankur Gulati Ch. Mgr

Page 6 of 6
 Annexure II

To, Date-09-03-23
Chief Manager (NR-ULDC)

POWERGRID

RHQ, NRTS-I, Faridabad

Ref: Upgradation/Extension of AMC for EPABX System installed under Hot Line
Speech Communication System (Alcatel Lucent)

Name of work: PROCUREMENT OF IP Based EPABX System.

Dear Sir,

With reference to mentioned subject we would like to mention that EPABX system which
has been installed in 2016-17 under mentioned project has older version only i.e. 11.0.

At present 100.1 version is available and all new hardware which is available will be
supportable to new version only.

So to continue with Comprehensive AMC we need to first upgrade/migrate the system

with the latest software version then we can continue for AMC.

We here by also confirm that post upgration we can support for further minimum 5 years.

Please suggest how can we proceed.

Sincerely yours,
for ALE India Pvt. Limited

Authorised Signatory
Name: Mukesh Kumar
Designation: Deputy General Manager
E-mail Id-Mukesh.kumar-sharma@al-enterprise.com

ALE India Private Limited (Formerly known as “Alcatel Lucent Enterprise India Private Limited”)
CIN: U64100KA2014PTC096578
Regd. & Corp Off: Brigade Magnum, Unit No. G01, ‘B Wing’ Amruthahalli, Kodigehalli Post, Bangalore- 560092,
Karnataka, India. Telephone number:+91-80-67696100
www.enterprise.alcatel-lucent.com
 Annexure-XVIIb

Minutes of the Meeting(Virtual mode) held on 09.05.2023 (Tuesday)regarding

dual reporting of RTU, PMU, VOIP, AGC etc. applications
A meeting on the subject was held on 09.05.23 at 11:00 AM with participants from
CEA, RLDCs, CTUIL, Grid-India, and POWERGRID. List of the participants is
enclosed at Annexure-I. 2. At the outset Sr. .DGM (CTU) welcomed the participants
and explained the agenda to all the participants. He requested all the participants to
contribute their valuable suggestion for agenda to reach at some conclusion.
Agenda: Dual reporting of RTU, PMU, VOIP, AGC etc. applications on 2+2
channel to main RLDC and Backup RLDC

Presently, one data channel and one voice channel are routed for reporting to main
RLDC and similarly one data & one Voice channel is reporting at backup RLDC.

It is proposed by GRID INDIA that to increase of the redundancy in the system at least
two data channels and two voice channels shall be routed for reporting to main RLDC
and another two data & two Voice channels shall report at backup RLDC.

A detailed deliberation in meeting dated 05/04/23 was done among RLDCs,

POWERGRID, CEA for evolving a common planning philosophy for all regions.

In the meeting GRID INDIA stated that as per communication regulation 2017/IEGC
dual channel reporting for all communication applications from each ISTS station is
required for both main and back up RLDCs. This requirement has also been conveyed
by ED, NLDC to ED, GA & C vide letter dtd.16.03.2020

It was stated in the meeting that present channel configuration operational at different
RLDCs for main and back up CC respectively is as follows:

a) NRLDC:1+1 & 2+1(for few stations)

b) SRLDC:1+1

c) WRLDC:2+1

d) ERLDC:1+1

e) NERLDC:1+1

POWERGRID stated that they are designing the ISTS Communication system with
1+1 channel configuration i.e. one channel for main RLDC and one channel for back
up RLDC.
However, CEA recommended as follows: Manual of Communication Planning in
Power System Operation clause 4.1.2 states:- “To ensure redundancy with route
diversity, each communication channel (working path) planned for the Users shall be
provided with alternate channel (protection path) in different routes, i.e., the working
path and protection path should be resource disjoint. For last mile connectivity to load
dispatch center(s), additional redundancy in different route may be considered. In case
of failure of the working path, the protection path shall be available for the required
communication services.”
Therefore, dual redundancy may be planned for both main and back-up load dispatch
centers.
At present following services are working on ISTS communication network:
i. SCADA
ii. PMU
iii. Tele protection
iv. Telecontrol
v. AGC
vi. Voice
vii. Automated Metering Application
viii. Telemetering
ix. Video conferencing
x. ICCP (between control canters)
xi. PDC
xii. PDC to PDC
xiii. Supervision of communications System
xiv. Video Surveillance
xv. Data Sync between MCC & BCC
The above applications need to be deliberated for dual redundancy requirement.
POWERGRID shall implement this redundancy for both main and backup Regional
load dispatch center(s) in all the regions wherever possible with the existing resources
in coordination with GRID INDIA.
In case of any additional requirement for implementation of redundancy POWERGRID
may update the details region wise i.e. availability of SAS gateway ports, spare
ethernet ports in existing FOTE, new FOTE if any etc. . POWERGRID shall quantify
these requirements along with tentative costs on Regional basis.
The action to be taken up by TSPs, IPPs, ISTS, ISGS besides POWERGRID also
needs to be discussed.

Deliberations: CGM(SRLDC) explained that Main and Backup control centre is old
terminology and now Main-I &Main-II control centre terminology is being used and at
each control centre one main & one backup channel is required. Grid India(NRLDC)
explained that at present data is being transmitted to respective main & Backup
RLDCs using 101 protocol through terminal server/DCPC for old RTUs and by using
104 protocol for SAS. Grid India agreed to share this detail in a week time. Further,
POWERGRID informed that RTUs are being replaced with SAS (104 PROTOCOL) as
soon as their life is completed. POWERGRID shall share the plan for replacement of
RTUs communicating on 101 Protocol.
POWERGRID queried that in CEA planning manual, only route redundancy is
mentioned and no where port redundancy is stated. Hence it needs to be clarified
whether port level redundancy is also required. CEA clarified that path should be
resource disjoint and so both path and ports should be resource disjoint.
POWERGRID (NR-ULDC), stated that there is constraint of ports for dual redundancy
of SCADA data in the RTUs procured under sub-station package and agreed for
upgradation of same subject to approval. POWERGRID further clarified that RTUs
with sufficient ports for dual redundancy are being planned recently as requested by
ED(NLDC) -GRID INDIA vide letter dated 16.03.2020.
At present PMU data is reporting to single location i.e. Main RLDC as per current
planning under URTDSM project. Grid India further stated that PMU data is transmitted
on dual channel through switch to main RLDC. Grid India require multi ports at PMU
for dual redundancy. Further redundant communication between SLDC PDC to RLDC
PDC, RLDC PDC to Main/backup NLDC PDC shall also be required.
Tele protection & Telecontrol are operated by TSPs and should be in dual redundancy.
For AGC services dual redundancy is already considered & being implemented by
TSPs . Dual channels to Main and Backup NLDC are required for AGC.
For Voice dual redundancy is also required. For the same, exchange to exchange dual
redundancy shall be planned. Exchanges are placed at all SLDCs &RLDCs. At present
Substation to Exchange link level protection is already available.
For AMR dual redundancy is also required. At present single channel is reporting to
RLDC. For video conferencing Grid India is requested to justify the requirement of
dual redundancy as per industry practice as mentioned in ‘Manual For Communication
Planning’ as suggested by CEA.
For ICCP dual redundancy is required for main RLDC to Backup RLDC, Main RLDC
to main SLDC, Main RLDC to backup SLDC, Backup RLDC to Main SLDC, Backup
RLDC to backup SLDC as planned under new SCADA system.
For PDC to PDC dual redundancy is also required. CTU requested Grid India to share
the architecture of new SCADA,PDC communication, ICCP.
Supervision of communication channels & Video Surveillance are not used by Grid
India. However, TSPs/ CTU may plan as per their requirement.
For data sync dual redundancy between MCC and BCC is also required.
ERLDC, Grid India suggested that planning for terminal equipment(SDH/PDH)at dual
redundancy is also required. However, it is suggested that dual redundancy of terminal
equipment may be planned for critical locations such as AGC, SPOFs(Single point of
failures).

As per discussion, following applications are summarised below for dual redundancy
up to existing and upcoming control centres of Grid India.
i. SCADA
ii. PMU
iii. AGC
iv. Voice
v. Automated Metering Application
vi. ICCP (between control canters)
vii. PDC to PDC
viii. Data Sync between MCC & BCC

Conclusion
1. Grid India shall share the data for all the RTUs/SAS , their connectivity
type(single or dual redundancy) & all other relevant data for all the TSPs(IPPs,
ISGS, TBCB,RTM etc.) within a week time.
2. POWERGRID shall analyse the existing system for dual redundancy and
implement the dual redundancy with existing resources wherever possible.
3. POWERGRID shall further state the additional requirements of
ports/cards/equipment etc. along with cost for implementation of dual
redundancy to above mentioned services on priority where dual redundancy
cannot be implemented because of resource constraints. Same shall be
discussed at respective RPC forum and shall be finally approved in NCT.
 Annexure-I
List of participants of the meeting
• CEA
1. Sh. Prateek Srivastava, Assistant Director, PCD
2. Sh. Akshay Dubey,
3. Ms. Priyam, Dy. Director, PSPA-I

• CTUIL
1. Sh. Shiv Kumar Gupta, Sr.DGM, CTUIL
2. Sh. Tej Prakash Verma, Ch.Mgr., CTUIL
3. Kalpana Shukla,DGM, CTUIL
4. Kaushal Suman, Manager, CTUIL

• Powergrid
1. Sh. Ajaya Kumar P, Sr.GM, ULDC
2. Sh. Satish Kr Sahare, GM, ULDC
3. Smt. Shyama Kumari, DGM, GA&C
4. Sh. Kapil Gupta, DGM, GA&C
5. Sh. Mahesh M, Ch. Mgr, ULDC
6. Sh. Narendra Kumar Meena, Ch. Mgr. ULDC
7. Sh. Santanu Rudrapal, Ch. Mgr, ULDC
8. Sh. Vishal Badlas, Mgr, GA&C
9. Sh. Kashif Bakht Muhammad Nabi, Dy. Mgr, ULDC
10. Sh. Ashish Kumar Das, Asst Mgr, ULDC

• GRID- India
1. Sh. MK Ramesh, CGM, SRLDC
2. Sh. Harish Kumar Rathour, GM, NLDC
3. Sh. Sanjeev, GM, WRLDC
4. Sh. L. Murlikrishna, Sr. DGM
5. Sh. Ankur Gulati, DGM, NRLDC
6. Sh. Sakal Deep, Engineer, NERLDC
7. Sh. Koti Naveen
8. Sh. Ananthakrishnan
9. Sh. Rakesh
10. Sh. Sudeep M
11. Bijender Singh Chhoer
12. P Doungel
RNOD (Recoded Notes of the discussion) of the virtual meeting held on 27.06.2023 (Tuesday)
regarding dual redundancy of RTU, PMU, VOIP, AGC etc.

A meeting on cited subject was held on 27.06.2023 at 10:30 A.M. with the participants from CEA,
RLDCs, CTUIL, GRID-India and POWERGRID. The list of the participants is enclosed at
Annexure-I. At the outset Sr. GM (CTUIL) welcomed the participants and stated the requirement
of two channels each at main and backup control centres, already discussed in the meeting held on
09.05.2023 and confirmed by PCD(CEA) subsequently. In view of this CTU requested the
participants to provide their valuable views/suggestions for each application for the said
redundancy.

Deliberation:

CTU stated that at present one data channel and one voice channel are routed for reporting to main
RLDC and similarly one data & one voice channel is reporting at backup RLDC. However, during
the meeting held on 09.05.2023, GRID-India requested for at least two data channels and two voice
channels for reporting to each RLDC i.e. main RLDC and backup RLDC, to increase the
redundancy in the system.

Further CTU stated to deliberate on all the data and voice applications being used from stations to
control centres (CC) and among CCs viz SCADA,PMU, AGC,VOIP etc.. CEA suggested that the
redundancy shall be developed in a phased manner and the constraints on the existing
communication network shall be explicitly reviewed and taken up accordingly.

Detailed deliberations were held among GRID-INDIA-RLDCs, POWERGRID, CEA, CTU for the
same and ISTS communication system was proposed for different services with redundancy:

1. SCADA

2. PMU

3. AGC

4. VOIP

5. Automated Metering Application(AMR)

6. ICCP (Between control centers)

7. PDC to PDC

8. Data sync between MCC & BCC

GRID-INDIA has submitted the data regarding present status of redundancy of these services
which is enclosed as Annexure-I. POWERGRID has also submitted the data of utilization of
optical fiber network for some links of Eastern region which is enclosed as Annexure-II. CTU
again requested POWERGRID to provide requisite data for the implementation of said redundancy
scheme.

It was also felt to analyze the enhancement required for the above mentioned 8 services on 2+2
redundancy as discussed below:

1. SCADA :- Currently SCADA is reporting through 1+1/2+1/2+2/1+0 (radial) channel in

different regions. For 2+2 redundancy of SCADA data, it requires extra ethernet ports at
RTU, SAS Gateway & FOTE along with suitable bandwidth in optical fiber network. CTU
stated that POWERGRID shall provide data of utilized and spare ethernet ports for existing
RTUs, SAS Gateways and FOTE and shall also asses the data for additional requirement
of the said redundancy. POWERGRID agreed the same.
2. PMU :- POWERGRID stated that presently one port of central sector PMUs is split into
two channels at MUX (SDH) level from where onwards one channel reports to NTAMC
(PG) and other reports to PDC (RLDC). GRID-India stated that as at present there is no
plan of backup PDC, hence PMU data may be sent to PDC at RLDC in 1+1 mode only.
Accordingly, one additional channel is required from PMUs to RLDCs. POWERGRID is
requested to check availability of additional port on PMU and FOTE along with bandwidth
requirement for configuration of additional backup channel to RLDC. POWERGRID
agreed the same.
3. AGC :- GRID-India-NLDC stated that currently 2 channels are reporting from generators
up to HMI of the station and there after through fibre optic network to NLDC Main Control
Centre (MCC). GRID-India explained that a separate RTU is provided to integrate the
generator data and route it further through the existing FOTE. This is in addition to existing
RTU/SAS Gateway reporting to RLDCs.. As per redundancy requirements of control
centre, 2 additional channels for AGC from generator station (in addition to the SCADA
data) are required for data reporting to Backup Control Centre (BCC). GRID-INDIA also
 stated that AGC signal to generator is being planned from RLDC in future. POWERGRID
is requested to check availability of ports on RTU (both SCADA and Generation), SAS
Gateway of AGC system and FOTE for implementation of same. POWERGRID agreed
the same.
4. VOIP :- POWERGRID stated that currently VOIP is communicating through single
channel only. GRID-India stated that they require redundancy on Port level and additional
port shall be required at VOIP phone, exchange & FOTE. As present VOIP exchange has
completed its life, it is suggested that requisite features for VOIP phones & exchange shall
be included during system upgradation/ replacement. POWERGRID agreed to provide
relevant data for the same.
5. AMR :- GRID-India stated that new AMR architecture is in planning phase and they will
provide required inputs after looking in architecture.
6. ICCP :- GRID-India stated that currently ICCP (Between NLDC, RLDC and SLDC) is
working on 2 communication channels for main-to-main control center and 2
communication channels for backup to backup control center only. For redundancy,
GRID-India requires 4 extra channels, 2 channels for main RLDC to backup SLDC
communication and 2 channels for backup RLDC to main SLDC communication.
POWERGRID is requested to provide additional requirements (if any) for implementation
of same. POWERGRID agreed the same.
7. PDC to PDC :- GRID-India stated that at present ‘1’ channel is provided between
PDC(SLDCs) to PDC (RLDC), for redundancy in PDC(SLDCs) to PDC(RLDC)
communication additional 1 channel is required as discussed in PMU above.
8. Data Sync between MCC & BCC :- GRID-India stated that presently 1 channel is
working for data sync between Main Control Center and Backup Control Center i.e. main
SLDC to backup SLDC, main RLDC to backup RLDC, main NLDC to backup NLDC,
further it is required to provide 1 additional channel for redundancy.

As per above discussion POWERGRID is requested to provide the requisite data for
implementation of redundancy of services as discussed above within 21 days. POWERGRID
agreed for the same. Meeting ended after vote of thanks by SR.GM(CTU).
 List of participants of the meeting

• CEA
1. Sh. Prateek Srivastava, Assistant Director, PCD
2. Ms. Priyam, Dy. Director, PSPA-I

• CTUIL
1. Sh. H.S. Kaushal, CGM, CTUIL
2. Sh. Shiv Kumar Gupta, Sr.DGM, CTUIL
3. Sh. Tej Prakash Verma, Ch.Mgr., CTUIL
4. Sh. Divesh Kamdar, AET, CTUIL

• POWERGRID
1. Sh. Satish Kr Sahare, GM, ULDC
2. Smt. Shyama Kumari, DGM, GA&C
3. Sh. Kapil Gupta, DGM, GA&C
4. Sh. Mangesh Shriram Bansod, DGM, IT
5. Sh. Sundeep Kumar Gupta, Ch. Mgr, GA&C
6. Sh. Narendra Kumar Meena, Ch. Mgr. ULDC
7. Sh. Santanu Rudrapal, Ch. Mgr, ULDC
8. Sh. Vishal Badlas, Mgr, GA&C
9. Sh. Hemanth Kumar, Asst. Mgr, ULDC

• GRID- India
1. Sh. Harish Kumar Rathour, GM, NLDC
2. Sh. Aukur Gulati, Ch. Mgr, NRLDC
3. Sh. Sakal Deep, Engineer, NERLDC
4. Sh. Akhil Singhal, NERLDC
5. Sh. P. Doungel, NERLDC
6. Sh. Amba Prasad Tiwari, NERLDC
7. Sh. Mohneesh Rastogi, NLDC
8. Sh. Ganesh, SRLDC
9. Sh. Rakesh, SRLDC
10. Sh. Ashutosh Pagare
11. Sh. Koti Naveen, WRLDC
 Annexure-XVIII

Annexure-V
List of Substaions where SAS/RTU upgradation is required
Data reporting RLDC
Sr. No. Region Name of Substation through RTU/SAS GW
1 NR-I Ajmer 765/400kV SAS GW
2 NR-I Bahadurgarh 400/220kV RTU
3 NR-I Baghpat 400/220kV GIS SAS GW
4 NR-I Bassi 400/220kV RTU
5 NR-I Bhadla 765/400/220kV RTU
6 NR-I Bhadla-II 765/400/220kV SAS GW
7 NR-I Bhinmal 400/220kV SAS GW
8 NR-I Bhiwadi 400/220kV RTU
9 NR-I Bhiwadi HVDC SAS GW
10 NR-I Bhiwani 765/400/220kV SAS GW
11 NR-I Bikaner 765/400/220kV SAS GW
12 NR-I Dehradun 400/220kV SAS GW
13 NR-I Fatehgarh-II 765/400/220kV SAS GW
14 NR-I Jaipur(S) 400/220kV SAS GW
15 NR-I Jhatikara 765/400kV SAS GW
16 NR-I Jind 400/220kV SAS GW
17 NR-I Kankroli 400/220kV SAS GW
18 NR-I Kotputli 400/220kV RTU
19 NR-I Koteshwar 765/400kV GIS SAS GW
20 NR-I Kurukshetra 400/220kV GIS SAS GW
21 NR-I Kurukshetra HVDC SAS GW
22 NR-I Manesar 400/220kV GIS SAS GW
23 NR-I Meerut 765/400/220kV SAS GW
24 NR-I Neemrana 400/220kV SAS GW
25 NR-I Sikar 400/220kV SAS GW
26 NR-I Sonipat 400/220kV SAS GW
27 NR-I Khetri 765/400kV SAS GW
28 NR-I Bikaner-II 400/220kV SAS GW
29 NR2 Chamba ABB SAS
30 NR2 New Wanpoh ABB SAS
31 NR2 Panchkulla ABB SAS
32 NR2 Fatehabad ABB SAS
33 NR2 Nalagarh GE SAS
34 NR2 LEH GE SAS
35 NR2 Kargil GE SAS
36 NR2 Drass GE SAS
37 NR2 Khalsti GE SAS
38 NR2 Samba GE SAS
39 NR2 Amritsar GE SAS
40 NR2 Patiala GE SAS
41 NR2 Ludhiana GE SAS
42 NR2 Moga 765 GE SAS
43 NR2 Malerkotla Siemens
44 NR2 Kalaamb Siemens
45 NR2 Banala Siemens SAS
46 NR2 Hamirpur Siemens SAS
 List of Substaions where SAS/RTU upgradation is required
Data reporting RLDC
Sr. No. Region Name of Substation through RTU/SAS GW
47 NR2 Jalandhar Synergee RTU
48 NR-III BALLIA HVAC SAS GW
49 NR-III BALLIA HVDC SAS GW
50 NR-III BAREILLY 765KV SAS GW
51 NR-III FATEHPUR SAS GW
52 NR-III FEROZABAD SAS GW
53 NR-III KANPUR GIS SAS GW
54 NR-III LUCKNOW 400KV RTU
55 NR-III LUCKNOW 765KV SAS GW
56 NR-III ORAI SAS GW
57 NR-III RAEBARELI RTU
58 NR-III SHAHJAHANPUR SAS GW
59 NR-III SITARGANJ SAS GW
60 NR-III SOHAWAL SAS GW
61 NR-III VARANASI SAS GW
62 NR-III VINDHYACHAL SAS GW
63 NR-III JAULJIBI SAS GW
64 NR-III RAMPUR SAS GW
 Annexure-XIX

State utility wise link details where fibre sharing is required are given below:
UPPTCL:

A. Links/Paths where fibre Sharing is required for NAPP (NPCIL):

1. Simbhavali (UP) - Shatabdi Nagar (UP)

2. Shatabdi Nagar (UP) - Modipuram (UP)-having ISTS FOTE

B. Links/Paths where fibre Sharing is required for Saharanpur (PG):

1. Sahararnpur (PG)- Deoband (UP)

2. Deoband (UP)- Saharanpur (UP)
3. Saharanpur (UP) -Nanauta (UP)
4. Nanauta (UP)-Shamli (UP)
5. Shamli (UP) -Muradnagar (UP)-having ISTS FOTE

PTCUL:

A. Links/Paths where fibre Sharing is required for Pithoragarh (PG):

1. Pithoragarh (PG) – Pithoragarh (PTCUL)

2. Pithoragarh (PTCUL) – Almora (PTCUL)
3. Almora (PTCUL) -Bhawoli (PTCUL)
4. Bhawoli (PTCUL) -Haldwani (PTCUL)
5. Haldwani (220kV) (PTCUL) Kamalwaganj (PTCUL)
6. 220kV Kamalwaganj (PTCUL) - Pantnagar (PTCUL)
7. Pantnagar (400kV) (PTCUL) Kashipur (PTCUL)

B. Links/Paths where fibre Sharing is required for Sitarganj (PG):

1. Sitarganj(PG) - Sitarganj(PTCUL)
2. Sitarganj(PTCUL) - Kiccha(PTCUL)
3. Kiccha(PTCUL) - Rudrapur(PTCUL)
4. Rudrapur (PTCUL) - Pantnagar (PTCUL)
5. Pantnagar (PTCUL) – Kashipur (PTCUL)

JKPTCL:

Links/Paths where fibre Sharing is required for Alusteng(PG), Drass(PG),

Kargil(PG), Khalasti(PG), Leh(PG):

1. Alusteng (PG) - Zainakote (JKPTCL)

2. Zainakote (JKPTCL) - Wagoora (PG)
 Annexure-XX

Government of India

Ministry of Power

Northern Regional Power Committee

lI'iW''1'1 /10S/04/2019/ 9 b:J 1- ;11 7 5 03 ffidkl( , 2019

rd
No. NRPC/ OPR/10S/04/2019/ Dated: 03 September, 2019

Members of TeST Sub-Committee (As per List)

<ft 15 <ff
I 'fiT 'fl14'fd
th
Subject: 15 meeting of TeST Sub-Committee - Minutes.

,
Sir,

'3m <ft <ft 15 <IT 07 2019 <f;T

'3m <m, 'f>cClIf{lIl 'l{ if dll<iiRld <ft.,-t I
if; 'f>P11d ;fiT 31T'l<ft if; @l

15th TeST Sub-Committee meeting of NRPC was held on 07 th August, 2019

at NRPC, Conference Hall, Katwaria Sarai, New Delhi. A copy of the minutes of the
meeting is enclosed herewith for favour of information and necessary action.

Yours faithfully,,

(31R.<ft.
(R.P. Pradhan)

Superintending Engineer
 15th meeting of TeST (07.08.2019)-Minutes

substations of BBMB, so as to rectify the discrepancy in the phasor mismatch

being observed in the PMUs installed under URTDSM Scheme.
POWERGRID agreed that they would take up the matter.

6. OTHER AGENDA

6.1 Establishment of State-of-the-Art Unified Centralized Network

Management System U-NMS for ISTS and State Utility Communication
Network. (Agenda by POWERGRID)
POWERGRID briefed the committee about the CERC notified Communication
Regulation which envisages Centralized Supervision System for ISTS
Communication. As per the regulation clause no 7.2 (vii): “CTU shall be the
Nodal Agency for supervision of communication system in respect of inter-State
communication system and will implement centralized supervision for quick
fault detection and restoration.”
POWERGRID informed that in line with regulation, provisions of Centralized
NMS and Centralized Monitoring by integrating its NMS with other users NMS,
has been kept in the documents of Technical standard & Manual of
Communication Planning Criteria being finalized by CEA. In addition to this
guideline on availability of Communication system for ISTS has been submitted
to CERC by CEA for which centralized NMS/OSS is considered essential.
POWERGRID made a detailed presentation (a copy of the same attached at
Annexure-6.1) on Unified Network Management System (U-NMS) Project to
be implemented for managing ISTS Communication System at Regional and
National level. Presentation covered various technical aspects of U-NMS,
configuration at Regional and National level, integration of existing NMSs and
Network Elements not having visibility in NMSs etc.
POWERGRID further added that that U-NMS configuration proposed at
Regional and National levels shall provide graphical representation of topology
of nodes and links, auto discovery and rediscovery of Network Elements and
sub-systems, Facility of end to end provisioning of bandwidth centrally, Fast
fault resolution and reduced restoration times, Proactive maintenance and
Customer support and working out channel availability etc. apart from analytics
for predictive maintenance etc.
POWERGRID informed that U-NMS Project is conceived to facilitate
Centralized Supervision for ISTS Communication in compliance to CERC
Regulation for Communication System notified in May’17 as present NMSs do
not have visibility of entire network and are not capable to support the
requirements envisaged for ISTS Communication in CERC Regulation.

23
 15th meeting of TeST (07.08.2019)-Minutes

Proposed U-NMS configuration at regional level shall also consider integration

of NMSs of State Communication Network to facilitate STUs to monitor and
maintain their network with the help of Work Station provided at their location
having direct access of Regional Server.
POWERGRID further stated that U-NMS Project implementation Schedule is
considered as 24 months and estimated cost for National and Regional U-NMS
is Rs. 120 Cr (Rs. 99.93 Cr for each Regional and Rs. 20Crs for National U-
NMS, considering 100Crs for National level covering all 5 Regions i.e. NR, ER,
NER, WR and SR) excluding AMC cost which is estimated as Rs. 2.6 Cr for 6
years after Warrantee period. However, the actual cost shall be discovered only
after implementation. The Tariff for the investment made is to be shared by all
constituents as per CERC notification. The scheme shall become part of
existing Commercial Agreement signed for ULDC Project.
Members deliberated on U-NMS proposal. The need of implementation of U-
NMS at Regional and National level was agreed by all members considering
provisions of Communication Regulation.
Member Secretary, NRPC requested utilities for their technical comments. He
further stated that utilities can also send their comments, if any, via email at
sec-nrpc@nic.in by 31st August, 2019.
NRLDC enquired regarding the space availability for U-NMS installation.
POWERGRID stated that they would install U-NMS in their premises and
informed that CTU shall manage the system after installation.
Sub-Committee agreed for in-principal technical approval of the scheme and
recommended for further deliberations in the next TCC/NRPC meetings.

6.2 Mapping of analogue data and digital status of SPS operation related
information in SCADA (Agenda by NRLDC)
NRLDC requested all concerned to integrate SPS signals in RTU so that same
can be visualized in SCADA. Further it was SPS signals originating from DTPC
to various sub-stations shall be integrated by POWERGRID. Further signals
shall also be wired and integrated at receiving end by respective utility.
NRLDC informed that as per the decision taken in various meeting, all mapping
of SPS signal for new SPS should be done by the agency who is responsible
for SPS installation.
Further NRLDC requested all concerned utilities to integrate SPS signals on
priority basis.
All utilities informed that integration work is in process and will be integrated at
the earliest.

24
 43rd TCC & 46thNRPC Meetings (23rd and 24th September, 2019) – Minutes

B.15.5 Punjab conveyed that after going through the minutes of the last TeST
sub-committee meeting, it appears that the proposed scheme has been
recommended by TeST sub-committee without much deliberation. Also,
this project could be considered for PSDF funding as Punjab had also got
PSDF funding for similar type of state projects. Regarding less deliberation
in TeST, MS, NRPC stated that state representation in meetings other
than TCC/NRPC has reduced to a level that in some states AE or AEE
participate against Chief Engineer, nominated member. Regarding PSDF
support, POWERGRID stated that PSDF support of 50% is for the state
sector, but for central sector no such provision is available in this scheme.
B.15.6 After detailed deliberations, it was decided that this agenda would be
again taken up in the next TeST meeting. PSTCL and RRVPNL informed
that they are ready to clear the scheme in 15 days if POWERGRID
deputes their engineer and they are convinced that while making scheme
due deligence has been given to use state network. States also agreed to
depute officer not below SE level in the meetings other then TCC/NRPC.

B.16 Establishment of State-of-the-Art Unified Centralized Network

Management System U-NMS for ISTS and State Utility Communication
Network

TCC Deliberations
B.16.1 POWERGRID informed that provisions of Centralized NMS and
Centralized Monitoring by integrating its NMS with other users NMS has
been kept in the draft Technical standard and Communication Planning
Criteria Manual of CEA. In addition to this, guideline on availability of
Communication system for ISTS has been submitted to CERC by CEA for
which centralized NMS/OSS is considered essential. MS, NRPC stated
that the scheme has been recommended by TeST sub-committee in its
15th meeting and same may deliberated in NRPC for approval.

NRPC Deliberations
B.16.2 POWERGRID stated that scheme has been discussed at length in last
meeting of TeST sub-committee wherein POWERGRID had made a
detailed presentation before the members. The estimated cost of Rs 600
Cr is for all regions.
B.16.3 Haryana stated that U-NMS is a necessary system because different make
of communication systems are to integrated at common plateform.
POWERGRID stated that in line with CERC’s regulations mentioning
communication system availability, the proposed U-NMS is also capable to
calculate the availability of the communication system besides providing
holistic view of network.
B.16.4 The Committee after detailed deliberation, approved the scheme.

20
Annexure-XXI
4.5 North Eastern Region Expansion Scheme-XXI Part-B (NERES-XXI Part-B)

4.5.1 The existing 132 kV Badarpur (POWERGRID) switching station was commissioned
in 1999 and shall be completing 25 years in service by 2024. POWERGRID, the
owner of the substation has informed that they are facing issues in O&M of the
switching station and to improve the reliability it would be prudent to upgrade the
switching station from single main and transfer bus scheme to double main transfer
bus scheme by converting from AIS to GIS.

4.5.2 The scheme was also discussed in the 23rd TCC & NERPC meetings held on 18th-19th
November 2022 wherein the subject upgradation was agreed to be carried out in
Green GIS.

4.5.3 Chairperson, CEA, opined that life of sub-stations is generally about 35 years and
hence, the reasons for replacement/upgradation of switching station after 25 years
needs to be ascertained.

4.5.4 After detailed deliberations, it was decided to review the scheme subsequently.

4.6 Implementation of Unified Network Management System (UNMS) in the Western

Region

4.6.1 Representative of CTUIL informed that Central Electricity Regulatory Commission

(Communication System for inter-State transmission of Electricity) Regulations 2017,
mentions that, CTU shall in due consideration of the planning criteria and guidelines
formulated by CEA be responsible for planning and coordination for development of
reliable National communication backbone for Inter-State Transmission System
(ISTS). CEA Technical Standards 2020 calls for centralized monitoring by integrating
its network management system with network management system of other users and
standalone network elements on regional and national basis. Further, CTUIL shall
implement centralized supervision for quick fault detection and restoration.

Accordingly, communication scheme i.e. Establishment of State-of Art Unified

Network Management System (U-NMS) for ISTS and State Utility Communication
System for all the Regions have been envisaged for five Regional systems and one
National system integrating all the regional ones; in main & backup configuration.
This will facilitate centralized supervision of ISTS as well as Intra-state
communication system at State level, Regional level and Inter-Regional
Communication system at national level.

CTUIL updated status for nationwide UNMS Scheme implementation being

undertaken by POWERGRID; UNMS for Northern, Eastern and Northeastern
Regions are scheduled for commissioning in year 2023/ 2024. And Southern Region
scheme approved in 13th NCT meeting in May’23 is under bidding stage.
4.6.2 WRPC has approved implementation of the WR-UNMS project in RTM mode in 47th
WRPC meeting held on 14th & 15th June 2023.

4.6.3 Representative of PCD Division, CEA, stated that a workstation console with
redundant connectivity would be required under UNMS-WR scheme at WRPC. It was
also suggested to include feature for Long, Medium & Short Term Planning for
preparing planning projections while including user configurable inputs such as
topology, congestion status, utility/ area wise, type of network, product life cycle,
sector growth etc. and provision for import of data in .xls or other similar forms for
consuming in preparing the planning projection for 2 years, 5 years, 10 years.

4.6.4 It was also discussed that UNMS workstation console with its associated hardware &
software along with redundant connectivity is required at all RPC locations for the
previously approved regional UNMS Scheme for NER, NR, ER and SR.

4.6.5 Chairman, NCT, started that central planning of the communication network for ISTS
and State system shall take the leverage from these Regional & National UNMS
having the details of both ISTS and State sector communication network. He also
emphasized that National UNMS system should be planned at the earliest to have a
holistic view of the network comprising of regional, intra-regional and intra state
network and this scheme shall have additional scope of Planning Software tool having
features as enlisted by representative of PCD Division.
He also emphasized that SOP for Centralized supervision & Maintenance of ISTS
Communication system should be finalized at the earliest while specifying the roles &
responsibilities of concerned entities/ agencies for smooth implementation of the
hierarchical UNMS Scheme situated in state, regional & national level.

4.6.6 After detailed deliberations, the followings were approved:

 WR UNMS scheme as per agenda along with additional scope listed below to be
implemented under RTM mode by POWERGRID.
a. Inclusion of Workstation Console and associated HW & SW along with
redundant communication link & AMC at WRPC location.
b. Additional feature of Planning Tool

 The National UNMS project proposal to be taken up at the earliest, as all regional
systems have been approved for implementation. The national UNMS scheme shall
have additional scope of Planning Software tool having features for Long, Medium
& Short Term Planning for preparing planning projections while including user
configurable inputs such as topology, congestion status, utility/ area wise, type of
network, product life cycle, sector growth etc and provision for import of data in
.xls or other similar forms for consuming in preparing the planning projection for 2
years, 5 years, 10 years., along with Workstation Console and associated
hardware/software with redundant connectivity at PCD Division, CEA.
  Additional scope for Supply, Installation & AMC for UNMS workstation console
with its associated hardware & software with redundant connectivity at all four
RPC locations for the previously approved regional UNMS Scheme for NER, NR,
ER and SR.

4.6.7 Summary of the WR UNMS scheme is as given below:

Sl.No. Name of the scheme and Estimated Cost Remarks
implementation timeframe (Rs. Crores)
1. Establishment of State-of Art Rs. 84* Crs. Approved to be
Unified Network Management (approx.) and 19.07 implemented under
System (U-NMS) for ISTS and Crs. AMC charges RTM mode by
for 7 years.
State Utility Communication POWERGRID
System for Western Region

Tentative Implementation
timeframe: 24 months from date of
allocation

4.6.8 Detailed scope of the scheme is as given below:

Sl. Scope of the scheme Estimated Cost
No. (Rs. Crs)
1. • Main & Back-up UNMS software and hardware along Rs. 84* Crs.
with required Application software including Video (approx.) and
Projection System (VPS), firewall and IDPS. 19.07 Crs. AMC
• Remote Workstation for SLDCs. charges for 7
• Video Projection System (VPS), Printer, furniture etc. at years.
main & back-up U-NMS location.
• Integration of existing NMS/NEs of ISTS and State Utility
in a region in the proposed UNMS.
• Integration of upcoming U-NMS for National & other
regions and upcoming NMS/NEs of ISTS and State Utility
in a region during implementation and AMC period of the
project.
• Operational support, training & maintenance for proposed
UNMS software and hardware.
• Auxiliary Power System for U-NMS system.
• Workstation Console along and other associated software
and hardware such as firewall, router, switch etc. at
WRPC, CTUIL HQ and WRLDC location
• Bandwidth connectivity & Its recurring charges for
WRPC & CTUIL HQ Office.
 Annexure-XXII

Reference: CC/HRD/NRPC/2023-24/Overseas Date:26 Feb 24

To,

The Executive Engineer (Protection),

Northern Regional Power Committee Secretariat,
New Delhi.

Kind Attention: Sh Reeturaj Pandey

Sub: Overseas Program on "International Best Practices in Energy Transition (With

study tour to Norway & Finland)" for NRPC constituents.

Dear Sir,

A. In reference to your request for the subject mentioned program, please find below our
offer. The details may be seen below.
1. Venue: PAL Manesar (Domestic portion), Norway & Finland (Overseas portion)
2. Duration: Domestic Portion:
i. One day domestic at PAL, Manesar
ii. Overseas portion including travel: Seven days.
3. Dates: around May to Sep 24 (All three batches) will be finalized after mutual
discussion.

B. The scope of services will be as mentioned below:

1. Tuition fees
2. Air fare economy class (Delhi to Oslo, Helsinki to Delhi),
3. Medical cum travel insurance
4. Visa
5. Airport transfers
6. Boarding & Lodging
7. Disbursal of per-diem,
8. Training kit including trolley bags & Blazer,
9. Tickets (if any) to official engagements (entry tickets to sight-seeing,
conferences etc.
10. Membership to ASCI alumni network.

C. Fee (including GST):

1. Fee for one batch upto 20 participants: INR 3,35,63,000.00
2. Per Participant fee for additional participants above 20: INR 16,78,150.00
3. Fee for three batches with total 60 participants: INR 10,06,89,000
D. Payment Terms:
1. 70% payment before the start of each batch based on proforma invoice
submitted by POWERGRID to NRPC.
2. 30% after the successful conduct of each batch and submission of GST invoice
by POWERGRID to NRPC.

केन्द्रीय कायाालय: "सौदामिनी", प्लॉट नंबर 2, सेक्टर -29, गुरुग्राि -122001, (हररयाणा) दूरभाष: 0124-2571700-719
Corporate Office: “Saudamini”, Plot No. 2, Sector-29, Gurugram-122001, (Haryana) Tel.: 0124-2571700-719
पंजीकृत कायाालय: बी -9, कुतुब इंस्टीट्यूशनल एररया, कटवाररया सराय, नई ददल्ली -110 016. दूरभाष: 011-26560112, 26560121, 26564812, 26564892, CIN: L40101DL1989GOI038121
Registered Office: B-9, Qutab Institutional Area, Katwaria Sarai, New Delhi-110 016. Tel: 011-26560112, 26560121, 26564812, 26564892, CIN : L40101DL1989GOI038121
Website: www.powergridindia.com
E. Validity: This offer will be valid for till 31.12.2024

Kindly acknowledge the offer and convey your acceptance.

Yours faithfully,
For and on behalf of
Power Grid Corporation of India Limited

Shafiqur Rahman
Chief Manager (HRD)
9599192365, shafiqur@powergrid.in

केन्द्रीय कायाालय: "सौदामिनी", प्लॉट नंबर 2, सेक्टर -29, गुरुग्राि -122001, (हररयाणा) दूरभाष: 0124-2571700-719
Corporate Office: “Saudamini”, Plot No. 2, Sector-29, Gurugram-122001, (Haryana) Tel.: 0124-2571700-719
पंजीकृत कायाालय: बी -9, कुतुब इंस्टीट्यूशनल एररया, कटवाररया सराय, नई ददल्ली -110 016. दूरभाष: 011-26560112, 26560121, 26564812, 26564892, CIN: L40101DL1989GOI038121
Registered Office: B-9, Qutab Institutional Area, Katwaria Sarai, New Delhi-110 016. Tel: 011-26560112, 26560121, 26564812, 26564892, CIN : L40101DL1989GOI038121
Website: www.powergridindia.com
 Annexure-XXIII

Capacity Building Programme on

“International Best Practices in Energy Transition”

for Constituents of Northern Regional Power Committee
(NRPC)

Proposal Submitted by Member Secretary on

behalf of Northern Regional Power Committee

March 2024
 Table of Content

Sl.No Chapter Page

1 About Northern Regional Power Committee 1

2 Summary of Proposal-Format A1 5

3 Detailed Proposal-Format A2 8

4 Summary of DPR-Format A3 13

5 Financial Implication of the Scheme-Format A4 16

6 Brief Derails of the Project Appraisal by 18

CTU/STU/RPC- Format A5
7 Affidavit –Format A6 19

8 Supplementary Information 20

1. ABOUT NORTHERN REGIONAL POWER COMMITTEE

• With an objective to facilitate integrated operation of power system in Northern
Region, Government of India, under the provision of Section 2, Subsection 55 of the
Electricity Act 2003 vide resolution F.No. 23/21/2021-R&R dated 3rd December 2021
(repealed resolution dated. 25.05.2005) published in the Gazette of India has
established the Northern Regional Power Committee comprising of states of Delhi,
Haryana, Himachal Pradesh, Punjab, Rajasthan, Uttaranchal and Uttar Pradesh and
the Union Territories of Chandigarh, Jammu & Kashmir and Ladakh.
• Manpower is posted by Central Electricity Authority (CEA).
• RPCs have been envisioned as self-financed. The expenditure of RPCs is met from
contribution collected from constituent members of region.
• Member Secretary is HoD of NRPC Secretariat and is convenor of RPC.

2. MEMBERS OF NRPC:
a.) Member (Grid Operation), Central Electricity Authority (CEA).

1
 b.) One representative each of Central Generating Companies, Central Transmission
Utility (CTU), Central Government owned Transmission Company, National Load
Despatch Centre (NLDC) and the Northern Regional Load Despatch Centre
(NRLDC).
c.) From each of the States in the region, the State Generating Company, State
Transmission Utility (STU), State Load Despatch Centre (SLDC), one of the State
owned distribution companies as nominated by the State Government and one
distribution company by alphabetical rotation out of the private distribution
companies functioning in the region.
d.) A representative nominated by the administration of the Union Territory concerned
out of the entities engaged in generation/ transmission/ distribution of electricity in
the Union Territory.
e.) A representative each of every generating company (other than central generating
companies or State Government owned generating companies) having more than
1000 MW installed capacity in the region.
f.) A representative of the generating companies having power plants in the region (not
covered in (b) to (e) above) by alphabetical rotation.
g.) A representative of one private transmission licensee, nominated by Central
Government, operating the Inter State Transmission System, by alphabetical
rotation out of such Transmission Licensee operating in the region.
h.) One member representing the electricity traders in the region by alphabetical
rotation, which have trading volume of more than 500 million units during the
previous financial year.
i.) A representative each of every Nodal Agency appointed by the Government of India
for coordinating cross-border power transactions with the countries having electrical
inter-connection with the region
j.) Member Secretary, NRPC – Convenor

3.SUB-COMMITTEES OF NRPC
• Technical Co-Ordination Sub-Committee (TCC)
• Operation Co-Ordination Sub-Committee (OCC)
• Protection Sub-Committee (PSC)

2
• Commercial Sub Committee (CCM)
• Telemetry, SCADA and Telemetry Sub-Committee (TeST)
• Other Sub Committees as decided as per requirement

4. FUNCTION OF NRPC

Function of NRPC is to facilitate the stability and smooth operation of the integrated grid
and economy & efficiency in the operation of power system in the region. NRPC is
carrying out following functions: -

1. To undertake Regional Level operation analysis for improving grid performance.

2. To facilitate inter-state/inter-regional transfer of power.

3. To facilitate all functions of planning relating to inter-state/ intra-state transmission

system with CTU/STU.

4. To provide views on the inter-state transmission system planned by CTU within 45

days of receipt of the proposal by NRPC. The views of NRPC will be considered by
National Committee on Transmission for sending their recommendation to Ministry
of Power for approval of new inter-state transmission system.

5. To coordinate planning & maintenance of generating machines of various generating

companies of the region including those of inter-state generating companies
supplying electricity to the Region on an annual basis and also to undertake review
of maintenance programme on a monthly basis.

6. To undertake planning of outage of transmission system on a monthly basis.

7. To undertake operational planning studies including protection studies for stable

operation of the grid.

8. To undertake planning for maintaining proper voltages through review of reactive

compensation requirement through system study committee and monitoring of
installed capacitors.

9. To evolve consensus on all issues relating to economy and efficiency in theoperation

of power system in the region.

3
10. Issuance of various Energy accounts mandated by various CERC regulations
i. Monthly Energy Accounts:
a. Regional Energy Account (REA) including Ramping Capability of CGSs,
Thermal Generators, Heat Rate Compensation for part load operation and
Secondary Oil Compensation.
b. Regional Transmission Account (RTA)
c. Regional Transmission Deviation Account (RTDA)
d. SCED Account

ii. Weekly Statement of Deviation Settlement Charges, Reactive Energy Charges

and Ancillary Services Charges.
iii. Quarterly statement of Interest Charges on Late Payment of above weekly
accounts.

11. Allocation of Power from Central Generating Station of NR.

4
 Format A1
SUMMARY OF PROPOSAL Page 1 of 1

For Official Use - To be filled by the Nodal Agency

Project Proposal Number : Date of Receipt :

To be filled by the Requesting Organization / Project Entity

1. Name of the requesting

Northern Regional Power Committee (NRPC)
Organization / Utility :

2. Short Summary of Project / Scheme / Activity

Capacity Building programme on “International

a. Name and location of the
Best Practices in Energy Transition” for
Project / Scheme / Activity
Constituents of Northern Regional Power
:
Committee (NRPC)
1. To understand the factors that
contributed to the success of the power
market liberalization in the Nordic
region.
2. To learn from international best
practices in Hydro Power Development,
Power Markets, energy transition –
Hydrogen, decarbonization and offshore
wind.
3. Overview of Power Markets/Nord Pool
at a Glance/ Intraday Trading
demonstration.
b. Objective of the Project /
4. To understand Norwegian Hydrogen
Scheme / Activity :
Economy and Low Carbon Society.
5. Capacity building programme to handle
trading of short term surplus power on
the Power exchange.
6. Interaction with EV Association, Norway
on The Norwegian EV Experience.
7. Price discovery in Nord pool.
8. Determination of transmission tariff and
sharing of transmission charges and
losses.
9. Financial settlement of power trades,
imbalances.

5
 10. Organization of forwards, futures and
options market in power, their operation
procedures, hedging etc.
11. Retail supply market.
12. Market clearing and settlement.
13. Market surveillance.
14. Imbalance settlement procedure.
15. Roles and responsibilities of various
stakeholders.
16. Reporting and information sharing.
17. Optimum power reserve estimation.
18. Real time system operation and
management.
19. Efficient maintenance practices of
transmission grids.
20. Better Understanding of the regulatory
and policy framework of the power
market in European countries.
21. EV integration in the grid along with
hydrogen powered vehicle.
22. Learning the best industry practices in
Nordic power market.
23. Enhancement of productivity and
performance.

Name : Vijay Kumar Singh, Member

Secretary, NRPC

E-mail ID : ms-nrpc@nic.in
c. Authorized Person For this
Project / Scheme / Activity Land line No : 011-26511211

Mobile No. : 9810177609

Fax No : 011-26868528

d. Nature of the Project /

Scheme / Activity: Inter – Training and Capacity Building of constituents
State / Intra – State (Please of Northern Region
Specify)
Personnel from the Central Transmission Utility
(CTU), State Transmission Utilities (STUs),
Distribution Companies (DISCOMs), State
e. Identified Beneficiaries Load Despatch Centres (SLDCs), Generators
(including ISGS), ISTS TransmissionLicensees
in Northern Region), Grid Controller of India
Limited and Northern Regional Power

6
 Committee (NRPC) Secretariat. Participation
from Central Electricity Authority (CEA),
Ministry of Power, GoI has also been
envisaged.
The programme will enable to understand:
1. Business Environment – Power Sector and
Strategy framework
f. Merits of the scheme 2. Energy Transition
3. Power Market Development
4. Energy transformation and decarbonisation
Further detailed in Annexure-A.

g. Limitations, if any No limitations

h. Time frame for

Implementation FY 2024-25
3 batches (each of 20 officials)

i. Estimated Cost of Project /

Scheme / Activity Rs. 10,06,89,000/--

j. Category under which the

project is classified (Please
refer Para 5.1 of the Para 5.1(e)
Guidelines/Procedure)

Signature:
Date:
Name:

(Authorized Representative)

7
 Format A2
DETAILED PROPOSAL (DP) Page 1 of 5
1. Details of the Requesting Organization / Project Entity

1.1 Details of Organization / Entity

Name of Organization / Northern Regional Power Committee

Entity
Acronym or Abbreviation (if NRPC
applicable)

1.2 Details of Head of the Organization

Name (Mr / Ms / Mrs) Mr. Vijay Kumar Singh

Designation Member Secretary
E-mail Address ms-nrpc@nic.in
Landline No. 011-26511211
Fax No. 011-26868528
18-A, Shaheed Jeet Singh Marg, Katwaria
Address
Sarai,
City New Delhi
Postal Code 110016

1.3 Details of Project Incharge / Project Manager (Authorized Person) for this
project/scheme/activity (Not below the rank of Dy. General Manager /
Superintending Engineer)

Name (Mr / Ms / Mrs) Mr. Vijay Kumar Singh

Designation Member Secretary
E-mail Address ms-nrpc@nic.in
Landline No. 011-26511211
Mobile No. 9810177609
Fax No. 011-26868528
18-A, Shaheed Jeet Singh Marg, Katwaria
Address
Sarai,
City New Delhi
Postal Code 110016

2. Justification of the Proposal

2.1 Analysis of the Objective

➢ The Electricity Act 2003 opened the power sector by laying down provisions
for promoting competition in the power market. By identifying electricity trade

8
 Format A2
Page 2 of 5

as a distinct activity, Electricity Act 2003, along with pursuant regulations from
the CERC, paved the way for a paradigm shift in the power sector.
➢ The Act envisages development of a competitive power market for promoting
efficiency, economy and for mobilisation of new investments in the power
sector. These transformations in power sector were supported by creation of
institutions to enhance efficiency in markets via bilateral trading and later in
2008 through trading on power exchanges.
➢ In addition, the fundamentals of power trading – such as licensing electricity
traders and ensuring open, non-discriminatory access to transmission
services – have been put into place to allow for expansion of opportunities in
all markets. As a result, there has been a paradigm shift in generation,
transmission and distribution activities, which have facilitated power trading.
➢ Nord Pool Spot runs the largest market for electrical energy in Europe,
measured in volume traded (TWh) and in market share.
➢ It operates in Norway, Denmark, Sweden, Finland, Estonia, Latvia,
Lithuania, Germany and theUK. More than 80% of the total consumption of
electrical energy in the Nordicmarket is traded through Nord Pool Spot.
➢ The capacity building programme will help personnel involved in Grid
operation and transmission planning & implementation in understanding the
policy and regulatory framework of Nordic power trading market.
➢ It will be immensely helpful as the participants will get to know about the
successful working of Europe’s leading power exchange, the integratedpower
markets and the financial derivative market.
➢ The program will include exposure to all the key issues related to a
competitive power market, price determination, congestion management,
imbalance management, reference price, risk management and market
surveillance.
➢ European countries have high share of renewable energy in their power
system. The effect of this RE power in power trading can be studied
thoroughly by this capacity building program. As India is planning to add 500
GW of renewable energy by 2030 under its commitment towards global
climate change, this program will surely help in this direction.

9
 Format A2
Page 3 of 5

Also refer Annexure-A

2.2 Identified Beneficiaries of the Project

Personnel from the Central Transmission Utility (CTU), State Transmission

Utilities (STUs), Distribution Companies (DISCOMs), State Load Despatch
Centres (SLDCs), Generators (including ISGS), ISTS Licensees in Northern
Region, Grid Controller of India Limited and Northern Regional Power Committee
(NRPC) Secretariat will benefit from the scheme. Participation from CEA/MoP
has also been envisaged.

2.3 Identified Source of Funding

The programme is to be funded fully from PSDF. As mentioned in the Para 6.2(III)
of the guidelines/procedure for disbursement of PSDF approved by Government
of India that up to 100 % grant to be given in case the project (Capacity Building)
mentioned under Para 5.1(f) of the same.

2.4 Details of Activities for Project / Scheme / Activity

➢ The programme will be implemented in three batches.

➢ Eight days (6 days training and 2 days travel) Training Program is proposed
to be conducted for each batch.
➢ The programme will be held between 01.05.2024 and 30.10.2024.
➢ The training programmes will be held in Norway and Finland.
➢ 3 batches each of 20 participants will participate for each 8-day program from
various utilities of Northern Region including CTU, SLDCs, STUs,
Generators, ISTS Licensees, DISCOM, Grid-India, NRPC Sectt, CEA and
Ministry of Power.
➢ Training Modules to cover various aspects of Power market operations,
impact of renewables through imbalance handling in energy trading as well
as cross border trading with neighbouring countries. The programme is

10
 Format A2
Page 4 of 5

designed to meet the needs of top officials of electricity utilities of India to

understand:
a. Business Environment – Power Sector and Strategy framework
b. Energy Transition
c. Power Market Development
d. Energy transformation and decarbonisation
➢ Training Modules for such programs have been designed after consultation
with POWERGRID.
➢ Field visits will be arranged during the programs to impart practical training to
the participants.

2.5 Executing Agency

POWERGRID will be the executing agency through Administrative Staff College

of India (ASCI).

2.6 Time line for Implementation of Project / Scheme / Activity

The programme is to be completed in FY 2024-25.

Timeline of the Project / Scheme / Activity

Duration of Project (in Between 01.05.2024 and 30.10.2024 (06
Months) months). 3 batches each of 20 participants.
Likely Start Date 01.05.2024
Likely Completion Date 30.10.2024

Date: Signature:
Name:
(Authorized Representative)

11
 Format A2
Page 5 of 5

Sl. Description Mar’24 June’24 July’24 Aug’24 Oct’24

No

1 Programme
Approval
2 1st Program
(proposed)
3 2nd Program
(proposed)

4 3rd Program
(proposed)

6 Programme
Report

Date: Signature:
Name:
(Authorized Representative)

12
 Format A3
Page 1 of 3
Summary of Detailed Project Report (DPR)

Objective: Capacity building of the personnel involved in Grid Operation, transmission

planning & implementation and overall policy & decision making towards creation of
efficient power markets and participation in power trading.

Executing Agency: The programme is to be executed by POWERGRID and all

arrangements like designing modules in consultation with ASCI, and power system experts
of NR utilities and coordination with Nordic countries, signing of contract with Norwegian
agencies, selecting travel partner, visa etc. shall be undertaken by Powergrid Corporation
of India Limited.

No of Programs and participants: Total 3 nos. of programs are proposed to beconducted

over one year. Each batch having 20 nos. of participants from NRPC constituents.
Personnel from the Central Transmission Utility (CTU), State Transmission Utilities (STUs),
Distribution Companies (DISCOMs), State Load Despatch Centres (SLDCs), Generators
(including ISGS), ISTS Licensees in Northern Region, Grid Controllerof India Limited and
Northern Regional Power Committee (NRPC) Secretariat will benefit from the scheme.
Participation from CEA/MoP has also been envisaged.

Venue of Programme: The capacity building programme will be held at Norway and
Finland starting from POWERGRID, Manesar.

Duration of Programme:

Participants per Duration of each Total years for which

batch Program (in days) each program will run
year
20 8 days (6 + 2 days for 1 year
travel)

13
 Format A3
Page 2 of 3

Course Content/ Training Modules: The tentative topics to be covered are placed below.

1. To understand the factors that contributed to the success of the power market
liberalization in the Nordic region.
2. Capacity building programme to handle trading of short term surplus power on the
Power exchange
3. Price discovery in Nord pool.
4. Determination of transmission tariff and sharing of transmission charges and losses.
5. Financial settlement of power trades, imbalances.
6. Organization of forwards, futures and options market in power, their operation
procedures, hedging etc.
7. Retail supply market
8. Market clearing and settlement
9. Market surveillance
10. Imbalance settlement procedure
11. Roles and responsibilities of various stakeholders
12. Reporting and information sharing
13. Optimum power reserve estimation
14. Real time system operation and management
15. Efficient maintenance practices of transmission grids
16. Better Understanding of the regulatory and policy framework of the power market in
European countries.
17. EV integration in the grid along with hydrogen powered vehicle.
18. Learning the best industry practices in Nordic power market.
19. Enhancement of productivity and performance.

14
 Format A3
Page 3 of 3
Total Cost of Training (refer Format A4):

No of Programs of Total (In Rs.)

8 days duration
3 10,06,89,000/- (including GST)

• Cost is inclusive of all taxes. However, tax rates are subject to revision by
Government.
• Final payment will be made on the basis of actuals

Terms of payment:
(1) 70% payment before the start of each batch based on proforma invoice submitted by
POWERGRID to NRPC.

(2) 30% after the successful conduct of each batch and submission of GST invoice by
POWERGRID to NRPC.

Summary of DPR given - Yes. Copy of the Proposal attached. – Yes

Date: Signature:
Name:
(Authorized Representative)

15
 Format A4
Page 1 of 2
Financial Implication of the Scheme

(Guidelines: The financial implications of the proposal may be worked out as accurately
as possible and should be detailed in this section. Further, the manner in which the
expenditure is proposed to be borne may also be clearly indicated. Please provide the
project cost estimate for its scheduled duration along with a break-up of year-wise,
component-wise expenses segregated into non-recurring and recurring expenses.)

1. Summary
S.No. Item Amount in Rs.
1. Total Cost Estimate 10,06,89,000/-
Funding Proposed from
2. 10,06,89,000/-
PSDF
Contribution from Internal
3. Nil
Sources
4. External Borrowings Nil

2. Details (Proposal POWERGRID is at Annexure-C)

2.1 Cost Estimate (including GST)

1. Estimated cost for three batches (consisting 20 persons each): Rs. 10,06,89,000/-

2. Estimated cost per batch (consisting 20 persons each): Rs. 3,35,63,000/-

3. Funding

3.1 Funding Proposed from PSDF as grant

The programme is to be funded completely from PSDF. As mentioned in the Para 6.3(III)
of the guidelines/procedure for disbursement of PSDF approved by Government of India

16
 Format A4
Page 1 of 2

that up to 100 % grant to be given in case the project (Capacity Building) mentioned
under Para 5.1(e) of the same.

3.2 Contribution from Internal Sources: Nil

3.3 External Borrowings: Nil

Signature:
Date:
Name:
(Authorized Representative)

17
 Format A5
Page 1 of 1
Brief Details of the Project Appraisal by CTU / STU / RPC

The applicant utility shall submit project appraisal by CTU / STU / RPC in the given format
and a copy of the Appraisal Report should be attached at Annexure.

Item Details to be filled by Applicant Utility

CTU STU  RPC

RPC
Appraisal By:

Date of Submission ------

to CTU / STU /
RPC for approval
Capacity Building programme on “International Best Practices in
Name of the Energy Transition” for Constituents of Northern Regional Power
Scheme Committee (NRPC).
Attached at Annexure-B
Details of the
Appraisal Report by
CTU/STU / RPC
(Attached at
Annexure)
Summary of Proposal NRPC appreciated the initiative taken
Appraised by NRPC Secretariat for benefit of NR
Technical Observations constituents and approved the
Financial Observations scheme for funding through PSDF.
Summary of
Compliance of Grid Standards
observations from
/ Codes by the Applicant
CTU/ STU/RPC
Limitations / Shortcomings
Appraisal Report
pointed out by CTU/STU/RPC
if any
Recommendations of
CTU/STU/RPC

Signature:
Date:
Name:
(Authorized Representative)

18
 Format A6
Page 1 of 1
I, Shri VIJAY KUMAR SINGH son of
------------------------------ and presently working as Member Secretary, Northern
Regional Power Committee hereby undertake to comply with the following terms
and conditions with regard to funding of the “Capacity Building programme on
“International Best Practices in Energy Transition” for Constituents of Northern
Regional Power Committee (NRPC)” with disbursement from PSDF:

• No tariff shall be claimed for the portion of the scheme funded from
PSDF.
• Amount of grant shall be refunded in case of transfer/disposal of the
facility being created under this proposal to any other scheme for
funding.
• Shall specifically mention if for the scheme under the proposal, the
grant from any other agency is being taken / proposed to be taken.
• The grant shall be refunded back to PSDF in case of non-utilisation
of the grant within one year of release of instalment.

Date: . Signature:
Name: Vijay Kumar Singh
(Authorized Representative)

19
 Supplementary Information

1. In 45th NRPC meeting held on 08.06.2019, NRPC proposed a capacity building

programme for studying the power exchange of Nordic countries, role of TSO
(Transmission System Operator), Renewable Energy in power trading, EV
integration with grid etc. to be carried out for Northern Region Constituents.
2. POWERGRID vide letter dated 09.10.2019 was requested to furnish the complete
proposal including estimated cost details for preparing the DPR for PSDF funding.
3. In 44th TCC & 47th NRPC Meetings (held on 10th and 11th December, 2019),
POWERGRID presented the detailed report and commercial implication of the
program.
4. Due to COVID pandemic, the program could not be completed.
5. Therefore, a revised estimate has been taken from POWERGRID and proposal of
Capacity Building programme on “International Best Practices in Energy Transition”
for Constituents of Northern Regional Power Committee (NRPC) has been approved
in ……………………………………… .
6. The justification for selection of Nord Pool is given in DPR. Further, a detailed
analysis is given in Annexure-A.
7. POWERGRID has been selected as implementaing agency by NRPC Forum.
8. Total 3 nos. of programs are proposed to be conducted over one year. Each batch
having 20 nos. of participants from NRPC constituents. Personnel from the Central
Transmission Utility (CTU), State Transmission Utilities (STUs), Distribution
Companies (DISCOMs), State Load Despatch Centres (SLDCs), Generators
(including ISGS), ISTS Licensees in Northern Region, Grid Controller of India
Limited and Northern Regional Power Committee (NRPC) Secretariat will benefit
from the scheme. Participation from CEA/MoP has also been envisaged.
9. Criteria for Selection:
i. The officers nominated must have at least 3 years of service left.
ii. No of Candidates from Each state/utility shall be as per decision of NRPC
forum so that 3 batches of 20 members each can be formed.
10. A copy of the minutes approved by Chairperson is enclosed for reference (refer
Annexure-B.

20
 Annexure-A
Justification for NORD Pool

Introduction: Power is a vital element that supports our modern lives at home and at work.
As power production and transmission capacity has been extended over the years,
transmission of power between countries has become more common. As a result, a
dynamic market has evolved where power can be bought or sold across areas and
countries more easily.

The power price is determined by the balance between supply and demand. Factors such
as the weather or power plants not producing to their full capacity can impact power prices.

While the price of power is determined according to supply and demand, it also becomes
clear where there are issues in the grid when the price of power goes up. This makes it
easier to identify where production or capacity is lacking, as there is too high demand
compared to production supply.

The Indian Context: The Indian power market consists of OTC Bilateral trades and non-
mandatory power exchange structure. With increasing participation from the private players,
the trading on the exchange is bound to increase in the future. Further, to meet the
requirements of customers, power exchanges have to bring out newer products such as
derivatives. Also, more and more players are becoming eager to purchase power in short
term on the exchanges. The integration of renewables will also give a push towards
innovative products for handling of this power. The market, regulatory environment and the
operator have to jointly discuss and prepare the ground for a vibrant power market in India.
A competitive power market will reduce prices and increase welfare.

Although, India has deregulated generation, the power market does not have sufficient
depth as most of the power sales are dictated according to long term contracts. Day by day
the commercial settlements and system operation are getting complex as decisions of the
operator in a regulated environment affect the financial obligations of the players. The road
ahead lies in reducing regulatory rule making and letting the market take over some of the
pricing signals.

It is seen from recent experience that beneficiaries of many of the generators who have
long term contracts under two-part tariff are reluctant to purchase power under the long

21
term PPA and try to economize their portfolio through buying and selling power on the OTC
markets and also on the exchange. Therefore, constituents feel a need to participate in
power markets.

The national tariff policy 2005 stated thus:

5.2 The real benefits of competition would be available only with the emergence of
appropriate market conditions.

9.0 The Act provides that the Appropriate Commission .............. necessary. Though there
is a need to promote trading in electricity for making the markets competitive, the
Appropriate Commission should monitor the trading transactions continuously and ensure
that the electricity traders do not indulge in profiteering in situation ......

However, the directions of the tariff policy could not have been implemented fully. The
CERC report on Short Term Power Market in India: 2015-16 has the following to offer:

1. Of the total electricity procured in India in 2015-16, the short-term power market
comprised 10%. The balance 90% of generation was procured mainly by distribution
companies through long-term contracts and short-term intra-state transactions.

Therefore, the participation in short term power market is still in nascent stages

2. In terms of volume, the size of the short-term market in India was 115.23BU (Billion
Units) in the year 2015-16. As compared to the volume of electricity transacted
through short-term market in the year 2014-15 (98.99BU), this was about 16%
higher.

There is a desire for increased participation in the short term power markets.

7. During 2015-16, about 93% of the volume of electricity transacted through traders
was at a price less than Rs. 6/kWh. About 61% of the volume was transacted at a
price less than Rs. 4/kWh.

8. During 2015-16, IEX transacted 99% of the volume of electricity at a price less than
Rs. 6/kWh while about 92% of the volume was transacted at a price less than Rs
4/kWh. During the year, PXIL transacted 99% of the volume of electricity at a price
less than Rs. 6/kWh while about 76% of the volume was transacted at less than Rs.
4/kWh.

Purchase of power in short term power markets is cost effective.

11. Competition among the trading licensees was shown for the period from 2004-05 to
2015-16. During the period, number of traders who were undertaking trading

22
 increased from 4 to 27 and concentration of market power (HHI based on volume of
trade undertaken by the licensees) declined from high concentration (HHI of 0.5512)
to non-concentration (HHI of 0.1432).

The Indian Power market is competitive with non-concentration of market power.

Government of India have also proceeded with the SAARC Framework Agreement for
Energy Cooperation (Electricity) which will facilitate trading of electricity among member
nations of SAARC. This will create challenges as well as opportunities for electricity trade
as different regulatory regimes will come into picture. The development of a cross border
market for electricity is also not far.

Recently, as per Tariff Policy, 2016, Central generating stations unable to get their power
scheduled are bringing their power to market for sale.

Although all the ingredients of a successful power market are present participants have to
build confidence to come out of their comfort zone of long term PPA and buy and sell power
on the market. In turn the market has to give that confidence to the participants.

It is natural that a commodity likes electricity, non-availability of which has huge negative
welfare implications would make the buyers shaky in case the market fails to operate
optimally. Therefore, a visit to Nord Pool which operates one of the oldest and one of the
biggest power markets in Europe would help in building confidence.

International Context: The last decade has seen the deregulation of several power
markets around the world, and especially the US and EU electricity supply industries are
undergoing a process of fundamental change. A central feature of most liberalised markets
is a Power Exchange, PX, with an optional or mandatory spot market, and, as a
complement, a market for financial instruments (futures, forwards and options)

The spot market accommodates suppliers and consumers in an auction determining market
clearing prices and quantities, while the financial market performs price hedging. In Europe
today, there are PXs with spot markets in England and Wales, The Netherlands,
Scandinavia (Denmark, Finland, Norway and Sweden), Spain and Switzerland. The
Scandinavian deregulation led to the establishment in 1993 of the joint Nordic Electricity
Exchange, otherwise known as Nord Pool.

Scandinavia, where countries have traded power for decades, has the world’s most
developed international market for electric power. Recently the trading system has changed
dramatically, moving from the old model of cooperation among the leading vertically
integrated utilities in each country, under the Nordel agreement, to competitive market
rules. The Nordic countries deregulated their power markets in the early 1990s and brought
their individual markets together into a common Nordic market. Estonia, Latvia and
Lithuania deregulated their power markets, and joined the Nord Pool market in 2010-2013.

23
To attract customers, a non-mandatory PX needs a spot market that creates confidence
among its actual and potential participants. Effective competition in the spot market is
important from several perspectives, directly for cost efficiency, transaction costs and the
potentially large distributional effects of market power, indirectly for its impact on related
financial markets.

The Nord Pool has over the years established itself as a very efficient and transparent
wholesale power market having the confidence of the market participants.

Nord Pool has played an important role in setting up of various other National/International
Power Exchanges such as the Leipzig power exchange (LPX) in Germany, developing the
power market in South African Power Pool (involving 12 countries), etc. Nord Pool is one
of the regional power pool having mature regional electricity market and facilitate more than
80% of the total Nordic electricity consumption through Nord Pool spot market.

In addition to the spot market, Nord Pool offers futures contracts, which are traded as
weekly contracts four to seven weeks ahead, as blocks of four weeks up to fifty-two weeks
ahead, or as seasons up to three years ahead. The futures are purely financial contracts
used for price hedging. About fifteen brokering companies offer services to the electricity
market. The bulk of the volume traded is in standardized financial contracts, often referred
to as over-the-counter (OTC) contracts. The liquidity of the OTC market is quite high,
particularly for the nearest season. Contracts can be resold, or a position netted out by
making an opposite contract.
Just as for bilateral trade, the PX-based financial market is heavily dependent on a well
functioning spot market to provide a relevant reference price. Any unnecessary uncertainty
in the spot price, due to possible strategic pricing, lends an extra uncertainty to the financial
contract prices. This leads to a diminished trade on the financial market which in turn
decreases the possibility for all participants in the electricity market to hedge their contracts,
thus reducing liquidity in the whole market. Research also indicates that the presence of a
well functioning financial (futures) market might actually reduce market power on the spot
market.
Nord Pool has well established and transparent futures products in electricity. By providing
tools for risk management, the financial market contributes to the efficient functioning of
both wholesale and end-user markets. The listed derivatives at Nord Pool are traded with
a reference price based on the system price in the Nordic day-ahead spot market. The
financial market is as such a purely financial market where all contracts are traded and
settled irrespective of transmission capacity.

The Nordic financial electricity market Report 8/2010 of NordREG (NordREG is a

cooperation of the Nordic energy regulators) states:

24
NordREG has found that the general view is that the Nordic financial electricity market
functions well and has a good liquidity in the basic products. There is also a general
consensus that there is trust in the market. The Nordic power market is often ranked highest
in Europe regarding transparency and efficiency. The Nordic power market also has the
highest turnover in exchange trading in relation to consumption in the area.

A Chronology of the development of Nord Pool over the years.

2016: Nord Pool Spot is rebranded to Nord Pool.

Nord Pool is appointed NEMO in Belgium, Germany, Luxembourg and Poland. Nord Pool
is together with IBEX opening the Bulgarian power market and together with Cropex
opening the Croatioan power market.

2015: Nord Pool Spot introduce a new Day Ahead Web and Intraday Web. Nord Pool Spot
is appointed Nominated Electricity Market Operator (NEMO) across 10 European power
markets; Austria, Denmark, Estonia, Finland, France, GB, Latvia, Lithuania, the
Netherlands and Sweden.

2014: Nord Pool Spot takes sole ownership of the UK market. North-Western European
power markets are coupled through the Price Coupling of Regions (PCR) project. Nord
Pool Consulting is launched.

2013: Elspot bidding area opened in Latvia. Intraday market, Elbas, introduced in both
Latvia and Lithuania.

2012: Nord Pool Spot opens bidding area in Lithuania.

2011: Elbas licensed to APX and Belpex as the intraday market in the Netherlands and
Belgium respectively.

2010: Nord Pool Spot and NASDAQ OMX Commodities launch the UK market N2EX. Nord
Pool Spot opens a bidding area in Estonia and delivers the technical solution for a new
Lithuanian market place.

2009: Norway joins the Elbas intraday market. The European Market Coupling Company
relaunches the Danish-German market coupling on 9 November. Nord Pool Spot
implements a negative price floor in Elspot.

2008: Highest turnover and market share recorded in the company's history until then.
Elspot market share 70%.

2007: Western Denmark joins the Elbas market. SESAM, the new Elspot trading system is
set into production.

25
2006: Nord Pool Spot launches Elbas in Germany.

2005: Nord Pool Spot opens the Kontek bidding area in Germany, which geographically
gives access to the Vattenfall Europe Transmission control area.

2004: Eastern Denmark joins the Elbas market.

2002: Nord Pool's spot market activities are organized in a separate company, Nord Pool
Spot AS.

2000: The Nordic market becomes fully integrated as Denmark joins the exchange.

1999: Elbas is launched as a separate market for balance adjustment in Finland and
Sweden. Elspot area trade begins 1 July.

1998: Finland joins Nord Pool ASA. Nord Pool opens an office in Odense, Denmark.

1996
A joint Norwegian-Swedish power exchange is established. The exchange is renamed Nord
Pool ASA.

1995: The framework for an integrated Nordic power market contracts was made to the
Norwegian Parliament. Together with Nord Pool's license for cross-border trading (given
by the Norwegian Water Resources and Energy Administration), this report made the
foundation for spot trading at Nord Pool.

1993: Statnett Marked AS is established as an independent company. Total volume in the

first operating year is 18.4 TWh, at a value of NOK 1.55 billion.

1991: Norwegian parliament's decision to deregulate the market for trading of electrical
energy goes into effect.

Annexure-B

Will be attached after approval.

26
 Annexure-C

Details of Cost Estimate (including GST)

1. Fee for one batch upto 20 participants: INR 3,35,63,000.00

2. Fee for three batches with total 60 participants: INR 10,06,89,000.00

3. Per Participant fee for additional participants above 20: INR 16,78,150.00

*****

27
 File No.CEA-GO-17-13(14)/1/2023-NRPC Annexure-XXIV 1
I/32534/2023
भारत सरकार
Government of India

िविद्यत ु मंत्रालय
Ministry of Power
उत्तर क्षेत्रीय िविद्यतु सिमित
Northern Regional Power Committee

Dated: 19.12.2023

सेवा मे ,

As per attached list

Subject: Nomination of members for Regional Level Disaster Management Group
(RDMG)-reg
Ref:
i. Disaster Management Plan for Power Sector Prepared by Central Electricity
Authority in fulfilment of provisions of Disaster Management Act 2005 issued in
January 2021 (enclosed)
ii. Minutes of 69th NRPC meeting issued vide letter dated 01.11.2023 (enclosed)

It is to apprise that the Central Electricity Authority has prepared a Disaster

Management Plan (January 2021) for Power Sector. Wherein, a four-tier structure has
been put in place at Central, Regional, State and Local Unit Level, with intervention and
response depending on the severity of the disaster /calamity for effectively dealing with
disaster situations in power sector and fulfilling the responsibilities as per section 36 of
the Disaster Management Act 2005.

As per above Disaster Management Plan (January 2021), the Regional Level
Disaster Management Group (RDMG) has composition as below:

a) Member Secretary (RPC) – Chairman

b) Representative of Secretary in-charge of Rehabilitation and Relief of the affected

State of the Region

c) Representatives of each State Civil Defence

18-ए, शहीद जीत िसंह मार्ग,र, कटवार्िरियार् सरिार्य, नई िदल्ली- 110016 फोन:011-26511211 फे क्स: 011-26865206 ई-मेल: ms-nrpc@nic.in वेबसार्ईट: www.nrpc.gov.in
18-A, Shaheed Jeet Singh Marg, Katwaria Sarai, New Delhi-110016 Phone: 011-26511211 Fax: 011-26865206 e- mail: ms-nrpc@nic.in Website: www.nrpc.gov.in
 File No.CEA-GO-17-13(14)/1/2023-NRPC 2
I/32534/2023
d) Regional HODs CPSUs (NTPC, NHPC, PGCIL etc.)

e) CMDs State TRANSCOs/Power Departments

f) SLDC in charge of each state.

g) Chief Engineer, Central Water Commission (CWC), for floods related early
warnings.

h) Deputy Director-General, Indian Metrological Department (IMD), for Earthquake,

and Cyclone related early warnings.

i) Group Head, Ocean Information and Forecast Services Group (ISG), for
Tsunami related early warnings.

j) Head of RLDC

Further, reference is invited to discussion held in 69 th NRPC meeting, held on

27.09.2023, wherein, it was decided that nomination will be asked from the constituents
of the group to decide and perform the roles and responsibilities collectively in any
future emergency situations.

In view of above, it is requested to nominate one representative from your

organization for the constitution of above Regional Level Disaster Management Group
(RDMG) of Northern Regional Power Committee. The nomination may be sent at
(Email:seo-nrpc@nic.in), with details as below:

Name of Officer Designation Mobile No. E-mail id Office address

Encl: as above

(V K Singh)
Member Secretary, NRPC

18-ए, शहीद जीत िसंह मार्ग,र, कटवार्िरियार् सरिार्य, नई िदल्ली- 110016 फोन:011-26511211 फे क्स: 011-26865206 ई-मेल: ms-nrpc@nic.in वेबसार्ईट: www.nrpc.gov.in
18-A, Shaheed Jeet Singh Marg, Katwaria Sarai, New Delhi-110016 Phone: 011-26511211 Fax: 011-26865206 e- mail: ms-nrpc@nic.in Website: www.nrpc.gov.in
 File No.CEA-GO-17-13(14)/1/2023-NRPC 3
I/32534/2023

List of Addressee:

Secretary in-charge of Rehabilitation and Relief:

Home Secretary, Secretary-II to Govt. of Principal Secretary (Revenue),
UT of Chandigarh, Haryana, Government of Himachal Pradesh,
2nd Floor, ChandigarhRevenue & Disaster HP Secretariat, Shimla - 171002
Secretariat, Sector 9,Management Department, 0177- 2880780
Chandigarh- 160 009Room No. 429, 4th Floor, New revsecy-hp@nic.in
Tel. +91 172 2740008 Haryana Secretariat, Sector-
hs-chd @nic.in 17, Chandigarh- 160017
secretaryrevenue2@gmail.co
m
Secretary, Department of Secretary Revenue, Secretary, Disaster Management,
DMRRR, Civil Secretariat, Punjab Government, Relief & Civil Defence Department,
Jammu/Srinagar, 180001 3rd Floor, Punjab Civil Government of Rajasthan,
dmrrr-sec@jk.gov.in Secretariat-1, Sector 1, Disaster Management, Relief and
Chandigarh- 160001 Civil Defence Department Food
0172-2742351 Building Secretariat, Jaipur
secy.r@punjab.gov.in (Rajasthan)- 302005
01412227390
relief-rj@nic.in
Secretary Revenue & Relief Secretary Disaster Secretary, Department of Social
Commissioner, Government Management, Uttarakhand Welfare, Govt. of NCT of Delhi,
of Uttar Pradesh, USDMA, Secretariat Campus, 7th Floor, MSO Building,
2nd Floor, Shastri Bhawan, 4-B, Subash Road, Dehradun I.T.O, New Delhi-110002
Lucknow-226001 Uttarakhand Secretariat- 01123324059
0522-2238200, 2215011 248001 pssw@nic.in
rahat@nic.in 0135-2659850
usdmauttarakhand@gmail.co
m
Head of State Civil Defence:
Deputy Commissioner-cum- Commandant General, Commandant General Home
Director, Civil Defence, UT Home Guards & Guards & Civil Defence, US Club,
of Chandigarh, Director Civil Defence, Shimla-171001
Estate Office Building, Haryana 0177-2811453
Sector 17, Chandigarh- 30 Bays Building, Sector - 17, dgp-hg-hp@nic.in
160017 Chandigarh- 160017
Tel. +91 172 2700109 0172-2701357
dc-chd@nic.in cghgndircd.hgncd-hry@gov.in
Commandant General Commandant General Home Secretary, Disaster Management,
HG/CD & SDRF Guards & Director Civil Relief & Civil Defence Department,
APHQ Complex, 2nd Floor, Defence, Punjab Government of Rajasthan,
Gulshan Ground, Gandhi 17 Bays Building, Sector-17-C, Disaster Management, Relief and
Nagar, Jammu- 180004 Chandigarh-160017 Civil Defence Department Food
0191-2435285 0172-2701353 Building Secretariat, Jaipur
(Rajasthan)- 302005
Cghgcd-sdrf@jkpolice.gov.in comdtgenlphg@punjab.gov.in
01412227390
relief-rj@nic.in
18-ए, शहीद जीत िसंह मार्ग,र, कटवार्िरियार् सरिार्य, नई िदल्ली- 110016 फोन:011-26511211 फे क्स: 011-26865206 ई-मेल: ms-nrpc@nic.in वेबसार्ईट: www.nrpc.gov.in
18-A, Shaheed Jeet Singh Marg, Katwaria Sarai, New Delhi-110016 Phone: 011-26511211 Fax: 011-26865206 e- mail: ms-nrpc@nic.in Website: www.nrpc.gov.in
 File No.CEA-GO-17-13(14)/1/2023-NRPC 4
I/32534/2023
DG, Civil Defence Commandant General, Home Director Civil Defence,
5th floor, Jawahar Bhawan, Guard & Civil Defence, 1, Kripa Narayan Marg Civil Lines,
Ashok Marg, Lucknow- Homeguard Headquater Delhi- 110054
226001 Nannurkeda, Dehradun, 011-23937350
0522-2286668 Uttarakhand- 248008 civildefencehq.delhi@gov.in
dgcdup@yahoo.com 0135-2784471
cghgcduk@gmail.com

18-ए, शहीद जीत िसंह मार्ग,र, कटवार्िरियार् सरिार्य, नई िदल्ली- 110016 फोन:011-26511211 फे क्स: 011-26865206 ई-मेल: ms-nrpc@nic.in वेबसार्ईट: www.nrpc.gov.in
18-A, Shaheed Jeet Singh Marg, Katwaria Sarai, New Delhi-110016 Phone: 011-26511211 Fax: 011-26865206 e- mail: ms-nrpc@nic.in Website: www.nrpc.gov.in
 Annexure-XXV

Nomination of members for Regional Level Disaster Management Group (RDMG)

Sr. No. Name of officer Designation E-mail id Office Address

1 Sh. Shahid Mehraj, IPS Director Civil Defence & SDRF Kashmir Srinagar sodighg@jkpolice.gov.in Zonal Police Headquarters, (Ground Floor) Batamallo Srinagar

2 Sh. Amit Kumar OSD to Secretary Revenue & Relief Commissioner, UP rahat@nic.in office of Relief Commissioner, 2nd floor Lal Bahadur Shashtri Bhawan, Lucknow
3 Sh. Suraj Prakash Rukwal Special Secretary to Government surajrukwal@gmail.com Civil Secretariat Jammu, UT of J&K

Dy. Commandent Gerneral, Punjab Home Guards & Dy. Director

4 Sh. Harmanjeet Singh Civil Defence, Punjab dcg.phg.chd@punjab.gov.in State HQ, 17 Bays Building, Sector-17D, Chandigarh
5 Sh. Manjeet Kumar Sahotra Deputy Secretary Revenue, Punjab usr.rev4@punjab.gov.in 2nd floor, Hall Punjab Civil Secretariat-1, Sector-1, Chandiharh
 Annexure-XXVI

Annexure-lV

Sr. ENTITY METER METER ELEMENT REMARK

No CODE SR NO
1 BB-68 NS-1059-A 220/66kV ICT-3(220kV) METER FAULTY
at Ballabgarh-BBMB
2 DL-51 NP-7762-A 220kV BTPS-1 at METER FAULTY
Ballabgarh-BBMB
3 BH-10 NS-1030-A 66 kV NFF-2 at Bhakra METER DATA NOT
Left Bank PROVIDED
4 PU-07 NP-1648-A 220kV Dhandari-1 at METER FAULTY
Jamalpur-BBMB
5 HR-03 NP-3024-A ICT-2(220kV) at Narela- TIME DRIFT
BBMB
6 BB-20 NS-1045-A 220/132kV ICT-1(132kV) METER READING NEAR
at Hissar-BBMB TO ZERO,
REPLACEMENT
NEEDED
7 BB-22 NR-3642-A 220/132kV ICT-3(132kV) METER READING NEAR
at Hissar-BBMB TO ZERO,
REPLACEMENT
NEEDED
8 BB-24 NP-7196-A 220/132kV ICT-2(132kV) METER READING NEAR
at Hissar-BBMB TO ZERO,
REPLACEMENT
NEEDED
9 BB-25 NP-1351-A 220kV Hissar (IA)-1 at METER FAULTY
Hissar-BBMB
10 BB-44 NR-3854-A 220kV Bhiwani(HVPN)-1 STATION NOT
BBMB at Bhiwani-BBMB PROVIDING METER
DATA
11 BB-45 NR-3582-A 220kV Bhiwani(HVPN)-2 STATION NOT
at Bhiwani-BBMB PROVIDING METER
DATA
12 BB-07 NR-3271-A 220/33kV T/F-1 (220 kV) TIME DRIFT
at Panipat-BBMB
13 BB-74 NP-3135-A 220/66kV ICT-3(66kV) at METER READING NEAR
Jagadhari-BBMB TO ZERO
14 CH-02 NP-6582-A 66kV UT Chd-2 Sec28 at METER FAULTY
Dhulkote-BBMB
15 BB-35 NP-5051-A 220kV Faridabad GPS-2 METER
at Samaypur-BBMB FAULTY(READING HAS
SPIKES SINCE LONG)
16 PU-26 WR-2164- 220/66kV ICT-2(66kV) at HAS OPPOSITE
A Sangrur-BBMB POLARITY
17 PJ-34 NS-1884-A 220/132kV ICT-1 (132kV) HAS OPPOSITE
at Jalandhar-BBMB POLARITY
18 PJ-36 NS-1898-A 220/132kV ICT-3 (132kV) HAS OPPOSITE
at Jalandhar-BBMB POLARITY
19 PJ-38 NS-1870-A 220/66kV ICT-1 (66kV) at HAS OPPOSITE
Jalandhar-BBMB POLARITY
20 PJ-39 NS-1862-A 220/66kV ICT-2 (66kV) at HAS OPPOSITE
Jalandhar-BBMB POLARITY
21 PJ-46 NS-1893-A 220/132kV ICT-2(132kV) METER READING
 at Jamalpur-BBMB ABRUPT
22 PJ-47 NS-1905-A 220/132kV ICT-3(132kV) METER READING
at Jamalpur-BBMB ABRUPT
23 GW-04 NP-1020-B 33 kV Nurpurbedi at TIME DRIFT
Ganguwal HPS
24 CH-15 NP-1356-A 66 kV Mohali-1 at TIME DRIFT OF 30 MINS
Chandigarh UT-Sec.39
CHANDIGARH
25 CH-16 NP-6573-A 66 kV Mohali-2 at TIME DRIFT OF 30 MINS
Chandigarh UT-Sec.39
26 DL-73 NP-5182-A 400kV Dadri-1 at Harsh TIME DRIFT
Vihar(Loni)-DTL
DELHI
27 DL-74 NP-1158-A 400kV Dadri-2 at Harsh TIME DRIFT
Vihar(Loni)-DTL
28 HY-17 NS-1016-A 400 kV Abdullapur-PG at METER FAULTY
Dipalpur-HVPNL
29 HP-25 NP-1406-A 220 kV Baddi ckt 1 at METER FAULTY
HARYANA
Pinjore-HVPN
30 HY-51 NR-3771-A 400 KV Jind(PG)-1 at TIME DRIFT
Kirori(HVPNL)
31 PU-36 NP-1883-A 220 kV Sarna at METER DATA NOT
Hiranagar-PDD PROVIDED
32 PU-35 NP-8534-A 220 kV Sarna at METER DATA NOT
Udhampur-PDD PROVIDED
33 JK-30 NP-5481-A 220 kV Kishenpur-PG-1 TIME DRIFT
at Barn-PDD
34 J&K JK-31 NP-5482-A 220 kV Kishenpur-PG-2 TIME DRIFT
at Barn-PDD
35 JK-38 NP-5467-A 132 kV SEWA II TIME DRIFT
CIRCUIT-1 at Mahanpur-
PDD
36 JK-39 NP-6195-A 132 kV SEWA II at TIME DRIFT
Kathua-PDD$
37 HP-07 NP-3137-A 132 kV Chohal at 132kV METER FAULTY
Hamirpur-HPSEB
38 HP-31 NP-6971-A 220kV Khodri-2 at Majhri- METER FAULTY
HPSEB
39 HP-09 NP-1869-A 132kV Kulhal at Majhri- METER FAULTY
HP
HPSEB
40 HP-12 NP-1867-A 220 kV Pinjore-HVPN ckt METER FAULTY
2 at Baddi(HP)
41 HP-34 NP-1392-A 132 kV Dehar at Kangoo- METER FAULTY
HPSEB
42 HY-67 NS-1205-A 400/220 kV ICT-3 METER DATA NOT
(400KV) at Kurukshetra PROVIDED
PG
43 MS-42 NR-3712-A ICT-3(220 kV) 500MVA METER HAS OPPOSITE
at Sohawal-PG POLARITY
44 HY-68 NS-1458-A 400/220 kV ICT-3 METER DATA NOT
POWERGRID
(220KV) at Kurukshetra PROVIDED
PG
45 CH-23 NS-1518-A 220/66 kV ICT 1(66 kV) METER HAS OPPOSITE
at Chandigarh(PG) POLARITY
46 CH-25 NS-1533-A 220/66 kV ICT 2(66 kV) METER HAS OPPOSITE
at Chandigarh(PG) POLARITY
47 NU-19 NR-3977-A 400 kV BLANK FILE, METER
Ratangarh(RVPNL)-II at FAULTY
Sikar-PG
48 PU-94 NP-3125-A ICT-2 (220 kV) at Patiala- READING 2/3RD
PG
49 PJ-33 NS-1391-A ICT-4 (220 kV)(500MVA) METER DATA NOT
at Patiala-PG PROVIDED
50 PU-96 NP-3158-A ICT-1 (220 kV) at HAS TIME DRIFT MORE
Amritsar-PG THAN 1 HR
51 PJ-09 NR-3426-A 220kV Mohali-2 at BLANK FILE, METER
Nalagarh-PG FAULTY
52 NB-09 NR-3383-A ICT-1 (400 kV) at Banala METER READING LESS
PG
53 LN-07 NS-1556-A 400kV Lahal (HP) ckt 1 at METER FAULTY
Chamba(PG)(Rajera)
54 LN-09 NS-1558-A 400kV Lahal (HP) ckt 2 at METER FAULTY
Chamba(PG)(Rajera)
55 HP-37 NR-3423-A 220kV HPSEB NANGAL- TIME DRIFT
1 at Nalagarh-PG
56 PS-01 NP-8268-A 400 kV Jallandhar(PG) at METER DATA NOT
Nakodar-PSEB PROVIDED
57 PS-02 NP-8158-A 400 kV Kurukshetra(PG) METER DATA NOT
at Nakodar-PSEB PROVIDED
58 PU-46 NP-1871-A 132 kV Hamirpur at METER FAULTY
Chohal-PSEB
59 PS-03 NR-3469-A 400 kV Moga(PG) at METER DATA NOT
PUNJAB
Nakodar-PSEB PROVIDED
60 PU-83 NP-1588-A 220 kV Jallandhar(PG)-1 METER DATA NOT
at Kartarpur-PSEB PROVIDED
61 PU-84 NP-1679-A 220 kV Jallandhar(PG)-2 METER DATA NOT
at Kartarpur-PSEB PROVIDED
62 PU-38 NS-2029-A 132 kV Kotla-2 at Ropar- HAS OPPOSITE
PSEB POLARITY
63 RJ-86 NP-5029-A 220kV Hissar(BBMB) at METER DATA NOT
Chirawa-RVPNL PROVIDED
64 RD-19 NS-1404-A 400kV Fathegarh 3(PG) METER DATA NOT
ckt 1 at Jaisalmer(RS) PROVIDED
RAJASTHAN
65 RD-20 NS-1322-A 400kV Fathegarh 3(PG) METER DATA NOT
ckt 2 at Jaisalmer(RS) PROVIDED
66 RH-19 NR-4472-A 400 kV Sikar (PG)-1 at METER FAULTY
Babai-RRVPNL
67 UP-30 NS-1578-A 220kV Agra-PG at METER DATA NOT
Kirawali(Agra)-UPPCL PROVIDED
68 UQ-20 NP-8123-A 400kV Lucknow(PG) at METER DATA NOT
400kV Lucknow-UPPCL PROVIDED
69 NV-03 NR-4307-A 400 kV Lucknow-2 at TIME DRIFT
Basti-UPPCl
UPPCL
70 NV-04 NR-4304-A 400 kV Gorakhpur 2 at TIME DRIFT
Basti-UPPCL
71 MS-34 NS-1569-A 400kV Varanasi(PG) ckt METER DATA NOT
1 at Jaunpur(UP) PROVIDED
72 MS-35 NS-1570-A 400kV Varanasi(PG) ckt METER DATA NOT
2 at Jaunpur(UP) PROVIDED
73 UTTARAKHAND UA-43 NP-1890-A 400kV Moradabad at METER DATA NOT
Kashipur-UPCL PROVIDED
74 UA-36 NP-1751-A 132kV Afzalgarh at TIME DRIFT
Kalagarh-UPCL(Feeder-
71)
75 UA-37 NP-1584-A 132kV Sherkot at TIME DRIFT
Kalagarh-UPCL(Feeder-
72)
 Annexure-XXVII

CENTRAL ELECTRICITY REGULATORY COMMISSION

NEW DELHI

No.L-1/268/2022/CERC Dated 15th March, 2024

(NOTIFICATION)

In the exercise of powers conferred under section 178 of the Electricity Act, 2003 (36 of

2003) read with Section 61 thereof and all other powers enabling it in this behalf, and after previous

publication, the Central Electricity Regulatory Commission hereby makes the following regulations,

namely:

CHAPTER – 1

PRELIMINARY

1. Short title and commencement. (1) These regulations may be called the Central Electricity
Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2024.

(2) These regulations shall come into force on 1.4.2024, and, unless reviewed earlier or extended
by the Commission, shall remain in force for a period of five years from 1.4.2024 to 31.3.2029:

Provided that where a generating station or unit thereof and transmission system or an element
thereof, has been declared under commercial operation before the date of commencement of these
regulations and whose tariff has not been finally determined by the Commission till that date, tariff
in respect of such generating station or unit thereof and transmission system or an element thereof
for the period ending 31.3.2024 shall be determined in accordance with the Central Electricity
Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2019 as amended from time
to time.

1
2. Scope and extent of application. (1) These regulations shall apply to all cases where tariff
for a generating station or a unit thereof and a transmission system or an element thereof is required
to be determined by the Commission under section 62 of the Act read with section 79 thereof:

Provided that any generating station for which agreement(s) have been executed for the
supply of electricity to the beneficiaries on or before 5.1.2011 and the financial closure for the said
generating station has not been achieved by 31.3.2024, such projects shall not be eligible for
determination of tariff under these regulations unless fresh consent of the beneficiaries is obtained
and furnished;

(2) These regulations shall also apply in all cases where a generating company has the arrangement
for the supply of coal or lignite from the integrated mine(s) allocated to it, for one or more of its
specified end use generating stations, whose tariff is required to be determined by the Commission
under section 62 of the Act read with section 79 thereof.

(3) These regulations shall not apply to the following cases: -

(a) Generating stations or transmission systems whose tariff has been discovered through tariff
based competitive bidding in accordance with the guidelines issued by the Central
Government and adopted by the Commission under section 63 of the Act;

(b) Generating stations based on renewable sources of energy whose tariff is determined in
accordance with the Central Electricity Regulatory Commission (Terms and Conditions for
Tariff determination from Renewable Energy Sources) Regulations, 2020.

3. Definitions. - In these regulations, unless the context otherwise requires: -

(1) 'Act' means the Electricity Act, 2003 (36 of 2003);

(2) 'Additional Capital expenditure' means the capital expenditure incurred, or projected to be

incurred after the date of commercial operation of the project by the generating company or the

transmission licensee, as the case may be, in accordance with the provisions of these regulations;

(3) 'Additional Capitalisation' means the additional capital expenditure admitted by the

Commission after prudence check, in accordance with these regulations;

2
(4) 'Admitted capital cost' means the capital cost which has been allowed by the Commission for

servicing through tariff after due prudence check in accordance with the relevant tariff regulations;

(5) 'Annual Target Quantity' or 'ATQ' in respect of an integrated mine(s) means the quantity of

coal or lignite to be extracted during a year from such integrated mine(s) corresponding to 85% of

the quantity specified in the Mining Plan;

(6) 'Ancillary Service' or 'AS' in relation to power system operation means the service necessary

to support the grid operation in maintaining power quality, reliability and security of the grid and

includes Primary Reserve Ancillary Service, Secondary Reserve Ancillary Service, Tertiary Reserve

Ancillary Service, active power support for load following, reactive power support, black start and

such other services as defined in the Grid Code;

(7) 'Auxiliary Energy Consumption' or 'AUX' in relation to a period in case of a generating

station means the quantum of energy consumed by auxiliary equipment of the generating station,

such as the equipment being used for the purpose of operating plant and machinery including

switchyard of the generating station and the transformer losses within the generating station,

expressed as a percentage of the sum of gross energy generated at the generator terminals of all the

units of the generating station;

Provided that auxiliary energy consumption shall not include energy consumed for the supply

of power to the housing colony and other facilities at the generating station and the power consumed

for construction works at the generating station and integrated mine(s);

Provided further that auxiliary energy consumption for compliance with revised emission

standards, sewage treatment plant and external coal handling plant (jetty and associated

infrastructure) shall be considered separately.

(8) 'Auxiliary energy consumption for emission control system' or 'AUXe' in relation to a

3
period in the case of coal or lignite based thermal generating station means the quantum of energy

consumed by auxiliary equipment of the emission control system of the coal or lignite based thermal

generating station in addition to the auxiliary energy consumption under clause (7) of this

Regulation;

(9) 'Auditor' means an auditor appointed by a generating company or a transmission licensee, as

the case may be, in accordance with the provisions of sections 224, 233B and 619 of the Companies

Act, 1956 (1 of 1956), as amended from time to time or Chapter X of the Companies Act, 2013 (18

of 2013) or any other law for the time being in force;

(10) 'Beneficiary' in relation to a generating station covered under clauses (a) or (b) of sub-section

1 of section 79 of the Act, means a distribution licensee who is purchasing electricity generated at

such generating station by entering into a Power Purchase Agreement either directly or through a

trading licensee on payment of capacity charges and energy charges;

Provided that where the distribution licensee is procuring power through a trading licensee,

the arrangement shall be secured by the trading licensee through back to back power purchase

agreement and power sale agreement.

Provided further that beneficiary shall also include any person who has been allocated

capacity in any inter-State generating station by the Government of India.

(11) 'Capital Cost' means the capital cost as determined in Regulation 19 of these regulations in

respect of generating station or transmission system, as the case may be, and Regulation 41 of these

regulations in respect of integrated mine(s);

(12) 'Change in Law' means the occurrence of any of the following events:

(a) enactment, bringing into effect or promulgation of any new Indian law; or

4
 (b) adoption, amendment, modification, repeal or re-enactment of any existing Indian law; or

(c) change in interpretation or application of any Indian law by a competent court, Tribunal

or Indian Governmental Instrumentality which is the final authority under law for such

interpretation or application; or

(d) change by any competent statutory authority in any condition or covenant of any consent

or clearances or approval or licence available or obtained for the project; or

(e) coming into force or change in any bilateral or multilateral agreement or treaty between

the Government of India and any other Sovereign Government having implications for

the generating station or the transmission system regulated under these regulations.

(13) 'Commission' means the Central Electricity Regulatory Commission referred to in sub-section

(1) of section 76 of the Act;

(14) 'Communication System' means communication system as defined in sub clause (h) of clause

(i) of Regulation 2 of the Central Electricity Regulatory Commission (Communication System for

inter-State transmission of electricity) Regulations, 2017;

(15) 'Competitive Bidding' means a transparent process for procurement of equipment, services

and works in which bids are invited by the project developer by open advertisement covering the

scope and specifications of the equipment, services and works required for the project, and the terms

and conditions of the proposed contract as well as the criteria by which bids shall be evaluated, and

shall include domestic competitive bidding and international competitive bidding;

(16) 'Cut-off Date’ shall be the last day of the financial year closing after thirty six months from

the date of commercial operation of the project, except in case of integrated mine(s);

(17) 'Date of Commercial Operation' or 'COD' in respect of a thermal generating station or hydro

5
generating station or transmission system or communication system shall have the same meaning as

defined in the Grid Code, as amended from time to time:

Provided that Date of Commercial Operation of integrated mine(s) shall have the same

meaning as specified in Regulation 5 of these regulations;

(18) 'Date of Operation' or 'ODe' in respect of an emission control system means the date of

putting the emission control system into use after meeting all applicable technical and environmental

standards, certified through the Management Certificate duly signed by an authorised person, not

below the level of Director of the generating company;

(19) 'Date of Commencement of Production' in respect of integrated mine(s) means the date of

touching of coal or lignite, as the case may be, as declared by the generating company;

(20) 'Declared Capacity' or 'DC’ in relation to a generating station means, the capability to deliver

ex-bus electricity in MW declared by such generating station in relation to any time-block of the day

as defined in the Grid Code or whole of the day, duly taking into account the availability of fuel or

water, and subject to further qualification in these regulations;

(21) 'De-capitalisation' for the purpose of the tariff under these regulations, means a reduction in

Gross Fixed Assets of the project as admitted by the Commission corresponding to the inter-unit

transfer of assets or the assets taken out from service;

(22) 'De-commissioning' means removal from service of a generating station or a unit thereof or

transmission system including communication system or element thereof, after it is certified by the

Central Electricity Authority or any other authorized agency, either on its own or on an application

made by the project developer or the beneficiaries or both, that the project cannot be operated due to

non-performance of the assets on account of technological obsolescence or uneconomic operation or

due to environmental concerns or safety issues or a combination of these factors;

6
(23) 'Design Energy' means the quantum of energy which can be generated in a 90% dependable

year with 95% installed capacity of the hydro generating station;

(24) 'Element' means an asset which has been distinctively defined under the scope of the

transmission project in the Investment Approval, such as transmission lines, including line bays and

line reactors, substations, bays, compensation devices, Interconnecting Transformers which can be

put to use.

(25) 'Emission control system' means a set of equipment or devices required to be installed in a

coal or lignite based thermal generating station or unit thereof to meet the revised emission standards;

(26) 'Escrow account’ means the account for deposit and withdrawal of mine closure expenses of

integrated mine(s), maintained in accordance with the guidelines issued by the Coal Controller,

Ministry of Coal, Government of India;

(27) 'Existing Project' means the generating station and the transmission system which has been

declared under commercial operation on a date prior to 1.4.2024;

(28) 'Expansion project' shall include any addition of new capacity to the existing generating

station or augmentation of the transmission system, as the case may be;

(29) 'Expenditure Incurred' means the fund, whether the equity or debt or both, actually deployed

and paid in cash or cash equivalent, for the creation or acquisition of a useful asset and does not

include commitments or liabilities for which no payment has been released;

(30) 'Extended Life' means the life of a generating station or unit thereof or transmission system or

element thereof beyond the period of useful or operational life, as may be determined by the

Commission on case to case basis;

(31) 'Force Majeure' for the purpose of these regulations means the events or circumstances or

7
combination of events or circumstances, including those stated below, which prevent the generating

company or transmission licensee from completing or operating the project, and only if such events

or circumstances are not within the control of the generating company or transmission licensee and

could not have been avoided, had the generating company or transmission licensee taken reasonable

care or complied with prudent utility practices:

(a) Act of God including lightning, drought, fire and explosion, earthquake, volcanic

eruption, landslide, flood, cyclone, typhoon, tornado, geological surprises, or

exceptionally adverse weather conditions which are in excess of the statistical measures

for the last hundred years; or

(b) Any act of war, invasion, armed conflict or act of a foreign enemy, blockade, embargo,

revolution, riot, insurrection, terrorist or military action; or

(c) Industry wide strikes and labour disturbances having a nationwide impact in India; or

(d) Delay in obtaining statutory approval for the project except where the delay is attributable

to the project developer;

(32) 'Fuel Supply Agreement' means the agreement executed between the generating company and

the fuel supplier for the generation and supply of electricity to the beneficiaries;

(33) 'Generating Station' shall have the same meaning as defined under sub-Section 30 of Section

2 of the Act and, for the purpose of these regulations, shall also include stages or blocks or units of

a generating station;

(34) 'Generating Unit' or 'Unit' in relation to a thermal generating station (other than combined

cycle thermal generating station) means steam generator, turbine-generator and auxiliaries, or in

relation to a combined cycle thermal generating station, means turbine-generator and auxiliaries or

8
combustion turbine-generator, associated waste heat recovery boiler, connected steam turbine-

generator and auxiliaries, and in relation to a hydro generating station means turbine-generator and

its auxiliaries;

(35) 'Grid Code' means the Central Electricity Regulatory Commission (Indian Electricity Grid

Code) Regulations, 2023;

(36) 'Gross Calorific Value' or 'GCV' in relation to a thermal generating station means the heat

produced in kCal by the complete combustion of one kilogram of solid fuel or one litre of liquid fuel

or one standard cubic meter of gaseous fuel, as the case may be;

(37) 'GCV as Received' means the GCV of coal as measured at the unloading point of the thermal

generating station through collection, preparation and testing of samples from the loaded wagons,

trucks, ropeways, Merry-Go-Round (MGR), belt conveyors and ships in accordance with the IS 436

(Part-1/ Section 1)- 1964:

Provided that the measurement of coal shall be carried out through sampling by a third party

agency to be appointed by the generating companies in accordance with the guidelines, if any, issued

by the Central Government:

Provided further that samples of coal shall be collected either manually or through hydraulic

augur or through any other method considered suitable, keeping in view the safety of personnel and

equipment:

Provided also that the generating companies may adopt any advanced technology for the

collection, preparation and testing of samples for measurement of GCV in a fair and transparent

manner;

(38) 'Gross Station Heat Rate' or 'SHR' means the heat energy input in kCal required to generate

9
one kWh of electrical energy at generator terminals of a thermal generating station;

(39) 'Implementation Agreement' means any agreement or covenant entered into (i) between the

transmission licensee and the generating company or (ii) between the transmission licensee and

developer of the interconnected transmission system for the execution of generation and transmission

projects in a coordinated manner, laying down the project implementation schedule and mechanism

for monitoring the progress of the projects;

(40) 'Indian Governmental Instrumentality' means the Government of India, Governments of

State (where the project is located) and any ministry or department or board or agency controlled by

the Government of India or the Government of State where the project is located, or quasi-judicial

authority constituted under the relevant statutes in India;

(41) 'Infirm Power' means electricity injected into the grid prior to the date of commercial

operation of a unit of the generating station in accordance with Central Electricity Regulatory

Commission (Indian Electricity Grid Code) Regulations, 2023;

(42) 'Input Price' means the price of coal or the price of lignite (including transfer price of lignite

in respect of existing lignite mines) sourced from the integrated mines at which the coal or lignite is

transferred to the generating station for the purpose of computing the energy charges for generation

and supply of electricity to the beneficiaries and determined in accordance with Chapter 9 of these

regulations;

(43) 'Installed Capacity' or 'IC' means the summation of the name plate capacities of all the units

of the generating station or the capacity of the generating station reckoned at the generator terminals,

as may be approved by the Commission from time to time;

(44) 'Integrated Mine' means the captive mine (allocated for use in one or more identified

generating stations) or basket mine (allocated to a generating company for use in any of its generating

10
stations) or both being developed by the generating company or its affiliate for supply of coal or

lignite to one or more specified end use generating stations for generation and sale of electricity to

the beneficiaries;

Explanation: Affiliate shall mean a company that is directly controlled and owned by a generating

company having at least twenty six percent (26%) of the voting rights of the entity.

(45) 'Inter-State Generating Station' or 'ISGS' has the meaning as assigned in the Grid Code;

(46) 'Investment Approval' means approval by the Board of the generating company or the

transmission licensee or Cabinet Committee on Economic Affairs (CCEA) or any other competent

authority conveying administrative sanction for the project, including funding of the project and the

timeline for the implementation of the project:

Provided that the date of Investment Approval shall be reckoned from the date of the resolution

of the Board of the generating company or the transmission licensee where the Board is competent

to accord such approval and from the date of sanction letter of competent authority in other cases;

Provided further that in respect of the integrated mine(s), funding and timeline for

implementation shall be indicated separately and distinctly in the Investment Approval;

Provided further that where investment approval includes both the generating station and the

integrated mine(s), the funding and timeline for implementation of the integrated mine(s) shall be

worked out and indicated separately and distinctly in the Investment Approval.

(47) 'Landed Fuel Cost’ means the total cost of coal (including biomass in case of co firing), lignite

or the gas/naphtha/liquid fuel delivered at the unloading point of the generating station and shall

include the base price or input price, washery charges wherever applicable, transportation cost

(overseas or inland or both) and handling cost, charges for third party sampling and applicable

11
statutory charges;

(48) 'Loading Point' in respect of integrated mine(s) means the location of railway siding or silo or

the coal handling plant or such other arrangements like a conveyor belt, whichever is nearest to the

mine, for despatch of coal or lignite, as the case may be;

(49) 'Long-Term Customer' shall have the same meaning as 'Long Term Customer' as defined in

the Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and

Medium-term Open Access in inter-State Transmission and related matters) Regulations, 2009 or

Designated ISTS Customers (DICs) or “General Network Access Grantee” or “GNA Grantee” as

defined in the Central Electricity Regulatory Commission (Connectivity and General Network

Access to the inter-State Transmission System) Regulations, 2022 (excluding those granted “T-

GNA”);

(50) 'Maximum Continuous Rating' or 'MCR' in relation to a generating unit of the thermal

generating station means the maximum continuous output at the generator terminals, guaranteed by

the manufacturer at rated parameters, and in relation to a block of a combined cycle thermal

generating station means the maximum continuous output at the generator terminals, guaranteed by

the manufacturer with water or steam injection (if applicable) and corrected to 50 Hz grid frequency

and specified site conditions;

(51) 'Mine Infrastructure' shall include assets of the integrated mine(s) such as tangible assets

used for mining operations, being civil works, workshops, immovable winning equipment,

foundations, embankments, pavements, electrical systems, communication systems, relief centres,

site administrative offices, fixed installations, handling arrangements, crushing and conveying

systems, railway sidings, pits, shafts, inclines, underground transport systems, hauling systems

(except movable equipment unless the same is embedded in land for permanent beneficial enjoyment

12
thereof), land demarcated for afforestation and land for rehabilitation and resettlement of persons

affected by mining operations under the relevant law;

(52) 'Mining Plan' or 'Mine Plan' in respect of integrated mine(s) means a plan prepared in

accordance with the Guidelines for Preparation, Formulation, Submission, Processing, Scrutiny,

Approval and Revision of Mining Plan for the coal and lignite block issued by the Ministry of Coal,

Government of India as amended from time to time or provisions of the Mineral Concession Rules,

1960, as amended from time to time and approved under clause (b) of sub-section (2) of section 5 of

the Mines and Minerals (Development and Rehabilitation) Act, 1957 by the Central Government or

by the State Government, as the case may be;

(53) 'New Project' means the generating station or unit thereof or the transmission system or

element thereof achieving its commercial operation on or after 1.4.2024;

(54) 'Non-Pit Head Generating Station' or 'Non-Pit Head Power Plant' means coal and lignite

based generating stations other than Pit Head Generating Stations.

(55) 'Operation and Maintenance Expenses' or 'O&M expenses' means the expenditure incurred

for operation and maintenance of the project, or part thereof, and includes the expenditure on

manpower, maintenance, repairs and maintenance spares, other spares of capital nature valuing up

to Rs. 10 lakhs, additional capital expenditure of an individual asset costing less than Rs. 20 lakhs,

consumables, insurance and overheads and fuel other than used for generation of electricity:

Provided that for integrated mine(s), the Operation & Maintenance Expenses shall not include

the mining charge paid to the Mine Developer and Operator, if any, engaged by the generating

company and the mine closure expenses.

(56) 'Original Project Cost' means the capital expenditure incurred by the generating company or

the transmission licensee, as the case may be, within the original scope of the project up to the cut-

13
off date, and as admitted by the Commission;

(57) 'Peak Rated Capacity' in respect of integrated mine(s) means the peak rated capacity of the

mine, as specified in the Mining Plan;

(58) 'Pit Head Generating Station' or 'Pit Head Power Plant' means as defined under The

Environment (Protection) Rules, 1986.

(59) 'Plant Availability Factor' or '(PAF)' in relation to a generating station for any period means

the average of the daily declared capacities (DCs) for all the days during the period expressed as a

percentage of the installed capacity in MW less the auxiliary energy consumption and auxiliary

energy consumption for emission control system as per these regulations;

(60) 'Plant Load Factor' or '(PLF)' in relation to a thermal generating station or unit thereof for a

given period means the total sent out energy corresponding to scheduled generation during the

period, expressed as a percentage of sent out energy corresponding to installed capacity in that period

and shall be computed in accordance with the following formula:

PLF - 10000 x ,%

Where,

IC = Installed Capacity of the generating station or unit in MW,

SGi = Scheduled Generation in MW for the ith time block of the period,

N = Number of time blocks during the period,

AUXn = Normative auxiliary energy consumption as a percentage of gross

energy generation; and

AUXen = Normative auxiliary energy consumption for emission control system as a percentage

14
 of gross energy generation, wherever applicable.

(61) 'Procedure Regulations' means the Central Electricity Regulatory Commission (Conduct of

Business) Regulations, 2023;

(62) 'Project' means:

i) in the case of a thermal generating station, all components of the thermal generating

station and including an integrated coal mine, biomass pellet handling system, pollution

control system, and effluent treatment plan, as may be required;

ii) in the case of a hydro generating station, all components of the hydro generating station

including the dam, intake water conductor system, power generating station, as

apportioned to power generation; and

iii) in case of transmission, all components of the transmission system, including the

communication system;

(63) 'Prudence Check' means scrutiny of the reasonableness of any cost or expenditure incurred or

proposed to be incurred in accordance with these regulations by the generating company or the

transmission licensee, as the case may be;

(64) 'Pumped Storage Hydro Generating Station' means a hydro generating station which

generates power through energy stored in the form of water energy, pumped from a lower elevation

reservoir to a higher elevation reservoir;

(65) 'Rated Voltage' means as specified in the Grid Code;

(66) 'Reference Rate of Interest' means the one year marginal cost of funds based lending rate

(MCLR) of the State Bank of India (SBI) issued from time to time plus 325 basis points;

(67) 'Revised Emission Standards' in respect of thermal generating station means the revised

15
norms notified as per Environment (Protection) Amendment Rules, 2015 or any other Rules as may

be notified from time to time;

(68) 'Run-of-River Generating Station' means a hydro generating station which does not have

upstream pondage;

(69) 'Run-of-River Generating Station with Pondage' means a hydro generating station with

sufficient pondage for meeting the diurnal variation of power demand;

(70) 'Scheduled Commercial Operation Date' or 'SCOD' shall mean the date(s) of commercial

operation of a generating station or generating unit thereof or transmission system or element thereof

and associated communication system as indicated in the Investment Approval or as agreed in power

purchase agreement or transmission service agreement as the case may be, whichever is earlier;

(71) 'Scheduled Energy' means the quantum of energy scheduled by the concerned Load Despatch

Centre to be injected into the grid by a generating station for a given time period;

(72) 'Scheduled Generation' or 'Scheduled injection' for a time block or any period means the

schedule of generation or injection in MW or MWh ex-bus, including the schedule for Ancillary

Services given by the concerned Load Despatch Centre in accordance with the Grid Code;

(73) 'Schedule Drawal' for a time block or any period means the schedule of drawal in MW or

MWh ex-bus, including the schedule for Ancillary Services given by the concerned Load Despatch

Centre;

(74) 'Sharing Regulations' means Central Electricity Regulatory Commission (Sharing of

Transmission Charges and Losses in inter-State Transmission System) Regulations, 2020 as

amended from time to time;

(75) 'Small Gas Turbine Generating Station' means and includes open cycle gas turbine or

16
combined cycle generating station with gas turbines in the capacity range of 50 MW or below;

(76) 'Start Date or Zero Date' means the date indicated in the Investment Approval for

commencement of implementation of the project, and where no such date has been indicated, the

date of Investment Approval shall be deemed to be Start Date or Zero Date;

(77) 'Statutory Charges' means and includes taxes, cess, duties, royalties and other charges levied

through Acts of the Parliament or State Legislatures or by Indian Government Instrumentality under

relevant statutes;

(78) 'Storage Type Generating Station' means a hydro generating station associated with storage

capacity to enable variation of generation of electricity according to demand;

(79) 'Thermal Generating Station' means a generating station or a unit thereof that generates

electricity using fossil fuels such as coal, lignite, gas, liquid fuel or a combination of these as its

primary source of energy or co-firing of biomass with coal;

(80) 'Transmission Line' shall have the same meaning as defined in sub-section (72) of Section 2

of the Act;

(81) 'Transmission Service Agreement' means the agreement entered into between the

transmission licensee and the Designated ISTS Customers or long-term transmission customers or

Central Transmission Utility as applicable in accordance with the Sharing Regulations and shall

include the Bulk Power Transmission Agreement and Long Term Access Agreement;

(82) 'Transmission System' means a line or a group of lines with or without associated sub-station,

equipment associated with transmission lines and sub-stations identified under the scheme as per the

Investment Approval(s) and shall include associated communication system;

(83) 'Trial Operation' in relation to the transmission system shall have the same meaning as

17
specified in Regulation 23 of Grid Code;

(84) 'Trial Run' in relation to the generating station shall have the same meaning as specified in

Regulation 22 of Grid Code;

(85) 'Sub-Station' shall have the same meaning as defined in sub-section (69) of section 2 of the

Act;

(86) 'Unloading Point' means the point within the premises of the coal or lignite based thermal

generating station where the coal or lignite is unloaded from the rake or truck or any other mode of

transport;

(87) 'Useful Life' in relation to a unit of a generating station, integrated mines, transmission system

and communication system from the date of commercial operation shall mean the following:

(a) Coal/Lignite based thermal generating station 25 years

(b) Gas/Liquid fuel based thermal generating station 25 years
(c) AC and DC sub-station 25 years
(d) Gas Insulated Substation (GIS) 25 years
(e) Hydro generating station including pumped storage 40 years
hydro generating stations

(f) Transmission line (including HVAC & HVDC) 35 years

(g) Optical Ground Wire (OPGW) 15 years

IT system, SCADA and Communication system

(h) excluding OPGW 7 years
(i) Integrated mine(s) As per the Mining Plan

Provided that in the case of coal/lignite based thermal generating stations and hydro generating

stations, the Operational Life may be 35 years and 50 years, respectively.

18
(88) The words and expressions used in these regulations and not defined herein but defined in the

Act or any other regulations of the Commission, shall have the meaning assigned to them under the

Act or any other regulations of the Commission.

4. Interpretations: - In these regulations, unless the context otherwise requires:

(1) 'Day' means a calendar day consisting of 24 hours period starting at 0000 hours;

(2) 'kCal' means a unit of heat energy contents in mineral, measured in one kilo calories or

one thousand calories of heat produced at any instantaneous period;

(3) 'Kilowatt-Hour' or 'kWh' means a unit of electrical energy, measured in one kilowatt or

one thousand watts of power produced or consumed over a period of one hour;

(4) 'Quarter' means the period of three months commencing on the first day of April, July,

October and January of each financial year in case of an existing project, and in case of a

new project, in respect of the first quarter, from the date of commercial operation to the

last day of June, September, December or March, as the case may be;

(5) 'Tonne' means a metric tonne of coal or lignite in respect of integrated mine(s);

(6) 'Year' means a financial year beginning on 1st April and ending on 31st March:

Provided that the first year in case of a new project or integrated mine(s) shall commence

from the date of commercial operation and end on the immediately following 31st March.

(7) Reference to any Act, Rules, and Regulations shall include amendment or consolidation

or re-enactment thereof.

19
 CHAPTER – 2

DATE OF COMMERCIAL OPERATION

5. Date of Commercial Operation: (1) The date of commercial operation of a generating

station or unit thereof or a transmission system or element thereof and associated communication

system shall be determined in accordance with the provisions of the Grid Code. In the event of

mismatch of COD between associated transmission and/or generating stations, the liability for the

transmission charges shall be in accordance with the provisions of the Sharing Regulations, 2020 as

amended from time to time.

(2) The date of commercial operation in case of integrated mine(s), shall mean the earliest of: -

a) the first date of the year succeeding the year in which 25% of the Peak Rated Capacity as

per the Mining Plan is achieved; or

b) the first date of the year succeeding the year in which the value of production estimated in

accordance with Regulation 7 of these regulations, exceeds total expenditure in that year;

or

c) the date of two years from the date of commencement of production:

Provided that on the earliest occurrence of any of the events under sub-clauses (a) to (c) of

Clause (2) of this Regulation, the generating company shall declare the date of commercial operation

of the integrated mine(s) under the relevant sub-clause with one week prior intimation to the

beneficiaries of the end-use or associated generating station(s);

Provided further that in case the integrated mine(s) is ready for commercial operation but is

prevented from declaration of the date of commercial operation for reasons not attributable to the

generating company or its suppliers or contractors or the Mine Developer and Operator, the

20
Commission, on an application made by the generating company, may approve such other date as

the date of commercial operation as may be considered appropriate after considering the relevant

reasons that prevented the declaration of the date of commercial operation under any of the sub-

clauses of Clause (2) of this Regulation;

Provided also that the generating company seeking the approval of the date of commercial

operation under the preceding proviso shall give prior notice of one month to the beneficiaries of the

end-use or associated generating station(s) of the integrated mine(s) regarding the date of commercial

operation.

6. Sale of Infirm Power: Supply of infirm power shall be in accordance with the Central

Electricity Regulatory Commission (Deviation Settlement Mechanism and Related matters)

Regulations, 2022:

Provided that any revenue earned by the generating company from the supply of infirm power

after accounting for the fuel expenses shall be applied in adjusting the capital cost accordingly.

7. Supply of Coal or Lignite prior to the Date of Commercial Operation of Integrated

Mine: The input price for the supply of coal or lignite from the integrated mine(s) prior to their date

of commercial operation shall be:

(a) in the case of coal, the estimated price available in the investment approval, or the notified

price of Coal India Limited for the corresponding grade of coal supplied to the power

sector, whichever is lower; and

(b) in the case of lignite, the estimated price available in the investment approval or the last

available pooled lignite price as determined by the Commission for the transfer price of

lignite, whichever is lower:

21
 Provided that any revenue earned from the supply of coal or lignite prior to the date of

commercial operation of the integrated mine(s) shall be applied in adjusting the capital cost of the

said integrated mine(s).

CHAPTER-3

PROCEDURE FOR TARIFF DETERMINATION

8. Tariff determination

(1) Tariff in respect of a generating station and emission control system, wherever applicable, may

be determined for the whole of the generating station or unit thereof, and tariff in respect of a

transmission system may be determined for the whole of the transmission system or element thereof

or associated communication system:

Provided that:

(i) In case of commercial operation of all the units of a generating station or all elements of a

transmission system prior to 1.4.2024, the generating company or the transmission licensee, as

the case may be, shall file a consolidated petition in respect of the entire generating station or

transmission system for the purpose of determination of tariff for the period from 1.4.2024 to

31.3.2029:

(ii) Tariff of the associated communication system forming part of the transmission system which

has achieved commercial operation prior to 1.4.2014 shall be as per the methodology approved

by the Commission prior to 1.4.2014.

(iii) The generating company shall file an application for determination of supplementary tariff for

the emission control system installed in a coal or lignite based thermal generating station in

accordance with these regulations not later than 90 days from the date of operation of such

emission control system.

22
(2) Where only a part of the generation capacity of a generating station is tied up for supplying

power to the beneficiaries through a long term power purchase agreement, the units for such part

capacity shall be clearly identified and, in such cases, the tariff shall be determined for such identified

capacity. Where the unit(s) corresponding to such part capacity cannot be identified, the tariff of the

generating station may be determined with reference to the capital cost of the entire project, but the

tariff so determined shall be applicable corresponding to the part capacity contracted for supply to

the beneficiaries.

(3) In case of expansion of the existing generating station, the tariff shall be determined for the

expanded capacity in accordance with these regulations:

Provided that the common infrastructure of the existing generating station, shall be utilized for

the expanded capacity and the benefit of new technology in the expanded capacity, as determined by

the Commission, shall be extended to the existing capacity.

(4) Assets installed for implementation of the revised emission standards shall form part of the

existing generation project, and the tariff thereof shall be determined separately in accordance with

the application filed under the 5th proviso to Clause (1) of Regulation 9 of these Regulations.

(5) Energy charge component of the tariff of the generating station getting coal or lignite from the

integrated mine shall be determined based on the input price of coal or lignite, as the case may be,

from such integrated mines:

Provided that the generating company shall maintain the account of the integrated mine

separately and submit the cost of the integrated mine, in accordance with these regulations, duly

certified by the Auditor.

(6) Tariff of generating station using coal washery rejects developed by Central or State PSUs or

Joint Venture between a Government Company and a company other than a Government Company

23
shall be determined in accordance with these regulations:

Provided that in case of a Joint Venture between a Government Company and a Company

other than the Government Company, the shareholding of the company other than the Government

Company either directly or through any of its subsidiary companies or associate companies shall not

exceed 26% of the paid up share capital:

Provided further that the energy charge component of the tariff of such generating station or

unit thereof shall be determined based on the fixed cost and the variable cost of the coal washery

project:

Provided also that the Gross Calorific Value of coal rejects shall be measured jointly by the

generating company and the beneficiaries.

(7) In the case of multi-purpose hydro schemes, with irrigation, flood control and power

components, the capital cost chargeable to the power component of the scheme only shall be

considered for the determination of tariff.

(8) If an existing transmission project is granted a licence under section 14 of the Act, read with

clause (c) of Regulation 6 of the Central Electricity Regulatory Commission (Terms and Conditions

of grant of Transmission Licence for Inter-State Transmission of electricity and related matters)

Regulations, 2009, the tariff of such project shall be applicable from the date of grant of transmission

licence or from the date as indicated in the transmission licence, as the case may be. In such cases,

the applicant shall file a petition as per Annexure-I (Part III) to these regulations, clearly demarcating

the assets which form part of the business of generation and transmission, the value of such assets,

source of funding and other relevant details after adjusting the cumulative depreciation and loan

repayment, duly certified by the Auditor.

24
9. Application for determination of tariff

(1) The generating company or the transmission licensee may make an application for

determination of tariff for a new generating station or unit thereof or transmission system or element

thereof in accordance with these Regulations within 90 days from the actual date of commercial

operation:

Provided that where the transmission system comprises various elements, the transmission

licensee shall file an application for determination of tariff for a group of elements on incurring of

expenditure of not less than Rs. 100 Crore or 70% of the cost envisaged in the Investment Approval,

whichever is lower, as on the actual date of commercial operation:

Provided further that transmission licensees shall combine the elements of the transmission

system in the Investment Approval, which are attaining commissioning during a particular month

and declare a single COD for the combined Asset, which shall be the date of the COD of the last

element commissioned in that month and such Asset shall be treated as single Asset for tariff

purposes.

Provided further that the generating company or the transmission licensee, as the case may

be, shall submit an Auditor Certificate and, in case of non-availability of an Auditor Certificate, a

Management Certificate duly signed by an authorised person, not below the level of Director of the

company indicating the estimated capital cost incurred as on the date of commercial operation and

the projected additional capital expenditure for respective years of the tariff period 2024-29:

Provided that for a new generating station or unit thereof or transmission system or element

thereof, the applicant, through a specific prayer in its application filed under Regulation 9(1) of these

regulations, may plead for an interim tariff, and the Commission may consider granting interim

tariff from the date of commercial operation after the first hearing of the application and where such

25
interim tariff of the generating station or unit thereof and the transmission system or element thereof

including communication system has been determined based on Management Certificate, the

generating company or the transmission licensee shall submit the Auditor Certificate not later than

90 days from the date of Commercial Operation:

Provided also that the generating company shall file an application for determination of

supplementary tariff for the emission control system installed in coal or lignite based thermal

generating station in accordance with these regulations not later than 90 days from the date of start

of operation of such emission control system.

(2) In case of an existing generating station or unit thereof, or transmission system or element

thereof, the application shall be made by the generating company or the transmission licensee, as the

case may be, by 30.11.2024 , based on admitted capital cost including additional capital expenditure

already admitted and incurred up to 31.3.2024 (either based on actual or projected additional capital

expenditure) and estimated additional capital expenditure for the respective years of the tariff period

2024-29 along with the true up petition for the period 2019-24 in accordance with the CERC (Terms

and Conditions of Tariff) Regulations, 2019.

(3) In case an emission control system is required to be installed in the existing generating station

or unit thereof to meet the revised emission standards, an application shall be made for the

determination of supplementary tariff (capacity charges or energy charge or both) based on the actual

capital expenditure duly certified by the Auditor.

(4) Where the generating company has the arrangement for the supply of coal or lignite from an

integrated mine(s) to one or more of its generating stations, the generating company shall file a

petition for determination of the input price of coal or lignite for determining the energy charge along

with the tariff petitions for one or more generating stations in accordance with the provision of

26
Chapter 9 of these regulations:

Provided that a generating company with integrated mine(s) shall file a petition for

determination of the input price of coal or lignite from the integrated mine(s) not later than 90 days

from the date of actual commercial operation of the integrated mine(s) in accordance with these

regulations.

(5) In case the generating company or the transmission licensee files the application as per the

timeline specified in sub-clause (1) to (4) of this Regulation, carrying cost at the simple interest rate

of 1-year SBI MCLR plus 100 basis points shall be allowed from the date of commercial operation

of the project:

Provided that in case the generating company or the transmission licensee delays in filing of

application as per the timeline specified in sub-clause (1) to (4) of this Regulation, carrying cost shall

be allowed to the generating company or the transmission licensee from the date of filing of the

application as per Regulation 10(6) and 10(7) of these regulations.

10. Determination of tariff

(1) The generating company for a specific generating station or unit thereof or for an integrated

mine or the transmission licensee for a transmission system or element thereof, as the case may be,

shall file a petition before the Commission as per Annexure-I to these regulations containing the

details of underlying assumptions for the capital expenditure and additional capital expenditure

incurred and projected to be incurred, wherever applicable.

(2) If the petition is deficient in any respect as required under Annexure-I to these regulations, the

application shall be returned to the generating company or transmission licensee, as the case may be,

for resubmission of the petition within one month of the date of return of the application after

rectifying the deficiencies as may be pointed out by the staff of the Commission.

27
(3) If the information furnished in the petition is in accordance with these regulations, the

Commission may consider granting an interim tariff of up to ninety per cent (90%) of the tariff

claimed in the case of a new generating station or unit thereof or transmission system, or element

thereof during the first hearing of the application for billing purposes till the final tariff is determined

by the Commission:

Provided that in case the final tariff determined by the Commission is lower than the interim tariff

by more than 10%, the generating company or transmission licensee shall return the excess amount

recovered from the beneficiaries or long term customers, as the case may be, with simple interest at

1.20 times of the rate worked out on the basis of 1 year SBI MCLR plus 100 basis points prevailing

as on 1st April of the financial year in which such excess recovery was made.

(4) In the case of the existing projects, the generating company or the transmission licensee, as the

case may be, shall continue to bill the beneficiaries or the long term customers at the capacity charges

or the transmission charges, respectively, as approved by the Commission and applicable as on

31.3.2024 for the period starting from 1.4.2024 till approval of final capacity charges or transmission

charges by the Commission in accordance with these regulations:

Provided that the billing for energy charges w.e.f. 1.4.2024 shall be as per the operational norms

specified in these regulations.

(5) The Commission shall grant the final tariff in the case of existing and new projects after

considering the replies received from the respondents and suggestions and objections, if any,

received from the general public and any other person permitted by the Commission, including

consumers or consumer associations.

(6) Subject to Sub-Clause (7) below, the difference between the tariff determined in accordance

with clauses (3) and (5) above and clauses (4) and (5) above, shall be recovered from or refunded to,

28
the beneficiaries or the long term customers, as the case may be, with simple interest at the rate equal

to the 1 year SBI MCLR plus 100 basis points prevailing as on 1st April of the respective year of the

tariff period, in a maximum of six equal monthly instalments;

Provided that the bills to recover or refund shall be raised by the generating company or the

transmission licensees within 45 days from the issuance of the Order.

Provided further that such interest, including that determined as per sub-clause (7) of this regulation

shall be payable till the date of issuance of the Order and no interest shall be allowed or levied during

the period of six-monthly instalments.

Provided further that in case where money is to be refunded and there is a delay in the raising

of bills by the generating company or transmission licensees beyond 45 days from the issuance of

the Order, it shall attract a late payment surcharge as applicable in accordance with these regulations.

(7) Where the capital cost approved by the Commission on the basis of projected additional capital

expenditure exceeds the actual trued up additional capital expenditure incurred on a year to year

basis by more than 10%, the generating company or the transmission licensee shall refund to the

beneficiaries or the long term customers as the case may be, the tariff recovered corresponding to

the additional capital expenditure not incurred, as approved by the Commission, along with simple

interest at 1.20 times of the rate worked out on the basis of 1 year SBI MCLR plus 100 basis points

as prevalent on 1st April of the respective year.

11. In-principle approval in specific circumstances: The generating company for a specific

generating station or for an integrated mine or the transmission licensee undertaking any additional

capitalization on account of change in law events or force majeure conditions may file petition for

in-principle approval for incurring such expenditure after prior notice to the beneficiaries or the long

term customers, as the case may be, along with underlying assumptions, estimates and justification

29
for such expenditure if the estimated expenditure exceeds 10% of the admitted capital cost of the

project or Rs.100 Crore, whichever is lower.

12. Truing up of tariff for the period 2019-24: The tariff of the generating stations, integrated

mines, and transmission systems for the period 2019-24 shall be trued up in accordance with the

provisions of Regulation 13 of the Central Electricity Regulatory Commission (Terms and

Conditions of Tariff) Regulations, 2019 along with the tariff petition for the period 2024-29. The

capital cost admitted as on 31.3.2024 based on the truing up shall form the basis of the opening

capital cost as on 1.4.2024 for the tariff determination for the period 2024-29.

13. Truing up of tariff for the period 2024-29: (1) The Commission shall carry out the truing

up exercise for the period 2024-29, along with the tariff petition filed for the next tariff period, for

the following:

a) the capital expenditure, including additional capital expenditure incurred up to 31.03.2029

as admitted by the Commission after prudence checks at the time of truing up;

b) the capital expenditure, including additional capital expenditure incurred up to 31.03.2029

on account of Force Majeure and Change in Law as admitted by the Commission;

c) the additional capital expenditure incurred up to 31.03.2029 on account of the Emission

Control System as admitted by the Commission.

(2) The input price of coal or lignite from the integrated mine(s) of the generating station(s) for the

tariff period 2024-29 shall be trued up for:

a) The capital expenditure, including additional capital expenditure incurred up to 31.03.2029

as admitted by the Commission after prudence check at the time of truing up;

b) the capital expenditure, including additional capital expenditure incurred up to 31.03.2029

30
 on account of Force Majeure and Change in Law, as admitted by the Commission.

c) The Operation and Maintenance expenses in accordance with provisions of Regulation 46

of these Regulations.

(3) The generating company for a specific generating station or for an integrated mine, or the

transmission licensee, as the case may be, shall make an application, as per Annexure -I to these

regulations, for carrying out truing up exercise in respect of the generating station or a unit thereof

or the transmission system or an element thereof by 30.11.2029.

(4) The generating company for a specific generating station or for an integrated mine, or the

transmission licensee, as the case may be, may make an application for interim truing up of tariff in

the year 2026-27 if the annual fixed cost increases by more than 20% over the annual fixed cost as

determined by the Commission for the respective years of the tariff period:

Provided that if the actual additional capital expenditure falls short of the projected additional

capital expenditure allowed under provisions of Chapter 7 of these regulations or reduction of tariff

on account of change in the rate of interest on loan or income tax rate, the generating company or

the transmission licensee, as the case may be, shall not be required to file any interim true up petition

for this purpose and shall refund to the beneficiaries or the long term customers, as the case may be,

the excess tariff recovered corresponding to the projected additional capital expenditure not incurred

or on account of change in the rate of interest on loan or income tax rate, in the same manner as

specified in Regulation 10(6) and 10(7) of these regulations, as the case may be under intimation to

the Commission:

Provided further that the generating company or the transmission licensee shall submit the

complete details along with the calculations of the refunds made to the beneficiaries or the long term

customers, as the case may be, at the time of true up.

31
(5) After truing up, if the tariff or the input price already recovered exceeds or falls short of the

tariff or the input price approved by the Commission under these regulations, the generating

company or the transmission licensee, shall refund to or recover from, the beneficiaries or the long

term customers, as the case may be, the excess or the shortfall amount, in accordance with Regulation

10(6) and 10(7) of these regulations as may be applicable.

Provided that in case of input price of coal and lignite, the generating company shall refund

such excess amount or recover the shortfall amount from the beneficiaries based on scheduled

energy.

32
 CHAPTER- 4

TARIFF STRUCTURE

14. Components of Tariff: (1) The tariff for the supply of electricity from a thermal generating

station shall comprise two parts, namely, capacity charge (for recovery of annual fixed cost

consisting of the components as specified in Regulation 15 of these regulations) and energy charge

(for recovery of primary and secondary fuel cost and cost of limestone and any other reagent, where

applicable as specified in Regulation 16 of these regulations).

(2) The Supplementary tariff consisting of supplementary capacity charges and supplementary

energy charges, on account of the implementation of revised emission standards in existing

generating stations or new generating stations, as the case may be, shall be determined by the

Commission separately.

(3) The capacity charge and energy charge of a generating station shall be determined in

accordance with the provisions of Chapter 11 of these regulations. The input price of coal or

lignite from the integrated mine, as determined in accordance with the provisions of Chapter 9 of

these regulations, shall form part of the energy charge of the generating station.

(4) The tariff for the supply of electricity from a hydro generating station shall comprise a

capacity charge and an energy charge to be derived in the manner specified in Regulation 65 or

66 of these regulations, as may be applicable, for recovery of the annual fixed cost consisting of

the components referred to in Regulation 15 of these regulations.

(5) The tariff for transmission of electricity on inter-State transmission system shall comprise

transmission charges for recovery of annual fixed cost consisting of the components specified in

Regulation 15 of these regulations.

33
15. Capacity Charges: (1) The capacity charges shall be derived on the basis of annual fixed

costs. The Annual Fixed Cost (AFC) of a generating station or a transmission system, including a

communication system, shall consist of the following components:

(a) Return on equity;

(b) Interest on loan capital;

(c) Depreciation;

(d) Interest on working capital; and

(e) Operation and maintenance expenses:

Provided that Special Allowance in lieu of R&M, where opted in accordance with

Regulation 28 of these regulations, shall be recovered separately and shall not be considered for

computation of working capital.

(2) Supplementary Capacity Charges: Supplementary capacity charges shall be derived on the

basis of the Annual Fixed Cost for emission control system (AFCe). The Annual Fixed Cost for the

emission control system shall consist of the components as listed in Sub-clauses (a) to (e) of Clause

(1) of this Regulation.

16. Energy Charges: Energy charges shall be derived on the basis of the landed fuel cost (LFC)

of a generating station (excluding hydro) and shall consist of the following costs:

(a) Landed Fuel Cost of primary fuel;

(b) Cost of secondary fuel oil consumption; and

(c) Cost of limestone or any other reagent, as applicable:

Provided that any refund of taxes and duties along with any amount received on account of

34
penalties from the fuel supplier shall be adjusted in fuel cost:

Provided further that the supplementary energy charges, if any, on account of meeting the

revised emission standards in case of a thermal generating station shall be determined separately by

the Commission as per Regulation 64 of these regulations.

Provided also that in case of supply of coal or lignite from the integrated mine(s), the landed

cost of primary fuel shall be based on the input price of coal or lignite, as the case may be, as

computed in accordance with these regulations.

17. Special Provisions for Tariff for Thermal Generating Station which have Completed 25

Years of Operation from Date of Commercial Operation: In respect of a thermal generating

station that has completed 25 years of operation from the date of commercial operation and the power

purchase agreement for supply of electricity to beneficiaries from such generating station is not

extended, the generating company and the beneficiary may agree on an arrangement, including

provisions for target availability and incentive, where in addition to the energy charge, capacity

charges determined under these regulations shall also be recovered based on scheduled generation.

35
 CHAPTER – 5

CAPITAL STRUCTURE

18. Debt-Equity Ratio: (1) For new projects, the debt-equity ratio of 70:30 as on date of

commercial operation shall be considered. If the equity actually deployed is more than 30% of the

capital cost, equity in excess of 30% shall be treated as normative loan:

Provided that:

i. where equity actually deployed is less than 30% of the capital cost, actual equity shall be

considered for determination of tariff:

ii. the equity invested in foreign currency shall be designated in Indian rupees on the date of

each investment:

iii. any grant obtained for the execution of the project shall not be considered as a part of

capital structure for the purpose of debt: equity ratio.

Explanation-The premium, if any, raised by the generating company or the transmission licensee, as

the case may be, while issuing share capital and investment of internal resources created out of its

free reserve for the funding of the project, shall be reckoned as paid up capital for the purpose of

computing return on equity, only if such premium amount and internal resources are actually utilised

for meeting the capital expenditure of the generating station or the transmission system.

(2) The generating company or the transmission licensee, as the case may be, shall submit the

resolution of the Board of the company or the approval of the competent authority in other cases

regarding the infusion of funds from internal resources in support of the utilization made or proposed

to be made to meet the capital expenditure of the generating station or the transmission system

including communication system, as the case may be.

36
(3) In the case of the generating station and the transmission system, including the communication

system declared under commercial operation prior to 1.4.2024, the debt-equity ratio allowed by the

Commission for the determination of tariff for the period ending 31.3.2024 shall be considered:

Provided that in the case of a generating station or a transmission system, including a

communication system which has completed its useful life as on 1.4.2024 or is completing its useful

life during the 2024-29 tariff period, if the equity actually deployed is more than 30% of the capital

cost, equity in excess of 30% shall not be taken into account for tariff computation;

Provided further that in case of projects owned by Damodar Valley Corporation, the debt:

equity ratio shall be governed as per sub-clause (ii) of clause (2) of Regulation 96 of these

regulations.

(4) In the case of the generating station and the transmission system, including communication

system declared under commercial operation prior to 1.4.2024, but where debt: equity ratio has not

been determined by the Commission for determination of tariff for the period ending 31.3.2024, the

Commission shall approve the debt: equity ratio in accordance with clause (1) of this Regulation.

(5) Any expenditure incurred or projected to be incurred on or after 1.4.2024 as may be admitted by

the Commission as additional capital expenditure for determination of tariff, and renovation and

modernisation expenditure for life extension shall be serviced in the manner specified in clause (1)

of this Regulation.

(6) Any expenditure incurred for the emission control system during the tariff period as may be

admitted by the Commission as additional capital expenditure for determination of supplementary

tariff, shall be serviced in the manner specified in clause (1) of this Regulation.

37
 CHAPTER-6

COMPUTATION OF CAPITAL COST

19. Capital Cost: (l) The Capital cost of the generating station or the transmission system, as the

case may be, as determined by the Commission after prudence checks in accordance with these

regulations shall form the basis for the determination of tariff for existing and new projects.

(2) The Capital Cost of a new project shall include the following:

(a) The expenditure incurred or projected to be incurred up to the date of commercial

operation of the project;

(b) Interest during construction and financing charges, on the loans (i) being equal to 70% of

the funds deployed and, in the event actual equity is in excess of 30% on a pari-passu

basis, by treating the excess equity over and above 30% of the funds deployed as a

normative loan, or (ii) being equal to the actual amount of the loan in the event of actual

equity being less than 30% of the funds deployed;

(c) Any gain or loss on account of foreign exchange risk variation pertaining to the loan

amount availed during the construction period;

(d) Interest during construction and incidental expenditure during construction as computed

in accordance with these regulations;

(e) Capitalised initial spares subject to the ceiling rates in accordance with these regulations;

(f) Expenditure on account of additional capitalization and de-capitalisation determined in

accordance with these regulations;

(g) Adjustment of revenue due to the sale of infirm power in excess of fuel cost prior to the

date of commercial operation as specified under Regulation 6 of these regulations;

38
 (h) Adjustment of revenue earned by the transmission licensee by using the assets before the

date of commercial operation;

(i) Capital expenditure on account of ash disposal and utilization including handling and

transportation facility;

(j) Capital expenditure incurred towards railway infrastructure and its augmentation for

transportation of coal up to the receiving end of the generating station but does not include

the transportation cost and any other appurtenant cost paid to the railway;

(k) Capital expenditure on account of biomass handling equipment and facilities, for co-firing;

(l) Capital expenditure on account of emission control system necessary to meet the revised

emission standards and sewage treatment plant;

(m) Expenditure on account of the fulfilment of any conditions for obtaining environment

clearance for the project;

(n) Expenditure on account of change in law and force majeure events; and

(o) Capital cost incurred or projected to be incurred by a thermal generating station, on account

of implementation of the norms under the Perform, Achieve and Trade (PAT) scheme of

the Government of India shall be considered by the Commission subject to sharing of

benefits accrued under the PAT scheme with the beneficiaries.

(p) Expenditure required to enable flexible operation of the generating station at lower loads.

(3) The Capital cost of an existing project shall include the following:

(a) Capital cost admitted by the Commission prior to 1.4.2024 duly trued up by excluding

liability, if any, as on 1.4.2024;

39
 (b) Additional capitalization and de-capitalization for the respective year of tariff as

determined in accordance with these regulations;

(c) Capital expenditure on account of renovation and modernisation as admitted by this

Commission in accordance with these regulations;

(d) Capital expenditure on account of ash disposal and utilization, including handling and

transportation facility;

(e) Capital expenditure incurred towards railway infrastructure and its augmentation for

transportation of coal up to the receiving end of generating station but does not include

the transportation cost and any other appurtenant cost paid to the railway;

(f) Capital cost incurred or projected to be incurred by a thermal generating station, on

account of implementation of the norms under the Perform, Achieve and Trade (PAT)

scheme of the Government of India shall be considered by the Commission subject to

sharing of benefits accrued under the PAT scheme with the beneficiaries;

(g) Expenditure required to enable flexible operation of the generating station at lower loads;

(h) Capital expenditure on account of biomass handling equipment and facilities, for co-

firing; and

(i) Expenditure on account of change in law and force majeure events;

(4) The capital cost in case of existing or new hydro generating stations shall also include:

(a) cost of approved rehabilitation and resettlement (R&R) plan of the project in conformity

with National R&R Policy and R&R package as approved; and

(b) cost of the developer's 10% contribution towards the Rajiv Gandhi Grameen Vidyutikaran

Yojana (RGGVY) and Deendayal Upadhyaya Gram Jyoti Yojana (DDUGJY) project in

40
 the affected area.

(c) For uninterrupted and timely development of Hydro projects, expenditure incurred

towards developing local infrastructure in the vicinity of the power plant not exceeding

Rs. 10 lakh/MW shall be considered as part of the Capital cost, and in case the same work

is covered under budgetary support provided by the Government of India, the funding of

such works shall be adjusted on receipt of such funds.

Provided that such funds shall be allowed only if the funds are spent through Indian

Governmental Instrumentality;

(5) For Projects acquired through NCLT proceedings under the Insolvency and Bankruptcy Code,

2016, the following shall be considered while approving Capital Costs for the determination of tariff:

(a) For projects already under operation, historical GFA of the project acquired or the

acquisition cost paid by the generating company, whichever is lower;

(b) For considering the historical GFA for the purpose of Sub-Clause (a) above, the same

shall be the capital cost approved by the appropriate commission till the date of

acquisition;

Provided that in the absence of any prior approved capital cost of an

Appropriate Commission, the Commission shall consider the same on the basis of audited

accounts subject to prudence check;

Provided further, that in case additional capital expenditure is required post

acquisition of an already operational project, the same shall be considered under the

provisions of Chapter 7 of these Regulations;

(c) In case any under construction project is acquired that has yet to achieve commercial

41
 operation, the acquisition cost or the actual audited cost incurred till the date of

acquisition, whichever is lower, shall be considered and;

(d) any additional capital expenditure incurred post acquisition of such project up to the date

of commercial operation of the project in line with the investment approval of the Board

of Directors of the generating company or the transmission licensees shall also be

considered on a case to case basis subject to prudence check.

Provided that post commercial operation, additional capital expenditure shall be

allowed under the provisions of Chapter 7 of these Regulations.

(6) The following shall be excluded from the capital cost of the existing and new projects:

(a) The assets forming part of the project but not in use, as declared in the tariff petition;

(b) De-capitalised Assets after the date of commercial operation on account of obsolescence;

(c) De-capitalised Assets on account of upgradation or shifting from one project to another

project:

Provided that in case such an asset is recommended for further utilisation by the

Regional Power Committee in consultation with CTU, such asset shall be de-capitalised

from the original project only after its redeployment;

Provided further that unless shifting of an asset from one project to another is of

a permanent nature, there shall be no de-capitalization of the concerned assets.

(d) In the case of hydro generating stations, any expenditure incurred or committed to be

incurred by a project developer for getting the project site allotted by the State Government

by following a transparent process;

(e) Proportionate cost of land of the existing generation or transmission project, as the case

42
 may be, which is being used for generating power from a generating station based on

renewable energy as may be permitted by the Commission; and

(f) Any grant received from the Central or State Government or any statutory body or authority

for the execution of the project that does not carry any liability of repayment.

20. Prudence Check of Capital Cost: The following principles shall be adopted for prudence

check of capital cost of the existing or new projects:

(1) In the case of the thermal generating station and the transmission system, the prudence check

of capital cost shall include scrutiny of the capital expenditure, in light of the capital cost of similar

projects based on past historical data, wherever available, reasonableness of the financing plan,

interest during construction, incidental expenditure during construction, use of efficient

technology, cost over-run and time over-run, procurement of equipment and materials through

competitive bidding as given in Regulation 101 below and such other matters as may be considered

appropriate by the Commission:

Provided that, while carrying out the prudence check, the Commission shall also examine

whether the generating company or transmission licensee, as the case may be, has been prudent in

its judgments and decisions in the execution of the project.

(2) The Commission may, for the purpose of vetting of capital cost of hydro generating stations,

appoint an independent agency or an expert body:

Provided that the Designated Independent Agency already appointed under the guidelines

issued by the Commission under Central Electricity Regulatory Commission (Terms and

Conditions of Tariff) Regulations, 2009 shall continue till completion of the assigned project.

(3) Where the power purchase agreement entered into between the generating company and the

43
 beneficiaries provides for the ceiling of actual capital expenditure, the Commission shall take into

consideration such ceiling for prudence check.

(4) The generating company or the transmission licensee, as the case may be, shall furnish the

capital cost for the execution of the existing and new projects as per Annexure-I to these regulations

along with tariff petition for the purpose of creating a database of benchmark capital cost of various

components.

21. Interest During Construction (IDC) and Incidental Expenditure during Construction

(IEDC)

(1) Interest during construction (IDC) shall be computed considering the actual loan and normative

loan after taking into account the prudent phasing of funds up to actual COD:

Provided that IDC on a normative loan corresponding to excess equity over 30% of funds

deployed shall be allowed only in cases where the actual infusion of equity on a pari-passu basis is

more than 30% of total funds deployed and shall be computed on a quarterly basis.

Provided further that in case IDC on normative loan is to be allowed prior to infusion of actual

loan, rate of interest for computing such IDC shall be equal to 1-year SBI MCLR as prevailing on

1st April of the respective year.

Provided further that IDC on normative loan, post infusion of actual loan shall be computed

based on WAROI for that respective quarter.

(2) Incidental expenditure during construction (IEDC) shall be computed from the zero date, taking

into account pre-operative expenses up to actual COD:

Provided that any revenue earned during the construction period up to actual COD on account

of interest on deposits or advances or any other receipts shall be taken into account for reduction in

44
incidental expenditure during construction.

(3) In case of additional costs on account of IDC and IEDC due to delay in achieving the COD, the

generating company for a specific generating station or for an integrated mine or the transmission

licensee, as the case may be, shall be required to furnish detailed justifications with supporting

documents for such delay, including prudent phasing of funds in the case of IDC and details of IEDC

during the period of delay and liquidated damages recovered or recoverable corresponding to the

delay.

(4) If the delay in achieving the COD is not attributable to the generating company or the

transmission licensee, such additional IDC and IEDC may be allowed after a prudence check, and

the liquidated damages, if any, recovered from the contractor or supplier or agency shall be adjusted

to the capital cost of the generating station or the transmission system, as the case may be.

(5) If the delay in achieving the COD is attributable either in entirety or in part to the generating

company or the transmission licensee or its contractor or supplier or agency, in such cases, IDC and

IEDC due to such delay may be disallowed after a prudence check, either in entirety or on a pro-rata

basis corresponding to the period of delay not condoned vis-à-vis total implementation period, and

the liquidated damages, if any, recovered from the contractor or supplier or agency shall be retained

by the generating company or the transmission licensee, in the same proportion of delay not

condoned vis-à-vis total implementation period.

[Note: For e.g.: In case a project was scheduled to be completed in 48 months and is actually

completed in 60 months. Out of 12 months of time overrun, if only 6 months of time overrun is

condoned, the allowable IDC and IEDC shall be computed by considering the total IDC and IEDC

incurred for 60 months and allowed in the proportion of 54 months over 60 month period.]

45
Provided that in cases where delay in achieving COD is beyond six months from SCOD on account

of delay in obtaining approval of any of the following activities namely, i) forest clearance, ii) NHAI

clearance, or iii) Railways permission, a time overrun maximum up to 95% shall be allowed after

prudence check.

(6) For the purpose of Clauses (4) and (5) of this Regulation, IDC on actual loan and normative

loan shall be considered in accordance with the normative debt-equity ratio specified under clause

(1) of Regulation 18 of these regulations.

22. Controllable and Uncontrollable factors: The following shall be considered as controllable

and uncontrollable factors for deciding time overrun, cost escalation, IDC and IEDC of the new

projects:

(1) The "controllable factors" shall include but shall not be limited to the following:

a. Efficiency in the implementation of the new projects not involving an approved change

in scope of such new projects or change in statutory levies or change in law or force

majeure events; and

b. Delay in execution of the new projects on account of contractor or supplier or agency

of the generating company or transmission licensee.

(2) The "uncontrollable factors" shall include but shall not be limited to the following:

a. Force Majeure events;

b. Change in Law; and

c. Land acquisition except where the delay is attributable to the generating company or

the transmission licensee.

23. Initial Spares: Initial spares shall be capitalised as a percentage of the Plant and Machinery

46
cost, subject to the following ceiling norms:

(a) Coal-based/lignite-fired thermal generating stations - 4.0%

(b) Gas Turbine/ Combined Cycle thermal generating - 4.0%

Stations
(c) Hydro generating stations including pumped storage - 4.0%
hydro generating station
(d) Transmission system

(i) Transmission line - 1.00%

(ii) Transmission Sub-station

-Green Field - 4.00%
-Brown Field - 6.00%
(iii) Series Compensation devices and HVDC Station - 4.00%
(iv) Gas Insulated Sub-station (GIS) -
-Green Field - 5.00%
-Brown Field - 7.00%
(v)) Communication system - 3.50%

(vi) Static Synchronous Compensator - 6.00%

Provided that:

i. Plant and Machinery cost shall be considered as the original project cost excluding IDC,

IEDC, Land Cost and Cost of Civil Works. The generating company and the transmission

licensee, for the purpose of estimating Plant and Machinery Costs, shall submit the break-up

of head-wise IDC and IEDC in its tariff application;

ii. where the generating station has any transmission equipment forming part of the generation

project, the ceiling norms for initial spares for such equipment shall be as per the ceiling

norms specified for the transmission system under these regulations.

47
iii. where the emission control system is installed, the norms of initial spares specified in this

Regulation for coal or lignite based thermal generating stations, as the case may be, shall

apply.

iv. Initial spares of high voltage underground cables used for the transmission system shall be

allowed based on actuals on a case-to-case basis after carrying out due a prudence check.

48
 CHAPTER – 7

COMPUTATION OF ADDITIONAL CAPITAL EXPENDITURE

24. Additional Capitalisation within the original scope and up to the cut-off date

(1) The additional capital expenditure in respect of a new project or an existing project incurred or

projected to be incurred, on the following counts within the original scope of work, after the date of

commercial operation and up to the cut-off date may be admitted by the Commission, subject to

prudence check:

(a) Payment made towards admitted liabilities for works executed up to the cut-off date;

(b) Works deferred for execution;

(c) Procurement of initial capital spares within the original scope of work, in accordance

with the provisions of Regulation 23 of these regulations;

(d) Payment against the award of arbitration or for compliance with the directions or order

of any statutory authority or order or decree of any court of law;

(e) Change in law or compliance with any existing law which is not provided for in the

original scope of work;

(f) For uninterrupted and timely development of Hydro projects, expenditure incurred

towards developing local infrastructure in the vicinity of the power plant not exceeding

Rs. 10 lakh/MW shall be considered as part of capital cost and in case the same work

is covered under budgetary support provided by Government of India, the funding of

such works shall be adjusted on receipt of such funds;

Provided that such expenditure shall be allowed only if the expenditure is incurred

through Indian Governmental Instrumentality; and

49
 (g) Force Majeure events.

Provided that in case of any replacement of the assets, the additional capitalization shall be

worked out after adjusting the gross fixed assets and cumulative depreciation of the assets replaced

on account of de-capitalization.

(2) The generating company or the transmission licensee, as the case may be shall submit the

details of works asset wise/work wise included in the original scope of work along with estimates of

expenditure, liabilities recognized to be payable at a future date and the works deferred for execution.

25. Additional Capitalisation within the original scope and after the cut-off date:

(1) The additional capital expenditure incurred or projected to be incurred in respect of an

existing project or a new project on the following counts within the original scope of work and

after the cut-off date may be admitted by the Commission, subject to prudence check:

(a) Payment made against award of arbitration or for compliance with the directions or

order of any statutory authority, or order or decree of any court of law;

(b) Change in law or compliance with any existing law which is not provided for in the

original scope of work;

(c) Deferred works relating to ash pond or ash handling system or raising of ash dyke in

the original scope of work;

(d) Payment made towards liability admitted for works within the original scope executed

prior to the cut-off date;

(e) Force Majeure events;

(f) Works within original scope executed after the cut-off date and admitted by the

Commission, to the extent of actual payments made; and

50
 (2) In case of replacement of assets deployed under the original scope of the existing project after

the cut-off date, the additional capitalization may be admitted by the Commission after making

necessary adjustments in the gross fixed assets and the cumulative depreciation, subject to

prudence check on the following grounds:

(a) Assets whose useful life is not commensurate with the useful life of the project and

such assets have been fully depreciated in accordance with the provisions of these

regulations;

(b) The replacement of the asset or equipment is necessary on account of a change in law

or Force Majeure conditions;

(c) The replacement of such asset or equipment is necessary on account of obsolescence

of technology; and

(d) The replacement of such asset or equipment has otherwise been allowed by the

Commission.

(e) The additional expenditure, excluding recurring expenses covered in O&M expenses,

involved in relation to the renewal of lease of lease hold land on case to case basis.

Provided that any claim of additional capitalisation with respect to the replacement of assets under

the original scope and on account of obsolescence of technology, less than Rs. 20 lakhs shall not be

considered as part of Capital cost and shall be met through normative O&M expenses.

26. Additional Capitalisation beyond the original scope

(1) The capital expenditure, in respect of the existing generating station or the transmission system,

including the communication system, incurred or projected to be incurred on the following counts

beyond the original scope, may be admitted by the Commission, subject to prudence check:

51
(a) Payment made against award of arbitration or for compliance of order or directions of any

statutory authority, or order or decree of any court of law;

(b) Change in law or compliance of any existing law;

(c) Force Majeure events;

(d) Need for higher security and safety of the plant as advised or directed by appropriate

Indian Government Instrumentality or statutory authorities responsible for national or

internal security;

(e) Deferred works relating to ash pond or ash handling system or raising of ash dyke in

addition to the original scope of work, on case to case basis:

Provided also that if any expenditure has been claimed under Renovation and

Modernisation (R&M) or repairs and maintenance under O&M expenses, the same shall

not be claimed under this Regulation;

(f) Usage of water from the sewage treatment plant in the thermal generating station.

(g) Works required towards biomass handling system to enable biomass co-firing and towards

enabling flexible operation of the generating station as may be required.

(h) Works pertaining to Railway Infrastructure and its augmentation for transportation of coal

up to the receiving end of the generating station (excluding any transportation cost and any

other appurtenant cost paid to railways) that are not covered under Regulation 24, 25 and

27, but shall result in better fuel management and can lead to a reduction in operation costs,

or shall have other tangible benefits:

Provided that the generating company shall have to mandatorily seek prior

approval of the Commission before implementing such works based on a detailed cost-

52
 benefit analysis of such schemes;

(i) Any additional capital expenditure which has become necessary for efficient operation of

generating station or transmission system as the case may be, including the works required

towards projects acquired through NCLT process. The claim shall be substantiated with the

technical justification and cost benefit analysis.

(2) Any claim of additional capitalisation less than Rs. 20 lakhs shall not be considered under

Clause (1) of this regulation and shall be met through normative O&M expenses.

(3) In case of de-capitalisation of assets of a generating company or the transmission licensee, as

the case may be, the original cost of such asset as on the date of de-capitalisation shall be deducted

from the value of gross fixed asset and corresponding loan as well as equity shall be deducted from

outstanding loan and the equity respectively in the year such de-capitalisation takes place with

corresponding adjustments in cumulative depreciation and cumulative repayment of loan, duly

taking into consideration the year in which it was capitalised.

Provided that in cases where an asset forming part of a scheme is de-capitalised and wherein

the historical value of such asset is not available, the value of de-capitalisation shall be computed by

de-escalating the value of the new asset by 5% per year until the year of capitalisation of the old

asset subject to a minimum of 10% of the replacement cost of the asset.

27. Additional Capitalisation on account of Renovation and Modernisation

(1) The generating company intending to undertake renovation and modernization (R&M) of the

generating station or unit thereof for the purpose of extension of life beyond the originally recognised

useful life for the purpose of tariff, shall file a petition before the Commission for approval of the

proposal with a Detailed Project Report giving complete scope, justification, cost-benefit analysis,

estimated life extension from a reference date, financial package, phasing of expenditure, schedule

53
of completion, reference price level, estimated completion cost including foreign exchange

component, if any, and any other information considered to be relevant by the generating company

or the transmission licensee:

Provided that the generating company making the applications for renovation and

modernization (R&M) shall not be eligible for Special Allowance under Regulation 28 of these

regulations;

Provided further that the generating company intending to undertake renovation and

modernization (R&M) shall seek the consent of the beneficiaries for such renovation and

modernization (R&M) and submit the response of the beneficiaries along with the Petition.

(2) Where the generating company, as the case may be, makes an application for approval of its

proposal for renovation and modernisation (R&M), approval may be granted after due consideration

of the reasonableness of the proposed cost estimates, financing plan, schedule of completion, interest

during construction, use of efficient technology, cost-benefit analysis, expected duration of life

extension, the response of the beneficiaries or long term customers, and such other factors as may

be considered relevant by the Commission.

(3) In the case of gas/ liquid fuel based open/ combined cycle thermal generating station after 25

years of operation from the date of commercial operation, any additional capital expenditure which

has become necessary for the renovation of gas turbines/ steam turbines or additional capital

expenditure necessary due to obsolescence or the non-availability of spares for efficient operation of

the stations may be allowed subject to a prudence check:

Provided that any expenditure included in the renovation and modernisation (R&M) on

consumables and cost of components and spares, which is generally covered in the O&M expenses

during the major overhaul of gas turbines shall be suitably deducted from the expenditure to be

54
allowed after prudence check.

(4) After completion of the renovation and modernisation (R&M), the generating company, as the

case may be, shall file a petition for determination of tariff. Expenditure incurred or projected to be

incurred and admitted by the Commission after a prudence check and after deducting the

accumulated depreciation already recovered from the admitted project cost shall form the basis for

the determination of tariff.

28. Special Allowance for Coal-based/Lignite fired Thermal Generating station

(1) In the case of coal-based/ lignite fired thermal generating stations, the generating company,

instead of availing renovation and modernization (R&M), may opt to avail of a 'special allowance'

in accordance with the norms specified in this Regulation, as compensation for meeting the

requirement of expenses towards any additional capital expenditure covered in Regulations 24, 25,

26 and 27 except for capital expenditure arising out of change in law, award of arbitration or for

compliance of the directions or order of any statutory authority, or order or decree of any court of

law, and force majeure after completion of 25 years from the date of Commercial operation of the

generating station or a unit thereof and in such an event, an upward revision of the capital cost shall

not be allowed and the applicable operational norms shall not be relaxed but the Special Allowance

shall be included in the annual fixed cost:

Provided that such option shall not be available for a generating station or unit thereof for

which renovation and modernization has been undertaken and the expenditure has been admitted by

the Commission before the commencement of these regulations, or for a generating station or unit

which is in a depleted condition or operating under relaxed operational and performance norms;

Provided further that special allowance shall also be available for a generating station which

has availed the Special Allowance during the tariff period 2009-14 or 2014-19 or 2019-24 as

55
applicable from the date of completion of the useful life.

(2) The Special Allowance admissible to a generating station shall be @ Rs 10.75 lakh per MW

per year for the tariff period.

(3) In the event of a generating station availing of Special Allowance, the expenditure incurred

upon or utilized from Special Allowance shall be maintained separately by the generating station,

and details of the same shall be made available to the Commission as and when directed.

(4) The Special Allowance allowed under this Regulation shall be transferred to a separate fund

for utilization towards Renovation & Modernisation and additional capitalisation as per clause (1)

above, and the expenditure incurred or utilized from the special allowance shall be made

available to the Commission as and when directed.

29. Additional Capitalization on account of Revised Emission Standards: (1) A generating

company requiring to incur additional capital expenditure in the existing generating station for

compliance with the revised emissions standards shall share its proposal with the beneficiaries and

file a petition for undertaking such additional capitalization.

(2) The proposal under clause (1) above shall contain details of the proposed technology as

specified by the Central Electricity Authority, scope of the work, phasing of expenditure, schedule

of completion, estimated completion cost including foreign exchange component, if any, detailed

computation of indicative impact on tariff to the beneficiaries, and any other information

considered to be relevant by the generating company.

(3) Where the generating company makes an application for approval of additional capital

expenditure on account of the implementation of revised emission standards, the Commission

may grant approval after due consideration of the reasonableness of the cost estimates, financing

56
plan, schedule of completion, interest during construction, use of efficient technology, cost-

benefit analysis, and such other factors as may be considered relevant by the Commission.

(4) After completion of the implementation of revised emission standards, the generating

company shall file a petition for determination of tariff. Any expenditure incurred or projected to

be incurred and admitted by the Commission after prudence check based on the reasonableness

of the cost and impact on operational parameters shall form the basis of the determination of tariff.

(5) Un-discharged liability, if any, on account of the emission control system shall be allowed

as additional capital expenditure during the year it is discharged, subject to prudence check.

57
 CHAPTER-8

COMPUTATION OF ANNUAL FIXED COST

30. Return on Equity: (1) Return on equity shall be computed in rupee terms, on the equity base

determined in accordance with Regulation 18 of these regulations.

(2) Return on equity for existing project shall be computed at the base rate of 15.50% for

thermal generating station, transmission system including communication system and run-of-

river hydro generating station and at the base rate of 16.50% for storage type hydro generating

stations, pumped storage hydro generating stations and run-of- river generating station with

pondage;

(3) Return on equity for new project achieving COD on or after 01.04.2024 shall be computed

at the base rate of 15.00% for the transmission system, including the communication system, at

the base rate of 15.50% for Thermal generating station and run-of-river hydro generating station

and at the base rate of 17.00% for storage type hydro generating stations, pumped storage hydro

generating stations and run-of-river generating station with pondage;

Provided that return on equity in respect of additional capitalization beyond the original

scope, including additional capitalization on account of the emission control system, Change in

Law, and Force Majeure shall be computed at the base rate of one-year marginal cost of lending

rate (MCLR) of the State Bank of India plus 350 basis points as on 1st April of the year, subject

to a ceiling of 14%;

Provided further that:

i. In case of a new project, the rate of return on equity shall be reduced by 1.00% for such

period as may be decided by the Commission if the generating station or transmission

58
 system is found to be declared under commercial operation without commissioning of any

of the Free Governor Mode Operation (FGMO), data telemetry, communication system up

to load dispatch centre or protection system based on the report submitted by the respective

RLDC;

ii. in case of an existing generating station, as and when any of the requirements under (i)

above of this Regulation are found lacking based on the report submitted by the concerned

RLDC, the rate of return on equity shall be reduced by 1.00% for the period for which the

deficiency continues;

iii. in the case of a thermal generating station:

a) rate of return on equity shall be reduced by 0.25% in case of failure to achieve the

ramp rate as specified under Regulation 45(9) of IEGC Regulations, 2023.

b) an additional rate of return on equity of 0.125% shall be allowed for every

incremental ramp rate of 0.50% per minute achieved over and above the ramp rate

specified by Central Electricity Authority, subject to the ceiling of additional rate of

return on equity of 1.00%:

31. Tax on Return on Equity. (1) The rate of return on equity as allowed by the Commission

under Regulation 30 of these regulations shall be grossed up with the effective tax rate of the

respective financial year. The effective tax rate shall be calculated at the beginning of every financial

year based on the estimated profit and tax to be paid estimated in line with the provisions of the

relevant Finance Act applicable for that financial year to the concerned generating company or the

transmission licensee by excluding the income of non-generation or non-transmission business, as

the case may be, and the corresponding tax thereon.

Provided that in case a generating company or transmission licensee is paying

59
 Minimum Alternate Tax (MAT) under Section 115JB of the Income Tax Act, 1961, the effective

tax rate shall be the MAT rate, including surcharge and cess;

Provided further that in case a generating company or transmission licensee has

opted for Section 115BAA, the effective tax rate shall be tax rate including surcharge and cess as

specified under Section 115BAA of the Income Tax Act, 1961.

(2) The rate of return on equity shall be rounded off to three decimal places and shall be

computed as per the formula given below:

Rate of pre-tax return on equity = Base rate / (1-t)

(3) The generating company or the transmission licensee, as the case may be, shall true up the

effective tax rate for every financial year based on actual tax paid together with any additional tax

demand, including interest thereon, duly adjusted for any refund of tax including interest received

from the income tax authorities pertaining to the tariff period 2024-29 on actual gross income of any

financial year. Further, any penalty arising on account of delay in deposit or short deposit of tax

amount shall not be considered while computing the actual tax paid for the generating company or

the transmission licensee, as the case may be.

Provided that in case a generating company or transmission licensee is paying

Minimum Alternate Tax (MAT) under Section 115JB, the generating company or the transmission

licensee, as the case may be, shall true up the grossed up rate of return on equity at the end of every

financial year with the applicable MAT rate including surcharge and cess.

Provided that in case a generating company or transmission licensee is paying tax under

Section 115BAA, the generating company or the transmission licensee, as the case may be, shall true

up the grossed up rate of return on equity at the end of every financial year with the tax rate including

surcharge and cess as specified under Section 115BAA.

60
 Provided that any under-recovery or over recovery of grossed up rate on return on

equity after truing up, shall be recovered or refunded to beneficiaries or the long term customers, as

the case may be, on a year to year basis.

32. Interest on loan capital: (1) The loans arrived at in the manner indicated in Regulation 18

of these regulations shall be considered gross normative loans for the calculation of interest on loans.

(2) The normative loan outstanding as on 1.4.2024 shall be worked out by deducting the

cumulative repayment as admitted by the Commission up to 31.3.2024 from the gross normative

loan.

(3) The repayment for each of the years of the tariff period 2024-29 shall be deemed to be equal

to the depreciation allowed for the corresponding year or period. In case of de-capitalization of

assets, the repayment shall be adjusted by taking into account cumulative repayment on a pro rata

basis, and the adjustment should not exceed cumulative depreciation recovered up to the date of

de-capitalisation of such asset.

(4) Notwithstanding any moratorium period availed of by the generating company or the

transmission licensee, as the case may be, the repayment of the loan shall be considered from the

first year of commercial operation of the project and shall be equal to the depreciation allowed for

the year or part of the year.

(5) The rate of interest shall be the weighted average rate of interest calculated on the basis of the

actual loan portfolio or allocated loan portfolio;

Provided that if there is no actual loan outstanding for a particular year but the normative

loan is still outstanding, the last available weighted average rate of interest of the loan portfolio for

the project shall be considered;

61
 Provided further that if the generating station or the transmission system, as the case may

be, does not have any actual loan, then the weighted average rate of interest of the loan portfolio

of the generating company or the transmission licensee as a whole shall be considered.

Provided that the rate of interest on the loan for the installation of the emission control system

commissioned subsequent to date of commercial operation of the generating station or unit thereof,

shall be the weighted average rate of interest of the actual loan portfolio of the emission control

system, and in the absence of the actual loan portfolio, the weighted average rate of interest of the

generating company as a whole shall be considered, subject to a ceiling of 14%;

Provided further that if the generating company or the transmission licensee, as the case may

be, does not have any actual loan, then the rate of interest for a loan shall be considered as 1-year

MCLR of the State Bank of India as applicable as on April 01, of the relevant financial year.

(6) The interest on the loan shall be calculated on the normative average loan of the year by

applying the weighted average rate of interest.

(7) The changes to the terms and conditions of the loans shall be reflected from the date of such

re-financing.

33. Depreciation: (1) Depreciation shall be computed from the date of commercial operation of

a generating station or unit thereof or a transmission system or element thereof including

communication system. In the case of the tariff of all the units of a generating station or all elements

of a transmission system including the communication system for which a single tariff needs to be

determined, the depreciation shall be computed from the effective date of commercial operation of

the generating station or the transmission system taking into consideration the depreciation of

individual units:

Provided that the effective date of commercial operation shall be worked out by considering

62
the actual date of commercial operation and installed capacity of all the units of the generating

station or capital cost of all elements of the transmission system, for which a single tariff needs to

be determined.

(2) The value base for the purpose of depreciation shall be the capital cost of the asset admitted

by the Commission. In case of multiple units of a generating station or multiple elements of a

transmission system, the weighted average life for the generating station or the transmission

system shall be applied. Depreciation shall be chargeable from the first year of commercial

operation. In the case of commercial operation of the asset for a part of the year, depreciation shall

be charged on a pro rata basis.

(3) The salvage value of the asset shall be considered as 10%, and depreciation shall be allowed

up to the maximum of 90% of the capital cost of the asset:

Provided that the salvage value for IT equipment and software shall be considered as NIL

and 100% value of the assets shall be considered depreciable;

Provided further that in the case of hydro generating stations, the salvage value shall be as

provided in the agreement, if any, signed by the developers with the State Government for the

development of the generating station:

Provided also that the capital cost of the assets of the hydro generating station for the

purpose of computation of depreciated value shall correspond to the percentage of the sale of

electricity under long-term power purchase agreement at regulated tariff:

Provided also that any depreciation disallowed on account of lower availability of the

generating station or unit or transmission system, as the case may be, shall not be allowed to be

recovered at a later stage during the useful life or the extended life.

63
(4) Land other than the land held under lease and the land for a reservoir in case of a hydro

generating station shall not be a depreciable asset and its cost shall be excluded from the capital

cost while computing the depreciable value of the asset.

(5) Depreciation for Existing Projects shall be calculated annually based on the Straight Line

Method and at rates specified in Appendix-I to these regulations for the assets of the generating

station and transmission system:

Provided that the remaining depreciable value as on 31st March of the year closing after a

period of 12 years from the effective date of commercial operation of the generating station or

transmission system, as the case may be, shall be spread over the balance useful life of the assets.

Provided further that in the case of an existing hydro generating station, the generating

company, with the consent of the beneficiaries, may charge depreciation at a rate lower than that

specified in Appendix I and Appendix II to these Regulations to reduce front loading of tariff.

(6) Depreciation for New Projects shall be calculated annually based on the Straight Line Method

and at rates specified in Appendix-II to these regulations for the assets of the generating station

and transmission system:

Provided that the remaining depreciable value as on 31st March of the year closing after a

period of 15 years from the effective date of commercial operation of the generating station or the

transmission system, as the case may be, shall be spread over the balance useful life of the assets.

Provided further that in the case of a new hydro generating stations, the generating company,

with the consent of the beneficiaries, may charge depreciation at a rate lower than that specified

in Appendix II to these Regulations to reduce front loading of tariff.

(7) In the case of the existing projects, the balance depreciable value as on 1.4.2024 shall be

64
worked out by deducting the cumulative depreciation as admitted to by the Commission up to

31.3.2024 from the gross depreciable value of the assets.

(8) The generating company or the transmission licensee, as the case may be, shall submit the

details of capital expenditure proposed to be incurred during five years before the completion of

useful life along with proper justification and proposed life extension. The Commission, based on

prudence check of such submissions, shall approve the depreciation by equally spreading the

depreciable value over the balance Operational Life of the generating station or unit thereof or

fifteen years, whichever is lower, and in case of the transmission system shall equally spread the

depreciable value over the balance useful life of the Asset or 10 years whichever is higher.

(9) In case of de-capitalization of assets in respect of generating station or unit thereof or

transmission system or element thereof, the cumulative depreciation shall be adjusted by taking

into account the depreciation recovered in tariff by the de-capitalised asset during its useful

service.

(10) Where the emission control system is implemented within the original scope of the generating

station and the date of commercial operation of the generating station or unit thereof and the date

of operation of the emission control system are the same, depreciation of the generating station or

unit thereof including the emission control system shall be computed in accordance with Clauses

(1) to (9) of this Regulation.

(11) Depreciation of the emission control system of an existing generating station that is yet to

complete its useful life or a new generating station or unit thereof where the date of operation of

the emission control system is subsequent to the date of commercial operation of the generating

station or unit thereof, shall be computed annually from the date of operation of such emission

control system based on the straight line method at rates specified in Appendix- I to these

65
 regulations;

Provided that the remaining depreciable value as on 31st March of the year closing after a

period of 12 years from the date of operation of such emission control system shall be spread over

the balance period of thirteen years or balance operational life of generating station, whichever is

lower;

Provided also that in case the date of operation of the emission control system is after the 20th year

of commercial operation of the generating station or unit thereof, but before the completion of the

useful life of the generating station, the depreciation on emission control system (ECS) shall be

computed annually from the date of operation of such ECS based on the straight line method, with

a salvage value of 10% and the depreciable value shall be recovered till the operational life of the

generating station.

(12) In case the date of operation of the emission control system is subsequent to the date of

completion of the useful life of generating station commercial operation of the generating station

or unit thereof, depreciation of ECS shall be computed annually from the date of operation of such

emission control system based on the straight line method, with a salvage value of 10% and

recovered over ten years or a period mutually agreed by the generating company and the

beneficiaries, whichever is higher.

34. Interest on Working Capital: (1) The working capital shall cover:

(a) For Coal-based/lignite-fired thermal generating stations:

(i) Cost of coal or lignite, if applicable, for 10 days for pit-head generating stations and

20 days for non-pit-head generating stations for generation corresponding to the normative

annual plant availability factor or the maximum coal/lignite stock storage capacity,

whichever is lower;

66
 (ii) Limestone towards stock for 15 days corresponding to the normative annual plant

availability.

(iii) Advance payment for 30 days towards the cost of coal or lignite and limestone for

generation corresponding to the normative annual plant availability factor;

(iv) Cost of secondary fuel oil for two months for generation corresponding to the

normative annual plant availability factor, and in case of use of more than one secondary

fuel oil, cost of fuel oil stock for the main secondary fuel oil;

(v) Maintenance spares @ 20% of operation and maintenance expenses, including water

charges and security expenses;

(vi) Receivables equivalent to 45 days of capacity charge and energy charge for the sale

of electricity calculated on the normative annual plant availability factor; and

(vii) Operation and maintenance expenses, including water charges and security expenses,

for one month.

(b) For emission control system of coal or lignite based thermal generating stations:

(i) Cost of limestone or reagent towards stock for 20 days corresponding to the normative

annual plant availability factor;

(ii) Advance payment for 30 days towards the cost of reagent for generation

corresponding to the normative annual plant availability factor;

(iii) Receivables equivalent to 45 days of supplementary capacity charge and

supplementary energy charge for the sale of electricity calculated on the normative annual

plant availability factor;

(iv) Operation and maintenance expenses in respect of the emission control system for

67
 one month;

(v) Maintenance spares @20% of operation and maintenance expenses in respect of

emission control system.

(c) For Open-cycle Gas Turbine/Combined Cycle thermal generating stations:

(i) Fuel cost for 15 days corresponding to the normative annual plant availability factor,

duly taking into account the mode of operation of the generating station on gas fuel and

liquid fuel;

(ii) Liquid fuel stock for 15 days corresponding to the normative annual plant availability

factor, and in case of use of more than one liquid fuel, cost of main liquid fuel duly taking

into account mode of operation of the generating stations of gas fuel and liquid fuel;

Provided that the above shall only be allowed to generating stations that have facilities

to store liquid fuel.

(iii) Maintenance spares @ 30% of operation and maintenance expenses, including water

charges and security expenses;

(iv) Receivables equivalent to 45 days of capacity charge and energy charge for the sale

of electricity calculated on the normative plant availability factor, duly taking into account

the mode of operation of the generating station on gas fuel and liquid fuel;

(v) Operation and maintenance expenses, including water charges and security expenses,

for one month.

(d) For Hydro generating station (including Pumped Storage Hydro generating station) and

Transmission System:

(i) Receivables equivalent to 45 days of annual fixed cost;

68
 (ii) Maintenance spares @ 15% of operation and maintenance expenses including security

expenses; and

(iii) Operation and maintenance expenses, including security expenses for one month.

(2) The cost of fuel in cases covered under sub-clauses (a) and (c) of clause (1) of this Regulation

shall be based on the landed fuel cost (taking into account normative transit and handling losses in

terms of Regulation 59 of these regulations) by the generating station and gross calorific value of the

fuel as per actual weighted average for the preceding financial year in case of each financial year for

which tariff is to be determined:

Provided that in the case of a new generating station, the cost of fuel for the first financial year

shall be considered based on landed fuel cost (taking into account normative transit and handling

losses in terms of Regulation 59 of these regulations) and gross calorific value of the fuel as per

actual weighted average for three months, as used for infirm power, preceding date of commercial

operation for which tariff is to be determined.

(3) Rate of interest on working capital shall be on a normative basis and shall be considered at the

Reference Rate of Interest as on 1.4.2024 or as on 1st April of the year during the tariff period 2024-

29 in which the generating station or a unit thereof or the transmission system including

communication system or element thereof, as the case may be, is declared under commercial

operation, whichever is later:

Provided that in case of truing-up, the rate of interest on working capital shall be considered

at Reference Rate of Interest as on 1st April of each of the financial year during the tariff period

2024-29.

(4) Interest on working capital shall be payable on a normative basis, notwithstanding that the

generating company or the transmission licensee has not taken a loan for working capital from any

69
outside agency.

35. De-Commissioning

(1) In case a generating station or unit thereof, or a transmission system including

communication systems or element thereof after it is certified by CEA or CTU or any other

statutory authority, that any asset cannot be operated or needs to be replaced on account of

environmental concerns or safety issues or system upgradation or a combination of these

factors not attributable to generating company or a transmission licensee, the unrecovered

depreciable value may be allowed to be recovered on a case-to-case basis after duly adjusting

the salvage value or realisation value, whichever is higher, post disposal of such project.

Provided that the manner of recovery, including a number of instalments in which

such unrecovered depreciation will be allowed, shall be specified by the Commission on a

case-to-case basis.

Provided further that no carrying cost shall be allowed on any delay associated with

such recovery.

36. Operation and Maintenance Expenses:

(1) Thermal Generating Station: Normative Operation and Maintenance expenses of thermal

generating stations shall be as follows:

(1) Coal based and lignite fired (including those based on Circulating Fluidised Bed Combustion

(CFBC) technology) generating stations, other than the generating stations or units referred to in

clauses (2), (4) and (5) of this Regulation:

70
 (in Rs Lakh/MW)
200/210/ 250 300/330/ 350 800 MW
500 MW 600 MW
Year MW MW Series and
Series Series
Series Series above
FY 2024-25 40.92 34.04 27.17 25.78 23.20
FY 2025-26 43.07 35.83 28.60 27.13 24.42
FY 2026-27 45.33 37.71 30.10 28.56 25.70
FY 2027-28 47.71 39.69 31.68 30.06 27.05
FY 2028-29 50.21 41.78 33.34 31.64 28.47

Provided also that operation and maintenance expenses of generating station having a unit

size of less than 200 MW not covered above shall be determined on a case-to-case basis.

(2) Tanda TPS:

(in Rs Lakh/MW)
Year Tanda TPS (Unit 1)
FY 2024-25 to
42.52
FY 2028-29

(3) Open Cycle Gas Turbine/Combined Cycle generating stations:

(in Rs Lakh/MW)

Year Small gas

Gas Turbine Combined turbine
Cycle generating power Advance F
Agartala
stations other than generating Class
GPS
small gas turbine power stations and Machines
generating stations Tripura Gas
Station
FY 2024-25 18.18 56.48 47.86 32.08
FY 2025-26 19.14 59.44 50.37 33.77
FY 2026-27 20.14 62.57 53.02 35.54
FY 2027-28 21.20 65.85 55.80 37.40
FY 2028-29 22.32 69.31 58.73 39.37

(4) Lignite-fired generating stations:

71
 (in Rs Lakh/MW)

Year 125 MW Sets

FY 2024-25 38.81
FY 2025-26 40.85
FY 2026-27 42.99
FY 2027-28 45.25
FY 2028-29 47.62

(5) Generating Stations based on coal rejects:

(in Rs Lakh/MW)
Year O&M Expenses
FY 2024-25 38.81
FY 2025-26 40.85
FY 2026-27 42.99
FY 2027-28 45.25
FY 2028-29 47.62

(6) The Water Charges, Security Expenses, Ash Transportation Expenses and Capital Spares

for thermal generating stations shall be allowed separately after prudence check:

Provided that water charges shall be allowed based on water consumption depending upon

type of plant and type of cooling water system or water agreement with state govt./utilities, and the

norms specified by the Ministry of Environment, Forest and Climate Change subject to prudence

check. The details regarding the same shall be furnished along with the petition;

Provided further that the generating station shall submit the assessment of the security

requirement and estimated expenses along with the petition seeking the determination of tariff;

Provided also that the generating station shall submit the details of year-wise actual capital

spares consumed individually costing above Rs. 10 Lakh at the time of truing up with appropriate

justification for incurring the same and substantiating that the same is not funded through

compensatory allowance as per Regulation 17 of Central Electricity Regulatory Commission

72
 (Terms and Conditions of Tariff) Regulations, 2014 or Special Allowance or claimed as a part of

additional capitalisation or consumption of stores and spares and renovation and modernization.

(7) Any additional O&M expenses incurred by the generating company due to any change in law

shall be considered at the time of truing up of tariff.

Provided that such impact shall be allowed only in case the overall impact of such change

in law event in a year is more than 5% of normative O&M expenses of the project allowed for the

year.

(8) In the case of a generating company owned by the Central or State Government, the impact

on account of implementation of wage or pay revision shall be allowed at the time of truing up of

tariff.

(9) The operation and maintenance expenses on account of emission control systems in coal or

lignite based thermal generating stations shall be 2% of the admitted capital expenditure (excluding

IDC and IEDC) as on its date of operation, which shall be escalated annually @ 5.25% during the

tariff period ending on 31st March 2029:

Provided that income generated from the sale of gypsum or other by-products shall be

reduced from the operation and maintenance expenses.

(2) Hydro Generating Station:

The following operations and maintenance expense norms shall be applicable for hydro

generating stations which have been operational for three or more years as on 1.4.2024:

(in Rs Lakh)
FY 2024-
Particulars FY 2025-26 FY 2026-27 FY 2027-28 FY 2028-29
25
THPS 40,548.78 42,765.88 45,104.19 47,570.36 50,171.37
KHEP 20,749.20 21,883.71 23,080.25 24,342.21 25,673.18

73
Bairasul 7,856.31 8,285.87 8,738.92 9,216.74 9,720.68
Loktak 8,876.09 9,361.41 9,873.26 10,413.10 10,982.46
Salal 17,208.43 18,149.34 19,141.69 20,188.30 21,292.14
Tanakpur 11,696.62 12,336.16 13,010.67 13,722.05 14,472.34
Chamera-I 14,397.75 15,184.98 16,015.25 16,890.92 17,814.47
Uri-I 11,755.75 12,398.52 13,076.44 13,791.42 14,545.50
Rangit 6,351.54 6,698.82 7,065.09 7,451.39 7,858.82
Chamera-II 12,149.92 12,814.25 13,514.89 14,253.85 15,033.21
Dhauliganga 11,323.06 11,942.18 12,595.14 13,283.81 14,010.13
Dulhasti 17,754.67 18,725.45 19,749.30 20,829.14 21,968.02
Teesta-V 15,193.93 16,024.69 16,900.88 17,824.97 18,799.59
Sewa-II 8,053.42 8,493.76 8,958.17 9,447.98 9,964.57
TLDP III 9,281.92 9,789.43 10,324.68 10,889.21 11,484.60
Chamera III 9,598.50 10,123.32 10,676.83 11,260.61 11,876.31
Chutak 4,259.73 4,492.64 4,738.28 4,997.36 5,270.60
Nimmo Bazgo 4,346.80 4,584.47 4,835.13 5,099.50 5,378.33
Uri II 9,135.41 9,634.91 10,161.71 10,717.33 11,303.32
Parbati III 10,703.93 11,289.19 11,906.45 12,557.46 13,244.07
Kishanganga 13,952.53 14,715.42 15,520.01 16,368.60 17,263.59
TLDP IV 10,697.94 11,282.87 11,899.79 12,550.43 13,236.66
Indira Sagar 15,030.66 15,852.50 16,719.27 17,633.43 18,597.57
Omkareshwar 10,183.66 10,740.48 11,327.73 11,947.10 12,600.34
Nathpa jhakari 48,588.63 51,245.32 54,047.26 57,002.41 60,119.15
Rampur 18,287.58 19,287.49 20,342.08 21,454.32 22,627.39
Koldam 13,113.75 13,830.78 14,587.01 15,384.58 16,225.77
Karcham
12,612.68 13,302.30 14,029.64 14,796.74 15,605.78
Wangtoo
Kopili 12,038.46 12,743.93 13,490.73 14,281.29 15,118.18
Khandong I 2,137.15 2,262.39 2,394.96 2,535.31 2,683.88
Khandong II 1,065.60 1,128.04 1,194.15 1,264.12 1,338.20
Doyang 7,540.48 7,982.36 8,450.13 8,945.31 9,469.52
Panyor 16,827.77 17,813.88 18,857.79 19,962.87 21,132.70
Pare 16,383.05 17,343.10 18,359.42 19,435.29 20,574.21
Turial 5,120.13 5,420.17 5,737.79 6,074.03 6,429.97
Maithon 3,261.23 3,439.55 3,627.61 3,825.96 4,035.15
Panchet 3,361.27 3,545.06 3,738.89 3,943.32 4,158.93
Tilaiya 1,027.67 1,083.86 1,143.12 1,205.62 1,271.54
Teesta Urja
27,438.21 28,938.46 30,520.73 32,189.51 33,949.55
Ltd.

a) In the case of the hydro generating stations declared under commercial operation on or after

1.4.2024, operation and maintenance expenses of the first year shall be fixed at 3.5% and

74
 5.0% of the original project cost (excluding the cost of rehabilitation & resettlement works,

IDC and IEDC) for stations with installed capacity exceeding 200 MW and for stations with

installed capacity less than or equal to 200 MW, respectively and shall be subject to annual

escalation of 5.47% per annum for the subsequent years.

b) In the case of hydro generating stations which have not completed a period of three years as

on 1.4.2024, operation and maintenance expenses for 2024-25 shall be worked out by

applying an escalation rate of 5.47% on the applicable operation and maintenance expenses

as on 31.3.2024. The operation and maintenance expenses for subsequent years of the tariff

period shall be worked out by applying an escalation rate of 5.47% per annum.

c) The Security Expenses, Capital Spares and Insurance expenses arrived through competitive

bidding for hydro generating stations shall be allowed separately after prudence check:

Provided that the generating station shall submit the assessment of the security

requirement, capital spares and insurance expenses along with its estimated expenses, which shall

be trued up based on the details of year-wise actual capital spares consumed, actual insurance

and security expenses incurred with appropriate justification.

Provided further that the value of capital spares exceeding Rs. 10 lakh shall only be

considered for reimbursement at the time of truing up with appropriate justification for incurring

the same and substantiating that the same is not claimed as a part of additional capitalisation or

consumption of stores and spares and renovation and modernization.

d) Any additional O&M expenses incurred by the generating company due to any change in law

event shall be considered at the time of truing up of tariff.

Provided that such impact shall be allowed only in case the overall impact of such change

in law event in a year is more than 5% of normative O&M expenses of the project for the year.

75
 e) In the case of a generating company owned by the Central or State Government, the impact

on account of implementation of wage or pay revision shall be allowed at the time of truing

up of tariff;

f) The operation and maintenance expenses of the generating station and the transmission

system of Bhakra Beas Management Board (BBMB) and Sardar Sarovar Project (SSP) shall

be determined after taking into account provisions of the Punjab Reorganization Act, 1966

and Narmada Water Scheme, 1980 under Section-6 A of the Inter-State Water Disputes Act,

1956 respectively.

(3) Transmission system: (a) The following normative operation and maintenance expenses

shall be admissible for the transmission system:

Particulars 2024-25 2025-26 2026-27 2027-28 2028-29

Norms for sub-station Bays (Rs Lakh per bay)
765 kV 41.34 43.51 45.79 48.20 50.73
400 kV 29.53 31.08 32.71 34.43 36.23
220 kV 20.67 21.75 22.90 24.10 25.36
132 kV and below 15.78 16.61 17.48 18.40 19.35
Norms for Transformers/Reactors (Rs Lakh per MVA or MVAR)
O&M expenditure per MVA or per
MVAr (Rs Lakh per MVA or per 0.262 0.276 0.290 0.305 0.322
MVAr)
Norms for AC and HVDC lines (Rs Lakh per km)
Single Circuit (Bundled Conductor
with six or more sub-conductors) 0.861 0.906 0.953 1.003 1.056
Single Circuit (Bundled conductor
with four or more sub-conductors) 0.738 0.776 0.817 0.860 0.905
Single Circuit (Twin & Triple
Conductor) 0.492 0.518 0.545 0.573 0.603
Single Circuit (Single Conductor)
0.246 0.259 0.272 0.287 0.302
Double Circuit (Bundled Conductor
with four or more sub-conductors) 1.291 1.359 1.430 1.506 1.585
Double Circuit (Twin & Triple
Conductor) 0.861 0.906 0.953 1.003 1.056
Double Circuit (Single Conductor)
0.369 0.388 0.409 0.430 0.453
Multi Circuit (Bundled Conductor
with four or more sub-conductor) 2.266 2.385 2.510 2.642 2.781

76
 Multi Circuit (Twin & Triple
Conductor) 1.509 1.588 1.671 1.759 1.851
Norms for HVDC stations
HVDC Back-to-Back stations
(Rs Lakh per MW) 2.07 2.18 2.30 2.42 2.55
Gazuwaka BTB
(Rs Lakh/MW) 1.83 1.92 2.03 2.13 2.24
HVDC bipole scheme
(Rs Lakh/MW) 1.04 1.10 1.16 1.22 1.28

Provided that the O&M expenses for the GIS bays shall be allowed as worked out by

multiplying 0.70 of the O&M expenses of the normative O&M expenses for bays;

Provided that the O&M expense norms of Double Circuit quad AC line shall be applicable

to for HVDC bi-pole line;

Provided that the O&M expenses of ±500 kV Mundra-Mohindergarh HVDC bipole scheme

(2500 MW) shall be allowed as worked out by multiplying 0.80 of the normative O&M expenses for

HVDC bipole scheme;

Provided further that the O&M expenses for Transmission Licensees whose transmission

assets are located solely in NE Region (including Sikkim), States of Uttarakhand, Himachal Pradesh,

the Union Territories of Jammu and Kashmir and Ladakh, district of Darjeeling of West Bengal shall

be worked out by multiplying 1.50 to the normative O&M expenses prescribed above.

(b) The total allowable operation and maintenance expenses for the transmission system shall be

calculated by multiplying the number of substation bays, transformer capacity of the

transformer/reactor/Static Var Compensator/Static Synchronous Compensator (in MVA/MVAr) and

km of line length with the applicable norms for the operation and maintenance expenses per bay, per

MVA/MVAr and per km respectively.

(c) Communication system: The operation and maintenance expenses for the ULDC or such similar

77
scheme shall be worked out at 2.0% of the original project cost related to such communication

system. The transmission licensee shall submit the actual operation and maintenance expenses for

truing up. The expenses in case of U-NMS shall be allowed on actual basis after due prudence check.

(d) The Security Expenses, Capital Spares individually costing more than Rs. 10 lakh and Insurance

expenses arrived through competitive bidding for the transmission system and associated

communication system shall be allowed separately after prudence check:

Provided that in case of self insurance, the premium shall not exceed 0.09% of the GFA of the assets

insured;

Provided that the transmission licensee shall submit the along with estimated security expenses based

on assessment of the security requirement, capital spares and insurance expenses, which shall be

trued up based on details of the year-wise actuals along with appropriate justification for incurring

the same and along with confirmation that the same is not claimed as a part of additional

capitalisation or consumption of stores and spares and renovation and modernization.

(e) On the occurrence of any change in law event affecting O&M expenses, the impact shall be

allowed to the transmission licensee at the time of truing up of tariff.

Provided that such impact shall be allowed only in case the overall impact of such change

in law event in a year is more than 5% of normative O&M expenses of the project for the year.

(f) In case of a transmission licensee owned by the Central or State Government, the impact on

account of implementation of wage or pay revision shall be allowed at the time of truing up of tariff.

78
 CHAPTER – 9

COMPUTATION OF INPUT PRICE OF COAL AND LIGNITE

FROM INTEGRATED MINE

37. Input Price of coal and lignite for energy charges: (1) Where the generating company has

the arrangement for supply of coal or lignite from the integrated mine(s) allocated to it for use in one

or more of its generating stations as end use, the energy charge component of tariff of the generating

station shall be determined based on the input price of coal or lignite, as the case may be, from such

integrated mines in accordance with these regulations.

(2) The generating company shall, after the date of commercial operation of the integrated

mine(s) till the input price of coal is determined by the Commission under these regulations, adopt

the notified price of Coal India Limited commensurate with the grade of the coal from the integrated

mine(s) or the estimated price available in the investment approval, whichever is lower, as the input

price of coal for the generating station:

Provided that the difference between the input price of coal determined under these

regulations and the input price of coal so adopted prior to such determination, the quantity of coal

billed shall be adjusted in accordance with Clause (4) of this Regulation.

(3) The generating company shall, after the date of commercial operation of the integrated

mine(s), till the input price of lignite is determined by the Commission under these regulations, fix

the input price of lignite for the generating station at the last available pooled lignite price as

determined by the Commission for transfer price of lignite or the estimated price available in the

investment approval, whichever is lower:

Provided that the difference between the input price of lignite determined under these

79
 regulations and the input price of lignite so fixed prior to such determination, for the quantity of

lignite billed, shall be adjusted in accordance with Clause (4) of this Regulation.

(4) In case of excess or short recovery of input price under Clauses (2) or (3) of this Regulation,

the generating company shall refund the excess amount or recover the shortfall amount, as the case

may be, with simple interest at the rate equal to 1-year SBI MCLR plus 100 basis points prevailing

as on 1st April of the respective year of the tariff period, in six equal monthly instalments.

Provided that such interest shall be payable till the date of issuance of the Order and no

interest shall be allowed or levied during the period of six-monthly instalments.

Provided that in case there is a delay in filing the Petition for determination of input price

as per the timelines specified under Regulation 9 of these regulations, no carrying cost shall be

allowed to the generating company or the mining company for such delay and in such cases the

carrying cost at the simple interest rate of 1-year SBI MCLR plus 100 bps shall be allowed from

the date of filing of the Petition.

38. Input Price of coal or Lignite: (1) Input price of coal or lignite from the integrated mine(s)

shall be determined based on the following components:

I) Run of Mine (ROM) Cost; and

II) Additional charges:

a. crushing charges;

b. transportation charge within the mine up to the washery end or coal handling

plant associated with the integrated mine, as the case may be;

c. handling charges at mine end;

d. washing charges; and

80
 e. transportation charges beyond the washery end or coal handling plant, as the case

may be, and up to the loading point:

Provided that one or more components of additional charges may be applicable in the case of

the integrated mine(s), based on the scope and nature of the mining activities;

Provided further that the input price of lignite shall be computed based on Run of Mine (ROM)

based on the technology such as bucket excavator-conveyor or belt-spreader or its combination and

handling charges, if any.

(2) Statutory Charges, as applicable, shall be allowed.

39. Run of Mine (ROM) Cost: (1) Run of Mine Cost of coal in case of integrated mine(s)

allocated through an auction route under the Coal Mines (Special Provisions) Act, 2015 shall be

worked out as under:

ROM Cost = (Quoted Price of coal) + (Fixed Reserve Price)

Where,

(i) The Quoted Price of coal is the Final Price Offer of coal in respect of the

concerned coal block or mine, along with subsequent escalation, if any, as

provided in the Coal Mine Development and Production Agreement:

Provided that additional premium, if any, quoted by the generating

company during auction shall not be considered in the Run of Mine Cost;

(ii) Fixed Reserve Price is the fixed reserve price per tonne along with subsequent

escalation, if any, as provided in the Coal Mine Development and Production

Agreement: and

(iii) Capital cost under Regulation 41 and additional capital expenditure under

81
 Regulation 42 shall not be admissible for the purpose of ROM cost in respect of

integrated mine(s) allocated through the auction route.

(2) Run of Mine Cost of coal in case of integrated mine allocated through allotment route under Coal

Mines (Special Provisions) Act, 2015 shall be worked out as under:

ROM Cost = [(Annual Extraction Cost / (ATQ or Actual production whichever is

higher) + Mining Charge] + (Fixed Reserve Price).

Where,

(i) Annual Extraction Cost is the cost of extraction of coal as computed in

accordance with Regulation 43 of these regulations;

(ii) Mining Charge is the charge per tonne of coal paid by the generating company

to the Mine Developer and Operator engaged by the generating company for

mining, wherever applicable; and

(iii) Fixed Reserve Price is the fixed reserve price per tonne along with subsequent

escalation, if any, as provided in the Coal Mine Development and Production

Agreement.

(3) Run of Mine Cost of lignite in case of integrated mine(s) for lignite shall be worked out as under:

ROM Cost = [(Annual Extraction Cost / (ATQ or Actual production whichever is

higher) + (Mining Charge)]

Where,

(i) Annual Extraction Cost is the cost of extraction of lignite as computed in

accordance with Regulation 43 of these regulations; and

82
 (ii) Mining Charge is the charge per tonne of lignite paid by the generating company

to the Mine Developer and Operator engaged by the generating company for

mining, wherever applicable.

(4) The generating company shall adhere to the Mining Plan for the extraction of coal or lignite on

an annual basis and shall submit a certificate to that effect from the Coal Controller or the competent

authority:

Provided that deviations from the Mining Plan shall be considered only if such deviations

have been approved by the Coal Controller or the revised Mining Plan has been approved by the

competent authority.

(5) Run of Mine Cost of coal and lignite shall be worked out in terms of Rupees per tonne.

40. Additional Charges: (1) Where crushing or transportation or handling or washing are

undertaken by the generating company without engaging the Mine Developer and Operator or an

agency other than the Mine Developer and Operator, additional charges shall be worked out as under:

(i) Crushing Charges = Annual Crushing Cost/Quantity;

(ii) Transportation Charges= Annual Transportation Cost/Quantity:

Provided that separate transportation charges, as applicable, shall be

considered from the mine up to the washery end or coal handling plant associated

with the integrated mine(s) and beyond the washery end or coal handling plant

associated with the integrated mine(s) and up to the loading point, as the case may

be;

(iii) Handling charges = Annual Handling Cost/ Quantity; and

(iv) Washing Charges = Annual Washing Cost/Quantity.

83
 Where,

(a) Annual Crushing Cost, Annual Transportation Cost, Annual Handling Cost

and Annual Washing Cost shall be worked out on the basis of the following

components, for which the generating company shall submit the capital cost

separately:

(i) Depreciation;

(ii) Interest on Working Capital;

(iii) Interest on Loan;

(iv) Return on Equity;

(v) Operation and Maintenance Expenses, excluding mining charge;

(vi) Statutory charges, if applicable.

(b) Quantity shall be the quantity of coal or lignite in a tonne crushed or

transported or handled or washed, as the case may be, during the year duly

certified by the Auditor.

(2) Where crushing, transportation, handling, or washing are within the scope of the Mine

Developer and Operator engaged by the generating company, no additional charges shall be

admitted, as the same shall be recovered through the Mining Charge of the Mine Developer and

Operator.

(3) Where crushing, transportation, handling, or washing are undertaken by the generating company

by engaging an agency other than the Mine Developer and Operator, the annual charges of such

agencies shall be considered as part of the Operation and Maintenance Expenses, provided that the

charges have been discovered through a transparent, competitive bidding process.

84
(4) The crushing charges, transportation charges, handling charges, and washing charges shall be

admitted by the Commission after a prudence check, considering charges of Coal India Limited or

similarly placed coal mines or any other reference charges.

(5) The crushing charges, transportation charges, handling charges, and washing charges shall be

worked out in terms of Rupees per tonne.

41. Capital Cost: (1) The expenditure incurred, including IDC and IEDC, duly certified by the

Auditor, for the development of the integrated mine(s) up to the date of commercial operation shall

be considered for arriving at the capital cost.

(2) Capital expenditure incurred shall be admitted by the Commission after a prudence check.

(3) Capital expenditure incurred on infrastructure for crushing, transportation, handling, washing

and other mining activities required for mining operations shall be arrived at separately in

accordance with these regulations:

Provided that where crushing, transportation, handling or washing are undertaken by the

generating company, the expenditure incurred on infrastructures of these components shall be

capitalized;

Provided further that where mine development and operation, with or without any

component of crushing, transportation, handling or washing, are undertaken by the generating

company by engaging the Mine Developer and Operator or an agency other than the Mine

Developer and Operator, the capital expenditure incurred by the Mine Developer and Operator or

such agency shall not be capitalised by the generating company and shall not be considered for the

determination of input price.

(4) The capital expenditure shall be determined by considering, but not limited to, the Mining

85
 Plan, detailed project report, mine closure plan, cost audit report and such other details as deemed

fit by the Commission.

(5) In the case of integrated mine(s) which have declared the date of commercial operation prior

to 1.4.2024, the capital expenditure allowed by the Commission for the period ending 31.3.2024

shall form the basis for the computation of input price.

42. Additional Capital Expenditure: (1) The expenditure, in respect of the integrated mine(s),

incurred or projected to be incurred after the date of commercial operation and up to the date of

achieving the Peak Rated Capacity may be admitted by the Commission, subject to a prudence check

and shall be capitalized in the respective year of the tariff period as additional capital expenditure

corresponding to the Annual Target Quantity of the year as specified in the Mining Plan or actual

extraction in that year, whichever is higher, on following counts:

(a) expenditure incurred on activities as per the Mining Plan;

(b) expenditure for works deferred for execution and un-discharged liabilities

recognized for works executed prior to the date of commercial operation;

(c) expenditure for works required to be carried out for complying with directions

or orders of any statutory authorities;

(d) liabilities arising out of compliance with the order or decree of any court of

law or award of arbitration;

(e) expenditure for procurement and development of land as per the Mining Plan;

(f) expenditure for procurement of additional heavy earth moving machineries

for replacement, on completion of their useful life; and

86
 (g) liabilities due to Change in Law or Force Majeure event;

Provided that in case of replacement of any assets, the additional capitalization shall be

worked out after adjusting the gross fixed assets and cumulative depreciation of the assets replaced

on account of de-capitalization;

Provided further that the generating company shall prepare guidelines for procurement and

replacement of heavy mining equipment such as Heavy Earth Moving Machineries and share the

same with the beneficiaries and submit it to the Commission along with its petition.

(2) The expenditure, in respect of the integrated mine(s), incurred or projected to be incurred after

the date of achieving the Peak Rated Capacity may be admitted by the Commission subject to a

prudence check, and shall be capitalized as Additional Capital Expenditure, corresponding to the

Annual Target Quantity of the respective years as specified in the Mining Plan, on following counts:

(a) expenditure incurred on activities, if any, as per the Mining Plan;

(b) expenditure for works required to be carried out for complying with directions

or orders of any statutory authority;

(c) liabilities arising out of compliance with an order or decree of any court of

law or award of arbitration;

(d) expenditure for procurement and development of land as per the Mining Plan;

and

(e) liabilities due to Change in Law or Force Majeure events;

Provided that in case of replacement of any assets, the additional capitalization shall be

worked out after adjusting the gross fixed assets, cumulative depreciation and cumulative repayment

87
of loan of the assets replaced on account of de-capitalization.

(3) The expenditure on the following counts shall not be considered as additional capital expenditure

for the purpose of these regulations:

a) expenditure incurred but not capitalized as the assets have not been put in

service (capital work in progress);

b) mine closure expenses;

c) expenditure on works not covered under the Mining Plan, unless covered

under sub-clause (g) of Clause (1) or sub-clause (e) of Clause (2) of this

Regulation;

d) expenditure on replacement due to obsolescence of assets on account of

completion of the useful life or due to obsolescence of technology if the

original cost of such assets has not been de-capitalised from the gross fixed

assets.

43. Annual Extraction Cost: The Annual Extraction Cost of integrated mine(s) shall consist of

the following components:

(i) Depreciation;

(ii) Interest on Loan;

(iii) Return on Equity;

(iv) Operation and Maintenance Expenses, excluding mining charge;

(v) Interest on Working Capital;

(vi) Mine closure expenses, if not included in mining charge; and

88
 (vii) Statutory charges, if applicable.

44. Capital Structure, Return on Equity and Interest on Loan: (1) For integrated mine(s), the

debt-equity ratio as on the date of commercial operation and as on the date of achieving Peak Rated

Capacity shall be considered in the manner as specified under Clause (1) of Regulation 18 of these

regulations:

Provided that for integrated mine(s) in respect of lignite with the date of commercial operation

prior to 1.4.2024, the debt-equity ratio allowed by the Commission for the period ending 31.3.2024

shall form the basis for computation of input price.

(2) For integrated mine(s), the debt-equity ratio for additional capital expenditure admitted by the

Commission under these regulations shall be considered in the manner specified under Clause (1) of

this Regulation.

(3) Return on equity shall be computed in rupee terms on the equity base arrived under Clause (1)

of this Regulation at the base rate of 14%.

(4) The base rate of return on equity as per Clause (3) of this Regulation shall be grossed up with

the effective tax rate computed in the manner specified under Regulation 31 of these regulations.

(5) Interest on loan, including normative loan, if any, determined under Clause (1) of this Regulation,

shall be arrived at by considering the weighted average rate of interest calculated on the basis of the

actual loan portfolio, in accordance with Clauses (2) to (7) of Regulation 32 of these regulations.

45. Depreciation: (1) Depreciation in respect of integrated mine(s) shall be computed from the

date of commercial operation by applying the Straight Line Method:

Provided that depreciation methodology allowed in respect of integrated mine(s) of lignite

which have been declared under commercial operation on or before 31.3.2024, shall continue to

89
apply for determination of input price of lignite.

(2) The value base for the purpose of depreciation shall be the capital cost of the asset admitted by

the Commission:

Provided that,

i) freehold land or assets purchased from grant shall not be considered as

depreciable assets, and their cost shall be excluded from the capital cost while

computing the depreciable value of the assets;

ii) where the allotment of freehold land is conditional and is required to be

returned, the cost of such land shall be part of the value base for the purpose

of depreciation, subject to a prudence check by the Commission; and

iii) leasehold land shall be amortized over the lease period or remaining life of

the integrated mine(s), whichever is lower.

(3) The salvage value of an asset shall be considered as 5% of the capital cost of the asset:

Provided that the salvage value shall be:

i) zero for IT equipment and software;

ii) zero or as agreed by the generating company with the State Government for land; and

iii) as notified by the Ministry of Corporate Affairs under the Companies Act, 2013 for

specialized mining equipment.

(4) Depreciation in respect of integrated mine(s) shall be arrived at annually by applying

depreciation rates or on the basis of expected useful life specified in Appendix III of these

regulations:

90
 Provided that specialized mining equipment shall be depreciated as per the useful life and

depreciation rate as notified by the Ministry of Corporate Affairs under the Companies Act, 2013.

46. Operation and Maintenance Expenses: (1) The Operation and Maintenance Expenses in

respect of integrated mine(s) shall be allowed as under:

(a) The Operation and Maintenance expenses in respect of integrated mine(s) of coal, for the

tariff period ending on 31st March 2029 shall be allowed based on the projected Operation

and Maintenance Expenses for each year of the tariff period subject to prudence check by

the Commission;

Provided that the Operation and Maintenance expenses allowed under this clause

shall be trued up based on actual expenses for the tariff period ending on 31st March 2029.

(b) The Operation and Maintenance expenses for the tariff period ending on 31st March 2029

in respect of the integrated mine(s) of lignite commissioned on or before 31st March 2024

shall be worked out based on the Operation and Maintenance expenses as admitted by the

Commission during 2023-24 and escalated at the rate of 5.25 % per annum;

(c) The Operation and Maintenance expenses for the tariff period ending on 31st March 2029

in respect of the integrated mine(s) of lignite commissioned after 31st March 2024 shall be

allowed based on the projected Operation and Maintenance Expenses for each year of the

tariff period, subject to prudence check by the Commission;

Provided that the Operation and Maintenance expenses allowed under this clause shall

be trued up based on actual expenses for the tariff period ending on 31st March 2029.

(2) Where the development and operation of the integrated mine(s) is undertaken by the generating

company by engaging the Mine Developer and Operator, the Mining Charge of such Mine Developer

91
and Operator shall not be included in Operation and Maintenance Expenses under Clause (1) of this

Regulation;

(3) Where an agency other than Mine Developer and Operator is engaged by the generating

company, through a transparent competitive bidding process, for crushing or transportation or

handling or washing or any combination thereof, the annual charges of such agency shall be

considered as part of Operation and Maintenance Expenses under clause (1) of this Regulation,

subject to a prudence check by the Commission.

47. Interest on Working Capital: (1) The working capital of the integrated mine(s) of coal shall

cover:

(i) Input cost of coal stock for 7 days of production corresponding to the Annual Target

Quantity for the relevant year;

(ii)Consumption of stores and spares, including explosives, lubricants and fuel @ 15%

of operation and maintenance expenses, excluding mining charge of the Mine

Developer and Operator and annual charges of the agency other than the Mine

Developer and Operator, engaged by the generating company; and

(iii) Operation and maintenance expenses for one month, excluding the mining charge

of the Mine Developer and Operator and annual charges of the agency other than

the Mine Developer and Operator engaged by the generating company.

(2) The working capital of the integrated mine(s) of lignite shall cover: -

(i) Input cost of lignite stock for 7 days of production corresponding to the Annual

Target Quantity for the year;

(ii) Consumption of stores and spare including explosives, lubricants and fuel @20%

92
 of Operation and Maintenance expenses, excluding Mining Charge of the Mine

Developer and Operator and annual charges of the agency other than the Mine

Developer or Operator engaged by the generating company; and

(iii)Operation and Maintenance expenses for one month, excluding the Mining Charge

of the Mine Developer and Operator and annual charges of the agency other than

the Mine Developer and Operator, engaged by the generating company.

(3) The rate and payment of interest on working capital shall be determined in accordance with

Clauses (3) and (4) of Regulation 34 of these regulations.

48. Mine Closure Expenses: (1) Where the mine closure is undertaken by the generating

company, the amount deposited in the Escrow account as per the Mining Plan, after adjusting interest

earned, if any, on the said deposits shall be admitted as Mine Closure Expenses:

Provided that,

a) the amount deposited in the Escrow account as per the Mining Plan prior to the Date

of Commercial Operation of the integrated mine(s) shall be indicated separately and

shall be recovered over the useful life of the integrated mine(s) in the form of annuity

linked to the borrowing rate;

b) the amount deposited in the Escrow account as per the Mining Plan or any

expenditure incurred towards mine closure shall be excluded from the capital cost

for computing input price;

c) where the expenditure incurred towards mine closure falls short of or is in excess of

the reimbursement received from the Escrow account during the tariff period 2024-

29, the shortfall or excess shall be carried forward to the subsequent years for

93
 adjustments.

(2) The amount towards mine closure shall be deposited in the Escrow account as per the Mining

Plan and shall be recovered as part of the input price irrespective of the expenditure incurred towards

mine closure during any of the years of the tariff period.

(3) Where mine closure is within the scope of the Mine Developer and Operator engaged by the

generating company and mine closure expenses are part of the Mining Charge of the Mine

Developer and Operator, the mine closure expenses shall be met out of the Mining Charge, and no

mine closure expenses shall be admissible to the generating company separately:

Provided that,

a) the amount deposited in the Escrow account by the Mine Developer and Operator

or by the generating company and any amount received from the Escrow Account

against expenditure incurred towards mine closure shall not be considered for

computing input price; and

b) the difference between the borrowing cost, arrived at by considering the weighted

average rate of interest calculated on the basis of the actual loan portfolio in

accordance with the methodology specified in Regulation 32 of these regulations,

and the amount deposited in the Escrow account and the interest received from

Escrow account in a year shall be adjusted in the input price of coal or lignite of

the respective year, as part of mine closure expenses, on case to case basis;

(4) Where the mine closure is within the scope of the Mine Developer and Operator engaged by

the generating company only for a part of useful life of the integrated mine(s)and the generating

company undertakes the mine closure for the balance useful life, the treatment of mine closure

during the period undertaken by the generating company shall be in accordance with Clause (1) of

94
 this Regulation and mine closure during the period undertaken by the Mine Developer and

Operator shall be in accordance with Clause (3) of this Regulation:

Provided that the treatment of mine closure at the end of the useful life of the integrated

mine(s) shall be decided by the Commission on a case-to-case basis.

(5) The mine closure expenses worked out in accordance with this Regulation shall not be

applicable in case of the integrated mine(s) allocated through an auction route under the Coal

Mines (Special Provisions) Act, 2015.

49. Determination of Input Price: (1) The input price of coal or lignite shall be determined as

under:

Input Price = [ROM Cost + Additional charges]

(2) The credit arising on account of adjustment due to shortfall in overburden removal, GCV

Adjustment and Non- tariff Income, if any, shall be dealt with separately in the manner specified

in these regulations.

(3) Statutory Charges, as applicable, shall be allowed.

50. Recovery of Input Charges: (1) The input charges of coal or lignite shall be recovered as

under:

Input Charges = [Input Price x Quantity of coal or lignite supplied] + Statutory

charges, as applicable;

Provided that where the energy charge rate based on the input price of coal from integrated

mine(s) exceeds 20% of the energy charge rate based on the notified price of Coal India Limited

for the commensurate grade of coal in a month, prior consent of the beneficiary(ies) shall be

required to be obtained by the generating company;

95
 Provided further that where such consents of beneficiaries are not available, the input price

of coal from such integrated mine(s) shall be so fixed that the energy charge rate based on the input

price of coal from integrated mine(s) does not exceed by more than 20% of the energy charge rate

based on the notified price of Coal India Limited for the commensurate grade of coal in a month;

Provided also that the energy charge rate based on the input price of coal does not lead to

a higher energy charge rate throughout the tenure of the power purchase agreement than that which

would have been obtained as per terms and conditions of the existing power purchase agreement.

(2) The generating company shall work out the comparative energy charge rate based on the input

price of coal and notified price of Coal India Limited for the commensurate grade of coal for every

month from the date of commercial operation of integrated mine(s) and share the same with

beneficiaries.

51. Adjustment on account of Shortfall of Overburden Removal (OB Adjustment):

(1) The generating company shall remove overburden as specified in the Mining Plan.

(2) In case of a shortfall of overburden removal during a year, the generating company shall be

allowed to adjust such shortfall against excess of overburden removal, if any, during the

subsequent three years.

(3) In case of excess of overburden removal during a year, the generating company shall be

allowed to carry forward such excess for adjustment against the shortfall, if any, during the

subsequent three years.

(4) Where the shortfall of overburden removal of any year is not made good by the generating

company in accordance with Clause (2) of this Regulation, the adjustment on account of the

shortfall of overburden removal (OB Adjustment) for that year shall be worked out as under:

96
 OB Adjustment = [Factor of adjustment for shortfall of overburden removal during the

year] x [Mining Charge during the year + Operation and

Maintenance expenses during the year]

Where,

i) Factor of adjustment for the shortfall of overburden removal during the year

shall be computed as under:

[(Actual quantity of coal or lignite extracted during the year x Annual

Stripping Ratio as per Mining Plan) - (Actual quantity of overburden

removed during the year/ Annual Stripping Ratio as per Mining Plan)]/

(Annual Target Quantity);

ii) Annual Stripping ratio is the ratio of the volume of overburden to be removed

for one unit of coal or lignite as specified in the Mining Plan.

iii) Mining Charge is the charge per tonne of coal or lignite paid by the generating

company to the Mine Developer and Operator engaged by the generating

company for mining, wherever applicable.

iv) Mining Charge and Operation and Maintenance expenses shall be in terms of

Rupees per tonne corresponding to the Annual Target Quantity.

(5) The provisions of this Regulation regarding adjustment on account of shortfall of overburden

removal shall not be applicable in case of the integrated mine(s) allocated through an auction route

under the Coal Mines (Special Provisions) Act, 2015.

52. Adjustment on account of shortfall in GCV (GCV Adjustment): (1) In case the weighted

average GCV of coal extracted from the integrated mine(s) in a year is higher than the declared GCV

97
of coal for such mine(s), no GCV adjustment shall be allowed.

(2) In case the weighted average GCV of coal extracted from the integrated mine(s) in a year is lower

than the declared GCV of coal of such mine(s), the GCV adjustment in that year shall be worked out

as under:

(a) Where the integrated mine(s) are allocated through an auction route under the Coal

Mines (Special Provisions) Act, 2015:

GCV Adjustment = (Quoted Price of coal + Fixed Reserve Price) X [(Declared

GCV of coal - Weighted Average GCV of coal extracted in the

year)/(Declared GCV of coal)]

Where,

i) Quoted Price of coal is the Final Price Offer of coal in respect of the concerned

coal Block or Mine, along with subsequent escalation, if any, as provided in

the Coal Mine Development and Production Agreement:

Provided that additional premium, if any, quoted by the generating

company in the auction shall not be considered; and

ii) Declared GCV of coal shall be the GCV of coal as specified or quoted in the

auction.

(b) Where the integrated mine(s) are allocated through an allotment route under the

Coal Mines (Special Provisions) Act, 2015:

GCV Adjustment = [(Annual Extraction Cost/ATQ) + (Mining Charge)] X [(Declared

GCV of coal – Weighted Average GCV of coal extracted in the

year)/(Declared GCV of coal)]

98
 Where,

i) Annual Extraction Cost is the cost of extraction of coal as computed in

accordance with Regulation 43 of these regulations;

ii) Mining Charge is the charge per tonne of coal paid by the generating company

to the Mine Developer and Operator engaged by the generating company for

mining, wherever applicable; and

iii) Declared GCV of coal shall be the average GCV as per the Mining Plan or as

approved by the Coal Controller.

53. Adjustment on account of Non-tariff income (NTI Adjustment): (1) Adjustment on

account of non-tariff income (NTI Adjustment) for any year, such as income from sale of washery

rejects in case of integrated mine of coal and profit, if any, from supply of coal to the Coal India

Limited or merchant sale of coal as allowed under the Coal Mines (Special Provisions) Act, 2015

shall be worked out as under:

NTI Adjustment = (2/3) x (Total Non-tariff income during the year)/(Actual quantity of

coal or lignite extracted during the year)

(2) The adjustment on account of non-tariff income worked out in accordance with this

Regulation shall not be applicable in case of the integrated mine(s) allocated through an

auction route under the Coal Mines (Special Provisions) Act, 2015.

Provided that in case the actual extraction is less than ATQ, no NTI adjustment shall be

made till the total cost of extraction is recovered.

54. Credit Adjustment Note: (1) The credit arising on account of OB Adjustment, GCV

Adjustment, and NTI Adjustment shall be dealt with through a Credit Adjustment Note for any year.

99
(2) The Credit Adjustment Note shall be issued in favour of the specified end use generating stations

on account of OB Adjustment, GCV Adjustment or NTI Adjustment, as the case may be, for that

year as under:

(i) OB Adjustment for the year X Quantity of coal or lignite supplied in that year;

(ii) GCV Adjustment for the year X Quantity of coal or lignite supplied in that year;

and

(iii) NTI Adjustment in the year X Quantity of coal or lignite supplied in that year.

(3) The amount in the Credit Adjustment Note shall be adjusted against the charges of coal or lignite

supplied after the date of issue of the Credit Adjustment Note. The integrated mine(s) shall prepare

an annual reconciliation statement of such adjustment and furnish the same to all the end use plants

and also publish the same on its website.

55. Quality Measurement: The quality of coal or lignite supplied from the integrated mine(s)

shall be measured at the loading point through third party sampling as per the guidelines and

procedure specified by the Ministry of Coal, Government of India and records of such measurement

of quality of coal shall be made available to the beneficiaries on demand.

56. Special Provision: Provisions of Chapters 5 to 8 of these regulations shall not be applicable

in case of integrated mine(s), except to the extent specifically provided for or referred to in Chapter-

9:

Provided that the financial parameters required for determination of input price of coal or lignite

from integrated mine(s), if not specifically provided for or referred to in Chapter-9, shall be

considered as per provisions of these regulations as applicable to the coal or lignite based generating

stations.

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 CHAPTER – 10

COMPONENTS OF ENERGY CHARGE

57. Energy Charges and Supplementary Energy Charges: The energy charge and

Supplementary Energy Charges in respect of the thermal generating Stations shall comprise the

landed cost of primary fuel, secondary fuel oil consumption and reagents on account of the

implementation of the revised emission standards.

58. Landed Fuel Cost of Primary Fuel: The landed fuel cost of primary fuel for any month shall

consist of the base price or input price of fuel corresponding to the grade and quality of fuel and shall

be inclusive of statutory charges as applicable, washery charges, transportation cost by rail or road

or any other means and loading, unloading and handling charges:

Provided that procurement of fuel at a price other than Government notified prices may be

considered if it is based on competitive bidding through a transparent process;

Provided further that the landed fuel cost of primary fuel shall be worked out based on the

actual bill paid by the generating company, including any adjustment on account of quantity and

quality;

Provided also that in the case of coal-fired or lignite based thermal generating station, the

Gross Calorific Value shall be measured by third party sampling, and the expenses towards the

third party sampling facility shall be reimbursed by the beneficiaries.

59. Transit and Handling Losses: For coal and lignite, the transit and handling losses shall be

as per the following norms: -

Thermal Generating Transit and Handling

Station Loss(%)
Pit head 0.20%
Non-pit head – All 0.80%

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 Rail route
Non-pit head multi-
modal
transportation
(using two or more
1.00%
than two mode of
transport involving
multiple trans-
shipments)

Provided that in the case of pit-head stations, if coal or lignite is procured from sources

other than the pit-head mines which is transported to the station through rail, transit and handling

losses applicable for non-pit head stations shall apply;

Provided further that in case of imported coal, the transit and handling losses applicable for

pit-head station shall apply.

60. Gross Calorific Value of Primary Fuel: (1) The gross calorific value for computation of

energy charges as per Regulation 64 of these regulations shall be done in accordance with 'GCV as

Received’;

(2) The measurement of GCV of domestic coal shall be done based on third party sampling through

an agency to be appointed by the generating company in accordance with the guidelines, if any,

issued by the Central Government and the generating company shall ensure recovery of

compensation as per Fuel Supply Agreement(s) and pass on the benefits of the same to the

beneficiaries of the generating station:

Provided that in the absence of third party sampling, computation of the energy charges as

per Regulation 64 of these Regulations shall be done in accordance with 'GCV as Billed’;

(3) In the case of an integrated coal mine, the GCV of coal received at the end use generating station

shall be adjusted by 15 kCal/Kg from the GCV measured at the mine end for every 100 km distance

102
beyond 200 Km, or actual whichever is lower, subject to the condition that such an adjustment in

aggregate shall not exceed 300 kCal/kg.

Provided further that the Commission after carrying out a detailed study may rationalise the

mechanism for arriving at the gross calorific value of domestic coal at the generating station by

considering the various factors impacting the calorific value throughout entire value chain from the

delivery of coal to receiving at the generating station.

(4) No loss in calorific value between ‘GCV as billed’ and ‘GCV as received' shall be admissible

for generating stations procuring coal through import.

(5) The generating company shall provide to the beneficiaries of the generating station the details in

respect of GCV and price of fuel i.e. domestic coal, imported coal, e-auction coal, lignite, natural

gas, RLNG, liquid fuel etc., as per the Form 15 prescribed at Annexure-I (Part I) to these regulations:

Provided that the additional details of the weighted average GCV of the primary fuel on a

received basis used for generation during the period, the blending ratio of the imported coal with

domestic coal, and the proportion of e-auction coal shall be provided, along with the bills of the

respective month;

Provided further copies of the bills and details of parameters of GCV and price of fuel such

as domestic coal, imported coal, e-auction coal, lignite, natural gas, RLNG, liquid fuel, details of

blending ratio of the imported coal with domestic coal, the proportion of e-auction coal shall also

be displayed on the website of the generating company.

61. Landed Cost of Reagent: (1) Where specific reagents such as Limestone, Sodium Bi-

Carbonate, Urea or Anhydrous Ammonia are used during the operation of an emission control system

for meeting revised emission standards, the landed cost of such reagents shall be determined based

on the normative consumption and the purchase price of the reagent through competitive bidding,

103
applicable statutory charges and transportation cost.

(2) The normative consumption of specific reagents for the various technologies installed for meeting

revised emission standards shall be as specified in Regulation 70 of these regulations.

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 CHAPTER – 11

COMPUTATION OF CAPACITY CHARGES AND ENERGY CHARGES

62. Computation and Payment of Capacity Charge for Thermal Generating Stations:

(1) The fixed cost of a thermal generating station shall be computed on annual basis based on

the norms specified under these regulations and recovered on a monthly basis under capacity

charge. The total capacity charge payable for a generating station shall be shared by its

beneficiaries as per their respective percentage share or allocation in the capacity of the generating

station. The capacity charge shall be recovered in two parts, viz., Capacity Charge for Peak Hours

of the month and Capacity Charge for Off- Peak Hours of the month as follows:

(2) The Capacity Charge payable to a thermal generating station for a calendar month shall be

calculated in accordance with the following formulae:

Capacity Charge for the Month (CCn) =

Capacity Charge for Peak Hours of the Month (CCpn) +

Capacity Charge for Off-Peak Hours of the Month (CCopn)

Where,

CCp1= [(0.20 x AFC) x (1/12) x (PAFMp1/NAPAF) subject to ceiling of {(0.20 x AFC) x (1/12)}]

CCp2= [(0.20 x AFC) x (1/6) x ( PAFMp2/NAPAF) subject to ceiling of {(0.20 x AFC) x (1/6)}]

– CCp1

CCp3= [(0.20 x AFC) x (1/4) x (PAFMp3/NAPAF) subject to ceiling of {(0.20 x AFC) x (1/4)}]

- (CCp1+ CCp2)

CCp4= [(0.20 x AFC) x (1/3) x (PAFMp4/NAPAF) subject to ceiling of {(0.20 x AFC) x (1/3)}]

105
- (CCp1+ CCp2+CCp3)

CCp5= [(0.20 x AFC) x (5/12) x (PAFMp5/NAPAF) subject to ceiling of {(0.20 x AFC) x (5/12)}]

- (CCp1+ CCp2+CCp3+CCp4)

CCp6= [(0.20 x AFC) x (1/2) x (PAFMp6/NAPAF) subject to ceiling of {(0.20 x AFC) x (1/2)}] -

(CCp1+ CCp2+CCp3+CCp4+CCp5)

CCp7= [(0.20 x AFC) x (7/12) x (PAFMp7/NAPAF) subject to ceiling of {(0.20 x AFC) x (7/12)}]

- (CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6)

CCp8= [(0.20 x AFC) x (2/3) x (PAFMp8/NAPAF) subject to ceiling of {(0.20 x AFC) x (2/3)}] -

(CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6 +CCp7)

CCp9= [(0.20 x AFC) x (3/4) x (PAFMp9/NAPAF) subject to ceiling of {(0.20 x AFC) x (3/4)}] -

(CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6+CCp7+CCp8)

CCp10= [(0.20 x AFC) x (5/6) x (PAFMp10/NAPAF) subject to ceiling of {(0.20 x AFC) x (5/6)}]

- (CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6 +CCp7 +CCp8 +CCp9)

CCp11= [(0.20 x AFC) x (11/12) x (PAFMp12/NAPAF) subject to ceiling of {(0.20 x AFC) x

(11/12)}] - (CCp1+ CCp2+ CCp3+CCp4+CCp5+CCp6 +CCp7+CCp8+CCp9+CCp10)

CCp12= [(0.20 x AFC) x (PAFMp12/NAPAF) subject to ceiling of (0.20 x AFC)] - (CCp1+ CCp2+

CCp3+CCp4+CCp5+CCp6 +CCp7+CCp8+CCp9+CCp10+CCp11)

CCop1= (0.80 x AFC) x (1/12) x (PAFMop1/NAPAF) subject to ceiling of {(0.80 x AFC) x (1/12)}

CCop2= [(0.80 x AFC) x (1/6) x (PAFMop2/NAPAF) subject to ceiling of {(0.80 x AFC) x (1/6)}]

– CCop1

106
CCop3= [(0.80 x AFC) x (1/4) x (PAFMop3/NAPAF) subject to ceiling of {(0.80 x AFC) x (1/4)}]

- (CCop1+ CCop2)

CCop4= [(0.80 x AFC) x (1/3) x (PAFMop4/NAPAF) subject to ceiling of {(0.80 x AFC) x (1/3)}]

- (CCop1+ CCop2+CCop3)

CCop5= [(0.80 x AFC) x (5/12) x (PAFMop5/NAPAF) subject to ceiling of {(0.80 x AFC) x

(5/12)}] – (CCop1+ CCop2+CCop3+CCop4)

CCop6= [(0.80 x AFC) x (1/2) x (PAFMop6/NAPAF) subject to ceiling of {(0.80 x AFC) x (1/2)}]

– (CCop1+ CCop2+CCop3+CCop4+CCop5)

CCop7= [(0.80 x AFC) x (7/12) x (PAFMop7/NAPAF) subject to ceiling of {(0.80 x AFC) x

(7/12)}] - ((CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6)

CCop8= [(0.80 x AFC) x (2/3) x (PAFMop8/NAPAF) subject to ceiling of {(0.80 x AFC) x (2/3)}]

- (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6+CCop7)

CCop9= [(0.80 x AFC) x (3/4) x (PAFMop9/NAPAF) subject to ceiling of {(0.80 x AFC) x (3/4)}]

- (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6+CCop7+CCop8)

CCop10= [(0.80 x AFC) x (5/6) x (PAFMop10/NAPAF) subject to ceiling of {(0.80 x AFC) x (5/6)}]

- (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6+CCop7+CCop8 +CCop9)

CCop11= [(0.80 x AFC) x (11/12) x (PAFMop12/NAPAF) subject to ceiling of {(0.80 x AFC) x

(11/12)}] - (CCop1+ CCop2+CCop3+CCop4+CCop5+CCop6 +CCop7+CCop8+CCop9+CCop10)

CCop12= [(0.80 x AFC) x (PAFMop12/NAPAF) subject to ceiling of (0.80 x AFC)] - (CCop1+

CCop2+CCop3+CCop4+CCop5+CCop6+CCop7+CCop8 +CCop9+CCop10+CCop11)

107
 Provided that in case generating station or unit thereof is under shutdown due to

Renovation and Modernisation or installation of emission control system, as the case may

be, the generating company shall be allowed to recover O&M expenses and interest on loan

only.

Where,

CCm= Capacity Charge for the Month;

CCP= Capacity Charge for the Peak Hours of the Month;

CCop= Capacity Charge for the Off-Peak Hours of the Month;

CCpn= Capacity Charge for the Peak Hours of nth Month;

CCopn= Capacity Charge for the Off-Peak of nth Month;

AFC = Annual Fixed Cost;

PAFMpn= Plant Availability Factor achieved during Peak Hours up to the end of nth Month;

PAFMopn= Plant Availability Factor achieved during Off-Peak Hours up to the end of nth

Month;

NAPAF= Normative Annual Plant Availability Factor.

(3) Normative Plant Availability Factor for "Peak" and "Off-Peak" Hours in a month shall be

equivalent to the NAPAF specified in Clause (A) of Regulation 70 of these regulations. The number

of hours of "Peak" and "Off-Peak" periods during a day shall be four and twenty, respectively. The

hours of Peak and Off-Peak periods during a day shall be declared by the concerned RLDC at least

a week in advance.

Provided that RLDC, after duly considering the comments of the concerned stakeholders,

108
shall declare Peak Hours in such a way as to coincide with the majority of the Peak Hours of the

region to the maximum extent possible:

Provided further that in respect of a generating station having beneficiaries across different

regions, the Peak Hours shall correspond to Peak Hours of the region in which the majority of its

beneficiaries, in terms of percentage of allocation of share, are located.

The shortfall in recovery of Capacity Charge for cumulative Off-Peak Hours derived based

on NAPAF shall be allowed to be off-set by over-achievement of PAF, if any, and consequent

notional over-recovery of Capacity Charge for cumulative Peak Hours.

Provided that the shortfall in recovery of Capacity Charge for cumulative Peak Hours derived

based on NAPAF, shall not be allowed to be off-set by over-achievement of PAF, if any, and

consequent notional over-recovery of Capacity Charge for cumulative Off-Peak Hours.

(4) The Plant Availability Factor for a Month ('PAFM') shall be computed in accordance with

the following formula:

𝑛
𝐷𝐶𝑖
𝑃𝐴𝐹𝑀 = 10000 𝑥 ∑ %
[𝑁 𝑥 𝐼𝐶 𝑥 (100 − 𝐴𝑈𝑋𝑛 − 𝐴𝑈𝑋𝑒𝑛)]
𝑖=1

Where,

AUXn = Normative auxiliary energy consumption as a percentage of gross energy generation;

AUXen= Normative auxiliary energy consumption for emission control system as a percentage of

gross energy generation, wherever applicable;

DCi = Average declared capacity (in ex-bus MW), for the ith day of the period i.e. the month or the

year, as the case may be, as certified by the concerned load dispatch centre after the day is over;

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IC = Installed Capacity (in MW) of the generating station;

n = Number of days during the period;

Note: DCi and IC shall exclude the capacity of generating units not declared under commercial

operation. In case of a change in IC during the concerned period, its average value shall be taken.

(5) In addition to the AFC entitlement as computed above, the thermal generating station shall

be allowed an incentive of up to 1.00% of AFC approved for a given year, which shall be billed

monthly as per the following.

Incentive = (1.00% x ß x CCy)/12

Where,

ß = Average Monthly Frequency Response Performance for that generating station, as

certified by RPCs, which shall be computed by considering primary response as per

the methodology prescribed by the NLDC with approval of the Commission, and ß

shall range between 0 to 1.

Provided that the incentive shall be payable only if the Beta value is higher than 0.30.

CCy= Capacity Charges for the Year.

(6) In addition to the capacity charge, an incentive shall be payable to a generating station or unit

thereof @ 75 paise/ kWh for ex-bus scheduled energy during Peak Hours and @ 55 paise/ kWh for

ex-bus scheduled energy during Off-Peak Hours corresponding to scheduled generation in excess of

ex-bus energy corresponding to Normative Annual Plant Load Factor (NAPLF) achieved on a

cumulative basis, as specified in Clause (B) of Regulation 70 of these regulations.

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63. Computation and Payment of Supplementary Capacity Charge for Coal or Lignite

based Thermal Generating Stations:

(1) The fixed cost of the emission control system shall be computed on an annual basis based on the

norms specified under these regulations and recovered on a monthly basis under a supplementary

capacity charge. The total supplementary capacity charge is payable for a generating station shall be

shared by its beneficiaries as per their respective percentage share or allocation in the capacity of the

generating station.

(2) The Supplementary Capacity Charge payable to a coal or lignite generating station for a

calendar month shall be calculated in accordance with the following formulae:

SCC1= (AFCe) x (1/12) x (PAFM1/NAPAF) subject to ceiling of {(AFCe) x (1/12)}

SCC2= [(AFCe) x (1/6) x (PAFM2/NAPAF) subject to ceiling of {(AFCe) x (1/6)}] – SCC1

SCC3= [(AFCe) x (1/4) x (PAFM3/NAPAF) subject to ceiling of {(AFCe) x (1/4)}] - (SCC1+

SCC2)

SCC4= [(AFCe) x (1/3) x (PAFM4/NAPAF) subject to ceiling of {(AFCe) x (1/3)}] - (SCC1+

SCC2 + SCC3)

SCC5= [(AFCe) x (5/12) x (PAFM5/NAPAF) subject to ceiling of {(AFCe) x (5/12)}] - (SCC1+

SCC2+SCC3+SCC4)

SCC6= [(AFCe) x (1/2) x (PAFM6/NAPAF) subject to ceiling of {(AFCe) x (1/2)}] - (SCC1+

SCC2+SCC3+SCC4+SCC5)

SCC7= [(AFCe) x (7/12) x (PAFM7/NAPAF) subject to ceiling of {(AFCe) x (7/12)}] -

(SCC1+SCC2+ SCC3+SCC4+SCC5+SCC6)

SCC8= [(AFCe) x (2/3) x (PAFM8/NAPAF) subject to ceiling of {(AFCe) x (2/3)}] - (SCC1+

111
 SCC2+ SCC3+SCC4+SCC5+SCC6 +SCC7)

SCC9= [(AFCe) x (3/4) x (PAFM9/NAPAF) subject to ceiling of {(AFCe) x (3/4)}] - (SCC1+

SCC2+ SCC3+SCC4+SCC5+SCC6+SCC7+SCC8)

SCC10= [(AFCe) x (5/6) x (PAFM10/NAPAF) subject to ceiling of {(AFCe) x (5/6)}] - (SCC1+

SCC2+ SCC3+SCC4+SCC5+SCC6 +SCC7 +SCC8 +SCC9)

SCC11= [(AFCe) x (11/12) x (PAFM11/NAPAF) subject to ceiling of {(AFCe) x (11/12)}] -

(SCC1+ SCC2+ SCC3+SCC4+SCC5+SCC6 +SCC7+SCC8+SCC9+SCC10)

SCC12= [(AFCe) x (PAFM12/NAPAF) subject to ceiling of (AFCe)] - (SCC1+ SCC2+

SCC3+SCC4+SCC5+SCC6 +SCC7+SCC8+SCC9+SCC10+SCC11)

Provided that in case of the generating station or unit thereof under shutdown due to

Renovation and Modernisation, the generating company shall be allowed to recover O&M expenses

and interest on the loan in respect of the emission control system only.

Where,

SCCn= Supplementary Capacity Charge for the nth Month;

AFCe = Annual Fixed Cost of the emission control system;

PAFMn= Plant Availability Factor achieved up to the end of nth Month;

NAPAF= Normative Annual Plant Availability Factor.

(3) Normative Plant Availability Factor for a month for the purpose of Supplementary Capacity

Charge shall be considered in the manner specified in Clause (3) of Regulation 62 of these

regulations. The PAFM shall be worked out in accordance with Clause (4) of Regulation 62 of

these regulations.

112
64. Computation and Payment of Energy Charge for Thermal Generating Stations and

Supplementary Energy Charge for Coal or Lignite based Thermal Generating Stations:

(1) The energy charge shall cover the primary and secondary fuel cost and limestone

consumption cost (where applicable) and shall be payable by every beneficiary for the total

energy scheduled to be supplied to such beneficiary during the calendar month on an ex-power

plant basis, at the energy charge rate of the month (with fuel and limestone price adjustment).

The total Energy charge payable to the generating company for a month shall be:

Energy Charges = (Energy charge rate in Rs./kWh) x {Scheduled energy (ex bus) for the

month in kWh}

(2) The supplementary energy charge on account of the emission control system shall cover the

differential energy charges due to auxiliary energy consumption and cost of reagent consumption

and shall be payable by every beneficiary for the total energy scheduled to be supplied to such

beneficiary during the calendar month on an ex-power plant basis, at the supplementary energy

charge rate of the month. The total supplementary energy charge payable to the generating

company for a month shall be:

Supplementary Energy Charges = (Supplementary energy charge rate in

Rs./kWh) x {Scheduled energy (ex-bus) for the month in kWh}

(3) Energy charge rate (ECR) and Supplementary Energy charge rate in Rupees per kWh on ex-

power plant basis shall be determined to three decimal places in accordance with the following

formulae:

(a) ECR for coal based and lignite fired stations:

ECR = [{(SHR - SFC x CVSF) x LPPF / CVPF} + (SFC x LPSFi) + (LC x LPL)] x 100

113
 /(100 - AUX)

(b) Supplementary ECR for coal and lignite based thermal generating stations:

Supplementary ECR = (ECR) + [(SRC x LPR / 10)/(100-(AUXn + AUXen))]

(c) For gas and liquid fuel based stations:

ECR = SHR x LPPF x 100/ {(CVPF) x (100 - AUX)}

Where,

AUX =Normative auxiliary energy consumption in percentage.

CVPF = (a) Weighted Average Gross calorific value of coal considering GCV as per

Regulation 60, in kCal per kg for coal based stations less 85 Kcal/Kg on account of variation

during storage at generating station;

(b) Weighted Average Gross calorific value of primary fuel as received, in kCal per kg, per

litre or per standard cubic meter, as applicable for lignite, gas and liquid fuel based stations;

(d) In the case of blending of fuel from different sources, the weighted average Gross calorific

value of the primary fuel shall be arrived at in proportion to the blending ratio:

CVSF = Calorific value of secondary fuel, in kCal per ml;

ECR = Energy charge rate, in Rupees per kWh sent out;

SHR = Gross station heat rate, in kCal per kWh;

LC = Normative limestone consumption in kg per kWh;

LPL = Weighted average landed cost of limestone in Rupees per kg;

LPPF = Weighted average landed fuel cost of primary fuel, in Rupees per kg, per litre or per

standard cubic metre, as applicable, during the month. (In case of blending of fuel from

114
 different sources, the weighted average landed fuel cost of primary fuel shall be arrived in

proportion to the blending ratio);

SFC = Normative Specific fuel oil consumption, in ml per kWh;

LPSFi = Weighted Average Landed Fuel Cost of Secondary Fuel in Rs./ml during the month;

(ECR) = Difference between ECR with revised auxiliary energy consumption with

emission control system equivalent to (AUXn + AUXen) and ECR with normative auxiliary

energy consumption as specified in these regulations;

SRC = Specific reagent consumption on account of revised emission standards (in g/kWh);

LPR = Weighted average landed price of reagent for the emission control system (in Rs./kg).

Provided that the energy charge rate for a gas or liquid fuel based station shall be adjusted for

open cycle operation based on certification of the Member Secretary of the respective Regional

Power Committee during the month.

In case of part or full use of an alternative source of fuel supply by coal based thermal generating

stations other than as agreed by the generating company and beneficiaries in their power purchase

agreement for the supply of contracted power on account of a shortage of fuel or optimization of

economical operation through blending, the use of an alternative source of fuel supply shall be

permitted to generating station:

Provided that the weighted average price of alternative source of fuel shall not exceed 30% of base

price of fuel computed as per clause (5) of this Regulation and in such case, prior permission from

beneficiaries shall not be a pre-condition, unless otherwise agreed specifically in the power purchase

agreement:

Provided further that where the energy charge rate based on weighted average price of fuel upon use

115
of alternative source of fuel supply exceeds 30% of base energy charge rate as approved by the

Commission for that year or exceeds 20% of energy charge rate for the previous month, whichever

is lower shall be considered and, in that event, prior consultation with beneficiary shall be made at

least three days in advance.

(4) Notwithstanding anything contained in clause 3 of this Regulation, the Commission after

considering the shortage of fuel, may vary through separate Order(s), the blending ratio and the

requirement of beneficiary consent thereof, towards use of alternative source of fuel..

(5) Where biomass fuel is used for blending with coal, the landed cost of biomass fuel shall be

worked out based on the delivered cost of biomass at the unloading point of the generating station,

inclusive of taxes and duties as applicable. The energy charge rate of the blended fuel shall be worked

out considering the consumption of biomass based on the blending ratio as specified by the Authority

or the actual consumption of biomass, whichever is lower.

(6) The Commission, through specific tariff orders to be issued for each generating station, shall

approve the energy charge rate at the start of the tariff period. The energy charge rate so approved

shall be the base energy charge rate for the first year of the tariff period. The base energy charge rate

for subsequent years shall be the energy charge computed after escalating the base energy charge

rate by escalation rates for payment purposes as notified by the Commission from time to time under

competitive bidding guidelines.

(7) The tariff structure as provided in Regulation 63 and Regulation 64 of these regulations may

be adopted by the Department of Atomic Energy, Government of India, for the nuclear generating

stations by specifying annual fixed cost (AFC), normative annual plant availability factor

(NAPAF), installed capacity (IC), normative auxiliary energy consumption (AUX) and energy

charge rate (ECR) for such stations.

116
65. Computation and Payment of Capacity Charge and Energy Charge for Hydro

Generating Stations:

(1) The fixed cost of a hydro generating station shall be computed on an annual basis, based on

norms specified under these regulations, and shall be recovered on a monthly basis under capacity

charge (inclusive of incentive) and energy charge, which shall be payable by the beneficiaries in

proportion to their respective allocation in the saleable capacity of the generating station, i.e., in

the capacity excluding the free power to the home State:

Provided that during the period between the date of commercial operation of the first unit of

the generating station and the date of commercial operation of the generating station, the annual

fixed cost shall provisionally be worked out based on the latest estimate of the completion cost for

the generating station, for the purpose of determining the capacity charge and energy charge

payment during such period.

(2) The capacity charge (inclusive of incentive) payable to a hydro generating station for a

calendar month shall be:

AFC x 0.5 x NDM / NDY x (PAFM / NAPAF) (in Rupees)

Where,

AFC = Annual fixed cost specified for the year, in Rupees

NAPAF = Normative plant availability factor in percentage

NDM = Number of days in the month

NDY = Number of days in the year

PAFM = Plant availability factor achieved during the month, in percentage

117
(3) The PAFM shall be computed in accordance with the following formula:

𝑁
DCi
PAFM = 10000 x ∑ {N (100
%
𝑖=1 x IC x − AUX)}

Where

AUX = Normative auxiliary energy consumption in percentage

DCi = Declared capacity (in ex-bus MW) for the ith day of the month, which the station can

deliver for at least three (3) hours, as certified by the nodal load dispatch centre after

the day is over.

IC = Installed capacity (in MW) of the complete generating station

N = Number of days in the month

(4) In addition to the AFC entitlement as computed above, the hydro generating station shall be

allowed an incentive of up to 3% of the Capacity Charge approved for a given year which

shall be billed monthly as per the following.

Incentive = (3% x ß x CCy)/12

Where,

ß = Average Monthly Frequency Response Performance for that generating station, as

certified by RPCs, which shall be computed by considering primary response as per

the methodology prescribed by the NLDC with approval of the Commission and beta

shall range between 0 to 1.

Provided that incentive shall be payable only if Beta value is higher than 0.30.

CCy= Capacity Charges for the Year.

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 (5) The energy charge shall be payable by every beneficiary for the total energy scheduled to be

supplied to the beneficiary, excluding free energy, if any, during the calendar month, on the ex-bus

basis, at the computed energy charge rate. The total energy charge payable to the generating

company for a month shall be:

Energy Charges = (Energy charge rate in Rs. / kWh) x {Scheduled energy (ex-bus) for the month

in kWh} x (100 – FEHS) / 100

(6) Energy charge rate (ECR) in Rupees per kWh on ex-power plant basis, for a hydro generating

station, shall be determined up to three decimal places based on the following formula, subject to the

provisions of clause (8) of this Regulation:

ECR = AFC x 0.5 x 10 / {DE x (100 – AUX) x (100 – FEHS)}

Where,

DE = Annual design energy specified for the hydro generating station, in MWh, subject to the

provision in clause (7) below.

FEHS = Free energy for home State, in per cent, as mentioned in EXPLANATION-III under

Regulation 76 of these regulations.

(7) In case the saleable scheduled energy (ex-bus) of a hydro generating station during a year is less

than the saleable design energy (ex-bus) for reasons beyond the control of the generating station, the

generating station may directly recover the shortfall in energy charges in six equal interest-free

monthly instalments after adjusting for DSM Energy in the immediately following year and shall be

subject to truing up at the end of the tariff period.

Provided that in case actual generation from a hydro generating station is less than the

design energy for a continuous period of four years on account of hydrology factor, the generating

119
station shall approach the Central Electricity Authority with relevant hydrology data for revision of

design energy of the station.

(8) Any shortfall in the energy charges on account of saleable scheduled energy (ex-bus) being less

than the saleable design energy (ex-bus) during the tariff period 2019-24, which was beyond the

control of the generating station and which could not be recovered during the said tariff period shall

be recovered in accordance with clause (7) of this Regulation.

(9) In case the energy charge rate (ECR) for a hydro generating station, computed as per clause (5)

of this Regulation exceeds one hundred and thirty paise per kWh, and the actual saleable energy in

a year exceeds {DE x (100- AUX) x (100 - FEHS) /10000} MWh, the energy charge for the energy

in excess of the above shall be billed at one hundred and thirty paise per kWh only.

(10) In addition to the above, an incentive shall be payable to a ROR Hydro generating station @

50 paise/ kWh corresponding to the saleable scheduled energy during peak hours of the day in excess

of average saleable scheduled energy during the day (24 hours).

66. Computation and Payment of Capacity Charge and Energy Charge for Pumped Storage

Hydro Generating Stations:

(1) The fixed cost of a pumped storage hydro generating station shall be computed on an annual

basis, based on norms specified under these regulations, and recovered on a monthly basis as a

capacity charge. The capacity charge shall be payable by the beneficiaries in proportion to their

respective allocation in the saleable capacity of the generating station;

Provided that during the period between the date of commercial operation of the first unit of

the generating station and the date of commercial operation of the generating station, the annual

fixed cost shall be worked out based on the latest estimate of the completion cost for the generating

station, for the purpose of determining the capacity charge payment during such period.

120
(2) The capacity charge payable to a pumped storage hydro generating station for a calendar month

shall be:

(AFC x NDM / NDY) (In Rupees), if actual Generation during the month is ≧ 75 % of the Pumping

Energy consumed by the station during the month and {(AFC x NDM / NDY) x (Actual Generation

during the month during peak hours/ 75% of the Pumping Energy consumed by the station during

the month) (in Rupees)}, if actual Generation during the month is < 75 % of the Pumping Energy

consumed by the station during the month.

Where,

AFC = Annual fixed cost specified for the year, in Rupees

NDM = Number of days in the month

NDY = Number of days in the year

Provided that there would be adjustments at the end of the year based on actual generation

and actual pumping energy consumed by the station during the year.

(3) The energy charge shall be payable by every beneficiary for the total energy scheduled to be

supplied to the beneficiary in excess of the design energy plus 75% of the energy utilized in pumping

the water from the lower elevation reservoir to the higher elevation reservoir, at a flat rate equal to

the average energy charge rate of 20 paise per kWh, if any, during the calendar month, on ex power

plant basis.

(4) Energy charge payable to the generating company for a month shall be:

= 0.20 x {(Scheduled energy (ex-bus) for the month in kWh- Design Energy for the month

(DEm)) + 75% of the energy utilized in pumping the water from the lower elevation reservoir

to the higher elevation reservoir of the month)}/ 100.

121
 Where,

DEm = Design energy for the month specified for the hydro generating station, in MWh

Provided that in case the Scheduled energy in a month is less than the Design Energy for the

month plus 75% of the energy utilized in pumping the water from the lower elevation reservoir to

the higher elevation reservoir of the month, then the energy charges payable by the beneficiaries

shall be zero.

Provided that if the energy for the pumping of water from lower reservoir to upper reservoir

is arranged by the generating company, the charges for the pumping energy till the ex-Bus of the

generating station shall be payable by the beneficiaries in proportion to their respective allocation in

the saleable capacity of the generating station.

(5) The generating company shall maintain the record of daily inflows of natural water into the

upper elevation reservoir and the reservoir levels of the upper elevation reservoir and lower elevation

reservoir on an hourly basis. The generator shall be required to maximize the peak hour supplies

with the available water, including the natural flow of water. In case it is established that the

generator is deliberately or otherwise, without any valid reason, not pumping water from a lower

elevation reservoir to a higher elevation during off-peak periods or not generating power to its

potential or wasting the natural flow of water, the capacity charges of the day shall not be payable

by the beneficiary. For this purpose, outages of the unit(s)/station, including planned outages and

forced outages up to 15% in a year, shall be construed as the valid reason for not pumping water

from the lower elevation reservoir to the higher elevation during an off-peak period or not generating

power using the energy of pumped water or natural flow of water:

Provided that the total capacity charges recovered during the year shall be adjusted on a pro-rata

basis in the following manner in the event of total machine outages in a year exceeding 15%:

122
(ACC)adj = (ACC) R x (100- ATO)/85

Where,

(ACC)adj - Adjusted Annual Capacity Charges

(ACC) R - Annual Capacity Charges recovered

ATO - Total Outages in percentage for the year including forced and planned outages

Provided further that the generating station shall be required to declare its machine availability daily

on day ahead basis for all the time blocks of the day in line with the scheduling procedure of Grid

Code.

(6) The concerned Load Despatch Centre shall finalise the schedules for the hydro generating

stations, in consultation with the beneficiaries, for optimal utilization of all the energy declared to be

available, which shall be scheduled for all beneficiaries in proportion to their respective allocations

in the generating station.

67. Computation and Payment of Transmission Charge for Inter-State Transmission

System and Communication System:

(1) The fixed cost of the transmission system or communication system forming part of the

transmission system shall be computed on an annual basis, in accordance with norms contained in

these regulations, aggregated as appropriate, and recovered on a monthly basis as transmission

charge from the users, who shall share these charges in the manner specified in clause (2) of this

Regulation.

(2) The Transmission charge (inclusive of incentive) payable for a calendar month for the

transmission system or part shall be computed for each region separately for the AC and DC system

as under:

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For AC system:

a) For TAFMn≦98.00%

AFC x (NDMn/NDY) x (TAFMn/98.00%)

b) For TAFMn: 98.00%<TAFMn< 98.50%

AFC x (NDMn/NDY) x (1)

c) For TAFMn: 98.50%<TAFMn ≦ 99.75%

AFC x (NDMn/NDY) x (TAFM/98.50%)

d) For TAFMn> 99.75%

AFC x (NDMn/NDY) x (99.75%/98.50%)

Where,

AFC = Annual Fixed Cost specified for the year in Rupees

NDMn = Number of days in nth month

NDY = Number of days in the year

TAFMn = Transmission System availability factor for the nth month, in percent computed in

accordance with Appendix IV.

For HVDC bi-pole links and HVDC back-to-back Stations:

TC1= AFC x (NDM1 / NDY) x (TAFM1/NATAF)

TC2 = AFC x (NDM2 / NDY) x (TAFM2/NATAF) – TC1

TC3 = AFC x (NDM3 / NDY) x (TAFM3/NATAF) - (TC1+TC2)

TC4 = AFC x (NDM4 / NDY) x (TAFM4/NATAF) - (TC1+TC2+TC3)

124
…..

TC11 = AFC x (NDM11/NDY) x (TAFM11/NATAF) - (TC1+TC2+....+TC10)

TC12= AFC x (TAFY/NATAF) - (TC1+TC2+....+TC11);

If,

(i) TAFM: 95.00%< TAFM < 97.50%, then TAFM=NATAF;

(ii) TAFM: 97.50%≦ TAFM ≦ 99.75%, then NATAF=97.50%; and

(iii) For TAFM ≧ 99.75%, then TAFM=99.75% and NATAF= 97.50%.

Where,

TCn = Transmission charges inclusive of incentive up to the nth month

AFC = Annual fixed cost specified for the year in rupees

NATAF = Normative Annual Transmission Availability Factor in percentage

NDMn = No of days up to the end of the nth month of the financial year

NDY = No. of days in the year

TAFMn. = Transmission availability factor up to the end of the nth month of the year in

percentage computed in accordance with Appendix -IV

TAFY = Transmission availability factor in per cent for the year.

(3) The transmission charges shall be calculated separately for part of the transmission system

having different NATAF and aggregated thereafter, according to their sharing by the long term

customers or DICs or GNA grantee. The charges of the communication system shall be a part of the

transmission charges and shall be shared by the long term customers.

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68. Deviation Charges: (1) Variations between actual net injection and scheduled net injection

for the generating stations, and variations between actual net drawl and scheduled net drawl for the

beneficiaries shall be treated as their respective deviations and charges for such deviations shall be

governed by the Central Electricity Regulatory Commission (Deviation Settlement Mechanism and

Related matters) Regulations, 2022.

(2) The actual net deviation of every generating station and Beneficiary shall be metered on its

periphery through special energy meters (SEMs) installed by the Central Transmission Utility

(CTU), and computed in MWh for each 15-minute time block by the concerned Regional Load

Despatch Centre.

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 CHAPTER - 12

NORMS OF OPERATION

69. Recovery of Tariff and Incentive: (1) Recovery of capacity charge, energy charge, supplementary

capacity charge, supplementary energy charge, transmission charge and incentive by the generating

company and the transmission licensee shall be based on the achievement of the operational norms

specified in the Regulation 70 to Regulation 72 of these regulations.

(2) The Commission may on its own revise the norms of Station Heat Rate specified in Regulation

70(C) of these regulations in respect of any of the generating stations for which relaxed norms have

been specified.

Norms of operation for thermal generating station

70. The norms of operation as given hereunder shall apply to thermal generating stations:

(A) Normative Annual Plant Availability Factor (NAPAF)

(a) 85% for all thermal generating stations, except those covered under clauses (b), (c), (d) and

(e);

(b) 83% for coal and lignite based generating stations completing 30 years from COD as on

31.03.2024;

(c) For the following Gas based Thermal generating stations of NEEPCO:

Assam GPS 70%

Agartala GPS 85%

Tripura GPS 85%

(d) Lignite fired generating stations using Circulatory Fluidized Bed Combustion (CFBC)

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Technology and generating stations based on coal rejects:

1. First Three years from the date of commercial operation – 68.50%

2. After completion of three years of the date of commercial operation - 75%

(e) For following lignite fired thermal generating stations of NLC India Ltd.

1. TPS-II State-I and Stage-II : 80%

2. Barsingsar (CFBC) : 75%

3. TPS-II Expansion (CFBC) : 70%

4. TPS-1 Expansion : 85%

5. New Neyveli TPS : 80%

(B) Normative Annual Plant Load Factor (NAPLF) for Incentive:

(a) 85% for all thermal generating stations, except for those covered under clause (b)

below

(b) 83% for coal and lignite based generating stations completing 30 years from COD as

on 31.03.2024

(C) Gross Station Heat Rate:

(a) Existing Thermal Generating Stations achieving COD before 1.4.2009

(i) For Coal-based Thermal generating stations other than those covered under clause (ii)

below:

200-300 MW Sets 500 MW Sets (Sub-critical)

2,415kCal/kWh 2,375kCal/kWh

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Note 1

In respect of 500 MW and above units where the boiler feed pumps are electrically operated, the

gross station heat rate shall be 40 kCal/kWh lower than the gross station heat rate specified above.

Note 2

For the generating stations having combination of 200/210/250 MW and above sets and 500 MW

and above sets, the normative gross station heat rate shall be the weighted average gross station heat

rate of the combinations.

Note 3

The normative gross station heat rate above is exclusive of the compensation specified as per the

Grid Code. The generating company shall, based on the unit loading factor, consider the

compensation in addition to the normative gross heat rate above.

Note 4

The gross station heat rate for the unit capacity of less than 200 MW sets, shall be dealt with on a

case-to-case basis.

(ii) For the following Thermal generating stations of NTPC Ltd:

Tanda TPS 2,750 kCal/kWh

(iii) Lignite-fired Thermal Generating Stations:

TPS-II (Stg I & II) : 2,880 kCal/kWh

TPS-I (Expansion) : 2,710 kCal/kWh

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 (iv) Open Cycle Gas Turbine/Combined Cycle Generating Stations: For the following gas-

based thermal generating stations:

Combined cycle Open Cycle

Name of generating station
(kCal/kWh) (kCal/kWh)

Gandhar GPS 2,040 2,960

Kawas GPS 2,050 3,010
Anta GPS 2,075 3,010
Dadri GPS 2,000 3,010
Auraiya GPS 2,100 3,045
Faridabad GPS 1,975 2,900
Kayamkulam GPS 2,000 2,900
Assam GPS 2,600 3,578
Agartala GPS 2,600 3,578
Ratnagiri 1,820 2,641

(b) Thermal Generating Stations achieving COD on or after 1.4.2009:

(i) For Coal-based and lignite-fired Thermal Generating Stations:

For 200-300 MW Sets. : 1.05 X Design Heat Rate (kCal/kWh)

For 500 MW Sets and above: 1.045 X Design Heat Rate (kCal/kWh)

Where the Design Heat Rate of a generating unit means the unit heat rate guaranteed by the

supplier at conditions of 100% MCR, zero per cent make up, design coal and design cooling

water temperature/back pressure.

Provided that depending upon the pressure and temperature ratings of the units, the

maximum design turbine cycle heat rate and minimum design boiler efficiency shall be as

per the table below:

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 Pressure Rating (Kg/cm2) 150 170 170
SHT/RHT (0C) 535/535 537/537 537/565
Electrical Turbine Turbine
Type of BFP Driven Driven Driven
Max Turbine Heat Rate
(kCal/kWh) 1955 1950 1935

Min. Boiler Efficiency

Sub-Bituminous Indian Coal (%) 86 86 86
Bituminous Imported Coal (%) 89 89 89

Pressure Rating
247 247 260 270 270
(Kg/cm2)
SHT/RHT (0C) 537/565 565/593 593/593 593/593 600/600
Turbine Turbine Turbine Turbine Turbine
Type of BFP
Driven Driven Driven Driven Driven

Max Turbine Heat

1900 1850 1814 1810 1790
Rate (kCal/kWh)
Min. Boiler Efficiency (%)
Sub-Bituminous Indian
86.00 86.00 86.00 86.50 86.50
Coal (%)
Bituminous Imported
89.00 89.00 89.50 89.50 89.50
Coal (%)
* For Lignite fired thermal generating station, the minimum boiler efficiency shall be 76% (for
pulverised) and 80% (for fluidised bed) based boilers.
In case designed turbine cycle heat rate and boiler efficiency are better than these values, the same

shall be considered for calculation of design unit heat rate.

Provided further that in case the pressure and temperature parameters of a unit are different

from the above ratings, the maximum design heat rate of the unit of the nearest class shall be taken:

Provided also that where the heat rate of the unit has not been guaranteed but turbine cycle

heat rate and boiler efficiency are guaranteed separately by the same supplier or different suppliers,

131
the design heat rate of the unit shall be arrived at by using guaranteed turbine cycle heat rate and

boiler efficiency:

Provided also that where the boiler efficiency is lower than 86% for Sub- bituminous Indian

coal and 89% for bituminous imported coal, the same shall be considered as 86% and 89% for Sub-

bituminous Indian coal and bituminous imported coal, respectively, for computation of station heat

rate:

Provided units based on a dry cooling system, the maximum turbine cycle heat rate shall be

considered as per the actual design or 6% higher than the values given in the table above,

whichever is lower;

Provided also that in the case of coal based generating station, if one or more generating units

were declared under commercial operation prior to 1.4.2024, the heat rate norms for those generating

units as well as generating units declared under commercial operation on or after 1.4.2024 shall be

lowest of the heat rate norms considered by the Commission during tariff period 2019-24 or those

arrived at by above methodology or the norms as per the sub-clause (C)(a)(i) of this Regulation:

Provided also that for Generating stations based on coal rejects, the Commission shall approve the

Station Heat Rate on a case-to-case basis.

Note: In respect of generating units where the boiler feed pumps are electrically operated, the

maximum design heat rate of the unit shall be 40 kCal/kWh lower than the maximum design heat

rate of the unit specified above with turbine driven Boiler Feed Pump.

(ii) For the following Thermal generating stations of NTPC Ltd:

Kanti TPS 2,500 kCal/kWh

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(iii) For the following lignite generating stations of NLC India Ltd:

Barsingsar (2X125 MW) 2,525 kCal/kWh

(c) For Gas-based/ Liquid based Thermal Generating Unit(s)/ Block(s) having COD on or

after 1.4.2009:

For Natural Gas and RLNG= 1.050 X Design Heat Rate of the unit/block (kCal/kWh)

For Liquid Fuel=1.071 X Design Heat Rate of the unit/block for Liquid Fuel (kCal/kWh)

Where the Design Heat Rate of a unit shall mean the guaranteed heat rate for a unit at 100% MCR

and at site ambient conditions, and the Design Heat Rate of a block shall mean the guaranteed heat

rate for a block at 100% MCR, site ambient conditions, zero per cent make up, design cooling water

temperature/back pressure.

(d) The Gross Station Heat Rate norms as specified in sub-clauses (a) and (b) of this clause, in

respect of the coal and lignite based generating stations or units thereof (except for the generating

stations or units thereof for which relaxed norms have been specified) and commissioned till

31.3.2024 (before 2009 and after 2009) shall remain applicable for such generating stations or units

thereof for the remaining operational life of the respective generating stations or units thereof.

(D) Secondary Fuel Oil Consumption:

(a) For Coal-based generating stations: 0.50 ml/kWh

(b) For Coal-based generating stations with wall (front/rear/sides) fired boilers: 1.00 ml/kWh

(c) For Lignite-fired generating stations (Pulverised and CFBC): 1.0 ml/kWh

(d) For Coal-based generating stations of DVC:

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 Mejia TPS (Unit 1 to 3) 1.00 ml/kWh
Mejia TPS (Unit 4) 1.00 ml/kWh

(e) For Generating Stations based on Coal Rejects: 2.0 ml/kWh

(E) Auxiliary Energy Consumption:

(a) For Coal-based generating stations except at (b) below:

With Natural Draft cooling tower

S. No. Generating Station or without cooling tower
(i) 200-300 MW series 8.50%
(ii) 300/ 330/ 350/ 500 MW and above
Steam driven boiler feed pumps 5.25%
Electrically driven boiler feed pumps 8.00%
(iii) 600 MW and above
Steam driven boiler feed pumps 5.25%
Electrically driven boiler feed pumps 8.00%

Provided that for thermal generating stations with induced draft cooling towers and where

ball and tube-type coal mill is used, the norms shall be further increased by 0.5% and 0.8%,

respectively:

Provided further that Additional Auxiliary Energy Consumption as follows shall be

allowed for plants with Dry Cooling Systems:

(% of gross
Type of Dry Cooling System
generation)
Direct cooling air cooled condensers with mechanical draft
1.0%
fans
Indirect cooling system employing jet condensers with 0.5%
pressure recovery turbine and natural draft tower

Note: The auxiliary energy consumption for the unit capacity of less than 200 MW sets shall be

dealt with on a case-to-case basis.

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(b) For other Coal-based generating stations:

(i) Tanda Thermal Power Station 12.00%

(ii) Chandrapur TPS (2x250 MW) (DVC) 9.50%

(c) For Gas Turbine /Combined Cycle generating stations:

(i) Combined Cycle : 2.75%

(ii) Open Cycle : 1.00%

Provided that where the gas based generating station is using electric motor driven Gas

Booster Compressor, the Auxiliary Energy Consumption in case of Combined Cycle mode shall be

3.30% (including the impact of air-cooled condensers for Steam Turbine Generators):

Provided further that an additional Auxiliary Energy Consumption of 0.35% shall be

allowed for Combined Cycle Generating Stations having direct cooling air cooled condensers with

mechanical draft fans.

(iii) Tripura CCPP : 3.50%

(iv) OTPC Palatana CCPP : 3.50%

(d) For Lignite-fired thermal generating stations:

(i) For all generating stations with 200 MW sets and above:

The auxiliary energy consumption norms shall be 0.5 percentage points more than the auxiliary

energy consumption norms of coal-based generating stations at (E) (a) above.

Provided that for the lignite fired stations using CFBC technology, the auxiliary energy

consumption norms shall be 1.5 percentage points more than the auxiliary energy consumption

norms of coal-based generating stations at (E) (a) above.

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(ii) For Barsingsar Generating station of NEC using CFBC technology: 12.50%

(iii) For TPS-I (Expansion) and TPS-II Stage-I&II of NLC India Ltd.:

TPS-II Stage-I and Stage-II 10.00%

TPS-II (Expansion) 12.50%

(e) For Generating Stations based on coal rejects: 10%

(f) Norms of Auxiliary energy consumption for the emission control system (AUXen) of thermal

generating stations:

AUXen (as % of
Name of Technology gross generation)
(1) For reduction of emission of Sulphur dioxide:
a) Wet Limestone based FGD system (without 1.0%
Gas to Gas heater )
b) Lime Spray Dryer or Semi dry FGD System 1.0%
c) Dry Sorbent Injection System (using Sodium NIL
bicarbonate)
d) For CFBC Power plant (furnace injection) NIL
e) Sea water based FGD system (without Gas 1.00%
to Gas heater)
(2) For reduction of emission of oxide of nitrogen:
a) Selective Non-Catalytic Reduction NIL
system
b) Selective Catalytic Reduction system 0.2%

Provided that where the technology is installed with a "Gas to Gas" heater, AUXen specified

above shall be increased by 0.20% of gross generation.

(F) Norms for consumption of reagent:

(1) The normative consumption of specific reagents for various technologies for the reduction of

emission of sulphur dioxide shall be as under:

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(a) For Wet Limestone based Flue Gas De-sulphurisation (FGD) system: The specific limestone

consumption (g/kWh) shall be worked out by following the formula:

[K x Normative heat rate (kcal/kWh) x Sulphur content of coal (%)/CVPF in kCal/Kg] x

[85/LP]g/kWh

Where,

GCV = (a) Weighted Average Gross calorific value of coal in kCal per kg for coal based thermal

generating stations computed in accordance with Regulation 60 of these regulations;

(b) Weighted Average Gross calorific value of lignite as received, in kCal per kg, as applicable

for lignite based thermal generating stations:

Provided that the value of K shall be equivalent to (35.2 x Design SO2 Removal Efficiency/96%)

to comply with the SO2 emission norm of 100/200 mg/Nm3 or (26.8 x Design SO2 Removal

Efficiency/73%) for units to comply with the SO2 emission norm of 600 mg/Nm3;

Provided further that the limestone purity shall not be less than 85%.

(b) For Lime Spray Dryer or Semi-dry Flue Gas Desulphurisation (FGD) system: The specific lime

consumption shall be worked out based on minimum purity of lime (LP) as at 90% or more by

applying formula [ 6 x90/LP] g/kWh;

(c) For Dry Sorbent Injection System (using sodium bicarbonate): The specific consumption of

sodium bicarbonate shall be 12 g per kWh at 100% purity.

(d) For CFBC Technology (furnace injection) based generating station: The specific limestone

consumption for CFBC based generating station (furnace injection) shall be computed with the

following formula:

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[62.9 x S x SHR/ CVPF] x[85/LP]

Where

S = Sulphur content in percentage,

LP = Limestone Purity in percentage,

SHR = Gross station heat rate, in kCal per kWh,

CVPF = (a) Weighted Average Gross calorific value of lignite as received, in kCal per kg as

applicable for lignite based thermal generating stations;

(e) For Sea Water based Flue Gas Desulphurisation (FGD) system: The reagent used in sea

water based Flue Gas Desulphurisation (FGD) system shall be NIL

(2) The normative consumption of specific reagent for various technologies for the reduction of

emission of oxide of nitrogen shall be as below:

(a) For Selective Non-Catalytic Reduction (SNCR) System: The specific urea consumption

of the SNCR system shall be 1.2 g per kWh at 100% purity of urea.

(b) For Selective Catalytic Reduction (SCR) System: The specific ammonia consumption of

the SCR system shall be 0.6 g per kWh at 100% purity of ammonia.

71. Norms of Operation for Hydro Generating Stations: The norms of operation as given

hereunder shall apply to hydro generating stations:

(A) Normative Annual Plant Availability Factor (NAPAF): (1) The following normative annual

plant availability factor (NAPAF) shall apply to hydro generating station:

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(a) Storage and Pondage type plants with head variation between Full Reservoir Level (FRL)

and Minimum Draw Down Level (MDDL) of up to 8%, and where plant availability is not affected

by silt: 90%;

(b) In the case of storage and pondage type plants with head variation between full reservoir

level and minimum draw down level is more than 8% and when plant availability is not affected by

silt, the month-wise peaking capability as provided by the project authorities in the DPR (approved

by CEA or the State Government) shall form the basis of fixation of NAPAF;

(c) Pondage type plants where plant availability is significantly affected by silt: 85%.

Run-of-river generating stations: NAPAF to be determined plant-wise, based on 10-day design

energy data, moderated by past experience where available/relevant.

(2) A further allowance may be made by the Commission in NAPAF determination under special

circumstances, e.g. abnormal silt problem or other operating conditions, and known plant limitations.

(3) A further allowance of 5% may be allowed for difficulties in North East Region.

(4) Based on the above, the Normative annual plant availability factor (NAPAF) of the hydro

generating stations already in operation shall be as follows: -

Station Type of Plant Plant Capacity No. of

Units x MW NAPAF (%)
THDC
THPS Storage 4x250 77
KHEP Storage 4x100 66

NHPC
Station Type of Plant Plant Capacity No. of
Units x MW NAPAF (%)
Bairasul Pondage 3x60 85
Loktak Pondage 3x35 88
Salal ROR 6x115 70
Tanakpur ROR 3x31.4 70
Chamera-I Pondage 3x180 90

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 Station Type of Plant Plant Capacity No. of
Units x MW NAPAF (%)
Uri I ROR 4x120 80
Rangit Pondage 3x20 90
Chamera-II Pondage 3x100 87
Dhauliganga Pondage 4x70 85
Dulhasti Pondage 3x130 90
Teesta-V Pondage 3x170 87
Sewa-II Pondage 3x40 86
TLDP III Pondage 4x33 80
Chamera III Pondage 3x77 87
Chutak ROR 4x11 48
Nimmo Bazgo Pondage 3x15 70
Uri II ROR 4x60 80
Parbati III Pondage 4x130 45
TLDP IV ROR with 4x40 90
Pondage
Kishanganga ROR with 3x110 83
Pondage
Teesta III Pondage 6x200 85

NHDC
Indira Sagar Storage 8x125 87
Omkareshwar Pondage 8x65 90

NEEPCO
Kopili I Storage 4x50 69
Khandong Storage 2x25 67
Kopili II Storage 1x25 69
Doyang Storage 3x25 65
Ranganadi Pondage 3x135 . 85
Tuirial Storage 2x30 75

NTPC
Koldam Storage 4x200 90

SJVNL
Nathpa Jhakri Pondage 6x250 87
Rampur Pondage 6x68.67 83

DVC
Panchet Storage 2x40 80
Tilaya Storage 2x2 80
Maithon Storage 3x20 80

Karcham Wangtoo ROR with 4x261.25 90

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 Station Type of Plant Plant Capacity No. of
Units x MW NAPAF (%)
Pondage

(B) In the case of pumped storage hydro generating stations, the quantum of electricity required

for pumping water from the down-stream reservoir to the up-stream reservoir shall be arranged by

the beneficiaries duly taking into account the transmission and distribution losses up to the bus bar

of the generating station. In return, beneficiaries shall be entitled to an equivalent energy of 75% of

the energy utilized in pumping the water from the lower elevation reservoir to the higher elevation

reservoir from the generating station during peak hours, and the generating station shall be under

obligation to supply such quantum of electricity during peak hours:

Provided that in the event of the beneficiaries failing to supply the desired level of energy during

off-peak hours, there will be a pro-rata reduction in their energy entitlement from the station during

peak hours:

Provided further that the beneficiaries may assign or surrender their share of capacity in the

generating station, in part or in full, or the capacity may be reallocated by the Central Government,

and in that event, the owner or assignee of the capacity share shall be responsible for arranging the

equivalent energy to the generating station in off-peak hours, and be entitled to corresponding energy

during peak hours in the same way as the original beneficiary was entitled.

(C) Auxiliary Energy Consumption (AEC):

AEC
Installed Installed Capacity
Type of Station
Capacity above upto
200 MW 200 MW
Surface
Rotating Excitation 0.7% 0.7%
Static 1.0% 1.2%
Underground

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 AEC
Installed Installed Capacity
Type of Station
Capacity above upto
200 MW 200 MW
Rotating Excitation 0.9% 0.9%
Static 1.2% 1.3%
* AEC for Tuirial HPS = 4%

Norms of operation for transmission system

72. Normative Annual Transmission System Availability Factor (NATAF):

(a) For recovery of Annual Fixed Cost, NATAF shall be as under:

(1) AC system: 98.00%;

(2) HVDC bi-pole links 95.00% and HVDC back-to-back stations: 95.00%:

Provided that the normative annual transmission availability factor of the HVDC bi-pole links shall

be 85% for the first twelve months from the date of commercial operation.

(b) For Incentive, NATAF shall be as under:

(1) AC system: 98.50%;

(2) HVDC bi-pole links and HVDC back-to-back Stations: 97.50%:

Provided that no Incentive shall be payable for availability beyond 99.75%:

Provided further that for AC and HVDC system, actual outage hours shall be considered for

computation of availability up to two tripping per year. After two tripping in a year, for every

tripping, an additional 12 hours of outage shall be considered in addition to the actual outage hours:

Provided also that in case of an outage of a transmission element affecting evacuation of power

from a generating station, outage hours shall be multiplied by a factor of 2.

73. Auxiliary Energy Consumption in the Sub-station

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(1) AC System: The charges for auxiliary energy consumption in the AC sub-station for the

purpose of air-conditioning, lighting and consumption in other equipment shall be borne by the

transmission licensee and included in the normative operation and maintenance expenses.

(2) HVDC sub-station: For auxiliary energy consumption in HVDC sub-stations, the Central

Government may allocate an appropriate share from one or more ISGS. The charges for such power

shall be borne by the transmission licensee from the normative operation and maintenance expenses.

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 CHAPTER - 13

SCHEDULING, ACCOUNTING AND BILLING

74. Scheduling: The methodology for scheduling and dispatch for the generating station shall be

as specified in the Grid Code.

75. Metering and Accounting: For metering and accounting, the provisions of the Grid Code

shall be applicable.

76. Billing and Payment of charges: (1) Bills shall be raised for capacity charge and energy

charge by the generating company and for transmission charge by the transmission licensee on a

monthly basis in accordance with these regulations, and payments shall be made by the beneficiaries

or the long term customers directly to the generating company or the transmission licensee, as the

case may be:

EXPLANATION-I: The physical copy of the Bill in Original at the office of the Authorised

Person of the beneficiary or long term customer, as the case may be, or the scanned copy of the

Original Bill through the official email ID of the Authorised Signatory of the Generating Company

or the Transmission Licensee, as the case may be, shall be recognized as a valid mode of presentation

of Bill:

EXPLANATION-II: Authorized Signatory or Signatories (official designation only) shall

be notified in advance by the Managing Director or Chief Executive Officer of the Company, and

any change in the list of Authorised Signatories for the purpose shall be communicated in the same

manner.

(2) Payment of the capacity charge for a thermal generating station shall be shared by the

beneficiaries of the generating station as per their percentage shares for the month (inclusive of any

144
allocation out of the unallocated capacity) in the installed capacity of the generating station. Payment

of capacity charge and energy charge for a hydro generating station shall be shared by the

beneficiaries of the generating station in proportion to their shares (inclusive of any allocation out of

the unallocated capacity) in the saleable capacity (to be determined after deducting the capacity

corresponding to free energy to home State as per Note 3 herein.

EXPLANATION-I: Shares or allocations of each beneficiary in the total capacity of Central sector

generating stations shall be as determined by the Central Government, inclusive of any allocation

made out of the unallocated capacity. The shares shall be applied in percentages of installed capacity

and shall normally remain constant for a month. Based on the decision of the Central Government,

the changes in allocation shall be communicated by the Member-Secretary, Regional Power

Committee in advance, at least three days prior to the beginning of a calendar month, except in case

of an emergency call for an urgent change in allocations out of unallocated capacity. The total

capacity share of a beneficiary would be the sum of its capacity share plus allocation out of the

unallocated portion.

EXPLANATION-II: The beneficiaries may propose surrendering part of their allocated firm share

to other States within or outside the region. In such cases, depending upon the technical feasibility

of power transfer and specific agreements reached by the generating company with other States

within or outside the region for such transfers, the shares of the beneficiaries may be re-allocated by

the Central Government for a specific period (in complete months) from the beginning of a calendar

month. When such re-allocations are made, the beneficiaries who surrender the share shall not be

liable to pay capacity charges for the surrendered share. The capacity charges for the capacity

surrendered and reallocated as above shall be paid by the State(s) to whom the surrendered capacity

is allocated. Except for the period of reallocation of capacity as above, the beneficiaries of the

145
generating station shall continue to pay the full capacity charges as per allocated capacity shares.

Any such reallocation and its reversion shall be communicated to all concerned by the Member

Secretary, Regional Power Committee in advance, at least three days prior to such reallocation or

reversion taking effect.

EXPLANATION-III: FEHS = Free energy for home State, in per cent and shall be taken as 13%

or actual, whichever is less.

Provided that in cases where the site of a hydro project is awarded to a developer, by the

State Government by following a two-stage transparent process of bidding, the 'free energy' shall

be taken as 13%, in addition to an energy corresponding to 100 units of electricity to be provided

free of cost every month to every project affected family for a period of 10 years from the date of

commercial operation of the generating station:

Provided further that the generating company shall submit a detailed quantification of

energy corresponding to 100 units of electricity to be provided free of cost every month to every

month to every project-affected family for a period of 10 years from the date of commercial

operation.

77. Recovery of Statutory Charges: The generating company shall recover the statutory charges

imposed by the State and Central Government, such as electricity duty and water cess, by considering

normative parameters specified in these regulations. In case the electricity duty is applied to the

auxiliary energy consumption, such amount of electricity duty shall apply to the normative auxiliary

energy consumption of the generating station (excluding colony consumption) and apportioned to

each of the beneficiaries in proportion to their scheduled dispatch during the month.

78. Sharing of Transmission Charges: (1) The sharing of transmission charges shall be

governed by the Sharing Regulations.

146
 (2) The charges determined under these regulations in relation to the communication system

forming part of the transmission system shall be shared by the beneficiaries or long term customers

in accordance with the Sharing Regulations:

Provided that charges determined under these regulations in relation to communication

systems other than that of the central portion shall be shared by the beneficiaries in proportion to

the capital cost belonging to respective beneficiaries.

79. Rebate: (1) For payment of bills of the generating company and the transmission licensee

through letter of credit on presentation or through National Electronic Fund Transfer (NEFT) or Real

Time Gross Settlement (RTGS) payment mode within a period of 5 days of presentation of bills by

the generating company or the transmission licensee, a rebate of 1.50% shall be allowed.

Provided that in case a different Rebate mechanism is provided in the PPA, the same shall be

governed by the provisions of the PPA.

Explanation: In case of computation of '5 days', the number of days shall be counted

consecutively without considering any holiday. However, in case the last day or day is an official

holiday, the 5th day for the purpose of Rebate shall be construed as the immediate succeeding

working day (as per the official State Government's calendar, where the Office of the Authorised

Signatory or Representative of the Beneficiary, for the purpose of receipt or acknowledgement

of Bill is situated).

(2) Where payments are made on any day after 5 days and within a period of 30 days of

presentation of bills by the generating company or the transmission licensee, a rebate of 1% shall

be allowed.

80. Late payment surcharge: (1) In case the payment of any bill for charges payable under these

regulations is delayed by a beneficiary or long term customer as the case may be, beyond a period

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of 45 days from the date of presentation of bills, a late payment surcharge as specified in the Ministry

of Power – Electricity (Late Payment Surcharge and Related Matters) Rules, 2022 as amended from

time to time shall be levied by the generating company or the transmission licensee, as the case may

be.

Provided that in case a different LPS mechanism is provided in the PPA, the same shall be

governed by the provisions of the PPA.

(2) Unless otherwise agreed by the parties, the charges payable by a beneficiary or long term

customer shall be first adjusted towards a late payment surcharge on the outstanding charges and,

thereafter, towards monthly charges billed by the generating company or the transmission licensee,

as the case may be, starting from the longest overdue bill.

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 CHAPTER – 14

SHARING OF BENEFITS

81. Sharing of gains due to variation in norms: (1) The generating company or the transmission

licensee shall work out gains based on the actual performance of applicable Controllable parameters

as under:

i) Station Heat Rate;

ii) Secondary Fuel Oil Consumption; and

iii) Auxiliary Energy Consumption.

(2) The financial gains by the generating company or the transmission licensee, as the case may be,

on account of controllable parameters shall be shared between the generating company or

transmission licensee and the beneficiaries or long term customers, as the case may be on an annual

basis. The financial gains computed as per the following formulae in the case of generating stations

other than hydro generating stations on account of operational parameters as shown in Clause (1) of

this Regulation shall be shared in the ratio of 1:1 between the generating stations and beneficiaries.

Net Gain = (ECRN- ECRA) X Scheduled Generation

Where,

ECRN = Normative Energy Charge Rate computed on the basis of norms specified for Station

Heat Rate, Auxiliary Energy Consumption and Secondary Fuel Oil consumption.

ECRA = Actual Energy Charge Rate computed on the basis of actual Station Heat Rate, actual

Auxiliary Energy Consumption and actual Secondary Fuel Oil Consumption.

Provided that in the case of hydro generating stations, the net gain on account of Actual

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Auxiliary Energy Consumption being less than the Normative Auxiliary Energy Consumption shall

be computed as per the following formulae provided the saleable scheduled generation is more than

the saleable design energy and shall be shared in the ratio of 1:1 between generating station and

beneficiaries:

(i) When saleable scheduled generation is more than saleable design energy on the basis of

normative auxiliary energy consumption and less than or equal to saleable design energy

on the basis of actual auxiliary energy consumption:

Net gain (Million Rupees) = [(Saleable Scheduled generation in

MUs) - (Saleable Design energy on the basis of normative auxiliary energy

consumption in MUs)] x [1.30 or ECR, whichever is lower]

(ii) When saleable scheduled generation is more than saleable design energy on the basis of

actual auxiliary energy consumption:

Net gain (Million Rupees) = {Saleable Scheduled generation in MUs- [(Saleable

Scheduled Generation in MUs x (100 - normative AEC in %)/(100 actual AEC

in %)]}x [1.30 or ECR, whichever is lower]

82. Sharing of savings in interest due to re-financing or restructuring of loan :(1) If re-

financing or restructuring of loan by the generating company or the transmission licensee, as the case

may be, results in net savings on interest after accounting for cost associated with such refinancing

or restructuring, the same shall be shared between the generating company or the transmission

licensee and the beneficiaries, as the case may be, in the ratio of 1:1.

(2) In case of dispute, any of the parties may make an application in accordance with the Central

Electricity Regulatory Commission (Conduct of Business) Regulations, 2023 for settlement of the

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dispute:

Provided that the beneficiaries or the long term customers shall not withhold any payment

on account of the interest claimed by the generating company or the transmission licensee during the

pendency of any dispute arising out of re-financing of the loan.

83. Sharing of net gains referred to in Regulation 48(3)(e) and Regulation 49(1)(l) of Grid Code,

unless specifically provided in the rules or the guidelines issued by the Central Government, shall

be in the ratio of 1:1.

84. Sharing of Non-Tariff Income: The non-tariff net income in case of generating station and

transmission system from rent of land or buildings, eco-tourism, sale of scrap, and advertisements

shall be shared between the generating company or the transmission licensee and the beneficiaries

or the long term customers, as the case may be, in the ratio of 1:1.

85. Sharing of Clean Development Mechanism Benefits: The proceeds of carbon credit from

approved emission reduction projects under the Clean Development Mechanism shall be shared in

the following manner:

(a) 100% of the gross proceeds on account of CDM to be retained by the project developer in the

first year after the date of commercial operation of the generating station or the transmission system,

as the case may be;

(b) In the second year, the share of the beneficiaries shall be 10% which shall be progressively

increased by 10% every year till it reaches 50%, where after the proceeds shall be shared in equal

proportion, by the generating company or the transmission licensee, as the case may be, and the

beneficiaries.

86. Sharing of income from other business of transmission licensee: The income from other

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business of the transmission licensee shall be shared with the long term customer in the manner as

specified in the Central Electricity Regulatory Commission (Sharing of revenue derived from

utilization of transmission assets for other business) Regulations, 2020.

CHAPTER 15

MISCELLANEOUS PROVISIONS

87. Operational Norms to be ceiling norms: Operational norms specified in these regulations

are the ceiling norms and shall not preclude the generating company or the transmission licensee, as

the case may be, and the beneficiaries and the long-term customers from agreeing to the improved

norms and in case the improved norms are agreed to, such improved norms shall be applicable for

determination of tariff.

88. Deviation from ceiling tariff: (1) The tariff determined in these regulations shall be a ceiling

tariff. The generating company or the transmission licensee and the beneficiaries or the long-term

customer, as the case may be, may mutually agree to charge a lower tariff.

(2) The generating company or the transmission licensee, may opt to charge a lower tariff for a

period not exceeding the validity of these regulations on agreeing to deviation from

operational parameters, reduction in operation and maintenance expenses, reduced return on

equity and incentive specified in these regulations.

(3) If the generating company or the transmission licensee opts to charge a lower tariff for a

period not exceeding the validity of these regulations on account of lower depreciation based

on the requirement of repayment in such case, the unrecovered depreciation on account of

reduction of depreciation by the generating company or the transmission licensee during

useful life shall be allowed to be recovered after the useful life in these regulations.

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 (4) The deviation from the ceiling tariff specified by the Commission, shall come into effect from

the date agreed to by the generating company or the transmission licensee and the

beneficiaries or the long-term customer, as the case may be.

(5) The generating company and the beneficiaries of a generating station or the transmission

licensee and the long term customer of the transmission system shall be required to approach

the Commission for charging a lower tariff in accordance with clauses (1) to (3) above. The

details of the accounts and the tariff actually charged under clauses (1) to (3) shall be

submitted at the time of true up.

(6) Where a generating company and its beneficiaries or a transmission licensee and its long-

term customers have mutually agreed to charge a lower tariff in respect of a particular

generating station or transmission system in terms of Clauses (1) to (3) of this Regulation,

the said agreed tariff shall not be revised upwards at the time of truing up based on the capital

cost and additional capital expenditures in accordance with these regulations:

Provided that where the trued up tariff is lower than the agreed tariff, the generating

company or the transmission licensee shall charge such trued-up tariff only:

Provided further that the difference between the agreed tariff and the trued-up tariff shall be

settled between the parties in accordance with Regulations 10(7) and 10(8) of these regulations.

89. Deferred Tax liability with respect to the previous tariff period: Deferred tax liabilities

for the period up to 31st March 2009, whenever they materialise, shall be recoverable directly by the

generating companies or transmission licensees from the then beneficiaries or long term customers,

as the case may be. Deferred tax liabilities for the period arising from 1.4.2009 to 31.3.2024, if any,

shall not be recoverable from the beneficiaries or the long term customers, as the case may be.

90. Hedging of Foreign Exchange Rate Variation: (1) The generating company or the

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transmission licensee, as the case may be, may hedge foreign exchange exposure in respect of the

interest and repayment of foreign currency loan taken for the generating station or the transmission

system, in part or in full at their discretion.

(2) If the petitioner enters into hedging arrangement(s) based on its approved hedging policy, the

petitioner shall communicate to the beneficiaries concerned, of entering into such arrangement(s)

within thirty days.

(3) Every generating company and transmission licensee shall recover the cost of hedging of

foreign exchange rate variation corresponding to the normative foreign debt, in the relevant year on

a year-to-year basis as expense in the period in which it arises and extra rupee liability corresponding

to such foreign exchange rate variation shall not be allowed against foreign debt.

(4) To the extent the generating company or the transmission licensee is not able to hedge the

foreign exchange exposure, the extra rupee liability towards interest payment and loan repayment

corresponding to the normative foreign currency loan in the relevant year shall be permissible,

provided it is not attributable to the generating company or the transmission licensee or its suppliers

or contractors.

91. Award of Arbitration: In cases where there is a liability with respect to capital works on

account of award of arbitration having principal amount along with interest payment, the principal

amount actually paid shall be capitalised.

Provided that any interest amount associated with the arbitration award and actually paid

shall be recovered in instalments along with carrying cost at the rate specified under Regulation

10(6) and 10(7) of these Regulations.

Provided further that such number of instalments shall be decided by the Commission on a

case-to-case basis depending upon the amount to be reimbursed.

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92. Recovery of the cost of hedging or Foreign Exchange Rate Variation (FERV):

(1) Every generating company and the transmission licensee shall recover the cost of hedging

and foreign exchange rate variation on a year-to-year basis as income or expense in the period in

which it arises.

(2) Recovery of the cost of hedging or foreign exchange rate variation shall be made directly by

the generating company or the transmission licensee, as the case may be, from the beneficiaries or

the long term customers, as the case may be, without making any application before the Commission:

Provided that in case of any objections by the beneficiaries or the long term customers, as

the case may be, to the amounts claimed on account of the cost of hedging or foreign exchange rate

variation, the generating company or the transmission licensee, as the case may be, may make an

appropriate application before the Commission for its decision.

93. Approval Process of Non-ISTS Lines carrying Inter-State Power:

Existing intra-state transmission lines other than Natural ISTS lines, as certified by CEA based

on the recommendations of the STU and RPC, shall be considered as ISTS systems.

Provided that these transmission lines are being used for evacuation and transfer of inter-state

power on a regular basis as identified by CTU in consultation with the concerned RPC and

RLDC;

Provided further that such transmission system is under operation and appropriate

metering system is in place to record flow of power;

Provided further that a proper mechanism is in place for the maintenance of such a

transmission system after its COD;

155
 Provided that such lines have not been developed for the sole purpose of the beneficiary(ies)

of a single State.

(1) Existing Intra State lines which were planned as ISTS System shall also be considered as ISTS

lines;

Provided that such lines have not been developed for the sole purpose of the

beneficiary(ies) of a single State;

Provided further that such transmission system is under operation and appropriate

metering system is in place to record flow of power;

Provided further that a proper mechanism is in place for the maintenance of such a

transmission system after its COD.

(2) CTU, in consultation with RLDC, shall identify all such non-ISTS lines which are utilized for

ISTS power transfer after ascertaining that such nature of flow of power has become permanent.

(3) No New ISTS lines shall henceforth be planned and developed by State Transmission Utility

unless agreed by CTU in consultation with RPC and approved by the Ministry of Power.

(4) New transmission lines which have been conceived as ISTS lines at the planning stage shall be

considered as part of the ISTS system;

Provided that such lines have not been developed for the sole purpose of the

beneficiary(ies) of a single State;

Provided further that such transmission system is under operation and appropriate

metering system is in place to record flow of power;

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 Provided further that a proper mechanism is in place for the maintenance of such a

transmission system after its COD.

(5) Tariff of all such ISTS lines shall be approved based on provisions of these Regulations, and the

fixed charges of such system shall be allowed based on the availability certified by respective

RPCs and shall be allowed to be recovered as per the mechanism specified in CERC (Sharing

of Inter-State Transmission Charges and Losses), 2020.

94. Application fee and publication expenses: The following fees, charges and expenses shall

be reimbursed directly by the beneficiary in the manner specified herein:

(1) The application filing fee and the expenses incurred on publication of notices in the

application for approval of tariff, may at the discretion of the Commission, be allowed to be

recovered by the generating company or the transmission licensee, as the case may be,

directly from the beneficiaries or the long term customers, as the case may be.

(2) The fees and charges shall be reimbursed directly by the beneficiaries in proportion to their

allocation in the generating stations or by the long term customers or DICs in proportion to

their share in the inter-State transmission systems determined in accordance with the Central

Electricity Regulatory Commission (Sharing of inter-State Transmission Charges and

Losses) Regulations, 2020, as amended from time to time.

(3) Fees and charges paid by the generating companies and inter-State transmission licensees

(including deemed inter-State transmission licensees) under the Central Electricity

Regulatory Commission (Fees and Charges of Regional Load Despatch Centre and other

related matters) Regulations, 2009, as amended from time to time or any subsequent

amendment thereof.

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 (4) Licence fees paid by the inter-State transmission licensees (including the deemed inter-State

transmission licensee) in terms of Central Electricity Regulatory Commission (Payment of

Fees) Regulations, 2012.

(5) Licence fees paid by NHPC Ltd to the State Water Resources Development Authority,

Jammu, in accordance with the provisions of the Jammu & Kashmir Water Resources

(Regulations and Management) Act, 2010.

(6) The Commission may, for the reasons to be recorded in writing and after hearing the affected

parties, allow reimbursement of any fee or expenses, as may be considered necessary.

95. Special Provisions relating to NLC India Limited: The tariff of the existing generating

stations of NLC India Ltd, namely, TPS-II (Stage I & II) and TPS-I (Expansion), whose tariff for the

tariff periods 2004-09, 2009-14 and 2014-19 has been determined by following the Net Fixed Assets

approach, shall continue to be determined by adopting Net Fixed Assets approach.

96. Special Provisions relating to Damodar Valley Corporation: (1) Subject to clause (2), this

Regulation shall apply to the determination of tariff of the projects owned by Damodar Valley

Corporation (DVC).

(2) The following special provisions shall apply for the determination of tariff of the projects

owned by DVC:

(i) Capital Cost: The expenditure allocated to the object 'power', in terms of sections 32 and 33

of the Damodar Valley Corporation Act, 1948, to the extent of its apportionment to

generation and inter-state transmission, shall form the basis of capital cost for the purpose of

determination of tariff:

Provided that the capital expenditure incurred on head office, regional offices,

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 administrative and technical centres of DVC, after due prudence check, shall also form part

of the capital cost.

(ii) Debt Equity Ratio: The debt-equity ratio of all projects of DVC commissioned prior to

01.01.1992 shall be 50:50, and that of the projects commissioned thereafter shall be 70:30.

(iii)Depreciation: The depreciation rate stipulated by the Comptroller and Auditor General of

India in terms of section 40 of the Damodar Valley Corporation Act, 1948 shall be applied

for the computation of depreciation of projects of DVC.

(iv) Funds under section 40 of the Damodar Valley Corporation Act, 1948 The Fund(s)

established in terms of section 40 of the Damodar Valley Corporation Act, 1948 shall be

considered as items of expenditure to be recovered through tariff.

(v) Expenses towards subsidiary activities as per Hon’ble Supreme Court Judgement in Civil

Appeal No. 4289 of 2008.

97. Special Provisions relating to BBMB and SSP: The tariff of the generating station and the

transmission system of Bhakra Beas Management Board (BBMB) and Sardar Sarovar Project (SSP)

shall be determined after taking into consideration, the provisions of the Punjab Reorganization Act,

1966 and Narmada Water Scheme, 1980 under Section 6-A of the Inter-State Water Disputes Act,

1956, respectively.

98. Special Provisions Relating to Certain Inter-State Generation Projects: (1) The tariff of

the generating station and the transmission system of the Indira Sagar generation project and such

other inter-state generation projects shall be determined on a case-to-case basis.

99. Special Provisions relating to Central Transmission Utility of India Ltd. (CTUIL): The

fees and charges of CTUIL shall be allowed separately by the Commission through a separate

159
regulation:

Provided that until such regulation is issued by the Commission, the expenses of CTUIL shall be

borne by Power Grid Corporation of India Ltd. (PGCIL) which shall be recovered by PGCIL as

additional O&M expenses through a separate petition.

100. Transmission Majoration Factor: Transmission Majoration Factor admissible for the

transmission projects executed through the JV route in terms of Regulation 410A of the Central

Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2001 shall be

available for a period of 25 years from the date of issue of the transmission licence.

101. Public Procurement through Competitive Bidding: The generating company for a specific

generating station or for an integrated mine or a transmission licensee shall procure equipment, work

and services through a transparent process of competitive bidding.

Provided that under certain exceptional circumstances, equipment, works and services may

be procured through other methods, as provided under general financial rules issued by the

Government of India and applicable from time to time.

102. Power to Relax: The Commission, for reasons to be recorded in writing, may relax any of

the provisions of these regulations on its own motion or on an application made before it by an

interested person.

103. Power to Remove Difficulty: If any difficulty arises in giving effect to the provisions of

these regulations, the Commission may, by order, make such provision not inconsistent with the

provisions of the Act or provisions of other regulations specified by the Commission, as may appear

to be necessary for removing the difficulty in giving effect to the objectives of these regulations.

104. Issue of Suo-Moto orders and practice directions: The Commission may, from time to time,

160
issue orders and practice directions in regard to the effective implementation of these regulations

and matters incidental or ancillary thereto as the Commission may consider appropriate.

Sd/-
(Harpreet Singh Pruthi)
Secretary

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 Appendix I
Depreciation Schedule

Depreciation Rate
Sr. No. Asset Particulars (Salvage Value=10%)
SLM
A Land under full ownership 0.00%
B Land under lease
(a) for investment in the land 3.34%
(b) For cost of clearing the site 3.34%
(c) Land for reservoir in case of hydro generating station 3.34%

C Assets purchased new

a. Plant & Machinery in generating stations
(i) Hydro electric 5.28%
(ii) Steam electric NHRB & waste heat recovery boilers 5.28%
(iii) Diesel electric and gas plant 5.28%

b. Cooling towers & circulating water systems 5.28%

Hydraulic works forming part of the Hydro-generating stations

c.

Dams, Spillways, Weirs, Canals, Reinforced concrete flumes and

(i) 5.28%
siphons
Reinforced concrete pipelines and surge tanks, steel pipelines,
(ii) sluice gates, steel surge tanks, hydraulic control valves and 5.28%
hydraulic works

d. Building & Civil Engineering works

(i) Offices and showrooms 3.34%
(ii) Containing thermo-electric generating plant 3.34%
(iii) Containing hydro-electric generating plant 3.34%
(iv) Temporary erections, such as wooden structures 100.00%
(v) Roads other than Kutcha roads 3.34%
(vi) Others 3.34%

e. Transformers, Kiosks, sub-station equipment & other fixed

apparatus (including plant)
Transformers, including foundations having a rating of 100 KVA
(i) and over 5.28%

(ii) Others 5.28%

162
 f. Switchgear including cable connections 5.28%

g. Lightning arrestor
(i) Station type 5.28%
(ii) Pole type 5.28%
(iii) Synchronous condenser 5.28%
Depreciation Rate
Sr. No. Asset Particulars (Salvage Value=10%)
SLM
h. Batteries 9.50%

Underground cable, including joint boxes and disconnected

(i) 5.28%
boxes
(ii) Cable duct system 5.28%

i. Overhead lines, including cable support

Lines on fabricated steel operating at terminal voltages higher
(i) 5.28%
than 66 KV
Lines on steel supports operating at terminal voltages higher than
(ii) 5.28%
13.2 KV but not exceeding 66 KV
(iii) Lines on steel on reinforced concrete support 5.28%
(iv) Lines on treated wood support 5.28%

j. Meters 5.28%

k. Self propelled vehicles 9.50%

l. Air Conditioning Plants

(i) Static 5.28%
(ii) Portable 9.50%

m(i) Office furniture and furnishing 6.33%

(ii) Office equipment 6.33%
(iii) Internal wiring, including fittings and apparatus 6.33%
(iv) Street Light fittings 5.28%

n. Apparatus let on hire

(i) Other than motors 9.50%

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 (ii) Motors 6.33%

o. Communication equipment
(i) Radio and high frequency carrier system 15.00%
(ii) Telephone lines and telephones 15.00%
(iii) Fibre Optic/OPGW 6.33%

p. I. T Equipment including software, UNMS, URTDSM, EMS, 15.00%

Cyber Security System, REMC, WAMS, SCADA System

q. Any other assets not covered above 5.28%

Note: Where the life of the particular asset is less than the useful life of the project, the useful life of such
particular asset shall be considered as per the provisions of the Companies Act, 2013 and subsequent
amendment thereto.

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 Appendix II
Depreciation Schedule for New Projects

Depreciation Rate
Sr. No. Asset Particulars (Salvage Value=10%)
SLM
A Land under full ownership 0.00%
B Land under lease
(a) for investment in the land 3.34%
(b) For the cost of clearing the site 3.34%
I Land for reservoir in case of hydro generating station 3.34%

C Assets purchased new

a. Plant & Machinery in generating stations
(i) Hydro electric 4.22%
(ii) Steam electric NHRB & waste heat recovery boilers 4.22%
(iii) Diesel electric and gas plant 4.22%

b. Cooling towers & circulating water systems 4.22%

Hydraulic works forming part of the Hydro-generating stations

c.

Dams, Spillways, Weirs, Canals, Reinforced concrete flumes and

(i) 4.22%
siphons
Reinforced concrete pipelines and surge tanks, steel pipelines,
(ii) sluice gates, steel surge tanks, hydraulic control valves and 4.22%
hydraulic works

d. Building & Civil Engineering works

(i) Offices and showrooms 3.34%
(ii) Containing thermo-electric generating plant 3.34%
(iii) Containing hydro-electric generating plant 3.34%
(iv) Temporary erections, such as wooden structures 100.00%
(v) Roads other than Kutcha roads 3.34%
(vi) Others 3.34%

e. Transformers, Kiosks, sub-station equipment & other fixed

apparatus (including plant)
Transformers, including foundations having a rating of 100 KVA
(i) and over 4.22%

(ii) Others 4.22%

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 f. Switchgear, including cable connections 4.22%

g. Lightning arrestor
(i) Station type 4.22%
(ii) Pole type 4.22%
(iii) Synchronous condenser 4.22%
Depreciation Rate
Sr. No. Asset Particulars (Salvage Value=10%)
SLM
h. Batteries 9.50%

Underground cable, including joint boxes and disconnected 4.22%

(i)
boxes
(ii) Cable duct system 4.22%

i. Overhead lines, including cable support

Lines on fabricated steel operating at terminal voltages higher 4.22%
(i)
than 66 KV
Lines on steel supports operating at terminal voltages higher than 4.22%
(ii)
13.2 KV but not exceeding 66 KV
(iii) Lines on steel on reinforced concrete support 4.22%
(iv) Lines on treated wood support 4.22%

j. Meters 4.22%

k. Self propelled vehicles 9.50%

l. Air Conditioning Plants

(i) Static 4.22%
(ii) Portable 9.50%

m.(i) Office furniture and furnishing 6.33%

(ii) Office equipment 6.33%
(iii) Internal wiring, including fittings and apparatus 6.33%
(iv) Street Light fittings 4.22%

n. Apparatus let on hire

(i) Other than motors 9.50%

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 (ii) Motors 6.33%

o. Communication equipment
(i) Radio and high frequency carrier system 15.00%
(ii) Telephone lines and telephones 15.00%
(iii) Fibre Optic/OPGW 6.33%

p. I. T Equipment including software UNMS, URTDSM, EMS, 15.00%

Cyber Security System, REMC, WAMS, SCADA system

q. Any other assets not covered above 4.22%

Note: Where the life of the particular asset is less than the useful life of the project, the useful life of such
particular asset shall be considered as per the provisions of the Companies Act, 2013 and subsequent
amendment thereto

167
 Appendix III
Depreciation Schedule for Integrated Mine
DEPRECIATION SCHEDULE FOR INTEGRATED MINE
Sr No Asset Particulars Life in Years
1 Land Freehold@ 999
2 Land Leasehold &&&
3 Temporary erections 1
4 HEMM$ 8
5 Roads, bridges, culverts, helipads 25
6 Main Plant Buildings 30
7 Machinery other than HEMM 15
8 Water Supply, Drainage and sewerage 15
9 Furniture and Fixtures 15
10 Office equipment/s other than computers 15
11 Hospital equipment(s) 15
12 EDP, WP machines, SATCOM & communication equipment 15
13 Electrical installations 15
14 Self propelled vehicles 10
15 Computers, Software 6.33
16 Laboratory & workshop equipment 15
17 Mine Development Expenses and Evaluation and Exploration # 20 or life of mine, whichever
is lower
18 Evaluation and Exploration# 20 or life of mine, whichever
is lower
19 Others not covered above 15
* Salvage Value shall be other than 5% for the following assets -
a. IT Equipment, software Zero (0)
b. Zero or as agreed with the state Government in case of land
c. For specialized mining equipment as specified by the Ministry of Corporate affairs
Mine Development expenses, Evaluation and Exploration Zero (0)
@ Petitioner to submit if the Freehold Land is attached with any conditions for return. If yes submit
the conditions and period after which the land is to be returned. In such a case, the land shall be
depreciable based on such details.
&&& To be filled by petitioner, least of lease agreement/mine life/right to use period
$ List of individual HEMM with the cost of each HEMM be provided separately
# In a generic sense Mine Development Expenditure is the expenditure incurred to bring the mine n
into usable condition after ensuring the economic viability and decision is taken by the Mine Owner
to develop the mine. While filling under this head, details to the extent feasible are to be given
separately. Evaluation and exploration expenditure is generally the expenditure incurred associated
with finding the mineral by carrying out topographical, geological, geochemical and geophysical
studies, exploratory drilling, trenching, sampling, expenditure for activities in relation to evaluation
of technical feasibility and commercial viability, acquisition of rights to explore etc. While filling
under this head, details to the extent feasible are to be given separately.

168
 Appendix-IV

Procedure for Calculation of Transmission System

Availability Factor for a Month

1. Transmission system availability factor for nth calendar month (“TAFPn”) shall be calculated by the
respective transmission licensee, verified by the concerned Regional Load Dispatch Centre (RLDC) and
certified by the Member-Secretary, Regional Power Committee of the region concerned, separately for each
AC and HVDC transmission system and grouped according to sharing of transmission charges. In the case
of the AC system, transmission System Availability shall be calculated separately for each Regional
Transmission System and inter-regional transmission system. In the case of the HVDC system, transmission
System Availability shall be calculated on a consolidated basis for all inter-state HVDC systems.

2. Transmission system availability factor for nth calendar month (“TAFPn”) shall be calculated by
considering the following:

i) AC transmission lines: Each circuit of AC transmission line shall be considered as one

element;

ii) Inter-Connecting Transformers (ICTs): Each ICT bank (three single-phase transformers
together) shall form one element;

iii) Static VAR Compensator (SVC): SVC, along with SVC transformer, shall form one
element;

iv) Bus Reactors or Switchable line reactors: Each Bus Reactors or Switchable line reactors
shall be considered as one element;

v) HVDC Bi-pole links: Each pole of the HVDC link, along with associated equipment at both
ends, shall be considered as one element;

vi) HVDC back-to-back station: Each block of the HVDC back-to-back station shall be
considered as one element. If the associated AC line (necessary for the transfer of inter-
regional power through the HVDC back-to-back station) is not available, the HVDC back-
to-back station block shall also be considered unavailable;

169
 vii) Static Synchronous Compensation (“STATCOM”): Each STATCOM shall be considered
as a separate element.

3. The Availability of the AC and HVDC portion of the Transmission system shall be calculated by
considering each category of transmission elements as under:

TAFPn (in %) for AC system:

(o X AVo)+(p X AVp) + (q X AVq) + (r X AVr)+(u X AVu)

= -----------------------------------------------------------------------------------x100
(o + p + q + r+u)

Where,

o = Total number of AC lines.

AVo = Availability of o number of AC lines
p = Total number of bus reactors/switchable line reactors

AVp = Availability of p number of bus reactors/switchable line reactors

q1 = Total number of ICTs

AVq = Availability of q number of ICTs

r = Total number of SVCs

AVr = Availability of r number of SVCs

u = Total number of STATCOM

AVu = Availability of u number of STATCOM

TAFMn (in %) for HVDC System:

s
t
∑ Cxbp (act) X AVxbp + ∑ Cy (act)btb X AVybtb
y=1
x=1

= -----------------------------------------------------------------------------x100

170
 s
t
∑ Cxbp + ∑ Cy btb
y=1
x=1

Where

Cxbp(act) = Total actual operated capacity of xth HVDC pole

Cxbp = Total rated capacity of xth HVDC pole
AVxbp = Availability of xth HVDC pole

Cybtb(act) = Total actual operated capacity of yth HVDC back-to-back station block

Cybtb = Total rated capacity of yth HVDC back-to-back station block

AVybtb = Availability of yth HVDC back-to-back station block

s = Total no of HVDC poles

t = Total no of HVDC Back to Back blocks

3. The availability for each category of transmission elements shall be calculated based on the
weightage factor, total hours under consideration and non-available hours for each element of that
category. The formulae for calculation of the Availability of each category of the transmission elements
are as per Appendix-V. The weightage factor for each category of transmission elements shall be
considered asunder:

(a) For each circuit of the AC line – The number of sub-conductors in the line multiplied by ckt-
km;
(b) For each HVDC pole- The rated MW capacity x ckt-km;

(c) For each ICT bank – The rated MVA capacity;

(d) For SVC- The rated MVAR capacity (inductive and capacitive);

(e) For Bus Reactor/switchable line reactors – The rated MVAR capacity;

(f) For HVDC back-to-back stations connecting two Regional grids- Rated MW capacity of each
block; and

(g) For STATCOM – Total rated MVAR Capacity.

171
4. The transmission elements under outage due to the following reasons shall be deemed to be
available:
i. Shut down availed for maintenance of another transmission scheme or construction of new
element or renovation/upgradation/additional capitalization in an existing system approved
by the Commission. If the other transmission scheme belongs to the transmission licensee,
the Member Secretary, RPC may restrict the deemed availability period to that considered
reasonable by him for the work involved. In case of a dispute regarding deemed availability,
the matter may be referred to the Chairperson, CEA, within 30 days.

ii. Switching off of a transmission line to restrict over-voltage and manual tripping of switched
reactors as per the directions of the concerned RLDC.

iii. Shut down of a transmission line due to the Project(s) of NHAI, Railways and Border Road
Organization, including for shifting or modification of such transmission line or any other
infrastructure project approved by Ministry of Power. Member Secretary, RPC may restrict
the deemed availability period to that considered reasonable by him for the work involved;
Provided that apart from the deemed availability, any other costs involved in the process of
such shutdown of transmission line shall not be borne by the DICs.

Provided that such deemed availability shall be considered only for the period for which
DICs are not affected by the shutdown of such transmission line.

5. For the following contingencies, the outage period of transmission elements, as certified by the
Member Secretary, RPC, shall be excluded from the total time of the element under the period of
consideration for the following contingencies:

i) Outage of elements due to force majeure events beyond the control of the transmission licensee.
However, whether the same outage is due to force majeure (not design failure) will be verified by the
Member Secretary, RPC. A reasonable restoration time for the element shall be considered by the
Member Secretary, RPC, and any additional time taken by the transmission licensee for restoration
of the element beyond the reasonable time shall be treated as outage time attributable to the
transmission licensee. Member Secretary, RPC may consult the transmission licensee or any expert

172
 for estimation of reasonable restoration time. Circuits restored through ERS (Emergency Restoration
System) shall be considered as available;

ii) Outage caused by grid incident/disturbance not attributable to the transmission licensee, e.g. faults in
a substation or bays owned by another agency causing an outage of the transmission licensee’s
elements, and tripping of lines, ICTs, HVDC, etc., due to grid disturbance. However, if the element
is not restored on receipt of direction from RLDC while normalizing the system following grid
incident/disturbance within reasonable time, the element will be considered not available for the
period of outage after issuance of RLDC’s direction for restoration;

iii) The outage period which can be excluded for the purpose of sub-clause (i) and (ii) of this clause shall
be declared as under:

a. Maximum up to one month by the Member Secretary, RPC;

b. Beyond one month and up to three months after the decision at RPC;
c. Beyond three months by the Commission for which the transmission license shall approach the
Commission along with reasons and steps taken to mitigate the outage and restoration timeline.

6. Time frame for certification of transmission system availability: (1) The following schedule shall
be followed for certification of availability by the Member Secretary of the concerned RPC:

• Submission of outage data along with documentary proof (if any) and TAFPn calculation by
Transmission Licensees to RLDC/ constituents

– By the 5th of the following month;

• Review of the outage data by RLDC / constituents and forward the same to respective RPC – by
20th of the month;

• Issue of availability certificate by respective RPC – by the 3rd of the next month.

173
 Appendix-V

FORMULAE FOR CALCULATION OF AVAILABILITY OF EACH CATEGORY

OF TRANSMISSION ELEMENTS

For AC transmission system

∑ o Wi(Ti -TNAi)/Ti
AVo(Availability of o no. of AC lines) = i=l
o
∑ i=l Wi

AVq(Availability of q no. of ICTs) = ∑q Wk(Tk -TNAk)/Tk

k=l
q
∑ k=l Wk

∑rr=1 Wl(Tl -TNAl)/Tl

l=l
AVr(Availability of r no. of SVCs) = r
∑ Wl
l=l

P
AVp(Availability of p no. of Switched Bus reactors) = ∑ Wm(Tm -TNAm)/Tm
m=l
P
∑ Wm
m=l

∑u Wn(Tn -TNAn)/Tn
n=l
AVu(Availability of u no. of STATCOMs) = u
∑ Wn
n=l

(Tx –TN )
AVxbp(Availability of an individual HVDC pole) =
Tx

AVybtb (Availability of an individual HVDC

(Ty- TNAy)
Back-to-back Blocks) =

Ty

174
For the HVDC transmission system

For the new HVDC commissioned but not completed twelve months;

For first 12 months: [(AVxbp or AVybtb)x95%/85%], subject to a ceiling of 95%.

Where,
o = Total number of AC lines;
AVo = Availability of o number of AC lines;
p = Total number of bus reactors/switchable line reactors;
AVp = Availability of p number of bus reactors/switchable line reactors;
q = Total number of ICTs;
AVq = Availability of q number of ICTs;
r = Total number of SVCs;
AVr = Availability of r number of SVCs;.
U = Total number of STATCOM;
AVu = Availability of u number of STATCOMs;
Wi = Weightage factor for ith transmission line;
Wk = Weightage factor for kth ICT;
Wl = Weightage factors for inductive & capacitive operation of lth SVC;
Wm = Weightage factor for mth bus reactor;
Wn = Weightage factor for nth STATCOM.
Ti, , Tk, Tl, The total hours of ith AC line, kth ICT, lth SVC, mth Switched Bus
-
, Reactor
Tm, Tn, Tx, & nth STATCOM, xth HVDC pole, yth HVDC back-to-back blocks
Ty during the period under consideration (excluding time period for
outages not attributed to transmission licensee for the reasons given
in Para 5 of the procedure)
TNAi ,TNAk The non-availability hours (excluding the time period for outages not
TNAl, TNAm, attributable to transmission licensee taken as deemed
availability as TNAn, TNAn, TNAx, TNAy per Para 5 of the procedure) for
ith AC line, kth ICT, lth SVC , mth Switched Bus Reactor, nth STATCOM,
xth HVDC pole and ythHVDC back-to-back block.

175
Annexure-XXVIIIA
 22-Nov-23

Annexure-II

Meeting to discuss
implementation of the
Unified Accounting Software for
RPCs under the chairmanship of
Member (GO&D), CEA

20-Nov-2023

Background
13th NPC meeting held on 5 July 2023 :

It was decided that the commercial subgroup of NPC will

finalise the standardization of the formats and software of the
commercial accounts and would be placed in next NPC
meeting.

1
 22-Nov-23

Background
Meetings of commercial subgroup of NPC:
Meeting held on 8 Aug 2023-Main decisions:
i. Commercial accounts to be standardized were identified.
ii. ERPC will submit draft standard output formats.
ERPC submitted draft formats on 20.09.2023 and the same was circulated for
the comments. SRPC vide email dated 04 Oct 2023 has provided comments.
Meeting held on 30 Oct 2023:
NPC Div. presented the draft formats based on ERPC and SRPC inputs. The draft
was discussed and tentatively finalised and circulated for further comments.
SRPC has provided further comments on final draft which will be suitably
incorporated during implementation.

Agenda of the meeting

Meeting in the O/o Member (GO&D), CEA held on 20.10.2023:
Member GO&D reviewed the works of standardization of the format and
software of the commercial accounts issued by RPCs. After due deliberations,
Member (GO&D), CEA has directed to schedule a meeting to discuss the
implementation of the Unified Accounting Software for RPCs.
Accordingly, a meeting has been scheduled to discuss the following agenda
points:
i. Scope of work for Unified Accounting Software for RPCs. (DPR
preparation, Standardization of Reports and formats etc.)
ii. Modalities for implementations of Unified Accounting Software for RPCs.
iii. Any other agenda item with the permission of the Chair.

2
 22-Nov-23

Proposal:
1. Nomination of nodal RPC for the following:
a. Hiring of consultant for preparation of DPR
b. Source of funding-PSDF/RPC fund
c. Preparation of NIT
2. Selection of vendor for accounting software by nodal RPC
3. Execution of work order and certification of completion of work by Nodal RPC
4. O&M/AMC/Ownership of project by Nodal RPC

THANK YOU

3
 Annexure-III

STANDARDIZATION OF OUTPUT REPORTS OF

COMMERCIAL ACCOUNTS ISSUED BY RPCs

As per the decision in the 13th meeting of NPC held on 05th July 2023 and mandate given in
Annexure-7: Accounting & Pool Settlement system under CERC IEGC Regulation 2023 and
subsequent decision taken in the Sub group meeting held on 08th August 2023, ERPC secretariat has
entrusted for preparing a draft standardization of Output format of all commercial accounts published
by RPCs for accounting and settlement.
In this regard, ERPC vide email dated 20.09.2023 has provided draft standardization of Output format
of all commercial accounts published by RPCs and the same was circulated for the comments. SRPC
vide email dated 04 Oct 2023 has given their observation for standardization of output format.

A meeting of the commercial sub-group of NPC was held on 30.10.2023 through video conference to
discuss Standardization of output formats of Commercial Accounts issued by RPCs. The
standardised output formats of the commercial accounts have been modified based on deliberations in
the meeting and circulated to all RPCs for comments. The comments/inputs dated 8.11.2023 was
received from SRPC and the same has been suitably incorporated.

After consideration of comments of SRPC and visiting the accounts published by RPCs, the
standardization of Output format of all commercial accounts published by RPCs has been prepared
by NPC Division for uniformity in all commercial account. The same has been given below with the
final suggestions:

Basis of Standardization of Output Formats:

1. Regulations of CERC and existing formats of commercial accounts issued by RPCs.
2. Unit of energy, power, INR and Constituent name should be unique and will be applicable for
all RPCs output report format uniformly.
3. Final modifications of output format may be done during the development of Unified
Accounting Software for all RPCs.

Note:
1. Proper mentioning of Amount (this shall be indicated along with sign (+/-) & Nature of
Amount (this shall be indicated a Payable to Pool/ Receivable from Pool).
2. All Amounts shall be shown in Rupee terms.
3. Resolution of Power (in MW) & Energy (in MWH) figures shall be restricted to THREE
Decimals in the Main Reports

1
A. Weekly Accounts

2
 Standard Format of Commercial Accounts
1. DSM Account Format:
1.1 Final Weekly DSM Account

DSM Settlement Account for the week

From DD-MM-YYYY to DD-MM-YYYY

Under Over Post-facto Payable

Entity Total Drawl Drawl Charges/ Final To Pool (“-
Deviation Charges/ Charges/ Charges for Charges “)/
(MWHr) Over Under Drawl (Rs) Receivable
Injection Injection without From Pool
Charges Charges Schedule (“+”)
(Rs) (Rs) (Rs)
States/UT/Drawee Entities
Ent-1

Ent-2
….

CGS
CGS-1
CGS-2
…

General Sellers
GS-1
GS-2
…

WS-Seller
Solar Entity
SE-1
SE-2
…

Wind Entity
WE-1
WE-2
…
Inter- regional

3
 Inter- National

Infirm generators

(All Figs. in Rs.)

Payable To The Pool (A) :
Receivable From The Pool (B) :
__ Deviation (A-B) :

1.2 Day-wise Report Format:

(All Figs. in Rs.)
Date Total Total Deviation Final Payable To Pool (“-
Scheduled Actual (MWH) Charges “)/ Receivable
(MWH) (MWH) (Rs) From Pool (“+”)

States/UT/Drawee Entities
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
CGS
Day-1
Day-2
Day-3

4
Day-4
Day-5
Day-6
Day-7
Weekly Total
General Sellers
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
WS-Seller
Solar Entity
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Wind Entity
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Inter- regional

Day-1
Day-2

5
 Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Inter National
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Infirm Generator
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Note: Energy unit in MWH and upto 3 decimal.

2. Ancillary Service Account:

2.1 SRAS Settlement Account for the week from dd-mm-yyyy to dd-mm-yyyy

Payments to the SRAS Provider(s) from the DSM pool

Sr. SRAS UP Down Net Energy Incentive Total Payable

No. Provider Regulation Regulation Energy Charges/ Charges Charge to the
due to due to (MWh) Compensati (Rs.) s (Rs.) pool/Re
SRAS SRAS on Charges ceivable
(MWh) (MWh) (Rs.) from
the pool

6
 Total

Notes :

1. Energy unit in MWH and upto 3 decimal.

2. Energy Charges/Compensation Charges for SRAS provider has been calculated as per the rate furnished
by the respective SRAS providers in Format AS and the same published in RPC website.
3. The Incentive has been calculated based on actual performance of SRAS providers.

2.2 SRAS Actual Performance Statement by __RPC

from dd-mm-yyyy to dd-mm-yyyy
Sr. SRAS dd-mm-yyyy dd-mm-yyyy dd-mm-yyyy … dd-mm-yyyy dd-mm-yyyy Remarks
No. Provider (Disqualification
Actual Actual Actual … Actual Actual period)
Performance(%) Performance(%) Performance(%) Performance(%) Performance(%)

…
…
…

2.3 TRAS Account:

TRAS Settlement Account for the week from dd-mm-yyyy to dd-mm-yyyy

(Short Fall/Emergency)

Net Charges Payable/Receivable by the TRAS Provider(s) to/from the Regional

Deviation and Ancillary Service Pool Account in Shortfall/Emergency Condition

TRA Energy Total Charges Energy Total Charges / Net Payable

SL S schedule /Compensatio scheduled Compensation Charges from Pool
No. Provi d under n Charges for under Charges for (Rs) to TRAS
der shortfall/ Shortfall/Eme Shortfall/Eme Shortfall/Emerge (E)=(B)- Provider/
Emergen rgency rgency ncy TRAS- (D) Receivabl
cy TRAS-Up TRAS-Down Down to be e by Pool
TRAS- (Rs) (MWh) paid back to Pool from
Up (B) (C) (Rs) TRAS
(MWH) (D) Provider
(A)

Notes:

7
A) TRAS settlement account for the week dd-mm-yyyy to dd-mm-yyyy has been prepared as per the detailed procedure
for Tertiary Reserve Ancillary Services (TRAS) approved by CERC.

B) Total Charges for TRAS providers have been calculated as per the rates furnished by the respective TRAS providers
and the same published in ___RPC website.

2.4 TRAS Settlement Account by RPC (Day Ahead and Real Time Market)
TRAS Account for Week from dd-mm-yyyy to dd-mm-yyyy.
Net Charges Payable/Receivable by the TRAS Provider(s) to/from the Regional Deviation and Ancillary
Service Pool Account

S. TRA TRAS-Up in Day Ahead AS Market TRAS-Up Energy in Real Time AS Market Total
No S Charges/
Provi compensati
der on charge
Nam for TRAS
e Up (Rs)
(I)=(C)+(D
)+ (G)+(H)
(11)
(1) (2) TR TRAS- TRAS TRAS-Up TRAS TRAS- TRASUp TRAS-Up
AS Up Up Commitme Up Up Energy Commitmen
Up Energy Energ nt Charges Cleare Energy Charges t Charges
Cle Sched y (Rs.) (D) d Schedule (Rs) (G) (Rs) (H)
ared uled Charg (6) (MWh d (MWh) (9) (10)
(M (MWh es ) (E) (F)
Wh) ) (B) (Rs.) (7) (8)
(A) (4) (C)
(3) (5)

1
2
3

TRAS-Down in Day Ahead AS Market TRAS-Down in Real Time AS Market Net Charges (Rs) Payable
(N)=(I)-(K)- (M) from Pool
(15) to TRAS
TRASDown TRASDown TRASDown TRASDown Charges Provider/R
Energy Charges to be paid Energy Scheduled to be paid back to eceivable
Scheduled back to Pool (Rs) (MWh) (L) Pool (Rs) (M) by Pool
(MWh) (J) (K) (14) (15) from TRAS
(12) (13) Provider

1
2

8
3. Reactive Energy Account Format:

3.1 Weekly Reactive Energy Account format after final Adjustment:

Regional MVArh_H MVArh_L Net Payable to Pool
Entity Name Amount (-)/
(Rs.) Receivable
from Pool (+)

States/UTs/ Drawee Utilities

CGS

General Sellers

WS Seller (Solar Entity)

WS Seller (Wind Entity)

WS Seller (Others)

(All Figs. in Rs.)

Payable To The Pool :
Receivable From The Pool :

3.2 Meter-wise Reactive Energy Details

Regional Station Element Meter No MVArh_H MVArh_L

Entity Name Name Name
Ent-1
Ent-2
…

9
 3.3 Day wise Format:
Reactive Energy export (-) / import (+) under high & low voltage condition
And Reactive Energy Charges thereof
(Reactive Energy Exchange in MVARH & Charges in Rs.)

Regiona ISTS/B Drawl Day1 (HV, … Day7(HV, Total HV Total Charges Charges
l BMB/D Point LV)... … LV) LV HV LV
VC etc.
Entity
Name

10
B. Monthly Accounts

11
 1. REA Accounts Formats:

___________Regional Power Committee

Regional Energy Account for the Month of ___________
1.1 Details of Plant Availability Factor (PAF) for CS Stations
High Demand Season for FY 20__-__

Peak Hours ( )
ISGS IC Auxiliary NPAF PAFM PAFC High Demand Season Low Demand Season
(MW) Consumptio (%) (%) (%)
n Peak Hour Off-Peak Hour Peak Hour Off-Peak Hour

PAFM PAFC PAFM PAFC PAFM PAFC PAFM PAFC

(%) (%) (%) (%) (%) (%) (%) (%)

ISGS-1

ISGS-2

……

…….

1.2 Details of Plant Load Factor (PLF) for CS Stations

High Demand Season for FY 20__-__

Peak Hours ( )
ISGS IC Auxili NPLF PLFM PLFC High Demand Season Low Demand Season
(MW) ary (%) (%) (%)
Consu Peak Hour Off-Peak Hour Peak Hour Off-Peak Hour
mptio
n
PLFM (%) PLFC PLFM PLFC PLFM (%) PLFC PLFM PLF
(%) (%) (%) (%) (%) C
(%)

ISGS-1

ISGS-1

……
…….

12
1.3 Details of Misdeclaration of Declared Capability by CS Stations

Entity Mis Declaration Date Incident No No. of days for which FC Deductible

1.4 Weighted Average Percentage Allocation - Peak & Off – Peak Hours combined from ISGS for the
FY 20__-__ Month- 20___

ISGS Ben-1 Ben-2 … … … … … Total

ISGS-1 (August-2023)
ISGS-1
Cumulative2023-24)
ISGS-2 (August-2023)
ISGS-2
(Cumulative 2023-24
…
…
ISGS-13 (August-2023)
ISGS-13
(Cumulative 2023-24

1.5 Details of Scheduled Energy to the Beneficiaries for Month, Year

1.5.a Energy Scheduled from ISGS to the Beneficiaries for Month, Year
All units in MWH

Entity Ben-1 Ben-2 … … … … … Total

ISGS-1
ISGS-2
…
Hydro Name of Hydro
Stations stations
Free Energy of
Hydro Stations
Nuclear Stations

Solar

Wind

13
 Shared Projects

STOA Export by Goa

Note: Energy unit in MWH and upto 3 decimal.

1.5.b Energy Scheduled from Renewable ISGS for the Month, Year
All units in MWH

Entity Total Energy Schedule Total Actual Energy Net Deviation for
(MWH) (MWH) the purpose of REC
(MWH)
SOLAR ENTITY
S1
S2
…
NON SOLAR ENTITY
NS1
NS2
…
Total Solar Deviation for the purpose of REC
Total Non-Solar Deviation for the purpose of REC

Note: Energy unit in MWH and upto 3 decimal.

1.6 Energy Scheduled above Normative PLF from Inter State Generating Stations for the FY 2023-24
(Incentive Energy)

1.6.a. High Demand Season

Details of Incentive Energy (in MWH) Beyond Target PLF
Incentive Energy Peak Period Incentive Energy Off Peak Period

Statio State Name Incentiv Incentive Incentiv Incentive Incentive Incentiv

n e Energy e Energy Energy upto Energy e Energy
Name Energy upto for the Last Month upto for the
upto Current Month Current Month
(D)
Last Month Month
(C)=(B)- (F)=(E)-
Month
(B) (A) (E) (D)
(A)
Station-
1

14
 Total

Station-
2

Total

Station-N

Total

1.6. b. Low Demand Season

Details of Incentive Energy (in MWH) Beyond Target PLF
Incentive Energy Peak Period Incentive Energy Off Peak Period

Statio State Name Incentiv Incentive Incentiv Incentive Incentive Incentiv

n e Energy e Energy Energy upto Energy e Energy
Name Energy upto for the Last Month upto for the
upto Current Month Current Month
(D)
Last Month Month
(C)=(B)- (F)=(E)-
Month
(B) (A) (E) (D)
(A)
Station-
1

Total

Station-
2

Total

Station-N

Total

15
 1.7. Compensation for Degradation of Heat Rate (SHR) and Auxiliary Energy Consumption (AEC)
As per Detailed Operating Procedure on Reserve Shutdown and Compensation Mechanism issued on 05-
05-2017 by Hon'ble CERC.

From Date: dd-mm-yyyy, To Date: dd-mm-yyyy

1.7 a Information used for ECR calculation

Installed Normative Normative Normative Normative Actual GHR Actual Actual Actual
capacity MCR SHR or Net SFC LC Aux. Cons / SHR SFC LC Aux.
Entity (SR-ISGS) (MW) SHR (ml/kWh) CVSF LPPF LPSFi (kg/kWh) LPL (%) CVPF (kCal/kWh) (ml/kWh) (kg/kWh) Cons
(kCal/kWh) (kCal/ml) (Rs./MT) (Rs./KL) (Rs./kg) (kCal/kg) (%)

ISGS-1

ISGS-2

ISGS-13

1.7 b Outage Data details for Stations for the Month, Year

Unit Installed Type of

Entity Start-Date time End Date time
No. Capacity Outage

ISGS-X

ISGS-X

…
Note: Outage Duration has been calculated from 01-04-2023 at 00:00 hrs.

1.7 c Compensation Calculated for each ISGS Stations up to Month , Year

Energy charge rate (ECR) in Rupees per kWh on ex-power
plant basis is determined to three decimal places.

Average Total
Unit schedule ECR EC (A)- EC
ENTITY ECR (Actual) ECR (SE) ECR (DC) EC EC EC (SE) EC (DC) (N) Comp Comp
Loading (MWH) (Norm)
(SR-ISGS) (Rs/kWh) (Rs/kWh) (Rs/kWh) (Norm) (Actual) (Rs) (Rs) (Rs) (P) (F)
(%)
(Rs/kWh) (Rs) (Rs) (Rs) (Rs)
ISGS-1

ISGS-2

ISGS-13

TOTAL

1.7 d Details of Entitlement and Schedule of Beneficiaries and SCED from ISGS

Ben-1 Ben-2 … Ben-15 SCED

SR-ISGS
Ent (MW) Sch (MW) Ent (MW) Sch (MW) Ent (MW) Sch (MW) Ent (MW) Sch (MW) Ent (MW) Sch (MW)
ISGS-1

ISGS-2

16
 …

ISGS-13

1.7 e Proportion of (Un-requisitioned Energy of beneficiaries when Schedule is below 85% of its
entitlement from ISGS) and (SCED)
Rounded off values are shown in the table below; however, actual values are considered for
computation of compensation payable by beneficiary.

SR-ISGS (NTPC) Ben-1 Ben-2 … … … … … … … … … … … … Ben15 SECD Total

ISGS-1

ISGS-2

ISGS-13

1.7 f Compensation Amount payable by Beneficiary

SR-ISGS (NTPC) Ben-1 Ben-2 … … … … … … … … … … … … Ben15 SECD Total

ISGS-1

ISGS-2

ISGS-13

Total for each Beneficiary

1.7 g Statement of Compensation due to Part Load Operation on Account of SCED

Month, Year

Compensation Compensation
Amount Payable Amount Payable
on account of on account of
Decrement due SCED from SCED from Payable/
SCED to SCED up to the National Receviable for
Pool National Pool
Generator month the month
Account (SCED) Account (SCED)
(MWhr) to SCED to SCED (Rs)
Generator upto Generator for
the month the month
(Rs) (Rs)
ISGS-1
ISGS-2
…
ISTS-13
Total

17
 1.8 Details of Intra/ Inter Regional Exchanges through Power Exchanges (COLLECTIVE TRANSCATION
DETAILS)
FROM DD/MM/YYYY TO DD/MM/YYYY
(In MWH)

Indian Energy Exchange Power Exchange of India Hindustan Power Exchange Limited
Import Import(St Export(Regi Export(Stat Import(Reg Import(St Export(Regi Export(Sta Import(Regi Import(St Export Export(
(Region ate on e ion ate on te on ate (Regio State
Peri) Peri) Peri) Peri) Peri) Peri) Peri) Peri) Peri) Peri) n Peri)
Peri)
DAM

Total
___________
Region
Through
__________
Region
Inter national

RTM

Total
___________
Region
Through
__________
Region
Inter national

GDAM

Total
___________
Region
Through
__________
Region
Inter national

HPDAM

Total
___________
Region
Through
__Region
Inter national

18
1.9 Bilateral Open Access Transactions (GNA/T-GNA/REMC Details) for the month …….
SL Access Applicant From From To To IR Approval Schedule
No. State Utility State Utility Link No. (MWh)
1 GNA
2 GNA
3
4 TGNA
TGNA
…

…
REMC
REMC

19
1.10 Certification of DC and Computation of Plant Availability Factor (PAF) and Plant
Load Factor (PLF) for IPPs

Up to Month, Year

Plant Plant
STATION NAME State Contracted Availability up to the Availability Load
Capacity (MW) Month(kWh) Factor (PAF) Factor (PLF)
IPP-1

IPP-2

For Month, Year

Plant Plant
STATION State Contracted Availability up to the Availability Load
NAME Capacity (MW) Month(kWh) Factor (PAF) Factor (PLF)
IPP-1

IPP-2

20
1.11 Statement of Scheduled Energy for exported electricity by Generation Plants (using fuel
except nuclear, gas, domestic linkage coal, mix fuel) for claiming Input Tax Credit

I. Generating Station Name

1. Month in which electricity was exported :

2. Name of Generating Station and Location :
3. Name of Company :
4. GSTIN of Company :
5. Installed Capacity of Generating Station (in
MW) :
6. Connection point state and Region :
7. Details of Scheduled Energy during the month :

Domestic
Scheduled Energy in (MU)
Name of Domestic Entity

…..
……
Power Exchange
Subtotal Domestic Sale (A)
Cross Border
Scheduled Energy in (MU)
Name of Cross Border Country with Exporting entity

Subtotal Export (B)

Total Scheduled Energy of Generating Station (C=A+B)

Note: As per decision taken in the special meeting held on 01st May'2023 under the chairmanship of
Member (Power System), CEA.

21
11. Availability, Schedule and Un-requisition Surplus Data of CGS (For Information) up to Month, Year

All values in MU. This is only for information. It has no commercial implications.
SURRENDER AT
SURRENDERAT GENERATOR
STATION NAME AVAILABILTY SCHEDULE EX-BUS TERMINAL
(SR-ISGS) (SURRENDER AT EX-
BUS/(1-NAux))
ISGS-1 (NAux= XX%)

ISGS-2 (NAux= XX%)

ISGS-13 (NAux= XX%)

22
12. _____________ Region High Demand & Low Demand Seasons and the hours of Peak and Off-Peak
periods during a day declared by ___RLDC

YEAR (F.Y) High demand Season Low Demand Season

Period Hours of Peak Period (4 Hours) during a day

23
 2. RTA Format:

………..REGIONAL POWER COMMITTEE

2.1 RTA for the billing month ……..
S.No. Name GNA GNA Net Usage Balanc National Regional Transformer Total
of DIC (MW) waive GNA based e AC Component Componen s component Transmissio
r (MW AC system (Rs.) t (Rs.) (Rs.) n Charges
(MW) ) system charges payable in
charge (Rs.) Rs.
s (Rs.)

NC-
AC- NC
AC-BC HVD RC TC
UBC -RE
C

2.2 Details of entity-wise bilateral billing

S.No. DIC Name of the Assets Bilateral charges (Rs) Remarks
DIC1
DIC2

24
 3. RTDA Format:

………..REGIONAL POWER COMMITTEE

3.1 RTDA for the billing month ……..
SL No. Gen/State/DIC Located Deviation Deviation Total Transmission Deviation
in State due to due to Deviation Deviation Charges
Over Over (MW) Rate (in Rs.)
drawl injection (Rs/MW)
(MW) (MW)
Beneficiaries of Region

Inter State Generating Stations

SELLER

Inter-National

Generating Station Under INFIRM Stage

Inter-National

3.2 Day wise RTDA format

………..REGIONAL POWER COMMITTEE

Day wise RTDA report for the Month …..
SL No. Gen/State/DIC Located Deviation Deviation Total Transmission Deviation
in State due to due to Deviation Deviation Charges
Over Over (MW) Rate (in Rs.)
drawl injection (Rs/MW)
(MW) (MW)
Beneficiaries of Region

Inter State Generating Stations

25
SELLER

Inter-National

Generating Station Under INFIRM Stage

Inter-National

26
 4. Ramping Accounting Format.

_______REGIONAL POWER COMMITTEE

Mont
Ramp Performance of Thermal Power Stations for Month
h
Number of months in computation (M):
No. of Average
Out of (D), Out of
Time No. of actual ramp
no. of (D), no. Recom
Total Blocks time rate during
time of time mende
no. of Where blocks blocks
Td blocks blocks F d
Time Declared where when E/
Station /T where where / chang
Block Ramp schedule scheduled D
m actual actual D e in
s Up & d ramp ≥ ramp ≥
ramp ≥ ramp ≥ RoE
(Tm) Down 1%/min 1%/min
scheduled 1%/mi (%)
rate ≥ (D) (%/min)
ramp (E) n (F)
1%(Td) (AARR)
Generator
1
Generator
2
Generator
3
Generator
4

5. SCED Account:

_______REGIONAL POWER COMMITTEE

SCED Settlement Account for the Month ______
SL SCED Increment Decrement Charges to Charges to be Net Payable
No. Generator due to due to SCED be paid to Refunded by Charges (+)
SCED scheduled to SCED SCED (in Rs) /Receivab
scheduled VSCED Generators Generators to le (-)
to VSCED (MWHr) from National Pool
(MWHr) (B) National (SCED) (in
(A) Pool Rs)
(SCED) (in (D)= (B) x
Rs) V.C.
(C)= (A) x
V.C.
1
2
3
Total

27
6. Details of Delayed Payments to DSM, Reactive Energy, Congestion
& Ancillary Services Pool and Interest Payable for Delayed Payments
SN Constituent Week Week Amount Amount Difference(Rs.) Due Date of Interest
No Payable Paid Date for Payment to be
(Rs.) (Rs.) Payment paid for
(7 Days) Delayed
Payments
1
2
…

*****

28
Regional Energy Account Statement
(Additional formats)

1
1. Details of Weighted Average Allocation from ISGS for 2023-
24
1.1 Weighted Average Allocation - Peak & Off – Peak Hours
combined from ISGS for the FY 2023-24 (August-2023)
(In MW terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (August-
2023)
ISGS-1
Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative 2023-
24)
…

1.2 Weighted Average Allocation High Demand Season- Peak Hours

from ISGS for the FY 2023-24 (April, 2023)
(In Percentage Terms)
Ben-1 Ben- … … … … … … … … … … …
ISGS Tota
2 l
ISGS-1 (April-
2023)
ISGS-1
(Cumulative
2023-24)
ISGS-2 (April-
2023)
ISGS-2
(Cumulative
2023-24)
…
…

(In MW Terms)
Ben-1 Ben- … … … … … … … … … … …
ISGS Tota
2 l
ISGS-1 (April-
2023)
ISGS-1
(Cumulative
2023-24)
ISGS-2 (April-
2023)
ISGS-2
(Cumulative
2023-24)
…
…

2
1.3 Weighted Average Allocation High Demand Season- Off Peak
Hours from ISGS for the FY 2023-24 (April, 2023)
(In Percentage Terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-
24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative
2023-24)
…

(In MW Terms)
Ben-1 Ben-2 … … … … … … … … … … …
ISGS Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-
24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative
2023-24)
…

1.4 Weighted Average Allocation Low Demand Season- Peak Hours

from ISGS for the FY 2023-24 (August, 2023)
(In Percentage Terms)
Ben-1 Ben-2 … … … … … … … … … … …
ISGS Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative
2023-24)
…

(In MW Terms)
Ben-1 Ben-2 … … … … … … … … … … …
ISGS Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2

3
 (Cumulative
2023-24)
…

1.5 Weighted Average Allocation Low Demand Season- Off Peak Hours
from ISGS for the FY 2023-24 (August, 2023)
(In Percentage Terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative
2023-24)
…

(In MW Terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative
2023-24)
…

4
2. Details of Incentive Energy for Inter State Generating Stations
for the FY 2023-24
2.1 Details of Energy Scheduled above Normative PLF from ISGS – Up
to April-2023 during Peak Hours
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-
24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative 2023-
24)
…

2.2 Details of Incentive Energy from ISGS – Up to April-2023 during

Peak Hours
Normative Schedule Schedule Energy in Incentive Energy
ISGS
Energy in KWhr KWhr in KWhr
ISGS-1
ISGS-2
…

2.3 Details of Energy Scheduled above Normative PLF from ISGS – Up

to April-2023 during Off-Peak Hours

Ben-1 Ben-2 … … … … … … … … … …
SR-ISGS … Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative 2023-24)
…

2.4 Details of Incentive Energy from ISGS – Up to April-2023 during

Off-Peak Hours
Nor.Schedule Energy Schedule Energy in Incentive Energy
SR-ISGS
in KWhr KWhr in KWhr
ISGS-1
ISGS-2
…

5
Additional formats of Output Data Files related to various Accounts:

SN Output Data File Name Output Data File Related

(Name is indicative only) Description Account (s)
1 Commercial_actual Day-wise, Block-wise Actuals DSM
of all DSM Entities
2 commercial_actual_ananthapuramu_inj Day-wise, Block-wise Actuals DSM
of Ananthapuram Entities
3 commercial_actual_pavagada_inj Day-wise, Block-wise Actuals DSM
of Pavagada Entities
4 commercial_dev2022_ENTITY Day-wise, Block-wise DSM DSM
Details of ENTITY;
5 commercial_dev2022_interregional Day-wise, Block-wise DSM DSM
Details of (SR, WR) & (SR ,
ER)

6 commercial_postfacto_ENTITY Postfacto Details of ENTITY DSM

from Eligible Sources
7 commercial_sch_sras_15minute Day-wise, Block-wise AS
Schedules of SRAS Providers
8 commercial_sch_rras Day-wise, Block-wise AS
Schedules of TRAS
Generators of SR
9 commercial_reactive_states Entity-wise, Station-wise, Reactive Energy
Element-wise, Meter-wise Account
Weekly Reactive Energy
Details
10 commercial_dev2022_ENTITY Day-wise, Block-wise RTA & RTA & RTDA
RTDA Details of ENTITY
11 commercial_transmission_charges Day-wise Details of RTA & RTDA
Transmission Charges of all
SR DICs
12 commercial_ecr_data ECR & Compensation REA
Parameters of ISGS Stations
13 commercial_ent_ENTITY Day-wise, Block-wise REA
Entitlement of ENTITY from
all ISGSs
14 commercial_entonbar_ENTITY Day-wise, Block-wise On-Bar REA
& Off-Bar Entitlement of
ENTITY from all ISGSs
15 commercial_gdam_px_iex Details of G-DAM REA
Transactions done in IEX
16 commercial_gdam_px_pxi Details of G-DAM REA
Transactions done in PXI
17 commercial_isgs Day-wise, Block-wise Details REA
of DC & Schedule of all ISGS
18 commercial_modify_dc_sch_isgs Modiefied Day-wise, Block- REA
wise Details of DC &
Schedule of all ISGS
19 commercial_on_off_dc_isgs Day-wise, Block-wise On-Bar REA
6
 & Off-Bar DC of ENTITY
from all ISGSs
20 commercial_outage_data Outage Details of all ISGSs REA
21 commercial_pushp_beneficiary Day-wise, Block-wise Details REA
of allocation inclusive of
PUShP Transactions of SR
Beneficiaries
22 commercial_px_ENTITY Day-wise, Block-wise Details REA
of DAM, GDAM, RTM,
HPDAM Transactions in
Power Exchanges
23 commercial_remc_schedule Day-wise, Block-wise Details REA
of REMC Schedules
involving SR RE Generators/
SR Entities
24 commercial_rnw_schedule Day-wise, Block-wise Details REA
of RENEWABLE bilateral
Schedules involving SR RE
Generators/ SR Entities
25 commercial_rtm_px_iex Day-wise, Block-wise Details REA
of RTM Transactions of SR
Entities in IEX
26 commercial_rtm_px_pxi Day-wise, Block-wise Details REA
of RTM Transactions of SR
Entities in PXI
27 commercial_sch_ENTITY Day-wise, Block-wise REA
Schedules of ENTITY from
all Sources
28 commercial_urs_ENTITY Day-wise, Block-wise Details REA
of URS Power scheduled to
ENTITY from ISGSs
29 Commercial_Gen_Parameters Details of various Parameters REA
of Generators present in the
region
30 commercial_sch_sced Day-wise, Block-wise SCED
Schedules of SCED
Generators of SR
31 commercial_sch_sced_acount Day-wise, Block-wise SCED
Amounts from SCED
Generators of SR

*****

7
Annexure-XXVIIIB
 केंद्रीय विद् यु त प्राविकरण
Central Electricity Authority

राष्ट्रीय विद् यु त सविवत

National Power Committee

Minutes of 14th Meeting of

National Power Committee (NPC)
held on 03.02.2024
At Bangalore.
 iv. The exception report of prolonged non-compliance of the recommendations of
the protection audit may be monitored by NPC on the basis of reports
submitted by RPCs on half yearly basis.
(Action: NPC/RPCs)
4. Unified Accounting Software (UAS) for RPCs
a. MS NPC informed that in the 13th meeting of NPC held on 05th July 2023, it was
decided that the commercial subgroup of NPC would recommend on the
standardization of the formats and software of the commercial accounts. The standard
formats and software finalised by the commercial sub-group would be placed in next
NPC meeting.
b. She further informed that two meetings of commercial sub-group was held on 8.8.23
and 30.10.23. Based on the inputs/comments of ERPC and SRPC, the standardised
output formats was discussed and the Final standard output formats (attached as
Annexure-V) were circulated to all RPCs. The Standard Output formats contains
the formats of the Weekly account (i.e. DSM Settlement Account, Ancillary Service
Account (SRAS, TRAS) and Reactive Energy Account), Monthly Account (i.e.
Regional Energy Account, RTA/RTDA, Ramping Account Format, SCED Account,
Delayed payment accounts) and Additional formats of some commercial account.
Further, a meeting to discuss the implementation of the Unified Accounting Software
for RPCs under the chairmanship of Member (GO&D), CEA was held on 20.11.2023
at Sewa Bhawan, New Delhi in hybrid mode. (MoM is attached at Annexure-VI). In
this meeting, the implementation of the Unified Accounting Software for RPCs were
discussed in detail and the following decisions were taken:

i. ERPC shall be the Nodal RPC for implementation of Unified Accounting Software
for RPCs.
ii. A Joint Committee shall be formed with representatives (Director/Superintending
Engineer/ Deputy Director Level) from all RPCs, GM Division, CEA and NPC
Secretariat. Superintending Engineer, ERPC would be the Member Convener of
Joint Committee with following Term of Reference (TOR):

 Hiring of consultant for preparation of DPR

 Identifying the possible source of funding i.e. through PSDF or RPC funds.
 Preparation of NIT and other documents related to tendering.
 Selection of vendor for commercial account software.
 Execution of work order and certification of completion of work.
 Recommend on O&M/AMC/Ownership of project.
 Any other matter related to Unified Accounting Software.

c. She further informed that in the pre-meeting among MS, RPCs and MS, NPC held on
29.01.2024, MS SRPC suggested that the development of Unified Accounting Software
may be carried out in two phases. In Phase –I, Technical specifications and scope of
work for commercial accounts may be finalised and in the Phase –II, Additional formats
for information or analysis of operational data, report formations may be carried out.
 MS SRPC also suggested the working level officers may be involved in the finalisation
of technical specifications. In pre-meeting, NRPC representative suggested that the
parallel efforts may also be carried out for identifying non uniformity in Commercial
accounts wrt different RPCs so that same may be accommodated simultaneously in
process finalisation. Further, a dedicated team/committee may also be formed at RPC
for carrying out changes required after implementation of the UAS.
d. The standard output formats of commercial accounts and constitution of the Committee
along with its ToR was proposed for approval of the Committee.
e. Chairperson SRPC raised the issue of funding for the Uniform Accounting Software
and suggested that the PSDF funding may be provided for the smoother implementation
of the project considering the importance of Accounts. It was suggested to plan the
implementation of the UAS in the comprehensive manner considering the
interoperability and uniformity among all the regions of the country.
f. Chairperson NPC queried regarding the cost estimates for implementation of the
Unified Accounting Software for all RPCs. MS NRPC informed that RPCs may
share the cost for hiring of consultant and preparation of DPR, however, the project
cost may be funded through PSDF.
g. Director (System Operation) Grid-India informed that the cost of implementation
for Uniform WBES software was around Rs. 20 crore including the cost of AMC.
Accordingly, UAS may cost around Rs. 20-30 crore and the provision of migrating to
5 min scheduling was made in their WBES and other applications. It was opined that
similar provision need to be made in Unified Accounting Software (UAS) of RPCs.
h. Chairperson NPC suggested to prepare a proposal for UAS and thereafter, the PSDF
funding may be sought. The project may be considered as critical project under PSDF
guidelines for bringing interoperability uniformity in the system and importance of
timely and accuracy of Regional accounts. ERPC will be nodal RPC for implementation
of the UAS and the ToR of the Joint Committee may be revised considering the NEA
and for carrying out changes required post implementation of the UAS. He also
suggested to include the NTPC and some states as member of the Joint Committee.
i. Decisions of the Committee:

i. The standard output formats of commercial accounts were approved.

ii. ERPC will be nodal RPC for implementation of the UAS and the ToR of the
Joint Committee may be revised considering the NEA, provisions of migrating
to 5 min scheduling and for carrying out changes required post
implementation of the UAS. NTPC and some states may be included as
member of the Joint Committee.

(Action: ERPC/JC/NPC)

iii. A proposal for UAS may be prepared and thereafter, the DPR may be
submitted to nodal agency i.e. NLDC for PSDF funding. The project may be
considered as critical item under PSDF guidelines for bringing interoperability
and uniformity in the system and importance of timely and accuracy of
 Annexure-XXVIIIC

1. REA Accounts Formats:

___________Regional Power Committee

Regional Energy Account for the Month of ___________
1.1 Details of Plant Availability Factor (PAF) for CS Stations
High Demand Season for FY 20__-__

Peak Hours ( )
ISGS IC Auxiliary NPAF PAFM PAFC High Demand Season Low Demand Season
(MW) Consumptio (%) (%) (%)
n Peak Hour Off-Peak Hour Peak Hour Off-Peak Hour

PAFM PAFC PAFM PAFC PAFM PAFC PAFM PAFC

(%) (%) (%) (%) (%) (%) (%) (%)

ISGS-1

ISGS-2

……

…….

1.2 Details of Plant Load Factor (PLF) for CS Stations

High Demand Season for FY 20__-__

Peak Hours ( )
ISGS IC Auxili NPLF PLFM PLFC High Demand Season Low Demand Season
(MW) ary (%) (%) (%)
Consu Peak Hour Off-Peak Hour Peak Hour Off-Peak Hour
mptio
n
PLFM (%) PLFC PLFM PLFC PLFM (%) PLFC PLFM PLF
(%) (%) (%) (%) (%) C
(%)

ISGS-1

ISGS-1

……
…….

12
1.3 Details of Misdeclaration of Declared Capability by CS Stations

Entity Mis Declaration Date Incident No No. of days for which FC Deductible

1.4 Weighted Average Percentage Allocation - Peak & Off – Peak Hours combined from ISGS for the
FY 20__-__ Month- 20___

ISGS Ben-1 Ben-2 … … … … … Total

ISGS-1 (August-2023)
ISGS-1
Cumulative2023-24)
ISGS-2 (August-2023)
ISGS-2
(Cumulative 2023-24
…
…
ISGS-13 (August-2023)
ISGS-13
(Cumulative 2023-24

1.5 Details of Scheduled Energy to the Beneficiaries for Month, Year

1.5.a Energy Scheduled from ISGS to the Beneficiaries for Month, Year
All units in MWH

Entity Ben-1 Ben-2 … … … … … Total

ISGS-1
ISGS-2
…
Hydro Name of Hydro
Stations stations
Free Energy of
Hydro Stations
Nuclear Stations

Solar

Wind

13
 Shared Projects

STOA Export by Goa

Note: Energy unit in MWH and upto 3 decimal.

1.5.b Energy Scheduled from Renewable ISGS for the Month, Year
All units in MWH

Entity Total Energy Schedule Total Actual Energy Net Deviation for
(MWH) (MWH) the purpose of REC
(MWH)
SOLAR ENTITY
S1
S2
…
NON SOLAR ENTITY
NS1
NS2
…
Total Solar Deviation for the purpose of REC
Total Non-Solar Deviation for the purpose of REC

Note: Energy unit in MWH and upto 3 decimal.

1.6 Energy Scheduled above Normative PLF from Inter State Generating Stations for the FY 2023-24
(Incentive Energy)

1.6.a. High Demand Season

Details of Incentive Energy (in MWH) Beyond Target PLF
Incentive Energy Peak Period Incentive Energy Off Peak Period

Statio State Name Incentiv Incentive Incentiv Incentive Incentive Incentiv

n e Energy e Energy Energy upto Energy e Energy
Name Energy upto for the Last Month upto for the
upto Current Month Current Month
(D)
Last Month Month
(C)=(B)- (F)=(E)-
Month
(B) (A) (E) (D)
(A)
Station-
1

14
 Total

Station-
2

Total

Station-N

Total

1.6. b. Low Demand Season

Details of Incentive Energy (in MWH) Beyond Target PLF
Incentive Energy Peak Period Incentive Energy Off Peak Period

Statio State Name Incentiv Incentive Incentiv Incentive Incentive Incentiv

n e Energy e Energy Energy upto Energy e Energy
Name Energy upto for the Last Month upto for the
upto Current Month Current Month
(D)
Last Month Month
(C)=(B)- (F)=(E)-
Month
(B) (A) (E) (D)
(A)
Station-
1

Total

Station-
2

Total

Station-N

Total

15
 1.7. Compensation for Degradation of Heat Rate (SHR) and Auxiliary Energy Consumption (AEC)
As per Detailed Operating Procedure on Reserve Shutdown and Compensation Mechanism issued on 05-
05-2017 by Hon'ble CERC.

From Date: dd-mm-yyyy, To Date: dd-mm-yyyy

1.7 a Information used for ECR calculation

Installed Normative Normative Normative Normative Actual GHR Actual Actual Actual
capacity MCR SHR or Net SFC LC Aux. Cons / SHR SFC LC Aux.
Entity (SR-ISGS) (MW) SHR (ml/kWh) CVSF LPPF LPSFi (kg/kWh) LPL (%) CVPF (kCal/kWh) (ml/kWh) (kg/kWh) Cons
(kCal/kWh) (kCal/ml) (Rs./MT) (Rs./KL) (Rs./kg) (kCal/kg) (%)

ISGS-1

ISGS-2

ISGS-13

1.7 b Outage Data details for Stations for the Month, Year

Unit Installed Type of

Entity Start-Date time End Date time
No. Capacity Outage

ISGS-X

ISGS-X

…
Note: Outage Duration has been calculated from 01-04-2023 at 00:00 hrs.

1.7 c Compensation Calculated for each ISGS Stations up to Month , Year

Energy charge rate (ECR) in Rupees per kWh on ex-power
plant basis is determined to three decimal places.

Average Total
Unit schedule ECR EC (A)- EC
ENTITY ECR (Actual) ECR (SE) ECR (DC) EC EC EC (SE) EC (DC) (N) Comp Comp
Loading (MWH) (Norm)
(SR-ISGS) (Rs/kWh) (Rs/kWh) (Rs/kWh) (Norm) (Actual) (Rs) (Rs) (Rs) (P) (F)
(%)
(Rs/kWh) (Rs) (Rs) (Rs) (Rs)
ISGS-1

ISGS-2

ISGS-13

TOTAL

1.7 d Details of Entitlement and Schedule of Beneficiaries and SCED from ISGS

Ben-1 Ben-2 … Ben-15 SCED

SR-ISGS
Ent (MW) Sch (MW) Ent (MW) Sch (MW) Ent (MW) Sch (MW) Ent (MW) Sch (MW) Ent (MW) Sch (MW)
ISGS-1

ISGS-2

16
 …

ISGS-13

1.7 e Proportion of (Un-requisitioned Energy of beneficiaries when Schedule is below 85% of its
entitlement from ISGS) and (SCED)
Rounded off values are shown in the table below; however, actual values are considered for
computation of compensation payable by beneficiary.

SR-ISGS (NTPC) Ben-1 Ben-2 … … … … … … … … … … … … Ben15 SECD Total

ISGS-1

ISGS-2

ISGS-13

1.7 f Compensation Amount payable by Beneficiary

SR-ISGS (NTPC) Ben-1 Ben-2 … … … … … … … … … … … … Ben15 SECD Total

ISGS-1

ISGS-2

ISGS-13

Total for each Beneficiary

1.7 g Statement of Compensation due to Part Load Operation on Account of SCED

Month, Year

Compensation Compensation
Amount Payable Amount Payable
on account of on account of
Decrement due SCED from SCED from Payable/
SCED to SCED up to the National Receviable for
Pool National Pool
Generator month the month
Account (SCED) Account (SCED)
(MWhr) to SCED to SCED (Rs)
Generator upto Generator for
the month the month
(Rs) (Rs)
ISGS-1
ISGS-2
…
ISTS-13
Total

17
 1.8 Details of Intra/ Inter Regional Exchanges through Power Exchanges (COLLECTIVE TRANSCATION
DETAILS)
FROM DD/MM/YYYY TO DD/MM/YYYY
(In MWH)

Indian Energy Exchange Power Exchange of India Hindustan Power Exchange Limited
Import Import(St Export(Regi Export(Stat Import(Reg Import(St Export(Regi Export(Sta Import(Regi Import(St Export Export(
(Region ate on e ion ate on te on ate (Regio State
Peri) Peri) Peri) Peri) Peri) Peri) Peri) Peri) Peri) Peri) n Peri)
Peri)
DAM

Total
___________
Region
Through
__________
Region
Inter national

RTM

Total
___________
Region
Through
__________
Region
Inter national

GDAM

Total
___________
Region
Through
__________
Region
Inter national

HPDAM

Total
___________
Region
Through
__Region
Inter national

18
1.9 Bilateral Open Access Transactions (GNA/T-GNA/REMC Details) for the month …….
SL Access Applicant From From To To IR Approval Schedule
No. State Utility State Utility Link No. (MWh)
1 GNA
2 GNA
3
4 TGNA
TGNA
…

…
REMC
REMC

19
1.10 Certification of DC and Computation of Plant Availability Factor (PAF) and Plant
Load Factor (PLF) for IPPs

Up to Month, Year

Plant Plant
STATION NAME State Contracted Availability up to the Availability Load
Capacity (MW) Month(kWh) Factor (PAF) Factor (PLF)
IPP-1

IPP-2

For Month, Year

Plant Plant
STATION State Contracted Availability up to the Availability Load
NAME Capacity (MW) Month(kWh) Factor (PAF) Factor (PLF)
IPP-1

IPP-2

20
1.11 Statement of Scheduled Energy for exported electricity by Generation Plants (using fuel
except nuclear, gas, domestic linkage coal, mix fuel) for claiming Input Tax Credit

I. Generating Station Name

1. Month in which electricity was exported :

2. Name of Generating Station and Location :
3. Name of Company :
4. GSTIN of Company :
5. Installed Capacity of Generating Station (in
MW) :
6. Connection point state and Region :
7. Details of Scheduled Energy during the month :

Domestic
Scheduled Energy in (MU)
Name of Domestic Entity

…..
……
Power Exchange
Subtotal Domestic Sale (A)
Cross Border
Scheduled Energy in (MU)
Name of Cross Border Country with Exporting entity

Subtotal Export (B)

Total Scheduled Energy of Generating Station (C=A+B)

Note: As per decision taken in the special meeting held on 01st May'2023 under the chairmanship of
Member (Power System), CEA.

21
11. Availability, Schedule and Un-requisition Surplus Data of CGS (For Information) up to Month, Year

All values in MU. This is only for information. It has no commercial implications.
SURRENDER AT
SURRENDERAT GENERATOR
STATION NAME AVAILABILTY SCHEDULE EX-BUS TERMINAL
(SR-ISGS) (SURRENDER AT EX-
BUS/(1-NAux))
ISGS-1 (NAux= XX%)

ISGS-2 (NAux= XX%)

ISGS-13 (NAux= XX%)

22
12. _____________ Region High Demand & Low Demand Seasons and the hours of Peak and Off-Peak
periods during a day declared by ___RLDC

YEAR (F.Y) High demand Season Low Demand Season

Period Hours of Peak Period (4 Hours) during a day

23
1. Details of Weighted Average Allocation from ISGS for 2023-
24
1.1 Weighted Average Allocation - Peak & Off – Peak Hours
combined from ISGS for the FY 2023-24 (August-2023)
(In MW terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (August-
2023)
ISGS-1
Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative 2023-
24)
…

1.2 Weighted Average Allocation High Demand Season- Peak Hours

from ISGS for the FY 2023-24 (April, 2023)
(In Percentage Terms)
Ben-1 Ben- … … … … … … … … … … …
ISGS Tota
2 l
ISGS-1 (April-
2023)
ISGS-1
(Cumulative
2023-24)
ISGS-2 (April-
2023)
ISGS-2
(Cumulative
2023-24)
…
…

(In MW Terms)
Ben-1 Ben- … … … … … … … … … … …
ISGS Tota
2 l
ISGS-1 (April-
2023)
ISGS-1
(Cumulative
2023-24)
ISGS-2 (April-
2023)
ISGS-2
(Cumulative
2023-24)
…
…

2
1.3 Weighted Average Allocation High Demand Season- Off Peak
Hours from ISGS for the FY 2023-24 (April, 2023)
(In Percentage Terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-
24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative
2023-24)
…

(In MW Terms)
Ben-1 Ben-2 … … … … … … … … … … …
ISGS Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-
24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative
2023-24)
…

1.4 Weighted Average Allocation Low Demand Season- Peak Hours

from ISGS for the FY 2023-24 (August, 2023)
(In Percentage Terms)
Ben-1 Ben-2 … … … … … … … … … … …
ISGS Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative
2023-24)
…

(In MW Terms)
Ben-1 Ben-2 … … … … … … … … … … …
ISGS Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2

3
 (Cumulative
2023-24)
…

1.5 Weighted Average Allocation Low Demand Season- Off Peak Hours
from ISGS for the FY 2023-24 (August, 2023)
(In Percentage Terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative
2023-24)
…

(In MW Terms)
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (August-
2023)
ISGS-1
(Cumulative 2023-
24)
ISGS-2 (August-
2023)
ISGS-2
(Cumulative
2023-24)
…

4
2. Details of Incentive Energy for Inter State Generating Stations
for the FY 2023-24
2.1 Details of Energy Scheduled above Normative PLF from ISGS – Up
to April-2023 during Peak Hours
Ben-1 Ben-2 … … … … … … … … … …
ISGS … Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-
24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative 2023-
24)
…

2.2 Details of Incentive Energy from ISGS – Up to April-2023 during

Peak Hours
Normative Schedule Schedule Energy in Incentive Energy
ISGS
Energy in KWhr KWhr in KWhr
ISGS-1
ISGS-2
…

2.3 Details of Energy Scheduled above Normative PLF from ISGS – Up

to April-2023 during Off-Peak Hours

Ben-1 Ben-2 … … … … … … … … … …
SR-ISGS … Total

ISGS-1 (April-2023)

ISGS-1
(Cumulative 2023-24)
ISGS-2 (April-2023)

ISGS-2
(Cumulative 2023-24)
…

2.4 Details of Incentive Energy from ISGS – Up to April-2023 during

Off-Peak Hours
Nor.Schedule Energy Schedule Energy in Incentive Energy
SR-ISGS
in KWhr KWhr in KWhr
ISGS-1
ISGS-2
…

5
 2. RTA Format:

………..REGIONAL POWER COMMITTEE

2.1 RTA for the billing month ……..
S.No. Name GNA GNA Net Usage Balanc National Regional Transformer Total
of DIC (MW) waive GNA based e AC Component Componen s component Transmissio
r (MW AC system (Rs.) t (Rs.) (Rs.) n Charges
(MW) ) system charges payable in
charge (Rs.) Rs.
s (Rs.)

NC-
AC- NC
AC-BC HVD RC TC
UBC -RE
C

2.2 Details of entity-wise bilateral billing

S.No. DIC Name of the Assets Bilateral charges (Rs) Remarks
DIC1
DIC2

24
 3. RTDA Format:

………..REGIONAL POWER COMMITTEE

3.1 RTDA for the billing month ……..
SL No. Gen/State/DIC Located Deviation Deviation Total Transmission Deviation
in State due to due to Deviation Deviation Charges
Over Over (MW) Rate (in Rs.)
drawl injection (Rs/MW)
(MW) (MW)
Beneficiaries of Region

Inter State Generating Stations

SELLER

Inter-National

Generating Station Under INFIRM Stage

Inter-National

3.2 Day wise RTDA format

………..REGIONAL POWER COMMITTEE

Day wise RTDA report for the Month …..
SL No. Gen/State/DIC Located Deviation Deviation Total Transmission Deviation
in State due to due to Deviation Deviation Charges
Over Over (MW) Rate (in Rs.)
drawl injection (Rs/MW)
(MW) (MW)
Beneficiaries of Region

Inter State Generating Stations

25
SELLER

Inter-National

Generating Station Under INFIRM Stage

Inter-National

26
 Standard Format of Commercial Accounts
1. DSM Account Format:
1.1 Final Weekly DSM Account

DSM Settlement Account for the week

From DD-MM-YYYY to DD-MM-YYYY

Under Over Post-facto Payable

Entity Total Drawl Drawl Charges/ Final To Pool (“-
Deviation Charges/ Charges/ Charges for Charges “)/
(MWHr) Over Under Drawl (Rs) Receivable
Injection Injection without From Pool
Charges Charges Schedule (“+”)
(Rs) (Rs) (Rs)
States/UT/Drawee Entities
Ent-1

Ent-2
….

CGS
CGS-1
CGS-2
…

General Sellers
GS-1
GS-2
…

WS-Seller
Solar Entity
SE-1
SE-2
…

Wind Entity
WE-1
WE-2
…
Inter- regional

3
 Inter- National

Infirm generators

(All Figs. in Rs.)

Payable To The Pool (A) :
Receivable From The Pool (B) :
__ Deviation (A-B) :

1.2 Day-wise Report Format:

(All Figs. in Rs.)
Date Total Total Deviation Final Payable To Pool (“-
Scheduled Actual (MWH) Charges “)/ Receivable
(MWH) (MWH) (Rs) From Pool (“+”)

States/UT/Drawee Entities
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
CGS
Day-1
Day-2
Day-3

4
Day-4
Day-5
Day-6
Day-7
Weekly Total
General Sellers
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
WS-Seller
Solar Entity
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Wind Entity
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Inter- regional

Day-1
Day-2

5
 Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Inter National
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Infirm Generator
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Note: Energy unit in MWH and upto 3 decimal.

2. Ancillary Service Account:

2.1 SRAS Settlement Account for the week from dd-mm-yyyy to dd-mm-yyyy

Payments to the SRAS Provider(s) from the DSM pool

Sr. SRAS UP Down Net Energy Incentive Total Payable

No. Provider Regulation Regulation Energy Charges/ Charges Charge to the
due to due to (MWh) Compensati (Rs.) s (Rs.) pool/Re
SRAS SRAS on Charges ceivable
(MWh) (MWh) (Rs.) from
the pool

6
 Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Inter National
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Infirm Generator
Day-1
Day-2
Day-3
Day-4
Day-5
Day-6
Day-7
Weekly Total
Note: Energy unit in MWH and upto 3 decimal.

2. Ancillary Service Account:

2.1 SRAS Settlement Account for the week from dd-mm-yyyy to dd-mm-yyyy

Payments to the SRAS Provider(s) from the DSM pool

Sr. SRAS UP Down Net Energy Incentive Total Payable

No. Provider Regulation Regulation Energy Charges/ Charges Charge to the
due to due to (MWh) Compensati (Rs.) s (Rs.) pool/Re
SRAS SRAS on Charges ceivable
(MWh) (MWh) (Rs.) from
the pool

6
 Total

Notes :

1. Energy unit in MWH and upto 3 decimal.

2. Energy Charges/Compensation Charges for SRAS provider has been calculated as per the rate furnished
by the respective SRAS providers in Format AS and the same published in RPC website.
3. The Incentive has been calculated based on actual performance of SRAS providers.

2.2 SRAS Actual Performance Statement by __RPC

from dd-mm-yyyy to dd-mm-yyyy
Sr. SRAS dd-mm-yyyy dd-mm-yyyy dd-mm-yyyy … dd-mm-yyyy dd-mm-yyyy Remarks
No. Provider (Disqualification
Actual Actual Actual … Actual Actual period)
Performance(%) Performance(%) Performance(%) Performance(%) Performance(%)

…
…
…

2.3 TRAS Account:

TRAS Settlement Account for the week from dd-mm-yyyy to dd-mm-yyyy

(Short Fall/Emergency)

Net Charges Payable/Receivable by the TRAS Provider(s) to/from the Regional

Deviation and Ancillary Service Pool Account in Shortfall/Emergency Condition

TRA Energy Total Charges Energy Total Charges / Net Payable

SL S schedule /Compensatio scheduled Compensation Charges from Pool
No. Provi d under n Charges for under Charges for (Rs) to TRAS
der shortfall/ Shortfall/Eme Shortfall/Eme Shortfall/Emerge (E)=(B)- Provider/
Emergen rgency rgency ncy TRAS- (D) Receivabl
cy TRAS-Up TRAS-Down Down to be e by Pool
TRAS- (Rs) (MWh) paid back to Pool from
Up (B) (C) (Rs) TRAS
(MWH) (D) Provider
(A)

Notes:

7
A) TRAS settlement account for the week dd-mm-yyyy to dd-mm-yyyy has been prepared as per the detailed procedure
for Tertiary Reserve Ancillary Services (TRAS) approved by CERC.

B) Total Charges for TRAS providers have been calculated as per the rates furnished by the respective TRAS providers
and the same published in ___RPC website.

2.4 TRAS Settlement Account by RPC (Day Ahead and Real Time Market)
TRAS Account for Week from dd-mm-yyyy to dd-mm-yyyy.
Net Charges Payable/Receivable by the TRAS Provider(s) to/from the Regional Deviation and Ancillary
Service Pool Account

S. TRA TRAS-Up in Day Ahead AS Market TRAS-Up Energy in Real Time AS Market Total
No S Charges/
Provi compensati
der on charge
Nam for TRAS
e Up (Rs)
(I)=(C)+(D
)+ (G)+(H)
(11)
(1) (2) TR TRAS- TRAS TRAS-Up TRAS TRAS- TRASUp TRAS-Up
AS Up Up Commitme Up Up Energy Commitmen
Up Energy Energ nt Charges Cleare Energy Charges t Charges
Cle Sched y (Rs.) (D) d Schedule (Rs) (G) (Rs) (H)
ared uled Charg (6) (MWh d (MWh) (9) (10)
(M (MWh es ) (E) (F)
Wh) ) (B) (Rs.) (7) (8)
(A) (4) (C)
(3) (5)

1
2
3

TRAS-Down in Day Ahead AS Market TRAS-Down in Real Time AS Market Net Charges (Rs) Payable
(N)=(I)-(K)- (M) from Pool
(15) to TRAS
TRASDown TRASDown TRASDown TRASDown Charges Provider/R
Energy Charges to be paid Energy Scheduled to be paid back to eceivable
Scheduled back to Pool (Rs) (MWh) (L) Pool (Rs) (M) by Pool
(MWh) (J) (K) (14) (15) from TRAS
(12) (13) Provider

1
2

8
3. Reactive Energy Account Format:

3.1 Weekly Reactive Energy Account format after final Adjustment:

Regional MVArh_H MVArh_L Net Payable to Pool
Entity Name Amount (-)/
(Rs.) Receivable
from Pool (+)

States/UTs/ Drawee Utilities

CGS

General Sellers

WS Seller (Solar Entity)

WS Seller (Wind Entity)

WS Seller (Others)

(All Figs. in Rs.)

Payable To The Pool :
Receivable From The Pool :

3.2 Meter-wise Reactive Energy Details

Regional Station Element Meter No MVArh_H MVArh_L

Entity Name Name Name
Ent-1
Ent-2
…

9
 3.3 Day wise Format:
Reactive Energy export (-) / import (+) under high & low voltage condition
And Reactive Energy Charges thereof
(Reactive Energy Exchange in MVARH & Charges in Rs.)

Regiona ISTS/B Drawl Day1 (HV, … Day7(HV, Total HV Total Charges Charges
l BMB/D Point LV)... … LV) LV HV LV
VC etc.
Entity
Name

10
 4. Ramping Accounting Format.

_______REGIONAL POWER COMMITTEE

Mont
Ramp Performance of Thermal Power Stations for Month
h
Number of months in computation (M):
No. of Average
Out of (D), Out of
Time No. of actual ramp
no. of (D), no. Recom
Total Blocks time rate during
time of time mende
no. of Where blocks blocks
Td blocks blocks F d
Time Declared where when E/
Station /T where where / chang
Block Ramp schedule scheduled D
m actual actual D e in
s Up & d ramp ≥ ramp ≥
ramp ≥ ramp ≥ RoE
(Tm) Down 1%/min 1%/min
scheduled 1%/mi (%)
rate ≥ (D) (%/min)
ramp (E) n (F)
1%(Td) (AARR)
Generator
1
Generator
2
Generator
3
Generator
4

5. SCED Account:

_______REGIONAL POWER COMMITTEE

SCED Settlement Account for the Month ______
SL SCED Increment Decrement Charges to Charges to be Net Payable
No. Generator due to due to SCED be paid to Refunded by Charges (+)
SCED scheduled to SCED SCED (in Rs) /Receivab
scheduled VSCED Generators Generators to le (-)
to VSCED (MWHr) from National Pool
(MWHr) (B) National (SCED) (in
(A) Pool Rs)
(SCED) (in (D)= (B) x
Rs) V.C.
(C)= (A) x
V.C.
1
2
3
Total

27
6. Details of Delayed Payments to DSM, Reactive Energy, Congestion
& Ancillary Services Pool and Interest Payable for Delayed Payments
SN Constituent Week Week Amount Amount Difference(Rs.) Due Date of Interest
No Payable Paid Date for Payment to be
(Rs.) (Rs.) Payment paid for
(7 Days) Delayed
Payments
1
2
…

*****

28
 Annexure-VIII 14th NPC

National Power Committee

National Energy Account
Week from ----------to ------------

A. Deviation Settlement Account Statement

DSM Weekly Statement (From DD-MM-YYYY to DD-MM-YYYY)

Inter-regional
From ↓/ To → ER WR NR SR NER Net Payable To
Charges National Pool /
Receivable From
(Rs)
National Pool

ER -
WR -
NR -
SR -
NER -
Inter-National
Bhutan
Bangladesh
Nepal
Dagachu HEP

Basachu HEP

DSM Pool Summary

Total Payable to National Pool

Total Receivable from National Pool

Net Total
 B. Settlement through National Pool Account

RRAS RRAS AGC

DSM Net Surplus Inter-Pool
Charges Charges Net Charges
Surplus (+)/ (+)/ Deficit (- transfer
Region paid from received in paid from
Deficit (-) ) required
DSM Pool DSM Pool a/c DSM Pool a/c
(A) (A-B+C-D) (Yes/No)
a/c (B) ( C) (D)
ER
WR
NR
SR
NER
Total
 Reactive Energy Account Statement
Statement of Reactive Energy Charges
(For The Period from DD-MM-YYYY to DD-MM-YYYY)

1. Reactive Energy Charges with the National Pool (For the Period
from DD-MM-YYYY to DD-MM-YYYY]

Regional MVArh_H MVArh_L Net Payable to Pool (-)/

Entity Name Reactive Receivable from Pool
Energy (+)
Charges
(Rs.)
Inter-National
IN-1
IN-2
…
Reactive Pool Summary
Total
Payable to
National
Pool
Total
Receivable
from
National
Pool
Net Total
 SCED MONTHLY ACCOUNT STATEMENTS
1. National SCED Account Statement - for the month of
Month, Year

* (+) means payable from the 'National Pool Account (SCED)' to SCED Generator
/ (-) means receivable by 'National Pool Account (SCED)' from SCED Generator

Increment
Decrement Charges To Charges To be
due to Payable
due to be Paid to Refunded by Net Charges (in from SCED
S.No SCED
SCED SCED SCED Rs)
SCED scheduled Pool (+)/
Generator scheduled Generator Generator to (E*= C-D)
to VSCED Receivable to
to VSCED from National Pool
(MWHr) SCED Pool
(MWHr) National (in Rs)
(A) Pool (in Rs) (D=B*VC) (+)
(B)
(C=A*VC)
ERPC

ISGS1

ISGS2

2 NERPC

ISGS1

ISGS2

NRPC

ISGS1

ISGS2

SRPC

ISGS1

ISGS2

WRPC

ISGS1
 ISGS2

Total

2. National Statement of Compensation due to Part Load Operation

on Account of SCED for the Month of Month, Year

Compensation Compensation
Amount Payable Amount Payable
on account of on account of
Decrement due SCED from SCED from Payable to Pool/
SCED to SCED up to National Pool National Pool Receivable from
Generator the month Account (SCED) Account (SCED) Pool for the
(MWhr) to SCED to SCED Month
Generator Generator
upto the month for the month (Rs)
(Rs) (Rs)
ERPC

ISGS-1

……

NERPC

ISGS-1

……..

NRPC

ISGS-1

…….

SRPC

ISGS-1
 …….

WRPC

ISGS-1

……

Total

3. National net SCED Benefits Distribution Statement- SCED Generator

for the Month of …………

Table 1: System Savings

Total Saving for the Heat Rate Net Saving for the SCED UP + DOWN in
month (Rs.) (A) Compensation (Rs.) (B) month (Rs.) (C) MWH (E)

Table 2: Share of System Savings for Merchant Generators

Generator SCED Contribution in Benefit Estimated Final benefit

Schedule SCED accrued to benefit (Rs. (Rs.)
MWH Generator per KWH)
(Rs.)

Table 3: Share of System Savings for Untied capacity

Generator SCED Contribution in Benefit Estimated Final benefit

Schedule SCED accrued to benefit (Rs. (Rs.)
MWH Generator per KWH)
(Rs.)
Table 4: Share of System Savings for tied capacity

System benefit for Benefit to net Gen Discoms SCED UP SCED

Savings Merhant United savings share share Generators DOWN
(Rs.) Generator Portion of for tied (50%) (50%) Contribution Generators
(Rs.) generator cap (Rs.) (Rs.) Contribution
with part (Rs.)
tied
capacity
(Rs.)

Table 4A: Share of System Savings for tied capacity for SCED UP & DOWN

For SCED Up

SCED UP SCED Contribution Generator's Estimated Generator Final additional

Generators UP % Contribution benefit Benefit Benefit to benefit
Schedule in Share of (Rs. per subject to Generator for
(MWH) Saving (Rs.) KWH) cap of 7 (Rs.) discoms
paise (Rs.)
/kWh
ISGS1
ISGS2
……

For SCED Down

SCED SCED Contribution Generator's Estimated Generator Final additional

Down UP % Contribution benefit Benefit Benefit to benefit
Generators Schedule in Share of (Rs. per subject to Generator for
(MWH) Saving (Rs.) KWH) cap of 7 (Rs.) discoms
paise (Rs.)
/kWh
 ISGS1
ISGS2
……

4. National net SCED Benefits Distribution Statement- Beneficiary for the

Month of ………..

Sl No State REGION Total 50% Additional Total

schedule Benefit benefit benefit
Energy(Mwh) sharing in sharing in sharing in
(Rs) (Rs) (Rs)
1 State1 ER
2 State2 ER
3 …….
4 State1 NER
5 …. NER
6 State1 NR
7 …. NR
8 State1 SR
9 …… SR
10 State1 WR
….. …… WR
 1
Annexure-XXIX
File NO. Hy?^L-5^F^m^m^fM^i^)^tm^^^uter No- 1046269)41
3p3©!2f9a823SYSTEM STUDY
A.20.1 NHPC Representative stated that they are repeate^ly requesting JKPCL, J&K to

open letter of credit (LC) for an amount of 96.76 Crs in accordance with letter of MoP

notification no. 23/22/2019- R&R (Part-4) dated 03.06.2022 "Electricity (Late

Payment Surcharge and Related matters) Rules, 2022". However JKPCL, J&K has

yet not opened the LC for the requisite amount in favour of NHPC Ltd.

A.20.2 NHPC Ltd. reiterated that in accordance with the Ministry of Power (MoP), Govt. of

India notification mentioned, requisite LC is necessarily required to be opened by

distribution company in favour of generating company before schedule of power to

them.

A.20.3 LC is to be opened by JKPCL, J&K of mentioned amount worked out on the basis of

105% of last 12 months average billing. In this regard, last reminder was sent to

JKPCL, J&K on 11.08.2023.

A.20.4 Member Secretary, NRPC highlighted that the issue is same as of SJVN. So

discussion on the same has already been done under agenda no. 7 of this meeting.

Decision of the Forum:

Forum decided to send a DO letter by Chairperson, NRPC to Secretary (Power),

^J&K and MHA, GOI highlighting the issue for early resolution.

A.21 Replacement of Various Size of ACSR Conductor (i.e.

wolf/panther/zebra/moose) with Equivalent HTLS Conductor to Reduce the

Overloading of Existing Transmission Lines and also to Improve the Reliability

of Power System in Haryana under PSDF Grant (agenda by HVPN)

A.21.1 EE (P) apprised about agenda of HVPN regarding re-conductoring work on their line.

A.21.2 HVPN representative added that due to exponential growth in power demand, the

existing lines are unable to cater power demand in the various region of Haryana. It

is further submitted that erection of new lines in these regions are not feasible due to

non-availability of RoW (Right of Way). Therefore, replacement of existing ACSR

conductors with equivalent HTLS conductor of higher current carrying capacity is the

only available option to reduce the overloading of existing lines and also to improve

~the reliability with capability to cater the increased load demand in Haryana.

A.21.3 He explained that the designing of HTLS conductor depends a lot on the conductors

ageing effect on sag and tension, existing creep mitigation methods of the conductor

and the profile of existing Transmission lines. Therefore, all the works have been

packaged as per existing size (type) of the conductor i.e. wolf, Panther, Zebra &

32
4
Generated from eOffice by PALAK SINHA, AE2 SYSSTDY, AE-2/SYS.STDY, HVPNL on 16/11/2023 12:53 PM
 File NO. HVPNL-58FJ*j!^^|}SHg^;a^^1046269) 42

23SYSTEM STUDY
Moose. Accordingly, following 3 no. packages have been prepared with overall

estimated cost of Rs. 290 Crore (approx.) (Annexure-VII).

A.21.4 Chairperson, NRPC highlighted that there are multiple cases of right of way issues in

NCR region so HTLS conductor is better option.

A.21.5 Member Secretary, NRPC appreciated the HVPN for their proposal and addressed

the importance of PSDF for improvement of grid network.

A.21.6 CTU representative stated that intra-state network augmentation may be discussed

at CEA level first for technical feasibility.

Decision of the Forum:

Forum accorded in-principal approval to proposal of HVPN for replacement of

various size of ACSR conductor (i.e. wolf/panther/zebra/moose) with equivalent

HTLS conductor. HVPN was requested to approach CEA for technical evaluation

and accordingly, DPR for PSDF may be put up for approval of NRPC in upcoming

meetings.

A.22 Non submission of Letter of Credit (LC) by M/s. JKPCL (agenda by NPCIL)

A.22.1 NPCIL representative apprised that as per Power Purchase Agreement the Discom-
M/s. JKPCL is required to open LC as payment security mechanism for an amount

worked out on the basis of 105% of last 12 months average billing.

A.22.2 He highlighted that LC of JKPCL has expired on 13.11.2019, and since then, inspite

of various reminders, DISCOM has not acceded to open LC in favour of NPCIL for

power supplied from Rajasthan Atomic Power Station and Narora Atomic Power

Station.
A.22.3 He further stated that NPCIL wants to get it resolved amicably without any litigation

or arbitration way. Accordingly, he requested Forum to sort the matter on its level.
A.20.5 Member Secretary, NRPC highlighted that the issue is same as of SJVN and NHPC.

So discussion on the same has already been done under agenda no. 7 and 20 of

this meeting.

Decision of the Forum:

Forum decided to send a DO letter by Chairperson, NRPC to Secretary (Power),

J&K and MHA, GOI highlighting the issue for early resolution.

33

Generated from eOffice by PALAK SINHA, AE2 SYSSTDY, AE-2/SYS.STDY, HVPNL on 16/11/2023 12:53 PM
 Annexure-XXX
File No.CEA-PS-11-22(13)/1/2019-PSPA-l Division/ t^^^^'366
W31631/2023

Government of India

Ministry of Power
^^i^ i^iertt >iii*t*fKfi
Centra! Electricity Authority
Rft ^I
Power System Planning & Appraisal-I Division
fr^rt/To,
Chief Engineer (PD&C),
Haryana Vidyut Prasaran Nigam Limited,
Shakti Bhawan,
Sector-6, Panchkula- 134109

^^t^r/Subject: HVPNL's proposal for replacement of various existing conductors (Le. wolf/

panther/ zebra/ moose) with equivalent HTLS conductor to reduce the

overloading of existing transmission lines

J<s^/ Reference:
(i)HVPNL letter no. Ch-18/HSS-39 l/III dated 25.08.2023
(ii)HVPNL letter no. Ch-32/HSS-39I/Vol-III dated 13.09.2023
(iii)HVPNL letter no. Ch-43/HSS^3# 1/VoMI dated 27.09.2023
(iv)HVPNL email dated 29.09.2023
(v)CEA email dated 13.10.2023
(vi)HVPNL email dated 16.10.2023

*l^kl/ Sir,

HVPNL has submitted that due to the exponential growth hi electricity demand, the existing
lines are unable to cater the power demand in various areas of Haryana. Therefore, HVPNL
vide its letters under reference (i) and (ii) has proposed replacement of existing conductors
with equivalent HTLS conductors in the areas where erection of new transmission lines is not
possible due to non-availability ©f RoW, •- •;; '' ;*;-:^;i;::^: , V^:^^ ..,:/.'^.J-^.j.,.;:^•^,-;; ;^^:^X

HVPNL's proposal was deliberated in a meeting held on 15.09.2023 amongst CEA, CTUIL,
Grid-India and HVPNL wherein CEA requested HVPNL to submit the proper justification
for requirement of reeonduetoring of various lines along with requisite data such as peak
loading observed till date, expected loading in future etc, along with load flow studies. The
same has been submitted by HVPNL vide letter u/f (Mij and emails u/r (iv) aud (vi).

Comments were sought from CTUIL and Grid-India on die above proposal. Based on the
comments of CTUIL and Grid-India, our observations are as follows:

(i) Based on the peak loading data, future Ibad projections and the load flow studies
submitted by HVPNL, proposals for reeonduetoring of following existing lines have
been found to be generally m order:

^^^^ ^eR, 3HT. %. ^W"I, -ff %Wfl^i 10066 ^dWHWs fU 1

Sewa Bhawan. R.K Puram-I, New De)hi-110066Tefefax: 011-26102045 email: rjB^ispai(^(yw inWafwita- ^mw r, m a nic. in
 File Nq.CEA-PS-1i-22(13)/1/2frl9-PSPA-l Division 367

1/31631/202;:•SI. No. HVPNL^s proposal

Reeonduetoring of Palwal - Mandkola 66 kV D/c line with HTLS conductor
having current carrying capacity of 600 Amp. (Route length-11.186 km)
Reeonduetoring of Palwal - Hathin 66 kV S/e line with HTLS conductor having
I
current carrying capacity of 600 Amp. (Route length-14.2 km)
Reeonduetoring of Badshahpw-Seetor 35-Harsaru 66 kV S/e line with HTl-S
conductor having current carrying capacity of 600 Amp along with raising of
height at some locations. (Route length-9.96 km)
Reeonduetoring of Khokrakot-Sector 3 Rohtak 132 kV S/e line with HTLS
conductor having current carrying capacity of 600 Amp. (Route lengtfa-7 km)
Reeonduetoring of Harsaru - Farukhnagar 66 kV S/e line with HTLS conductor
having current carrying capacity of 600 Amp. (Route length-12.162 km)
Reeonduetoring of portion* of HSIIDC- Barwala 66 kV S/e line (created after
• LILO of one circuit of Madanpur- Barwala 66 kV D/c line at HSIIDC) from
Barwala S/s upto the LILO point with HTLS conductor having current carrying
capacity of 600 Amp (Route length-4.8 km)•
Reeonduetoring of Daultabad-Sector 10 Gurugram 66 kV D/c line with HTLS
7. conductor haying current carrying capacity of 600 Amp. (Route length-10.5 km)
Reeonduetoring of Chormar- Dabwali 132 kV S/e line with HTLS conductor
8.
having current carrying capacity of 600 Amp, (Route length-24 km)
9.Reeonduetoring of Shahpur Begu - Sirsa 132 kV S/c line with HTLS conductor
I having current carrying capacity of 600 Amp. (Route length-9.5 km)
10.! Reeonduetoring of Jiwan Nagar - Rania 132 kV S/c line with HTLS conductor
having current carrying capacity of 600 Amp. (Route length-14 km)
Reeonduetoring of A4-Ford 66 kV D/c line with HTLS conductor" having current
11.
carrying capacity of 600 Amp. (Route length-0.72 km)
Reeonduetoring of Palla- Faridabad Sector 31 66 kV D/c line with HTLS
12.
conductor having current carrying capacity of 600 Amp. (Route length-3 km)
Reeonduetoring of Rohtak - Khorkrakot Rohtak 132 kV D/c line ckt-1 with
13.
HTLS conductor having current carrying capacity of 600 Amp. (Route length-

2.7 km):
Reeonduetoring of Rohtak - Khorkrakot Rohtak 132 kV D/c line ckt-2 with
14.
HTLS conductor having current carrying capacity of 600 Amp. (Route length-
2.7km) ' '".y.^[:^^^.i "vi::k::.. ' ,/.• ^ . / ..,,'..,.•..,.;.,. .,

Reeonduetoring of portion* of Nissing-Jalmana 132 kV S/e line (which is to be

15. LILOed at Dacher) with HTLS conductor having current carrying capacity of
600 Amp from Nissing S/s up to LILO Point. (Route length-6.5 km)
Reeonduetoring of Isherwal - Behal 132 kV S/c line with HTLS conductor
16.
having current carrying capacity of 600 Amp. (Route length-19.5 km)
Reeonduetoring of Chhajpur-Chandoli 132 kV S/c line with HTLS conductor
17.
having current carrying capacity of 600 Amp. (Route length -8 km)
Reeonduetoring of Bastara- Madhubao 132 kV S/c with HTLS conductor having
18.
current carrying capacity of 600 Amp (Route iength-5.821 km)
Reeonduetoring of Karnal- Madhuban 132 kV S/c line with HTLS conductor
19.
having current carrying capacity of 600 Amp (Route length^12.065 km)
Reeonduetoring of Nunamajra-MIE Bahadurgarh 132 kV S/e line with HTLS
20. conductor having current carrying capacity of 600 Amp (Route length-11.3 km)
Reeonduetoring of portion* of Bapora-Tosham 132 kV S/c line from Tower
21,
Location (TL) No. 69-92 with HTLS conductor having current carrying capacity
of 600 Amp. (Route length-5.6 km) r
Reeonduetoring of LILO portion* of LILO of Narwana- Jind 132 kV S/c line at
22.
Uchana with HTLS conductor having current carrying capacity of 600 Amp.
 File No,GEA-PS-11-22(13)/1/2019-PSPA-l Division 368

1/31631/20^ 1. No. HVPNL's proposal

(Route lengtfa-1,094 km)
Reeonduetoring of Nuhiyawali-Khairekan 132 kV S/c line with HTLS
23. conductor having current carrying capacity of 600 Amp (Route lengtfa-25 km)
Reeonduetoring of Daultabad-IMT Manesar 220 kV D/c line along with LILO of
24. one circuit at 220 kV Substation Seetor-85, Gurugram with HTLS conductor
having ettrrettt carrying capacity of 1200 Amp.( Route length-!7.56 infr
Reeonduetoring of LILO portion* of LILO of 2nd circuit of Daultabad-IMT
25. Manesar 220 kV D/c line at 220 kV Substation Sector-99, Gurugram with HTLS
conductor having current carrying capacity of 1200 Amp.( Route length-2.39

km)
Recondtictoring of Sector 72 Gurgaon (POCIL) - Sector 72 Gurgaon (HVPNL)
26. 220 kV 3xS/c line with HTLS conductor having current carrying capacity
equivalent to Twin Moose conductor (Route length-0.12 km)
Reeonduetoring of Sector 46-Palli 220 kV D/c line with HTLS conductor having
27. current carrying capacity of 1200 Amp. (Route tength-8.01 km)
Reeonduetoring of PGCIL (Khanpur)-Kaithal 220 kV D/c line with HTLS
28. conductor having current carrying capacity of 1200 Amp along with the
replacement of existing insulators (Route length -15.9 km)
*Rest of the line already implemented/ under implementation with high capacity

conductor-.
(ii) Regarding the remaining proposals submitted by HVPNL, as per the load flow
studies, it has been observed that reeonduetoring of the lines with HTLS conductor
may not be required. Therefore, HVPNL is requested to review the proposals or
submit proper justification for requirement of the reeonduetoring of the lines. Details
of the proposals along with observations of CEA are enclosed as Annexure A.
(iii) Along with recomdttctoring of the proposed line^, HVPNL may also ensure matching
of bay upgradation works associated with lines whose reeonduetoring has been

proposed.
(iv) It has been observed that various Intra State lines and ICTs of HVPNL are 'N-1' non-
compliant. HVPNL may plan necessary transmission system strengthening works for

fixe same.
/ Yours faithfully,

^^

^^t/Manjari Chaturvedi)
Director)

Copy to:
1.COO (CTUIL), Saudamini, Plot no. 2, Sector -29, Gurgaon-122 001
2.Director (System Operation), Grid Controller of India Limited (Grid-India), B-9,
Qutab Institutional Area, Katwaria Sarai, New Delhi - 110010.
 FileNo.CEA-GO-17-14(13)/1/2023-NRPCa^23^
1/3^257/2023/Wfl^^ - _O^
48^ TCC & If^ NRPC Meeting (17-18 Nov 2023)-MoM—
Annexure-XXXI
i. Forum appreciated the initiative of RVPN for use of drone technology in tower
surveillance,

ii. RVPN was requested to do analysis on tower design and causes of its failure.

A.31 Replacement of various size of ACSR conductor (i.e.

wolf/panther/zebra/moose) with equivalent HTLS conductor to reduce the
overloading of existing transmission line thereby improving the reliability of

power system in Haryana (agenda by HVPN)

TCC Deliberation

A.31.1 EE (P) apprised that The HVPNL proposal for 31 No. existing overloaded
transmission lines for augmentation with HTLS conductor through PSDF funding was
discussed in 68th NRPC meeting held on 18.08.2023 for grant of PSDF wherein

following was decided:

Forum accorded in-principal approval to proposal of HVPN for replacement of

various size of ACSR conductor (i.e. wolf/panther/zebra/moose) with

equivalent HTLS conductor. HVPN was requested to approach CEA for
technical evaluation and accordingly, DPR for PSDF may be put up for

approval of NRPC in upcoming meetings.

A.31.2 Subsequently, the detailed proposal was submitted by HVPN to Central Electricity

Authority (CEA) vide letter dated 25.08.2023.

A.31.3 After detailed deliberations and meeting held on dated 15.09.2023, wherein CTU and
Grid India were also present, CEA concurred the proposal for augmentation with
HTLS conductor of 28 No transmission lines.
A.31.4 Accordingly, Detailed Project Report (Annexure-XVI) is placed for approval of
Forum.

A.31.5 MS, NRPC appreciated HVPN and encouraged states to come with such proposals

from PSDF fond.

A.31.6 In concurrence to CEA, forum approved the DPR for proposal of 28 nos, of lines to
be implemented by PSDF fund and recommended to NRPC forum for approval.

NRPC Deliberation

Forum concurred the decision of the TCC forum.

Decision of NRPC Forum:

 File No.CEA-GO-17-14(13)/1/2023-NRPC23^
I/32257/2023
48P TCC & 7(f NRPC Meeting (17-18 Nov 2023)-MoM

Forum approved DPR for reeonduetoring proposal of 28 nos. of lines to be

implemented by PSDF fond.

A.32 Philosophy of Drawal Points of ICTs at Transmission Substation of PGCIL

(agenda by UPSLDC)
TCC Deliberation

A.32.1 EE (P) apprised that in 23rd TeST sub-committee meeting held on 21.09.2023 issue
of Drawal Points of ICTs at Transmission Substations of PGCIL was deliberated.

A.32.2 In the meeting, it was submitted that SEM installed at 220kV feeders should be taken
for purpose of energy drawal and accounting of states. In case, there is some issue
in SEM of 220kV feeders, meters installed at LV side of ICTs may be taken for the
purpose of Energy. In the meeting, it was decided that a separate meeting may be
held to discuss the issue of philosophy of Drawal points.
A.32.3 Accordingly, a separate meeting was held on 13.10.2023 at NRPC Secretariat
wherein UP raised concern in calculation of energy loss and stated that drawal is
being calculated from the POWERGRID substation's HV side, but the drawal point of
state is on the LV side of ICT which should be taken for the purpose of energy
drawal and accounting of states. MoM of the meeting is attached as Annexure-XVII.
A.32.4 Further, it was deliberated that according to CEA metering regulation, 2005 location
of meter to be installed is on the HV side of the ICT and if, two or more states are
fed, it should be placed on feeder. However, if LV side of ICT is taken for energy
drawl and accounting then ICT losses will be borne by CTU, which will be distributed
all over India which may not be a correct practice.
A.32.5 Furthermore, CERC (Sharing of ISTS and Losses) Regulations, 2020 states that
Transformer Component for a State shall comprise of Yearly Transmission Charges
for inter-connecting transformers (ICTs) planned for drawl of power by the concerned
State. Hence, only socializing of losses may be unjust.
A.32.6 CE, UPSLDC stated that as the asset is of POWERGRID, then state should not bear

loss of it by connecting meter on HV side.

A.32.7 MS, NRPC quoted that as per CERC and CEA regulation, metering is to be done
from HV side. CTU will not bear the ICT loss. UP STU may approach to UPERC or
CERC for the resolution.
A.32.8 CE (RA division), CEA commented that meter should not be at interface side, it
should be on LV side. But as per practice and provisions of regulations the metering
is to be done from HV side. He suggested to take the matter to CEA for any
 ^^vf^^-ml f # H| l , ; , , 1 , ^ j.

Annexure-XXXII 558
ifi*

^^^stry of Power

^^ntral Electricity A^thority

w^^ usi4l U t^^^ta
Power System Planning & Apprrisa^ Dhrtsto

Chief Engineer (PD&C),

Haryana Vidyut Prasaran Nigam Limited
Shakti Bhawan, Sector-6
MM Panchkula (Haryana) -134109

^PTO /Subject*. HVPNL's proposal for replacement of various existing conductors (Le. wolf/
panther/ zebra/ moose) with equivalent HTLS conductor to reduce the
overloading of existing transmission lines

^/Reference: HVFNLletterno. Gh^8/HSS-3^lAfoMII dated 11.12,2023

In view of the exponential growth in the power demand in Haryana^ HVFNL vide letters
dated 25.08^023 and 13,09:2023 had proposed: reeonduetoring of 32 nos. of existing
transmission lines witifci eq^ivalent HTLS conductors in die areas where erection of new
transmission lines is not possible due to non-availability of RoW. Subsequently, CEA vide
letter dated 15.111023 concurred the HV^NI^s proposal for reeonduetoring ^f 28 no*, of
transmission lines and recommended HVFNL to review foe following recooductarmg

proposals of remaining 4 nos. oftransmission lines:

S.No. HVPNL^s proposal

Reeonduetoring of Badshahpur - Sohna 66 kV D/o line wifo HTLS conductor
1.
havmg current c^^rying capacityoT600 Amp, (Route lengfo-14.594 km)
Reeonduetoring of Kaifoal-Khanpur
n....^.,n:An ^^^VnU^.1 VI— 11^ 132 U\T
kV S/e
d/j% linewifo
U^m -nritU HTLS
HTT S conductor
PnTl^if having
currentcarrying capacity of 600 Anq?. (Route lengfo-16.52 km)

Reeonduetoring of Samaypur-Palli 220 kV D/c line wifo HTLS conductor having

3.
current carrying capacity of 1200 Amp (Route length- 9 km).
Creation of LILO of one circuit of 220 kV Nuna Majra * Daultabad D/c line wifo
4; HTLS conductor having ampadty of twin moose ACSR conductor (1262 amp^ at
4001 kV substatioh Bahadurgarh (EGCIL^ <approx. 2^1 krn^ alor^ wifo
al^mentation of existing conductor of same circuit which is being LILOed for foe
section from 220 kV substation Nuna Majra to foe LILO point wifo HTLS
conductor (Route lengfo-3.0i km)
 ^3)n
1/33929/2024

HVFNL vide letter under reference dated UJ^m has ^f^ ^f^f
requirement of reeonduetoring of above transmission lines. Further, comments were also
sought from GTXJIL and Grid-India on foe above proposal.

Based on foe justification fomished by HVFNL and comments of CTUIL and Grid-India, our
observations are as follows:^ 0 .., ,
(i) HVPNL's proposal for reeonduetoring of transmission lines at S. No. 1, l and i in me
above table seems to be generally in order.Xt a • •
(ii) Regarding foe proposal for reeonduetoring of transmission line at S.No. 4, it is to
mention that as present, 2 ckts already exist between Bahadurgarh and Nuna Majra and
3rt ckt would be created wifo LILQ of one circuit of220 kV Nuna Majra - Daultabad D/
o line whose recondcutoring has been proposed by HVPNL. As per foe present loading
and power flow studies, there does not seem to be need for reeonduetoring only one ckt
of Bahadurgarh - Nuna Majra 220 kV line. Reeonduetoring of foe same may be carried
out at a later stage based on the increase in loading in real time,
(iii) Along wifo reeonduetoring of the proposed lines, HVPNL may also ensure matching of
bay upgradation works associated with lines whose reeonduetoring has been proposed,
(iv) It has been observed that various intra-state lines and ICTs of HVFNL are not N-l
compliant Accordingly, HVFNL may plan necessary transmission system
strengthening works for the same.

I Yours faithfully,

Signed by Nitin Deswal

Date: 20-02-202410^6:57

^^finl
Copyto:(^^^^r/D^uty Director)

1. COOfOTUIL),SfliiHamini p)ptno.2^Sector 29 Gnm^.'Yja ' h

JJircctor (System ODMmHnn^ ar^ a /-</^>,ii^— j. • ... *' _\
\^^>wui v^^viouuu^, uuu ^ontroller of India^Lim
Qutab Institutional Area, Katwaria Sarai, New Delhi -110010' ^

;i
 Annexure-XXXIII
>• •

HVPN
HARYANA VIDYUT PRASARAN
NIGAM

DETAILED PROJECT
REPORT
Replacement of existing 0.15/0.2/AL-
59/0.4/0.5sq" ACSR conductors with
equivalent HTLS conductor of higher
current carrying capacity instate of
Haryana
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

Table of Contents

1BACKGROUND3-4
2JUSTIFICATION.„4-5

3PROJECT OBJECTIVES5-6
3.1Project Highlights...6
3.2Scope of Work...7

4TARGET BENEFICIARIES7-8
5PROJECT STRATEGY.......8

6LEGAL FRAMEWORK8
7ENVIRONMENTAL AND SOCIAL ASPECTS8
7.1Forest involvement / Clearance8

7.2Social Issues /R &R measures9

8TECHNICAL FEATURES 9-10

9MODE OF FINANCE AND PROJECT BUDGET10-11
9.1Project Cost Estimate10-11

9.2Basis of Cost Estimate11

9.3Physical Milestones of the project work11-12

9.4Financial Milestones of the project work12-13

10SUSTAINABILITY13
10.1Environmental Sustainability13-14

10.2Economic Sustainability14

10.3Social Sustainability14

11Spare parts Management System14-15

12Training of personnel15
13Annexure-I16

14Annexure-ll
 DETAILED PROJECT REPORT
^eplacement of various size of low current carrying capacity
hvIpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

1.a.Due
BACKGROUND
to exponential growth in power demand, the existing transmission lines are unable to

cater power demand in the various region of Haryana. The erection of new lines in these

regions is not feasible due to non-availability of RoW (Right of Way). Therefore, replacement

of existing ACSR conductors with equivalent HTLS conductor of higher current carrying
capacity is the only available option to reduce the overloading of existing lines and also to

improve the reliability with capability to cater the increased load demand in Haryana.

b.Various inter-utility meetings were conducted between the officers of HVPNL & DISCOMs
for integrated planning to review the district-wise distribution and transmission infrastructure

for the strengthening of power system in Haryana.

C. During the meetings, proposals for creation of new substation/augmentation of existing

substation and also erection of new transmission lines/ augmentation of existing

transmission line were discussed. It was decided in-principle that HVPNL may replace the
ACSR conductors of existing transmission lines with equivalent higher current capacity

HTLS conductors wherein erection of new transmission lines is not feasible due to non

availability of RoW (Right of Way).

d.Accordingly, various existing overloaded lines wherein erection of new tower/lines is not

feasible due to RoW issue were identified by the field offices of HVPNL & DISCOMs while
considering the various proposals for strengthening of power infrastructure of the area. The

detailed proposal were prepared area-wise and same was got approved from the WTDs of

concerned DISCOMs & HVPNL.

e.It has been observed that the designing of HTLS conductor depends a lot on the conductors

ageing effect on sag and tension, existing creep mitigation methods of the conductor and

the profile of existing Transmission lines. Therefore, all the works were packaged as per

existing size (type) of the conductor i.e. wolf, Panther, Zebra & Moose etc.

f.In view of the above, the following 3 no. packages have been prepared with overall

estimated cost of Rs. 290 crore (approx.):-

I.Package-A (Tentative estimate cost: Rs. 45.04 Crore) Augmentation works of 07 no.

Transmission lines with existing Wolf conductor to HTLS conductor.

II.Package-B (Tentative Estimate cost: Rs. 102.44 Crore). Augmentation works of 17 no.

Transmission lines with existing Panther and AL-59 conductor to HTLS conductor.
III. Package-C (Tentative estimate cost: Rs 114.73 crore). Augmentation works of 07 no.
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

Transmission lines with existing Zebra and Moose conductor to HTLS conductor,
g. The proposal of HVPNL for power system strengthening & improvement in Haryana by
replacement of existing ACSR conductors with equivalent HTLS conductor of higher current
carrying capacity was placed before the NRPC forum in its 68th meeting held on 18.08.2023
with request to recommend the proposal for 100% PSDF grant.

h. The proposal of HVPNL was deliberated at the NRPC forum and the decision of the forum is
reproduced as under:-

"Forum accorded in-principal approval to proposal of HVPN for replacement of

various size of ACSR conductor (i.e. wolf/panther/zebra/moose) with equivalent
HTLS conductor. HVPN was requested to approach CEA for technical evaluation
and accordingly, DPR for PSDF may be put up for approval of NRPC in upcoming
meetings."
i. Accordingly, detailed proposal for Replacement of existing 0.15/0.2/AL-59/0.4/0.5sq" ACSR

conductors with equivalent HTLS conductor of higher current carrying capacity in State of
Haryana was submitted to Central Electricity Authority (CEA) for their consideration &
recommendations.

j. Director/CEA vide their letter dated 15.11.2023 has conveyed that based on the peak loading
data, future load projections and the load flow studies submitted by HVPNL, proposal for re
eonduetoring of 28 no. existing Transmission lines as per Annexure-V have been found to
be generally in order. Further, regarding remaining 4 no. lines for reeonduetoring with HTLS

conductor CEA requested with HVPNL to review and submit proper justification for
requirement of reeonduetoring.

k. NRPC in its meeting held on 18.11.2023 approved a DPR for proposal of 28 no. lines to be

implemented by PSDF fund estimated cost of Rs. 225.99 Crores (Annexure-VI).

I. CEA vide letter dated 20.02.2024 considered the justification submitted by HVPNL regarding
proposal for reeonduetoring with HTLS of another 4 no. lines and given concurrence for the
3 no. lines (Annexure-VII).

ID. The estimated cost of the re-conductoring work of existing 3 no. Transmission lines

recommended by CEA as per letter dates 20.02.2024 comes to the tune of Rs. 40,78,96,771.
The detail estimate of same is placed at Annexure-I to III.

2. JUSTIFICATION
The replacement of ACSR (Aluminum Conductor Steel Reinforced) conductor with HTLS
(High-Temperature Low-Sag) conductor can be justified for catering to the growing power
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

demand in Haryana due to following reasons:-

a.Increased Capacity: HTLS conductors have a higher ampacity compared to ACSR
conductors. They can carry more current without overheating, allowing for increased

power transmission capacity. This is especially important in areas experiencing growing

power demand, as it enables the transmission of larger amounts of electricity without the

need for additional transmission lines.

b.Reduced Line Losses: HTLS conductors have lower electrical resistance compared to

ACSR conductors. This reduces the I2R losses, resulting in improved efficiency in power

transmission. By minimizing line losses, HTLS conductors help optimize the power
infrastructure and reduce energy wastage, leading to better utilization of available

resources.
c.Enhanced Reliability: HTLS conductors offer improved mechanical strength and reduced
sag compared to ACSR conductors. This enables them to withstand adverse weather

conditions such as high winds, ice, and heavy snowfall. By maintaining proper clearance

between conductors and minimizing the risk of line faults, HTLS conductors contribute to

a more reliable power supply, reducing downtime and enhancing the overall grid reliability.

d.Environmental Benefits: HTLS conductors enable power utilities to optimize the existing
transmission infrastructure, reducing the need for new transmission lines. This result in

lower land requirements and minimized environmental impact associated with the

construction of new power corridors.

3. PROJECT OBJECTIVES
a.The Replacement of Various Sizes of ACSR/AL-59 Conductor with Equivalent High-

Temperature Low Sag (HTLS) Conductor project in Haryana State is a critical

infrastructure initiative aimed at enhancing the efficiency and reliability of the state's power
transmission network. This project is driven by the need to modernize the existing

electrical grid, reduce transmission losses, improve the capacity to handle increasing

power demand, and promote sustainability through the deployment of advanced

technologies.
b.The scope of this project encompasses the replacement of traditional Aluminum

Conductor Steel Reinforced (ACSR) and Aluminum Conductor Alloy Reinforced (AL-59)
conductors with HTLS conductors across various transmission lines within Haryana State
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

due to exponential growth in power demand in the various regions of Haryana.

C. The erection of new lines in these regions is not feasible due to non-availability of RoW
(Right of Way). Therefore, replacement of existing ACSR conductors with equivalent HTLS
conductor of higher current carrying capacity is to reduce the overloading of existing lines
and also to improve the reliability with capability to cater the increased load demand in
Haryana.

d.The growing power demand in Haryana suggests that the demand will continue to increase

in the future. By replacing ACSR conductors with HTLS conductors, the power

infrastructure can be upgraded to handle the anticipated load growth. This proactive
approach ensures that the transmission lines can accommodate future demands without

requiring frequent replacements or significant modifications.

e.The Replacement of Various Sizes of ACSR/AL-59 Conductor with Equivalent HTLS

Conductor project in Haryana State is a strategic initiative aimed at improving the state's
power transmission infrastructure. By achieving the project objectives of increased

efficiency, capacity enhancement, and reduced maintenance, Haryana State is poised to

meet the growing energy demands of its citizens, support the integration of renewable
energy sources, and contribute to environmental sustainability. This project stands as a

testament to the state's commitment to delivering reliable and efficient power supply while
embracing advanced technologies in the energy sector.

3.1 PROJECT HIGHLIGHTS

Sr. Description of Projects Tentative Completion
No.
estimated schedule
cost (in INR)
1. Replacement of existing conductor 0.15 SQ'ACSR 12,69,55,496 12 Months
Conductor of 66 KV D/C line from 220 kV s/stn
Badshahpur -66 kV S/stn Sohna with HTLS
Conductor.
2. Augmentation of 132 kV Kaithal-Khanpur Line 12,08,57,583 12 Months
having 0.2 Sq" ACSR conductor with HTLS
conductor equivalent to 0.2 sq" ACSR conductor
3. Augmentation of 220 kV Samaypur-Palli line with 16,00,83,692 15 Months
0.4 sq" ACSR conductor to 0.4 sq" HTLS conductor
(1200 Amp)
Total 40,78,96,771
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvipn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

Note: NRPC in its meeting held on 18.11.2023 approved a DPR for proposal of 28 no. lines

to be implemented by PSDF fund.

3.2 SCOPE OF WORK

Since, the designing of HTLS conductor depends a lot on the conductors ageing effect on
sag and tension, existing creep mitigation methods of the conductor and the profile of

existing Transmission lines., Therefore, scope of works under the project to be

implemented by HVPNL have been categorized in 3 number packages as per existing size

(type) of the conductor i.e. wolf, Panther, AL-59, Zebra & Moose. CEA has given

recommendation for 28 no. vide letter dated 15.11.2023.

Now CEA vide letter dated 20.02.2024 has given the recommendation for reeonduetoring

of remaining 3 no. works of different size of conductor and same is as under:-.

I. Replacement of existing conductor 0.15 SQ'ACSR Conductor of 66 KV D/C line from

220 kV s/stn Badshahpur -66 kV S/stn Sohna with HTLS Conductor. (Tentative

estimated cost 12.69 cr. as Annexure "II")

II. Augmentation of 132 kV Kaithal-Khanpur Line having 0.2 Sq" ACSR conductor with
HTLS conductor equivalent to 0.2 sq" ACSR conductor. (Tentative estimated cost

12.08 cr. as Annexure "III")

III. Augmentation of 220 kV Samaypur-Palli line with 0.4 sq" ACSR conductor to 0.4
sq" HTLS conductor (1200 Amp). (Tentative estimated cost 16.00 cr. as

Annexure "IV").

4. TARGET BENEFECIARIES
The Replacement project works of existing Wolf, Panther, AL-59, Zebra & Moose conductor

with equivalent HTLS conductor of higher current capacity is to be implemented to meet the

growing power demand in view of the expansion of power system network and other

infrastructure. HTLS conductors enable power utilities to optimize the existing transmission

infrastructure, reducing the need for new transmission lines. This result in lower land

requirements and minimized environmental impact associated with the construction of new

power corridors.
Thus beneficiaries of the project would be all the citizen of Haryana state by supporting the
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

industrialization without impacting agriculture sector by reducing land requirement for new
power corridors.

5.PROJECT STRATEGY
HTLS conductors have a higher current carrying capacity compared to ACSR conductors.

They can carry more current without overheating, allowing for increased power transmission

capacity. This is especially important in areas experiencing growing power demand, as it

enables the transmission of larger amounts of electricity without the need for additional

transmission lines. Replacement project work would be executed on transmission lines of

Haryana State Transmission Utilities, wherein, existing conductor shall have to be replaced

with equivalent weight of HTLS conductor, which require shutdown of the transmission line
and sometimes addition of the tower in existing transmission lines may also be required for

interconnecting the existing transmission Lines/ substations for improving reliability.

It is necessary to strengthen the existing transmission line network between substations in

the State so as to handle the challenges posed by growing power demand in the absence of
Right of Way (ROW).

6.LEGAL FRAME WORK

It is proposed to execute the Replacement project works of existing Wolf, Panther, AL-59,

Zebra & Moose conductor with equivalent HTLS conductor of higher current capacity as per

provisions contained in the Indian Electricity Act, 2003 and the rules made there-under and
the Electricity (Supply)Act 1948, and subsequent amendments made thereof, so far as these
are applicable.

7.ENVIRONMENTAL AND SOCIAL ASPECTS

7.1 Forest involvement/ Clearance

The project for Implementation of Replacement project works of existing low current
carrying conductor with equivalent HTLS conductor of higher current capacity is to be
carried out on the existing transmission lines of HVPNL, therefore, separate clearance

for involvement of forest for any work related to the proposed work is not foreseen.
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

7.2 Social Issues/ R&R measures

Not foreseen, as the proposed scheme shall be established on the existing transmission

lines and the requirements of Social Issues/ R&R measures shall be taken care in

specific transmission line work if required.

8. TECHNICAL FEATURES
a.The physical and operating performance requirements of the transmission line with

HTLS conductor is complying with the specified requirements. Particulars of the

proposed conductor along with calculations to establish compliance with the specified
requirements is provided in the detailed specification.

b.The bidder shall indicate the technical particulars and details of the construction of
the HTLS conductor in the relevant schedule of GTP during bidding. The bidder shall
also guarantee the DC resistance of conductor at 20 deg C and AC resistance at the

calculated temperatures corresponding to 50Hz specified alternating current flow per

sub conductor at specified ambient conditions. The HTLS conductor (except GAP
Conductor) shall meet the following minimum requirements:-

Overall diameter of complete HTLS Not exceeding existing ACSR

conductor conductor overall diameter

Approx. mass of complete HTLS Less than or equal to weight of existing

conductor (kg/km) ACSR conductor(kg/km)
UTS/Weight ratio of HTLS Conductor Better than UTS/Weight ratio of
existing ACSR Conductors.

Direction of lay of outer layer Right Hand

Should be at least 15% less than that
DCResistance@20C and AC
of Existing ACSR Conductor
Resistance@75C
c.The bidder shall submit the supporting calculations for the AC resistance indicating
details & justifications of values of temperature coefficient of resistance & DC to AC

resistance conversion factor(s) with due reference to construction/ geometry of the

conductor.

d.The offered conductor/ equipment of relevant technology should be type tested for
each size, rating & assembly line. Test reports should not be more than seven years
old reckoned from the date of bid opening in respect of all the tests carried out in
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

accredited laboratories (based on ISO/IEC vide 25/17025 or EN 45001 by the National

accreditation body of the country where laboratory is located) or witnessed by HVPNL
or another electric power utility and shall be submitted by the Bidders.

e. The main materials required for the work of replacement are Hardware fittings,

conductor and earth wire. The accessories required are Split pin, suspension

assembly, suspension clamp, Preformed Armour Rods Set, armour grip suspension

clamp, dead end assembly, bolts, nuts and washers, Mid Span Compression Joint,

Repair Sleeve, Vibration dampers, Armour grip bundle spacers, spacer dampers.

All the materials to be used shall conform to the Indian/International Standards which
shall mean latest revisions, with amendments/ changes adopted and published, unless

specifically stated otherwise in the Specification.

The bidder shall also supply mandatory spares (approximately 5% of main items) as
specified in the BOQ of the project. The cost of mandatory spares would be included in
the bid evaluation.

9. MODE OF FINANCE AND PROJECT BUDGET

9.1 Project Cost Estimate: - Scope of works under the project to be

implemented by HVPNL have been categorized in 3 number packages as per

existing size (type) of the conductor i.e. wolf, Panther, AL-59, Zebra & Moose.

NRPC in its meeting held on 18.11.2023 has approved DPR for proposal of 28 no
lines to be implemented by PSDF fund. The remaining 3 no. works which is

recommended by CEA vide letter dated 20.02.2024 is as under:-

Sr.No. Description of Projects Tentative estimated Completion

cost(inlNR) schedule

1. Replacement of existing conductor 0.15 12,69,55,496 12 Months

SQ'ACSR Conductor of 66 KV D/C line
from 220 kV s/stn Badshahpur -66 kV
S/stn Sohna with HTLS Conductor (In
package-A).
2. Augmentation of 132 kV Kaithal-Khanpur 12,08,57,583 12 Months
Line having 0.2 Sq" ACSR conductor

10
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

with HTLS conductor equivalent to 0.2

sq" ACSR conductor (In package-B).

3. Augmentation of 220 kV Samaypur-Palli 16,00,83,692 15 Months

line with 0.4 sq" ACSR conductor to 0.4
sq" HTLS conductor (1200 Amp) (In
package-C).
Total 40,78,96,771

9.2 Basis Of Cost Estimate: - The basis taken into consideration for

the preparation of the estimate is as under:-

i. Rates of Civil Works are prepared by Civil design wing of HVPNL on the basis of

HSR.
ii. The annual price list is being prepared and circulated by HVPNL for the major
equipments; therefore rates for the items which are available in the latest rate list

of HVPNL have been taken.

The rates which are not available in rate list are taken from latest Purchase Orders
hi.

of the HVPNL.
The rates of HTLS conductor has been taken as per the lowest rates received from
IV.
the budgetary offers of its original manufacturers.
Transportation of material from site store to site work, insurance, storage charges/
V.
watch and ward, survey & stacking etc @ 5% of supply rate list items

VI. LabourCess @ 1% of Supply & Erection

vii. Administrative Charges @ 1% LabourCess

viii. Contractor premium @ 10% of Supply (only HVPNL rate list items)
ix. Contingencies & Incidental charges @ 5% total estimated cost of estimate.
The above cost estimate is inclusive of GST as funding for supply of equipment is
assumed to be done through domestic sources. F&l have also been considered

in the said estimate.

9.3 PHYSICAL MILESTONES OF THE PROJECT WORK:-

PERT CHART for 12 months (Package-A & B) and 15 months (Package-C) to execute the
project (including supply and erection) has been prepared as Annexure "VIII". However,
the time line of the salient milestones is as under: -
12 months PERT Chart
Sr. No. I Description of activity Timeline
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

i. Detailed Survey including route alignment & profiling 1st to 3rd month
ii. Supply of Stubs, Earthing, Towers & Gantaries 2nd to 7th month
iii. Casting of tower foundation 5th to 9th month
iv. Supply of HTLS conductor 5th to 9th month
V. Dismantlement & erection of towers 5th to 9th month
vi. Stringing & replacement of conductor 7th to 11th month
vii. Inspection by CEI 12th month
15 months PERT Chart
Sr. No. Description of activity Timeline
i. Detailed Survey including route alignment & profiling 2nd to 10th month
ii. Supply of Stubs, Earthing, Towers & Gantaries 2nd to 12th month
iii. Casting of tower foundation 3rd to 13th month
iv. Supply of HTLS conductor 4th to 13th month
V. Dismantlement & erection of towers 5th to 12th month
vi. Stringing & replacement of conductor 5th to 14th month
vii. Inspection by CEI 15th month

9.4 FINANCIAL MILESTONES OF THE PROJECT

WORK:-

Package "A" has already been awarded on 09.03.2024. NIT for Package "B" have already
been floated on 21.09.2023 respectively and NIT for Package "C" is also likely to be floated
by 31.05.2024. Package-A has already been awarded. Package-B likely to be awarded by
June 2024 and Package-C will be awarded by October 2024 with completion schedule of
12 months (Package-A & B) and 15 months (Package-C).

Tentative projection for the expenditure to be incurred on the project is as under: -

For package-A

Sr. Description Projection of Timeline

No. the considering April
expenditure (in 2024 as 1st month
% of project
cost)
1 10 % Advance to the EPC contractor 10% 1st month
2 Supply of Stubs, Earthing, Towers & 1% 2nd to 7th month
Gantries
3 Casting of tower foundation 2% 5* to 9th month
4 Supply of HTLS conductor 60% 5th to 9th month
5 Dismantlement & erection of towers 5% 5* to 9th month
6 Stringing & replacement of conductor 20% 7^10 11th month
7 Inspection by CEI 2% 12th month

For Package-B

Sr. Description Projection of Timeline

No. the considering July

12
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

expenditure (in 2024 as 1st month

% of project
cost)
10% 1st month
1 10 % Advance to the EPC contractor
2nd to 7th month
2 Supply of Stubs, Earthing, Towers & 1%
Gantries
5th to 9th month
3 Casting of tower foundation 2%
5th to 9th month
4 Supply of HTLS conductor 60%
5th to 9th month
5 Dismantlement & erection of towers 5%
7th to 11th month
6 Stringing & replacement of conductor 20%
2% 12th month
7 Inspection by CEI

For package-C
Sr. Description Projection of Timeline
the considering
No.
expenditure November 2024
(in % of project as 1st month
cost)
10% 1st month
1 10 % Advance to the EPC contractor
2nd to 12th month
2 Supply of Stubs, Earthing, Towers & 1%
Gantries
3rd to 13th month
3 r Casting of tower foundation 2%
4th to 13th month
4 Supply of HTLS conductor 60%
5th to 12th month
5 Dismantlement & erection of towers 5%
5th to 14th month
6 Stringing & replacement of conductor 20%
2% 15th month
7 Inspection by CEI

10. SUSTAINABILITY
The sustainability of High-Temperature Low-Sag (HTLS) conductors can be evaluated

from various perspectives, including environmental, economic, and social aspects. Here

are some considerations regarding the sustainability of HTLS conductors:

10.1 Environmental Sustainability:

i. Reduced Line Losses: HTLS conductors are designed to operate at higher

temperatures and carry more current, which can reduce line losses during electricity

transmission. This increased efficiency can lead to lower energy consumption and

reduced greenhouse gas emissions, contributing to environmental sustainability.

ii. Extended Service Life: HTLS conductors are built for durability and often have a
longer service life compared to traditional conductors. This can reduce the need for

frequent replacements and the associated environmental impact of manufacturing and

disposing of conductor materials.

 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

iii. Compatibility with Renewable Energy: HTLS conductors can support the integration
of renewable energy sources like wind and solar by enhancing the grid's capacity and

reliability, which is critical for transitioning to cleaner energy generation.

iv. Reduced Land Requirements: The low sag of HTLS conductors can lead to reduced

right-of-way requirements, minimizing the environmental impact of clearing land for

transmission line corridor.

10.2Economic Sustainability:
i. Efficiency Improvements: HTLS conductors' ability to reduce line losses and increase

power transmission capacity can lead to cost savings for utilities and consumers. This

economic sustainability can help justify the investment in upgrading transmission

infrastructure.

ii. Reduced Maintenance Costs: The longer service life and durability of HTLS
conductors can result in lower maintenance and replacement costs over time,

contributing to the economic sustainability of power transmission systems.

iii. Compatibility with Existing Infrastructure: HTLS conductors are designed to be

compatible with existing transmission infrastructure, which can reduce the overall cost
of upgrades and modernization.

10.3Social Sustainability:
i. Reliability: HTLS conductors' ability to maintain proper tension and low sag, even in

extreme conditions, can enhance the reliability of the electrical grid. This reliability is
essential for meeting the energy needs of communities and businesses.

ii. Reduced Outages: By reducing the risk of overheating and power outages, HTLS
conductors can contribute to social sustainability by ensuring a stable supply of
electricity for critical infrastructure, emergency services, and everyday life.

iii. Safety: HTLS conductors are designed with safety in mind, reducing the risk of
accidents such as conductor clashing with vegetation or other objects. This helps

protect both the environment and people living near transmission lines.

11. SPARE PARTS MANAGEMENT SYSTEM

a. The primary objective of spare part management system is to ensure timely availability of

proper spare parts for efficient maintenance of the transmission line without excessive

14
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

build-upon non-moving and slow moving inventory.

b.The main materials required for the work of replacement are Hardware fittings, conductor

and earth wire. The accessories required are Split pin, suspension assembly, suspension

clamp, Preformed Armour Rods Set, armour grip suspension clamp, dead end assembly,

bolts, nuts and washers, Mid Span Compression Joint, Repair Sleeve, Vibration dampers,

Armour grip bundle spacers, spacer dampers.

c.The main materials required for the work of replacement are Hardware fittings, conductor

and earth wire. The accessories required are Split pin, suspension assembly, suspension

clamp, Preformed Armour Rods Set, armour grip suspension clamp, dead end assembly,

bolts, nuts and washers, Mid Span Compression Joint, Repair Sleeve, Vibration dampers,

Armour grip bundle spacers, spacer dampers.

d.To ensure the supply of the quality materials in the project there would be provisions in the
contract that the offered materials of relevant technology should be type tested for each

size, rating & assembly line. Also all the materials to be used in the project shall conform
to the Indian/International Standards which shall mean latest revisions, with amendments/

changes adopted and published, unless specifically stated otherwise in the Specification.
e.To ensure availability of proper spare parts for efficient maintenance of the transmission

line there would be provision in the contract that the bidder shall also supply mandatory

spares (approximately 5% of main items) as specified in the BOQ of the project. The cost
of mandatory spares would be included in the bid evaluation

12. TRAINING OF PERSONNEL

The expertise available within the organization is required to be augmented to cater

maintenance of transmission line to be installed under the proposed project. Accordingly,

the training shall be imparted to the team of 3 Engineers (per line) nominated by the Nigam
have to be arranged at suppliers place and site which is considered essential under the

project.
 DETAILED PROJECT REPORT
Replacement of various size of low current carrying capacity
hvpn conductor with equivalent HTLS conductor of higher current
capacity in state of Haryana

ANNEXURE-I
List of 3 No. transmission lines for

reeonduetoring of HTLS recommended by

CEA
i. Replacement of existing conductor 0.15 SQ'ACSR Conductor of 66 KV D/C line from
220 kV s/stn Badshahpur -66 kV S/stn Sohna with HTLS Conductor (Part of package-
A).

ii. Augmentation of 132 kV Kaithal-Khanpur Line having 0.2 Sq" ACSR conductor with
HTLS conductor equivalent to 0.2 sq" ACSR conductor (Part of package-B).

iii. Augmentation of 220 kV Samaypur-Palli line with 0.4 sq" ACSR conductor to 0.4 sq"

HTLS conductor (1200 Amp) (Part of package-C).

16
 Une wise Estimated Cost for Package-AAnnexure-ll
Sr. No. Name of Line CM. Km Amount (In Rs.)

Augmentation of 66kV D/C Patwal-Mandkola with HTLS 22.372 94889505

Conductor equivalent to ACSR Wolf having current
capacity equivalent to 600 Amp on the existing towers
(Tentative D/C Route Length-11.186 KM)
Replacement of existing conductor 0.15 SQ'ACSR 29.188
Conductor of 66 KV D/C UNE FROM 220 KV S/STN
126955496
BADSHAHPUR -66 KV S/STN SOHNA with HTLS
Conductor.
(Tentative D/C Route Length-14.594 KM)
Replacement of existing conductor 0.15 SCTACSR
14.2 61487680
Conductor of 66 KV S/C LINE FROM 220 KV S/STN Palwa
-66 KV S/STN Hathin with HTLS Conductor
(Tentative S/C Route Length-14.2 KM)
Augmentation of 66kVS/C Badshahpur-Sector-35-Harsaru
10 63837730
line-provision of HTLS conductor of size 0.15 sq. inch
(having ampacity of 600Amp thereoff) alongwith raising of
height at some locations
(Tentative S/C Route Length-9.96 KM)
Augmentation of existing conductor 0.15 SCTACSR
5.75 26066799
Conductor on HSEB Towers of 132 KV S/C Khokrakot-
Sector-3 Rohtak Line with HTLS Conductor.
(Tentative S/C Route Length-5.75 KM)
Augmentation of conductor of 66 kV S/C Harsaru -
12.162 54600488
Farukhnagar line from 0.15 Sq. Inch ACSR conductor to
0.15 Sq. inch HTLS conductor having capacity of 600 amp
in FY 2022-23
(Tentative S/C Route Length-12.162 KM)

Replacement of 0.15 AAAC Conductor with HTLS from

4.8 22602613
LILO point to 66kV S/Stn of one circuit of 66kV Madanpur-
Barwala line with HTLS Conductor equivalent to 600 Amp
on the existing towers
(Tentative S/C Route Length-4.8 KM)
Total 98.472 450440311

Preaudited By Checked By

Xen/Contract
Replacement of existing conductor 0.1 S SQ'ACSR Conductor of S KV D/C LINE FROM 220 KV S/STN BADSHAHPUR -66 KV S/STN
SOHNA with HTLS Conductor.
(Tentative lennth of D/C line - 14.594KM)
UNIT Qty. Spares Total Qty. Unit price Total Rats taken from
S.N. DESCRIPTION
Budgetary offer
HTLS Conductor having-cuirent carryin^ from M/s Apar,
1 capacity of about 600 Amp size equivalent Km . 'm y 82.5^ '998280.00 / 92340900.00 M/s Steriite &
to ACSR Wolf conductor 7 M/sJsk
(CP-17)
A/F type Disc Insulator or Silicon Rubber
Polymer Insulator strings / / Y.
2 ZTQ/7 /)^oo.ao ^405000.00 Rate list dated
1) 70 kN No. 270/ y^Y 27.04.2023
i0 9OkN No. 252^ ' • ^^ / 252 YJ /}700.0( < . 428400.00 (CP-20)
Hardware Fittings of HTLS Conductor having current carrying / r *• '/ /.
(a) Single '1' Suspension String set 264> "Y^YI ^WA/t/ 9658.00 i^/^18892.00 PO REC-207
3 (b) Single suspension pilot string Set 6 / Y 1 ^ /Iff, Y/i^ss.oo // 22302.00 (CP-18)
(c) Single Tension string Set 228 J /31860.00 ^/^582680.00
^olsosoji ^ .,862344.00 PO REC-207
(d) Double Tension string Set 12 / (CP-18)
' - Y/ Y y /// 0.00

I
HTLS conductor accessories 59^ Y Y ^.62J(, ' ^/612.00 '/7/\ 711944.00
i) Mid Span Compression Joint No. PO REC-207
ii) Repair sleeves No. 18^ Y 1 <7 / 19^' / 3610.80 f/ 68605.20 (CP-18)
No. 936 J. - 40 J - 976 Y) 2548.$^ ' 2487628.80
iii) Vibration damper for conductor
Total of Supply 108528696.00 Y
Erection P!10% of Supply 10862869.60
DISMANTLEMENT WORK to be
Included In. Erection Part ofBOQ
Dismantlement of existing of 0.15sq* f Rate @5 % of
ACSR conductor complete with H/W Supply rate after
6 fittings. Insulators for above portion of line 29.188* updating with
Ckm. 8704.46 195689.89 CACMAIJuly
and their transportation proper stacking at
Dedicated 2023
Store of HVPNL. .(CP-21)
Dismantlement 195689.89 Y
Total (Eraction+Dismantlement
charges) 11048559.49
Total Rate list Items 833400.00 Y
Total Supply + Erection^ Dismantlement
119577255.49 /
Transporation of material from site
store to site work, insurance, storage
charges/ watch and ward, survey &
stacking etc 6 5% of supply rate list
terns 41670.00
LabourCess @ 1% of Supply.eraction
& Dismantlement 1195772.55 y
Administrative Charges g1% Labour
Cess 11957.73 y
Contractor premium <$10% of Supply
rate list items)
!
83340.00 yY
Total (Total estimated cost) 120909995.77 Y
Contingencies & Incidental charges 6
5% total estimated cost 6045499.79 /y
Gross Total Estimate 126955496 Y

Pre-Audlted By

AD^fe-audr
audit Xen/Contract
Sr.No. Name of Una (Package- B) CM. Km Amount (in Rs.)
••:{

Replacement of existing conductor 0.2 SQ" inch ACSR Conductor of 132KV Chormar- 24 136463600
Dabwall S/Ckt line with HTIS Conductor.
(Tentative S/C Route Ungth-24 KM)
Replacement of existing conductor 0.2 SQ" Inch ACSR Conductor of 132 KV Shahpur 55445296
Begu-Slrsa S/Ckt line with HTIS conductor
(Tentative S/C Route Length-9.5 KM)
f
Replacement of existing conductor 0.2 SQ" ACSR Conductor of 132 KV Jiwan Nagar • 14 78964593
Rania S/Ckt line with HTIS conducotr
(Tentative S/C Route Length-14 KM)
Augmentation of 66kV D/C A4-Ford line having 0.2 sq- Inch ACSR conductor with 0.2 1.4S 4393S04
sq. inch HTLS conductor having current capacity equivalent for 600 Amp on the Y
existing towers.
(Tentative D/C Route Length-1.45 KM)
Augmentation of 66kv D/C Palla-Sec-31, Faridabad line having 0.2 sq. Inch ACSR 6.1 48074968
conductor with 0.2 sq. Inch HTIS conductor having current capacity equivalent for
600 Amp on the existing towers
(Tentative D/C Route Length-3 KM)
Augmentation of existing 0.2 sq" AL-59 conductor on HSEB Design towers of 132 kV 1.4 10160688
Rohtak (220 kV) - Khorkrakot Rohtak.CKM
(Tentative S/C Route length-1.4 KM)
Augmentation of existing 0.2 sq" AL-59 conductor on HSEB Design towers of 132 kV 1.12 844385:
Rohtak (220 KV) - Khorkrakot Rohtak CKt-2
(Tentative S/C Route length-1.12 KM)
Augmentation of 132 kV Kaithal-Khanpur line having 0.2 Sq" ACSR conductor with 16.5 120857583
HTIS conductor equivalent to 0.2 sq" ACSR conductor
(Tentative S/C Route Length-16.52 KM)
Augmentation of existing 132 kV Nissing-Jalmana S/C 0.2 Sq" Inch ACSR line 6.5 39264324
Conductor with equivalent HTLS Conductor having ampacity 600A from 220 kV
NisslnguptoULOPoinL
(Tentative S/C Route Length-6.5 KM)
10 To replace the existing 0.2 sq" ACSR conductor of 132 kV S/C Isherwal-Behal Une with 19.51 109394286
0.2 sq'HTIS conductor
(Tentative S/C Route Length-19.5 KM)
11 Augmentation of existing 0.2 sq* ACSR conductor of 132 kV S/C ChhaJpur-ChandoU 48331746
line with HTLS conductor.
(Tentative S/C Route Ungth-8 KM)
12 Replacement of 0.2 sq" ACSR conductor of 132 kV S/C Bastara- Madhuban/ S.82 35162467
(Tentative S/C Route Length-5.821 KM)

13 Replacement of 0.2 sq" ACSR conductor of 132 kV S/C Kamal- Madhuban line with 12.06 69009004
high capacity conductor nearly equivalent to 0.4 sq Inch ACSR conductor
(Tentative S/C Route length-12.065 KM)
14 Augmentation of 0.2 Sq" AL-59 conductor of 132 kV S/C Nunamajra -MIE 11.15 69997703
Bahadurgarh Una with 0.2 sq Inch AL-59 qulvalent HTIS conductor having ampacity
600A
(Tentative S/C Route Length-11.15 KM)

teplacement of existing 0.2sq" Conductor of 132kV S/C line from 220kV Bapora- S.6 32278324
rosham One from U no. 69-92 with OPGW with HTLS conductor of equivalent size of
2Sq" conductor with current capacity equivalent to 0.4sq" ACSR Conductor
(600Amp).
(Tentative S/C Route Length-5.6 KM)
16 Replacement of ULO section of Narwana- Jind line at Uchana will be converted from 1.92 15807053
0.2sq" Conductor to 0.2sq" HTIS conductor of having current capacity equivalent to
60QAmp without replacement of towers
(Tentative S/C Route length-1.094 KM)
Replacement of existing conductor 0.2SQ" inch ACSR Conductor of 132 KV D/C 142383340
17
Nuhlyawali Khalrekan line with HITS conductor
(Tentative S/C Route Length-25 KM)
Total 169.63 1024432328

PreauditodBy

Xen/Contrect
 Augmentation of 132 kV Kaithal-Khanpur Line having 0.2 Sq" ACSR c
onductor with HTLS conductor equivalent to 0.2 sq" ACSR
conductor
(Tentative S/C Route Len pth-18.52 KM)
S.N DESCRIPTION UNIT Qty. Spares Total Unit pries
Qtv. (Including GST) Total Rate taken from

Fabrication and eupply of following tower As per latest rate

parts with stubs, bolts 6 nuts step bolts, list dt.
1 U Bolts hangers, D-ehakle etc of 27.04.2023 and
following deelgns updating the
samelEEMA
132kV D/C DB tvoe towers (KRR design) upto July 2023
No. 18 0 18 YY 524442.11 9439959.19 (CP-23)
Supply of earthing of towers /Gantry
2 I.) Dice tvoe sets 18 0 18 r 5858.92 101824.56
II) Counterpoise type sets 0 0 0 0
Supply of following Tower Accessories
i.) Danger plate No 18 0 18 Y 403.58 EPOD-79dt
7264.08
3 f.) Number plate No 18 0 18
Y
^^ Y
403.58
09.08.2022
(CP-17)
iii) Phase plate (set of 3) 7264.08
sets 18 0 18 • Y 403.58
iv) circuit plate (set of 2) 7264.08
sets 18 0 18 / / 403.58 7264.08
v) And dimbing device sets 18 0 18 Y 12391.11 223041.24
4 HTLS Conductor having current carrying Budgetary otter
capacity of about 600 Amp Km 50.05 2.5 52.55 1401840.00 73666692 from M/s Apar, M/s
StartaaSM/sJsk
(CP-17)
132 lev A/F type disc Insulator or 132kV
Silicon Rubber Polymer Insulator strings
5
ii) 90 kN No. y 2300 Rate List dated
108 0 108 248400 27.04.2023
Hardware Fittings of HTLS Conductor (CP^1)
having currant carrying capacity of about
600 Amp
6 (a) Sinqle 'I' Suspension Strin^ Y .
set 123 7 130^ Y 9558
Single Suspension 1242540
set 12 1 13 ^ ' ^ 3186
(b)Single Tension string Set 4141 PO REC-207
(Cj Double Tension string 252 13 265 // 31860
Set 8442900 (CP-19)
HTLS conductor accessories 30 2 32 <J ^ 61596 1971072
I) Mid Span Compression Joint for
7 conductor No. 34 2 36 -^ 27612
ii) Repair sleeves for conductor 994032
No. 10 PO REC-207
iii) Vibration damper for conductor 1 11/ / 3611 39711
No. 810 41 (CP-19)
Accessories for existing Earth wire size 851 „ 254E 2169021
7/2.50 mm '
S i) Earth wine Tension damp Y
No. 36 0 36 f ' 508
|l) Vibration Damper . No. 1827!
iii) Flexible copper bond 72 0 72 / / 508 POEPC-O-15
No. 18 36546
Total of Supply 0 18 / 520 (CP-18)
9362
Erection ©10% of Supply 98673863 ^—'
DISMANTLEMENT WORK to be Included In Erection Part ofBOQ 9867386 Y~
Dismantlement of existing of 0.15sq"
ACSR conductor complete with H/W
Rate ^5 % of
9 fittings, Insulators for above portion of line Ckm. Supply rate after
and their transportation proper stacking at 16.5 y 8615.70
Dedicated 142159 updating with
Store of HVPNL s CACMAl July,
Dismantlement
f 2023(CP-22)
_ )lvB Items 142151
1 10 Detailed Survey
Km.
Y
H Furnishing bore log date 17 0 17/ /18967.32
No. 17 322444
0 17 / 6322.44 107481
^onstruction of toww found^tions ss pw
HVPNL Drga & Specifications for 0 to 6Mtr.
12 axtn. including excavation, concreting, supply
and placement of steel reinforcement and 0 0 0
backfilling complete in all respect

13 132kV D/C DS type towers (KRR

esign) classified as 0 0
14 Wet Y 0
No. 18 0 18 / 187332.08
19 Preventive Measure 3371977
Brick masonry in 1:4 (cement sand) 0 0
22 0
mortar (HSR Ref.No. 7.21.1) Cum 1 0 '/ 4357.74 4358 As per Rates
 Obtained from
Earth fBkng including compaction, leveling / CM Design
1 0 1 / ^• 88.5 89
23 4 dressing etc. (HSR Ref.No. RM079 + Cum
3.1.2 + 4.32) Y
M-20 (1:1.5:8) concrete for top seal cover Cum 1 0 1( 5161.32 5161
24
Lean concrete (1:3:6) complete In al ^ 3434.96
1 0 1 3435
25 respect excluding centering and Cum
shuttering. (HSR Ref.No. 6.1.4)
Lean concrete (1:4:8) complete in al
/
2882 2682
26 respect excluding centering and Cum
shuttering. (HSR Ref.No. 6.1.6)
1 0
V s
RCC (1:1.5:8) including all material
labour, excavation, cutting and placing o
28 steel, centering 6 shuttering, concreting Cum 1 0
•/I 11591.14 11591
etc. complete In al respect.
Total Civil Charges 3829419 /
Total (Erection+Dismantlement +CMI 13838964 Y^
charges)
Total Rate list Items C983051f
Total Supply + Erecon+ 112512827 Y^
Dlsmantiement+Chrll
Transporation of material from sits
store to site work, insurance, storage
charges/ watch and ward, survey A ^1!52g
stacking sto 0 6% of supply rate list
items
Labour Csss 01% of Suppiy.snction 1125128 Y
& Dismantlement
Administrative Charges <$ 1% Labour 11251 y
Cess
Contractor premium 810% of Supply (9830^1 ^^3C
rate list Items)
Total (Total estimated cost) C11S1237M ll^\02160
Contingencies t, Incidental charges Q ^~5756ijl 575" 5" 13-3
5% total estimated cost
Sross Total Estimate L2.oftT7^X

Preauotad By Checked By

XeiVContract
 Annexure-IV
line whs Estimated Cost for Package-C Amount (In Rs.)
Name of Line CktKm
Sr. No. Augmentation of Conductor of 220 kV D/C Daultabad-IMT Manesar line with allied equipment along 35.12 316196979
1 with LILO of one circuit of Mid line at 220 kV Substation Sector-85, Gurugram from 0.4 sq" ACSR
conductor to 0.4 sq' HTLS conductor (Capacity 1200 A) in FY 2024-26.
(Tentative D/C Route Langth-17.56 KM)

Creation of one Ckt. of 220 kV D/C Dauttabad-IMT Manesar Line at 220 kV 4.78 14171788
Substation Sector-99, Gurugram (alternate to circuit which is LILO at Sector-85,
Gurugram) with 0.4 sq" HTLS Conductor (capacity 1200A) by using 220 kV
D/C/M/C/Monopoles towers as per requirement in FY 2024-25.
(Tentative D/C Route Length-2.39 KM)
Augmentation of existing 3 no 220kv S/C link between 400kV substation sector-72 0.24 5790410 Y
Gurgaon (PGCIL) & 220kV substation sector-72 Gurgaon (HVPNL) from single Moose
ACSR to Single HTLS conductor having current carrying capacity equivalent to twin
Moose conductor
(Tentative D/C Route Length-0.12 KM)
Augmentation of 220 kV D/C Sector-46-Palli line with 0.4 sq" ACSR conductor to 0.4 15.84 Yy
142788141 Yy
sq" HTLS conductor (1200 Amp) in FY 2023-24.
(Tentative D/C Route Length-7.92KM) 160083692
Augmentation of 220 kV Samaypur-Palli line with 0.4 sq" ACSR conductor to 0.4 sq* 18
HTLS conductor (1200 Amp) in FY 2023-24
(Tentative D/C Route Length-9.075 KM)
Replacement of existing 0.4sq* Conductor of 220kv D/C PGCIL (Khanpur)-Kaithal line 31.802 280987456
with HTLS conductor of equivalent size of Zebra conductor with current bearing
capacity of 1200A along with the replacement of existing insulators.
(Tentative D/C Route Length-15.901 KM)
/
Creation of LILO of one circuit of 220 kV Nuna Majra - daultabad D/C Line with HTLS 6.0 99767626
conductor equivalent to Zebra conductor having ampacity of twin moose ACSR
conductor (1262 amp) at 400 kV substation Bahadurgarh (PGCIL) approx. 2.0 kMs
(LILO point just outside 220 kV substation Nunamajra) along with augmentation of
existing conductor of same circuit which is being LILOed for the section from 220 kV
substation Nuna Majra to the LILO point (2L2830*)
(Tentative.Route Length of line tor LILO portion=2.906KM)
(Tentative Route Length of line for Nuna Majra-Daboda D/C line -0.596KM) '
(Tentative Route Length of line for Nuna Majra-Daultabad D/C line -0.302KM)

Total 111.782 I1147332181

udltedBy Checked By

AO/Pre-audlt
 Augmantetfon of 220 kV Samaypur-Palll tine with 0.4 aq" ACSR conductor to 0.4 aq- HTLS conductor (1200 Amp)
(Tentative D/C Route Lenpth-.075KM)
S.N. DESCRIPTION Unit price
UNIT oy. Spares Total Qty. Rate taken
(Including Total
r-JCTI from
1 HTLS Conductor of equivalent size of ACSR Panther
conductor with ampacity (1200 Amp) ' 2184120.00 Budgetary from
Km / *// 121190720 M/sApar, M/s
SteritteAMte
A/F type Disc Inautetor or Silicon Rubber Polymer JSK(CP-10)
Insulator strings
2 i) 70 kN /• /
No. 135^ '" 0 135 / Y/ 2500.00. r 337500
IQWkN
/ Rate List dated
Hardware Fittings of HTLS Conductor of sizs equivalent
to ACSR Panther conductor
No.
;
216^ 216/
3600.0^ ^ 777600
27.04.2023
(CP-15)
t
3
a) Single T Suspension String /Y /
b) Single suspension pilot string set 132-^ ' , 3 YT , 13SY 0
Set iY Yr \Y I ' * Y /, 16499.94
/ 16499.94 ' 2227492
c) Single Tension string
Set 192/ ^/8 > ' 196^^ ' ^. 6600C EPC-D-263(CP
(d) Double Tension string 40191.91 Y 7958012 14)
Set /- ^ / 50703.82 Y 709853
12 REC-227
HTLS conductor accessories ' ^? (CP-11)
Q Mid Span Compression Joint / / /^
No. 38^ "y/^ - ^Yj '^ 15336.6T ^, 562791
4 S) Reoair sleeves
ii) Vibration damper lor conductor No. 1D/i ^ / Yf , 11-^ ' 4230.76 EPC-D-283(CP
No. 672^ ri3/ 46539 14)
iv) Glow Platee fOr 220kV Towere 685 > 7 4230.78 ^ 2898087
total of Supply
No. */ / y/ 362.26 725 EP&tM5(CP-
*r
M
Erection 6)10% of SuddIv
DISMANTLEMENT WORK to be Included In
Erection Part of BOO
/ •^
t 136795319
13679532
^ 13)

Dismantlement of existing of ACSR Zebra conductor

0 complete with H/W fittings, Insulators for above portionfin^
of fne and their transportation and proper stacking at
Rate ©5% of
Ckm. .V Supply rate alter
any Dedicated 16431.1 295760
Store of HVPNL Y updating with
CACMAISep.,
Dismantlement 2023 (CP-17)
Total (Erection+Dismantlement charges) 295760. Y
total Rate list Kerns 13975292 ^,
Total Supply + Erections Dismantlement 1115100
Transporation of material from site store to site 150770611
work, insurance, storage charges/ watch and ward,
survey 6 stacking ate 0 6% of supply rate list Items

Labour Cess Q1%ofSupply,*rsction A 55755

Dismantlement
Administrative Charges 01* Labour Cess 1507706 y^
Contractor premium 0 10% of Supply (rate list 15077. y
items)
total (Total estimated cost) 111510 ^y
Contingencies & Incidental charges 6 5% <tal 152460659.
estimated cost
Cross Total Estimate 7623033
160063692
^/
 File No.CEA-PS.11.22(13)/1/2018-PSPA-l DlvlsltW 366
1631/2023

Govermneat of India

Ministry of Ptrw^f;^t
-iMtflU WJfl )^lwfftW>
Central Electric^ty Anthority
WSj^ UVUPh q|vi(4l t(t| IJJt^iM-t Hil'l ,
^ System Planning & Aobralsal-I Division

ChiefEngtoee^IPD&G),;. ,^• ^^ ^^ n f>' <•> :^:^'^r:'..'":

HatyanaVidyto;Prasaran;$liga5^^^to^^: ''::>'^/y':^J- iu'- ''.
;Shakti Bhawan, . • ';,.:. ,;. -•,: ''^yy^^yBY^'^

^^^^/Subjects'HVHC%f^, .

• ;ovedflsd^^^.fa^• '"'::" '^

tt^^/ Reference:
(i)- •'HW^^^#^^^i
:((ii)
ii> HV^l^too;^^^|2^|^^^ii^S^|.
^^^^^mst^^m^mss^^^ ^-^^^
(hi) ^^^\^m^^s^m^m^^$^p^Y^^.

j1t^)5'l/Sto' '^-Y "••;"<.: •^•*•••"^ ........y^, •..,...-....,

IItoesareuiutofc^ca!^^^
J! vide its';letters' und^ito^^^^^lto^l^^P^j^ '^••^^r^w^^^^^irtri-^fhe^ti^ti^^^^'flne5:'^s^^o^ •

SHVPNL's

for requir
loading .:' •*• •' • •
'^f-!*!f^^^'f^^fY'^m^'\,
^^^0f^^^0^T^s^m foe

loadtoK dati, future load projections and the load flow studies
0)' it^ ^hI, P™Psalir f6r reconductorin^ of following existing lines have

been found u> bo generally to order. %.,,

 S-.As

1/31631/20 HVPNL's proposal •••:/ ' :XYh • .'.. : •,, v --—-—_ZZ~]

51. No.
Reconductoring of Palival - Mandkola 66 kV B/o line with HTLSco^^ri
current canrying^|a^rif60(iAnto.
having eunentcag^tog^Ejdty of 600 Amp. (Route lengt^^l 1.186 kmV
length11.186 ltmj_^__ j
Reeonduetoring of Palwal - Uatliin
n.j..._^nfD.i,,,i^ Hathin.66 kV S/c line with WTLS
RAMS/c HTLS cnnHn^tkr
conductor ^..,:_
having~i
current carrying capacity of 600 Anip. (Route length-142 km)
VUU^1U WUU Vlll^^ ^u^u^itj t/i vvv w^. ^^
3, Reconducforing of Badshahpur-Sector 35-HarsaW ^i ^X S/c line with ^T^S.
cond^ctor having ciirrent carrying capacity of 60fl Amp along with ^ising of
height ht some locations. (Route l6ngth-9.^6 bn)
Reeonduetoring of Khokrakot-Sector 3 Rohtak 132 kV S/c line with HTLS
conductor having current carrying capacity of 600 Amp, (Route length-/7 ^m)
^-^,-^.., ..-. ...^. ...... ....j^rj,
RecohdiJCtoring_ of
Tv^^^i-j:.^^.:^. Harearu - T-.l.L..........
^rit... Farukhnagar 66wxrkV bl^
S/c I1^
line ....'.L.
with tt-pv
HTLS
c\ conductor
having ciirrent canytog Capacity of 600 Amp. (Route length-12.162 km)
d^4..^i..:_^ _<>_„.*;,..:* ..^trernv d^.^u ^ ^^r e/^ i:-- /•.^
Recoridiictortog of portion* of HSIIDC- Barwala 66 kV S/c line (creat^d aftlf
LILO of one circuit of Madanpur- Barwala 66 kV D/c line at HSIIDG) from
Barwala S/s upto the LILO point with HTLS conductor having current carrying
capacity of 600 Amp (Route length-4.8 km)
7. Reconductoring of Daultabad-SectorlO Gurugram 66 kV D/c line with HTLS
conductor having current canytog capacity of 600 Amp. (Route length-I (L5 km!
. -- -^ —.,,--^-o--r --J ~ --•'• V-...^uriu^lUU)
^ -' -. • ••'•••
Reeonduetoring of^ Chormar-
^*- . . . Dabwali
T-,^111 132-kV-S/c
1^^\ I If ^L 1*. -, HTLS^doiiductof
line with ^^ ^ ^ ^TTZ
having current carrying capacity of 600 Amp. (Route Iength-24 km)
9. Reeonduetoring of Shahpur Begu - Sir^a 132 kV S/c line with HTLS hoftductof
having current carrying capacity of 600 Amp. (Route length-9.S km)
10. Reeonduetoring of Jiwan Nagaf - Rania 132 kV S/c line with HTLS conductor
haying current carrying capacity of 600 Amp. (Route length-14 km)
11. Reconductoring of A4-Ford 66 kV D/c line with HTLS-conductor having current
carrying capacity of 600 Amp. (Route length-0.72 km)' '
12. Reconductoring. of Palla- ^aridabad Sector 31' 66 kV D/c line with HTLS
conductor having current carrying capacity of 600 Amp. (Route length-3 km)
13. Reconductoring of Rohtak >• Khorkrakot Rohtak 132 kV D/g line cki-1 with
HTLS conductor having current carrying capacity of 600 Amp. (Route length-
2.7 km) -:"
14. Rettohitoctortogto^I^h^^S^^with
h.^Routelength-
15. Reconductoring of portion* of Nissing-Jahnana, 132 kV^S/p line (which is to be
LILOed at Dacher)'with HTLS'conductor, having current carrying capacity of
^lcngth-6.5 km)
Behal 132 kV S/c line with HTLS conductor
„ _o -r-..y of 600 Amp. (Route lengch-19.5 km)
Reconductoring of Chhajpi^r-ChandoliJ32 kV S/c line with Ha^ conductor
havinggcurrent carrying capacity
n carrying capacity of
of 600
600 Amp.
Amp. (Route
(Route length
length -8
-8 fan)
fan)^
Reconductofinig of Bastara- Madhuban 132 kV S/c with HTLS conductor having J
S/ ih
currehtcartying capacity .of 600 Amp (Route length-5.821 Jan)
D.__j _^,• • —^ "' •^ '• ; " "^>^^>u^tv ^vuEm^J.04.1 ^mi . • ; : • :;::::• .-•
132 kV S/ i
20. -^--^-^^-l^J11^^UlC ICH
 * *

File No.CEA-PS-11-22(13)/1/20i9^PSPA-l Division 368

1/31631/202^
S1.NO. HVPNL's proposal
(Route lcngth-1.094 km)
Reconductoring of Nuhiyawali- Khalrekan 132 kV S/c line with HTLS
23.
conductor having current carrying capacity of 600 Amp (Route length-25 km)
Reconductoring of Daultabad-IMT Manesar 220 kV D/c Jine.along; with LILO of
24.
one circuit at 220 kV Substation Seotor-85, (Surogrem with HliLS conduct^*
having current carrying capacity of 1200 Afflplf RoUte'Iengfo-17:36ianX
Reconductoring of LILO portion* of LILO of 2nd circuit of Daultabad-IMT
Manesar 220 kV D/c line at 220 kV Substation Sector-99, Gurugram wifo HTLS
conductor having current carrying capacity Of 1200 Amp.( Route lengfo-2.39

km)
Reconductoring of Sector 72 Gurgaon (PGCIL),- Sector 72 Gurgaon (HVPNL)
26.
220 kV 3xS/c line with HTLS conductor having current carrying capacity
equivalent to Twin Moose conductor (Route length - 0.12 km)''
Reconductoring of Sector 46-Palli 220 kV D/c line with HTLS cohductor having
27.
current carrying capacity of 1200 Amp: (Route length-8.01 km)'
Reconductoring of PGCIL (Khanpur)-Kaifoal 220 kV D/c line with HTLS
28.
conductor having current carrying capacity of 1200 Amp along with the
replacement of existing insulators (Route length-15.9 km)
?Rasf of the line already .implemented/ under implementation with- high capacity

conductor-.-. . -

(ii) Regarding foe remaining proposals submitt^d-by HVPNL, as per foe load flow
studies, it has been observed thaf recOndMcforin^.of foe lines wifo HTLS conductor
may not be required. Therefore; .HVPNL is,req^ested to review,foe proposals or
submit proper justification for requirement offoe reconductoring offoe lines., Details
of foe proposals along wifo observations of CEA are enclosed as Annexure A.
(iii) Along wifo reconductoring of foe proposed lines, HVPNL may: also ensure matching
of bay upgradation works associated wifo lines whose reconductoring has been
proposed.• ' yI. ';'- '< l'-'\ Y> " < ';" "^l^ '*
(iv) It has been'observedthat--yaridus' Iiiira State lines" add iCTs of,]^Pl^E are *N-l'-non-
compliant. HVPNL may plan necessary trat^fo^ion systefo strengfoeforig -works for
foe same.'• "

Copy to:

1.COO (CTUIL), Saudamini,Plot no. 2, Sectof -29,^Qurgaon-122 0Q1

2.Director (System Operation), Grid Controller^ of Indfo iforited (Grid-India) B-9
 \^FIIeNo.CiA.GO1?^4(13)/1/2023-NRPC161
U32257/2^23 r ^*^
48* TCC & 7(f> NRPC Meeting (17-18 Nov 2023)-MoM

MOKIMHI

Minutes of
The 4^ meeting of Technical Coordination
Committee &
The 70th meeting of
Northern Regional Power Committee

Date: 17th & 18th November 2023

Time: 10:30 AM
^^' ^TVenue:LeMeridien Amritsar
J^nata Rd, Bal Schamler, Raja Sansi, Bal,
Amritsar, Punjab
 . "*.

Subject: 70th Northern RelotteN^PC lchiifcal

(NRPC) waseld Offfct1i2023"

Member Secretary

. V.

•| M(iftiiftJ0l0ilta^|iilAl^ei^^1^^
 ^
.. . ••>'•

FileNo.CEA-GO-17-14(13)/1/2023-NRPC 23^
1/32257/2023 48P TCC & 7<F NRPC Meeting (17-18 Nov 2023)-MoM

I Forum appreciated the initiative of RVPN for use of drone technology in tower

surveillance,
ii. RVPN was requested to do analysis on tower design and causes of its failure.

Replacement of various size of ACSR conductor (i.e.

A.31
wolf/panther/zebra/moose) with equivalent HTLS conductor to reduce the
overloading of existing transmission line thereby improving the reliability of

power system In Haryana (agenda by HVPN)

TCC Deliberation
A.31.1 EE (P) apprised that The HVPNL proposal for 31 No. existing overloaded
transmission lines for augmentation with HTLS conductor through PSDF funding was
discussed in 68th NRPC meeting held on 18.08.2023 for grant of PSDF wherein

following was decided:

Forum accorded In-principal approval to proposal of HVPN for replacement of

various size of ACSR conductor (I.e. wolf/panther/zebra/moose) with
equivalent HTLS conductor. HVPN was requested to approach CEA for
technical evaluation and accordingly, DPR for PSDF may be put up for

approval of NRPC In upcoming meetings.

A.31.2 Subsequently, the detailed proposal was submitted by HVPN to Central Electricity

Authority (CEA) vide letter dated 25.08.2023.

A.31.3 After detailed deliberations and meeting held on dated 15.09.2023, wherein CTU and
Grid India were also present, CEA concurred the proposal for augmentation with

HTLS conductor of 28 No transmission lines.

A/31.4 Accordingly, Detailed Project Report (Anrtttire-XVI) is placed for approval of

Forum.
A.31.5 MS, NRPC appreciated HVPN and encouraged states to come with such proposals.

from PSDF fund.

A.31.6 In concurrence to CEA, forum approved the DPR for proposal of 28 nos, of lines to

be implemented by PSDF fund and recommended to NRPC forum for approval.

NRPC Deliberation

Forum concurred the decision of the TCC forum.

Decision of NRPC Forum;

66
 1/32257/2023F"6 No<CEA'GO"17"14(13)/1/2023^RPC

48P TCC & 7CP NRPC Meeting (17-18 Nov 2023)-MoM

A.32.1 EE (P, apprised tha. in 23rd TeST sub-committee meeting held on 21.09 2023 issue
Iy T " 'CTS * TratlSmlS8lOn SUbSte^ - ^>- - ^^
A 32 2 I
A.32.2 n e meehng, was aubnr^ed
meehng, was aubnr^ ma, SEM installed a, 220KV feeder, should be taken

^:^?ydz
^:^yand z
purposs, of Ener9y. ,„ ^^e, meeting.
metera installed at LV side of ICTs may be taken for the
„ ^as decided foe. a separate mee^ ma I

held to discuss the issue of philosophy of Drawal points

^^ ^^T T was held on 13-10-2023 at NRPc

UP nnsed concern In calculation of enaw foss and stated that dmwal is

state s on the LV side of ICT which should be taken for the purpose of

to CEA —to reoulahen, 2005

*"

A.32.8

suggested to take the matter to CEA for any

67
 558

Government of India
fajfttswr
Ministry of Power
^(i
Central Electricity Authority
ui^^ siuiiMi iii4i^i ^i *^^ul*+.iinn'T
Power System Planning & Appraisal-I Division

Chief Engineer (PD&C),

Haryana Vidyut Prasaran Nigam Limited
Sbakti Bhawa^ Sector-6
Ml Panchkula (Haryana) -134109

^^^^ /Subject: HVPNL's proposal for replacement of various existing conductors (i.e. wolf/
panther/ zebra/ moose) wifo equivalent HTLS conductor to reduce foe
overloading of existing transmission lines

^/Reference: HVFNLletter no. Ch48/HSS-3?l/Vol-in dated 11.12.2023

In view of foe exponential growth in foe power demand in Haryana, HVPNL vide letters
dated 25.08.2023 and 13.09.2023 had proposed reconductoring of 32 nos. of existing
transmission tines wifo equivalent HTLS conductors in foe areas where erection of new i;
transmission lines is not possible due to non^vailability of RoW. Subsequently, CEA vide
letter dated 15.11.2023 concurred foe HVPNL's proposal for reconductoring of 28 nos. of
transmission tines and recommended HVPNL to review foe Mowing reconductoring
proposals of remaining 4 nos. of transmission tines:

S.No. HVPNL's proposal

1. Reconductoring of Badshahpur - Sohna 66 kV D/c line wifo HTLS conductor
having current carrying capacity of 600 Amp. (Route length-14.594 km)
Reconductoring of Kaithal-Khanpur 132 kV S/c line with HTLS conductor having
current carrying capacity of 600 Amp. (Route length-16.52 km)

3.
Reconductoring of Samaypur-Palli 220 kV D/c tine wifo HTLS conductor having
current carrying capacity of 1200 Amp (Route length—9 km).
Creation of LILO of one circuit of 220 kV Nuna Majra Daultabad D/c tine wifo
HTLS conductor having ampacity of twin moose ACSR conductor (1262 amp) at
400 kV substation Bahadurgarh (PGCIL) (approx. 2.0 kms) along wifo
augmentation of existing conductor of same circuit which is being LILOed for foe
section from 220 kV substation Nuna Majra to foe LILO point wifo HTLS
conductor (Route length-3.01 km)

Scnra Bhawan, fUtPuwH Nw DrtW-1 lOOSSTeltfMC 011.26102048 enurtl: ^^BdiBiiBl0anJtlBWbttte: w^w ^^m nlc.h
 File No.CEA^S-11-a2(13)/1/2(M9-PSPA4 Division
133929/2024

HVFNL vide letter under reference dated 1L12^Q23 has submitted ^e justifieatioa for
requirement of reconductoring of above fransmission lines. Further, comments were also

Based on foe justification furnished by HVPNL and comments of CTI^L and Gxw^ndia, our
observations are as follows:. . . ^
(i) HVPNL's proposal for reconductoring of transmission lines at S. No. 1,4m 4 m the
above table seems to be generally in order., .
(i^^ Regarding foe proposal for reconductoring of transmission line at S.No. 4, it is to
mention that as presort, 2 ckts already exist between Bahadurgarh and Nuna Majra and
3^^ ckt would be created wifo LILO of one circuit of 220 kV Nuna Majra - Daultabad D/
c line whose recondcutoring has been proposed by HVPNL. As per foe present loading
and power flow studies, there does not seem to be need for reconductoring only one ckt
of Bahadurgarh - Nuna Majra 220 kV line. Reconductoring of foe same may be carried
out at a later stage based on foe increase in loading in real time.
(iii) Along wifo reconductoring of foe proposed lines, HVPNL may also ensure matching of
bay upgradation works associated wifo lines whose reconductoring has been proposed
(iv) It has beat observed that various intra-state lines and ICTs of HVPNL are not N-l
compliant Accordingly, HVPNL may plan necessary transmission system
strengthening works for the same.

/ Yours faithfully,

Signed by Nilin Deswal

Date: 20-02-202410:56:57
son:
itin
Copy to: (<w m<wi* /Deputy Director)

1. COO (CTUIL), Saudamini, Plot no. 2, Sector -29, Qaqp^ls^^^^^^^^

m Director (System Operation), Grid Controller of Indw Limiiiliirid-India)
Qulah Institutional Are^KatwariaSaraLNewD^^i inniW'^^^mm^^**^-^
 Annexure-XXXIV

S. No. Task Name Total Scope Start Date Likely Partial Shutdown Complete Shutdown
Completion Apr'24 May'24 Jun'24
Unit Qty. Date
W-1 W-2 W-3 W-4 W-1 W-2 W-3 W-4 W-1 W-2 W-3 W-4
1 Work during Partial Shutdown Period (1st April 24 to 15th May 24 )
A. Balance work of BAFFLE WALL CONSTRUCTION AT
HPP – TRT OUTLET
1 Construction of approach road up to El.611.00m Rm 70.0 4/1/2024 4/20/2024 40 30
2 Upstream and downstream ramp construction Cum 2450 4/1/2024 5/15/2024 300 350 400 400 500 500
3 Drilling and Grouting at center portion of baffle wall Rm 280 4/1/2024 5/15/2024 45 45 45 45 45 55
4 Partial Micro piling work in front of 3A & 3B. Nos 58 4/1/2024 5/15/2024 18 22 18
5 Slope Protection work (Left Bank) Sqm 2640 4/1/2024 5/15/2024 440 440 440 440 440 440
6 Slope Protection work (Right Bank) Sqm 1110 4/1/2024 5/15/2024 185 185 185 185 185 185
B. Approach road construction PSP – TRT OUTLET
1 Construction of access road upto Baffle wall at EL Rm 90 4/15/2024 5/6/2024 30 30 30
603.0m.
C. a TRT OUTFALL – Cum 8000 4/1/2024 5/15/2024 1000 1000 1500 1500 1500 1500
Breaking of Flood Protection Wall upto EL 609.00m
b. Extension of raft (Upto EL 598.50m) Cum 450 4/15/2024 5/7/2024 200 250
C. Curtain Grouting from EL 598.00 m 4/24/2024 5/14/2024 200 200 200
2 Work during Complete Shutdown Period (16th May’24 to 30th June’24)
WORKS OF TRT OUTFALL

The entire dismantling of FPW from EL 609.00m to EL 1500 1500 4000 4000 4000 4000
1 Cum 19000 5/16/2024 6/30/2024
596.50m.
Extension of approach from baffle wall to flood protection 10 10
2 RM 20 5/16/2024 5/30/2024
wall at EL 598m.
3 Balance micro piling (200 Nos Approx.) Nos 70 5/25/2024 6/15/2024 22 24 24
4 Extension of raft (Upto EL 598.50m) Cum 650 5/16/2024 6/24/2024 200 250 200 200
Extension of U/s & D/s Guide wall up to river. (about 250 250 300
5 30m each from EL 598m to EL616m) Cum 800 5/16/2024 6/30/2024

Construction of access road at left bank, reaching up to 10 10 10 10 10 10

6 RM 60 5/16/2024 6/30/2024
the River bank
BAFFLE WALL,Construction of access road from El 470 500 500 500 500 500
7 603.0m to EL598.0m & RAMP CONSTRUCTION PSP – Cum 2970 5/16/2024 6/30/2024
TRT OUTLET
250 250 300
8 Concrete in U/S and D/s Guide wall extension Cum 800 6/8/2024 6/30/2024

9 Curtain Grouting from EL 598.00 m RM 1400 5/16/2024 6/30/2024 200 200 250 250 250 250
10 Slope Protection work (Left Bank) Sqm 2640 5/16/2024 6/30/2024 440 440 440 440 440 440
11 Slope Protection work (Right Bank) Sqm 1110 5/16/2024 6/30/2024 185 185 185 185 185 185
 Annexure-XXXV

RIVER JOINING WORKS

OF
TEHRI PSP (4x250 MW)
(Considering partial shutdown from 01.04.2024 to 15.05.2024 and
Complete shutdown from16.05.2024 to 30.06.2024)
 Why Partial & Complete shutdown is required?
➢Two nos baffle walls are required to be constructed to avoid the entry of debris etc in the
water conductor system of PSP from TRT side during Pumping Mode of operation. The
location of the proposed baffle wall is as below:
U/s of HPP TRT from EL.600.00m to El.607.00m.
U/s of PSP TRT from EL.597.00m to El.603.00m.
During operation of HPP & KHEP, the water level is generally above El.603.00m. Hence, the
above two nos Baffle wall cannot be constructed without partial & complete shutdown of
HPP & KHEP.
➢The adjacent rock condition of river valley near U/s of PSP TRT area is filled with loose
materials & required to be protected before operation of PSP. Further, the proposed
approach road for the treatment (left & right bank) is upto EL.597.00m. Hence, to
take up the work of slope protection with construction of approach road for baffle
wall & as well as for slope protection works, the proposed partial & complete
shutdown of HPP & KHEP is required.

• The existing Flood protection wall at PSP TRT outfall area (from El.616.00m to
El.597.00m) is required to be removed before operation of PSP and subsequently raft at
EL. 598.00m and U/s & D/s guide walls upto El.616.00m are required to be constructed.
 Requirement of partial & complete shutdown of Tehri HPP & KHEP
➢Partial Shutdown (THPP & KHEP): 1st April-24 to 14th May-24.
➢Complete Shutdown(THPP & KHEP): 15th May-24 to 30th Jun-24.
 Balance work of HPP TRT
baffle wall

River Dredging from u/s baffle wall

Slope Protection work to d/s baffle wall

Construction of
Baffle wall PSP-TRT Breaking Of Flood
Protection wall and
River Dredging from d/s Extension of Raft of TRT
baffle wall to further 250 m Outfall structure
d/s of PSP outfall

06-10-2023 Tehri - River Dredging, Baffle Wall, Flood Protection wall dismantling

4
 BAFFLE WALL CONSTRUCTION AT HPP – TRT OUTLET

5 06-10-2023 Tehri - River Dredging, Baffle Wall, Flood Protection wall dismantling
 Approach road construction PSP – TRT OUTLET

6 06-10-2023 Tehri - River Dredging, Baffle Wall, Flood Protection wall dismantling
 BAFFLE WALL & RAMP CONSTRUCTION PSP – TRT OUTLET

7 06-10-2023 Tehri - River Dredging, Baffle Wall, Flood Protection wall dismantling
 DISMANTLING OF Flood Protection Wall:

8 06-10-2023 Tehri - River Dredging, Baffle Wall, Flood Protection wall dismantling
Annexure-XXXVI
Annexure-XXXVII
 Annexure-XXXVIII

Grid Controller of India Limited

(A Govt. of India Enterprise)
(Formerly Power System Operation Corporation Limited)
National Load Despatch Centre

Date:28.07.2023

Grid-India Inputs regarding the time block to be considered for procurement of new ISTS IEM, AMR & MDP to be
implemented region wise in PAN India basis.

Ref: Email from NPC division of CEA dtd 25.07.2023

With reference to above, Input from Grid-India is as below:

1. CERC in Petition No. 07/SM/2018, in the matter of “Pilot Project on 05-Minute Scheduling, Metering, Accounting
and Settlement for Thermal/Hydro, and on Hydro as Fast Response Ancillary Services (FRAS)”, has given order on
16.07.2018(Attached as Annexure-1). Relevant part of the order is as follows:

Quote
……. All future procurements of Interface Energy Meters should ideally have recording at 5- min interval and frequency
resolution of 0.01 Hz. They should be capable of recording Voltage and Reactive Energy at every 5-min and should have
feature of auto-time synchronization through GPS…….
Unquote

2. CEA vide notification dated 23.12.2019 has notified Central Electricity Authority (Installation and Operation of
Meters) (Amendment) Regulations, 2019(Attached as Annexure-2). Relevant part of the Regulations is as follows
Quote

“under the Schedule Part II (Standards for interface meters), 1 b (viii),

…. Provided that the time block for recording of meter data by the meter shall be 15 minutes or as specified by the
Central Commission.”
Unquote

3. NPC (CEA) Joint Committee after due deliberation has finalised the "Technical Specification (TS) of Interface Energy
Meters, Automatic Meter Reading system and Meter Data Processing system” and notified the same on
06.12.2022(Attached as Annexure-3). Relevant part of the provisions covered in the Technical Specifications is as
follows:

Quote
“All the procured IEMs shall be configured as 5 min time block. These meters shall record and send 5 min block data to
regional AMR system. AMR system shall share [. npc] file of 5 min Time Block data to POSOCO through reliable
communication. MDP at its end shall do the necessary computation to convert 5 min Time Block data to 15 min Time
block data until complete replacement of 15 min existing IEMs with new 5 min IEMs.”
Unquote

4. Group constituted by Ministry of Power for “Development of Electricity Market in India” proposed comprehensive
solutions to address key issues, inter-alia, implementation of 5-minutes based metering, scheduling, dispatch, and
settlement in May 2023. (Attached as Annexure-4).

In view of above, 5 minute time block could be considered for procurement of new ISTS IEM, AMR & MDP.
FW: Letter to NPC- IEM Meters & Time Block Reg.
Sangita Sarkar {संगीता सरकार} <jana.sangita@powergrid.in>
Wed 02-08-2023 16:10
To:Rahul Kumar Shakya {} <rshakya@powergrid.in>

5 attachments (6 MB)
Grid-India Inputs regd time block of IEM AMR and MDP.pdf; Annexure-1 CERC-order-07SM2018 dtd
16.07.2018.pdf; Annexure-2-CEA (Installation and Operation of Meters) (Amendment) Regulations, 2019.pdf;
Annexure-3 NPC- Joint Committee_TS_CEA_6July-2022.pdf; Annexure-4 MOP-PressRelease.pdf;

Important.. Please file .

Regards

From: NPC CEA <cenpccea@gmail.com>

Sent: Monday, July 31, 2023 12:59 PM
To: Ashok Pal {अशोक पाल} <ashok@powergrid.in>; Nutan Mishra {नूतन िमश्रा}
<nutan@powergrid.in>; Sangita Sarkar {संगीता सरकार} <jana.sangita@powergrid.in>
Cc: sharan Rishika <rishika_sh@yahoo.com>; satyendra dotan <skdotan21@gmail.com>
Subject: Fwd: Letter to NPC- IEM Meters & Time Block Reg.

Sir,

With reference to the trailing email, the inputs received from GRID-India is forwarded herewith.

---------- Forwarded message ---------

From: Neeraj Kumar (नीरज कुमार) <neeraj.kumar@grid-india.in>
Date: Fri, 28 Jul 2023 at 18:00
Subject: RE: Letter to NPC- IEM Meters & Time Block Reg.
To: NPC CEA <cenpccea@gmail.com>, Vandana Singhal <cedpr-cea@gov.in>, sharan Rishika
<rishika_sh@yahoo.com>, satyendra dotan <skdotan21@gmail.com>
Cc: CMD - Grid-India(सीएमडी - िग्रड-इं िडया) <cmd@grid-india.in>, S. S. Barpanda (एस. एस. बरपंडा)
<ssbarpanda@grid-india.in>, R K Porwal (आर के पोरवाल) <rk.porwal@grid-india.in>, S. C.
Saxena (एस. सी. सक्सेना) <scsaxena@grid-india.in>, N Roy (एन रॉय) <nroy@grid-india.in>, R
Sutradhar (आर सूत्रधार) <rajibsutradhar@grid-india.in>, S P Kumar (एस पी कुमार) <spkumar@grid-
india.in>, V Balaji (वी बालाजी) <vbalaji@grid-india.in>, Amaresh Mallick (अमरेश मिल्लक)
<amareshmallick@grid-india.in>

Sir,

With reference to the trailing email from National Power Committee Division, Grid-India Inputs
on the captioned subject are attached herewith.

With Regards,

Neeraj Kumar

From: NPC CEA <cenpccea@gmail.com>

Sent: 25 July 2023 15:09
To: CMD - Grid-India(सीएमडी - िग्रड-इं िडया) <cmd@grid-india.in>; Vandana Singhal <cedpr-
cea@gov.in>; Neeraj Kumar (नीरज कुमार) <neeraj.kumar@grid-india.in>
Cc: sharan Rishika <rishika_sh@yahoo.com>; satyendra dotan <skdotan21@gmail.com>
Subject: Fwd: Letter to NPC- IEM Meters & Time Block Reg.

****Warning****
This email has not originated from Grid-India. Do not click on attachment or links unless
sender is reliable. Malware/ Viruses can be easily transmitted via email.

Sir,

The trailing email received from CTU regarding time block of ISTS IEM is
forwarded herewith wherein it has been requested to review the time block of
ISTM IEM (as per the Technical Specifications of IEM, AMR and MDP) in line
with the IEGC 2023 and CEA metering regulations. In this regard, it is
requested to provide the comments by 28.07.2023.
---------- Forwarded message ---------
From: Nutan Mishra {नूतन िमश्रा} <nutan@powergrid.in>
Date: Mon, 24 Jul 2023 at 18:55
Subject: Letter to NPC- IEM Meters & Time Block Reg.
To: Rishika Sharan <rishika@nic.in>, rishika sh <rishika_sh@yahoo.com>, cenpccea
<cenpccea@gmail.com>, Chief Engineer NPC <cenpc-cea@gov.in>
Cc: Ashok Kumar Rajput <akrajput@nic.in>, rajput ashok <rajput.ashok@gmail.com>, "Shilpa
Agarwal" <shilpa@cercind.gov.in>, "Awdhesh Kumar Yadav" <awdhesh@nic.in>,
memeberpscea@nic.in <memeberpscea@nic.in>, mserpc-power@nic.in <mserpc-
power@nic.in>, Satyanarayan S <ms-wrpc@nic.in>, mssrpc-ka@nic.in <mssrpc-ka@nic.in>,
ms-nerpc@nic.in <ms-nerpc@nic.in>, ms-nrpc@nic.in <ms-nrpc@nic.in>, S C Saxena
<scsaxena@posoco.in>, Vikram Singh Bhal {िवक्रम िसं ह भाल} <vsbhal@powergrid.in>, Sangita
Sarkar {संगीता सरकार} <jana.sangita@powergrid.in>, Ashok Pal {अशोक पाल}
<ashok@powergrid.in>, P C Garg {पी.सी. गगर्} <pcgarg@powergrid.in>

Dear Madam,

Pls find enclosed the letter regarding Time Block of ISTS IEM for kind review & advise for
further implementation.

Warm regards,

Nutan Mishra
Sr GM, CTUIL- POWERGRID
9873918449 (M)

दावात्याग : यह ईमेल पावरिग्रड के दावात्याग िनयम व शतोर्ं द्वारा शािसत है िजसे

http://apps.powergrid.in/Disclaimer.htm पर देखा जा सकता है। Disclaimer: This e-mail is governed
by the Disclaimer Terms & Conditions of POWERGRID which may be viewed at
http://apps.powergrid.in/Disclaimer.htm
--
Regards,

O/o Chief Engineer (National Power Committee Division)

Central Electricity Authority
Phone No: 011-26732014 / 9868021299
New Delhi - 110066.
Follow Grid-India on:

* This e-mail is an official email of Grid Controller of India Limited (Grid-India), is confidential and intended to
use by the addressee only. If the message is received by anyone other than the addressee, please return the
message to the sender by replying to it and then delete the message from your computer. Internet e-mails are
not necessarily secure. The Grid Controller of India Limited (Grid-India) does not accept responsibility for
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transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening
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considers appropriate. Visit our website at www.posoco.in *

--
Regards,

O/o Chief Engineer (National Power Committee Division)

Central Electricity Authority
Phone No: 011-26732014 / 9868021299
New Delhi - 110066.
 Annexure-XXXIX

From: "Vandana Singhal" <cedpr-cea@gov.in>

To: cenpccea@gmail.com, secy@cercin.gov.in, "Awdhesh Kumar Yadav"
<chiefengg@cercind.gov.in>, cmd@grid-india.in
Sent: Tuesday, August 8, 2023 12:49:03 PM
Subject: Letter to NPC- IEM Meters & Time Block Reg.

This in reference to the Time Block of ISTS Interface Energy Meters in which CTU has raised a problem
of mismatch between CEA ( Installation and Operation of Meters) regulations, 2019 and Technical
Specification for ISTS Metering System prepared by Joint commission (Nov' 2020) under NPC. In light
of this, a meeting has been scheduled on 18 August 2023 at 11:00 AM in Room No: 628, 6th
floor, Sewa Bhawan, Sector 1, R K Puram, New Delhi 110066.

You are requested to nominate a person well versed with subject to attend the meeting. Further,
documents related to above pertaining matter is attached for your reference.

Regards,
Vandana Singhal,
Chief Engineer(Distribution Policy and Regulatory Division),
Central Electricity Authority
Ph: 011-26732661
Fax: 011-26102793
 Annexure-XXXX

Transmission scheme for evacuation of power from Ratle HEP (850MW)

Description of Transmission Element Scope of work
Sl. (Type of
No. Substation/Conductor
capacity/km/no. of bays
etc.)
1 400 kV Kishenpur-Samba D/c line (Quad) Length -35 km (Quad)

(only one circuit is to be terminated at Kishenpur while

second circuit would be connected to bypassed circuit of
400kV Kishtwar – Kishenpur line (Quad))
2 Bypassing of one ckt of 400kV Kishtwar – Kishenpur 400kV
D/c line (Quad) at Kishenpur and connecting it with one of
the circuit of Kishenpur-Samba 400kV D/c line(Quad), thus
forming 400kV Kishtwar - Samba (Quad) direct line (one
ckt)
3 1x80 MVAr Switchable line reactor at Samba end of 400kV • 420 kV, 80 MVAr
Kishtwar-Samba 400kV line-165km (Quad) [formed after switchable line reactors at
bypassing of 400kV Kishtwar – Kishenpur line (Quad) at Samba S/s end– 1 nos.
Kishenpur and connecting it with one of the circuit of
Kishenpur-Samba 400kV D/c line(Quad))
• Switching equipment for
420kV, 80 MVAr
switchable line reactors at
Samba S/s end – 1 no
4 Bypassing both ckts of 400kV Kishenpur – Samba D/c line
(Twin) & 400 kV Samba – Jalandhar D/c line (Twin) at
Samba and connecting them together to form 400kV
Kishenpur– Jalandhar D/c direct line (Twin)
5 Bays upgradation works (2000A to 3150A) at Samba end 400kV Bay upgradation
(bays vacated after bypassing of Kishenpur – Samba D/c works- 4 nos. bays
line (Twin) & 400 kV Samba – Jalandhar D/c line (Twin))
6 1x63 MVAr Switchable line reactor on each ckt at Jallandhar • 420 kV, 63 MVAr
end of Kishenpur– Jalandhar D/c direct line -170km(Twin) switchable line reactors at
(formed after bypassing both ckts of 400kV Kishenpur – Jallandhar S/s end– 2 nos.
Samba D/c line (Twin) & 400 kV Samba – Jalandhar D/c
line (Twin) at Samba and connecting them together to form
• Switching equipment for
Kishenpur– Jalandhar D/c direct line (Twin))
420kV, 63 MVAr
switchable line reactors at
Jallandhar S/s end – 2 no
7 400kV Samba- Jalandhar D/c line(Quad) Line Length -135 km

(only one circuit is to be terminated at Jalandhar while

second circuit would be connected to bypassed circuit of
Jalandhar –Nakodar 400kV D/c line)
8 1x80 MVAr Switchable line reactor at Samba end of Samba • 420 kV, 80 MVAr
–Nakodar direct line (Quad) formed after bypassing of switchable line reactors at
400kV Jalandhar – Nakodar line-177km (Quad) at Samba S/s end– 1 no.
Jalandhar and connecting it with one of the circuit of • Switching equipment for
Samba-Jalandhar 400kV D/c line(Quad Moose), thus
420kV, 80 MVAr
forming Samba –Nakodar line (Quad)
switchable line reactors at
Samba S/s end – 1 no.
9 Bypassing 400kV Jalandhar – Nakodar line (Quad) at
Jalandhar and connecting it with one of the circuit of
Samba-Jalandhar 400kV D/c line(Quad Moose), thus
forming 400kV Samba –Nakodar line
10 LILO of 400 kV Kishenpur- Dulhasti line (Twin) at Kishtwar LILO Length- 10km
S/s along with associated bays at Kishtwar S/s • 400kV Kishenpur -
Kishtwar (LILO section) is
on Twin HTLS (with
minimum 2100 MVA
capacity) configuration
• 400kV Dulhasti -Kishtwar
(LILO section) is on Twin
Zebra configuration
• 400kV line bays at
Kishtwar – 2 nos. (line
bays at Kishtwar S/s end
shall be rated accordingly)
11 Reconductoring of 400 kV Kishenpur-Kishtwar section** Length – 132km
with Twin HTLS (minimum 2100 MVA capacity) (formed 400kV Bay upgradation
after LILO of Kishenpur-Dulhasti line at Kishtwar S/s) along work- 1 no. bay at
with bay upgradation works (2000A to 3150A) at Kishenpur Kishenpur end
end for above line.
Annexure-XXXXI
 Annual Budget/ Expenditure for FY 2023-24 for NRPC
Annexure-XXXXII

Account Head Q1 Q2 Q3 Q4 Expenditure NRPC Fund Total

Expenditure Expenditure Expenditure upto Feb'24 FY 2023-24 Expenditure upto Feb'24
Salary 5,516,609 4,784,328 4,428,361 2,665,134 17,394,432
Rewards -2,817 2,817 73,817 0 73,817
Medical Treatment 114,694 205,613 310,705 263,501 894,513
Allowances 3,924,333 2,975,939 3,072,402 1,707,994 11,680,668

LTC 146,004 47,671 118,227 0 311,902

Taining 0 0 0 17,700 17,700
DTE 161,013 265,631 217,000 353,057 996,701

OE 402,130 1,161,534 7,869,559 5,345,481 14,761,004

RRT 0 0 0 416,812 416,812

Digital Equipment 24,445 140,457 81,915 51,711 298,528

Minor Works 0 0 0 0
Repair And Maintenance 33,350 206,816 496,981 6,396,373 7,133,520
Other Revenue Exp. 15,633 101,599 162,999 133,562 413,793

Machinery and Equipment 0 0 5,167,930 0 5,167,930

INFORMATION, COMPUTER TELECOMMUNICATIONS 0 622,512 2,396,823 0 3,019,335

Furniture and fixtures 0 0 0 0 0

Total 10,335,394 10,514,917 24,396,719 17,351,325 62,580,655
* Total Expediture for the FY 2023-24 is Rs. 6,25,80,655/- and NRPC received from NRLDC (for electricity and water charges share) Rs. 96,56,563. Hence total expenditure
for the FY 2023-24 is Rs. 5,29,24,092/-
Annexure-XXXXIII
 File No.CEA-GO-17-14(13)/1/2023-NRPC 260
I/33245/2024 th th
71 NRPC Meeting (27 September, 2023)–Agenda

S. Name of Period Contribution Payment Penalty

No. Constituent (FY) amount Paid Date Pending
(Rs)
1 HPSEB 2023-24 10,00,000 03.11.2023 10000
2 NTPC 2023-24 10,00,000 07.11.2023 10000
3 UJVNL 2023-24 10,00,000 17.11.2023 10000
4 UT of Ladakh 2023-24 10,00,000 05.12.2023 20000
5 JVVNL 2023-24 10,00,000 06.12.2023 20000
6 *Lanco Anpara 2023-24
Private Limited 10,00,000 08.12.2023 -
7 Renew Power 2023-24 10,00,000 14.12.2023 20000
Grand Total 90,000
*Due to restructuring of company, demand letter not received by them. Demand letter was
again sent by NRPC Secretariate at new address of the company with payment date by
15.12.2023.
A.15.3 Recently, CAG audited at NRPC and observed the pending interest amount of
constituents towards NRPC contribution fund. The same is attached as Annexure-
XVIII.
A.15.4 Lanco Anpara Private Limited vide email dated 14.11.2023 informed NRPC
Secretariat that due to management change, there was delay in receipt of demand
letter. It requested for revised demand letter and accordingly revised demand letter
with due date of 15.12.2023 was sent from NRPC Secretariat.
A.15.5 Further, it is also to mention that UT of J&K and MVVNL have not paid the
contribution amount till date. Details of pending amount along with applicable penalty
is mentioned below:

S. No. Name of Period Contribution Penalty Total

Constituent (FY) amount (Rs) Outstandin
g amount
1 Madhyanchal
Vidyut Vitaran
Nigam Ltd. 2023-24 10,00,000 30000 10,30,000
2 UT of J&K 2023-24 10,00,000 30000 10,30,000

Decision required from Forum:

Forum may deliberate the above issue and facilitate contribution towards NRPC fund
from the concerned utilities.

A.16 Outstanding Contribution from constituent member J&K (agenda by NRPC

Secretariat)

i
 File No.CEA-GO-17-14(13)/1/2023-NRPC 261
I/33245/2024 th th
71 NRPC Meeting (27 September, 2023)–Agenda

A.16.1 NRPC Secretariat has been receiving contribution from most of the constituents in a
timely manner except few members. Since FY 2021-22, there has also been
provision of penalty of 1% simple interest per month on late payment as decided in
NRPC meeting.
A.16.2 It is informed that till JKPDCL and JKPDD have pending membership payments of
32 lakhs and 22.5 lakhs respectively, details of which are mentioned below:

S. Name of Period Outstanding Penalty Total

No. Constituent (FY) amount (Rs.) (Rs) outstandin
g amount
(Rs.)
1 J&K State Power 2014-15 11,00,000 - 11,00,000
2 Development 2015-16 11,00,000 - 11,00,000
3 Corp. Ltd. 2018-19 10,00,000 - 10,00,000
4 J&K State Power 2019-20 10,00,000 - 10,00,000
5 Development 2021-22 10,00,000 2,50,000 12,50,000
Department
Grand Total 54,50,000

A.16.3 In this regard, pending payment status was discussed in various meetings and
several reminders and D.O. letters have also been communicated by NRPC
Secretariat (copy enclosed as Annexure-XIX), however above payment is pending
till date.
A.16.4 CAG in its audit of NRPC fund, has also raised concern over late and delayed
payments to NRPC fund for the past Financial Years. It has mentioned that this is
resulting in loss of recurring interest.

Decision required from Forum:

Forum may suggest appropriate measures for timely payments to NRPC fund and
direct J&K to clear all outstanding dues towards NRPC membership.
******

i
 REMII{DtrR
D.o No. NRPCIASA,IRPCFUND/ z0tg-20 (
frZl Dated: ?.8 tOU2020
."*I
s( NI Rti L\
to my D.o. letter of even number dated 31rr october,207g
Please refer
regarding
payment of membership fee to the Northern R-egional power committee
(NRpc) by the
constituent members r:f NRPC for the financial yeas 20lg-20,201g-tg
and 2016-17 for meeting
the annual expenditure of NRpC establishment.

2' In this regard I would like to mention that previously the

amount of annual membership
fee to be paid to the NRPC by each constituent member
of the NRpc had been fixed as Rs. t 0
lakh' During the 45tl' NRPC meeting held recently on 0g.06.2019,
the amount of the annual
membership fees the financial year 20lg-20 also was
decided to be fixed as Rs.lo Lakh for each
constituent' NRPC Secretariat has already requested you vide
its letters of even number dated
3l'10'2019 for payment of the said contribution amounting to
Rs.27 Lakh for the above cited
financial years on urgent basis. The matter for payment of
the above contribution has also
discussed during the last few RPC meetings when Members
of the committee agreed to expedite
the said payment. Hourever, in spite of that the contribution
from your organ izationin respect of
the above cited financial years is still awaited.

3' Therefore, I shall be grateful if you could kindly intervene and

arrange to expedite the
amount of the aforesaid contribution amount of Rs.27 Lakh for
smooth running of the NRpC
Secretariat. The payment could be made either through Demand Draft,
drawn in favour of
"NRPC Fund" or through RTGS in the Bank account named '.NRpC Fund,, (Aic
No.
3083000105096078 RTGS / NEFT Code: ptrNB0308300).

R--#''^-n^EeL'\ /
Yours Sincerely,
.,11 . 1

Encl: As Above ll ,'l

,"" [' {--*u^f\{ | ")+}-*

(Naresh Bhandarri*8"
To,
Sh. M. Raju,
Secretary Power,
Power Development Department,
Civil Secretariat,
SRINA(iAR (J&K)

' l-
 ffi qTwvtrnT
ffi
qtqrffi
Ft-;:rTiq n?fi
Rw riTrv*
r\Rei*rRWqfrR
rfrfrTffiEqrnf,
18-q,
HEFq'SfuT fie-*ftmTKFT, ,rtfu-fr -1
10016
$\mq . 265 11211, 26513265

D.O No. NRPC/ASA,TRPCFUND

"t*,-^,,
/20t9_201 tggr.l
S( Ll.aA-{ Dated : j\ /t0t20tg
The mafter.::lt:t^, to pending
pa)'ment of membership
Power committee (Tlls]t". fee of the Norrhern Rc,gio'ar
rtr*r't.',r., i... 20t9-20.aoir-t9
annual expenditure of
NRPC
and 20t6_r7 fbr meeting the
pDD has notpuia
lakh for the vear 2018-19 "tt"iiirrtr"T. Nnnc membership fbe of Rs r7
and iotlil-t') Dur::rg +s* NniC
contribution amount rneeting herd on 08.06.20re.
was decided as Rs.l0 Laii rhe
paymentofRs2Tlakh_Rs ro, zoin]:0. Accordingr,i,. pDD
l0lakheachfor20lr_t,.ZOrr-ZOandRsTlakhfbr20 is ro make
l6-tT.lnthis
Secreta riat has .'nn,
ffi?::'"i ;Tf
-:[ilH:lJ:1.',:1il-PC un i.oted w ith your o r-nce. thc

I your {tind intervention.

seek
for clearance of afbresaid
basis. 'fhe payment contribution amount. on an
could be rnuO, it.ugh Demand n.ut Oru*n in
earry
The contribution can also favour of ..NRpC Fund.l,
be made through RTGS in
(A/c No' 3083000r 050e6078 the Bunk u""o,rnr named ..NRpc
nici i niit pUN80308300). Fund..

h.J ,zc D
"*e: t

Yours S incerelr .
Encl: As above rlr
/l
i ,'!

,J'
\+t.- ---..,''
l-r' "
v
,-],

,,

(l{aresh Bhandari)

To,,
Sh. Hirdesh Kumar, IAS
Secret ary power,
Power Development Department.
Civil Secretariat,
SRTNAGAR (J&K)

.il

;
 TTT(tr trcdF'r(

fgil {-{rd:{
enrt*fiqfr{TsfrR
18-9, tfl-SqfrilRfEqr{t,
m-r{rfurr {RTq, rr{ fufr - 1 1 oo 1 6

K{Irrq . 265 11211 , 26513265

D.O N O. NRPC/ASA{RPCFTJN D/20 Ii)-20 r ZZEJI

I Dated:3t ll}n0te
s^- l'UtA-e-rl,- L,*..,
The matter relates to pending payment of membership
f'ee of the Northern Regional
Power Committee (NRPC) for four years i.e.2019_20.20tg_19.201_s-16
and 201.+_15 for
meeting the annual expenditure of NRPC establishment.
PDCL has not paid NRpc mernbership
fbe of Rs 32 lakh for the year 2018-l g.2015-t5
and 20ll-15. During 4irh NRpc meeting held
on 08'06'2019. the contribution amount was deeided as
Rs.l0 Lakh fbr 20 l9-20.Acc.rdinglv.
PDCL is to make payment of Rs 42 lakh Rs l0
- lakh each fbr 20lg-19, 2019-20 and Rs I I lakh
each for 2015-16,2014-15. In this regard. I woulei
like to conveJ- thar NRPC Secretariat has
communicated with your office, the copies of communication
are enclosed.

I seek your kind intervention, for clearance of aforesaid contribution

amount. on an earl,r.
basis' The payment could be nrade through Demand Draft.
drar.vn in fbvour of ..NRpC FuncJ...
The contribrttion can also be made through RTCS in the Bank
accourrt name<l -'NRPC Furrcl..
(A/c No' 3083000 r05096078 RTGS / NEFT code: pL,NB0i0g300).

i^J,aq R** *). ,!

V
,/

Yours S incerelr,.
Encl: As above tA
l|l,l,' ;

f,\I _-t >--

7'!
,

(Naresh Bhandari)
/ ,

To,
Sh. Hirdesh Kumar. IAS
SecretaryPower,
I &, K State Power Development Corp. Ltd..
Shaw Inn, the Boulevard, !

SRTNAGAR-19000q (J&K)

t^
 REMII{DER
D -O l.{o. NRPC/ASA{RPCF[J}.{D/2 [tg -2ol
as€ Dated:.i6 lot/2020

S(, r\"{ Rt1-,

to my D.o. letter of even number dated 3lrr october,20lg
Please refer
payment of membership fee to the Northern regarding
Regional Power Committee (NRpc) by the
constituent members of NRPC for the financial
years 20lg-20, 20lg-lg, 2015-16 and 2014-15
for meeting the annuar expenditure of NRpc
establishment.
2' In this regard Lwould like to mention that previously
the amount of annual membership
fee to be paid to the NPoc by each constituent
member of the NRpc had been fixed as Rs.10
lakh' During the 45th NRPC meeting held recently on 0g.06.2019,
the amount of the annual
membership fees the financial year 20lg-20 also was
decided to be fixed as Rs.l0 Lakh for each
constituent' NRPC Secretariat has already requested you
vide its letters ofl.u.n number dated
3l'10'2019 forpayment of the said contribution amounting to
Rs.42 Lakh for the above cited
financial years on urgent basis. The matter for payment
of the above contribution has also
discussed during the last few RPC meetings when
Members of the committee agreed to expedite
the said payment. However, in spite of that the contribution from
your organ izationin respect of
the above cited financial years is still awaited.
t
3' Therefore, I shall be grateful if you could kindly intervene
and arrange to expedite the
amount of the aforesaid contribution amount of Rs.42 Lakh
for smooth **ing of the NRpC
Secretariat. The payment could be made either through Demand
Draft, drawn in favour of
"NRPC Fund" or through RTGS in the Bank aocount named ,,NRpC Fund,' (A/c
No.
3083000105096078 RTGS / NEFT Code: pLrNB0308300).

/
\-,-*v?L\ Yours Sincerely,
r'l
Encl: As Above .,,i / ,

;
lv I,J

(Naresh Bhandari) -?5: l"za}.c

To,
Sh. M. Raju,
Secretary Power,
J& K State Power Development Corp. Ltd.,
Shaw Inn, the Boulevard,
SRNAGAR-19000e (J&K)
 Annexure-XXXXIV

NRPC Fund Contribution F.Y. 2022-23 To be made till 31.03.2023

Date of
Sr. Name of the Contribution Penalty @ Amount
receipt Balance
No. Constitutents Member Amount 1% Received
in NRPC Fund
1 HPPTCL Shimla 04-04-2023 1000000 10000 1000000 10000
2 UT Chandigarh 10-04-2023 1000000 10000 1000000 10000
3 DTL 10-04-2023 1000000 10000 1000000 10000
4 HPGCL 13-04-2023 1000000 10000 1000000 10000
5 Adani Power Rajasthan 15-04-2023 1000000 10000 1000000 10000
6 Aravali Power Co.P.Ltd. 20-04-2023 1000000 10000 1000000 10000
7 NPCIL 26-04-2023 1000000 10000 1010000 0
8 NHPC Ltd. 26-04-2023 1000000 10000 1010000 0
9 UPPTCL 27-04-2023 1000000 10000 1000000 10000
10 Mahindra Susten Pvt. Ltd. 20-05-2023 1000000 20000 1020000 0
11 JKPDC 13-05-2023 1000000 20000 1010000 10000
12 HPSEB 30-05-2023 1000000 20000 1010000 10000
Ajmer Vidyut
13 20-06-2023 1000000 30000 1000000 30000
Vitran Nigam Ltd.
14 Dakshinanchal 08-08-2023 1000000 50000 1050000 0
230000 120000
 NRPC Fund Contribution F.Y. 2021-22 To be made till 14.11.2021

Sr. Name of the Date of receipt Contribution

Penalty @ 1% Amount Received Balance
No. Constitutents Member in NRPC Fund Amount

1 UPRVUNL 17-11-2021 1000000 10000 1000000 10000

2 JSW Hydro 17-11-2021 1000000 10000 1000000 10000
3 CTU 23-11-2021 1000000 10000 1010000 0
4 THDC 25-11-2021 1000000 10000 1000000 10000
5 HVPNL 29-11-2021 1000000 10000 1000000 10000
6 RVUNL 08-12-2021 1000000 20000 1000000 20000
7 PITCUL 14-12-2021 1000000 20000 1010000 10000
8 PGCIL 28-12-2021 1000000 20000 1000000 20000
9 UPCL 28-12-2021 1000000 20000 1010000 10000
10 IPGCL 29-12-2021 1000000 20000 1000000 20000
11 HPSEB 21-12-2021 1000000 20000 1010000 10000
12 DTL 10-01-2022 1000000 30000 1000000 30000
13 DDL Tata Power 24-01-2022 1000000 30000 1000000 30000
14 Jaipur VVNL 25-01-2022 1000000 30000 1000000 30000
15 Dakshin Haryana Bijli 31-01-2022 1000000 30000 1000000 30000
16 PSPCL 31-01-2022 1000000 30000 1000000 30000
17 Greenko Group 31-01-2022 1000000 30000 1010000 20000
18 HPPTCL 01-02-2022 1000000 40000 1000000 40000
J&K State
19 02-02-2022 1000000 40000 1000000 40000
Power Development
20 HPGCL 03-02-2022 1000000 40000 1000000 40000
21 MVVNL 05-02-2022 1000000 40000 1000000 40000
510000 460000
 Annexure-XXXXV

NRPC Members for FY 2024-25

S. No. NRPC Member Category Remarks

1 Member (GO&D), CEA Member (Grid Operation & Distribution), -

Central Electricity Authority (CEA)
2 Member (PS), CEA Nodal Agency appointed by the -
Government of India for coordinating
cross-border power transactions
3 CTUIL Central Transmission Utility -
4 PGCIL Central Government owned Transmission -
Company
5 NLDC National Load Despatch Centre -
6 NRLDC Northern Regional Load Despatch Centre -
7 NTPC -
8 BBMB -
9 THDC -
Central Generating Company
10 SJVN -
11 NHPC -
12 NPCIL -
13 Delhi SLDC -
14 Haryana SLDC -
15 Rajasthan SLDC -
16 Uttar Pradesh SLDC State Load Despatch Centre -
17 Uttarakhand SLDC -
18 Punjab SLDC -
19 Himachal Pradesh SLDC -
20 DTL -
21 HVPNL -
22 RRVPNL -
23 UPPTCL State Transmission Utility -
24 PTCUL -
25 PSTCL -
26 HPPTCL -
27 IPGCL -
28 HPGCL -
29 RRVUNL -
State Generating Company
30 UPRVUNL -
31 UJVNL -
32 HPPCL -
33 PSPCL State Generating Company & State owned -
Distribution Company
34 UHBVN There are only 2 STATE DISCOMs DHBVN & UHBVN

35 Jodhpur Vidyut Vitran Jodhpur Vidyut Vitran Nigam Ltd. Comes after Jaipur
Nigam Ltd. Vidyut Vitran Nigam Ltd. as per alphabatic rotation.
There are 3 state DISCOMs Ajmer, Jaipur & Jodhpur.
State owned Distribution Company
36 Paschimanchal Vidyut (alphabetical rotaional basis/nominated by Paschimanchal Vidyut Vitaran Nigam Ltd. comes after
Vitaran Nigam Ltd. state govt.) MVVNL as per alphabatical rotation. There are 4 state
DISCOMs: Dakshinanchal, Madhyanchal,
Paschimanchal, Purvanchal.

37 UPCL UPCL is sole state DISCOM

38 HPSEB HPSEB is sole state DISCOM
39 Prayagraj Power -
Generation Co. Ltd.
40 Aravali Power Company -
Pvt. Ltd
41 Apraava Energy Private -
Limited
42 Talwandi Sabo Power Ltd. -
43 Nabha Power Limited -
44 Lanco Anpara Power Ltd IPP having more than 1000 MW installed -
45 Rosa Power Supply capacity -
Company Ltd
46 Lalitpur Power Generation -
Company Ltd
47 MEJA Urja Nigam Ltd. -
48 Adani Power Rajasthan -
Limited
49 JSW Energy Ltd. (KWHEP) -

50 TATA POWER IPP having less than 1000 MW installed TATA POWER RENEWABLE comes after RENEW
RENEWABLE capacity (alphabetical rotaional basis)
51 UT of J&K JKPCL has been considered.
From each of the Union Territories in the
region, a representative nominated by the
52 UT of Ladakh LPPD has been considered.
administration of the Union Territory
concerned out of the entities engaged in
53 UT of Chandigarh generation/ transmission/ distribution of Electricity Wing of Engineering Department,
electricity in the Union Territory. Chandigarh Administration

54 NPCL Private Distribution Company in region NPCL comes after BYPL. There are 4 private
(alphabetical rotaional basis) DISCOMs in NR i.e. BRPL, BYPL, NPCL and TPDDL.

55 Fatehgarh Bhadla Private transmission licensee (nominated by As nominated by CEA on alphabatical rotataional
Transmission Limited cetral govt.) basis.
56 NTPC Vidyut Vyapar Nigam Electricity Trader (nominated by central As nominated by CEA.
Ltd. govt.)
Annexure-XXXXVI