TANGEDCO vs The Secretary Central Electricity Regulatory Commission & Ors on 13 October 2026

JUDGEMENT

PER HON’BLE MR. AJAY TALEGAONKAR, TECHNICAL MEMBER

Background and Factual Matrix

1. Appeal Nos. 56 and 329 of 2018 are being considered together. In Appeal No. 56 of 2018, Tamil Nadu Generation and Distribution Corporation Limited (“TANGEDCO”) challenges the order dated 19.09.2017 passed by the Central Electricity Regulatory Commission (“Central Commission”/ “Respondent No. 1”/ “CERC”) in Petition No. 235/TT/2016 concerning transmission tariff for some assets forming part of the transmission scheme associated with the Coastal Energen Private Limited and Ind-Barath Power (Madras) Limited generation projects in the Tuticorin area.

2. In Appeal No. 329 of 2018, TANGEDCO has challenged the order dated 21.11.2017 passed by CERC in Petition No. 71/TT/2017 whereby CERC had determined tariff for some other assets forming part of the above mentioned transmission scheme.

3. The Appellant, TANGEDCO is a distribution licensee in the State of Tamil Nadu. Respondent No. 1 is CERC which passed the Impugned Orders.

Respondent No. 2 is Power Grid Corporation of India Limited (“PGCIL”) which implemented the transmission assets and filed the tariff petition before the Central Commission. Respondent Nos. 3 to 16 and 19 comprise transmission utilities, distribution companies and electricity departments in the Southern Region. Respondent Nos. 17 and 18 are Coastal Andhra Private Limited (“Coastal Energen”) and Ind-Barath Power (Madras) Limited (“Ind-Barath”), respectively. Respondent No. 20 is Central Transmission Utility of India Limited (“CTUIL”).

4. The common transmission system was discussed at the 29th and 30th meetings of the Standing Committee on Power System Planning held on 27.08.2009 and 13.04.2010. The title of the approved scheme indicates that scheme was primarily meant for evacuation of generation from generating stations owned by Coastal Energen and Ind-Barath. It comprised pooling stations at Tuticorin and Salem; the LILO of both circuits of the Tuticorin JV- Madurai 400 kV double-circuit line at Tuticorin; the Salem Pooling Station- Salem 400 kV double-circuit line; the Tuticorin-Salem 765 kV double-circuit and Salem-Madhugiri 765 kV single-circuit lines, both initially to be charged at 400 kV; and associated bays. Each generating company was to develop dedicated line from its switchyard to Tuticorin Pooling Station.

5. PGCIL, which at that point of time was also entrusted the role of CTU, granted long-term access (“LTA”) of 1,100 MW to Coastal Energen against its proposed 1,200 MW project and 900 MW to Ind-Barath against its proposed 1,320 MW project. Of the aggregate 2,000 MW LTA, 1,045 MW was indicated to remain in the Southern Region, while 550 MW and 405 MW was indicated to flow to the Western Region and Northern Region respectively.

6. TANGEDCO has pointed out that at a special meeting of the Southern Regional Power Committee on 25.11.2010, concerns were raised about transmission charges attributable to independent power producers whose beneficiaries had not been identified. PGCIL stated that the generators would bear the charges until firm beneficiaries were identified. TANGEDCO subsequently entered into a Power Purchase Agreement (PPA) for 558 MW with Coastal Energen.

7. The investment approval for the scheme was granted by PGCIL’s board of directors on 19.09.2011 while revised cost estimates were approved in 2017. TANGEDCO submitted that the project of Ind-Barath got abandoned and Coastal Energen’s dedicated evacuation line was not built until 29.07.2016; and beneficiaries for the balance capacity, other than 558 MW to Tamil Nadu, had not been firmed up.

8. By the Impugned Orders dated 19.09.2017 and 21.11.2017 in Petition Nos. 235/TT/2016 and 71/TT/2017, respectively, the Central Commission approved the commercial operation dates of the respective transmission assets as 13.11.2016 and 23.10.2016, and held that the associated transmission charges would be recovered through the Point of Connection (PoC) mechanism. Aggrieved thereby, TANGEDCO filed the present appeals.

9. The Appellant in Appeal No. 56 of 2018 has prayed for the following relief before us: “1. to set aside the order dated 19.09.17 passed by the Central Electricity Regulatory Commission in petition No. 235/TT/2016; and

2. pass any other order or orders as this Hon'ble Appellate Tribunal may deem fit and proper in the facts of the case.”

10. The Appellant in Appeal No. 329 of 2018 has prayed for the following relief before us: “1. to set aside the order dated 22/11/2017 passed by the Central Electricity Regulatory Commission in 71/TT/2017; and

2. pass any other order or orders as this Hon'ble Appellate Tribunal may deem fit and proper in the facts of the case.”

11. The common factual matrix is that the system was planned against aggregate LTA of 2,000 MW of Coastal Energen and Ind-Barath. TANGEDCO had a PPA for 558 MW with Coastal Energen while the balance capacity/ beneficiaries had not been firmed up. CERC’s Impugned orders in Petition Nos. 235/TT/2016 and 71/TT/2017 held that the respective assets were in use as part of the meshed network and directed recovery of their charges through the PoC mechanism.

Issues for Consideration

12. TANGEDCO in both the Appeals had raised several issues, however during the course of the hearing they pressed only the issues related to declaration of commercial operation and sharing of transmission charges. Accordingly, we have formulated the following issues for our consideration:

Issue 1: Whether the respective assets validly achieved COD under the 2014 Tariff Regulations? Issue 2: Whether the subject transmission assets could be included in the PoC mechanism and their charges recovered from DICs, despite substantial LTA remaining unutilised?

Our Analysis and Conclusions

13. We have heard the Learned Counsel for the Appellant and the Learned Counsel for the Respondents at length. We have also carefully considered

their respective submissions and the relevant material on record. Upon due consideration of the arguments advanced and the documents placed before us, we now proceed to analyse the issues arising for our consideration in the present Appeal.

Issue 1: Whether the respective assets validly achieved COD under the 2014 Tariff Regulations?

Submissions of the Appellant -TANGEDCO

14. PGCIL declared the Date of Commercial Operation (“DOCO” or “COD”) of the assets in Appeal Nos. 329 and 56 of 2018 as 23.10.2016 and 13.11.2016, respectively. The CERC approved these DOCO based on the RLDC certificate and the CEA clearance certificate.

15. TANGEDCO submitted that these technical certificates alone do not satisfy Regulation 4(3)(ii) read with Regulations 12(1) and 12(2) of the 2014 Tariff Regulations in view of the facts of the case. The contention is that in accordance with Regulations, DOCO could not have been declared without beneficial use of the asset.

16. Reliance is placed on Appeal No. 123 of 2011 for the proposition that a transmission asset can attain commercial operation only when it is put to its intended beneficial use. Since one generating project did not get commissioned, the other only had LTA to the extent of 558 MW, no external beneficiaries were identified and the planned connectivity was incomplete, the concerned assets could not be regarded as operational for their intended purpose.

17. TANGEDCO also relied upon the order dated 15.09.2025 in Appeal Nos. 206 and 332 of 2017, to contend that a DIC (Designated ISTS Customer) cannot be saddled with charges for an asset from which it derives

no corresponding benefit, especially where the asset cannot be utilised as intended. An artificial DOCO, it submitted, cannot be used to impose PoC liability upon DISCOMs.

18. It sought a declaration that DOCO was not validly achieved for want of intended beneficial use, with transmission-charge liability for untied LTA remaining upon the defaulting generators rather than existing DICs.

Submissions of the Respondent No. 2 - PGCIL

19. Respondent No. 2 submitted that the assets were completed in accordance with the applicable Tariff Regulations and that TANGEDCO’s admitted drawal of 558 MW from Coastal Energen through the system established actual use from commissioning. The approval of COD is therefore justified.

20. Respondent No. 2 contended that the RLDC charging certificate and CEA clearance were only corroborative material establishing regular service; they were neither the exclusive nor determinative basis of PGCIL’s declaration.

21. Respondent No. 2 further relied upon proviso (ii) to Regulation 4(3), which permits the transmission licensee to approach CERC for approval of COD where regular service is prevented for reasons not attributable to it, including delay in the concerned generating station or upstream/ downstream system. It submitted that Ind-Barath’s non-commissioning and abandonment, along with the right-of-way delays set out in the tariff petition, fall within that proviso. Thus, COD from 23.10.2016, as placed before and accepted by CERC, is stated to conform to Regulation 4(3).

22. Lastly, Respondent no. 2 distinguished Appeal No. 123 of 2011 pointing out that in that case the transmission line was not ready for use, whereas the present assets were completed, commissioned and used by TANGEDCO for drawal from Coastal Energen.

Submissions of the Respondent No. 20 - CTUIL

23. The transmission assets were, entrusted to PGCIL pursuant to CERC’s regulatory approval, in proceedings where TANGEDCO’s predecessor, TNEB, and other beneficiaries were parties. The approval was never challenged and has attained finality.

24. CTUIL approached the CERC vide Petition No. 233/2009 concerning the requirement for nine High Capacity Power Transmission Corridors, including the Corridor in issue. CERC had granted regulatory approval for the assets covered in the aforesaid petition vide Order dated 31.05.2010 noting that both IPPs had executed BPTAs, furnished Bank Guarantees and completed the requisite milestones for grant of LTA, except for the MoEF clearance in the case of Ind-Barath. In view of this it has been contended that submission of TANGEDCO that CTUIL or PGCIL proceeded without regard to the status of the generation projects or in disregard of the applicable regulatory requirements is unfounded.

25. It has been contended that CTUIL had, from the outset, sought a stronger performance-security mechanism, submitting that the then bank guarantee of about ₹10-15 lakh/MW or ₹5 lakh/MW was inadequate to protect developers and beneficiaries in implementing the identified high- capacity transmission corridors. However, CERC did not issue such a direction.

26. CERC correctly declared COD under the 2014 Tariff Regulations. Inclusion of a commissioned ISTS asset in the PoC pool is only a consequential incident of COD under the Sharing Regulations, 2010 (Central Electricity Regulatory Commission (Sharing of inter-State Transmission Charges and Losses) Regulations, 2010). TANGEDCO has not shown how COD contravened any applicable law.

27. Reliance on PSPCL v. PGCIL, Appeal No. 123 of 2011, decided on 02.07.2012, is misplaced, as that judgment did not interpret the 2014 Tariff Regulations governing COD in the present case.

28. Even assuming any lapse by CTUIL in monitoring, it cannot deprive the transmission developer of tariff after commissioning, particularly where the system was developed under a final regulatory approval. In any event, CTUIL continuously monitored the projects through Joint Coordination Committee (“JCC”) meetings.

29. The JCC record relied upon by CTUIL shows:

• On 21.01.2015, Coastal Energen’s Unit 1 had achieved COD in December 2014; Unit 2 was expected by August-September 2015; its dedicated line and bays were expected by March 2016; and its Unit 1 PPA with TANGEDCO had been signed, while Unit 2 remained untied.

• By June/October 2015, Coastal Energen’s Unit 1 was commissioned and Unit 2 was expected by November-December 2015. Ind-Barath’s Unit 1 was projected for March/June 2017, while Unit 2 had not been awarded.

• In February 2016, Coastal Energen was recorded as not attending, with both units shown commissioned; Ind-Barath’s Unit 1 was projected for June 2018 and Unit 2 was abandoned.

• In June and September 2016, Coastal Energen’s two units were recorded as commissioned. Ind-Barath acknowledged that it would be liable for

transmission charges upon completion of the associated corridor; CTUIL advised it to regularise the reduction in LTA. In September 2016, Ind-Barath stated that 35% of its project had been completed, with ₹900 crore invested out of ₹3,500 crore, but its project was uncertain due to non-signing of PPAs and absence of tenders.

• By March 2018, Coastal Energen had relinquished 542 MW LTA pursuant to CERC’s directions in IA No. 1/2018 in Petition No. 246/MP/2016, while Ind-Barath informed that its generation project had been abandoned. By December 2018, Ind-Barath’s DIC status had ceased and its LTA was revoked. Our Analysis and Conclusion on Issue 1

30. TANGEDCO has challenged date of commercial operation (DOCO) to be 23.10.2016 for assets covered in Appeal No. 329 of 2018 and 13.11.2016 for assets covered in Appeal No. 56 of 2018 respectively, as approved by CERC. The thrust of the contention is that in accordance with Regulations, DOCO could not have been declared without beneficial use of the asset. In this context, judgment dated 02.07.2012 of this Tribunal in Appeal No 123 of 2011 has been relied upon.

31. Before we proceed to analyse the issue, it will be worthwhile to peruse the relevant Regulation of Central Electricity Regulatory Commission (Terms and Conditions of Tariff) Regulations, 2014, which is extracted below: “4. Date of Commercial Operation The date of commercial operation of a generating station or unit or block thereof or a transmission system or element thereof shall be determined as under:

(1) …….

(2) ……..

(3) Date of commercial operation in relation to a transmission system shall mean the date declared by the transmission licensee

from 0000 hour of which an element of the transmission system is in regular service after successful trial operation for transmitting electricity and communication signal from sending end to receiving end: Provided that:

(i) where the transmission line or substation is dedicated for evacuation of power from a particular generating station, the generating company and transmission licensee shall endeavour to commission the generating station and the transmission system simultaneously as far as practicable and shall ensure the same through appropriate Implementation Agreement in accordance with Regulation 12(2) of these Regulations :

(ii) in case a transmission system or an element thereof is prevented from regular service for reasons not attributable to the transmission licensee or its supplier or its contractors but is on account of the delay in commissioning of the concerned generating station or in commissioning of the upstream or downstream transmission system, the transmission licensee shall approach the Commission through an appropriate application for approval of the date of commercial operation of such transmission system or an element thereof.”

32. We note from the Impugned Order that the argument about non- beneficial utilization of the asset was put forward by TANGEDCO before CERC as well. However, CERC had approved the DOCO based on the certificate from RLDC and energization certificate from CEA. The certificate from CMD, as mandated by the Regulations was not submitted by PGCIL in case of assets covered in Petition No. 71/TT/2017 but the same was not insisted upon by CERC with the direction that such certificate may be submitted at the true up stage.

33. On the issue of DOCO, PGCIL has submitted that the asset has been used by TANGEDCO for drawing 558 MW from Coastal Energen since its’ commissioning. This appears to be the factual position on perusal of the submissions of TANGEDCO on the next issue i.e. sharing of transmission charges.

34. It is clear from the earlier extracted part of Regulation 4 of CERC Tariff Regulations, 2014 that essential condition for declaration of DOCO is that the asset should have been put in regular use. The term regular use has to be differentiated from full use, which TANGEDCO seems to be insisting upon.

35. It must be appreciated that transmission line is a lumpy asset and it does not have a modular feature which enables its capacity to be progressively augmented in small increments as system utilisation increases. To take a simple example, suppose that, based on long-term planning requirements, a transmission corridor is required to facilitate transfer of up to 2500 MW of power from point A to point B. At the initial stage, the actual power flow may, however, be only 150 MW. It would be fallacious to contend that the transmission line should have been constructed only at 220 kV on the ground that such voltage level was sufficient to transfer the initial 150 MW. It would be impractical to construct a 220 kV line initially, decommission or replace it within a few years, and thereafter construct a 400 kV and ultimately a 765 kV line as the power flow progressively increases towards 2500 MW. Such an approach would result in avoidable duplication of investment, besides causing considerable difficulties in obtaining the necessary Right of Way (ROW) and other statutory clearances.

36. This aspect assumes even greater significance in the present circumstances, where obtaining ROW for transmission lines is becoming increasingly difficult. Transmission planning, therefore, necessarily takes into account the anticipated requirements over a reasonably long-term horizon. A transmission line may accordingly be constructed at a higher voltage level with higher capacity than what may be warranted merely by the power flow prevailing at the time of its commissioning, so that the same transmission

corridor can serve the system requirements over a much longer period. The fact that the line is initially lightly loaded, therefore, cannot by itself lead to the conclusion that the asset was not required or that it was not put to beneficial use.

37. The possibility of modular augmentation is available, to some extent, in the case of substation transformers. For instance, a substation may initially be commissioned with a minimum configuration of two transformers to provide the necessary operational reliability and redundancy, with additional units installed progressively as system demand and power flows scale up. In fact, investment in substation components can be strategically deferred by temporarily operating a high-capacity transmission line at a lower voltage level, as is the case here, where 765 kV transmission lines were initially operated at 400 kV to match early-stage system requirements. Such incremental or phased optimization, however, is generally not possible for the transmission line itself.

38. It is also important to appreciate that a transmission line is not intended to be operated continuously at its full thermal capacity. The permissible loading of a transmission element is determined not merely by its thermal rating but also by the requirement to maintain system security under credible contingencies. In particular, the N-1 reliability criterion requires that with the outage of any one element of a transmission corridor having parallel paths, the system parameters, including voltage, loading and frequency, remain within the permissible limits. Consequently, a transmission line may be required to operate below its thermal capacity so that, in the event of an outage, the power can be redistributed through alternate transmission paths without resulting in unacceptable overloading and further tripping of transmission elements. Such cascading outages can lead to widespread disturbances and loss of load and/ or generation. Thus, low loading of a

transmission line cannot, by itself, be regarded as evidence of under- utilisation or non-utilisation of the asset.

39. More fundamentally, it is necessary to distinguish between utilisation of the transmission capacity and availability of the transmission asset for the intended purpose. A transmission asset is created not merely to carry a particular quantum of electricity at the time of its commissioning, but to provide the required transmission capability to the system. Its utility may consist in providing transfer capability, reliability, redundancy, contingency support and the ability to accommodate the anticipated growth in generation and demand. The fact that the entire available capacity is not actually utilised at a particular point in time does not mean that the transmission asset has not been put to use or that the asset is incapable of performing its intended function.

40. Indeed, the very purpose of transmission planning is to create the required network in advance of the point at which the full capacity may actually be required. If DOCO were to be recognised only when the transmission asset is utilised to, or approaches, its full capacity, it would effectively require the transmission system to be constructed only after the requirement has already materialised. Such an approach would be inconsistent with the very nature of transmission planning, which necessarily involves anticipation of future demand and generation and provision of adequate capacity in advance, including margins required for reliability and system security.

41. Accordingly, the actual power flow on a transmission line at or immediately after its commissioning cannot be the sole or determinative criterion for deciding whether the asset has been commissioned and put to use. Once the transmission asset has been completed, commissioned and

is capable of performing its intended function as part of the transmission network, the absence of full utilisation of its capacity cannot, by itself, justify postponing its DOCO. To hold otherwise would equate the commissioning and availability of a transmission asset with its instantaneous level of utilisation, which is neither consistent with the manner in which transmission systems are planned and operated nor reflective of the reliability and system- security functions performed by such assets.

42. In the judgment dated 02.07.2012 in Appeal No. 123 of 2011, the Barh- Balia line had merely been idle-charged from one end; the switchgear, protection and metering arrangements at the other end were not ready and no evidence of successful trial operation was produced. The Tribunal, therefore, held that the line was not even ready for regular service and could not attain COD merely because the components within PGCIL’s own scope had been completed. In the present case, however, the Central Commission recorded that the respective assets had been completed and were in regular service, supported by the RLDC and CEA certificates; further, TANGEDCO was drawing 558 MW of power from Coastal Energen through the transmission system, which formed part of the meshed network. The judgment in Appeal No. 123 of 2011 is therefore not applicable in the present case.

43. We are constrained to observe that in spite of express provision in the Regulations that the CMD’s certificate was mandatory and noting that the same had not been furnished, the CERC vide Impugned Order dated 21.11.2017 in Petition No. 71/TT/2017 proceeded to approve COD as 23.10.2016 and relegated submission of the certificate to the stage of truing- up that too without recording any reasons for such a course. The Central Commission ought, to have insisted upon the certificate before approving COD or recorded cogent reasons for permitting any departure from the

requirement. Including a specific provision in the Regulations while framing them, and thereafter ignoring the same provision at the stage of tariff determination, without any explanation, is not expected of a regulatory Commission. However, in the absence of any specific mention, we presume that such certificate was submitted during the true-up proceedings. In view of this, at this stage, we are not inclined to give much weightage to this issue. We, however, advise the CERC to bear in mind that the applicable Regulations, having the force of law, are required to be complied with not only by those to whom they apply, but also bind the Commission and govern the exercise of jurisdiction by this Tribunal, to the extent applicable.

44. In view of the foregoing analysis, we are of the opinion that the contention of TANGEDCO that commercial operation of the assets could not have been declared in the absence of their being put to what it terms as “beneficial use” is devoid of merit. Accordingly, we conclude that CERC had not erred in declaring commercial operation of the transmission assets covered in the present Appeals.

Issue 2: Whether the subject transmission assets could be included in the PoC mechanism and their charges recovered from DICs, despite substantial LTA remaining unutilised?

Submissions of the Appellant- TANGEDCO

45. The scheme, according to TANGEDCO, was premised upon the generators securing firm beneficiaries. At the Special SRPC meeting of 25.11.2010, PGCIL stated that the IPPs would bear transmission charges until beneficiaries were firmed up. Clause 22.7 of the Detailed Procedure required at least 50% of the LTA to be backed by PPAs three years before

LTA operationalisation; upon failure, CTUIL was required to reconsider implementation and where necessary, obtain CERC approval.

46. TANGEDCO submitted that only 558 MW was ultimately firmed up through its PPA with Coastal Energen. Ind-Barath neither commissioned its project nor had any PPA; Coastal Energen sought relinquishment of substantial LTA. Thus, 1,442 MW of the 2,000 MW LTA remained unused and without a procurer.

47. It is contended that the basis for the scheme had disappeared; the IPPs’ dedicated evacuation lines and complete upstream/ downstream connectivity were not established as envisaged; there was no 765 kV upstream connectivity or identified beneficiary beyond Salem Pooling Station; and no interstate transfer was taking place through the system. The 558 MW purchased by TANGEDCO, it is urged, could be evacuated through the State network.

48. Regulation 8(1), 8(5) and 8(6) of the Sharing Regulations is relied upon to submit that transmission charges must correspond to operationalised LTA and actual utilisation. Where the approved injection or withdrawal does not materialise, the concerned DIC/ generator remains liable; the burden cannot be shifted to unrelated DICs through the PoC pool.

49. TANGEDCO further relied upon the 32nd Commercial Sub-Committee meeting of SRPC held on 17.10.2016, where TANTRANSCO raised that the generator should bear charges until procurers were identified and that the beneficiaries should be consulted before such schemes enter the PoC pool. It invoked Section 29(4) of the Electricity Act and the finding in Appeal No. 206 of 2017 that approvals in such meetings have legal sanctity and bind all parties to the meeting.

50. The Appellant further contented that the PoC mechanism is only a clearing arrangement for pooling Annual Transmission Charges of regional/ ISTS licensees and billing DICs based on their access/ utilisation. It does not authorise recovery from the pool for untied or unutilised LTA. Existing DICs, who neither sought the system nor executed a BPTA cannot be made liable for the IPPs’ default.

51. CERC’s finding that the assets formed part of a meshed network is said to be insufficient. TANGEDCO submitted that the order acknowledges only 558 MW utilisation and charging of the 765 kV line at 400 kV but does not address the absence of intended interstate evacuation or the obligation to recover charges from the defaulting generators.

52. The Appellant further submitted that CERC’s order is a non-speaking one since after recording the parties’ contentions, it merely held that the assets were part of a meshed network and directed PoC recovery without deciding the regulatory objections. It relied on CCT v. Shukla & Bros., (2010) 4 SCC 785, and APTEL’s judgment dated 01.10.2024 in Appeal No. 243 of 2016 on the requirement of reasoned quasi-judicial orders.

Submissions of the Respondent No. 2- PGCIL

53. According to Respondent No. 2, TANGEDCO’s reliance on Clause 22.7(ii) of the Detailed Procedure, 2009 is selective. Clause 22.7(iv) permits augmentation/ strengthening to be undertaken with CERC approval where necessary, even where a generator fails to meet the stipulated condition. CTUIL obtained such regulatory approval in CERC’s order dated 31.05.2010 in Petition No. 233 of 2009 before implementing the subject assets.

54. The order dated 31.05.2010 was passed after considering the relevant facts and objections; it treated the system as part of ISTS, with charges and losses governed by the 2010 Sharing Regulations. TANGEDCO participated in those proceedings but never challenged the order. Respondent No. 2 therefore characterises the present challenge to the necessity or implementation of the corridor as an impermissible, belated collateral challenge to an order that has attained finality.

55. Respondent No. 2 submitted that CTUIL planned the ISTS after receiving LTA applications from Coastal Energen and Ind-Barath in July/ September 2008 for the Southern, Western and Northern Regions. At the time, the Tuticorin area had Tuticorin (1,050 MW), Tuticorin JV (1,000 MW), Kudankulam APP (2,000 MW), around 7,000 MW wind potential, and a proposed further 2,000 MW Kudankulam expansion. Given approximately 6,500 MW of concentrated coastal generation, the 765 kV corridor, initially charged at 400 kV, was planned to conserve right of way; Salem was selected as the suitable pooling location.

56. It is submitted that TNEB/ TANGEDCO participated throughout; the 28th Standing Committee/ LTOA meeting on 15.06.2009, the meeting with generators on 15.07.2009, the 29th Standing Committee meeting on 27.08.2009, and the 30th meeting on 13.04.2010. At the 15.07.2009 meeting, both IPPs had stated that their projects were progressing and expected commissioning by December 2011; TNEB had expressed interest in drawing power and planning the matching State grid. The 30th meeting approved LILO of both circuits, rather than one circuit, of the Tuticorin JV-Madurai 400 kV D/C line because of space constraints.

57. Respondent No. 2 stated that both IPPs had executed Bulk Power Transmission Agreements (BPTAs), furnished bank guarantees and

achieved requisite milestones, except MoEF clearance for Ind-Barath. Investment approval was obtained in September and December 2011. Project progress was monitored from August 2009, reassessed in March 2011, and thereafter reviewed in JCC meetings. Coastal Energen commissioned its first unit on 23.12.2014; Ind-Barath first communicated abandonment at the 15th JCC meeting on 10.06.2016 and confirmed it at the 16th JCC meeting on 30.09.2016, when the assets were already at an advanced stage. Respondent No. 2 submitted that the assets were finally commissioned on 13.11.2016.

58. It is further contented that TANGEDCO did not object to the JCC progress reports, despite their availability on the CTU/ PGCIL website, and subsequently drew Coastal Energen’s power under MTOA through the system. It submitted that the system was necessary even for Coastal Energen’s evacuation; operating constraints had earlier required backing down of its power. The choice of a 765 kV line, initially charged at 400 kV, is said to remain justified by the area’s generation and wind potential and the anticipated need to charge it at 765 kV as noted in the 37th Standing Committee meeting dated 31.07.2014.

59. Respondent No. 2 disputed that PGCIL assured States that they would never bear charges until beneficiaries were identified. Its position is that, at the SRPC Special Meeting of 25.11.2010, it stated that sharing would follow CERC’s prevailing transmission-price-sharing mechanism- firmed-up capacity would be paid by beneficiaries and untied capacity by the generator availing LTA to the target region.

60. Respondent No. 2 submitted that TANGEDCO has misconstrued Regulation 8(5) of the 2010 Sharing Regulations. It states that the provision secures recovery of a transmission licensee’s legitimate tariff upon asset

commissioning and is not applicable in the manner urged by TANGEDCO because Coastal Energen commissioned on 23.12.2014, its dedicated line was commissioned on 29.10.2016, and it supplied TANGEDCO under MTOA through the asset. It further stated that Coastal Energen’s charges are recovered under the 2009 Connectivity Regulations and Ind-Barath’s construction bank guarantee was encashed due to project delay.

61. Respondent No. 2 submitted that Coastal Energen’s relinquishment of 542 MW LTA was recognised by interim order dated 01.03.2018. Generator liability was dealt with in Petition No. 92/MP/2015, wherein relinquishment charges were determined on 09.03.2019. That order is under challenge in Appeal No. 336 of 2019, tagged with 24 similar appeals including Appeal No. 251 of 2019; the order dated 08.10.2020 directed that invoices not be raised during pendency, except in insolvency-related cases.

62. The assets are said to be part of a common meshed ISTS network serving multiple users, not dedicated solely to the two IPPs. Coastal Energen’s power flows from Tuticorin Pooling Station through the disputed asset to the new Salem Pooling Station and then to the existing Salem substation for dispersal across the grid. Hence, recovery through PoC is consistent with the Sharing Regulations; imposing the entire charge on the IPPs, while TANGEDCO uses the asset, is said to be unsustainable.

63. Respondent No. 2 alternatively seeks recovery from IPPs and contends that PGCIL cannot recover any charge because the asset was not put to intended use. Respondent No. 2 submitted that, having implemented and commissioned the assets after regulatory approval and by incurring substantial expenditure and debt, it cannot be denied the legitimate transmission charges.

64. Respondent No. 2 denied that the impugned order is non-speaking. It relied on paragraph 87, where CERC recorded that 558 MW out of 2,000 MW LTA had been operationalised, the assets were connected to the existing Salem and Nagapattinam substations as part of a meshed network, and the assets were in use. These findings justify PoC recovery under Regulation 43 of the 2014 Tariff Regulations read with the 2010 Sharing Regulations.

Submissions of the Respondent No. 20- CTUIL

65. Under the Sharing Regulations, tariff of all ISTS assets is recovered through the PoC pool. Consequently, once COD is validly declared, inclusion of the asset in the PoC mechanism necessarily follows.

66. After contracts are awarded, a transmission licensee cannot abandon construction merely because generators subsequently relinquish LTA, especially where the system is a common transmission system for the region. The regulatory mitigation available is recovery of relinquishment charges. CTUIL accordingly published relinquishment charges under Petition No. 92/MP/2015 on 20.05.2019, with Coastal Energen’s amount revised under CERC’s order dated 21.08.2020: LTA Grantee Quantum Relinquished LTA effective date LTA relinquishment date Relinquishment charges Coastal Energen 542MW /1100MW relinquished 01.12.2016 01.03.2018 (28.11.2016 as per CERC order) Rs. 44.12 Cr. (revised to Rs. 55.63 Cr.) Ind- Barath 495/900 MW relinquished 01.12.2016 01.12.2016 Rs. 49.13 Cr. Ind- Barath 405/900 MW relinquished 02.05.2018 02.05.2018 Rs. 37.42 Cr.

67. The bank guarantees furnished by Coastal Energen and Ind-Barath were invoked. Ind-Barath’s guarantee was encashed, while proceedings concerning Coastal Energen’s guarantee are pending before the Madras High Court.

68. The primary question in the appeal is that TANGEDCO bears charges for capacity not utilised because of LTA relinquishment and/ or project abandonment by the proposed developer. CTUIL submitted that the regulations prescribe billing of ISTS charges to all constituents and provide no mechanism to place only a part of a commissioned line’s capacity in the PoC pool.

69. Generation and transmission cannot be matched exactly MW to MW; transmission elements are developed as lumped assets and some under- utilisation is unavoidable. Such under-utilisation cannot justify denial of tariff for assets commissioned under the applicable law. CTUIL therefore submitted that the appeal lacks merit and is liable to be dismissed.

Our Analysis and Conclusion on Issue 2

“Plans are worthless, but planning is everything.” — Dwight D. Eisenhower, President of the United States (1953-1961)

70. We note that the core contention of TANGEDCO revolves around faulty planning and its implementation. It is stated that the assets remain under- utilized; the DICs should not be saddled with PoC charges corresponding to this unutilized capacity; rather, such charges ought to be recovered from the two generators who failed to achieve the generation capacity on which the transmission network planning was originally premised.

71. Having concluded in the Issue No. 1 that there was no error in the declaration of the commercial operation of the assets in question, in our opinion, it follows that recovery of transmission charges in respect of these assets had to commence from the respective DOCO. The only question that remains for consideration is as to how these transmission charges are to be apportioned.

72. As regards contention of TANGEDCO that the two generators responsible for under-utilisation of transmission assets should be made to pay for it, we note that the CTUIL has levied relinquishment charges on Ind- Barath and Costal Energen in accordance with the provisions of the CERC (Grant of Connectivity, Long-term Access and Medium-term Open Access in inter-State Transmission and related matters) Regulations, 2009. In this context, it would be useful to refer to Regulation 18 of the aforesaid Regulations, which is extracted below: “18. Relinquishment of access rights.

(1) A long-term customer may relinquish the long-term access rights fully or partly before the expiry of the full term of long-term access, by making payment of compensation for stranded capacity as follows: - (a) Long-term customer who has availed access rights for at least 12 years

(i) Notice of one (1) year – If such a customer submits an application to the Central Transmission Utility at least 1 (one) year prior to the date from which such customer desires to relinquish the access rights, there shall be no charges.

(ii) Notice of less than one (1) year - If such a customer submits an application to the Central Transmission Utility at any time lesser than a period of 1 (one) year prior to the date from which such customer desires to relinquish the access rights, such customer shall pay an amount equal to 66% of the estimated transmission charges (net present value) for the stranded transmission capacity for the period falling short of a notice period of one (1) year.

(b) Long-term customer who has not availed access rights for at least 12 (twelve) years - such customer shall pay an amount equal to 66% of the estimated transmission charges (net present value) for the stranded transmission capacity for the period falling short of 12 (twelve) years of access rights: Provided that such a customer shall submit an application to the Central Transmission Utility at least 1 (one) year prior to the date from which such customer desires to relinquish the access rights; Provided further that in case a customer submits an application for relinquishment of long-term access rights at any time at a notice period of less than one year, then such customer shall pay an amount equal to 66% of the estimated transmission charges (net present value) for the period falling short of a notice period of one (1) year, in addition to 66% of the estimated transmission charges (net present value) for the stranded transmission capacity for the period falling short of 12 (twelve) years of access rights.

(2) The discount rate that shall be applicable for computing the net present value as referred to in sub-clause (a) and (b) of clause (1) above shall be the discount rate to be used for bid evaluation in the Commission's Notification issued from time to time in accordance with the Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by Distribution Licensees issued by the Ministry of Power.

(3) The compensation paid by the long-term customer for the stranded transmission capacity shall be used for reducing transmission charges payable by other long-term customers and medium-term customers in the year in which such compensation payment is due in the ratio of transmission charges payable for that year by such long-term customers and medium-term customers.”

73. A careful perusal of the aforesaid provision makes it clear that the compensation payable by an LTA customer upon relinquishment of its access rights is linked to the transmission capacity that becomes stranded as a consequence of such relinquishment. The compensation is determined with reference to the estimated transmission charges attributable to such stranded capacity for the period prescribed under Regulation 18, subject to the specific conditions applicable to the nature and timing of the relinquishment. Thus, the regulatory mechanism seeks to ensure that the

financial consequences of stranded transmission capacity arising from relinquishment are not left to be borne entirely by the remaining customers.

74. Significantly, Regulation 18(3) provides that the compensation so paid by the long-term customer for the stranded transmission capacity shall be utilised for reducing the transmission charges payable by other long-term customers and medium-term customers in the year in which such compensation payment becomes due, in the ratio of the transmission charges payable by such customers. The Regulations, therefore, specifically provide a mechanism for mitigating the burden of transmission charges on other customers arising from stranded capacity.

75. We are conscious that the issue is presently the subject matter of a separate litigation due to appeals filed by several generators who were required to pay compensation for relinquishment of LTA in other transmission schemes arising as a consequence of the order passed by the CERC in Petition No. 92/MP/2015. Subject to the outcome of the said litigation, to the extent any relief becomes available on account of the relinquishment charges recovered from the concerned LTA customers, the DICs presently bearing the transmission charges through the sharing mechanism would correspondingly get compensated in respect of any unutilised capacity covered by such charges.

76. It can thus be seen that, insofar as the sharing of transmission charges is concerned, the CTUIL has followed the mechanism prescribed under the applicable Regulations, including the mechanism specifically provided for dealing with the financial consequences of relinquishment of LTA and the resultant stranded transmission capacity.

77. Another contention of TANGEDCO is that the Transmission Scheme was undertaken by disregarding Clause 22.7(ii) of the detailed procedure, which requires Generators to show PPA for at least 50% of their capacity.

78. We do not find merit in aforesaid contention since in its response, it has been pointed by PGCIL that Clause 22.7(iv) of the same procedure permits the Transmission Scheme to be undertaken with the approval of CERC even where Generators failed to meet stipulated condition. It is beyond doubt that the regulatory approval for the Scheme was granted by CERC vide Order dated 31.05.2010 in Petition No. 233 of 2009.

79. TANGEDCO has also submitted that the basis for the scheme had disappeared due to non-commissioning of Ind-Barath and only part capacity materialising in case of the Costal Energen.

80. We have noted from the minutes of the Joint Coordination Committee (JCC) meetings that first unit of Coastal Energen was commissioned in December 2014. Further, in the 12th JCC meeting held in May 2015, Ind- Barath had indicated expected commissioning of its first unit in March 2017. In the next JCC meeting held in October 2015, this date was pushed further to June 18. Ind-Barath first indicated abandonment of project in June 2016 and confirmed it in September 2016, while Costal Energen sought relinquishment of part LTA capacity after the transmission assets had already been commissioned.

81. In view of the aforesaid facts, we find considerable force in the submission of PGCIL that by time Ind-Barath had informed abandonment of its generation project, execution of the scheme had progressed to such an extent that it could not had been altered.

82. It is well recognised that planning, however carefully undertaken, is necessarily based on assumptions and projections about future developments, and there is always a possibility that actual developments may differ from those envisaged at the time of planning. A good planner does not remain passive when the assumptions underlying a plan do not materialise; rather, the plan is suitably adapted to the changed circumstances so as to ensure that the assets created continue to serve their intended purpose and are utilised efficiently.

83. The same principle applies with greater significance to transmission planning, given the large and lumpy nature of transmission investments. If, for instance, a transmission line has remained substantially under-utilised because the generation envisaged at the connected generating stations did not materialise, the appropriate response should not necessarily be to regard the line as an inefficient investment and leave it under-utilised. The planning process should instead consider whether generation capacity can be developed or facilitated at the concerned stations, or whether other suitable generation or demand can be connected, so that the available transmission capacity is put to effective use.

84. We note from the minutes of the joint study meeting of Southern Region held on 10th and 11th May 2018 which were submitted by TANGEDCO as part of their rejoinder dated 13.11.2018 that though Coastal Energen has LTA of 558 MW, but entire capacity (2 x 660 MW) is being pooled at Tuticorin Pooling station. Further, generation from Kudamkulam NPP (2x 1000 MW) and Tuticorin JV (2 x 500 MW), which were not specifically mentioned in planned scheme, is also being pooled at Tuticorin Pooling station. Thus, utilization of the assets in question is not limited only for transfer of 558 MW to Tamil Nadu.

85. As a broad analogy, the situation may be compared with the development of an apartment complex by a group housing society. Suppose an architect designs the complex, including common facilities such as a park, clubhouse and other amenities, based on the number of flats proposed and the anticipated occupancy. If fewer flats are subsequently occupied, the architect cannot, merely for that reason, be held responsible for the under- utilisation of those facilities, provided the design was appropriate on the basis of the information, projections and assumptions reasonably available at the time of planning.

86. The same principle would apply to a contractor who constructs the complex in accordance with the approved design. The contractor cannot ordinarily be faulted merely because some facilities are subsequently under- utilised. The position may be different if, before the relevant stage of execution, the contractor was instructed to defer, modify or omit any facility; though such a change may also have cost and contractual implications. Further, if the contractor is also responsible for maintaining the common facilities and is entitled to recover the admissible fixed costs, lower occupancy would not, by itself, justify a reduction in such recovery. The cost is incurred for creating, operating and maintaining the facility and keeping it available. It does not necessarily depend upon the extent to which the facility is actually used at a particular time.

87. A similar principle applies to transmission planning. The planning agencies may broadly be compared with the architect. Their role is to assess anticipated system requirements, apply the prescribed planning criteria and design the transmission network accordingly. The transmission licensee may, in turn, be broadly compared with the contractor. Its role is to implement the approved transmission scheme in accordance with the directions of the competent authority. The transmission licensee is also responsible for

operating and maintaining the transmission assets under the provisions of the Act. Under the applicable tariff and transmission-charge sharing framework, it is entitled to recover its admissible annual fixed costs. Such recovery cannot, by itself, depend upon the actual utilisation or power flow through an individual transmission element at a particular point in time. The relevant consideration is whether the capacity has been created, commissioned, maintained and kept available in accordance with the applicable regulatory requirements.

88. Thus, if a transmission asset was planned and implemented on the basis of the requirements, information and assumptions reasonably prevailing at the relevant time, its subsequent under-utilisation would not, by itself, establish an error in planning or implementation. Nor would lower utilisation, by itself, justify denial or reduction of otherwise admissible fixed- cost recovery.

89. The relevant questions would be whether there was a reasonable basis for the capacity and configuration approved; whether the licensee implemented the approved scheme as directed; whether the asset has been maintained at the prescribed level of availability; and whether any subsequent change required the competent authority to defer, modify, stage, abandon or otherwise alter the scheme.

90. The PoC mechanism also proceeds on this broad principle. The costs of the inter-State transmission system are pooled and shared among the designated ISTS users in accordance with the applicable framework. Once a transmission asset is completed, commissioned and made available as part of the approved transmission system, its admissible costs form part of the common transmission-cost pool. The rationale underlying this approach appears to be captured, albeit briefly , in the CERC’s description of the basis

for sharing the transmission charges among all DICs, namely, that the transmission system forms part of a meshed network.

91. The fact that an individual asset may, at a particular time, be used by fewer users or carry lower power flows than anticipated does not make the cost of the created capacity disappear. Subject to the applicable regulations, tariff orders and any valid direction regarding deferment, modification, non- commissioning or abandonment, the transmission licensee remains entitled to recover its admissible annual fixed costs.

92. This approach is also consistent with the nature of transmission planning. Transmission systems are planned not only for present flows, but also for anticipated demand and generation, reliability, contingency requirements, security of supply, evacuation needs, redundancy and future system requirements. Such planning necessarily involves uncertainty regarding the timing of demand, generation addition and changes in system conditions. Therefore, subsequent lower utilisation cannot, without more, be treated as conclusive evidence of imprudent planning or as a basis for denying recovery of otherwise admissible fixed costs.

93. In view of the foregoing, it is evident that in the present case, the foundational assumptions on the basis of which the transmission scheme was planned did not fully materialise. However, the non-materialisation of these assumptions cannot, by itself, be attributed to any lapse, imprudence or deficiency on the part of PGCIL, which implemented the scheme in accordance with the approved transmission plan and the investment approval. Accordingly, PGCIL is entitled to recovery of the transmission charges in respect of the subject assets through the PoC mechanism, in accordance with the CERC Sharing Regulations, 2010, subject to the

Commission’s prudence check and determination of the admissible capital cost.

94. We have also considered TANGEDCO’s submission that the impugned orders are non-speaking. The requirement that a quasi-judicial authority must record reasons is indisputable; however, the adequacy of reasons must be assessed with reference to the issue decided and the material considered. In the present case, the CERC has given a reason for including the transmission charges in the PoC mechanism for sharing by all DICs, namely, that the assets form part of the meshed transmission network. The reasoning is brief, but it cannot, therefore, be said that the Impugned Orders are wholly without reasons. At the same time, the fact that the assets form part of a meshed network does not, by itself, necessarily preclude bilateral billing. There have been instances where bilateral billing has been imposed, particularly in cases of default. This aspect seems to have been missed by the CERC. The reasoning, therefore, does not adequately explain why, in the facts and circumstances of the present case, the transmission charges were required to be shared through the PoC mechanism by all DICs.

95. Thus, while the Impugned Orders cannot be characterised as non- speaking, they do fall short in adequately explaining the rationale for the conclusion reached. We recognise that a reasoned order should ordinarily set out adequate justification for the conclusions arrived at. However, the absence of more elaborate reasoning, by itself, cannot be a ground for setting aside the Impugned Orders, particularly when the entire record, the applicable Regulations and the submissions of the parties are before us. The issues have also been fully argued before this Tribunal. We have, therefore, considered and determined the substantive challenge on its merits, as set out above.

ORDER

For the foregoing reasons as stated above, the Appeal Nos. 56 and 329 of 2018 are dismissed. Accordingly, the Impugned Orders dated 19.09.2017 in Petition No. 235/TT/2016 and dated 21.11.2017 in Petition No. 71/TT/2017 are upheld.

The Captioned Appeal and pending IAs, if any, are disposed of in the above terms.

PRONOUNCED IN THE OPEN COURT ON THIS 13th DAY OF OCTOBER, 2026.

(Ajay Talegaonkar) Technical Member (Virender Bhat) Judicial Member

REPORTABLE / NON-REPORTABLE kns/mg/mkj/kks