India Grid Trust BUY INDIA. Equity Research. Poised for strong growth. Infrastructure

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1 Equity Research May 28, 2018 BSE Sensex: Limited is the author and distributor of this report Infrastructure Target price Rs110 Shareholding pattern Sep 17 Dec 17 Mar 18 Promoters Institutional investors MFs, FIs FIIs Others Price chart (Rs) Jun-17 Sep-17 Research Analysts: Jan-18 May-18 Adhidev Chattopadhyay Rahul Modi Apoorva Bahadur INDIA India Grid Trust Poised for strong growth Market Cap Rs27.2bn/US$398mn (YE March 31) FY18 FY19E FY20E FY21E Bloomberg INDIGRID IN Revenue (Rs bn) Shares Outstanding (mn) EBITDA (Rs bn) week Range (Rs) 100/91 EPS (Rs) Free Float (%) 79.3 AUM (Rs bn) FII (%) 29.2 Distribution/Unit (DPU) Absolute Return 3m (%) 5.7 Cash Yield (%) Please refer to important disclosures at the end of this report BUY Rs96 Reason for report: Initiating coverage India Grid Trust (Indigrid) is an infrastructure investment trust ( InvIT ) established to own inter-state power transmission assets in India. We initiate coverage on Indigrid with a BUY rating and target price of Rs110 (includes Rs2/unit as residual cash as of March 2018). Our target price is based on discounting the Distribution per Unit (DPU) of cash flows from the InvIT over the residual life of assets post FY18 at a cost of equity of 11% and assumes injection of another 8 assets into Indigrid over FY19-22E through 3 incremental tranches of fund raising funded by a 51:49 mix of equity and debt. Based on incremental dilution at Rs100 for balance 3 tranches of asset additions, we expect the IRR returns of the Indigrid Trust to reach ~12% by FY22E (this assumes Rs100/unit as the initial outgo). Our calculation also assumes inclusion of a terminal value for each asset considering perpetual growth rate of 2%, cost of equity 12%, cost of debt of 8.5% and 50% capital gearing. At current levels, the Trust unit offers an attractive cash yield of 12.6%, 14.0% and 14.6% over FY19-21E, respectively, assuming a 100% pay out of the Net Distributable Cash Flow (NDCF) every year. High cash flow visibility from underlying assets: Unlike other infrastructure asset classes such as roads, ports and power generation assets, which have a riskier return profile on account of exposure to operational performance of underlying assets, Indigrid s ownership of power transmission assets, which have long-term fixed tariff contracts, offers high cash flow visibility with minimal risks. Aggressive growth plan in place: Indigrid is targeting to grow its assets under management (AUM) from Rs55bn as of FY18 to ~Rs300bn by FY22E, of which Rs195bn will be from ROFO assets and the balance through organic/inorganic route. It already has 6 assets under management (including Patran, a third party asset) with another 8 assets planned to be added in 3 tranches over FY19-22E. IRR returns the ideal metric to assess performance vs. cash yield: Typically, investors may look at the cash yield of the instrument by benchmarking the distribution per unit (DPU) for a given year and dividing it with the prevailing price per unit to arrive at the yield. However, in the case of Indigrid, which has a declining tariff trajectory, unless new assets come into the InvIT, the actual annual DPU may see a decline in the medium term. Hence, we believe that an Internal Rate of Return or IRR, based return on the initial cost per unit, is the correct method to compute returns for benchmarking them to G-Sec yields. Future asset injections should also be factored in valuations: Depending on the nature of underlying assets, they may or may not have a finite life. Hence, for an investor, who buys an InvIT unit today, the IRR return would be a function of the residual cash flows from the underlying assets which flows to the InvIT. However, an Investment Manager for an InvIT has the option of extending the life of the InvIT by bringing in new assets from time to time, by seeking approval of the existing Unit holders and structuring the funding of such acquisitions through a mix of debt and equity at the InvIT level. Hence, we prefer to look at valuations after factoring in the proposed asset injections.

2 TABLE OF CONTENTS Company Description... 3 Valuations... 8 Key Risks Infrastructure Investment Trusts (InvITs): Overview Power transmission sector Overview and growth prospects How India shifted from moving coal to transmitting power Green corridors and grid strengthening renewable capacity addition spree to offer more transmission opportunity Tariff-based competitive bidding (TBCB) Point of Connection (PoC) methodology: Payment security mechanism for inter-state transmission assets Overview of existing and pipeline assets Financial summary (Consolidated)

3 Company Description Chart 1: Current Assets owned by Indigrid India Grid Trust (Indigrid) is an infrastructure investment trust ( InvIT ) established to own power transmission assets in India. Indigrid was established on October 21, 2016 by its Sponsor, Sterlite Power Grid Ventures Limited (SGL), and is registered with SEBI pursuant to the InvIT Regulations. SGL, the Sponsor of Indigrid, is one of the leading independent power transmission companies operating in the private sector, with extensive experience in bidding, designing, financing, constructing and maintaining power transmission projects across India. As an InvIT, Indigrid is focused on providing stable and sustainable distributions to its unit-holders. The sponsor owns 10 inter-state power transmission projects with a total network of 29 power transmission lines of ~6,767ckms and seven sub-stations with 12,630MVA transformation capacity. Some of these projects have been fully commissioned, while others are at different stages of development. Of the 10 inter-state power transmission projects owned by the sponsor, IndiGrid has acquired five projects with total network of 13 power transmission lines of ~3,361ckms and three substations having 7,000MVA of transformation capacity. Pursuant to the ROFO deed, IndiGrid has right of first offer to acquire the balance eight projects of the sponsor. Owns inter-state high voltage power transmission assets Fully operational and revenue generating portfolio Focused on stable and sustainable distribution to unitholders PTCL Strong growth pipeline with ROFO on Sponsor assets ~Rs55bn* AUM 6 Project SPVs RTC L Kota Shujalpur JTCL Ranchi Purlia 3,361 circuit KM 7,000 MVA AAA Rated Perpetual Ownership 13 Lines and 3 substations ~33 years of residual contract # * Based on independent valuation report for BDTCL and JTCL as of 30 Sep 2017 and for RTCL, PKTCL, MTL and PTCL as of 30 Jun 2017 # Remaining TSA contractual life of 33 years. However, the projects are on BOOM model with perpetual ownership of IndiGrid BDTC L Yeddumailaram Mehboobnagar Nizamabad Chaibasa Kharagpur Mehesshwaram MTL IPAs PKTCL ROFO Assets injected Proposed Investment in the asset of Techno 3

4 Chart 2: Indigrid Trust Management Structure Sterlite Power Grid Ventures Limited Sponsor & Project Manager ~20.7% ~79.3% Public Unitholders Sterlite Investment Managers Limited Investmentmanager Trustee SGL1 Proposed third party investment (expected to be completed by Q1 FY19) BDTCL 1 JTCL 1 RTCL 2,4,8 PKTCL 2,5,8 MTL 2,6,8 PTCL 3,7 Note 1: 100% owned. 2: 49% owned. 3: Proposed 46% investment. 4: RTCL - 74% by Mar-18, 100% by Mar-21. 5: PKTCL - 100% by Mar-18. 6: MTL - 74% by Dec-19, 100% by Dec-22. 7: PTCL - 74% by Nov-18, 100% by Nov-21. 8: Balance stake today held by Sponsor entities. INDIGRID ROFO Assets Pursuant to the ROFO deed with the Sponsor, IndiGrid has right of first offer with respect to eight inter-state power transmission projects, having transmission network of 21 power transmission lines of ~4,831ckms and five sub-stations with 6,630MVA transformation capacity. Under the ROFO deed or otherwise, potential acquisition of power transmission projects will be assessed for their suitability with IndiGrid s investment mandate and subject to mutual agreement between the sponsor and the Investment Manager on behalf of IndiGrid as well as approval by unit holders. Chart 3: Pipeline of Existing Sponsor Assets East North Interconnection Ltd (ENICL) NRSS XXIX Transmission Ltd (NTL) Odisha Generation Phase Transmission Ltd (OGPTL) Gurgaon- Palwal Transmissio n Ltd (GPTL) Khargone Transmission Ltd (KTL) NER-II Transmissio n Limited Goa Tamnar Transmissio n Project Ltd. Overview 2 x 400 kv D/C lines 3x400 kv D/C lines, 1x400/220 kv D/C GIS substation 1x765 kv D/C line, 1x400 kv D/C line 5x400kV D/C lines and 3x400/220 kv substations 2x765 kv D/C lines, 1x400 kv D/C line and 1x765/400 kv substation 2x400 kv D/C lines, 2x132 kv D/C lines and 2x400/132 kv substations 2x400 kv D/C quad lines, 1x765 kv D/C line, 2x500 MVA, 400/220 kv substation Scheduled COD Commissioned Oct 2018 Aug 2019 Sep 2019 Jul 2019 Nov 2020 LOI Received on Nov 30, 2017 Length 909 ckms 887 ckms 715 ckms 271 ckms 624 ckms 900 ckms ~500 ckms (tentative) Revenues (5 yr. avg.) Rs1,420 mn Rs5,030 mn Rs1,590 mn Rs1,440 mn Rs1,860 mn Rs4,520 mn Tariff adoption order awaited 4

5 Chart 4: Operational Performance of Assets BDTCL JTCL Normative availability Availability over normative Normative availability Availability over normative (%) (%) FY16 FY17 FY18 Q1FY18 Q2FY18 Q3FY18 Q4FY18 FY16 FY17 FY18 Q1FY18 Q2FY18 Q3FY18 Q4FY18 RTCL PKTCL MTL Normative availability Availability over normative Normative availability Availability over normative Normative availability Availability over normative (%) (%) (%) FY18 Q1FY18 Q2FY18 Q3FY18 Q4FY18 FY18 Q1FY18 Q2FY18 Q3FY18 Q4FY18 FY18 Q3FY18 Q4FY18 Table 1: Management Overview Board of Directors Tarun Kataria Additional Independent Director Kuldip K. Kaura Additional Non- Executive Director Shashikant H. Bhojani Additional Independent Director Pratik Agarwal CEO & Executive Director Rahul Asthana, IAS Additional Independent Director Harsh Shah CFO & Executive Director Independent Non-Executive Director of Mapletree Logistics Trust Management Almost 30 years of experience in banking and capital markets in New York, Hong Kong, Singapore, Mumbai MBA in Finance from the Wharton School of the University of Pennsylvania Rich experience in cement, natural resources and power Previously CEO & MD of ACC, CEO of Vedanta, COO of Vedanta Resource, Managing Director of ABB India Limited Served as a member of the National Council of Confederation of Indian Industries Independent Director on the board of directors of L&T Infrastructure Finance Company Limited Partner at Cyril Amarchand Mangaldas since years of experience with ICICI Limited, starting as Law Officer and reaching Board of Directors MD & CEO of Sterlite Power 10+ years of experience in building core infrastructure businesses in ports, power transmission and broadband Bachelor s degree from the Wharton Business School and MBA from the London Business School Non Executive Director on the board of directors of Mahindra Vehicles Manufacturing Ltd, Vadhivare Specialty Chemicals, Aegis Logistics, NBS International and Mumbai Metro Rail corp Ltd Ex Chairman of Mumbai Trust and Maharashtra State Electricity Board Bachelor s degree from IIT Kanpur and MBA from ICPE University of Ljubljana, Slovenia CFO of Sterlite Power 10+ years of experience in PE Financing, Mergers and Acquisitions, Infrastructure financing, regulatory and macro economic policy focused on Infrastructure Bachelor s degree from the Nirma Institute of Technology and MBA from the National University of Singapore 5

6 Chart 5: Quarterly DPU (Rs) 0.92 Q1 Q2 Q3 Q4, I-Sec research Chart 6: FY18 Indigrid NDCF Calculation (Rs mn) 4,155 (55) (710) (160) ,438 (344) (90) (212) 2,792 2,702 EBITDA Non cash income Interest External debt Tax Working capital NDCF at SPVs 10% NDCF retained at SPVs External Int paid by IG ISRA NDCF at IG FY18 distribution, I-Sec research 6

7 How are power transmission assets better? Returns from various infrastructure projects like roads, ports and power generation rely mostly on the operational performance of the assets, which in turn is dependent on factors where developers have limited control. While in the case of ISTS transmission projects, the revenue counter party is a pool of distribution and generation companies, thus reducing the counterparty risk based on account of diversification. Also, in the case of an inter-state transmission asset, the revenue stream is consistent based on the unitary charge (Rs mn/annum) determined at the time of bidding for the entire concession period of 35 years. These charges are independent of the total power transmitted through the transmission lines and hence factors such as volume and traffic do not fluctuate the revenues. Moreover, inter-state transmission assets have limited O&M costs as compared to other infrastructure assets. Typically, transmission projects incur relatively low O&M costs of 7-8% of revenues in order to ensure normative availability. In comparison, road projects incur costs as high as 35% - 40% as O&M costs. In addition, transmission lines could also be used for providing telecom services thereby diversifying the revenue profile. Telecom and data service companies leverage reach of the transmission towers in potential semi-urban and rural regions to offer their services. Thus, other infrastructure projects, over and above the construction risk, also bear the risk of poor returns in case of lower utilization of assets. Transmission projects, on the other hand, are insulated from such risk, thus making it an attractive investment. Chart 7: Comparison of Transmission Assets with Other Infrastructure Assets 7

8 Valuations InvITs are hybrid instruments with fair degree of certainty on cash flows and have the characteristics of both debt and equity instruments. Typically, InvITs pay out returns to investors in the form of interest, dividend or capital return through buybacks, depending on the structure of the InvIT. IRR returns are the ideal way to value InvITs given nature of cash flows of underlying assets Typically, investors may look at the cash yield of the instrument by benchmarking the distribution per unit (DPU) for a given year and dividing it with the prevailing price per unit to arrive at the yield. However, in the case of Indigrid, which has a declining tariff trajectory, unless new assets are added into the InvIT, actual annual DPU may see a decline over time. Hence, we believe that an Internal Rate of Return or IRR based return on the initial cost per unit is the correct method to compute returns for benchmarking them to G-Sec yields. IRR returns should also factor in future asset injections Depending on the nature of underlying assets, they may or may not have a finite life. Hence, for an investor who buys an InvIT unit today, the investor s IRR return would be a function of the residual cash flows from the underlying assets which flows to the InvIT. However, an Investment Manager for an InvIT has the option of extending the life of the InvIT by bringing in new assets from time to time, by seeking approval of the existing Unit holders and structuring the funding of such acquisitions through a mix of debt and equity at the InvIT level. Hence, we prefer to look at valuations after factoring in the proposed asset injections by the Indigrid. Indigrid IRR returns to grow to 12% with 3 incremental tranches of asset addition From current AUM of Rs55bn (Rs195bn including ROFO assets), Indigrid targets to manage Rs300bn plus AUM over the next five years, resorting to organic as well as inorganic routes. As explained earlier, apart from the existing portfolio of 6 assets (including Patran), Indigrid has a roadmap to inject 8 more assets by FY22E into the InvIT through 3 incremental tranches of asset injection. 8

9 Chart 8: Indigrid plans to grow AUM to Rs300bn by FY22E AUM (Rs bn) FY18 FY19E FY20E FY21E FY22E, I-Sec research Every round/tranche of asset injection would result in higher Net Distributable Cash Flows to shareholders and also boost the DPU and IRR profile of the Indigrid InvIT. Post the first tranche of asset infusion of 4 new assets in FY18 (including Patran), Indigrid has hit the maximum permissible leverage ratio of 49% at the InvIT level. Hence, for any further asset additions in the upcoming tranches, the Trust would have to raise fresh equity, which would lead to dilution. We have assumed every incremental fund-raise at a price of Rs100, based on which we have calculated our IRRs for every tranche of asset injection. For fresh debt at InvIT level, we have assumed an interest rate of 8.5% for each round of debt raising. Table 2: Indigrid NDCF to grow to Rs12.3bn by FY22E with 3 further tranches of asset injection (Rs bn) Details FY18 FY19E FY20E FY21E FY22E BDTCL & JTCL Add: Tranche 1 (MTL+PKTCL+RTCL+Patran) Post Tranche Add: Tranche 2 (ENICL+NRSS) Post Tranche Add: Tranche 3 (KTL+OGPTL+GPTL) Post Tranche Add: Tranche 4 (NER+Goa) 2.4 Post Tranche Source: I-Sec research estimates 9

10 Chart 9: Indigrid NDCF to grow to Rs12.3bn NDCF (Rs bn) FY18 FY19E FY20E FY21E FY22E Source: Source: I-Sec research estimates Based on incremental dilution at Rs100 for balance 3 tranches of asset additions, we expect the IRR returns of the Indigrid Trust to reach ~12% by FY22E (this assumed Rs100/unit as the initial outgo). Our calculation also assumes inclusion of a terminal value for each asset considering 2% perpetual growth rate, 12% cost of equity, 8.5% cost of debt, 50:50 gearing. Our IRR does not include any value for residual cash at Indigrid level as of March Chart 10: Indigrid IRR to reach 12% by FY22E IRR 14% 12% 10% 8% 8.13% 9.52% 11.47% 11.83% 11.97% 6% 4% 2% 0% FY18 FY19E FY20E FY21E FY22E Source: I-Sec research estimates We value Indigrid with a Target Price of Rs110/share and initiate with a BUY rating Based on our assumptions of balance 3 rounds of asset injections to be completed by FY22E, we value Indigrid with a target price of Rs110/share, which includes Rs2/share for residual cash at Indigrid, as of March 2018 (FY18 closing cash less DPU payout of Rs3/unit post March 2018). We have assumed a cost of equity of 11% to discount the DPUs over the life of the asset based on incremental DPU post March

11 Chart 11: Indigrid Distribution per Unit assuming asset injections DPU (Rs/unit) FY18 FY19E FY20E FY21E Source: I-Sec research estimates At current levels, the Trust unit offers an attractive yield of 12.6%, 14.0% and 14.6% over FY19-21E, respectively. We initiate with a BUY rating as the unit offers an absolute return of 15% along with a FY19 DPU of Rs12.1/unit. Chart 12: Indigrid Cash Yield at CMP of Rs Cash yield (%) FY18 FY19E FY20E FY21E Source: I-Sec research estimates 11

12 Key Risks Fluctuations in Interest Rates As InvITs are hybrid instruments which have features of debt and equity with a long tenure, their returns are often benchmarked to G-Sec yields with expectations of a bps additional IRR return over G-Secs. As assets held under the InvIT may carry external debt at the SPV level and external debt at the InvIT level as well, any hardening of interest rates may lead to refinancing risk which may lead to fluctuations in the unit price of an InvIT to reflect the increased return expectations of investors. As Indigrid carries external debt at SPV level as well as Invit level, it is exposed to interest rate risks. However, we are of the view that with the addition of new assets into the Indigrid InvIT, the Trust can continue to deliver a bps IRR return over Indian G-Sec yields. Incremental capital raising for ROFO assets Our assumptions for addition of ROFO assets assume all incremental equity capital fund raising at Rs100/share and leverage at the Indigrid Trust level at between % for each tranche of incremental asset infusion. However, any variance in the same could lead to a larger than expected dilution at the Trust level, which could change the IRR returns of the instrument. Dependence on Investment Manager to deliver expected returns The Investment Manager for the Indigrid Trust is entrusted with the responsibility of delivering the expected returns, management of macro risks and ensuring that incremental asset addition takes place at reasonable valuations. Any failure on the part of the Investment Manager to effectively manage these risks, could alter the expected return at the Trust level. Risk from asset unavailability IndiGrid s assets are entitled to earn revenues by maintaining availability above a certain threshold. In the event of it falling below 95% (due to system breakdown, human error, etc.), the company will under-recover revenues and/or face penalties Revenue loss from force majeure events While loss from force majeure events is normally compensated, there could be situations wherein such compensation might not fully offset the loss/damage incurred by the company, thus impacting its financials Risk of payment delays Arising out of weak financial position of State Electricity Boards and Power Grid s conflict of interest as both, the Central Transmission Utility (entrusted with the responsibility of collecting payments) and transmission asset owner (paying itself first, in the event of collection shortfall) Risk of inability to pass-through cost escalations While generally, when bidding for transmission assets under the TBCB mechanism, developers factor cost increases, the risk from unexpected increase in cost/aggressive bid assumptions persist, given the fact that such additional costs would not be passedthrough 12

13 Infrastructure Investment Trusts (InvITs): Overview What are InvITs? Infrastructure Investment Trusts or InvITs essentially aim to create a pool of assets which throw up a stable stream of cash flows for investors. For infrastructure developers and asset owners, InvITs serve as an effective vehicle to free up capital in existing projects and channel this capital towards creation of new assets. Infrastructure assets which can be brought into an InvIT include power transmission assets, power generation assets, toll/annuity road assets and ports. Each class of infrastructure assets have their own risk profile in terms of the predictability of cash flows from the underlying assets which makes an InvIT a hybrid product with characteristics of both debt and equity wherein a portion of the returns are fairly certain with possibility of further upsides from better than expected performance of the underlying assets, injection of new assets at a reasonable valuation which can boost overall returns for investors and keeping an efficient capital structure at the InvIT level by the Investment Manager of the InvIT. Chart 13: Key Objectives for Introducing InvITs Key Objectives for Introducing InvITs Provide Suitable and Long-term Financing/ Re-financing for Existing Infrastructure Projects and Create Investment Options Free Up Current Developer Capital for Reinvestment into New Infrastructure Projects Also acts as a Vehicle to Attract new Capital into Indian Infrastructure Sector Enable Investors to Hold a Diversified Portfolio of Infrastructure Assets Proposed to Bring Higher Standards of Governance into Infrastructure Development and Management Additional Investment Avenue for Investors Source: I-Sec research 13

14 Chart 14: SEBI (Infrastructure Investment Trust) Regulation, 2014, as amended Infrastructure as defined All infrastructure sub-sectors defined by the Cabinet Committee on Infrastructure; vide the Notification of Ministry of Finance dated 1 March 2012 (i.e. under the categories - transport, energy, water sanitation, communication and social and commercial infrastructure) Registration The InvIT has to be registered with SEBI Parties in an InvIT Structure & Key Responsibilities Key investment conditions Trustee Sponsor Investment Manager (IM) Holds the InvIT Net worth of at Decision-making assets in trust for least Rs. 1 Bn in w.r.t. the benefit of unit case of body investments in holders corporate or a assets Execution of company or net Overseeing Investment intangible assets Project Management of Rs 1bn in case Manager s Agreement with of a LLP activities the IM Ensuring Ensuring assets Overseeing aggregate have legally Investment minimum postissue enforceable titles Manager or holding of & that material Project at least 15% (with contracts are Manager s a three- year lock- legally activities as in) enforceable provided Divestment of Declaring and Reviewing of 15% holding: making transactions Possible only distributions to between the after 3 yrs from unit holders Investment the date of listing Coordinate with Manager and Trustee for associates operations of InvIT Project Manager Undertaking the operation, management, maintenance and supervision of assets Ensuring compliance with the concession agreement Undertaking all obligation of project implementation in compliance with the terms of the project management agreement Invest at least 80% of the value of the assets in completed and revenue generating infrastructure assets Balance 20% can be invested in under-construction infrastructure projects and securities of infrastructure companies in India (cannot invest in units of other InvITs) InvIT should hold (directly or through SPVs) the infrastructure assets for at least 3 years from the date of purchase of the asset by the InvIT (except investment in securities of infrastructure companies) Investment into SPVs is subject to the InvIT holding a controlling interest (at least 51% of equity share capital) in the SPVs Source: I-Sec research 14

15 Chart 15: InvIT Regulation Dividend Policy, leveraging and other aspects Distribution Policy Leveraging Related Party Transactions Governance Source: I-Sec research At least 90% of distributable cash flow of the SPV shall be distributed to the InvIT in proportion to its holding in the SPV At least 90% of distributable cash flow of the InvIT shall be distributed to the unit holders Dividend declared to be paid within 15 days; distributions to the unit holders to be made on a half yearly basis Borrowings and deferred payments not to be more than 49% of value of InvIT assets (excluding any borrowings made by the InvIT to the SPVs) Borrowings and deferred payments more than 25% of the value of assets are subject to: Credit rating; Approvals of unit holders where the votes cast in favor should be more than the votes cast against the resolution Related parties of InvIT shall include (i) parties to the InvIT; (ii) promoters, directors and partners of the persons mentioned in and as per Companies Act, 2013 and as per Accounting Standards; Transactions with related parties to be disclosed in the offer document w.r.t. transactions prior & proposed after the offer The Sponsor will not have voting rights on matters pertaining to related party transactions Approval by way of votes cast in favor of the resolution shall be at least 1.5 times the votes cast against for certain cases Change in Investment Manager or Auditor or Valuer or Trustee Prior approval of at least 60% of unit holders Special approval by way of votes cast in favor of the resolution should be at least 1.5 times the votes cast against Annual report for unit holders within 3 months from the end of the financial year; half-yearly report within 1 month Price sensitive information to be disclosed to stock exchange Chart 16: Key rights of Investors and Investment mangager Rights of Unit Holders Rights & Responsibilities of Investment Manager Growth Source: I-Sec research Unit holders shall have right to receive income through distributions from the Trust With respect to any matter requiring approval of the unitholders A resolution shall be considered as passed when the votes cast by unit holders in favour of the resolution exceeds those casting against the resolution For removal of the IM, an approval from the Unitholders shall be required where the votes cast in favour of the resolution shall not be less than one and a half times the votes cast against the resolution The investment manager shall recommend to the Unitholders investment decisions with respect to underlying assets or projects of the Trust including any further investment or divestment of the assets The Board of Directors of the investment manager will have at least 50% of the Directors as Independent The investment manager shall ensure adequate and timely redressal of all unit holders grievances pertaining to activities of the Trust The Trust may purchase both sponsor and non-sponsor assets as per its investment strategy Prior approval of the unit holders will be required at the time of any purchase / divestment of assets 15

16 Chart 17: Tax implications at various levels SPV Interest on debt from InvIT Distribution of dividend to InvIT SPV InvIT Dividend income of the InvIT Tax on other income Gains on disposal of assets Unit-holder Interest income received from InvIT Dividend income distributed by the InvIT Capital gains on sale of units Any other income distributed by the InvIT No. Entity Issue 1 SPV Interest on loans from InvIT not subject to witholding tax obligations at SPV level Distribution of dividend to trust not subject to DDT if InvIT holds 100% interest in the SPV 2 InvIT Income of trust Dividend and Interest received by trust from SPV Tax Exempt Capital gains on disposal of assets - taxable in the hands of InvIT Any other income taxable at maximum marginal rate Interest component of income distributed by trust to the unit holders would attract withholding 5%/ 10% for nonresident and resident unit holders respectively 3 Unitholder Interest income shall be taxable in the hands of Unit Holders as if they have received the interest directly At applicable rates for resident unit holders At 5% for non-resident / offshore investors; benefits under DTAA, if any, shall be available Dividend Income distributed by the Trust is exempt in the hands of Unit Holders Sale of listed units of InvIT on the exchange to attract levy of STT at par with that of listed equity shares Long term capital gains (LTCG), where units held for over 36 months, would be tax exempt and short term capital gains (STCG) would be 15% Where sale of units is off the exchange LTCG taxable at 20% and applicable rates For Non-Resident Unit Holders, benefits under respective DTAA, if any, shall be available Source: I-Sec research 16

17 Power transmission sector Overview and growth prospects India s power transmission sector can be segregated into inter-state network (national grid) and intra-state networks (state grids), with inter-state grid s management, regulation and expansion falling in the domain of central government (and related entities) and that of intra-state grids with respective state and state agencies. Over the past 5-6 years, inter-state transmission capacity has witnessed robust additions, (with the 13th Five-Year Plan assigning a capex target of Rs1tn to be achieved by FY22) as the government worked towards ensuring robust power evacuation and transmission infrastructure between sprouting power plants and major demand centers. But, intra-state transmission infrastructure development could not keep pace as SEBs struggled with financial constraints. However, this trend is beginning to correct of late, as UDAY helped improve the financial condition of SEBs, to a certain extent. 13th Five-Year Plan has pegged the intra-state transmission capex target at Rs1.6tn (likely to be increased to Rs2tn over the next five years), potentially providing fillip to the power transmission sector. Chart 18: Transmission line addition trend (Ckm) HVDC 765kV 400kV 230/220kV 10th FYP 11th FYP 12th FYP - E 13th FYP - E Source: CEA, I-Sec research 17

18 Chart 19: Substation capacity addition trend (Ckm) 1, kV 400kV 230/220kV 10th FYP 11th FYP 12th FYP - E 13th FYP - E Source: CEA, I-Sec research Table 3: State-wise power transmission capex target under Power for all Scheme (Rs bn) State Transmission FY18 FY19 Andhra Pradesh Arunachal Pradesh Assam Bihar Chhattisgarh 7.6 NA Delhi Gujarat Haryana Himachal Pradesh Jammu and Kashmir Jharkhand Karnataka Kerala Madhya Pradesh Maharashtra Orissa Punjab Rajasthan Tamil Nadu Telangana Uttar Pradesh Uttarakhand West Bengal Source: Ministry of Power, I-Sec research Table 4: T&D capex target vs. actual for key states FY12 FY13 FY14 FY15 FY16 (Rs bn) Target Actual Target Actual Target Actual Target Actual Target Actual Andhra Pradesh Gujarat w Haryana Karnataka Madhya Pradesh Maharashtra Punjab Rajasthan Tamil Nadu Telangana Uttar Pradesh West Bengal All India , Source: PFC, I-Sec research 18

19 Three modes of investment in intra-state transmission projects Cost-plus by state transmission companies wherein companies with expertise in transmission system planning and development can act as a consultant while entire investment is made by the state transmission company itself Forming JVs with the state transcos and jointly making the investments where both earn regulated RoE on the equity invested Via TBCB route, wherein state agencies auction transmission infrastructure projects to lowest bidder. This model is most relevant to Indi Grid Demand growth and need for more generation and transmission capacity As per the revised CEA data, the power requirement for FY22/FY27 is estimated at 1,619MUs / 2,130MUs, implying a CAGR of 6-7% over FY17, which is quite significant as it incorporates the savings resulting from energy efficiency measures. As per the planning authority, peak demand for FY22 is 235GW while peak availability during the same year is expected to be 247.5GW (assuming 100GW of renewables vs the 175GW target; addition of 50GW coal-based power plants currently under construction against 22GW of retiring capacities). If demand grows by 6-7% annually, per capita demand of electricity is expected to increase to 2,000kWh by 2030 from 1,050kWh currently. Hence, India will require more generating capacities by FY24 for which regular demand monitoring is being done. This will also lead to higher requirement of transmission capacities. Further, more than 40mn families currently do not have electricity connections which are being provided for free under the Saubhagaya scheme. Looking at the railway constraints on coal movement, we expect incremental generating capacity to come up in pithead rather than load centres, for which more inter/intra-state transmission will be needed beyond what is planned till FY24. How India shifted from moving coal to transmitting power Chart 20: Improving transmission connectivity making it an attractive proposition over coal transport despite increasing per unit cost 1.8 Transmission cost Coal transportation cost for 1000 KM away plant Rs/kWhr FY2007 FY2008 FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016 FY2017 FY2018E FY2019E FY2020E FY2021E FY2022E Source: Power Grid, Ministry of Railways, I-Sec research 19

20 Chart 21: Power Grid s infrastructure creation spree moving the country towards one nation one price one frequency PGCIL capitalisation PGCIL Capex Rs bn FY2007 FY2008 FY2009 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016 FY2017 FY2018E FY2019E FY2020E FY2021E FY2022E Source: Power Grid, I-Sec research Green corridors and grid strengthening renewable capacity addition spree to offer more transmission opportunity India s massive renewable capacity addition drive required creation of large scale power evacuation infrastructure and investment in grid robustness. For this, the government planned development of Green Energy Corridors, to ensure creation of power evacuation infrastructure for upcoming renewable capacity. The rationale for creating a separate transmission corridor for renewable generation is as follows: It helps in managing volatility and intermittency of renewable sources. Developing a separate transmission infrastructure will insulate the main grid from volatilities of renewable power. Solar projects are generally executed within months, outpacing transmission infrastructure creation by months. Requirement for speedy execution is also the reason for PGCIL being nominated for execution of the first two phases of Green Energy Corridor project. Green Energy Corridor project entails the following: An intra-state transmission strengthening scheme, which would facilitate evacuation of renewable power and integration into the grid An inter-state transmission strengthening scheme for transfer of renewable power from host state to other states Last-mile connectivity system for interconnection of renewable energy projects to common pooling stations Real time measurements/monitoring schemes Energy storage as a power balancing mechanism to address intermittency Setting up of Renewable Energy Management centres for facilitation of forecasting the renewable power generation capacity and smooth transmission of the renewable energy management mechanism 20

21 Table 5: TBCB projects auctioned so far Tariff-based competitive bidding (TBCB) Under the TBCB, tariff for projects is not on a cost plus basis and bidders are required to quote tariff for a period of 35 years for establishing transmission lines. The bidder quoting the lowest levelised tariff, is selected. The successful bidder is then required to acquire a special purpose vehicle or SPV incorporated by the bid process coordinator or BPC. Once the process of acquisition is complete, the SPV approaches CERC to obtain a transmission license. S. No. Transmission Project Winner 1 Transmission system associated with IPPs of Nagapattinam / Cuddalore Area- Package A PGCIL 2 Transmission System associated with IPPs of Vemagiri Area-Package A PGCIL 3 Transmission system for Strengthening in SR for Import of Power from ER PGCIL 4 ATS of Unchahar TPS PGCIL 5 NR System strengthening SchemeNRSS-XXXI(Part-A) PGCIL 6 Transmission System associated with Gadarwara STPS (2x800 MW) of NTPC (Part-A) PGCIL 7 Transmission System associated with Gadarwara STPS (2x800 MW) of NTPC (Part-B) PGCIL 8 Transmission System Strengthening associated with Vindhyachal- V PGCIL 9 Strengthening of Transmission system beyond Vemagiri PGCIL kv System Strengthening Scheme in Eastern Region. ERSSXVIII PGCIL 11 System Strengthening Scheme in Eastern Region ERSS XXI PGCIL 12 New WR-NR 765 kv Inter- Regional Corridor PGCIL 13 System strengthening for WR Sterlite Power 14 System strengthening common for WR and NR Sterlite Power 15 Scheme for enabling import of NER/ER surplus by NR Sterlite Power 16 Part ATS for RAPP U-7&8 in Rajasthan Sterlite Power 17 Eastern Region System Strengthening Scheme-VII Sterlite Power 18 Northern Regional System Strengthening Scheme, NRSS-XXIX Sterlite Power 19 Connectivity lines for Maheshwaram 765/400 kv S/S Sterlite Power 20 Common Transmission system for phase-ii generation projects in Orissa and immediate evacuation system for OPGC project (Orissa) Sterlite Power 21 Creation of new 400 kv GIS substations in Gurgaon area and Palwal as a part of ISTS Sterlite Power 22 Connectivity system for Khargone TPP (2x660MW) Sterlite Power 23 NER System Strengthening Scheme II Sterlite Power 24 Additional 400kV Feed to Goa and Additional System for Power Evacuation from Generation Projects pooled at Raigarh (Tamnar) Pool Sterlite Power 25 Eastern Region System Strengthening Scheme-VI Essel Infra 26 Northern Region System Strengthening Scheme, NRSS-XXXI (Part-B) Essel Infra 27 Additional inter regional AC link for import into southern region i.e Warora-Warangal and Chilakaluripeta Hyderabad Kurnool 765 kv link Essel Infra 28 System strengthening in northern region (NRSS XXXVI) along with LILO of Sikar-Neemrana 400 kv D/C line at Babai(RVPNL) Essel Infra 29 Additional system strengthening for Sipat STPS Adani Transmission 30 Additional system strengthening for Chhattisgarh (B) Adani Transmission 31 System strengthening for IPPs in Chhattisgarh and other generation projects in western region Adani Transmission 32 Immediate evacuation for North Karanpura (3x660MW) generation project of NTPC(ERSS XIX) Adani Transmission 33 Transmission System for Ultra Mega Solar Park in Fatehgarh, Distt. Jaisalmer Rajasthan Adani Transmission 34 Transmission System required for evacuation of power from Kudgi TPS (3x800 MW in Phase-I) of NTPC L&T 35 Transmission System for Patran 400kV S/S Techno Electric 36 Transmission System Associated with Krishnapattnam UMPP- Synchronous interconnection between SR and WR (Part-B) RSTCL 37 Transmission system strengthening in Indian system for transfer of power frem new HEP s in Butan Kalpataru 38 North Eastern Region Strengthening Scheme (NERSS-VI) Kalpataru 39 Transmission System associated with DGEN TPS (1200 MW) of Torrent Power Instalaciones Inabensa S A Spain 40 System Strengthening in NR Reliance Power 41 Augmentation of Talcher-II transmission System Reliance Power Source: CEA, I-Sec research 21

22 Point of Connection (PoC) methodology: Payment security mechanism for inter-state transmission assets National Electricity Policy (NEP) of 2005 directed CERC to develop a transmission tariff framework which takes into account quantum, distance and direction of power flow in order to ensure that Designated Inter-state Transmission System Customers (DICs) pay for their utilization of transmission system. This led to CERC introducing CERC (Sharing of Inter State Transmission Charges and Losses), Regulations 2010, which replaced the old Regional Postage Stamp method of appropriation of transmission charges and losses with Point of Connection (PoC) methodology. The new framework is based on the principle of a national integrated transmission grid, where charges and losses will be apportioned on the basis of quantum and location. Regional Postage Stamp Method (pre-2010 method): Under this method, transmission charges and losses were pooled at a regional level and all states located within the region shared it in the ratio of power drawn through ISTS. Total power drawn = Power drawn from central govt. generators (Fixed share + drawings from unallocated quota) + Long-term agreements (PPAs between states and IPPs/other states) For example: If state A draws 10% power from the regional pool, it will be liable to pay 10% of the total transmission charges for that region. Why did it need to be replaced? The Regional Postage Stamp method worked reasonably well when the transmission system lacked national inter-connectivity. However, with the country moving towards complete grid inter-connectivity, need for a utilisation-based transmission charge and loss sharing mechanism became pertinent. Besides, regional postage stamp method resulted in artificial increase in transmission charges due to pancaking (being charged twice once at each end) because consumer state had to bear transmission charges and losses at both, generation and consumption states. Point of Connection Method: This method provides the generator or a consumer with a single, location based transmission charge. The idea is to allow them to decide the location of a power plant by comparing costs of fuel transportation and cost of electricity transmission For any given location If cost of fuel transportation > cost of electricity transmission setup power plant nearer to the fuel source If cost of electricity transmission > cost of fuel transportation setup power plant closer to the demand node Assessment of Yearly Transmission Charge: Yearly Transmission Charge under the PoC framework = PoC Charge + Reliability Support Charge + HVDC Charge + Transmission Losses PoC Charge for generator = PoC transmission rate of generation zone * Approved injection 22

23 PoC Charge for consumer = PoC transmission rate of demand zone * Approved withdrawal It is important to note that PoC charges are billable only to consumers (at the withdrawal node) and power generators having LTA but without PPA Reliability Support Charge = Reliability support rate * Approved Injection/Withdrawal where, Reliability support rate = 10% of monthly transmission charges of the ISTS / Total approved Injection and Withdrawal for the region HVDC Charge = HVDC Charge for the region x Approved Injection/Withdrawal / Total approved Injection and Withdrawal for the region *this will be for recovery of 90% of MTC, remaining 10% will be recovered via reliability support charges as HVDC help in controlling voltages and power flow in inter-regional lines Transmission Losses Determination of Basic Network: The Regulation requires transmission charges to be limited to transmission network of ISTS Licensees and other Regional Power Committees (RPC) certified licensees whose transmission network is being used for inter-state transmission. In order to define the network for calculation of YTCs, the regulation proposed 400kV to be the upper limit for network truncation as most of PGCIL s assets operate at 400kV. Creation of PoC Pool: In order to calculate Yearly Transmission Charges, annual transmission charge of each approved line is computed based on CERC tariff orders or competitive bids for existing lines and on benchmark capital cost for new lines. Dedicated lines constructed, owned and operated by the generator will not be a part of basic network and hence also not of PoC Pool. Assets below 132kV (except in cases where generator is connected to the grid at 110kV) will not be a part of PoC pool. YTC of substations will also be apportioned to transmission lines based on the following principles: Such apportionment will be on the basis of length of associated transmission lines YTC of sub-station attributed to higher voltage line = 2x YTC of sub-station attributed to lower voltage line Determination of PoC Charges: The regulation defines a hybrid methodology to compute Point of Connection charges (in Rs/MW/month) and Loss Allocation Factors that are to be shared among the users of ISTS. The hybrid method factors both average and marginal utilisation of transmission assets to arrive at the transmission charge. While average charge distributes transmission cost via rule-based allocation, marginal charge accounts for the incremental usage of system due to the addition of a user in the system. The PoC charges so computed will be determined for peak and non-peak conditions in the following seasonal blocks: April to June 23

24 July to September October to November December to February In order to ensure uniformity in transmission charges (per ckm) at each voltage level and conductor configuration, total transmission charge recoverable for a particular voltage level is divided by total length of lines at that voltage level. Further, the Implementing Agency has to create demand and generation zones of geographically and electrically proximate nodes to aggregate and arrive at a uniform zonal demand and generation charges. Special cases: Transmission charges for thermal generators connected directly to ISTS or via pooling stations will be determined at those specific nodes and not clubbed with other generator nodes in the area For generation stations not a part of Basic Network, transmission charges will be determined for the region where they are located No transmission charges or losses will be levied on solar generation over the useful life of plants commissioned till 2014 In case of a delay in commissioning of power plant, generator will be liable to pay withdrawal charges corresponding to its Long Term Access from the date such LTA was granted (HCPTC I case) Similarly, if there is a demand draw down, the power consumer will have to bear charges as per the demand schedule Treatment of HVDC lines: Since HVDC systems are typically set up for bulk, inter-regional transfer of power, the regulation attributes cost of HVDC systems to the Designated ISTS Customers (DICs) of that particular region, in proportion to their approved withdrawal. Steps for calculating HVDC charges: Step 1: Connect HVDC lines and calculate transmission charges of AC network for all ISTS beneficiaries Step 2: Disconnect the HVDC lines and again calculate AC network transmission charges for all beneficiaries Step 3: Compute the difference between transmission charges at all nodes The nodes where transmission charges are higher due to the presence of HVDC lines are recognized as 'beneficiaries' of the HVDC system and the YTC of HVDC lines is then proportionately distributed among the identified beneficiaries. 90% of HVDC lines YTC will be recovered by the methodology defined above. The remaining 10% of YTC will be recovered through Reliability Support Charge as HVDC lines improve the overall stability of transmission systems. 24